# REPORT TO CONGRESS ON COMPETITION
IN WHOLESALE AND RETAIL MARKETS
FOR ELECTRIC ENERGY

Pursuant to Section 1815 of th e Energy Policy Act of 2005



# The Electric Energy Market Competition Task

Force

# The Electric Energy Market Competition Task Force

Members:

J. Bruce McDonald, Department of Justice Michael Bardee, Federal Ener gy Regulatory Commission John H. Seesel, Federal Trade Commission David Meyer, Department of Energy Karen Larsen, Department of Agriculture

Report Contributors :

Robin Allen – Depart ment of Justice
Kathleen Barrón – Federal En ergy Regulatory Commission Tracey Chambers – Department of Justice
Lee-Ken Choo – Federal Ener gy Regulatory Commission Jade Eaton – Department of Justice Patricia Ephraim – Department of Energy Douglas Hale– Department of Energy; Energy Information
Administration
John Hilke – Federal Trade Commission Douglas Hilleboe – Federal Trade Commission David Kathan – Federal Energy Regulatory Commission Robin Meigel – Department of Agriculture
Richard O'Neill – Federal En ergy Regulatory Commission Moon Paul – Federal Energy Regulatory Commission Astrid Rapp – Federal En ergy Regulatory Commission Steven Reich – Federal Energy Regulatory Commission Janelle Schmidt – Department of Energy Harry Singh – Federal En ergy Regulatory Commission Michael Wroblewski – Federal Trade Commission (left the FTC in June 2006) David Zlotlow – Department of Justice

This report was prepared by the Task For ce with the assistance of the Department of

# Justice, Federal Energy Regulatory Commission, Federal Trade Commission, Department of Energy, and Department of Agriculture. The Task Force assumes full responsibility for the report and the views expressed herein.

# TABLE OF CONTENTS

Table of
Contents...................................................................................................................... i

Executive Summary

................................................................................................................. 1

Chapter 1. Industry Structure, Legal and Regulatory Background, Trends and Developments................................................................................................... 10 Chapter 2. Context for the Task Force’s Study of Competition in Wholesale and Retail
Electric Power
Markets........................................................................................... 44 Chapter 3. Competition in Wholesale Electric Power Markets
............................................... 53 Chapter 4. Competition in Retail Electric Power
Markets....................................................... 84

Appendix A. Index of Comments Received
...........................................................................109 Appendix B. Task Force Meetings with Outside Parties
........................................................116 Appendix C. Annotated Bibliogr aphy of Cost Benefit Studies
..............................................117 Appendix D. State Retail Competition Profiles
.....................................................................137 Appendix E. Analysis of Contract Length and Price

Terms....................................................177 Appendix F. Bibliography of Primary Information on Electric Competition
.........................182 Appendix G. Credit Ratings of Ma jor American Electric Generation Companies..............184

Table 1-1. U.S. Retail Electric Providers, 2004

....................................................................... 14 Table 1-2. U.S. Retail Electric Sales, 2004
.............................................................................. 15
Table 1-3. U.S. Retail Electric Provid ers, 2004, Revenues from Sales to
Ultimate Consumers ............................................................................................... 15 Table 1-4. U.S. Electricity Generation, 2004
........................................................................... 16
Table 1-5. U.S. Electric Generation Capacity, 2004
................................................................ 16

# Table 1-6. Power Generation Asse t Divestitures by I nvestor-Owned Electric Utilities, as of April 2000
............................................................................................................... 43 Table 4-1. Percentage of Utility Ownership of Generation Assets
................................ 93

Figure 1-1. U.S. Electric Power Industry, Av erage Retail Price of Electricity by State, 2004 ............................................................................................................. 26 Figure 1-2. Status of State Electric Industry Restructur ing Activity and Retail Competition, July 2006 ......................................................................................... 28 Figure 1-3. RTO Configurations in 2006
................................................................................. 32 Figure 1-4. Utility and Nonutility Generation Capacity Additions, 1995-
2004....................... 35 Figure 1-5. Transmission Construction Expendi tures by Investor-Owned Utilities, Actual and Projected, 1975-2009........................................................................... 36 Figure 1-6. National Average Reta il Prices of Electricity for Residential Customers,
1960-2005 ............................................................................................................. 38 Figure 1-7. Natural Gas Plants Domi nate New Generating Unit Additions
............................ 39 Figure 1-8. Net Generation Shares by Energy Source
............................................................. 40 Figure 1-9. Fossil Fuel Costs fo r Electric Generators, 2001-2006

.......................................... 41

Figure 3-1. U.S. Electric Generati ng Capacity Additions, 1960-2005
.................................... 60 Figure 3-2. Estimate of Annual New York Capacity Values
.................................................. 65 Figure 4-1. U.S. Electric Power Industry, Av erage Retail Price of Electricity by State, 1995............................................................................... 87 Figure 4-2. States Retail Competition Status, 2003
................................................................. 91 Figure 4-3. Average Revenues per kWh for Retail Customers, 1990-2005
............................ 95

Appendix D Tables 1-
34....................................................................................................139-174

# EXECUTIVE SUMMARY

A. Congressional Request

The Energy Policy Act of 2005 (EPAct 2005) 1 was designed to provide a comprehensive l ong-range energy plan for the United States. Section 1815 of the Act2 created an “Electric Energy Market Comp etition Task Force”3 (Task Force) to conduct a study of competi tion in wholesale and retail markets for electricity in the United States. Section 1815(b)(2 )(B) required the Task Force to publish a draft final report fo r public comment at least 60 days prior to submitting the final report to Congress. The Task Fo rce published the draft final re port in June 2006 and sought comm ent on the preliminary
observations contained in the draft. Base d on those comments, and other input receive d earlier, the Task Force hereby submits this final report to Congress.

B. Task Force Activities

In preparing this report, the Task Forc e undertook several activities, as follows:

Section 1815(c) of the EPAct 2005 required the Task Force to “consult with and solicit co mments from any advisory entity of the Task Force, the states, representatives of the electric power industry, and the public.” Accordingly, the Task Force published a Federal Regis ter notice seeking comment on a variety of issues related to competition in wholes ale and retail electric power markets. Over 80 commenters provi ded a variety of opinions and analyses in response. These comments are availabl e online for public review in the Task Force docket maintained b y the Federal Energy Regulatory Commission (FERC) under Docket No. AD05-17-000. The lis t of parties who submitted comments is attached as Appendix A.4

The Task Force met and discussed competition- related issues with a variety of repres entatives of the states, the electric power industry, and other
stakeholders in October-December 2005. Th ese groups are listed in Appendix B.

The Task Force prepared an annot ated bibliography of the public cost/benefit studi es that have attempted to analyze the status of wholesale and retail competition. Appendix C cont ains this bibliography.

The Task Force reviewed the status of reta il competition in the states and examined in detail the experiences of seven states w ith active retail competition programs: Illinois, Maryland, Massachusetts, New Jersey, New York, Pennsylva nia, and Texas. These states have tak en a variety of approaches to introducing retail competiti on. Appendix D profiles these retail comp etition programs, updating information prep ared by the Federal Trade Commission (FTC) staff.

1 Pub. L. No. 109-58, 119 Stat. 594 (2005).

2 Pub. L. No. 109-58, § 1815, 119 Stat. 594, 1128 (2005).

3 The Task Force consists of five members: (1) one employee of the Department of Justice, appoint ed by the Attorney General of the United States; (2) one employee of the Federal Energy Regulatory Commission, appointed by the Chairperson of that Commission; (3) one employee of the Federal Trade Commission, appointed by the Chairperson of that Commission; (4) one employee of the Department of Energy, appointed by the Secretary of En ergy; and (5) one employee of the Rural Utilities Service, appointed by the Secretary of Agriculture.

4 Abbreviations for those parties are also listed in Appendix A.

5 Pub. L. No. 95-617, 92 Stat. 3117 (c odified in U.S.C. titles 15, 16, 26, 30, 42, and 43) (1978).

6 Pub. L. No. 102-486, 106 Stat. 2776 (1992).

7 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Serv ices by Public Utilities; Recovery of S tranded Costs by Public Utilities and Transmitting Utilities , Order No. 888, 61 Fed. Reg. 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. Transmissi on 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 Order No. 888].

8 16 U.S.C. §§ 791a et seq. (2000).

9 APPA comments.

10 Id.

11 NRECA comments.12 7 U.S.C. 901 et seq.

13 “Nonutilities” – as that term is define d for EIA reporting purposes and as used he re – may still be characterized as “utilitie s” and subject to public service regulation under state law and regulated as “public utilities” by FERC.

14 QFs are small power producers using eligible alternative elect ric generating technologies and i ndustrial and commercial cogene rators (combined heat and power producers) that have sp ecial status under PURPA.

15 EEI comments.

16 L EONARD S. H YMAN , A MERICA ’ S E LECTRIC U TILITIES : P AST

, P RESENT AND F UTURE 64 (Public Utility Reports, Inc. 1988) [hereinafter H YMAN ]. In the City of Chicago, the city council granted 29 different electric fran chises between 1882 and 1905; thr ee of them were citywide.

17 For more on the history of electric utilities, see also U.S. Department of Energy, Energy Information Administration, The Changing Structure of the Electric Power Industry: 1970-1991 , at 57 (March 1993), available at http://tonto.eia.doe.gov/FTPROOT/ele ctricity/0562.pdf [hereinafter EIA 1970-1991 ]; U.S. Department of Energy, Energy Information Administration, The Changing Structure of the Electric Power Industry 2000: An Update, Appendix A (October 2000), available at http://www.eia.doe.gov/cneaf/elect ricity/chg_stru_update /update2000.html [hereafter EIA Update 2000 ].

18 H YMAN at 68.

19 In economic literature, the concept of a “natural monopoly” deve loped over time as a rationalization for the regulation of ele ctric utilities. In brief, a “natural monopoly” is an industry characterized by long-run decreasing co sts where a single provider can supply product or service at a lower cost than competition.

A LFRED E. K AHN

, T HE E CONOMICS OF R EGULATION : P RINCIPLES AND I NSTITUTIONS , Volume 1, at 11-12 (John Wiley & Sons, Inc. 1970). Kahn also notes the substantial legal and historical “public interest” rationale for regulation of the electric utility industry. Economists have debated whether the electric utility industry or segments of it are natural monopolies for several d ecades. This debate focuses on the economic theory rationalizat ion for regulation and not the public policy or legal basis fo r electric power regulation. See, e.g. , Vernon Smith, Regulatory Reform in the Electric Power Industry (1995) (working paper, on file with the Department of Econo mics, University of Arizona); R ICHARD F. H IRSCH

, P OWER L OSS : T HE O RIGINS OF D EREGULATION AND R ESTRUCTURING IN

THE A MERICAN U TILITY S YSTEM (MIT Press 1999); S HARON B EDER

, P OWER P LAY : T HE F IGHT TO C ONTROL THE W ORLD ’ S E LECTRICITY (W.W. Norton 2003).

20 H YMAN at 68.

21 See EIA Update 2000

.

22 H YMAN at 74.

23 15 U.S.C. §§ 79a et seq. (2000).

24 In Public Utilities Commission of Rhode Isl and v. Attleboro Steam & Electric Co ., 273 U.S. 83 (1927), the Supreme Court ruled that state regulators were barred by the Commerce Clause from setting the pr ices of electricity sold across state lines.

25 See EIA 1970-1991

.

26 EIA Update 2000 at 114-15.

27 The costs of constructing new nuclear plants quadrupled between 1971 and 1976. Over 63 nuclear units were canceled between 19 75 and 1980. EIA Update

2000 at 114-15.

28 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,640-41.

29 Id. at 31,641.

30 Id. at 31,639, n.9.

31 The response to the blackout included the formation of regi onal reliability councils and the North American Electric Reliabili ty Council (NERC) to promote the reliability and adequacy of bulk power supply. EIA Update 2000 at 109.

32 Paul L. Joskow, The Difficult Transition to Competitive Electricity Markets in the U.S. 6-7 (AEI-Brookings Joint Ctr. fo r Regulatory Studies, Working Paper No. 03-13, 2003), available at http://www.aei-brookings.org/ admin/authorpdfs/page.php?i d=271 [hereinafter Joskow, Difficult Transition ].

33 See EIA 1970-1991 at 22.

34 PURPA specifically set forth criteria on w ho and what could qualify as QFs (mainly technology, size, and ownership criteria). Two types of QFs were recognized: cogenerators, which sequentially produce electric energy a nd another form of energy (suc h as heat or steam) using t he same fuel source, and smallpower producers, which use waste, renewable energy, or geothermal energy as a primary energy source. See EIA 1970-1991 at 5.

35 Id. at 24.

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

37 See Paul L. Joskow, Deregulation and Regulatory Reform in the U.S. Electric Power Sector , at 17 (February 16, 2000) (revised discussion draft prepared for the Brookings-AEI Conference on Deregulation in Network Industries, Dec. 9-10, 1999) [hereinafter Joskow, Deregulation ].

38 C ONG

. R ESEARCH S ERV

., C OMM

. ON E NERGY AND C OMMERCE

, 102 D C ONG

., E LECTRICITY : A N EW R EGULATORY O RDER ? 92 (Comm. Print 1991).

39 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,644.

40 Joskow, Deregulation at 19.

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

42 EIA 1970-1991 at vii.

43 Id. at 27.

44 See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,643.

45 See Regulations Governing Bidding Programs , Notice of Proposed Rulemaking, 53 Fed. Reg. 9,324 (Mar. 22, 1988), FERC Stats. & Regs. ¶ 32,455 (1988) (modified by 53 Fed. Reg. 16,882 (May 12, 1988)). This proposal would have a dopted competitive bidding into the process of acq uiring and pricing power from QFs and would have largely abandoned th e prior avoided cost purchase rates.

See Regulations Governing Independent Power Producers , Notice of Proposed Rulemaking, 53 Fed. Reg. 9,327 (Mar. 22, 1988), FERC Stats. & Regs. ¶ 32,456 (1988) (modified by 53 Fed. Reg. 16882 (May 12, 1988)). This propos al would have relaxed rate re view and regulation of wholesa le sales by independent power producers, and other public utilities that did not operate retail distribution systems.

See Administrative Determination of Full Avoided Costs, Sales of Power to Qualifying Facilities, and Interconnection Facilities , Notice of Proposed Rulemaking, 53 Fed. Reg. 9,331 (Mar. 22 1988), FERC Stats. & Regs . ¶ 32,457 (1988) (modified by 53 Fed. Reg. 16882 (May 12, 198 8)). This proposal would have revised the elements used in making administrative determ inations of avoided costs for rates for utilities’ PURPA QF purch ases.

46 Hearing on National Energy Security Act of 1991 (Title XV) Before the S. Comm. on Energy and Natural Resources, 102d Cong. 97 (1991) (statement of Cynthia A. Marlette, Associate General Counsel for Hydroelectric and Electric, Federal Energy Regulatory Commission).

47 Id. at 100.

48 Id.

49 Id. at 102.

50 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,642-43.

51 Joskow, Deregulation at 21. See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,644.

52 Joskow, Deregulation at 23. Under PUHCA 1935, those public utility holding companies th at did not qualify for an exemp tion were subject to extensi ve regulation of their financial activities and operations. These regul ations limited the availability of exemptions and the grow th and expansion of electric utility companies. PUHCA 1935 restricted utility operations to a singl e integrated public-utility system and prevented utility holding companies from owning other businesses that were not reasonably incidental or functionally re lated to the utility business. Further, registered holding co mpanies had to obtain Securities and Exchange Commission (SEC) approval for the sale and issuance of securities, for tran sactions among their affiliates and subsidi aries and for services, sales, and construction contracts, and they were required to f ile extensive financial reports with the SEC.

Although PUHCA 1935 provided for limited exemptions, it was long cr iticized as discouraging new investment in the electric util ity industry by nonutility entities. Mergers and acquisitions of utilities subject to PUHC A 1935 have largely been by other domestic and foreign utilitie s. Investment by entities outside the industry has been limited, as these entities avoi d the extensive regulations imposed by PUHCA 1935.

53 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,645.

54 Joskow, Deregulation at 24.55 See EIA 1970-1991 at 30; Joskow, Deregulation at 23.

56 Pub. L. No. 102-486, §§ 721-26, 106 Stat. 2776 (1992).

57 Order No. 888, FERC Stats. & Regs. ¶ 31,036, at ¶ 31,654.

58 Id. Order No. 888 also clarified FERC's interpretation of the federal/state jurisdictional bounda ries over transmission and local distribution. While it reaffirmed that FERC has exclusive jurisdic tion over the rates, terms, and conditions of unbundled retail transmission in inter state commerce by public utilities, it nevertheless recognized the legitimate concerns of state regulat ory authorities for the development of competition within their states. FERC therefore declined to extend its unbundling requirement to the transmission component of bundled retail sales and reserv ed judgment on whether its ju risdiction extends to such transactions. The United States Supreme Cour t affirmed this element of Order No. 888. New York v. FERC , 535 U.S. 1 (2002).

59 Open Access Same-Time Information System (Formerly Re al-Time Information Networ ks) and Standards of Conduct , Order No. 889, 61 Fed. Reg. 21,737 (May 10, 1996), FERC Stats. & Regs. ¶ 31,035 at 31,583 (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).

60 Joskow, Deregulation at 29.

61 EIA 2000 Update at 66.

62 Id. at 66, 68, 80.

63 Id. at 67.

64 Joskow, Deregulation at 27-28.

65 EIA 2000 Update at ix.

66 See discussion infra , Box 1-1.

67 Joskow, Deregulation at 19.

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

69 EIA 2000 Update at 43.

70 Id. at 81-82.

71 Paul L. Joskow, Markets for Power in the United States: An Interim Assessment , E NERGY J. 2 (forthcoming 2006), available at http://stoft.com/metaPage/lib/Joskow-2006-power-ma rket-assessment.pdf [hereinafter Joskow, Interim Assessment ].

72 Federal Energy Regulatory Commission, The Western Energy Crisis, the Enron Bankruptcy, and FERC’s Response

, available at http://www.ferc.gov/industries/electric /indus-act/wec/chron/chronology.pdf.

73 Id.

74 Id.

75 For example, the Idaho PUC commented that the pass-through power cost adjustment portion of retail rates increased between 30 to 50 percent as a direct result of the impacts of the Western energy crisis. Idaho PUC comments.

76 See discussion infra , Box 4-3.

77 See, e.g.

, California Attorney General, Energy White Paper: A Law Enforcement Perspect ive on the California Ener gy Crisis, Recommendation s for Improving Enforcement and Protecting Cons umers in Deregulated Energy Markets (April 2004), available at http://ag.ca.gov/publications /energywhitepaper.pdf [hereinafter Cal. Atty Gen. White Paper]; Federal Energy Regulatory Commission, Final Report on Price Manipulation in Western Energy Markets: Fact Finding Investigation of Potential Manipul ation of Electric and Natural Gas Prices , Docket No. PA02-2-000 (March 26, 2003); U.S. General Accounting Office, Restructured Electricity Market s, California Market Design Enabl ed Exercise of Market Power (June 2002), available at http://www.gao.gov/new.items/d02828.pdf; Lock yer v. FERC, 383 F.3d 1006 (9th Cir., 2004); U.S. Senate, Committee on Governmen tal Affairs, Committee Staff Investigation of the Federal Energy Re gulatory Commission’s Oversight of Enron Corp (November 2002), available at http://hsgac.senate.gov/_file s/111202fercmemo.pdf.78 For more on FERC proceedings, see the FERC webpage, “Addressi ng the 2000-2001 Western Energy Cr isis,” at http://www.ferc.gov/i ndustries/electric/indusact/wec.asp.

79 Regional Transmission Organizations , Order No. 2000, FERC Stats. & Regs. ¶ 31,089, 65 Fed. Reg. 809 (Jan. 6, 2000), order on reh’g , Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092, 65 Fed. Reg. 12,088 (March 8, 2000), aff'd, Public Utility District No. 1 v. FERC , 272 F.3d 607 (D.C. Cir. 2001) [hereinafter Order No. 2000].

80 In Order No. 2000, FERC found that “opportunities for undue discrimi nation continue to exist that may not be remedied adequate ly by [the] functional unbundling [remedy of Order No. 888].” Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,105.

81 The term “rate pancaking” refers to circ umstances in which a transmission customer must pay separate access charges for each u tility service territory crossed by the customer's contract path.

82 Although RTOs do not now own tr ansmission facilities, they are not precluded by regulation from doing so. FERC’s Order No. 20 00 allows RTOs that are independent transcos – transm ission-owning RTOs that do not ow n or operate generation and are not affiliated with generation o wners or operators. Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,036-37.

83 Federal Energy Regulatory Commission, Offi ce of Market Oversight and Investigations, State of the Markets Report: An Assessment of Energy Markets in the
United States in 2004 , at 51 (2005) [hereinafter FERC State of the Markets Report 2004 ], available at http://www.ferc.gov/legal/staff-reports.asp.

84 Id. at 53.

85 Id. at 52.

86 See, e.g. , APPA comments (2); NRECA comm ents (2); Alliance of State Leaders Protecting El ectricity Consumers comments (2); Wisconsin Loa d Serving Entities comments (2); Progress and Santee Cooper comments (2).

87 U.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.

88 Id. In contrast, the November 1965 Northeast Blackout resulted in the loss of over 20,000 MWs of load and affected 30 million peo ple.

89 Id. at 107.

90 See, e.g. , New York State Public Service Commission, NYPSC Staff Second Report on the August 13-14, 2003 Blackout (November 2005), available at http://www.dps.state.ny.us. Also, see the NERC blackout website materials, available at http://www.nerc.com/~filez/blackout.html, and the reports of the Michigan Public Service Commission, available at http:www.michigan.gov/mpsc.

91 EIA 2000 Update at ix. The size of the cost improveme nts depends on the underlying fuel prices.

92 Id.

93 Id. at 23.

94 EIA 1970-1991 at vii.

95 Id.

96 U.S. Department of Energy, Energy Information Administration, Electric Power Annual 2004 , at 2 (November 2005), available at http://www.eia.doe.gov/cneaf/electric ity/epa/epa.pdf [hereinafter EIA Electric Power Annual 2004 ].

97 APPA comments (2).

98 Edison Electric Institute, EEI Survey of Transmission Investment: Hi storical and Planned Capital Expenditures , at 1 (May 2005).

99 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,640.

100 Joskow, Difficult Transition at 7.

101 U.S. Department of Energy, Energy Information Administration, Electric Power Monthly , Table 5.3 (July 2006), available at http://www.eia.doe.gov/cneaf/electricity/epm/epm_sum.html.102 According to an analysis for EEI, “Fuel and purchased power costs have risen substa ntially and are by far the largest cause of recent electricity price increases. On an industry-wide basis, these account for roughly 95 percent of increases in total operations and maintenance (O&M) costs ex perienced by electric utilities in the last five years.” Peter Fox-Penner, et al.

, Behind the Rise in Prices: Electricity Price Increa ses Are Occurring Across the Country, Among all types of Electricity Providers. Why? , E LEC

. P ERSPECTIVES 53 (July/August 2006).

103 EIA 1970-1991 at 20.

104 During the 1990s, with natural gas prices at an all time low and availability of efficient, modular gas turbines, many nonutil ities built natural-gas generation facilities to enter wholesale markets. Today, as a result of restructuring-related asset sa les and divestitures, nonutilities own and operate a broad mix of nuclear, coal, natural- gas and renewable generation facilities that suppl y wholesale markets. Natural- gas-fired generating capacity wa s 57 percent of nonutility generating capacity in 2004. According to EPSA, based on EIA data, 36 percent of elect ricity produced by competitive generator s was coal-fired, 30 percent natural gas, 24 percent nuclear, 6 percent hy droelectric and other renewabl es, and four percent oil-fired. EPSA comments (2).

105 EIA Electric Power Annual 2004 at 2.

106 Federal Energy Regulatory Commission, The Western Energy Crisis, The Enron Bankruptcy, & FERC’s Response , at 1, available at http://www.ferc.gov/industries/electric/i ndus-act/wec/chron/chronology.pdf.

107 See EIA Electric Power Annual 2004 at 17, table 2.4, available at http://www.eia.doe.gov/cneaf/el ectricity/epa/epat2p4.html.

108 See U.S. Department of Energy, National Energy Technology Lab, Tracking New Coal-Fired Power Plants , at 3-4, available at http://www.netl.doe.gov/coal/refshelf/nc p.pdf (predicting 85 GWs of new coal capacity created by 2025).

109 The information provided in this section is current as of July 2006 and does not reflect any subsequent changes.

110 See U.S. Congress, Office of Technology Assessment, Electric Power Wheeling and Dealing: Technologi cal Considerations for Increasing Competition , at 47, OTA-E-409 (Washington, DC: U.S. G overnment Printing Office, May 1989).

111 EIA 2000 Update at 91.

112 Id. at 105-06.

113 Id. at 105.

114 Id. at 91.

115 Id. at 106.

116 The EIA periodically reports on generation plant transfer s. For a list of plants transferred in 2003- 2006, see the EIA Electric Power Monthly (July 2006),
available at http://www.eia.doe.gov/cneaf/electricity/epm/tablees4.html.

117 FERC State of the Markets Report 2004 at 30-32.

118 Announced in December 2003, Ameren closed its ac quisition of Illinois Power Co. in September 2004. Id. at 31.

119 In January 2004, Black Hills Corp announced the acquisition of Ch eyenne Light, Fuel & Power from Xcel Energy. In July 2004, P NM Resources, the parent of Public Service Company of New Mexico, a nnounced the intention to acquire TNP Enterpri ses, the parent of Texas New Mexico Pow er Company from a group of private equity investors. Id. at 31-32. In December 2004, Exelon announced its intent to merg e with PSEG, a plan that would create the nation’s largest utility company by generation ownership, market capitalization, revenues, and net income. Id. at 32.

120 Id. at 30.

121 For a full discussion of the theory of competition in wholesale electricity markets, see S TEVEN S TOFT

, P OWER S YSTEM E CONOMICS : D ESIGNING M ARKETS

FOR E LECTRICITY (IEEE Press 2002).

122 From an economic perspective, retail electricity prices (or rate s) that do not closely track wholesale price trends do not sen d economically “accurate” price signals when they do not reflect temporal variations in producti on costs and wholesale market prices within days, across season s, or even across years (except after long lags).

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

124 See, e.g. , KIP VISCUSI ET AL., ECONOMICS AND REGULATION OF ANTITRUST 6- 7 (MIT Press, 4th ed. 2005) [her einafter VISCUSI, ET AL.].125 Most states also regulate the siti ng of major electric power facilities.

126 In the academic literature, the risk of utility overinvestment has been explaine d by the Averch-Johnson Ef fect. The Averch-Jo hnson Effect reflects that “a firm that is attempting to maximize profits is given, by the fo rm of regulation itself, incentives to be inefficient. Furtherm ore, the aspects of monopoly control that regulation is intended to address, such as high prices, are not necessarily mitigated, and coul d be made worse, by the reg ulation.” K ENNETH E. T RAIN

, O PTIMAL R EGULATION 19 (1991) [hereinafter T RAIN ]. The Averch-Johnson Effect also predicts that if a re gulator attempts to reduce a firm’s profits by reducing its rate of return, the firm will have an incentive to further increase its re lative use of capital. Id. at 56. Thus, the most obvious regulatory control within costbase rate regulation creates further dist ortions. The Averch-Johnson Effect is sometimes thought to explain why a regulated fi rm is led to “gold plate” its facilities, i.e

. , incur excessive costs so long as those expenses can be capitalized.

127 U.S. Department of Energy, The Future of Electric Power in America: Economic Supply for Economic Growth (June 1983) (DOE/PE-0045).

128 Under price cap regulation, a firm can theoretically “produce w ith the cost-minimizing input mi x [and] invest in cost-effectiv e innovation.” T RAIN at 318. However, this dynamic only occurs where the price cap is fixe d over time and the utility receive s the benefit of cost reduction s and cost-effective innovations. Further, the benefit of this increased e fficiency “accrues entirely to the firm: c onsumers do not benefit from the production e fficiency.” Id. Where the price cap is adjusted over time, firms are induced to engage in strategic behavior. Additionally, “if, as . . . expected, the review of price caps is conducted like the price reviews under cost-base rate regulation, th en the distinction blurs between price-ca p regulation and cost-base rate regulation. ” Id. at 319. One way for consumers under a rate cap system to share the benef its of efficiency improvements without elic iting strategic behavior from the regulate d firm is to include periodic,
automatic reductions in rates based on general trends in productivity.

129 U.S. Department of Energy, Benefits of Demand Response in Electricity Markets and Reco mmendations for Achieving Them: A Report to the United States Congress Pursuant to Section 1252 of the Energy Policy Act of 2005 (February 2006) [hereinafter DOE EPAct Demand Response Report ]. The DOE EPAct Demand Response Report discusses the benefits of demand respons e in electric power markets and makes reco mmendations to achieve these benefits.

130 There is substantial literature on setting rates ba sed on marginal costs in the electric sector. See, e.g. , M. C REW & P. K LEINDORFER

, P UBLIC U TILITY
E CONOMICS (St. Martin’s Press 1979); B. M ITCHELL

, W. M ANNING

, & J. P AUL A CTON

, PEAK–LOAD PRICING (Ballinger 1978). Other papers suggest that setting rates based on marginal costs will result in a misallocation of resources. See S. Borenstein, The Long-Run Efficiency of Real-Time Pricing , 26:3 E NERGY J. (2005). Nevertheless, the literature also indicates that ma rginal-cost pricing may result in a revenue shortfall or excess, and standard rate-making practice is to require an adjustment (presumably to an in elastic component) to reconcile with embedde d cost-of-service. Various rate structur es to accomplish marginal-cost pricing include two-part tariffs and alloca tion of shortfalls to rate classes. See V ISCUSI

, ET AL

.

131 The reduction of cross subsidies can be seen as having both po sitive and negative implications for society as a whole – depend ing on one’s perspective and whether the cross-subsidy supports publicly accep table goals, such as rural electrification.

132 DOE EPAct Demand Response Report at 7.

133 Estimates of the total costs in the Un ited States due to the August 14, 2003, blackout range between $4 billion and $10 billio n. Electricity Consumers Resource Council, The Economic Impacts of the August 2003 Blackout (Feb. 2, 2004).

134 Chuck Goldman, et al.

, Does Real-Time Pricing Deliver Demand Response? A Case Study of Niagara Mohawk’s Large Customer RTP Tariff , Lawrence Berkeley National Laboratory (August 2004) , available at http://drrc.lbl.gov/pubs/54974.pdf; Nicole H opper, Charles Goldman and Bernie Neenan, Demand Response from Day-Ahead Hourly Pricing for Large Customers , 19:3 E LECTRICITY J. 52 (Apr. 2006) [hereinafter Hopper, et al. ].

135 Charles River Associates, Final Report on the Impact Evaluation of the California Statewide Pricing Pilot (March 16, 2005), available at http://www.energy.ca.gov/demandresponse/document s/group3_final_reports/2005-03- 24_SPP_FINAL_REP.PDF. Customers on a similar CP P program at Gulf Power also have high satisfaction with the program, wh ich incorporates automated response to CPP events.

136 See EEI comments. Pepco cautions that many customers, particularly residential and commercial customers, are relatively inflexibl e in responding to price changes due to constraints imposed by their operations and equipment. See Pepco comments.

137 See DOE EPAct Demand Response Report ; Mercatus Center comments (2).

138 APPA comments.

139 While the demand for surplus ener gy in wholesale markets can vary as a function of the cost of owned generation and existing c ontracts, the ultimate demand for energy is entirely a function of end-use load.

140 Alcoa comments.

141 TAPS comments.

142 APPA comments.

143 Wholesale markets involve sales of electric power among genera tors, marketers, and load serv ing entities (i.e., distribution utilities and competitive retail providers) that ultimately resell the electric power to end-use customers (e.g., residential, commercial, and industrial custom ers).144 U.S. v. Otter Tail Power Company , 410 U.S. 366 (1973) (the United States sued a vertically integrated utility when it re fused to deal with the Town of Elbow Lake, MI, a town that was seeking alternative sources of w holesale power for a planned muni cipal distribution system).

145 See discussion infra Chapter 1.

146 Retail price impacts of competition are discussed in this report's Chapter 4.

147 In a 2002 report, the then-named General Accounting Office made a related point, connecting increasing competition to structur al changes. U.S. General Accounting Office, GAO-03-271, Lessons Learned From Electric Industry Restructuring , at 21 (2002) (“Increasing the amount of competition requires structural changes within the electric industry, such as allowing a greater number of sellers and buyers of electricity to enter the marke t”).

148 It is important to note that competition in wholesale electric markets may not lead to an effi cient allocation of resources in volving the services that prevent network collapse. Where there are “public good” aspects to the delivery of a good or service, such as with reliability, regula tion may be the best way to ensure that the correct level of the good or service is provided. In some circumstances, however, market remedies may be available th at are superior to regulation.

149 See EPAct 1992 House Report, H.R. REP. NO. 102-474(I), at 138.

150 The New York State Public Service Commi ssion correctly commented that another metric with which to measure competition is its effect on production
efficiencies. The Task Force did not seek to quantify this effect, given the constraints of the Report.

151 EPAct 1992 House Report, H.R. REP. NO. 102-474(I), at 133.

152 See discussion infra Chapter 1 for more information on FERC Order No. 888.

153 The demand charge for long-term point-to-poi nt transmission service is known in advance. For network service, the transmissio n customer pays a load-ratio share of the transmission provider’s FERC-approved transmission reve nue requirement. Thus, even if redispatch to relieve trans mission congestion occurs and the costs are charged to customers, or e xpansion is necessary and the expansion cost s are added to the revenue requirement, the distribution over the whole system has allowed the charges to individual customers to remain relatively stable. Customers who take either service have a r ight to continue taking service when their contract expires, although point-t o-point customers may have to pay a differe nt rate (up to the maximum rate in the transmission provider’s tariff) if another customer offers a higher rate.

154 APPA comments; TAPS comments. See also Midwest Stand-Alone Transmission Companies comments.

155 Prior to wholesale competition, several of the regions liste d had “power pools” of utilities that undertook some central econo mic dispatch of plants and divided the cost savings among the vertically integrated utility members.

156 For example, RTOs using LMP pricing address physical deliver ability concerns by giving physi cal access to all users willing to pay the market-determined price. The potential for high LMPs due to limited transmission av ailability presents a risk that many market participants pref er to hedge. Financial transmission rights (FTRs) have been developed as a means for transmission us ers to hedge against transmission pricing risk. The amount of FTR MWs available for hedging are determined by the transmission capabilities of the grid, so that a hol der of an FTR generally can depend on being able to u se the transmission service covered by the FTR. In some RTOs, FTRs are allocated on the basis of hi storic transmission use. In others, FTRs are allocated either through an auction or through a process that awards FTRs in proportion to the total requests for FTRs for a particular transmission service. Under the latter two approaches, some historic transmission users may have to acquire additi onal FTRs from other parties in order to hedge their previous levels of transmissi on use. In particular, in circumstances where certain transmission paths have become highl y congested, historic transmissi on users may have to make signi ficant expenditures to maintain traditional levels of transmission rights.

157 Companies can also limit their exposure to price swings through financial instrument s rather than contracts for physical deliv ery of electricity. Such contracts are essentially a bet between two parties as to the future pri ce level of a commodity. If the actual price for power at a given time and location is higher than a financial contract price, Party A pays Pa rty B the difference; if the price is lower, Party B pays Party A the difference. In fact, in the United States electricity markets, such agreements are sometimes called “contracts for diffe rences.” Purely financial c ontracts involve no obligation to deliver physical power. In this report, the Task Force discusses contracts for physical delivery rather than financial contracts, unless otherwise noted.

158 Federal Energy Regulatory Commission, Staff Report to the Federal Energy Regulatory Commission on the Causes of Wholesale Electric Pricing Abnormalities in the Midwest During June 1998 (1998).

159 Federal Energy Regulatory Commission, Office of Market Oversight and Investigations, State of the Markets Report: Assessment of Energy Markets for the Period January 1, 2002 through June 30, 2003 , at 109 (2004), available at http://www.ferc .gov/legal/staff-reports.asp [hereinafter FERC State of the Markets Report 2002-2003 ].

160 Id. at 50.

161 FERC State of the Markets Report 2004 at 77.

162 Southern comments.163 See Fitch Ratings, Wholesale Power Market Update (Mar. 13, 2006), available at http://www.fitchratings.com/corporate/sector s/special_reports.cfm?sector_flag=2&market sector=1&detail=&body_content=spl_rpt.

164 Currently, the CAISO operates only an imbalance energy market.

165 See discussion infra Chapter 1, for a more extensive discussion of the Western Energy Crisis of 2000-2001.

166 FERC State of the Markets Report 2004 at 69; FERC State of the Markets Report 2002-2003 at 41-43.

167 CAISO comments.

168 FERC State of the Markets Report 2002-2003 at 109.

169 ISO New England Inc., Forecast Report of Capacity, Energy, Loads, and Transmission , at 76 (2006), available athttp://www.isone.com/trans/celt/report/ 2006/2006_CELT_Report.pdf.

170 FERC State of the Markets Report 2002-2003 at 83 (“These load pockets did not exhibit materially higher locational prices in 2004, probably because the cost of expensive units used to ensure resource adequacy and transmi ssion security in these areas are frequently not eligible to set the clearing price”).

171 Id. at 36.

172 Devon Power LLC , 115 FERC ¶ 61,340 (2006); Press Release, ISO New England Inc., ISO New England Announces Broa d Stakeholder Agreement on New Capacity Market Design (Mar. 6, 2006), available at http://www.iso-ne.com/nwsiss/pr/ 2006/march_6_settlement_filing.pdf.

173 FERC State of the Markets Report 2002-2003 at 109.

174 FERC State of the Markets Report 2004 at 97.

175 FERC State of the Markets Report 2002-2003 at 39.

176 PJM Interconnection, L.L.C. , 115 FERC ¶ 61,079, at 61,236, reh’g denied , 117 FERC ¶ 61,331 (2006).

177 FERC State of the Markets Report 2002-2003 at 109.

178 FERC State of the Markets Report 2004 at 112.

179 Id. at 188.

180 AEP proposes to build a new 765-kilovolt (kV) transmission line st retching from West Virginia to New Jersey, with a projected in-service date of 2014. AEP Interstate Project Summary

, available at http://www.aep.com/newsroom/resources/docs/AEP_Intersta teProjectSummary.pdf. Allegheny Power (Allegheny) proposes to construct a new 500-kV transmission line, with a targ eted completion date of 2011, which will extend from southwest ern Pennsylvania to existing substations in West Virginia and Vi rginia and continue east to Dominion Virginia Power’s Loudoun Substation. Allegheny Power Transmission Expansion Proposal

, available at http://www.alleghenypower.com/TrAIL/TrAIL.asp . More recently, Pepco has proposed to build a 500-kv transmission line from Nor thern Virginia, across the Delmarva Peninsula and into New Jersey.

181 ERCOT Response to the DOE Questi on Regarding the Energy Policy Act 2005

, available at http://www.oe.energy.gov/Docu mentsandMedia/ercot2.pdf.

182 Ross Baldick and Hui Niu, Lessons Learned: The Texas Experience

, available at http://www.ece.utexas.edu/~bal dick/papers/lessons.pdf.

183 U.S. General Accoun ting Office, GAO-02-427, Restructured Electricity Markets, Three St ates' Experiences in Adding Generating Capacity , at 9 (2002) [hereinafter GAO, Restructured Electricity Markets, Three States’ Experiences ].

184 Id. at 19.

185 Public Utilities Commission of Texas comments (2)

.

186 For more information regarding LAAR, see http://www.ercot.com/servi ces/programs/load/laar.

187 Available at http://www.columbiagrid.org

188 For a complete discussion of generation characteristics of the Northwest, see NW Power & Con. Council, The Fifth Northwest Power and Conservation Plan

,Ch. 2 (2005), available at http://www.nwcouncil.org/energy/ powerplan/plan/Default.htm.

189 Under a pay-as-bid market, sellers are paid their actual bid prices, while under a “single price” or uniform price market, all sellers are paid the single marketclearing price.

190 Par Holmberg, Comparing Supply Func tion Equilibria of Pay-as-Bid and Uniform Price Auctions (2005) (Uppsala University, Sw eden Working Paper 2005:17); 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.

191 Alfred E. Kahn, et al.

, Uniform Pricing or Pay-as-Bid Pric ing: A Dilemma for California and Beyond (Blue Ribbon Panel Report, study commissioned by the California Power Exchange, 2001).

192 In theory, a pivotal supplier could bid $1 million or more and set the clearing price, so in practice the ISO would have still set a cap, albeit a high one. In its comments, the Public Utilities Commission of Texas describes a pl an it expects to adopt in summe r 2006, to raise offer caps inc rementally in its energy-only market. The Public Utilities Commission of Texas expects to ulti mately pay $3000 per MWh for energy in some hours of the year.

193 See generally Edison Mission Energy, Inc. v. FERC , 394 F.3d 964 (D.C. Cir. 2005).

194 Robert J. Michaels and Jerry Ellig, Price Spike Redux: A Market Emerged, Remarkably Rational , 137 P UB

. U TIL

. F ORTNIGHTLY 40 (1999). Wholesale customers with supply contracts for which the prices were tied to the market price paid higher prices for electric power during those hours.

195 Sometimes, in fact, entry may not be jus tified, even in the face of high prices. Po tential entrants must consider the benefit s as well as the costs of entry. Some areas may be so costly to enter, that it is more efficient for society as a whole to pay the higher prices rather than pay the high investment costs to build lower cost generation, institute price-responsiv e demand programs, or invest in transmission access to lower-cost generation.

196 Making demand response eligible to meet reserve margins may ease these concerns.

197 In the areas that need capacity the most – densely populated areas signi ficantly bounded by topographical barriers such as oce ans – land prices, environmental restrictions, aesthetic considerations, and other factors may make new generation more (or even pr ohibitively) expensive. In f act, there are some environmental restrictions that serve as de facto bars to new generation entry.

198 PJM Interconnection, L.L.C., PJM Regional Transmission Expansion Plan

, at 20 (2006), available at http://www.pjm.com/planning/ reg-trans-exp-plan.html

.

199 See supra note 180. AEP and Allegheny are both requesting that their pr oposed transmission projects be designated as a National Interes t Electric
Transmission Corridor under EPAct 2005.

200 Regulatory solutions, more so than market -based outcomes, may outlive the circumstan ces that made them seem reasonable.

201 New York G&E comments; Idaho PUC comments.

202 FERC’s efforts are not limited to the orga nized markets, and extend to other markets as well. Also, federal and state antitru st enforcement agencies have jurisdiction to challenge anticompetiti ve conduct in electricity markets.

203 NYPSC comments.

204 ELCON comments; NRECA comments; APPA comments.

205 E.g. , PJM comments; EPSA comments.

206 Constellation comments; Mirant comments.

207 ELCON comments.

208 In competitive markets, customers also ha ve the ability to build their own generati on facility if they are unable to obtain th e long-term purchase contracts that they seek.

209 See, e.g. , Maine Public Advocate comments; NASUCA comments.

210 The July 2006 Energy Velocity database s hows that of the 165,163 MW of generation th at is permitted, proposed, application-pen ding or has had a feasibility study performed, 110,964 MW, about two-thirds, is nuclear, combined cycle, coal-fired steam or integrated coal gasification tec hnology (generation types typically considered base-load or mid-merit).211 See Inquiry Concerning Alternative Power Pooli ng Institutions Under the Federal Power Act , Notice of Inquiry, 59 Fed. Reg. 54,851 (Oct. 26, 1994), FERC Stats. & Regs. ¶ 35,529 (1995) (FERC Docket No. RM94-20-000).

212 Comments of U.S. Department of Justice, Inquiry Concerning Alternative Power Pooli ng Institutions Under the Federal Power Act , at 6 (Mar. 2, 1995) (FERC Docket No. RM94-20-000). See also Reply Comments of the U.S. Department of Justice, Inquiry Concerning Alternati ve Power Pooling Institutions
Under the Federal Power Act (Apr. 3, 1995) (FERC Docket No. RM94-20-000).

213 See Comment of the Federal Trade Commission, Market-Based Rates for Public Utilities , at 7-8 (Jul. 16, 2004) (FERC Docket No. RM04-7-000), available at http://www.ftc.gov/os/comme nts/ferc/v040021.pdf.

214 APPA comments; Carnegie Mellon comments.

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

216 APPA comments; TAPS comments.

217 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958 (2005) (emphasis added).

218 Constellation comments; Mirant comments.

219 In December 2005, FERC proposed to adopt a general rule on the sta ndard of review that must be met to justify proposed modific ations to contracts under the FPA, except transmission service agreements executed under an open access transmission tariff as provided for under Order No. 8 88, and under the Natural Gas Act, except agreements for the tr ansportation of natural gas executed pursuant to th e standard form of service agreement in pip eline tariffs. Standard of Review for Modifications to Filed Agreements , Notice of Proposed Rulemaking, 71 Fed. Reg. 303 (Janua ry 4, 2006), FERC Stats. & Regs. ¶ 61,317 (2005) (Comm’r Kelly, dissenting). Specifically, FERC propos ed that, in the absence of specified contractual language permitting the Commissi on to act on proposed modifications to an agreement on its own motion or on behalf of a signatory or non- signatory under the “just and reasonable” st andard, the Commission, a signatory or a non-signatory seeking to change a contract must s how that the change is necessary to protect the public interest . FERC explained that its proposal recognized the importance of providing certain ty and stability in energy markets, and helped promote the sanctity of contracts. A final rule is pending.

220 Nevada Power Company v. Enron , 103 FERC ¶ 61,353, order on reh’g , 105 FERC ¶ 61,185 (2003); Public Utilities Commission of California v. Sellers of 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).

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

222 See Howard L. Siegel, The Bankruptcy Court vs. FE RC- The Jurisdictional Battle , 144 P UB

. U TILS

. F ORTNIGHTLY 34 (2006).

223 Another factor creating a potential prefer ence for self-built generation as opposed to long-term purchases is the treatment by some credit rating agencies of power purchase contracts as imputed debt. If a utility’s self- built generation is treated as an asset but long-term purchase c ontracts are treated as imputed debt, it may cause utilities and state regulators to favor constructing and owni ng over purchasing. See EPSA comments.

224 See infra Chapter 4 for a discussion of regulated service offerings in states with retail competition.

225 Mirant comments; Constellation comments.

226 Paul L. Joskow, Competitive Electricity Markets and In vestment in New Generating Capacity (April 28, 2006) (MIT Working Paper).

227 C ONG

. B UDGET O FFICE

, F INANCIAL C ONDITION O F T HE U.S. E LECTRIC U TILITY I NDUSTRY (1986), available at http://www.cbo.gov/showdoc.cfm?i ndex=5964&sequence=0.

228 Southern comments; Duke comments.

229 Commodity Futures Trading Commission, The Economic Purpose of Futures Markets

, available at http://www.cftc.gov/opa/broc hures/opaeconpurp.htm.

230 APPA comments.

231 Task Force Meetings with Credit Agencies, see Appendix B.

232 GAO, Restructured Electricity Markets, Three States’ Experiences at 13.

233 Connecticut DPUC comments.234 GAO, Restructured Electricity Markets, Three States’ Experiences at 13.

235 U.S. Department of Energy, Energy Information Administration, The Changing Structure of the Electric Power Industry: An Update , at 38 (December 1996),
available at http://tonto.eia.doe.gov/FTPR OOT/electricity /056296.pdf.

236 Id.

237 Hearing on Nuclear Power, Before the Subcomm. on Energy of the S. Comm. on Energy & Nat’l Res. (Mar. 4, 2004) (statement of Mr. James Asselstine, Managing Director, Lehman Brothers). See also Nuclear Energy Institute, Investment Stimulus for New Nuclear Powe r Plant Construction: Frequently Asked Questions

, available at http://www.nei.org/documents/New_P lant_Investment_Stimulus.pdf.

238 Natural Gas Factors Affecting Prices and Po tential Impacts on Consumers: Testimony Before the Permanent Subcommittee on Investi gations, Committee on Homeland Security and Governmental Affairs , United States Senate; GA-06-420T (Feb. 13, 2006), at 7.

239 EPSA comments.

240 Occasionally in the past few years net revenues have been suff icient to cover the costs of new peaking units, and in 2005 they were enough to cover the costs of a new coal plant. PJM Interconnection, LLC, Market Monitoring Unit, 2005 State of the Market Report , at 118 (2006), available at http://www.pjm.com/markets/market-monitor/som.html

241 PJM Interconnection , 115 FERC at 61,236.

242 Public goods have two characteristics – “nonexclusiveness” and “nonrivalry.” Nonexc lusiveness means that others cannot be exc luded from the use of the good (e.g., if one person refuses to pay taxes, that person still can enjoy public park s) and nonrivalry implies that one perso n’s consumption of the good does not diminish another person’s consumption (e.g., the fact that one person enjoys the increased safe ty engendered by military spendi ng doesn’t decrease another person’s safety.) “Preventing network collapse” is nonexclusive because if the network collapses there is nothing one can do t o escape it (unless one constructs freestanding on-site generation) and it is nonrivalrous because one pers on being protected from co llapse does not preclude anot her person’s being protected.

243 Joskow, op. cit.

244 Federal Energy Regulatory Commission, Staff Report on the Assessment of De mand Response and Advanced Metering (August 2006).

245 The Task Force adopts the convention of designating states as permitting retail competition on the basis of whether a state al lows alternative suppliers to enter and obtain multiple, geographically dispersed customers. An even broader poten tial definition of retail competition would take into account policies that allow individual retail customers to provide some or all of their own generation needs ( i.e., to make rather than buy electricity) . Onsite generation is common in some industries in some sections of the country. Small onsite gene ration projects – often referred to as “Distributed Generation” o r “Distributed Resources” projects – are gaining popularity as well. Many states that do not have re tail choice in the conventional se nse do have provisions for va rious forms of onsite generation and net metering. Another broader form of retail competition involve s municipal utilities or cooperatives. NRECA comments (2). T hese entities can be carved out of existing private utility distribution areas, or can be added back into them if the municipality d ecides to do so (or if the cooperative disbands). The Otter Tail

Power case, 410 U.S. 366 (1973), was decided on the ba sis of this form of retail competition. If these broader definitions of “reta il competition” were used, all (or nearly all) states would be designated as retail competition states.

246 In this report, the Task Force refers to state-mandated and -regulated electrical service in states with consumer choice progr ams as POLR service. A broad range of terms is used in different states to denote this type of service. Some states have mo re than one form of mandated ser vice or have changed the form of POLR service over time. In many states, POLR service orig inated as an element in arra ngements to pay the stranded ( i.e ., non-recovered) costs of vertically integrated utilities – costs that may have become unrecoverable when the state adopted a retail customer choice approach.

247 Debt rating agencies may downgrade the cr editworthiness of utilities in states that require utilities to sell at prices below their costs. For example, Moody’s Investors Services reportedly ha s downgraded the creditworthiness of utilities in Maryland – in particular, Baltimore Gas & Ele ctric, due to that firm’s inability to pass on increased input costs to consumers, which “leaves BG E in a weakened state that ma kes it vulnerable to further downgr ades and even in solvency if it faces further energy price shocks or other costs that the legislature deems cannot be passed on to customers.” Patricia Hill, Maryland Utilities Designated Near
Junk , W ASH

. T IMES (July 12, 2006), available at http://www.washingtontimes.com/functions/p rint.php?StoryID=20060711-103048-5690r.

248 In most retail customer choice states, supply contracts (vesti ng contracts) have been used to enable distribution utilities to offer POLR service at the capped price level after they have divested generating plants or transf erred them to unregulated affiliates. The “rate shock” anticip ated in these states is due in part to the lack of laddering in the vesting contracts beyond the end of the transition period, as defined in the legislation. There are t wo exceptions worth noting. In California, vesting agreements were de-emphasized in favor of pr ocurement at spot market prices . In upstate New York, vesting agreements were longer term and continue to have a moderating effect on average procurement prices fo r POLR service. Public Utility Law Project of New Yor k comments (2) at 36.

249 Several commenters emphasized the potential spillovers from probl ems at the wholesale level to the retail level, including NYP SC comments (2) at 3-4; APPA comments (2) at 4, 21-25; New York Co mpanies comments (2) at 2, 4-5; Direct En ergy comments (2) at 7; Alliance for Retail Energy Markets comments (2) at 3-4; Industrial Consumers comments (2) at 9-10, 21-22; Allegheny comments (2) at 15, 19.

250 Retail competition and options for onsite generation can provide opportunities for a customer to find alternative supply sourc es, including self-generation, if the customer’s present supplier tries to raise prices above the competitive level ( i.e ., attempts to exercise market power).

251 See Appendix D infra for each state profile.252 Restructured states as of May 2006 include Connecticut, Delawa re, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hamp shire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia, plus the District of Columbia. The states profiled in App endix D display a range of conditions that are similar to the other states with retail compe tition. Virginia is similar to Pennsylvania in that its trans ition to retail competition evolved over a 10-year period. Maine and Rhode Island are similar to New York a nd Texas in that prices for “provider of last resort” (POLR) s ervice have been adjusted regularly to reflect changes in wholesale prices. Delaware, the District of Columbia, Illinois, Michigan, New Hampshire, Ohio, and Rhode Island share the situation faced by Maryland, where the tran sition period of fixed prices for residential and small C&I POLR service will end in the near future. Massachusetts’s rate cap period ended recently. Many of the states poised to end the transition period are deve loping approaches to bring POLR prices for residential and small C&I customers up to market rates in stages rather than all at once. Several of thes e states also share Maryland’s and New Jers ey’s interest in auctions for procuring POLR service supplies. Oregon’s situation differs from the other states in that only nonresidential customers can sh op, and that shopping is limited to a short window of time each year.

253 Retail electric customers in 30 states continue to receive service almost exclusively under a traditional regulated monopoly u tility service franchise. These states include 44 percent of all U.S. retail customer s, accounting for 49 percent of electricity demand.

254 For example, Georgia law allows any new customers with loads of 900 kilowatts or mo re to make a one-time selection from among competing eligible electric suppliers. Southern comments.

255 FERC and the states will continue to regulate the price for transmission and distribution services, and the local distributio n utility will continue to deliver the electricity in most states, regardless of wh ich generation supplier the customer chooses.

256 A.B. No. 1890, 1995-1996 Sess. (Cal. 1996) (enacted), available at http://www.leginfo.ca. gov/pub/95-96/bill/asm/ab_1851- 1900/ab_1890_bill_960924_chaptered.pdf.

257 Wisconsin regulators apparently believed that retail compe tition might increase the cost of capital for new generation and tra nsmission projects. PSC Wisconsin Comments (2) at 3.

258 See, e.g. , Cal. Atty Gen. White Paper; Fe deral Energy Regulatory Commission, Final Report on Price Manipulation in Western Energy Markets: Fact Finding Investigation of Potential Manipulat ion of Electric and Natural Gas Prices (March 26, 2003) (Docket No. PA02-2-000); U.S. General Accounting Office, Restructured Electricity Market s, California Market Design Enabl ed Exercise of Market Power (June 2002), available at http://www.gao.gov/new. items/d02828.pdf.

259 CPUC comments; Alliance for Retail Energy Markets comments (2).

260 Many alternative suppliers reportedly have developed customized time-of-use and othe r forms of energy management contracts for large C&I customers. Wal-Mart comments at 10-11; Commercial End-Users commen ts at at 3; Direct Energy comments (2) at 3.

261 The degree to which customers switch to a lternative suppliers sometimes is used to measure the extent of retail competition. States with retail customer choice usually report these switching statistics. This can be a useful measure when the greatest concern is that the POLR serv ice provider is obstructing switching, or that certain features of re gulation (including lack of information a bout the retail choice process and below-mark et pricing of POLR service) are discouraging entry and active consumer shoppi ng for electricity service. Another way to gauge the success of retail competitio n policy is to survey consumers about their awareness of retail choices and perceptions of the difficulty of switching between suppliers. However, surveys are expensive and results are not available systematically. More generally, consumers can obtain the benefits of comp etition if existing competition, entry, or the threat of entry prevents incumbent suppliers from exercising market power manifested in the form of higher prices, lo wer product quality, or reduced inn ovation. In this sense, retail competition could be effective even without any switching to alternative suppliers. NASUCA comments (2).

262 There is no reason to believe, however, that retail competition in this market will not function as competition does in any ma rket, by reducing quality-adjusted prices.

263 See infra Massachusetts, New Jersey, and New York profiles, A ppendix D. See also Federal Trade Commission, Staff Report on Competition and Consumer Protection Perspectives on Electric Power Re gulation Reform: Focus on Retail Competition , at 43 (2001), available at http://www.ftc.gov/reports/elec/elec tricityreport.pdf [hereinafter FTC Retail Competition Report ].

264 The prices of generation assets have b een volatile since these divestitures occurred. Asset prices often are keyed not only t o the cost of the fuel necessary to generate the electricity, but also to the lo cation of the asset on the transmission grid.

265 See Illinois and Pennsylvania profiles, Appendix D. See also FTC Retail Competition Report , Appendix A (profiles of Illinois and Pennsylvania).

266 See infra Texas profile, Appendix D.

267 See infra New York profile, Appendix D.

268 Massachusetts Department of Telecommunications and Energy, List of Competitive Suppliers/Electricity Brokers

, available at http://www.mass.gov/dte/restruct/company.htm.

269 Massachusetts Department of Telecommunications and Energy, Active Licensed Competitive Suppliers and Electricity Brokers

, available at http://www.mass.gov/dte/restruct/competition/index.htm#License d%20Competitive%20Suppliers%20and%20Electricity%20Brokers.270 New Jersey Board of Public Utilities, List of Licensed Suppliers of Electric

, available at http://www.bpu.state.nj.us/home/supplierlist.shtml. For example, in the Connectiv territory, there are 18 C&I suppliers and only one residential supplier. Eighteen suppliers serve C&I customers and one serves residential customers in the PSE&G service territory.

271 Texas Public Utility Commission, Texas Electric Choice Compare Offers from Your Local Electric Providers

, available at http://www.powertochoose. org/default.asp.

272 New York State Public Service Commission, Competitive Electric and Gas Marketer Source Directory

, available at http://www3.dps.state.ny.us/e/esco6.nsf/. The NYPSC reports that this range has moved to between 6 and 16 alternative suppliers, and the ag ency expects the number and va riety of services offered by alternative suppliers to increase as New York State moves forward with retail comp etition. NYPSC comments (2). Some listed su ppliers may not be actively marketing to residential customers. Public Utility Law Project of New York comments (2) at 41-42.

273 A substantial number of these switches ar e the result of community aggregations (pri ncipally the Cape Light Compact) rather th an individual residential switches. Cape Light Compact comments (2) at 1-2.

274 See infra Massachusetts profile, Appendix D.

275 See infra Texas profile, Appendix D. There likely is a “chicken-or-egg” pr oblem about whether more switch ing over time is attributable to a prior increase in suppliers or vice-versa (or whether both effects interact).

276 See infra New Jersey profile, Appendix D. See also Kenneth Rose, 2003 Performance of Electric Power Markets (Aug. 29, 2003), at II-19 (review conducted for the Virginia State Corporation Commission).

277 See infra Massachusetts profile, Appendix D.

278 Although the POLR service price is based on the hourly wholesale price of electricity, customers in Maryland and New Jersey wh o purchase this service are unaware of the price until they consume the power or until they are billed. Galen Bar bose, Charles Goldman, and Bernie Neenan, The Role of Demand Response in Default Service Pricing , 19:3 ELEC. J. 64 (Apr. 2006) [hereinafter Barbose et al.].

279 See, e.g., ELCON comments; Portland Cement comments; Allia nce of State Leaders comments; Alcoa comments.

280 Portland Cement comments; Lehigh Cement comments.

281 See infra Appendix C for reference to some price comparisons by other parties.

282 Rates for residential POLR service in the Consolidated Edison distribution areas in New York State, however, are reported to vary by month rather than being averaged over longer periods of time. Public Utility Law Project of New York comments (2) at 35-36.

283 For discussion of the exposure to hourly prices among the entire class of the largest C&I customers, rather than just the cus tomers still taking POLR service,

see Barbose et al.; Hopper, et al. The authors report that although most customers switch away from POLR service when it is an hourly price, they often select offers from alternative suppliers that contain elements of hourly pricing. Further, they report that the proportion of custome rs accepting hourly price aspects in their supply contracts – over 90 percent – is far higher when the price is set on the day-ahead spot market. The authors belie ve that the higher participation rates in hourly pricing under this circumstance are due to the early warn ing that customers get in the day-ahead market and the custo mers’ consequently greater ability to respond to these pricing signals.

284 Direct Energy comments (2) at 7; Mercatus Center comments at 2; CP Consultin g comments at 2. Results from trial programs usi ng advanced meters for
residential customers indicate that residential demand for air conditioning is more price sensitive than other uses, particular ly if the response is automated. Robert Earle and Ahmad Faruqui, Toward a New Paradigm for Valuing Demand Response , 19:4 E LEC . J. 21 (May 2006).

285 Constellation comments; Pepco comments; Southern comments; EE I comments; IURC comments; NYPSC comments; ISO-NE comments.

286 National Grid comments.

287 For example, Pepco stopped actively supporting its air-conditioner di rect load control program wh en it divested its generation assets.

288 In addition to the policies surrounding POLR service discussed above, the comments id entified other factors that depress or de lay entry into retail markets. For example, the Pennsylvania Consumer A dvocate identified several factors that depr essed retail entry by suppliers to serve re sidential customers, including “the acquisition costs associated with mark eting programs to reach residential customer s, the costs of serving such customers o nce acquired, and the rising prices for generation supply service in the wholesale market.” PA Cons umer Advocate comments at 3. The Maine Office of Public Advoca te echoed these factors and also identified the “miscalculation by some s uppliers as to the risks and rewards for retail electricity competition.” Maine P ublic Advocate comments at 3. The
Industrial Consumers observed that retail markets are not fully competitive because of insufficient generation divestitures tha t left suppliers with market power. ELCON comments at 2. Another factor identified by Industrial Consumers is the inability of a lternative suppliers to gain acces s to necessary transmission
services to serve their customers. ELCON comments at 6. Ot hers customers suggested that the lack of uniform rules throughout every service territory hinders entry for suppliers. Wal-Mart comments at 13. Other commenter s argued that alternative supplie rs need access to customer use data from utilities to be able to market to prospective customers. Constellation comments at 43. Still others argued for no minimum stay requirements at POLR a nd constrained shoppingwindows, which can dampen entry. RESA comments at 30-31; Strategi c comments at 10; Wal-Mart comments at 13. The lack of entry in most states makes it
difficult for the Task Force to evaluate whic h additional factors are the most important.

289 There is one potential exception: a supplier that offers a s ubstantially different product – for example, “green” power from wind turbines – may be able to charge a higher price and still attract customers.

290 Although state utility regulators often require that POLR servic e be provided or proc ured by the incumbent distribution utilit y, the task of providing or procuring POLR service could be carried out by other entities. New York Companies co mments (2). For example, it could be assi gned to one or more alternative suppliers, awarded through a co mpetitive bidding process, or assumed dir ectly by the state utility regulator (as in Maine). In any case, the firm assigned to provide or procure POLR service may be exposed to the risk that this responsibility will be unprofitable because co sts and demand are volatile or because state utility regulators impose costs on the provider of PO LR service (such as switchi ng incentives) during the transit ion to retail customer choice. This risk can create financial difficulties for the distribution utility or another entity with this responsibility. New York Compa nies comments (2).

291 See, e.g., Illinois Commerce Commission comments; PPL comments; PA Office Consumer Advocate comments.

292 See, e.g. , PA Office Consumer Advocate comments; NASUCA comments.

293 See, e.g. , RESA comments; Wal-Mart comments; Nati onal Energy comments; SUEZ comments.

294 Most states have a mechanism by which high-risk drivers can obtain insurance. Of ten insurers in a state are assigned a portio n of the pool of high-risk drivers
based on each firm’s share of drivers outsi de the pool. AIPSO manages many of the pools and maintains links with individual st ate programs at https://www.aipso.com/adc/DesktopDefault.aspx?t abindex=0&tabid=1. Similar plans are ava ilable in many states for individuals w ith prior health conditions who are seeking health insurance coverage. See C OMMUNICATING FOR A GRICULTURE AND THE S ELF -E MPLOYED , C OMPREHENSIVE H EALTH I NSURANCE OF
H IGH

- RISK I NDIVIDUALS (19th ed. 2005).

295 Texas will end its “price to beat” system in 2007 ( See infra Texas profile, Appendix D). Massachusetts ende d its rate-capped POLR service in February 2005 ( See infra Massachusetts profile, Appendix D). In the Atlanta Gas Light distribution territory, the di stribution utility petitioned the Georgia Public Service
Commission to withdraw from retail sales. In Georgia, under the amended Natural Gas Competition and Deregulation Act of 1997, a customer who does not choose an alternative supplier is randomly assigned an alterna tive supplier. Discussion and doc umentation about the Georgia na tural gas retail competition program are available at http://www. psc.state.ga.us/gas/ngdereg.asp.

296 See infra New Jersey profile, Appendix D.

297 See infra Illinois profile, Appendix D.

298 See infra Texas profile, Appendix D. In contrast, a state with long lags in fuel cost adjust ments would have retail prices well below m arket rates during periods of increasing fuel prices, and prices well above market rates during periods of declining fuel prices. A single snapsh ot comparison of prices would be misleading in these circumstances.

299 See discussion infra of the California energy crisis, in wh ich one of the state’s utilities declared bankruptcy because, among other reasons, cappe d POLR rates were substantially below wholesale prices.

300 The distribution utility continues to charge the customer a delivery char ge (a “wires” charge) to cover the transmission and d istribution expense.

301 Thomas L. Welch, Chairman, Maine Public Utilities Commission, UtiliPoint PowerHitters interview (Jan. 24, 2003), available athttp://mainegovimages.informe.org/mpuc/staying_informed/ about_mpuc/commissioners/ph-welch.pdf.

302 See Kenneth Rose, Electric Restructuring Issues for Residential and Small Business Customers , National Regulatory Research Institute Report NRRI 00-10 (June 2000), available at http://www.nrri.ohio-state.edu/dspace/bits tream/2068/610/1/00-10.pdf, for a discussion of adders and their relationship to who lesale prices and headroom for entrants in Pennsylvania and other states.

303 Id.

304 Over time, the shopping credit in Pennsylva nia faded in significance as the competitive rates increased rela tive to POLR servi ce prices due to fuel cost
increases. See the pattern of customer switching in the Pennsylvania profile in Appendix D infra

.

305 FTC Retail Competition Report , State Profiles, Appendix A.

306 See infra New York profile, Appendix D; FTC Retail Competition Report , Appendix A (profile of New York).

307 See infra Illinois profile, Appendix D.

308 See infra New Jersey profile, Appendix D.309 See, e.g. , Maine Public Advocate comments.

310 See infra New York profile, Appendix D.

311 Because the marginal cost of supplying el ectricity varies over the course of the da y and season and because fuel costs sometim es are volatile, efficient retail prices for electricity are more volatile than the prices that customers are used to paying under traditional regulation. Elect ricity prices under traditional regulation typically reflect average costs for electricity and risk manage ment over extended periods. In a retail choice environment, alt ernative suppliers can offer a variety of risk management (hedging) levels that range from full, immediate pass-through of whol esale spot market prices to fixed rates for extended periods. For a discussion of how much hedging is requi red to eliminate portions of volatility, see Severin Borenstein, Customer Risk from Real-Time Retail Electricity Pricing: Bill Volatility and Hedgability , (June 6, 2006) (University of California Energy Institute CSEM Working Paper 155), available at http://www.ucei.berkeley.edu/PDF/csemwp155.pdf. It is important to note that these bundles of electricity and risk management also can constitute efficient retail prices, although they contain a cost component associated w ith the risk management services . If POLR service prices bec ome more volatile, a customer who prefers less risk will have incentives to search for an alternative supplier that offers a price/risk tradeoff – slightly h igher prices but less volatility.

Alternative suppliers will have incentives to offer preferable price/risk alternatives to gain customers. Retail customers can also consider whether onsite generation or other forms of upstrea m vertical integration offer a preferable price/risk combination.

In general, so long as customers are served by alternative supp liers or upstream vertical integr ation is an option, the POLR pr ice is only one component of the average market price.

In a traditional regulatory setting, utilities sometimes offer cust omers a discount if they agree to have their service interru pted during peak demand periods. Removing restrictions to interruptible service rates would allow more customers to improve the match between their risk prefere nces and their electric service. Industrial Coalitions comments (2) at 25.

312 Some commenters observed that cost averaging, cost deferrals , inaccurate cost allocations, double counting of costs, and price caps all can distort consumption and investment that result in loss of consumer welfare. Strategic Energy comments (2) at 6; Constellation comments (2) at 8.

313 The electricity industry has traditionally pr ovided discounts or other form s of assistance to low-inco me families. States may need to exam ine whether the
level of this assistance should be increas ed in response to price increases or gr eater price volatility. National Association of State Utility Consumer Advocates (2). Similarly, firms whose competitors are in areas with stab le or declining prices or dimi nishing price volatility could fac e financial distress, just as if they experienced other types of increased or more volatile input cost s relative to their rivals. Firms with electricity-intensive p roduction processes are likely to be particularly sensitive to increased prices or price volatility. Alcoa comments (2); Industrial Coalitions comments (2) at 26.

314 This statement would need to be qualified to the extent there is market power and to the extent there are unpriced externaliti es such as pollution.

315 See, e.g. , Wal-Mart comments; WPS comments; Illinois Commerce Commission comments; PPL comments; RESA comments.

316 See, e.g. , Wal-Mart comments; RESA comments.

317 See, e.g. , EEI comments.

318 See, e.g. , RESA comments.

319 See, e.g. , Wal-Mart comments at 10-11; Commercial End-Users comments.

320 In Case 03-E-0641, the New York State Public Service Commissi on required New York utilities to f ile tariffs for mandatory real -time pricing (RTP) for large C&I customers. The order observed that “average energy prici ng reduces customers’ awareness of the relationship between their usage and the actual cost of electricity, and obscures opportunities to save on electric bills that would become apparent if RTP were used to reveal varying price signals.” It further notes that
“if a sufficient number of customers reduced load in response to RTP, besides benef iting themselves, the reduction in peak peri od usage would ameliorate extremes in electricity costs for all other customers.”

321 See infra New Jersey profile, Appendix D; RESA comments.

322 See, e.g. , New York Companies comments; Alliance fo r Retail Energy Markets comments; Constella tion comments; PPL comments; RESA comments ; NYPSC comments; Direct Energy comments; Reliant comments; PA O ffice Consumer Advocate comments; Wal-Mart comments; Commercial E nd-Users

comments.

323 Steven Braithwait and Ahmad Faruqui, The Choice Not to Buy: Energy Savings and Policy Alternatives for Demand Response , P UB

. U TILS

. F ORTNIGHTLY (Mar. 15, 2001).

324 James Zolnierek, Katie Rangos, and James Eisner, Industry Analysis Division, Common Carrier Burerau, Federal Communications Co mmission, Long Distance Market Shares, Second Quarter 1998 , at 19-20 (Sept. 1998), available athttp://www.fcc.gov/Bureaus/Common_Carrier/Reports/FCCState_Link/IAD/mksh2q98.pdf; Thomas L. Welch, Chairman, Maine Public Utilities Commission, UtiliPoint PowerHitters interview (Jan. 24, 2003) available at http://mainegov-images.informe.org/mpuc/staying_inf ormed/about_mpuc/commissioners/ph-welch.pdf.325 Economists refer to this phenomenon as “rational ignorance.” Clemson University, The Theory of Rational Ignorance (The Community Leaders’ Letter, Economic Brief No. 29), available at http://www.strom.clemson.edu /teams/ced/econ/8-3No29.pdf.

326 Joskow, Interim Assessment

.

327 See, e.g. , ELCON comments; Progress Energy comments; Constellation commen ts; Pepco comments; PA Office Consumer Advocate comments.

328 In Case 05-M-0858, the New York State Public Service Commi ssion adopted the “PowerSwitch” a lternative supplier referral progra m (first developed by Orange & Rockland) as the model for all utilities in the state.

329 New York State Consumer Protection Board, Comment to the New York St ate Public Service Commission , Case 05-M-0334, Orange & Rockland Utilities, Inc., Retail Access Plan, at 5 (May 2, 2005). The Consumer Prot ection Board indicated that reta il customers who have participa ted in “PowerSwitch” are returning to POLR service at a rate of less than 0.1 percent pe r month. The Board applauded PowerSwitch because it is complete ly voluntary and provides assured initial savings to consumers.

330 This review focuses on original studies – responses and criti ques to these studies are listed under the “Alternate Views” tabl e category.

331 Information in this appendix is derived in large part from – and updates info rmation contained in the FTC Retail Competition Report . Because economic circumstances and state laws and regulations change, regulatory authorities in each state and market participants should be con sulted for more detailed and up-todate information on state re tail choice programs.

332 Average monthly maximum electrical demand on the electric utility’s system during the 6 months equals the customer’s highest m onthly maximum demands in the 12 months ending June 30, 1999.

333 220 I LL

. C OMP

. S TAT . 5/16-104 (West 2001).

334 S.B. 2081 (Ill. 2002) (extending th e transition period from January 1, 2005, to January 1, 2007).

335 Commonwealth Edison Company , Illinois Commerce Commission, Docket No. 02-0479 (March 28, 2003), available athttp://eweb.icc.state.il.us/edocket/reports/view_file.a sp?intIdfile=83392&strc=bd.

336 220 I LL

. C OMP

. S TAT . 5/16-113.

337 Id . at 5/16-110.

338 Id. at 5/16-115.

339 Illinois Commerce Commission, Competition in Illinois Retail Electric Markets in 2005 , Table 2 (May 2006) , available at http://www.icc.illinois.gov/docs/ en/060524garpt16120b.pdf.

340 See S.B. 24 (Ill. 1999) (amending H.B. 362). Illinois Commerce Commission comments at 17-18.

341 220 I LL

. C OMP

. S TAT . 5/16-107.

342 Id . at 5/16-102.

343 Robert Lieberman (ICC Commissioner), Ruminations on Demand Response – a View from Chicago (Oct. 28, 2005), available at http://www.raabassociates .org/Articles/Lieber man_10.28.05.ppt#299.

344 220 I LL

. C OMP

. S TAT . at 5/16-103.

345 Id . at 5/16-108.

346 See 220 I LL

. C OMP

. S TAT . 5/16/-103(d).

347 U.S. Department of Energy, Energy Informati on Administration, Illinois State Profile, Table 4, available at http://www.eia.doe.gov/cneaf/electri city/st_profiles/illinois.pdf.

348 220 I LL

. C OMP

. S TAT . at 5/16-122.

349 Department of Energy, Energy Information Administration, Disclosure Policies

, available athttp://www.eere.energy.gov/gr eenpower/markets/disclos ure.shtml?print.

350 Illinois Commerce Commission Resolution, Response to Governor’s Sustainable Energy Plan for the State of Illinois , Case No. 05-0437 (July 19, 2005),
available at http://eweb.icc.state.il.us/e-docket/reports /view_file.asp?intIdFile=148072&strC=bd.

351 M D

. C ODE A NN

., P UB

. U TIL

. C OS ., §'7-509 (2000).

352 Id. at § 7-507(b).

353 Id. at § 7-507(c).

354 Maryland Public Se rvice Commission, Supplier Authorization Procedures (Mar. 17, 2000), available at http://www.psc.state.md.us/psc/elect ric/supplierauthorization.htm.

355 Andrew Green, Legislators Not Close on Rates , B ALT

. S UN (Apr. 4, 2006).

356 Patrice Hill, Maryland Utilities Designated Near Junk , W ASH

. T IMES (July 12, 2006), available at http://www.washingtontimes.com/functions/p rint.php?StoryID=20060711-103048-5690r.

357 M D

. C ODE A NN

., P UB

. U TIL

. C OS ., § 7-505(d) (2000).

358 Maryland Public Se rvice Commission, Maryland Electric Choice FAQ

, available at www.psc.state.md.us/psc/electric/FAQ/overall.htm.

359 M D

. C ODE A NN

., P UB

. U TIL

. C OS ., § 7-513 (2000).

360 Id. at § 7-501(p).

361 Id. at § 7-512.1 (2000).

362 Id. at § 7-505.b(10).

363 Id. at § 7-505(b)(13).

364 Id. at § 7-508.

365 Id. at 7-505(b).

366 Maryland Public Se rvice Commission, In the Matter of the Commission’s Inquiry into the Provision and Regulation of Electric Service , Order No. 76110 (Apr. 25, 2000).

367 Maryland Public Se rvice Commission, In the Matter of the Commission’s Inquiry into the Provision and Regulation of Electric Service , Order No. 76241 (June 15, 2000). See section below on adver tising restrictions for supplier requirement s to disclose pricing information to cu stomers.

368 M D

. C ODE A NN

., P UB

. U TIL

. C OS ., § 7-505(b) (2000).

369 M ASS

. G EN

. L AWS ch. 164, § 1F(1) (2001).

370 220 M ASS

. C ODE R EGS . 11.05(2) (2001).

371 Massachusetts Department of Telecommunications and Energy, Massachusetts Competitive Electricity Suppliers (February 14, 2006). The current listing of active suppliers for each distribution territory is accessible at http://www.mass.gov/dte/restruct/competition /index.htm#licensed%20competitive%20Suppliers %20and%20electricity%20brokers (under “Generation Service Information.”)

372 M ASS

. G EN

. L AWS ch. 164, § 1B(b) (2001).

373 Id. at § 1G(c)(2).

374 Id. at § 1B(b).375 Id. at § 1B(d).

376 Id. at § 1G(a).

377 Id. at § 1G(e).

378 David L. O’Connor (Commissioner, Ma ss. Division of Energy Resources), Retail Competition: Managing a Difficult Transition (Apr. 6, 2001), at 6, available

at

http://www.nga.org/Files/ppt/ElecOconnor.ppt.

379 Cape Light Compact comments.

380 M ASS

. G EN

. L AWS ch. 164, § 1A(b)(2) (2001).

381 Id. at § 1A(c).

382 Id. at § 1A(b)(1).

383 U.S. Department of Energy, Energy Information Ad ministration, Massachusetts State Profile, Table 4, available at http://www.eia.doe.gov/cneaf/electricity /st_profiles/massachusetts.pdf.

384 U.S. Department of Energy, Energy Information Administrati on, State Electricity Profiles 2002, Massachusetts Electric Power In dustry Generating Capability by Primary Energy Sources, 1993, 1997, and 2002.

385 220 M ASS

. C ODE R EGS . 11.04(12).

386 U.S. Department of Energy, Energy Information Administration, Disclosure Policies

, available at http://www.eere.energy.gov/ greenpower/markets/discl osure.shtml?print.

387 225 Mass. Code Regs. 14.00.

388 New Jersey Board of Public Utilities, In the Matter of the Electric Discount and Energy Compe tition Act of 1999 Customers Acc ount Services Proceeding: Consolidated Billing, Customer Da ta Card, & Competitive Metering. Energy Consu ltant: Amendment to Customer Usage Information P rocess (June 23, 2004),
available at http://www.state.nj.us/bpu/wwwroo t/energy/EX99090676_20040624.pdf.

389 N.J. S TAT

. A NN

. § 48:3-51.3 (2001).

390 New Jersey Board of Public Utilities, Interim Licensing and Registration Standards § 4.e, available at www.state.nj.us/bpu/wwwroot/energy/licensstands.pdf.

391 Jeanne M. Fox (Chair, New Jersey Board of Public Utilities), New Jersey’s BGS Auction: A Model for the Nation , P UB

. U TILS

. F ORTNIGHTLY 16-19 (2005).

392 Press Release, New Jersey Board of Public Utilities, New Jersey ’s Basic Generation Service (BGS) Auction Locks in Electric Pri ces for Retail Customers (Feb. 15, 2002), available at http://www.state.nj.us/bpu/wwwroo t/communication/04-02.pdf.

393 N.J. S TAT

. A NN . § 48:3-57.9.a (2001).

394 Id. at § 48:3-51.3.

395 FTC Retail Competition Report at A80 (citing comments received from the New Jersey Division of the Ratepayer Advocate).

396 N.J. S TAT

. A NN . § 48:3-61.13.i.

397 FTC Retail Competition Report at A78 -A80.

398 New Jersey Board of Public Utilities, New Jersey Electric Statistics (Dec. 2005).

399 FTC Retail Competition Report at A78-A80.

400 N.J. S TAT

. A NN . at § 48:3-59.11.a.

401 FTC Retail Competition Report at A80 (citing comments received from the New Jersey Division of the Ratepayer Advocate).402 New Jersey Board of Public Utilities, Summary Order Including Protective Order in Docket No . EM99030195, Petition of Rockland Electric Company for Approval of the Sale of Orange and Rockland Utilities, Inc.’s Ge nerating Assets and Certain rela ted Property, a Transition Powe r Sales Agreement, and a
Protective Order (June 24, 1999), available at http://www.state.nj.us/bpu/wwwroo t/energy/recodive stord.pdf.

403 U.S. Department of Energy, Energy Information Administration, New Jersey State Profile, Table 4, available at http://www.eia.doe.gov/cneaf/electric ity/st_profiles/new_jersey.pdf.

404 N.J. S TAT

. A NN . § 48:3-85.36.b.

405 U.S. Department of Energy, Energy Information Administration, Disclosure Policies

, available at http://www.eere.energy.gov/ greenpower/markets/discl osure.shtml?print.

406 New York Public Service Commission, Statement of Policy on Further Steps towa rd Competition in Retail Energy Markets (Aug. 25, 2004) (Case No. 00-M0504).

407 New York Public Service Commission, Order Adopting ESCO Referral Program Guidelines and Approving an ESCO Referral Program Subject to Modifications (Dec. 22, 2005) (Case No. 05-M-0858, et al.); NYPSC comments at 17.

408 New York Public Service Commission, Order Instituting Further Proceedings an d Requiring the Filing of Draft Tariffs (Sept. 23, 2005) (Case No. 03-E0641).

409 New York Public Service Commission, In the Matter of Competitive Metering (Feb. 26, 2001) (Case No. 00-E-0165); New York Public Service Commission , In the Matter of Competitive Opportunities Regarding Electric Service (Feb. 26, 2001) (Case No. 94-E-0952).

410 New York Public Service Commission, Opinion and Order Regarding Competiti ve Opportunities for Electric Service (May 20, 1996) (Opinion No. 96-12).

411 Id.

412 New York Public Service Commission, Staff Report on the State of Competitive Energy Ma rkets: Progress to Date and Future Opportunities (Mar. 2, 2006) (Electric and Natural Gas Retail Markets sections I to III).

413 NYPSC comments at 18.

414 New York Public Service Commission , Opinion and Order Regarding Competiti ve Opportunities for Electric Service (May 20, 1996) (Opinion No. 96-12).

415 New York Public Service Commission , PSC Rate and Restructuring Plan Fact Sheets

, available at www.dps.state.ny.us/energyarch.htm#facts.

416 New York Independent System Operator, Inc., Frequently Asked Questions

, available at www.nyiso.com/public/services/customer_relations/faqs/index.jsp.

417 U.S. Department of Energy, Energy Information Administration, New York State Profile, Table 4, available at http://www.eia.doe.gov/cneaf/electric ity/st_profiles/new_york.pdf.

418 New York Public Service Commission , Unifor m Retail Access Business Practices, Appendix A, Customer Information (Apr. 14, 1999), at www.dps.state.ny.us/doc5743_appendix_a.pdf (Case No. 98-M-1343). For information on the acceptance of uniform retail access bu siness practices in New York, see www.dps.state.ny.us/ubr.htm.

419 U.S. Department of Energy, Energy Information Administration, Disclosure Policies

, available at http://www.eere.energy.gov/ greenpower/markets/discl osure.shtml?print.

420 Pennsylvania Public Utility Commission, Pennsylvania Electric Choice, Q&A

, available at http://www.puc.state.pa.us/utilitychoice.

421 Pennsylvania Public Utility Commission, Pennsylvania Electric Choice, How to Shop Guide

, available at http://www.puc.state.pa.us/utilitychoice.

422 Letter from the Pennsylvania Public Utility Commission to the Ener gy Association of Pennsylvania approving an extension of a s uspension of work of the Electronic Data Exchange Working Group as it relates to the implementation of competitive me tering, Docket No. P-00021957 (Feb. 5, 2004).

423 66 P A

. C ONS

. S TAT . § 2809.A (2001).

424 Id. at § 2804.4.

425 Comments of the Pennsylvania Public Utility Commission to the FTC Retail Competition Report (Apr. 9, 2001).426 Ahmed Kaloko (Chief Economist, Pennsylvania Public Utility Commission), Power 99–California & Pennsylvania Retail Market Development

.

427 66 P A

. C ONS

. S TAT . § 2807.E (2001).

428 Id.

429 Id.

430 The order is available at http://www.puc.state.pa.us/PcDocs/578097.doc.

431 66 P A

. C ONS

. S TAT . § 2808.A, B (2001).

432 Pennsylvania Public Utility Commission, Electric Choice Frequently Asked Questions (A re there any penalties for changing suppliers?)

, available at http://www.puc.state.pa.us/utilityc hoice/faq.aspx?ut=ec#4.

433 66 P A

. C ONS

. S TAT . § 2804.5 (2001).

434 Pennsylvania Public Utility Commission, Bureau of Conservation, Economics , and Energy Planning, Electric Power Outlook for Pennsylvania:1999-2004 (July 2000).

435 Press Release, PJM Interconnection, LLC, Allegheny Power and PJM File with FERC to Create PJM West (Mar. 15, 2001), available at www.pjm.com/contributions/news-releases/ 2001/20010315-ap-pjm-file-with-ferc.pdf.

436 U.S. Department of Energy, Energy Information Ad ministration, Pennsylvania State Profile, Table 4, available at http://www.eia.doe.gov/cneaf/electricity /st_profiles/pennsylvania.pdf.

437 52 PA. CONST. STAT. § 54.8 (2001).

438 Id. at § 54.122.2.

439 Comments of the Pennsylvania Utility Commission to the FTC Retail Competition Report (Apr. 9, 2001).

440 U.S. Department of Energy, Energy Information Administration, Disclosure Policies

, available at http://www.eere.energy.gov/ greenpower/markets/discl osure.shtml?print.

441 T EX

. U TIL

. C ODE A NN . § 39.102 (2001).

442 Public Utility Commission of Texas, Scope of Competition in Electric Markets in Texas (January 2005) at 36-38, available at http://www.puc.state.tx.us/electric/report s/scope/2005/2005sc ope_elec.pdf.

443 T EX

. U TIL

. C ODE A NN . § 39.352-55 (2001).

444 Available at http://www.puc.state.tx.us/electric/repor ts/RptCard/rptcrd/a ug05rptcrd.pdf.

445 Tex. Util. Code A nn. at § 39.052.

446 Id. at § 39.202.

447 Public Utility Commission of Texas, Scope of Competition in Electric Markets in Texas (January 2005), available at http://www.puc.state.tx.us/electric/report s/scope/2005/2005sc ope_elec.pdf.

448 Id. at 24.

449 Public Utility Commission of Texas, Sub. Rules § 25.43.

450 Public Utility Commission of Texas, Project No. 31416, Evaluation of Default Service for Residential Custom ers and Review of Rules Relating to the Price to Beat and Provider of Last Resort ; Reliant comments.

451 Public Utility Commission of Texas, Texas Electric Choice, Electricity Information-FAQ’s

, available at http://www.powertochoose.org/y ourrights/q_changing.asp.452 Although the System Benefit Funds are being collected, the Legi slature did not appropriate any fund for a low-income discount or for customer education in the 2005 session. Some REPs are continuing to offer low-income discounts and other benefits to these customers on a voluntary basis. Funding will be reconsidered in the 2007 legislative session; Reliant comments.

453 Tex. Util. Code A nn. at § 39.051.

454 Id. at § 39.105.

455 Id. at § 39.153.

456 Id. at § 39.154.

457 Public Utility Commission of Texas, Electric Competition-Fostering Competition

, available at www.choiceenergyservices.com/residential/pdf/Competition.pdf.

458 ERCOT is not electrically synchronized with the Eastern or Western Interconnects.

459 Electric Reliability Council of Texas, The Market Guide: A Guide to How the Electric Reliability Council of Texas (ERCOT) Facilitates the Competitive
Power Market (Feb. 22, 2001).

460 U.S. Department of Energy, Energy Informati on Administration, Texas State Profile, Table 4, available at http://www.eia.doe.gov/cneaf/electri city/st_profiles/texas.pdf.

461 Reliant comments; Public Utility Commission of Texas, Consumer Protections in a Competitive Electric Market

, available at http://www.powertochoose.org/public ations/consumer_brochure.pdf.

462 U.S. Department of Energy, Energy Information Administration, Disclosure Policies

, available at http://www.eere.energy.gov/ greenpower/markets/discl osure.shtml?print.

463 The consumer brochure on electricity offer labeling is available at http://www.powertochoose.org/publi cations/efl_broc hure.pdf.

464 Reliant comments.

465 Public Utility Commission of Texas, Electric Restructuring to Improve Air Quality

, available at www.puc.state.tx.us/nrelease/2000/082400.cfm.



# The Task Force published the draft final report in the Federal Register for public comment on June 13, 2006, 71 Fed. Reg. 34,083 (2006). The notice accompanying the draft requested comments on
the Task Force observations. About 80 different en tities provided comments and suggestions on the draft report. These commenters are listed in Ap pendix A. Draft report comments are available for public review online in the Task Force docke t maintained by FERC under Docket No. AD05-17-
000.

In preparing the draft report, the Task Force conducted fu rther research and reviewed the
information from comments and interviews.

C. The Goal of Increasing Competition in Electric Power Markets

Federal and several state policymakers generally intr oduced competition in the electric power industry to overcome perceived shortcomings of traditional cost-bas ed regulation. In compe titive markets, prices are expected to guide consumption a nd investment decisions, leading to more economically efficient investments and lower prices than un der traditional cost of service monop oly regulation. More specifically, market-based, as compared to regulated, pricing of elect ricity would be expected to more accurately reflect the underlying costs of production. These prices should t hus align the price of el ectricity with the value customers place on electricity, leading to a more effi cient allocation of electr ical resources and lower overall prices than would be the case in the absen ce of market-based prices. These price signals should

# also serve to increase price duri ng periods of scarcity, thereby elic iting reductions in consumption, moderating market power and improving reliability.

D. Observations on Competition in Wholesale Electric Power Markets

Congress has taken a number of step s to facilitate competition in whol esale electric power markets. The Public Utility Regulatory Policies Act of 1978 (PURPA), 5 the Energy Policy Act of 1992 (EPAct 1992),6 and EPAct 2005 promoted competition by lowering entry barriers and increasing tr ansmission access. Federal electricity policies have sought t o strengthen competition but continue to rely on a combinat ion of competition and regulation.

In assessing wholesale competition, the Task Force addressed th e following question: Has competition in wholesale markets for e lectricity resulted in sufficient generation supply and transmission to provide wholesale customers with the kind of choice that generally is associat ed with competitive
markets?

To answer this question, the Task Force examined whether competition has elicited the consumption and investment decisions gene rally associated with competitive wholesale markets.

The Task Force found this question challenging to address due to a number of complicating factors. The various U.S. regional w holesale electric power markets developed differently since the introduction of widespr ead wholesale competition. There were significant regional regu latory and structural differences in the electric power industry when Congress enacted EPAct 1992 and when FERC adopted Order No. 8887 in 1996, manda ting nondiscriminatory access to the transmission grid. Even today, th e regional markets have different features and characteristic s. As discussed in Chapter 3, these differences make it difficu lt to identify and separate th e determinants driving consumption and investment dec isions and thus make it
difficult for the Task Force to evaluate the degree to which more competitive market s have influenced such decisions.

Despite the difficulty of directly answering the question at ha nd, the Task Force’s examination of wholesale competition did yi eld useful observations,
as outlined below.

1. Wholesale Market Structures

Wholesale markets exhibit regional differences and generally rely on one of two types of market st ructures to support wholesale transactions.

a . One approach to competition in wholesale markets is to base trades exclusively on bilateral sales negotiated directly between suppliers and scheduled through individual, non-regionalized transmission owners. This approach predominates in the Northwest and Southeast. This tra ditional trading format allows for somewhat independent operation of transmission control areas and, in the view of some market participants, better ac commodates historical contracts. However, prices and terms are more transaction-speci fic and, for some timeframes, less publicly available than in o rganized markets, which may result in less efficient generation dispatch. It can be di fficult for system operators to coordinate transmission efficien tly in these systems, as congestion costs and impacts are not readily apparent. A lack of centralized, shared information about generation dispatch and trades on interconnected systems requires a transmission owner to hold part of its transmission capacity as unused “reserves” to ensure reliable system operation. In some of these markets, wholesale customers have difficulty gaining unqualified access to the transmission needed to access competitivel y priced generation, thus limiting their ability to shop for least-cost supply options.

b. Another approach to wholesale competition relies on entities that are independent of market participants to control operation of all transmission facilities across a wide region and to operate trading markets – regional transmission organizati ons (RTOs) or independent syst em operators (ISOs). Variations of this approach predominate in the Northeast, Mid-Atlantic, Midwest, Texa s, and California. The market designs in these regions provide participants with guaranteed physical access to the transmission system (subject to transmission security constraints). These customers are responsible for the cost of that access (if they choose to participate), and thus are exposed to congestion price risks. This more open ac cess to transmission can increase competitive options for wholesale customers and suppliers as compared to most bilateral markets. The price transparen cy in these regional organized markets can increase the efficiency of the trading pro cess for sellers and buyers and can give clear price signals in dicating the best place and time to build new generation. Concerns have been raised, ho wever, about the inability to obtain long-term transmission access at predictable prices in these markets and the impact that this can have on access to co mpeting suppliers and incentives to constr uct new generation. So me customers have raised concerns about high and sometimes volatile commodity price levels in these markets.

2. Generation Investment in Competitive Wholesale Markets

New generation investment has varied signi ficantly by region since the adoption of ope n access transmission and the growth of c ompetition. The Task Force examined comments on how competition policy choices have aff ected investment decisions of both buyers and sellers in whol esale markets. A number of issues emerged. One was the difficulty of raising capital to build facilities whose re venue streams ar e affected by changing fuel prices, demand fluctuations, and the potential for regulatory intervention. A related theme was the investment dampening effects of a perceived lack of longterm contracting options for generation and transmission. Overall, the Task Force id entified several factors that affect inves tment decisions in wholesale power markets.

a. Availability of Long-Term Contracts. Both generators and wholesale customers cited long-te rm contracts as critical in obtaining financing for new generation and ensuring adequate supplies for retail loads at pred ictable prices. Several explanations were offered for a perc eived lack of long-term contracting opportunities. First, short-term market conditions, pa rticularly in organized markets with uniform price auctions, may be affecting the availability, pricing, and terms for long-term power supplies under bilateral contracts. Base-load and mid-merit generators ma y see relatively high profits in short-term markets where cleari ng prices are often set by higher cost mid-m erit and/or peaking plants reliant on oil or natural gas, particularly when fuel prices rise. Second, generators and marketers may be unwilling to enter into long-term supply contracts because of l imited opportunities to hedge the potential risks of long-term commitments in highly volatile electricity markets. Third, both generators and customer s cited continuing

### uncertainties over availability and certainty of long-term deliver y options (transmission). Fourth, long-term contracts may be difficult to arrange
because of inherent uncertainties associated with federal and st ate regulation of these contracts. Finally, the uncertainty th at distribution utilities face over how much supply they will need to procure for customers th at have an option to switch can also discourage utilities from s igning long-term

contracts.

b. Capital Investment. Potential entrants to generation market s must be able to convince capital market s that generation is a viable profitable undertaking. The availability of long-term contracts, as noted above, is critical to the ability of nonutility generators to s ecure capital for new investment. Transmission access can be vital to supporting comp etitive options for market pa rticipants. Recently, capital for large investment projects
has flowed to traditional utilities more than to merchant generators. Th is shift in part reflects reduced profitability of man y merchant generators in
recent years.

c. Transmission Infrastructure. The availability of transmission is often key in determining whether a generating facility is likely to be profitable and, thus, elicit investment. Despite legislative and regulatory efforts to expand transmission access for competitive generation a nd to reduce the potential for discrimination, the perception of disc rimination persists. Commenters reported that such discrimination can increase deliv ery risk because purchasers fear their transmission transactions could be termin ated for anticompetitive reasons. One response to this risk is to turn over operation of the regional transmission grid to ISOs and RTOs. Another is to ad opt additional reforms to the Order 888 Open Access Transmission Tariff (OATT). New federal authorities provided by EP Act 2005 also address transmi ssion infrastructure issues.

3. Pricing and Entry in Wholesale Markets for Electricity

Several options may be used to elicit adequate supply in wholesale markets:

a. One possible, but controversial, way to spur entry is to allow wholesale price spikes when suppl y is short. The profits reali zed during these price spikes can provide incentives for generators to invest in new ca pacity. However, if wholesale customers have not hedged (or ca nnot hedge) against price spikes, then these spikes can lead to adverse customer reactions. Unfortunately, it can be difficult to distinguish high prices due to the exercise of market power from those due to genuine scarcity. Past price sp ikes have caused regulators and various wholesale market operato rs to adopt price caps in certain markets. Although price caps may limit price spikes an d some forms of market manipulation, they can also limit legi timate scarcity pricing and impede incentives to build generation in the face of scarcity. Not all the caps in place may be necessary or set at approp riate levels.

b. “Capacity payments” also can help elicit new supply and help moderate price volatility. Wholesale customers pay suppliers to assure the availability of generation when needed. Where there are capacity payments in organized wholesale markets, however, it is difficult for regu lators to determine the appropriate level of capacity payments to spur entry without over-t axing market participants and customers. Also, capacity pay ments may elicit new generation when transmission or other responses to price changes mi ght be more affordable and equally effective. Depending on their format, capacity payments also may discourage entry by payi ng uneconomical generation to continue runni ng when market conditions otherwise would have led to not running, or even decommissioning.

c. Expanding transmission capacity may encourage entry of new genera tion and/or the more efficient use of existing generation. H owever, transmission owners may resist building transmission facilities if they also own generation and if the proposed upgrades would increase competition in their sheltered markets. Another challenge is that it is of ten difficult to assess the beneficiaries of transmission upgrades, who should pay for the upgrades, and how regulators should provide for recovery of the investment through rates. This regulatory challenge may cause uncertainty about the price for transmission and about return on investment both for new generators and for transmission providers.

d. Another option for ensuring adequate generation supply is to exercise traditional regulatory authority over electricity genera tors/suppliers. In this situation, regulated monopoly utility providers operate under an oblig ation to plan and secure adequate generation to meet the needs of their customers. Regulators allow the utilities to earn a fair rate of return on their investment, thereby encouraging utility investment. This approach is not without risk to the utility, as regulators have authority to disallow excessive costs. Furthermore, these traditional methods are imperfect and can in some cases lead to overinvestment, underinvestment, excessive spending and unnecessa rily high costs. These met hods can distort both investment and consumption
decisions.

E. Observations on Retail Market Competition

In the early 1990s, several states with high electricity prices began exploring opening retail electric service to competition. While customers would choose their supplier, the local distribution utility would s till handle the delivery of electricity. Retail competition was e xpected to result in lower retail prices, innovative services and pricing options . It also was expected to shift the risks of assuring adequate new generation c onstruction from ratepayers to competitive market providers. By 2006, 16 states and the Dist rict of Columbia had restructured retail electric service and allowed competitive suppliers to provide service to some, if not all, retail customers at prices set in the market.

Most restructured states required the local utility to continue to offer service under regulated “provider of last resort” (POL R) rates for all retail customers who did not switch suppliers or who lost or discontinue d competitive service. These PO LR rates were typically fixed for extended periods of time. In many of these states, vertically integrated utilities di vested or transferred their generation assets as part of rest ructuring plans. As a result, in these states the retail load serving utili ties obtain electricity from wholesale market s to meet the needs of their retail cust omers, including POLR obligations. Some states also require d that the utilities join RTOs.

1. Retail Competition Experience in Profiled States

The Task Force examined in detail the imp lementation of retail competition in Illinoi s, Maryland, Massachusetts, New Jersey, Ne w York, Pennsylvania, and Texas. Common goals for retail competition included:

lower electricity prices than under traditional cost of servi ce regulation through retail suppliers’ (and eligible customers’) access to competitive wholesale markets; better service and more options for customers; technological innovation and new products and services for consumers; and

### environmental improvements.

In most profiled states, retail competition has not developed as e xpected for all customer classes. Few residential customers h ave switched to alternative providers. (Exceptions include Massachusetts, New York, and Texas. ) In most of the profiled states, few residential customers have a wide variety of alternative suppliers and pricing options. Commercial and industri al (C&I) customers have more choices and options, but in sev eral states large industrial customers have become increasingly dissatisfied with re tail market prices. To the extent that multiple suppliers se rve retail customers, prices have not decreased as expected, and the range of new options and services is often limited.

At the same time, there is some evidence that alternative supp liers have offered new retail products, including “green” product s that are more environmentally friendly for residential and non-residential cust omers and customized energy management products for large C&I customers.

Legislative or regulatory limits on POLR prices have hampered entry by competitive suppliers in retail markets. In the profile d states, regulators often capped the POLR electricity price for “trans itional” multi-year periods that are now just ending. Several states also required price reductions for POLR service below existing regulated rates (in order to proxy the e xpected benefits of competition). Over time, these capped and d iscounted POLR prices fell below prevailing wholesale market price levels. These POLR price caps have the unintended effect of dampening competitive price signals and discouraging entry by competitive suppliers.

The POLR rate caps and the sharp increase in fossil fuel cost s affecting all retail suppliers across the country, complicate Ta sk Force efforts to discern any price differences attributable to the introduction of comp etition. The implementation of retail competition is a relativel y new exercise, and retail competition policies involve a number of unresolved issues (inc luding regulatory issues) that can inhibit vigorous competition. It should be easier to evaluate the impact of restructuring in retail electricity ma rkets once some of these issues have been resolved.

2. State Retail Competition Issues

Initial POLR rate discounts, freezes and caps have been lifted in several states, and caps in several more expire in 2006 and 2 007. When the rate caps

expire, states must decide whether to con tinue POLR for all customer classes, how POLR providers will secure adequate generatio n supplies, 

# and how to price POLR service for each class. The Task Fo rce identified some key issues that states may wish to consider as they evaluate their retail competition and POLR policies.

a. Function of POLR Pricing . If regulated POLR service is to be a proxy for efficient price signals, POLR rates must closely approximate a competitive price, which is based on supply and demand at any given time. If the POLR service price does not closely ma tch the competitive price, it is likely to distort consumption and investment decisions.

b. Adjustments to POLR Rates . If POLR prices remain fixed while prices for fuel and wholesale power are rising, customers may experience rate shock when the transition period ends. This can create public pressure to continue the fixed POLR rates at belo w-market levels. One regulatory response may be to phase in the price increase gradually, by deferring recovery of part of th e supplier’s costs. This approach reduces rate shock, but it is likely to distort retail electricity markets both in the short term (when costs are deferred) and in the long term (when the deferred costs are recove red). The better pr actice is to make frequent adjustments to the cap (at least to reflect ch anges in fuel costs) or to abandon the cap altogether and use a competitive process to procure supply.

c. Nature of POLR Service . States have different policy goals for establishing and maintaining POLR service in competitive retail markets. These policies can affect entry of competitive retail suppliers. POLR service (or an equivalent provision) th at is limited to an obligation to se rve customers of a supplier that has left the market, while the customer obt ains another supplier, is the least in trusive form of POLR service. It also is consistent with protecting consumers against una nticipated loss of electric service. POLR service that goes beyond short-term access to the wholesale sp ot market involves providing a bundle of services that electricity marketers also co uld provide. A more expansive vers ion of POLR service may hamper development of alternative suppliers. The economic rationale for maintaining a POLR service obligation usually is limited to trying to correct market imperfections. If a state adopts a more expansive version of POLR service, it should period ically review the rationale for continuing the service.

d. Treatment of Different Customer Classes . States may find that effec tive retail competition programs require different POLR service designs for different customer classes. Large C&I customers are logical leaders for retail choice because of their familiarity with energy procurement processes and because they
are comfortable with decisions to ad just input use based on input prices. State policies ha ve allowed POLR

# rates for these large customers to reflect wholesale spot market prices more than POLR rates for residential customers. This approach generally has led large customers to switch suppliers more than small customers have. Also, more suppliers have tried to solicit these large customers.

e. Consumer Education . Customers may find it difficult to find co mpetitive supplier offers in the first place and to understand the terms and c onditions of those offers. It also is unclear whether the perceived potential cost savings are sufficient to give customers incentives to undertake the effort to find this information. For these smaller, less sophisticated s hoppers, issues of awareness and access to comparative pricing information should be addressed as retail customer choice is implemented.

f. Customer Aggregation . Competitive provider interest in resi dential and small business customers has been slow to develop in most stat es. While POLR policies have dampen ed price signals, the higher perunit costs of marketing and switching for small custom ers may also be a disincentive for providers. Retail aggregation programs can reduce shopping burdens a nd uncertainties for indivi dual customers and lower customer acquisition costs for competitive providers. Several states have appr oved customer aggregation plans as an alternative ap proach to developing retail competition. Opt-out customer aggregations may be worth considering because they can minimize trans action costs without lim iting customer choice.

g. Procurement of POLR Supply . In all retail competition states, a substantial number of retail customers continue to depend on POLR service. Some states have used, or are pr oposing to use, auctions to procure POLR supply. Auctions may allow retail customers to get the benefit of compe tition in wholesale markets as suppliers compete to supply the necessary load. Various auction processe s have been suggested.

h. Switching Costs . Switching is important for retail electricity competition to work. Rules and procedures for switching should allow customers to switch easily but should deter unauthori zed switching (slamming).

Section E of Chapter 4 presents a description of va rious approaches to overcoming some of the abovementioned difficulties and to encouraging competition in retail electricity markets.
CHAPTER 1 INDUSTRY STRUCTURE, LEG AL AND REGULATORY BACKGROUND, TRENDS AND DEVELOPMENTS

For almost all of the 20th Century, the electric power industry was dominated by regulated monopoly utilities. Beginning in the late 1960s, a number of technological, economic, regulatory, and political developments led to fundamental changes in the structure of the industry.

In the 1970s, vertically integrated utility companies (i nvestor-owned, municipal, orcooperative) controlled over 95 percent of the electric genera tion in the United States. Typically , a single local utility sold and delivered electricity to retail cust omers under an exclusive franchise regu lated under state law. Today, the electric power industry includes bo th utility and nonutility entities, including many new companies that produce, market and deliver electric energy in wholes ale and retail markets. As a result of industry changes, by 2004 electric utilities ow ned less than 60 percent of electric generating capacity. Increasingly, decisions affecting retail customer s and electricity rates are split among federal, state, and new private, regional entities. This chapter highl ights structural changes in the indus try since the late 1960s. It provides an overview of the important legislativ e and regulatory changes, as well as trends that have contributed to increased competition.

# A. Industry Structure and Regulation

Participants in the electric power sector in the Unit ed States include investor-owned utilities and electric cooperatives; federal, state, and m unicipal utilities, public utility di stricts and irriga tion districts; cogenerators and onsite generators ; and nonutility independent power pr oducers (IPPs), affiliated power producers, power marketers, and independent transmissi on companies that generate, distribute, transmit, or sell electricity at w holesale or retail.

In 2004, 3,276 regulated retail electric providers supplie d electricity to over 136 million customers, with retail sales totaling almost $270 billion. Retail custom ers purchased more than 3.5 billion megawatt hours (MWhs) of electricity. Active retail electric prov iders include utilities, federal agencies, and power marketers selling directly to retail customers. Thes e entities differ greatly in size, ownership, regulation, customer load characteristics, a nd regional conditions. These differe nces are reflected in policy and regulation. Tables 1-1 to 1- 5 provide selected statistics for the elec tric power sector by type of ownership in 2004 based on information reported to the Depa rtment of Energy (DOE), Energy Information Administration (EIA).

1. Investor-Owned Utilities

Investor-owned utility operating companies (IOUs) are private, shareholder-owned companies ranging from small local operations serving a retail customer base of a few thousand to giant multi-state holding companies serving millions of customers. Most IOUs are or are part of a vertically integrated system that owns or controls generation, transmission, and distributi on facilities/resources to meet the needs of retail
customers in their franchise serv ice areas. Many IOUs have under gone significant restructuring and reorganization under state retail competition plans over the past decade. As a result, many IOUs no longer own generation, but those that sell electric power to retail customer s must procure electricity from wholesale markets. See Chapter 4 and Appendix D of this document for details on state experience with retail competition. IOUs continue to be a majo r presence. In 2004 there were 220 IOUs serving approximately 94 million retail distribution customers, accounting for 68.9 percent of all retail customers and 60.8 percent of retail electricity sales. IOUs directly owned about 39.6 pe rcent of total electric generating capacity and accounted fo r 44.8 percent of generation for retail and wholesale sales in 2004. IOUs provide service to retail cust omers under state regulation of territo ries, finances, operations, services,
and rates. States that have not restructured retail service generally regulate retail rates under traditional
bundled cost-of-service rate methods. In states that have re structured IOUs, distribu tion services continue to be provided under monopoly cost-of- service rates, and retail customer s obtain generation service either at market rates from alternative competitive providers or at regulated “provider of last resort” (POLR) rates from the distribution utility or anot her designated POLR service provider. IOUs serve retail customers in every state but Nebraska.

Under the Federal Power Act (FPA), 8 the Federal Energy Regulatory Commission (FERC) re gulates wholesale electricity transactions (sales for resale) and unbundled transmission activities of IOUs as “ public utilities” engaged in inters tate commerce. The exceptions are IOUs that do not have direct
interconnections with utilities in other states that allow unimpeded flow of electricity across systems. Thus, IOUs in Alaska, Hawaii, and the Electric Reliability Council of Texas (ERCOT) region of Texas genera lly are not subject to FERC jurisdiction.

2. Public Power Systems

The more than 2,000 publicly owned power systems include local, municipal, state, and regional public power system s. These providers range from tiny municipal distribution companies to large syst ems such as the Los Angeles Department of Water and Power. Publicly owned system s operate in every state but Hawaii. About 1,840 of these systems are cities and municipal governments that own a nd control the day-to-day operation of the ir electric utilities.9 Public power systems served over 19.6 million retail customers in 2004, or about 14.4 percent of all custom ers. Together, they genera ted 10.3 percent of the nation’s power in 2004, accounted for 16.7 percent of total electricity sa les and owned about 9.6 percen t of total generating capacity. Many public systems are distribution-only utilities that purchase, rather than generate, power. According to th e American Public Power Association, ab out 70 percent of public power retail sales were met from wholesale power purchases, including pu rchases from municipal joint action agencies by the agencies’ member systems. Only about 30 percent of the electricity for public power retail sales comes from power generated by a utility to service its own native l oad.10 Publicly owned utilities, thus, depend overwhelmingly on transm ission and the wholesale market to bring electricity to their retail customers.Regulation of public power systems varies among states. In so me, the public utility commission exercises jurisdiction in whole or part over operations and rates of publicly-owned systems. In most states, public power system s are regulated by local government s or are self-regulated. Mun icipal systems usually are governed by a local city council or an inde pendent board elected by voters or appointed by city officials. Other public power s ystems are operated by public utility districts, irrigation districts, or special state authorities.

On the whole, state retail restructuring initiatives did not affect retail services in public systems. However, some states al low public systems to adopt retail choice alternatives voluntarily.

3. Electric Cooperatives

Electric cooperatives are privately-owned, non-profit electric syst ems owned and controlled by the members they serve. Members vote directly for the board of directors. In 2004, 884 electric distributi on cooperatives provided retail electric se rvice to almost 16.6 million customers. In addition, anot her 65 generation and transmission cooperatives (G&Ts) own and ope rate generation and transmission and secure wholesale power and transmission servic es from others to meet the needs of their distribution cooperative memb ers’ retail customers and other rural native load customers. G&T systems and their members engage in joint planning and power supply operations to achie ve some of the savings available under a vertically integrated utility structure. Electric cooperatives operate in 47 states. Most were originally organized and financed under th e federal rural electrification progr am and operate in primarily r ural areas. Cooperatives provide electric service in all or parts of 83 per cent of the counties in the United States.11

In 2004, electric cooperatives sold more than 345 million MWhs, serv ed 12.2 percent of retail cu stomers, and accounted for 9.7 percent of electricity sold at retail. Nationwide electric cooperatives ge nerate about 4.7 percent of total electri c generation and own a pproximately 4.2 per cent of generating capacity.

While some cooperative systems generate their own power and sell power in excess of thei r members’ needs, most G&Ts and distrib ution cooperatives are net buyers. Cooperatives nationwide generated onl y about half of the power needed by their retail customers. They secured approxi mately half of their power needs from other wholesale suppliers in 2004. Although cooperatives own and operate transm ission facilities, almost all rely to some extent on transmission owned by others to deliver power to their customers.

Regulatory jurisdiction over cooperatives varies among states. So me states exercise considerab le authority over rates and oper ations, while others exempt cooperatives from state regulation. In a ddition to state regulation, cooperatives w ith outstanding loans under the Rural Elect rification Act of 193612 are subject to financial and operating require ments of the Rural Utilities Service (RUS), Depa rtment of Agriculture. RUS must approve borr owers’ long-term wholesale power contracts, operating agreements, and transfers of assets. Cooperatives that have repaid th eir RUS loans and that engage in wholesale sales or provide transmission services to others have been regulated by FERC as public utilities under the FPA. EPAct 2005 gave FERC additional discretionary jurisdiction over transmission services provided by larger electric cooperatives.

4. Federal Power Systems

Federally-owned or chartered power systems include the federal power marketing administrations (PMAs), the Tennessee Valley Aut hority (TVA), and facilities operated by the U.S. Army Corps of Engineer s, the Bureau of Reclamation, the Bureau of Indian Affa irs, and the International Wa ter and Boundary Commission. Wholesale power from federal facilities (primarily hydroelectric dams) is marketed through four federal power marketing agencie s: Bonneville Power Administration, Western Area Power Administration, Southeastern Po wer Administration, and Southwestern Power Administration. T he PMAs own and control transmission to deliver power to wholesale a nd direct service customers. They also may purchase power from others to meet contr actual needs and may sell surplus power as available to wholesale markets. Existing legi slation requires that the PMAs and TVA give preference in sellin g their generation to public power systems and to rural electric cooperatives.

Together, federal systems have an installe d generating capacity of appr oximately 71.4 gigawatts (GW) or about 6.9 percent of to tal capacity. Federal systems provided 7.2 percent of the nation’s power generation in 2004. A lthough most federal power sales ar e at the wholesale level, s ome are made to end users. Federal systems nationwide directly served 39,845 retail customer s in 2004, mostly industrial cust omers and about 1.2 percent o f retail load.

5. Nonutilities

Nonutilities are entities that generate, transmit, or sell electr ic power but do not operate regulated retail distribution fran chises.13 They include wholesale nonutility affiliates of regulated utilities, merchant generators , and qualifying facilities (QFs).14 They also include power marketers that buy and sell power at wholesale or retail but that do not own ge neration, transmission, or distribution f acilities. Independent transmission compani es that own and operate transmission facilities but do not own generati on or retail distribution facilities or sell electricity to retail customers are also included in this category for EIA reporting purposes.

Non-QF wholesale generators enga ged in wholesale power sales in interstate co mmerce are subject to FERC regulation under the FP A. Power marketers selling at wholesale are also subject to FERC oversight. Power market ers selling only at retail are subject to state jurisdiction and oversight in states where they operate. FERC regulates interstate transmission serv ices of independent transmission companies under the FPA. Such companies also may b e organized and regulated as utilities where they are located for planning, siting, permitting, and other purposes.

As retail electric providers, 152 power marketers reporting to EI A served about 6 million retail cu stomers or about 4.4 percent of all retail customers and reported revenues of over $28 billion, on about 11.6 percent of retail electricity sold.

Nonutilities are a growing presence in the industry. In 2004, nonutilities owned or controlled approximately 408,699 megawatts (MWs) or 39.6 percent of all electric generation capacity, compared to about 8 percent in 1993. About half of nonutility generation capacity is owned by no nutility affiliates or subsidiaries of holding companies that also own a regulated electric utility. 15 Nonutilities accounted for about 33 percent of generation in 2 004. Tables 1-1 through 1-5
summarize this information.

Table 1-1. U.S. Retail Electric Providers, 2004



## Ownership Number of Electricity
Providers Percent of
Total Number of Customers Percent of
Total

## Full-Service Delivery only* Total

Publicly-owned
utilities 2,011 61.4 19,628,710 6,125 19,634,835 14.4

Investor-owned
utilities 220 6.7 90,970,557 287,9114 93,849,671 68.9

Cooperatives 884 27 16,564,780 12,170 16,576,950 12.2

Federal Power Agencies 9 0.3 39,843 2 39,845 0.03

Power

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

Notes : *Delivery-only customers represent the number of customers in a utility’s service territory that purchase energy from an altern ative supplier.

** Ninety-eight percent of all power market ers’ full-service customers are in Texas. Investor-owned utilities in the ERCOT reg ion of Texas no longer report
ultimate customers. Their customers are counted as full-servi ce customers of retail electric providers (REPs), which are class ified by the Energy Information Administration as power marketers. The REPs bill customers for full-service and then pay the IO U for the delivery portion. REP s include the regulated distribution utility’s successor affiliated retail electric provider that assumed service for all retail customers that did not select an alternative provider. Does not
include U.S. territories.

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



# Table 1-2. U.S Retail Electric Sales, 2004

Sales to Ultimate Consumers in Thousands of MWhs

Ownership 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 60.8

Cooperatives 344,267 890 345,157 9.7

Federal Power Agencies 41,169 352 41521 1.2

Power Marketers 207,696 203,202 410,898 11.6

Total 3,267,089 27,3269 3,540,358 100.0

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



# Table 1-3. U.S. Retail Electric Providers, 2004, Revenues from Sales to Ultimate Consumers

## Ownership Sales in $ millions
Full-Service Energy only * Delivery Total ** Publicly-owned utilities $37,734 $5,787 $27 $43,548
Investor-owned utilities $162,691 $128 $8,746 $171,565 Cooperatives $25,448 $37 $7 $25,492 Federal Power Agencies $1,211 $13 $1 $1,224
Power Marketers $17,163 $11,000 0 $28,162
Total $244,247 $16,965 $8,761 $269,992

Notes : * Energy-only revenue represents reve nue from a utility’s sales of energy out side of its own service territory.

** Total shows the amount of revenue each provider group receives from both bundled (full-service) and unbundled (retail choice ) sales to ultimate customers. Eighty-five percent of the energy -only revenue attributed to publicly-owned utilitie s represents revenue fr om energy procured f or California’s investor-owned utilities by the California Department of Water Resources Electric Fund. Ninety-eight percent of power marketers’ full-service sales and revenues occur in Texas. IOUs in the ERCOT region of Texas no longer repor t sales or revenue to ultimate consumers on EIA 861.

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



# Table 1-4. U.S. Electricity Generation, 2004

Thousands of MWhs and Percent of Total

Ownership Generation Percent of Total

(thousands of MWhs)

Publicly-owned utilities 397,110 10.3

Investor-owned utilities 1,734,733 44.8

Cooperatives 181,899 4.7

Federal Power Agencies 278,130 7.2

Power Marketers 42,599 1.1

Nonutilities 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 EIA906/920 for generation. Data are for 2 004, adjusted for joint ownership.



# Table 1-5. U.S. Electric Generation Capacity, 2004

Ownership Nameplate Capacity Percent of Total

(in MWs)

# Publicly-owned utilities 98,686 9.6

Investor-owned utilities 408,699 39.6

Cooperatives 43,225 4.2

Federal Power Agencies 71,394 6.9

Nonutilities 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 jo int ownership. Data are for 2004.



# B. Growth of the Electric Power Industry

For a variety of legal, economic, a nd technological reasons, th e electric utility industr y in the United States developed as a collection of separate , mostly vertically-integrated monop oly franchises with wholesale and retail prices and services extensivel y regulated under state and federal la w. Many states have elected to maintain this model. The legacy of this vertic ally-integrated monopoly stru cture creates substantial challenges for state and federal efforts to restru cture the industry and to create new institutional arrangements to facilitate increased reliance on comp etitive market prices. This section provides a brief overview of the evolutionary change s in the electric power industry.

1. The Rise of Electric Utility Monopolies and Public Utility Regulation

In the late 19 th 

# Century, electric utilities deve loped as small central station power plants with limited local
distribution networks. Franchise rights granted by manufacturers and by municipal governments allowed use of public streets and rights of ways . These franchises were often excl usive, but in some cities there was head-to-head competition among competing electric lighting companies. 16 In addition, because lighting, electric motors, and traction were the major uses of electricity, customers could turn to alternatives – natural gas lighting or self-generation in the case of street railway, commercial, and industrial customers.17 Many municipalities elect ed to create and operate their own electric utility systems.

Certain characteristics of providing electric service were r ecognized early on. Utility systems incurred high fixed costs for investments in generating plants needed to meet peak load and to extend the delivery system. Because they had relatively low operating costs, their profits wer e determined by the percent of time the power plant was in use. Complementary load diversity – such as balancing daytime traction and electric motor loads wi th evening lighting loads – could raise generating plant use and revenues to offset fixed costs and boost profits. Th e high capital costs of electric generating plants made investments risky. Steady gains in generation, transmission, and distribution econo mies of scale provided incentives to expand the electric networ ks. Larger plants produced cheaper electricity than many smaller plan ts. The substantial investment required fo r electric utility plants also spurred cre ation of long-term fi nancing structures and the corresponding interest in providing a ssurances to investors that the entity w ould be profitable and would remain financ ially viable long enough to repay
the debt.

These characteristics led some to suggest that a single monopoly provider of inte grated generation, transmission and distributi on service could provide electric service most economically and safely. To avoid abuses of this monopoly power, it was suggested that impartial state agencies s hould be created to award franchises and establish rates and service standards. An early associate of Thomas Edison, Samuel Insull of Chicago Edison was among them and proposed state regulation of private utilities in a speech before the National Electric Light Associ ation in 1898.18 Insull characterized ele ctricity production as a “natural monopoly.”19 Initially, the proposal for stat e regulation was poorly received, but as private electric companies began to grow and consolidate and concerns were raised over trusts in many industries, the concept began to gain support. In 1907, Wisconsin adopted legislation regulating el ectric utilities and was quickly joined by two other states. By 1916, 33 states had esta blished state agencies to ove rsee private electric utilities.20

Generally, under this approach, the state re gulatory commission granted exclusive retail electric franchises to private compani es within specified territories, protecting the utility from competition. In return, the utility a ssumed an obligation to provide safe and adequate service to all retail customers within its territory under just and reasonable rates, terms and conditions overseen by the state. Often the utility was authorized to use public ri ghts of way and eminent domain for electric facilities. To meet this obliga tion to serve, most private utilities built a nd controlled the generation, transmissio n, and distribution facilities needed to provide service to customers. Rates were set to cover the compan ies' reasonable costs plus a fair return on shareholders’ inves tment. The utility could expect a right to reasonable compensation for its services, although a speci fic rate of return was not guaranteed. Retail rates (price) were based on the average historical system cost of production (including the i nvestors’ fair return on investment).

In the early 20 th Century, private electric utilities continued to expand under this system of state regul ation. Most continued to build their own generation plants and transmission systems, primarily due to the cost and technological limitations of transmitting electricity over distances.21 Initially, there was little wholesale trade among utilities. As the industry grew, continued improvement s in technology allowed expansi on beyond central cities, and prices for electricity fell at the same time that demand increased substantially.Over the same period, electric utility holding companies were created and began to acquire lo cal private and municipal utilitie s. While a holding company’s local utility operating companies were regulated by the state, th e holding company and its other affiliates and subsidiaries we re not, and often did business in several states. The proliferation, consolidation, and complexity of such companies coincided w ith a number of financial and se curities abuses that were documented in an investigation by the Fede ral Trade Commission (FTC). These holding co mpanies often became the sole providers of various services and products to their affiliated utilities, and their sometimes inflat ed costs were passed through to the retail customers. By 193 2, the eight largest utility holding companies controlled 73 percent of the investor-owned electric industry.22

This pattern of consolidated ownership a nd holding company abuses led to calls for federal involvement in the electric power in dustry. As a result of the FTC findings, Congress passed the Public Utility Holding Company Ac t of 1935 (PUHCA 1935),23 which required the breakup and stringe nt federal oversight of the large utility holding companies. The FPA expanded the Federal Power Commission’s aut hority to include overs ight and regulation of interstate sales of wholesale power (e.g., sales of power between utility systems) a nd interstate electricity transmission at wholesale by “public utilities” (i.e., investor-owned utilities). FPA jurisdiction over interstate sales closed a gap in electric industry regulation that the Supreme Court had ide ntified in 1927.24

When the FPA was enacted, wholesal e and interstate sales of electricity were lim ited. Most wholesale transactions were long-te rm power supply contracts by investor-owned utilities to sell and deliver power to neighbor ing public power and cooperative utilities. Over time, utilities became more interconnected via high-voltage transmission networks. Constr ucted primarily for reliability, these ne tworks also facilitated more opportunities for interstate trade. However, wholesale trade was slow to develop.

Until the late 1960s, the vertically integrated monopoly utility model appeared to work reasonably we ll. Utilities were able t o meet increasing demand for electricity at decreasing prices as adva nces in generation technology and transmi ssion provided increased economies of scale wi th larger units and decreased
costs.25

2. The Energy Crisis of the 1970s, PURPA, and the Expa nsion of Nonutility Generation and Wholesale Power Markets

The shift toward a more compe titive marketplace for electricity was precipitated by industry changes that began in the late 196 0s and accelerated throughout the 1970s. Resulting financial stresses challenged the continued profitability of the large vertically integrated utility model. They also provoked criticisms of the traditional cost-of-service regulatory model that allowed the pa ss-through of higher costs and risks of construction to consume rs.

By the end of the 1960s, electricity demand and generation were in creasing at an annual rate of 7.5 percent, and residential ra tes were declining at an average annual rate of 1.5 percent.26 At the same time, the new large nuclear and coal plants built in the 1970s did not yield the dramatic improvements in economies of scale that earlier technological advances in generating plant size had produced. The industry’s characterization as a long-term decreasing cost i ndustry came into question. Periods of rapid inflation and higher inte rest rates substantially increased the comp letion costs of large, base load generatin g plants.27 New environmental and safety regulations required addition of pollu tion controls and design features that a dded to costs and construction time. More over, once in operation, many of the new, larger units required more maintenan ce and longer downtimes than expected. T hus, by the late 1970s, a newer, larger, gene ration facility no longer could be assumed to be more cost-efficient than a smaller plant.28

This experience stimulated interest in sm aller, modular, more energy-efficient genera ting units. One expression of this intere st resulted in commercialization of aeroderivative gas turbine technology. This technology allowed sma ller generation units to be constructed at lower costs, more quickly, and at less financial risk than large base-load coal and nuclear plan ts.29 Thus, construction of low-cost ge neration became an option for utilities that were formerly captive to high-cost generators and emerged as a viable path for new nonutility generators to enter the market.

As the difficulties plaguing utilities’ genera tion construction programs were playing out, utility fuel prices were escalating rapidly in response to the Arab oil embargo of 1973-1974 and subsequent world o il market disruptions. Significantly higher energy prices added to inflation and in creased electric rates.30 Other developments also substantially contributed to the growing in terest in electric utility reform s. First, the 1965 Northeast pow er blackout raised concerns about the reliability of weakly coordinated bulk pow er system operating arrangements among utilities.31 The nuclear accident at the Thre e Mile Island plant in Pennsylvania on March 28, 1979, heightened c oncerns over safety and led to stringent new regulatory requirements for nuclear pl ants.

Criticism of the traditional cost-of-service utility regulation mode l by economists and policy analysts also increased during t he 1970s with suggestions for alternate approaches to regulation and changes in industry struct ure. Critics of cost-based regulation argued that the industr y structure limited opportunities for more efficient suppliers to expand, placed insufficient pressure on less efficient supp liers to improve performance, and insula ted customers from the cost impacts of energy use.32

Congress enacted the Public Utility Regulatory Policies Act (PURPA) as a response to the energy cr ises of the 1970s. PURPA’s m ajor goal was to promote energy conservation and alternative energy technologies and to reduce oil and gas consumption through use of improved technolog y and regulatory reforms. A perhaps unanticipated side effect was that PURPA prompted a number of parties to see potential profits in developing competitiv e generating plants, creating an opportunity for nonutilities to emerge as impor tant electric power producers.33

PURPA required electric utilities to interconnect with and purch ase power from cogeneration f acilities and small power producer s that met statutory criteria for a qualifying facility (QF). A utility had to pay the QF at the utility’s incremental cost of production. In a departure from co st-based rate approaches, FERC defined this as the utility’s avoided cost of power.34 Box 1- 1 discusses how implementation of PURPA encouraged nonutility gen eration suppliers by guaranteeing a market for the electricity produced.35 PURPA cha nged prevailing views that vertically integrated public utiliti es were the only reliable sources of power36 and showed that nonutilities could bu ild and operate generation facilities eff ectively and without disrupting the relia bility of the electric grid. PURPA contributed substantially, both directly and indirectly, to the creation of an indepe ndent competitive generation sector.37

Before passage of PURPA, nonutility generati on was confined primarily to commercial and industrial facilities that generated he at and power for onsite use where it was advantageous to do so. Although nonutility generati on facilities were located acro ss the country, development was heavily concentrated geographically, with about two-thirds of such facilities located in Ca lifornia and Texas. Nonutility generation development ad vanced in states where avoided costs were high enough to attract interest and where natural gas supplies were available. Federal law largely precluded electr ic utilities from constructing new natural gas plants during the decade followi ng enactment of PURPA, but nonutility genera tors faced no such restriction and quic kly turned to the new smaller gas turbines as the preferred generating technology.

The response to PURPA was dramatic. Annual QF filings at FE RC rose from 29 applications covering 704 MW in 1980 to 979 in 1986 totaling over 18,000MW. From 1980 to 1990, FERC received a total of 4,610 QF app lications for a total of 86,612 MW of generating capacity.38

Following PURPA, continued improvement in ge nerating technology lowered costs and further contributed to an influx of new entra nts in wholesale markets. They could sell electric power profitably w ith smaller scale generators, including rene wable energy technologies and more effic ient, modular gas turbines.39 Other nonutilities that could not meet QF crit eria began building new capacity to compete in bulk power markets to meet the nee ds of utilities.40 These new entities were known as merchant generators or independent power producers (IPPs).41 By 1991, nonutilities (QFs and IPPs) owned about 6 percent of the electric generating capacity and produced about 9 percent of the total electricity ge nerated in the United States.42 Nonutilit y facilities accounted for one-fifth of all additions to generating capacity in the 1980s.43 Beginni ng in the 1980s, FERC allowed many new utility and nonutility gene rators to sell electricity at rates negotiated in wholesale markets, rather than established under cost-of-service formulas.44

Box 1-1

State Implementation of PURPA

PURPA required states to determine each utility’s avoided costs of production. This cost was us ed to set the price for purchas ing a QF’s power. To encourage renewable and alternative energy generation, several states, including California, New York, Massachusetts, Maine, and New Jers ey, required utilities to sign long-term contracts with QFs at prices that eventually ended up being much higher than the utilities’ actual marginal savings o f not producing the power itself (avoided costs). As a result, many utilities in these states entered into long-term pur chase contracts at prices higher than t hose available in the competitive wholesale markets. The costs of these QF contracts were reflect ed in retail rates as cost pass-throughs. The experience added to the dissatisfaction with retail rate regulation.

In 1988, FERC solicited public comments on three notices of proposed rulemaking (NOPRs) dealing with electricity pricing in who lesale transactions. These NOPRs addressed the following issues: (1) competitive bidding for new power requirement s; (2) treatment of independent power p roducers; and (3)
determination of avoided costs under PURP A.45 These proposals would ha ve moved FERC towards greater use of a “non-traditional” market-based pricing approach in ratemaking as opposed to the agency’s “traditional” cost-based approach. The NOPR s, however, proved controversial, and efforts to establish formal rules or policies were abandoned. However, the ove rall policy goals were still pursued on a case-by-case basis.

Between 1983 and 1991, FERC was asked to appr ove more than 30 non-traditional market-bas ed rate proposals. These proposals wer e brought by IPPs, power brokers/marketers, utility-affiliated power pr oducers, and traditional franchised utilities. FERC approved all but four.46 In explaining its approach, FERC staff wrote: “The Commission has accepted non-traditi onal rates where the seller or its affilia te lacked or had mitigated market powe r over the buyer, and there was no potential abuse of affiliate relationships wh ich might directly or indirectly influe nce the market price and no potential abuse of reciprocal dealing between the buyer and seller.”47 In determining whethe r the seller could exercise market power over the buyer, FERC considered whether the seller or its affiliates owned or controlled transmission that might prevent the buyer from acce ssing other power sources. A selle r with transmission control mi ght be able to force the buyer to purchase from the seller, thus limiting competition and significan tly influencing price. The FP A does not allow rates to refle ct an exercise of such market power.48

FERC recognized the potential for control of transmission to create market power and th e challenge such control created in movi ng to greater reliance on marketbased rates. FERC staff told Congress, “Because the Commissi on’s very premise of finding market-based rates just and reasonab le under the FPA is the absence or mitigation of market power, or the exis tence of a workably competitive market, and because the FPA mandates that the Commiss ion prevent undue preference and undue discrimination, we believe the Co mmission is legally required to prevent a buse of transmission control and affiliate or any other relationships which may influence the price charged a ratepayer.”49

Despite these developments, two limitations at that time were perceived to discourage competitive wholesale generation markets. First, IPPs and other generators of cheaper electric power could not easily access the transmission grid to reach poten tial customers.50 Under the F PA as then written, FERC had limited authority to order access. FERC would subsequently fi nd that "intervening" transmitti ng utilities would deny or limit transmission service to competing suppliers of generation to protect demand for wholesale power supplied by their own facilities.51 Second, unlike QFs that enjo yed a statutory exemption under PURPA, IPPs were subject to PUHCA 1935, which discouraged nonutilities from en tering the generation business.52

3. The Energy Policy Act of 1992 and FERC Orders Nos. 888 and 889



# EPAct 1992 amended the FPA and PUHCA 1935 to addr ess what were then seen as the two major limitations to the development of a competitive generation sector.

First, EPAct 1992 created a new category of power producers, called exempt wholesale generators (EWGs). 53 An EWG is an entity that directly, or indirectly through one or more affiliates, owns or operates facilities dedicated excl usively to producing

electric power for sale in wholesale markets.54 

# EWGs are exempted from PUHCA 1935 regulations, thus eliminating a major barrier for utility-affiliated and nonaffiliated power producers that wanted to build or acquire new non-rate-based power plants to sell electricity at wholesale. 55

Second, EPAct 1992 expanded FERC’s authority to order transmitting utilities to pr ovide transmission service for wholesale powe r sales to any electric utility, federal power marketing agency, or any pers on generating electric energy.56 It provide d for orders to be issued on a case-by-c ase basis following a hearing if certain protective conditions were met. Although FERC implemente d this new mandatory wheeling authority, it ultimately conclud ed that procedural limitations restricted its reach and a broader remedy was needed to elimin ate pervasive undue discrimination in transmission service that h indered competition in wholesale
markets.

In April 1996, FERC adopted Order No. 888 in exercise of its stat utory obligation under the FPA to remedy undue transmission di scrimination. The goal was to
ensure that transmission owners do not use their transmission facility monopoly to unduly discriminate against IPPs and other s ellers of electric power in wholesale markets. In Order No. 888, FERC found that undue disc rimination and anti-competitive practices existed in transmissi on service provided by public
utilities in interstate commerce. FERC determined that non-di scriminatory open access transmissi on service was an appropriate remedy and one of the most critical components of a successful transition to competitive whol esale electricity markets. Accordingly, FERC required all pu blic utilities that own, control or operate facilities used for transmitting elect ric energy in interstate commerce to f ile open access transmission tariffs (OATT s) containing certain non-price termsand conditions. They also were required to “functionally unbundle” wholesale power services from transmission services. 57 This meant that a public utility was required to: (1) take wholesale transmissi on services under the same tariff of gene ral applicability as it offered its customer s; (2) define separate rates for wholesale generation, transmission and ancilla ry services; and (3) rely on the same el ectronic information network that its tra nsmission customers rely on to obtain information about the utility’s transmission system.58

Concurrent with Order No. 888, FERC issued Order No. 889 

### 59 that imposed standards of conduct governing communications between a utility’s transmission and wholesale power functions to prevent the u tility from giving its power marketing arm preferential access to tr ansmission information. Order No. 889 requires each public utility that owns, controls, or operates facilities used for the transmission of electric en ergy in interstate commerce to create or participate in an Open Access Same-Time Information System (OASIS). OASIS must provide information regarding avai lable transmission capacity, prices, and other information that will en able transmission customers to obtain open access to non-discr iminatory transmission
service. 60



# In Order No. 888, FERC also encouraged grid regiona lization through the formati on of independent system operators (ISOs). Participating util ities would voluntarily transfer operating control of their transmission facilities to the ISO to ensure independent operation of the transmission grid. 61 The expectation was that ISO regional control would lead to improved coordination, reliability, and e fficient operation.62 However, ISO participation was voluntary and was not embraced in all regions.63 Together, Order Nos. 888 and 889 serve as the prim ary federal regulatory foundation for providing nondiscriminatory transmission service and information about the availability of transmission service.64

4. Retail Electricity Competition and State Electric Restructuring Initiatives

In the early 1990s, several states with high electricity prices began exploring opening retail electric service to competition. While customers would choose their supplier, the delivery of electricity would still be done by th e local distribution utility. Retail competition was expected t o result in lower retail prices, innovative services and pricing options. It also was expected to shift the risks of new genera tion construction from ratepayers to compet itive market providers. The substantial rate disparity among and between utilities in different states spurred state interest in retail competition. For e xample, in 1998, customers in New York paid more than two and one-half times the ra tes paid by customers in Kentucky. Rates in California were well over twice the ra tes in Washington.65 Some of this disparity can be attributed to diff erent natural resource endowments across regions , such as the availa bility of hydroelec tric resources in the Northwest and of abundant coal reserves in Kentucky and Wyom ing– which were reflected in the low cost of electricity in these states. In contra st, in more urban states without these resources, utilities invested heavily in large, new nuclear and coal plants, whic h often turned out to be more expensive than anticipated, adding to retail rates. Some utilities in high-cost states also had entered into long-term PURPA contracts that subsequently resulted in higher prices than in the wholesale power market.66 These QF contract costs were ultimate ly reflected in the regulated retail rates.67

Many large industrial customers viewed th ese rate disparities among states as a competitive disadvantage and looked to retail c ompetition as a way to secure lower cost electricity supplies. Many i ndustrial customers had long objected that they subsidized lower rates for residential customers under state regulated rates. For example, a survey by the Electricity Consumers Resource C ouncil in 1986 contended that industrial electricity consumers pai d more than $2.5 billion

annually in subsidies to other electricity customer s (e.g., commercial and residential customers). 68 It was presumed that allowing industrial customers to choose a new supplier would avoid these subsidies, thereby resulti ng in lower electricity prices for such customers.

Thus, it was not surprising that many states adopting plans to restructure retail electric service were those with higher price s.69 (Figure 4-1 in Chapter 4 shows average retail electricity prices in 1995.) States with high el ectricity rates, such as California and those in New England an d the mid-Atlantic region, were among the most aggressive in adopting retail competition and rest ructuring electric service in the hope of lowering retail rate s. As of 2004, the disparity in retail prices among the states persisted, as illustrated in Figure 1-1, below.

Figure 1-1. U.S. Electric Power Industry, Aver age Retail Price of Electricity by State, 2004

Cents per kWhSource : EIA, Electric Power Annual 2004 , Figure 7.4



# Most states considered the merits and implications of competition a nd industry restruct uring, but not all adopted retail competition plans. As of July 2000, 24 states and the Di strict of Columbia had enacted legislation or passed regulatory orde rs to restructure their electric power industries. Two states had legislation or regulatory orders pending, while 16 states ha d ongoing legislative or regulatory investigations. Only eight states did not formally initiate restructuring studies. 70 The meltdown of California’s electricity markets and the ensuing Western Energy market crisis of 2000-2001 are widely perceived to have halted interest by s tates in restructuring retail markets. Since 2000, no additional states have announced plans to implement retail co mpetition programs, and several states th at had introduced such programs have delayed, scaled back, or repealed thei r programs entirely (see Figure 1-2 below).71

In 2006, retail customers in 30 states continue to receive se rvice almost exclusively under a traditional regulated monopoly ut ility service franchise. These states include 44 percent of all U.S. retail cust omers, representing 49 percent of electricity demand. However, 20 states and the Dis trict of Columbia have state restructuring plans in force that allow co mpetitive retail providers to provide service to some if not all retail customers at prices set in the market.

State retail restructuring plans often involved divestiture of gene rating assets by local vertically integrated utilities. As a result, the distribution utilities that sell electricity to retail customers must proc ure power from wholesale markets under long- or short-term bilateral contracts and fro m wholesale spot markets. These jurisdictions include many of the most populous states, accounting fo r over half of all retail customers and loads. With some exceptions, retail competition has been slow to develop in many of these states, particularly fo r residential customers. Without a competitive provider option, m ost customers continue service under regulated “provider of last resort” (POLR) rates. In so me states, freezes and caps on POLR rates approved by state regul ators under retail restructuring cases are expiring, and POLR rates are bei ng revised sharply upward to reflect higher market-based wholesale electricity costs. State experience with electric competition and related issues is discussed in Ch apter 4, Retail Competition, and in Appendix D.

Figure 1-2. Status of State Elect ric Industry Restructuring Activity and Retail Competition, July 2006Note: Nevada repealed its retail choice legislation in 2001. It s ubsequently enacted legislation allowing state regulators to appr ove requests from very lareg C&I customers to procure electricity from alternative suppliers if the contract is found to be in the public interest.

Source : Task Force Comments and EIA, Status of State Electricity Industry Restructuring Activity 2003 , February 2003, available at http://www.eia.doe.gov/cneaf/electri city/chg_str/restructure.pdf.



# 5. The Western Energy Market Crisis 2000-2001.

California opened its retail markets to competition and started spot markets for wholesale electricity in 1998. In response to the state plan, the three major investor-owned util ities divested most of their nonnuclear generation and turned over op eration of transmission facilities to the new California Independent System Operator (CAISO). The IOUs were required to sell into and purc hase power through the new California Power Exchange (CalPX) and the CAISO. Retail rates were reduced but remained well above the national average. Rates were then frozen until the u tilities recovered their strand ed costs. At that point, competitive markets were expected to drive prices lower. San Diego Gas and Electric (SDG&E) fully recovered its stranded costs by summer of 1999, and its re tail rates were then allowe d to reflect the utility’s cost of obtaining power in the wholesale markets. Re tail rates for the other two major utilities remained
frozen.

In late May 2000, the CAISO called its first Stage 2 power alert as system reserves fell below 5 percent. PX prices that had averaged about $27 per MWh in April spiked to over $50 in May and continued upwards, eventually reaching a high of $450 per MWh in January 2001. These higher prices were quickly passed through in San Diego, where average customer bills tripled by mid-summer. California’s other major utilities, Pacific Gas and Electric (PG&E) and S outhern California Edison (SCE), were forced to pay the unexpectedly higher PX wholesale prices, but could not pass increases on to retail customers as they
were still under a rate freeze.

Price spikes were not California’s only problems. On June 14, 2000, the CAISO imposed rolling blackouts
in PG&E’s San Francisco service area because of s hortages attributed to the maintenance shutdown of several generating plants. These we re the first of many power emergencies and blackouts affecting the state that did not end until July 2001.

Responding to public concern, the Califor nia Public Utilities Commission, th e state’s attorney general, and FERC all launched investigations. On August 2, 2000, SDG&E filed a complaint at FERC against all
sellers in the PX and ISO market s and asked for a price cap of $250. 72 FERC opened a formal investigation of wholesale pricing in California and the West in general. A preliminary FERC staff report in November 2000 found that the market rules an d structure were “seriouslyflawed” and, coupled with supply and demand imbalance, could result in rates that were not “just and reasonable.”73 The staff r eport concluded that the state’s market structure created the potential for abuse of market power when supplies were tight. FERC proposed interim emergency rem edies that were instituted in
December 2000.74

As the state’s market problems continued and spread, price spikes a ffected electricity pricing hubs and utilities across the We st, including states that had not adopted retail competition and that were not included in the CAISO. The region’s increased power costs were estimated in the t ens of billions and led to retail rate increases in many Western states.75 California declared multiple power emergencies in December 2000, followed by blackout s in January and March 2001. High wholesale market prices that utilities were not allowed to recover through retail rates threat ened the solven cy of the sta te’s three major IOUs. California sought to end the procurement difficulties faced by IOUs in the state by entering into long-term contracts to secure power on b ehalf of the utilities and to preserve service to retail customers. Contract prices were se t at some of the highest prices prevailing over this period.76 A s a condition of assuming responsibility for power procurement, the st ate suspended retail competition for all but large customers that already had contr acts with competitive suppliers. In April, PG&E’s retail electric utility subsidia ry, one of the largest in the nation, f iled for bankruptcy pr otection, later join ed by a number of wholesale sellercreditors, because the financially distresse d distribution utilities did not make timely payments to these generators. Power p rices did not return to “normal” ranges until fall of 2001.

Over this period, FERC issued a number of orders setting and lowering price caps, establishing market monitoring requirements, and opening an investigation of possible market manipulation in the run-up of natural gas prices in the West. State, federal, a nd private investigations ultim ately uncovered a number of market abuses and regulatory gaps.77 Many FERC and other proceedings arising out of th e dysfunctional California markets continue tod ay.78 A number of energy traders eventually f aced criminal charges. The 2000-2001 We stern Energy Crisis had wide repe rcussions as other regions adapted their market rules and structures to avoid the problems encountered in the West.

6. Development of Regional Transmission Or ganizations and Regional Wholesale Markets

After issuing Order Nos. 888 and 889, FERC c ontinued to receive complaints about tran smission owners discriminating against ind ependent generating companies. Transmission customers remain ed concerned that implementation of func tional unbundling did not produce complete sep aration between operating the transmission system and marketing and selling electric power in wholesale markets. There were also concerns that Order No. 888 made some discriminatory
behavior in transmission access more subtle and difficult to identify and document.



# After FERC issued Order Nos. 888 and 889, the electric industry continued to evolve in response to competitive pressures and state retail restructuring in itiatives. Utilities today purchase more wholesale power to meet load than in the pa st and are relying more on availabi lity of other utility transmission facilities to deliver power . Retail competition increased significan tly, and state initiatives brought about the divestiture of generation plants by traditional elec tric utilities. In addition, there were a number of mergers among traditional electric util ities and among electric utilities a nd gas pipeline companies. The number of power marketers and independent generation developers increased dram atically, and ISOs were established to manage large part s of the transmission system. Trade in wholesale power markets has increased significantly, and the nation's transmission gr id is now used more heavily and in new ways.

In December 1999, responding to continuing complaints of discrimination and lack of transmission availability, FERC issued Order No. 2000. 79 This order recognized that Order No. 888 set up the foundation for competitive electric markets, but did not eliminate the potentia l to engage in undue discri mination and preference in providing transmission service .80 FERC concluded that regional transmission organizations (RTOs) could eliminate transmission rate pancaki ng,81 increase region-wide reliability, and eliminate any residual discrimination in transmission services where operation of the tran smission system remains in the control of a vertically integ rated utility. Accordingly, FERC encouraged voluntary formation of RTOs.

RTOs are entities set up in response to FERC Order Nos. 888 and 2000 encouraging utilities to volunt arily enter into arrangemen ts to operate and plan regional transmission systems on a nondiscriminatory open access basis. RT Os are independent entities that control and operate regional electric transmission grids for the purpose of promoting efficiency and re liability in the operation and planning of the transmission grid and for ensuring non -discrimination in the provision of
electric transmission services. RTOs currently do not own transmission.82

FERC has approved RTOs or ISOs in several regions including the No rtheast (PJM, New York ISO, ISO-New England), California, the Midwest (MISO) and the Southwest (SPP), as shown in Figure 1-3 below. By the end of 2004, regions accounting for 68 percent of all economic activ ity in the United States had chosen the RTO option.83 In 2004 and 2005, the PJM RTO grid e xpanded substantially to include several additional service terri tories in the Midwest. In 2004, the territories served by Commonwealth Edis on (ComEd), American Electric Power (AEP), and Dayton Power and Light joined PJM. T he expansion continued in 2005 with the addition of Duquesne Light and Dominion Resources. PJM now covers about 18 percent of total electricity consu mption in the United States and includes utility service territories in the Mid- Atlantic, Midwest, and parts of the Southeast.84

In most cases, RTOs have assumed responsibility to calculate th e amount of available transfer capability (ATC) for wholesale tr ades for member systems across the footprint of the RTO. RTOs also are responsible for coordinating regional planning, at least for facilities necessary for reliability above a certain voltage. As of 2004, all RTOs coordinate dispatch of generators in thei r systems and provide transmission services under a single RTO open access tariff. In addition to operating the regional transmission grid, RTOs operate regional organized energy market s, including a short-term market which p rices energy, congestion, and losses. RTOs in the East offer day-ahead and real-time markets, while California and Texas offe r real-time markets alone. All current RTOs use or plan to use some form of locational pricing to manage transmission congestion and ha ve independent market monito rs that assess and report o n market activities.85 RTOs and regional wholesale markets are descri bed in more detail in Chapter 3.Figure 1-3. RTO Configurations in 2006

Note : The above map shows the general locati on of approved RTOs. Not all transmitting u tilities within the shad ed area of an RTO are necessarily members of the RTO and some RTO members are not shown in this map.

Source : FERC RTO Regional Map, 2006, created using Platts POWERmap, available at http://www.ferc.gov/industries/elect ric/indus-act/rto/rto-map.asp



# The RTO model and regional organized wholesale mark ets have been voluntarily adopted by utilities and market participants in the Northeas t, Mid-Atlantic, California, and part s of the Midwest and Southwest. Some states required RTO participa tion as part of restructuring under the state retail competition plan.
RTO members include utilities in st ates that have not adopted retail competition. State regulators often serve on RTO advisory bodies and have been acti ve in FERC proceedings involving RTOs. Although RTOs enjoy broad participation by utilities and compe titive power suppliers, some comments filed with the
Task Force 86 raised concerns over perceived high costs of RTO impl ementation and operations and ove rsight of RTO markets.

In other regions, including most of the Southeast, the West outside of California, and other parts of the Midwest, RTOs have be en considered, but formation has stalled. State regulators and utilities in these regions have found it difficult to assess the potential benefits and costs of establishing RTOs. They have been reluctant to create new institutional arrange ments that could diminish local contro l over transmission facilities and could imp ose additional costs on retail

customers.

7. August 2003 Blackout

On August 14, 2003, an electrical outage in Ohio precipitated a cascading blackout acro ss seven other states and as far north a s Ontario, Canada, leaving more than 50 million people without power.87 The August 2003 blackout was the largest in United States history, leaving some parts of the nation without power for up to four days and costing between $4 b illion and $10 billion.88 It affected large portions of the Midwest and Northeast Unit ed States and Ontario and an estimated 61,800 MWs of load. It was the eighth major blackout in North America since the 1965 Northeast Blackout. A Joint U.S .-Canada Power System Outage Task Force issued a final Blackout Report in April 2004. The report identified factors that were common to some of the eight major outages from 1965 through the 2003, as shown below:

(1) conductor contact with trees; (2) overestimation of dynamic r eactive output of system generators; (3) inability of system o perators or coordinators to visualize events on the en tire system; (4) failure to ensure that sy stem operation was within safe limits; (5) lack of coordination on system protection; (6) ineffective communication; (7) lack of “s afety nets;” and (8) inadequate training of ope rating personnel.89In addition to the Joint Study, a ffected states and NERC90 carried out their own investigations.

8. The Energy Policy Act of 2005

In August 2005, Congress passed EPAct 2005, which amended the core statutes (FPA, PURPA, PUHCA 1935) governing the electric pow er industry. Among the notable provisions of EPAct 2005 are the following:

Reliability : Section 1211 authorizes FERC to certify an Electric Reliab ility Organization to propose and enforce reliability standards fo r the bulk power system. EPAct 2005 authorized penalties fo r violation of these mandatory standards.

Transmission Siting : Section 1221 requires the Secretary of Energy to conduct a study of electricity congestion with in one year of the enactment of EPAct 2005 and every three years thereafter. It authorizes the Secretary of Energy to designate certain areas experiencing con gestion as “National
Interest Electric Transmission Corridors” based on these studies. In certain limited circumstances, FERC is authorized to appr ove construction permits for transmission facilities in designa ted corridors when states either lack su ch authority, or withhold approval for mo re than one year after filing of an application or corridor designa tion. Proponents of this new federal aut hority argue that it will facilitate const ruction of new transmission and help alleviate transmission congestion that can impair competition in electric markets.

Transmission Investment Incentives : Section 1241 requires FERC to establish incentive- based rate treatments for public utilities’ transmission infrastructure to promote capital investment in transmission infrastructure, attract ne w investment with an attractive return o n equity, encourage improvement in transmission technology, and allow for recovery of prudently incurred costs rela ted to reliability and improved transmission infrastructure. Proponents contend this will encourage the expansion of transmission cap acity and, thus, help foster greater c ompetition in electric
markets.

PURPA Reform : Section 1253 permits FERC to terminate, pr ospectively, the obligation of electric u tilities to buy power from QFs, such as i ndustrial cogenerators. FERC may do so when the QFs in the relevant area have adequate opportunities to make competitive sales, as defin ed by EPAct 2005. The premise is that growth in competitive opportunities in elect ric markets negates the need for PURPA’s “forced sale” requirem ents.

PUHCA 1935 Repeal : Title XVII, subtitle F repeals PUHCA 1935 and replaces it with new PUHCA 2005. It provides FERC and state access to books and records of holding companies and their members. It al so provides that certain holding companies or states may obtain FERC-authorized cost allocations for non-power goods or serv ices provided by an associate company to public utility members in the holding comp any. PUHCA 2005 also contains a mandatory exemption from the federal books and records access provisions for entities that are holding companie s solely with respect to EWGs, QFs or foreign utility companies. The goal is to redu ce legal obstacles to investment in the electric utility industr y and, thereby, help
facilitate the construction of adequate infrastructure.

C. Recent Trends Related to Competition in the Electric Energy Industry

This section discusses several more recent electric industry policy developments and characteristics.

1. Increases in Generation and Grow th of Nonutility Generation Suppliers

Electric power industry restructuring has been sustained largel y by technological improvements in gas turbines. It is no longe r necessary to build a larger generating plant to gain operating efficiencies. Combined-cycle gas turbines reach maximum e fficiency at 400 MW, while aero-de rivative gas turbines can be efficient at sizes as low as 10 MW. These new gas-fired combined cycle plants can be more energy efficient and less costly tha n the older oil and gas-fired plants.91 Because of their smaller footprint and low emissions, gas turbine generators can often be located close to load, avo iding the need for additional transmission. Coupled with greater transm ission access as a result of Order No. 888, it became feasible for generating plants hundreds of miles apart to compete with each other, giving customers more choices in electricity suppliers.92

The market participation of utilities and other generation suppliers began changing in response to increases in energy costs in the 1970-1990s and the passage of PURPA, which facilitated entry of nonutility QF s as energy-efficient, environmentally-fr iendly, alternative sources of electric power. The change continued through Order No. 888, which opened up the tran smission grid to competing wholesale electricity suppliers.93 Until the early 1 980s, electric utilities’ share of electric power production increased steadily , reaching 97 percent in 1979.94 By 1991, how ever, the trend had reversed itself, and the utilities’ share declined to 91 percent.95 By 2004, regulated electric utilities' share of to tal generation continued to d ecline (63.1 percent in 2004 vers us 63.4 percent in 2003) as nonutilities’ share increased (28.2 percent versus 27.4 percent in 2003).96

This trend is illustrated by comparing increases in capacity additions for utility and nonutility generation suppliers, as show n in Figure 1-4 below. While most of the existing capacity and most of the add itions to capacity through the late 1980s we re built by electric utilities, their shar e of capacity additions declined in the 1990s. Between 1996 and 2004, roughly 74 percent of electricity capacity additions were made by nonutility power producers.

Figure 1-4. Utility and Nonutility Gen eration Capacity Additions, 1995-2004Source : FERC analysis of Platts PowerDat data.



# However, the pattern of merchant generation invest ment outpacing utility investment may be shifting. Traditional regulated utilities, in cluding public power and cooperative utilities, accounted for about 60 percent of capacity additions from 2005 through May 2006. In Californi a, six new power plants began operations, including four owned by public utilities and two owned by IOUs. 97

2. Transmission Investment

Despite these increased investments in new generation, the Edison Electric Institute (EEI) reports that IOU investment in trans mission declined from 1975 through 1999. See Figure 1-5. Over that period, electricity demand more th an doubled, resulting in a significant decrease in transmission capacity relative to demand. Box 1-2 suggests reasons for this trend. Since 1999, according to EEI surveys, transmissi on investment has increased annually. From 1999 to 2003, IOU investment increased 12 percent annually. 98 For 2004 to 2008, IOUs expect to inve st about $28 billion in transmission, an almost 60 percent increase over the prior five-year period.

Figure 1-5. Transmission Construction Expenditures by Investor-Owned Utilities, Actual and Projected, 1975-2009

3. Retail Prices of Residential ElectricityAs seen in Figure 1-6 below, between 1970 and 1985, national averag e residential electricity prices more than tripled in nomina l terms and increased by 25 percent in real terms (adjusting for inflation).99 U.S. real retail electricity prices began to fall after the mid-1980s until 2000-2001 as fossil fuel prices and
interest rates declined and inflation m oderated significantly.100 Real retail prices stayed flat through 2004, but have begun to increase in all regions reflecting higher fuel prices and operating costs.

According to the latest information from EIA, residential electric prices in 2005 averaged 9.43 cents per kilowatthour (kWh), a n increase of about 5 percent from 2004. Retail electric prices continue to increase, and the na tional average price for residential customers in April 2006 was 10.31 cents per kWh, up 12 percent from a year earlier.101 These increases reflect s ubstantially higher fuel and purchased power costs.102

Box 1-2

Decline in Transmission Investment

Transmission is the physical link between el ectricity supply and demand. Without ade quate transmission capacity, wholesale com petition cannot function effectively.

Some reasons suggested for the decline in transmission investment between 1975 and 199 7 (see Figure 1-5) are a decline in inves tment in large base-load generating plants requiring associated new large transmission add itions, an overbuilt system prior to 1975, lack of available c apital due to other investment activities by vertically integrated utilities, the protection of vertically integrated utility generation from competition, and regulatory uncertainty over recovery of
new transmission investment.

Another explanation for the decline in investment is the diffi culty of siting new transmission lines. Siting can bring long de lays and negative publicity. Local opposition can be significant. Also, some states may require a s howing of benefits to the state for approval of a transmission line. This creates challenges for interstate transmission facilities proposed to primarily benefit interstate commerce.

Figure 1-6. National Average Retail Prices of Electricity for Residential Customers, 1960-2005

Note : Real prices are shown in chained (2000) dollars, calculated by using gross domestic product implicit price deflators.

Source : EIA, Annual Energy Review 2004 , Table 8.10 Average Retail Prices of El ectricity, 1960-2004, and EIA, Monthly Energy Review, July 2006, Table 5-3.



# 4. Changing Patterns of Fuel Use for Generation – Reaction to Increased O il Prices and Clean-Air Environmental Regulations

For many years, coal was the fuel most commonly us ed to generate electric ity, providing 46 percent of utilities’ generation in 1970 and more than 50 percen t since 1980. As world oil prices escalated in the

# 1970s, oil-fired and gasoline-fired generation’s share of electricity supply began decreasing and utilities’ use of oil and gas for new generation was restricted by federal law.

Hydroelectric power also has played a large role in the supply of electri c power, but its share has declined relative to other major fuels mainly because there are a limited number of suitable sites for hydroelectric projects. Nuclear power emerged as the second larg est fuel source in 1991 but was not expected to
increase. 103

For nonutilities, natural gas has been the majo r fuel for new plant additions.104 Indeed , in recent years, new capacity additi ons reflect the prevalence of natural gas.105 As shown in Figure 1-7, recent plant additions illustrate this change. The Clean Air Act Amendments of 1990 (CAA) and state clean air requirements also contributed to increased use of natural gas. The CAA sought to address the most widespread and persistent pollution probl ems caused by hydrocarbons and nitrogen oxides, both of which are prevalen t with traditional coal and petroleum-based generation. The CAA fundamentally chang ed the generation business because emission of air pollutants would no lo nger be cost-free. As a result, many ge neration owners and new plant developers turned to cleaner-burning natural gas as the fuel source for new generation plants. California has depended heavily on gas-fired generation because of its speci fic air quality standards.106

Figure 1-7. Natural Gas Plants Domi nate New Generating Unit Additions

Source : FERC analysis of Platts PowerDat data.



# The result of these plant additions through Decembe r 2005 is that 49.9 percent of the nation's electric power was 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 2.5 per cent was generated at petroleum liquid-fired plants. Conventional hydroelectric power prov ided 6.6 percent of the total, wh ile other renewables (primarily biomass, but also geothermal, solar, and wind) an d other miscellaneous energy sources generated the remaining electric power.

Figure 1-8. Net Generation Shares by Energy So urce: Total (All Sectors), January-December 2005

Source : EIA, Electric Power Monthly , July 2006, Table 1-1. 

# The trend toward gas-fueled capacity additions may be changing. There is renewed interest in coal-fired

# generation as reflected in utilities’ and nonutilities’ announcements of new coal plant construction projects. Two major reasons may explain coal’s resurgence: (1) the relative price of natural gas compared to coal has increased substantially and (2) th e cost of environmental equipment fo r coal plants, such as scrubbers, has decreased. “Over the past decad e, many merchant combined-cycle ga s-fired units were built on the assumption that natural gas would be relatively inexpensive and that cl eaning technology for coal plants would drive the price of coal plants significantly higher. Sharp increases in natural gas prices in recent years have challenged these assumptions.” DOE’s EIA estimated that 573 MWs of new coal generation would be added nationally in 2005, which compares w ith an estimate of 15,216 MWs of gas-fired additions for the same year. For 2009, however, predicted trends shift; the EIA projects that 8,122 MWs of new coal generation will be added that year, whereas onl y 5,451 MWs of gas-fired generation additions are predicted. 107 DOE predicts a resurgence of coal-fired generation as far into the future as 2025.108

Higher gas prices and environmenta l concerns have also spurred renewed interest in nuclear generation. EPAct 2005 includes a n umber of provisions intended to encourage and facilitate a new and improve d generation of nuclear power plants.

5. Fuel Price Trends

Natural gas prices have been increasing in recent years, due in part to historically high petroleum prices. Natural gas prices increased 51.5 percent between 2002 and 2003, 10.5 percent between 2003 and 2004, and 37.6 percent between 2004 and 2005. Strong demand for natural gas, as well a s natural gas production disruptions in the Gulf of Mexico, contri buted to these increases. As shown in Figure 1-9, for December 2005 the overall price of fossil fuels was influenced by the price increases in natural gas. In December 2005, the av erage price for fossil fuels was $3.71 per million Btu (MMBtu), 10 .1 percent higher than for November 2005, and 44.4 percent higher than in December 2004. As natural gas prices increase relative to coal prices, the chan ge may make development of clean-burning coal plants more economically attractive than they were when natural gas fuel prices were lower.

Figure 1-9. Fossil Fuel Costs for Electric Generators, 2001-2006

Dollars per Million BtuSource : EIA, Monthly Energy Review , July 2006, Table 9.10. Cost of Fossil-Fuel Receipts at Electric Generating Plants.



# 6. Mergers, Acquisitions, and Power Plant Dive stitures of Investor- Owned Electric Utilities 109

Many IOUs have fundamentally reassessed their corporate strate gies to function more like competitive, market-driven entities th an in their more regulated past.110 One result is that there was a wave of mergers and acquisitions in th e late 1980s through the late 1990s between tr aditional electric utilities and between electric utilities and gas pipeline companies.

IOUs also have divested a substantial number of generation asse ts to IPPs or transferred them to an unregulated nonutility subs idiary within the company.111 Even though FERC-regulated IOUs have functiona lly unbundled generation from transmission, and some have formed RTOs and ISOs, m any utilities have divested their power plants because of state requirements. So me states that opened the electric market to retail competition v iew the separation of power generation ownership from power transmission and distribution ownership as a prer equisite for retail competition. For example, California, Connecticut, Maine, New Hampshire, and Rhode Island enacted laws requiring utilities to divest their power plants. In other states, the state publ ic utility commission may encourage divestiture to arrive at a quantifiable le vel of stranded costs for purposes of rec overy during the transition to competition.1 12

Since 1997, IOUs have divested power gene ration assets at unprecedented levels,113 and these power pl ant divestitures have also reduced the total number of IOUs that own generation capacity.114 A few utilities have decide d to sell their power plants, as a business strategy, decidin g that they cannot compete in a competitive power market. In a few inst ances, an IOU has divested power generati on capacity to mitigate potential market power resulting from a merger.115 As described in Table 1-6 below, between 1998 and 2001, over 300 plants, representing n early 20 percent of U.S. installed gener ating capacity, changed ownership.

Since 2001 the merger trends have shifted s lightly, as financial difficulties of the merc hant generating sector have prompted t he sale or transfer of a substantial share of the merchant fleet. Some purchasers have been traditional utilities, including public power and cooperative utilities .116

There were no significant electric power company mergers from 2001 to 2004, but in 2004 utilities and financial institutions ex hibited growing interest in mergers and acquisitions, prompting many analysts to herald 2004 as a new round of consolidation in the power sector.117 One u tility-to-utility acquisition closed,118 and three were announced.119 Most electric acquisitions in 2004 involved th e purchase of specific generation assets . Many companies strove to stabilize financial profiles through asset sales. In aggregate, almost 36 GW of generation, or nearly 6 percent of installed c apacity, changed hands in 2004.120

Table 1-6. Power Generation Asse t Divestitures by Investor-Owned Electric Utilities, as of April 2000

GWs and Percent of Total and U.S. Generating Capacity



# Status Category Capacity (GW) Percent of
Total Percent of Total U.S.Generation Capacity

Sold 58.0 37 8

Pending Sale (Buyer Announced) 28.2 18 4

# For Sale (No Buyer Announced) 31.9 20 4

Transferred to Unregulated Subsidiary 4.1 3 1

Pending Transfer to Unregulated Subsidiary 34.2 22 5

Total 156.5 100 22

Source : EIA, The Changing Structure of the Electric Power Industry 2000: An Update, (October 2000), Table 19. 

# CHAPTER 2
CONTEXT FOR THE TASK FORCE’S STUDY OF COMPETITION IN
WHOLESALE AND RETAIL E LECTRIC POWER MARKETS

This chapter provides context and theoretical underpin nings to the Task Force’s study of competition in
wholesale and retail electric power markets. It describes (1) perc eived shortcomings of traditional costbased regulation that motivated rest ructuring and regulatory reform, (2) the theoretical role competitive market price signals play in guiding consumption and investment decisions, 121 and (3) a brief discussion of expected benefits of shifting from cost-based rate regulation to mark et-based pricing of electricity.

A. Overview of Perceived Shortcomings of Cost-Based Rate Regulation

State and federal policymakers regulated provi ders of the generation, transmission, a nd distribution of electric power as verti cally-integrated monopolies for approximately 70 years. For much of this period it was consid ered economically inefficient a nd technologically challenging to have multiple sources of generation, transmission, and di stribution facilities serving customers in the same geographic area. Competition was considere d impractical and not in the public interest because it would require costly duplication of facilitie s and likely engender competition that would not be sustainabl e due to economies of scale. Under this model, competition was expected eventu ally to result in ratepayers paying for failed facilities without benefiting from al ternative sources of supply.

The traditional “regulatory compact” required an electric power u tility to serve all retail customers in a defined franchise ar ea in exchange both for the opportunity to earn a reasonable return on its investment and for protection against entry by potential rivals. Consumer price s or “rates” were based on the regulated utilities’ average historic cost of production plus an adder for a fair retu rn on investment and often adjustments fo r changing fuel prices. Regulators used this “cost-based” regulation to try to ensure adequate supplies at reasonable pr ices for consumers, as required by state l aws. Under most state regulatory policies, utilities could not recover new inve stments in rates until regulators determined that the investment was “prudent” an d the facilities were “used and useful” (actually being used to serve customers). Historically, some states allowed large nuclear cost overruns to be included in the rate base, while other states did not. In general, disallowances of investments have been rare.

As described in Chapter 1, beginning in the 1970s, the combined effects of a number of change s – improvements in smaller-scale generation technology, transmission, communications and control t echnologies, rising energy prices, environmen tal policy concerns, increased concerns about the effectiveness of traditional utility rate regulation, and favorable experience with the introduction of increased competition in other network i ndustries – began to transform the structure and regulation of the electric power sector.

1. Effects on Electricity Demand and Prices

Under cost-based regulation, end-use, and so metimes wholesale, customers often paid prices for their electricity that were base d on average costs calculated over extended periods of months or years so that the prices did not vary with consumption or the marginal cost of generation. These rates were stable and often only varied by season. Although time-based rates and certain regulated products such as interruptible or curtailable services had b een used within the electric power industry for decades, they had not been applied to the vast majority of retail customers.

The average cost-based pricing formula precludes economically a ccurate price signals from guidi ng consumption decisions.122 In efficiency has resulted as consumers purchased either too much electricity (when the averag e price was below the efficient price) or too little electricit y (when the average price exceeded the efficient price). Inefficient resource use can translate to higher production costs and prices . Historical average cost e lectricity prices, for example, gave consumers no economic reason to conserve electricity when supplie s were short or demand was high. Similarly, suppliers did not receive economically accurate price signals to guide their short- and l ong-term sales of generation. In addition, many industrial customers among others hav e objected that retail rate structures frequently contained cross-subsidies among customer classes and thus, furt her distorted prices.123

2. Effect on Investment Decisions

Regulators’ influence over generation constr uction decisions likely also contributed to inefficiency. Historically, regulators had encouraged local utilities to build or contract for sufficient generation to serve customers within their territories. Regul ators blocked entry by independe nt generators or allowed the utilities to do so. This resulted in utilities owning nearly all generation assets within their service te rritories and discouraged comp etition among generators. While the intent of these policies was partly to k eep price down, the unintended effect was to dampen incentives for cost reduction, inve stment in new capacity andinnovation.124 More competition might have led earlier to technological innovation and lower generation costs.

The fact that regulators had to agree that a capital investment was necessary and prude nt before rate recovery was allowed125 f urther discouraged innovation. Utilities were reluctant to take investment risks that might end up being unrecoverable if regula tors deemed their cost unreaso nable. Thus, long-term planners and regulators had significan t influence over when and where generation would be built. In making decisions, regulators strugg led to strike a balance between reasonable rates and providing utilities with incentives to make necessary and sufficient investments.

This regulatory oversight also possibly encouraged an overcapitali zation of the industry, as generators were assured a rate of return on any approved capital project. It might also have led to under capitalization if a regulator was too conserva tive. Further, if rates were set too hi gh, utilities could earn a higher return on new generation investments than would be wa rranted by the cost of capital. If regulat ors were unlikely or unable to identify a nd disallow excessive construction costs, utilities had little incentive to design new generation plants cost-effectively. At the same time, regulatory disallowa nces of some costs imposed risk on utility decisions to elicit capital and build new generation, and investors sought compensation for this risk when they supplie d capital to utilities.126

Ultimately, ratepayers were left to bear much of the investme nt risk, as they had to pay fo r regulator-approved projects result ing in overinvestment as well as any subsequent higher costs from underinvestment (for example, cost s of running higher cost generati on more often than is economica lly efficient).

A 1983 DOE analysis of electric power generation plant construc tion showed that electric utilitie s (regulated under a cost-base d regulatory regime) had limited ability to control construction costs of coal and nuclear plants . During the 1970s and early 1980s, the cost range per MW to b uild a nuclear plant varied by nearly 400 percent and by 300 percent for coal plants. The study s howed that some companies were not competent to manage such large-scale, capital-intensive projects. In addition, they tended to custom design plants, as opposed to using a basic design and then refining it.127

One alternative to traditional cost -based rate-of-return regulation is price cap regulation. Under this approach, the regulato r caps the price a firm is allowed to charge.128 This alternative may remedy so me of the incentive problems of cost-based regulation, but comes with its own costs. Another alternative is the addition of an open, transparent Integrat ed Resource Planning process by utilities to consider and support choices about buildi ng new generation procuring supplies from wholesale markets, and/or inve sting in demand-side options to meet proj ected load growth. In some states, regulat ors are involved in the utility IRP process and may approve the resulting plan. Even with this oversight mechanism, regulators have few reference points to de termine if a builder’s choices about design, efficiency, and materials fo r the IRP selected plant are prudent.

3. Motivation for Change

In part, the struggles of regulators to ensure adequate supplie s of power at reasonable rates led policymakers to examine wheth er competition could provide more timely and efficient incentives for what to consume and build. Advances in technology also allowed the entry of a variety of n ew, nonutility generators and demand response alternatives and weakened the argument for preserving utilities’ monopolies on ge neration services. These deve lopments set the stage for considering competitive pricing as an option for eliciting entry by new generators or expansion by existing generators. Genera lly, transmission and distribution have continued to be regulated services.

B. Overview of the Role of Price in Competitiv e Wholesale and Retail Electric Power Markets

How much a supplier will produce at a given price is determined by many things, including (in the long run) how much it must pa y for the labor it hires, the land and resources it uses, the capital it employs, the fuel inputs it must purchase to generate the electric power, the transmissio n it must use to deliver the electric power to end users, and the risks associat ed with its investment. Consumers’ overa ll willingness to pay for a product also is determined by a large variety of factors, such as the ex istence and prices of substitutes, in come, and individual preferences.

The following is a review of expectations based on economic theory of how competition might determine prices and discipline inv estment in the electric utility industry. Chapters 3 and 4 examine how well actual wholesale a nd retail electricity market stru ctures are meeting these expect ations.

1. Price Affects Customer Consumption

Price changes play an important economic f unction by encouraging customers and supplie rs to respond to changing market conditio ns. Price changes signal to
customers in wholesale and retail markets th at they should change their decisions about how much and when to consume electric p ower. Price increases signal customers to reduce consumption. The more consumers reduce thei r consumption in response to an increase in prices, the less ma rket power sellers are likely to have. Lower prices encourage customers to increase consumption. Consumer price responsiveness is often referred to as “demand response.”129

The primary purpose of incorporating market driven prices into wholesale and retail electric power markets is to provide price signals that accurately reflect underlying costs of production and thereby enc ourage efficient consumption patterns. Ec onomic analysis suggests that the marke t dynamics of this type of pricing will result in lower overall production costs, which will translate into lower consumer prices.

Accurate price signals are expected to improve the efficiency of electric power production by more closely aligning the price t hat customers pay for and the value they place on electricity. In particular, by exposing customers to prices based on marginal production costs, resources can be allocated mo re efficiently.130 Accurate price signals also reduce cross s ubsidies between customers and among customer classes.131 Flat electricity prices ba sed on average costs can lead customers to “over-consume – relative to an optimally efficient sy stem in hours when electricity prices are higher than the ave rage rates, and under-consume in hours when the cost of producing electricity is lower than average rates.”132 Efficien t price signals also have the benefit of increasing price response during periods of scarcity and high prices, which can help moderate generator market power and improve reliability.

When there are many close substitutes for a particular commodity, a relatively small price increase will result in a relatively large reduction in consumption. For example, if natural gas were a very good su bstitute for electric power at prevailing pr ices, then even a re latively small incre ase in electricity prices could persuade many consumers to switch in part or entirely to natural gas. To induce those consumers to return to electricity, elec tricity prices would not need to fall by very much. However, where there are no close substitutes fo r electric power, the price of electricity may have to rise subs tantially to reduce consumption by a significant amount.

Empirical literature shows that, even if th e retail price of electricity increases by a large percentage, consumption of electr icity does not decline much. In economic terms, it is said that the short-run demand for electricity is “inelastic” with respect to price. See Box 2-2. This inability to substitute other products for electricity in the short run means that changes in supply conditi ons (price of input fuels, etc. ) are likely to cause wider pri ce fluctuations than would be the case if customers could easily reduce consumption when prices rise. Fu rthermore, electric power has few viable substitutes for key end uses such as refrigeration and lighting, and thus the consequences for s upply shortfalls can be significant.133 In th e long run, this effect may be somewhat muted as customers may have moreability to adjust consumption and fuel s ources in response to price changes.

Box 2-1

Market Prices

Market prices reflect myriad individual d ecisions about prices at which to sell or buy . They act as a mechanism that equalizes the quantity demanded and the quantity supplied. Rising prices signal consumers to purchase less and producers to supply more . Falling prices signal consum ers to purchase more and producers to supply less. Prices will stop rising or falling when they reach the new equilibrium price: the price at which the quantity that consumers demand matches the quantity that producers supply.

Experience with retail pricing experiments in New York, Georgia, California, and other states have demonstrated that customers are able to adjust their electricity consumption and are at least somewhat responsive to short-run price changes (i.e., have a non-zero short-run price elasticity o f demand). Georgia Power's Real Time Pricing (RTP) tariff option found that certain large industr ial customers who receive RTP based on an hour-ahead market ar e somewhat price-responsive (short-run price elasticities ranging fr om approximately -0.2 at moderate prices, to -0.28 at prices of $1/kWh or more). Among day-ahead RTP customers, shortrun price elasticities range from approximatel y -0.04 at moderate prices to -0.13 at high prices. National Grid also found lim ited responsiveness to price in its pricing program.134 A critical p eak pricing (CPP) experiment in California in 2004 determined that a test group of residential and small business customers responded to price and significantly reduced consumption (13 percen t on average, and as much as 27 percent when automated contr ols such as controllable thermostats were installed) during critical peak periods. In a ddition, the California pilot found that most customers on the C PP tariffs had a favorable opinion of the rates and would be interested in continuing in the program.135

Customer response to prices requires the following conditions: (1) that time-differentiated price signals are communicated to c ustomers; (2) that customers have the ability to respond to price signals (e.g., by reducing consum ption and/or turning on an on-site generator); and (3) that cu stomers have interval meters (i.e., so the utility can determine how much power wa s used at what time and bill accordingly) .136 Most conventional metering and billin g systems are inadequate for charging time-varying rates, and most customers are not used to considering price changes in making consumption decisions on a daily or hourly basis. There is, however, a significant effort underway to im prove metering technology and infrastructure to better f acilitate end-use price res ponsiveness.137

Box 2-2

Price Elasticity of Demand

The desire and ability of consumers to change the amount of a pr oduct they will purchase when its price increases is at the cor e of the concept of price elasticity of demand for that product. The price elasticity of demand is th e ratio of the percent change in the quantity demanded to the percent change in price. That is, if a 10 percent price increase results in a 5 pe rcent decrease in the quantity demanded, th e price elasticity of demand equals -0.5 (-5 percent ÷ 10 percen t). If the ratio is close to zero, demand is considered "inelastic," and demand is more "elastic" as the ratio increases. Short-run elasticitie s are typically lower than long-run
elasticities.

2. Supplier Responses Interact with Cust omer Demand Responses to Drive Production

Generation supply responses are equally important in the theoretical determination of an appropriate market price. The extent of supply responses will depend on the cost of increasing or decreasing output. Generally, the l onger industry has to adjust to a change in demand, the lower the cost of expanding output will be. With more time, firms have more opportunity to cha nge their operations or invest in new capacity.

If the cost of increasing production is small, a relatively sma ll price increase may be enough to encourage producers to increa se production in response to
increased demand. If the cost of increasing electricity output is high, how ever, suppliers will not increase production unless the price increases enough to cover the higher costs. In that case, customers would be compelled to pay significantly higher prices for additional supply. Additi onally, when suppliers are already delivering as much electric power as they physically can, increas ed demand can be met only from new capacity. If prices are to provide incentives for resource additions, suppliers must be confident that prices will rema in high enough for long enough to justify building a new generating plant.

These supply decisions are complicated because electric power ca nnot be stored economically, thus there are generally no invent ories of electricity. Therefore, electricity generation must always exactly match electricity consumption.138 The lack of inventories means that wholesale dema nd is nearly completely determined by end-use demand.139 Moreover, any distant generation must “travel” over a transmission system with its own limiti ng physical characteristics.140 Transmission capability must allow customers access to distant gene ration sources. The system is further complicated by the dy namics of the AC transmission grid, which can create network effects and can produce positive externalities (dependi ng on the method used in accounting for t ransmission costs).141 That is to say, where transmission users are not charged for the congestion impacts of their use patterns, users’ actions can cause costs to others which the causal party is not obligated to pay. This dynamic can distort the effect of price signals on dispatch efficiencies.

Another complication derives from the fact that aggregate retail de mand fluctuates throughout the day and over seasons, with ty pically higher demand during the day than at night. System operators must maintain a sufficien t mix of generating capacity and demand response (plus a margin o f standby generation and demand response for system support and reliability purposes) to meet peak customer demands at all times – even if a substantial share of that resource mix is only used during a small portion of the day or year. Thus, load-serving entities must supply or procure (through long-term con tracts and/or short-term “spot” market purchases) sufficient “energy” and demand response to meet varying loads. Generating res ources designed to meet these load changes are generally categorized as “base” load, “intermediate” lo ad and “peak” load. Base load generation runs more or less constantly and can be expensive to build but inexpensive to run once it is built (i.e., la rge coal and nuclear plants). Intermedia te load plants are designed to be brought online and shut down quickly to meet fairly predictable daily changes in load a bove the base level and below peak. A variet y of generating plants can be used for i ntermediate loads, including gas turbines, gas- and oil-fired steam boilers a nd hydro-electric plants. Peak load genera tion tends to come from units such as co mbustion turbines that can respond rapidly to changes in load, are quick and inexpensive to build, but are often expensiv e to run. The costs of generating electr icity for these different applications can differ substantially.

In any case, a higher price driven by resource scarcity shoul d signal a legitimate opportunity for economic profit, attracting new resource construction where it is most highly valued. At the same time customer demand may decrea se in response to rising prices. The increase in resources cou pled with a demand responseshould work together to bring prices down.

3. Customer and Supplier Behavior Res ponding to Price Changes in Markets

In sum, the combined impact of consumer and supplier responses to changed market conditions should produce a new market equilib rium price. Current prices must change when they create an imbalan ce between the quantity demanded and the quantity supplied. For example, when demand sp ikes, short-run prices might have to swing sharply highe r to provide incentives for short-run supply incr eases. However, consum ers do not have many g ood substitutes for electric power, and suppliers usually cannot increase output instantly or transport distant available ge neration to increase the quantit y supplied to a market. Even if higher prices give incentives to change behavior, consumers a nd producers may have little ability to do so in the short term. Over longer time frames, however, they have more options to react to higher prices. The result is that long-run price increases usually will be much smaller tha n the short-run price increases needed to induce additional generation.

C. Comparing the Benefits to the Costs of Restructuring Markets for Electricity

While the shortcomings of cost-based regulation played a major role in the shift to ward competitive electricity market structur es, some market participants question whether the benefits outweigh the costs associated with establishing such markets. Some question whether electricity markets are, by nature, sufficiently competitive to warran t expected price reductions.142 They note the co st of operating ISOs and the cost to consume rs of market manipulations and failures. Respondents to these concerns suggest that these ma rkets are too new to warrant passing such judgment. They note th at these failures may be a result of ill-advised market designs, and they find benefits despite such failures.

As various regulatory bodies considered whether to deregulate el ectricity markets, some conducted formal cost-benefit studies t o address the relative benefits of the status quo versus proposed policy changes. The Task For ce received many comments identifying, endorsing, or criticizing su ch studies. The Task Force did not, however, have the resources or time to fully examine, critique, or draw definitiv e conclusions from th ese widely varying s tudies. An annotated bibliography of many of these studies is attached as Appendix C. The Task Force also refers the reader to the summary conclusion of a recen t DOE review of RTO benefit
cost studies. See Box 2-3.

Box 2-3

Review of Cost-Benefit Studies

In December 2005, the Department of Energy released a study re viewing recent RTO Cost/Benefit an alyses. This study provides a review of the state of the art in RTO Cost/Benefit studies and suggests methodological improvement s for future studies. Following is a summary of this study ’s conclusions.

In recent years, government and private orga nizations have issued numerous studies of the benefits and costs of regional transm ission organizations (RTOs) and other electric market restructuring efforts. Most studies have focused on benefits that can be readily estimated using traditi onal production-cost simulation techniques, which compare the cost of centr alized dispatch under an RTO to dispatch in the region without an RTO, and on the co sts associated with RTO startup and operation. Taken as a whole, it is difficult to draw definitive conclusions from these studies because they have not ex amined potentially much larger benefits (and costs) resulting from the impacts of RTOs on relia bility management, generation and transmission investment and o peration, and on wholesale electricity market operation.

Existing studies should not be criticized fo r often failing to consider these additiona l areas of impact, because for the most part neither data nor methods yet exist on which to base definitive analyses. Th e primary objective of future studies should be to establish a more robust empirical basis for ongoing assessment of the electric industry’s evolution. These efforts should focus on impact s that have not been adequate ly examined to date, including reliability management, generation and transmission invest ment and operational efficiencies, and wholesale electricity markets. Systematic considerati on of these impacts is neither straightforward nor possible without im proved data collection and analysis.

J. Eto, B. Lesieutre, & D. Hale, A Review of Recent RTO Benefit-Cost Studi es: Toward More Comprehensive Assessmen ts of FERC Electricity Restructuring
Policies (December 2005) (prepared for the Department of Energy).
CHAPTER 3
COMPETITION IN WHOLESALE ELECTRIC POWER MARKETS

A. Introduction and Overview

As described in the preceding chapters, prio r to the introduction of wholesale market competition, vertically integrated utilit ies sold their excess electric power to other utilities and to wholesale customers such as municipalitie s and cooperatives that had little or no generating capacity of their own.143 FERC and its predecessor agency, the Federal Po wer Commission, regulated prices, terms and cond itions of interstate wholesale sales by inves tor-owned utilities. Wholesale purchasers’ desire to escape being captive to a vertically in tegrated monopoly supplier of elect ricity was a fundamental impetu s to opening the generation sector to competition.144 Sellers of wholesale power were also interest ed in accessing more customers. This desire for competition t o play a greater role in determining supply and demand is consistent with standard economic theory, which asse rts that effective competition ensures an economically efficient
allocation of resources.

As described in Chapter 2, an important effect of a competitive market operation is that it provides customers with prices that reflect market conditions (abundance, scarcity, etc.). These market-b ased prices are an essential component of effective competition, as they discipline both consumption and production such that the cost of generating electricity is minimized. Ho wever, the demand for wholesale power is derived entirely from co nsumption choices at the retail level. In electricity there has been an impediment to efficien cy in that prices of electricity to retail customers often are n ot directly connected to the wholesale prices in the market in which supplies ar e sold. This is because states have ju risdiction over retail prices, and state regula tors generally set retail rates based onaverage costs. Thus, unlike whol esale market-based prices, retail prices did not vary with consumption or the cost of producti on.145

The effects of this regulated price disconnect are heightened by one of the shortcomings of cost-based rate regulation: its dif ficulty in providing incentives for investors to make economically efficient decisions concerning when, where, and how to build new generation.146 If competition is to allocate resources in an economically efficient manner, customers must have access to a su fficient number of competing suppliers either via transmission , incumbent generation, demand response, or new local generation.147

Competitive policies in electricity markets were introduced to alleviate these disconn ects between retail demand, wholesale dem and, and investment incentives and to create more efficient markets.148 In EPAct 1992, Congre ss determined that competition in wholesale electric markets wou ld benefit from two changes to the traditional regulatory landscape: (1) expansion of FERC’s au thority to order utilities to tran smit, or “wheel,” electric p ower on behalf of others over their own transmission lines and (2) reduction of entry barriers so a dditional nonutilities could enter th e market. The former chang e permitted wholesale customers to purchase supply from distant generators, while the latter provided customers with competitive alte rnatives from independent ent rants.149

In examining the experience with competition to date, a fundamental question to ask is whether competition in wholesale markets has resulted in sufficient generation supply and transmission to provide wholesale customers with the kind of choice that is generally associated with com petitive markets. This is the primary question the Task Force attempts to address in this chapter. Answering th is question has been challenging due to diffi culties in identifying determinants of investment decisions. Each region was at a different regulatory and structural poi nt when Congress enacted EPAct 1992. For example, some regions began with tight power pools, while others opera ted transmission and generation in a less ce ntralized manner. Some regions had higher population densities and thus more tightly configured transmission networ ks than did others. Some regions had access to fuel sources unavailable or less ava ilable in other regions (e.g., natural gas supply in the Southeast, hydropower in the Northwes t). Currently, some regions operate under a transmission open-a ccess regime that has not changed since the early days of open access, while other regions have well developed independent providers of transmission serv ices and organized day-ahead exchange markets for electric power and ancillary services.

This chapter discusses the question at hand anecdotally – by a ddressing whether and how entry ha s occurred in several regions w ith different forms of competition (i.e., the Midwest, Southeast, California, the Northw est, Texas, and the Northeast). It includes a discussion of h ow long-term purchase and supply contracts, capital requirements, regulatory intervention, and transmission investment affect supplier and customer decisions. The chapter concludes with observations on various regional experiences with wholesale comp etition.150 These observations hi ghlight the trade-offs involv ed with various policy instruments used to introduce competition.

B. Background

One of the overall purposes of EPAct 1992 was “to use the market rather than government regulation wherever possible both to ad vance energy security goals and to protect consumers.”151 Policymaker s recognized that vertically integrated utilities had market power in both transmissi on and generation because they owned all transmission and nearly all generation plants within certain geographi c areas. Congress enhanced FERC’s ability to r educe monopoly power by enhancing its authority to order utilities, case by case, to transmit power for alternative s ources of generation supply.

Today, vertically integrated utilities and other entities that ope rate transmission systems genera lly are required to offer tra nsmission service under the terms of the standard Open Access Transmission Tariff (OATT) adopted by FERC in Order No. 888.152 Transmission providers offer two type s of long-term
transmission service under the OATT: networ k integration transmission service (network service) and point-to-point transmissio n service. Box 3-1 describes both types of transmission service. The OATT seeks to put market participants on equal footing when it comes to transmission a ccess – making competition more viable. Price has been predictable and stab le for both OATT services over the long term.153



# Comments to the Task Force raised several concer ns over transmission-dependent customers’ access to alternative generator suppliers via OATTs. In particul ar, some commenters noted the continued possibility
of transmission discrimination in thei r regions and that the ability for transmission suppliers to discriminate can block access to alternative suppliers. 154 Commenters concluded that transmission di scrimination can increase delivery risk because purchasers fear their transmission transacti ons might be terminated for anticompetitive reasons by their vertically integrated rival, if they purchase from a generator that is not affiliated with the transmission provider. The facts that elect ricity cannot be stored economically and electricity demand is very inelastic in the short term heighten delivery risk.

Box 3-1

How Transmission Services Are Provided Under the OATT

OATT contracts can be for point-to-point (PTP) or “network” transm ission service. Network inte gration transmission service all ows transmission customers (e.g., load-serving entities) to integrate their generation supply and load de mand with that of the transmission provider.

A transmission customer taking network serv ice designates “network resources,” which include all generation owned, purchased or leased by the network customer to serve its designated load, and individual network loads to which the transmission provider will provide transmissio n service. The transmission provider then provides transmission service as necessary from th e customer’s network resources to its network load. The custom er pays a monthly charge for this basic service, based on a “load ratio share” (i.e., the per centage share of the total load on the system that the customer ’s load represents) of the transmissionowning and operating utility’s “revenue requirement” (i.e., FERC-a pproved cost-of-service plus a r easonable rate of return).

In addition to this basic charge, there may be additional charges. For example, when a transmission customer takes network ser vice, it agrees to “redispatch” its generators as requested by the transmissi on provider. Redispatch occurs when a u tility, due to congestion, changes the output of its generators (either by producing more or less energy) to maintain the energy balance on the system. If the transmission provider redispatches its sys tem due to congestion toaccommodate a network customer’s needs, the costs of that redispatch are passed thr ough to all of the transmission provider’s n etwork customers, as well as to its own customers, on the same load-ratio sh are basis as the basic monthly charge.

The transmission provider must plan, construct, operate and mainta in its transmission system to en sure that its network custome rs can continue to receive service over the system. To the extent that upgrades or expansions are needed to maintain service to a network customer, the costs are included in the transmissionowning utility’s revenue requirement, thus impacting th e load-ratio share paid by network customers.

Point-to-point transmission service, which is available on a firm or non-firm basis and on a long- term (one year or longer) or short-term basis, provides for transmission between designated points of r eceipt and designated points of delivery. Tr ansmission customers that take this kind of service specify a contract path. A customer taking firm point-to-point tran smission service pays a monthly demand char ge based on the amount of capacity it rese rves. Generally, the demand charge may be the higher of the transmission provider’s embedded co sts to provide the service, or the incremental costs of any system expansion needed to provide the service. If the transmission system is constraine d, the demand charge may reflect the higher of the embedded costs or the transmission provider’s “opportunity” costs, with the latter ca pped at incremental expansion costs.

One response to this risk is to turn over operation of the regiona l transmission grid to an independent operator, such as the I SOs and RTOs that now operate in New England, New York, the Mid-Atlantic, the Midwes t, Texas, and California (organized markets). 

### 155 RTOs address deliverability concerns in several

ways. 156 The market designs in these regions provide participants with guaranteed physical access to the transmission system (subje ct to transmission security constraints). See Box 3-2 for a discussion of how tran smission is provided in organized wholesale markets.

In regions with RTOs, wholesale electricity can be bought and so ld through negotiated bilateral contracts, through “standard co mmercial products” available in all regions, and through various products offere d by the organized exchange market.

For bilateral contracts, the contract can be individually negotiated w ith terms and conditions unique to a single transaction. Standard products are available through brokers and over-the-counter (OTC) exchanges such as the NYMEX and InterContinental Exch ange (ICE).157 Standard produc ts have a standard set of specifications so that the main variant is price. Finally, some RTOs also operate organized ex change markets that offer variou s products including electric power and ancillary services. These markets typically involve both real -time and day-ahead sales. Ancillary services include variou s categories of generation reserves such as spinning and non-spinning reserves in addition to Automatic Generation Control (AGC) for frequency control.

Box 3-2

How Transmission Is Priced in an ISO or RTO

ISOs and RTOs (hereinafter RTOs) provide transmission service across a region under a single transmission tariff. They also op erate organized electricity markets for the trading of wholesale electric power and/or anc illary services. Transmission customers in these regions schedul e with the RTO injections and withdrawals of electric power on the system , instead of signing contracts for a specifi c type of transmission service with the transmission owner under an OATT.

The pricing for transmission service is substantially different in these regions than under a standard OATT. RTOs generally ma nage congestion on the transmission grid through a pricing mechanism called Locational Marg inal Pricing (LMP). Under LMP, the price to withdraw elect ric power (whether bought in the exchange market or obtained through some other method) at each location in the grid at any given time reflects the cost of making available an additional unit of electric power for purchase at that location and time. In other words, congestion may requi re the additional unit of energy to come from a more expensive generating unit than the one that cannot be accessed due to the sy stem congestion. In the absen ce of transmission congestion, a ll prices within a given area are the same at any given time. However, when c ongestion is present, the prices at various locations typically will not be the same, a nd the difference between any two locational prices represents the cost of transmission system congestion between thos e locations. This congestion cost constitu tes the only significant “variable
cost” of transmission – the fixed costs of infrastructure investment are recovere d through a standard transmission access fee.

Because congestion on the grid changes constantly, a transmission customer may be unable to determine beforehand the price for electric power at any location. To reduce this uncertainty, RTOs make a fi nancial form of transmission rights availabl e to transmission customers, as well as o ther market participants. Generally known as financial transmission rights (FTRs), they c onfer on the holder the right to receive certain congestion paym ents. Generally, an FTR allows the holder to collect the congestion costs paid by any user of the transmission system and collected by the RTO for electricity delivered over the specific path. In short, if a transmission customer holds an FTR for the path it takes service over, it will pa y on net either no congestion char ges (if the FTR matches the path exactly) or lower congestion charges (if th e FTR partially matches), providing a fina ncial “hedge” against the uncertainty.

In general, FTRs are now available for one-year terms (or less) and are allocated to entities that pay access charges or fixed transmission rates. Pursuant to EPAct 2005, FERC has adopted rules to ensu re the availability of long-term FTRs.

As described above, there is a question as to whether the price signals described in Chapter 2 have functioned to elicit the co nsumption and investment decisions that were expected to occur with wholesale ma rket competition.

C. Wholesale Electric Power Markets and Generation Investment by Region

New generation investment has varied signi ficantly by region since the adoption of ope n access transmission and the growth of c ompetition. Figure 3-1 shows the overall pattern of new investment by region. There has been substantial new investment in the Southeast, Midwest, and Texa s, while other regions have not experienced as much investment. Each re gion has different pricing formats for transm ission services. Moreover, regions that o perate exchange markets for electric power and ancillary services use different forms of lo cational pricing, price mitigati on, and capacity markets.Figure 3-1. U.S. Electric Generating Capacity Additions, 1960 – 2005

Source : FERC analysis of Platts PowerDat Data



# These regional differences provide some insight into the impact of different policy choices on creating markets with sufficient supply choices to support co mpetition and to allocate resources efficiently.

1. Midwest

a. Wholesale Market Organization

In 2004, the Midwest RTO began providing transmission services to wholesal e customers in its footprint. On April 1, 2005, the Midwest Independent System Op erator (MISO) commenced its organized electric power market operations. Prior to that, there were no centralized electric power exchange markets and
wholesale customers obtained transm ission under each utility’s OATT.

b. New Generation Investment

Wholesale prices spiked in th e Midwest in the summer of 1998, 158 as an increase in demand due to unusually hot weather combined with unexpected generation outages. A significant amount of new generation was built in response to the price spike, as shown in Table 3-1. For example, from January 2002 through June 2003, the Midwest added 14,471 MW in capacity.159

Most of the new generation was gas-fired, even though the regi on as a whole relies primarily on coal-fired generation.160 More recently, new generation has been coal fired, in part because of rising natural gas prices.161 This entry and the subsequent drop in wholes ale power prices has resulted in (1) merchant generators in the region declar ing bankruptcy and (2) vertically integrated u tilities returning certain generation assets from unregulated wholesale affiliates to
rate-base.

2. Southeast

a. Wholesale Market Organization

Wholesale customers in the region obtain transmission under each u tility’s OATT (e.g., Entergy or S outhern Companies). There a re no centralized electric power markets specific to the region.

b. New Generation InvestmentDue to the Southeast’s proximity to natural gas in the Gulf of Mexico and pipe lines to transport it, natural gas is a popular f uel choice for those building plants in the region. The Southeast has seen considerable new generation c onstruction, as shown in Figure 3-1. More than 23,000 MW of c apacity were added in the Southern control area between 2000 and 2005, 162 and several generation units owned by merchants or load-serving entities have b een built in the Carolinas in the past few years.

A significant portion of the region’s new gene ration was nonutility merchant generation, a nd a number of merchant companies tha t built plants in the 1990s have sought bankruptcy protection. Ofte n, the plants of bankrupt companies have been purchased by local vertically integrated utili ties and cooperatives, such as Mirant’s sale of its Wrightsville plant to Arkansas Electric C ooperative Corporation and NRG’s sale of its Audrain plant to Ame ren.163 Even apart from bankruptcies, some independent power producer s have withdrawn from the region.

3. California

a. Wholesale Market Organization

The California ISO began operation in 1998 to provide transmission se rvices. Concurrently, a separa te Power Exchange (PX) oper ated electric power exchanges. After the 2000-2001 energy crisis, the PX was dissolved.164

b. New Generation Investment

Even before the California energy crisis, California depended on imported electric power from neighboring states. Much of the generation capacity that serves
load in Southern California was built a s ubstantial distance away from the populati on it serves, making the region heavily depe ndent upon transmission. In the past few years, much of the generation in California has operated under long-term c ontracts negotiated by the state during the energy crisis.165 Since 2000- 2001, California’s demand has increased, but construction of local generation has not ke pt pace. Over 6,000 MW of new generati on capacity entered California in 2002-2003, but very little was built in congested, urban areas such as San Francisco, Los Angele s, and San Diego.166 Most n ew generation projects have
been in Northern California.167 In the past five years, transmission i nvestments have improved links between Southe rn and Northern California, and accessible generation investment in the Southwest has increased.

4. New England

a. Wholesale Market Operation

The New England ISO (ISO-NE) provides transmission services as well as a centralized electric power market. Under the electric power pricing mechanism adopted by ISO-NE, certain units used to ma intain local resource adequacy must bid into the energy markets at marginal costs un der must-run reliability
contracts. The fixed costs of these hi gh-priced units are recovere d from users in the pertinent reliability zone.

b. New Generation Investment

Much of New England’s net new generation ha s been built in less populated areas of the re gion, such as Maine, while most of the demand for power is in southern New England. From January 2002 through June 2003, ISO-NE added 4,159 MW in capacity.168 There were fewer capacity additions in 2004 than in the two previous years. In 2004, four generation projects came on line. Generation retirements in 2004 totaled 343 MW, of whic h 212 MW are deactivated

reserves.

Demand growth in the organized New England markets has led to “load pockets,” areas of high pop ulation density and high peak de mand that lack adequate local supply to meet demand and for which tr ansmission congestion prevents use of dist ant generation. These pockets have not s een entry of generation to meet local demand, and transmission has not always been adequate to bridge this gap. In general, New England needs new generation i n the congested areas of Boston and Southwest Connecticut, increased demand response, or in creased transmission investment to reduce congestion. Signif icant transmission upgrades were expected to go into operation in Bo ston and Southwest Connecticut during 2006.169

Theoretically, locational prices should elicit generation investment where needed, but th is has been inadequate in load pockets . The ISO-NE pricing methodology often did not allow the market clearing price to refl ect the cost of generation used to serve the congested areas.1 70 The resulting locational prices were not sufficient to attract significant new entry. Several po licies have been adopted to pr ovide the needed incentives. In 2003, ISO-NE implemented a temporary measure known as the Peaking Unit Safe Harbor (PUSH) m echanism, which was intended to enable greater cost recovery fo r high-cost, low-use units in designated congestion areas; however, PUSH units were not able to recover all thei r fixed costs.171 In June 2006, FERC appr oved a settlement establishing a forward capacity market in New England that will project demand three years in advance and hold annual auctions to purchase pow er resources for the region’s needs.172 The forward capacity market incl udes a locational component to account for areas where transmission congestion limit s the ability to import capacity necessary to meet local demand.

5. New York

a. Wholesale Market Operation

NYISO provides transmission services as well as a centralized electric power market. NYISO uses price mitigation to guard agai nst wholesale price spikes, but, in contrast to early ISO-NE practice, it includes high- cost generators in marginal locational pricing.

b. New Generation Investment

New York traditionally has built generation in less populated areas and transmitted the power to more populated areas. For exa mple, the New York Power Authority was created, in part, to get hydroelectric power from the Niagara Falls area into more congested areas of the state. From January 2002 through June 2003, NYISO added 316 MW in capacity.173 Three generating plants with a total summer capacity of 1,258 MW came on line in 2004 . Three plants totaling
170 MW retired in 2004.174

Currently, transmission constraints in and around New York City li mit competition in the city and lead to greater use of expens ive local generation, which resultsin high prices. NYISO uses price mitigation measures designed to avoid mitigating prices resulti ng from genuine scarcity. NYI SO has separate mitigation rules for New York City. In an effort to lessen distortion of market signals, NYISO includes the cost of running generators to serve load pockets in its calculation of locational prices. Thus, potential entrants get a more accurate price signal regarding investme nt in the load pocket.

In a further effort to spur new construction, NYISO also sets a more generous “reference price” for new generators in their fir st three years of operation (bids above the reference prices may trigger pric e mitigation).175 Unlike New England, New York is seeing new generation investment in at least one congested area. Approximately 1,000 MW of new capacity entere d commercial operation in the New York City area in 2006. The fact that New York is better able than New England to match locational need with invest ment is likely due to New York’s clearer market price signals, both in energy marke ts and capacity markets. However, the Public Utility Law Project of New York commented that it is the public power agencies and traditional investor-own ed utilities – rather than merchants responding to NYISO prices – that have invested in new infrastructure.

The effect of load pockets on prices is shown in Figure 3-2, which estimates the annual value of capacity based on weighted ave rage results of three types of auctions run by the NYISO. Capacity prices are highe r in the tighter supply areas of NYC and Long Island.



# Figure 3-2. Estimate of Annual NY Capacity Values

Dollars per kilowatt-year ($/kW-yr)

Source: FERC analysis of NYISO data



# 6. PJM

a. Wholesale Market Operation

The PJM Interconnection provides transm ission services as well as a centr alized electric power market. PJM has both energy and capacity markets. Its ener gy market has locational pr ices, and FERC recently approved, in principle, PJM’s pr oposal to shift to locational pr ices in its capacity markets. 176 The locational capacity market has not yet been implemented.

b. New Generation Investment

PJM capacity includes a broad mix of fuel types. Recent PJM e xpansion into new territories has added significant low-cost coal resources to PJM’s overall generation mix, although the National Rural Electric Cooperative Asso ciation (NRECA) commented that other parts of PJM lack suf ficient generation as a result of inadequate capacity additions. From January 2002 through June 2003, PJM added 7,458 MW in capacity.177 Capacity additions i n 2004 were lower than in the two previous years, especially consid ering that PJM added significant new territory in 2004. In 2004, 4,202 MW of new gene ration was completed in PJM. During the year, 78 MW of generation wa s mothballed and 2,742 MW was retired.178Like other areas, PJM depends on transmission to move power from areas of low-cost generation to areas of high demand. The flo w is generally from the western part of PJM, an area with significan t low-cost coal-fired generati on, to eastern PJM. The easternmost part of PJM is l imited by transmission line capacity constraints, which at times limit the deliverability of generation from the west . This means that higher-cost generat ion must be run in the eastern region to meet local demand. Furthermore, within the eastern region, there are areas of even more limited transmission. As a result, in some areas generation that is not economical to run is given reliability must-run (RMR) contracts to prevent it from retiring and possibly reducing local reliabi lity.179 Recently, three utilities in PJM proposed major transmission expansions to increase capacity fo r moving power into eastern parts of PJM.180 In its comments , PJM contends that it is experiencing a “robust” level of new transm ission investment for reliability upgrades.

7. Texas

a. Wholesale Market Operation

The Electric Reliability Council of Texas (ERCOT) manages power sc heduling on an electric grid consisting of about 77,000 MWs o f generation capacity and 38,000 miles of transmission lines. It also manages financial se ttlement for market participants in Texas's deregulated wholes ale bulk power and retail electric market. The Public Utility Commission of Texas regulates ERCOT. ERCOT generally is not subject to FERC jurisdiction because it s operations are not integrated with other electric systems outside of Texas (i.e., there is no interstate electric transmission). ERCOT is the onl y market in which regulatory oversight of the wholesale and retail markets is perfor med by the same governmental entity.

Each year, ERCOT determines the set of transmission constraints within its system that it deems Commercially Significant Constr aints (CSCs). Once approved by the ERCOT Board, the CSCs and the resulting Congestion Zones are used by the ERCOT dispatch pro cess for the next year. In 2 005, ERCOT had six CSCs and five Congestion Zones. When the CSCs bind, ERCOT economica lly dispatches generation units’ bi ds against load within each z one. To balance the system in real time, ERCOT issues unit-specific instructions to manage Local (intra-zonal) Congestion, then clears the zonal Balancing Energy Market. The balancing energy bids from all the generators are cleared in order of lowest to highest bid.181

At least one study asserts that when there is local congestion, lo cal market power is mitigated in ERCOT by ad hoc procedures a imed at keeping prices relatively low while maintaining transmission flows within limits. The study concludes that, as a result, pr ices may be too low to elici t needed investment when there is local scarcity. Since it is difficult for new entrants to enter local markets at these prices, local monopoly positions are es sentially entrenched.182

b. New Generation Investment

In the late 1990s, developers added more th an 16,000 MW of new capacity to the Texas market.183 Certain aspects of this market may make it attractive to new investment. Texas consumers directly pay (via their electricit y bills) for transmission system updates made to accommodate new plants. In other states, FERC often requires developers to pay for syst em upgrades upfront and recoup the cost over time through credits against their transm ission rates.184 In addition, the Texas PUC plans to implement an energy-only resource adequacy market design in the fall of 2006 that requires incrementally rai sing the energy offer caps over time. More than 13,000 MWs of new capacity is scheduled to be online in 2009-2011.185

c. Hybrid Wholesale/Retail Demand Response

ERCOT has a competitive market-based demand response program that allows competitive retailers, along with willing customers, t o respond to market-based price signals. Under the Load Acting As a Resource Program (LAA R), customers bid demand response into ERCOT's ancillary servic es market for responsive reserves through their scheduling agent.186 If needed by ERCOT, th e load is then paid the market-clearing price for responsive reserve. The LAAR program is fully subscribed at 1,150 MWs.

8. The Northwest

a. Wholesale Market Organization

Wholesale customers obtain transmission service through agreements executed pursuant to indivi dual utility OATTs. There are no centralized exchange markets specific to the region, but there is an ac tive bilateral market for short-term sales within the Northwest and to the Southwest and California, which makes use of centralized electronic exchange platforms (such as the InterCon tinental Exchange). Several tr ading hubs with significant level s of liquidity provide priceinformation. Multiple attempts to esta blish a centralized Northwest transmission ope rator have proven unsuccessful for a varie ty of reasons, including difficulties in applying standard restructuri ng ideas to a system dominated by cascading (i.e., interdependent nodes) hydroelec tric generation and difficulties in understanding the potential cost shifts that might result in rest ructuring contract-based transmission rights. A nascent organ ization created to enhance coordinated regional reliability and planning, ColumbiaGrid, has recently seated a board and begun development of various “func tional agreements.”187

b. New Generation Investment

The Northwest’s generation portfolio is dominated by hydroelect ric generation, which comprises roughly half of all generation r esources in the region on an energy basis.188 Coal and natural gas resources make up most of the remaining generation, with smaller contributions from wind, nuclear, and other resources. The hydroelectric share has decreased steadily since the 1960s.

The Northwest’s hydroelectric base allows the region to meet almo st any capacity demands within the region, but the region is s usceptible to energy limitations (given the finite amount of water availabl e to flow through dams). This ability to meet peak demand buffers incentives for bui lding new generation, which might be needed to assure sufficient energy supplies during times of drought. In three out of four years, hydro generation can displ ace much of the existing thermal generation in the Northwest. However, generation was added in recent years to meet load growth and to attempt to capitalize on high-prices during the Western energy crisis of 2001-2002. Due to high power purchase costs during this crisis, so me utilities have added thermal resources a s insurance against droughtinduced energy shortages and high prices. Altogether, over 3,800 MWs of new generation has been added to the Northwest Power P ool since 1995. Of that, 75 percent was commissioned in 2001 or later.

D. Observations on Current Wholesale Market Options

One of the most diffiult questions federal regulators currently face is whether the different forms of competition in wholesale markets have resulted in an
efficient allocation of resources. The vari ous approaches used by the different regi ons show the range of available options.

1. Open Access Transmission without an Organized Exchange Market

One option is to rely on the OATT to make generation options av ailable to wholesale customers. No centralized transmission ope rator or exchange market for electric power operates in regions that rely on this option (the Northwest and Southeas t). However, active trading platforms c an be found in these regions. These platforms provide liquidity and price transparency in some da y-ahead or longer-term markets – although the prices do not direct ly reflect the costs of congestion. For long-term sales in these markets, wholesale customers shop for alternatives through bilateral contracts with suppliers. In both cases, customers separately arrange for transmission via the OATT. With a range of supply options to choose from, long-term bilateral contracts for physic al supply can provide price stability for wholesale customers and send them a rough price signal so they can determin e whether to build or buy. However, p rices and terms can be unique to each transaction and may not be publicly available. Furthermore, the lack of centrali zed information about trades leaves trans mission operators with system security risks that constrain transmission capacity. The lack of price transparency can add to the difficulty of pricing long- term contracts in these markets.

This model depends significantly on the ava ilability of transmission capaci ty that is sufficient to allow buyers and sellers to connect. Thus, it also depends on the accurate calculation and reporting of availabl e transmission capacity. Short-term ava ilability is not sufficient, even if accu rately reported, to form a basis for long-term decisions such as contracting for supply or building new generation. Not only must transmission be available, it als o must be seen to be available on a nondiscriminatory basis. As FERC noted in Order 2000, persistent allegations of disc rimination can discourage investment even if they are not proven. Without the assurance of long-term transmission rights, wholesale custom ers may remain dependent on local generation owned by one or on ly a few sellers, because they cannot access competitive options supplied by more distant generation. Similarly, new suppliers may have no means of competing with incumbent generators
located close to traditional load.

2. Organized Wholesale Markets

In organized markets, market participants have access to an exchange market where prices for electric power are set in referenc e to supply offers by generators and demand by wholesale customer s (including Load-Serving Entities or LSEs). While prices can be set by a number of mechanisms , all U.S. exchange markets have a uniform price auction to determine the price of electric power. Uniform price auctions theoretically provide suppliers an incentive to bi d their marginal costs, to maximize their chan ce of getting dispatched.

The principal alternative to uniform price auctions is a pay-as -bid market.189 Research on whether pay-as-bid auctions result i n lower prices than do uniform price auctions has been evolving and the results are, at best, mixed. Theoretically, pay-as-bid auctions do not result in lowe r market-clearing prices and may even raise prices as suppliers base their bids on forecasts of market-clearing prices instead of their marginal costs. Recent research suggests that pay-as-bid can sometimes result in lower costs for customers.190 But the pay-as-b id approach may reduce dispatch efficiency, to the extent ge nerator bids deviate from their marginal costs.191 From a practical persp ective, academics and market designers genera lly agree that uniform price auctions in competitively structured markets produce economically efficient prices.

Currently, in uniform price auction markets some generators (e .g., coal- or nuclear-fueled units) may be earning a return above those typically allowed under cost-based regulation. But other generators (e.g., natural gas-fueled units) are earn ing returns below those typically allowed under cost-based regulation. In a competitive market, a unit’s profitability in a uniform price auction will depend on wh ether, and by how much, its production c osts are below the market clearing price. A uniform price auction thus may pr oduce very high prices compared with the co sts of some generators and yet not high e nough to give investors an incentive to build new generation that could moderate prices goi ng forward. The uniform price auction creates strong incentive s for entry by low-cost generators that will be able to displace high-cost gene rators in the merit dispatch order. The sufficiency of entry in uniform price auct ion markets has been a topic of discussion among policymakers and market participants. Four policy options have been suggested.

a. Unmitigated Exchange Market Pricing

One possible, but controversial, way to spur entry is to let whol esale market prices rise with scarcity.192 As discussed in Ch apter 2, the market likely will respond in two ways. First, the resulting pr ice spikes will attract capital and investme nt. To assure that the price signals elicit appropriate investment and consumption decisions, they must reflect the differences in prices of electricity avai lable to serve particular locations. The costs of supplying customers within the region may vary where transmission capacity limits the availability of electric power from some generators within a regiona l market. Without locational prices, investors may not make wise choices about where to invest in new generation.

Unfortunately, it is difficult to distinguish high prices due to th e exercise of market power from those due to genuine scarcit y. High prices due to scarcity are
consistent with the existence of a competitive market, and ther efore perhaps suggest less need for regulatory intervention. Hi gh prices stemming from the exercise of market power in the form of withholding capacity ma y justify regulatory intervention. Being able to distinguish be tween the two situations is therefore important in markets with market-based pricing.193Second, higher prices likely will influence cu stomer decisions about how much and when to consume. Price increases signal cust omers to reduce the amount they consume. Indeed, during the Midwest wholesale price spikes in the summer of 1998, consumption fell when prices rose as cu stomers purchased little supply during those periods.194 To reduce c onsumption efficiently, retail customers mu st have the ability to react to accurate price signals. As discussed in Chapter 4, customers often have limited in centive, even in markets with retail competition, to reduce their consumption when th e marginal cost of electricity is high. This is because retail rates in the short term do not vary to account for the costs of pr oviding the electricity at the actual time it was consumed.

b. Moderation of Price Volatility with Caps and Capacity Payments

To date, the alternative to unmitigated exch ange market pricing has been price and bid caps in wholesale exchange markets. Alt hough price and bid caps may moderate wide swings in market -clearing prices, there is disagreement as to th e appropriate level of the caps. Higher caps may strike a balance between a policy of smoothing out the peaks of the highest price spikes and one of demonstrating where capital is required and can recover its f ull investment. Some argue, however, that high price caps may burden consumers with high prices and yet not allow prices to rise to the level that will act ually ensure that investors will
recover the cost of new investment.195 T hus prices can rise significantly and yet not attract additional supply that could eve ntually moderate price.

Capacity payments are one way to ensure that investors recover fixed costs. Such payments can provide a regular payment stream that, when added to power market income, can make a project more economically viable. Li ke any regulatory construct, howev er, capacity payments have lim itations. It is difficult to determine the appropriate level of capacity payments to spur entry without over-taxing ma rket participants and consumers. In a ddition, because capacity payments include a reserve margin added on to demand, capacity markets may be more susc eptible to market pow er than energy mark ets. These markets may not be viable unless there is some mitigation policy, but de termining the appropriate mitig ation policy is a challenge.196

To the extent that capacity rules change, there is a perception of risk about capacity payments that may limit their effectiven ess in promoting investment and ultimately new generation. When rules ch ange, builders and investors ma y take advantage of short-term capacity payment spikes in a manner that is inefficient from a longer-term perspective.

If capacity payments are provided for generation, they may prompt generation entry when transmission or demand response would b e more affordable and equally effective. Capacity payments also may reward trad itional utilities and their affiliates disproportionately by providin g significant revenues for units that are fully depreciated. Capacity payments also may discourage entry by paying uneconomical units to keep running instead of exi ting the market. These concerns can be addressed somewhat by appropriate rules – e.g ., NYISO’s rules giving capacity payment preference to newly-enter ed units. In general, however, it is difficult to tell whether capacity payments alone would spur economically efficient entry.

One issue is whether capacity prices should be locational, simila r to locational electric power prices. PJM, ISO-NE and NYISO have either proposed or implemented locational capacity markets that may increase incen tives for building in transmissi on-constrained, high-demand area s. The combination of high electric power prices and high capacity prices in these areas ma y create adequate incentive to bu ild generation in load pockets .197

c. Encouraging Additional Transmission Investment

Building the right transmission facilities may encourage entry of new generation or more efficient use of existing generation l ocated near, but outside, load pockets. But transmission expansion to serve increased or new lo ad raises the difficulty of creating a rate structure that tie s the economic and reliability benefits of transmission to particular consumers. Because transmission investments can benefit multiple market participants, it is diff icult to assess who should pay for the upgrade, particularly when some market participants do not re quire the transmission to meet their needs. This regulatory c hallenge may cause uncertainty about the price for transmission and about return on investme nt both for new generators a nd for transmission providers.

Merchant transmission lines, built by nonutilities, once were thought to be a solution to the need for long distance transmissi on lines. However, few merchant
lines have been built. Uncertainties about revenue have made financing difficult. In add ition, difficulties in obtaining need ed rights-of-way and environmental approvals have chilled potential merchant projects.198 Provisions of EPAct 2005 that allow for federal permitting of transmiss ion projects under certain circumstances appear to have encour aged interest in new transmission projects, including merchant projects.199

Building or expanding transmission capacity, where possible, may re move the congestion that contributes to higher electricity p rices in load pockets and other transmission-constrained areas. However, the potential for build ing new transmission may reduce the incentive to build new gen eration in the load pockets or develop demand response and thus may sustain the high prices ther e. Once new transmission capac ity is built, it will increase supply options and decrease or dampen prices just as newly built generation or demand respons e would. Building or expanding transmission may increase supply more cost effectively than building new generation in load pocke ts and other constrained areas.

Both generation and merchant transmission builders must deal with an existing transmission owner or an RTO/ISO to obtain permis sion to interconnect their facilities. Moreover, there are substantia l difficulties in siting new transmission lines. It is difficult to assess whether these risks are higher for transmission builders than for generation builders or demand response programs.

d. Governmental Control of Generation Planning and Entry

The final alternative is a regulatory, rather than market, mechanism to assure that adequate generation is available to wholesa le customers. As a method to spur investment, regulatory oversight of planning has some positive aspects, but it al so has costs. Using regulation through govern mentally determined resource planning to encourage entry could result in more entry than th rough market-based solutions, but that entry may not occur where, when, or in a way that most benefits customers. Regulatory oversight of investment also means regulators can ba r entry for reasons other than efficiency. The stable rate of return on invested capital under rate regulation can en courage investment. On the other hand, rate regulation can lead to overinvestment , excessive spending and unnecessarily high costs. Regula tion also does not provide the same market disc ipline that effective competition provides. Un der regulation, ratepayers may bear the risk of mistakes resulting from where and how investme nts are made. In competitive mark ets, the penalties for such mi stakes fall on management and shareholders. Future accountability for investment decisi ons can lead to better decision-making at the outset.200

Some commenters strongly supported Integrated Resource Planning or other governmentally supervised planning processes to provid e optimal fuel diversity.201 In particular, they were concerned that the market acting alone creates boom-bust cycles where investors overreact to market si gnals and too many parties invest in one region. This creates overcapacity, which in turn leads to lower prices. Regulatory ove rsight of planning could result in greater fuel diversity, and thus less exposure to risks associated with changes in fuel prices or availability. Although IRP often includes consideration of future fuel prices, it is difficult to determine in advance the appropriate mix of fuels given the difficulty of projecting fuel prices. Regulator s and planners too can make f lawed resource decisions and have done so in the past.3. Market Oversight of Wholesale Energy Markets

Under current law, market oversight to pr event anticompetitive behavior is an important feature of organized wholesale electric ity markets. There is consensus about the need for market oversight and rules to ensure that wholesale electricity markets func tion efficiently and provide ben efits to consumers. FERC’s Office of Enforcement and state regulators perform this service by revi ewing wholesale electricity markets and the reports of internal and independent market monitors.202 Organized markets also are subject to ongoing scru tiny by state regulators and the independent market monitoring arms of RTOs.203 In sum, market oversight continues to be a vital element of organi zed wholesale markets, and efforts are ongoing to strengthen the oversight process.

E. Factors that Affect Investment Decisions in Wholesale Electric Power Markets

The Task Force examined comments on how competition policy choices have affect ed investment decisions of buyers and sellers in wholesale markets. A number of issues emerged. One was the difficulty of raising capital to build facilities whose revenue streams are affected by changing fuel prices, demand fluctuations, and the potential for regulatory intervention. A related theme was the i nvestment dampening effects of a perceiv ed lack of long-term contracting options. Some commenters asserted that significant problems s till exist in organized markets, including steep price increases in some locations without the moderating effect of long-term contracting and new construction.204 Alternately, the co mment was made that in some markets pri ces are so low that they discourage entry by new suppliers, despite growing projected de mand relative to supply.205 Overa ll, the Task Force identified six factors that affect investment decisions in wholesale power markets.

Commenters cited long-term contracts as a critical prerequisite in obtaining financing for new ge nerators.206 Both generators and consumers said they were unable to arrange long term contracts.

1. Unavailability of Long-Term Supply C ontracts - Wholesale Buyer Perspective

Many wholesale buyers said they had sought to enter into long- term contracts but found few or no offers.207 The Task Force att empted to determine whether the available data supported these allegati ons by examining 2004-2005 data collected by FERC through its Electric Quarterly Rep orts for three regions – New York, the Midwest, and the Southeast. Appendix E contains this analysis. Although inconclusive ( due to data limitations descr ibed in Appendix E) the analysis showed that contracts of less than one year predominated in each of the three regional markets examined. In two of the markets , longer contract terms were
observed to be associated with lower contract prices on a per MWh basis.

Three reasons may explain why buyers perceive they ca nnot enter long-term purchase power contracts.208

First, the APPA commented that its members in RTO regions who attempt to procure power under l ong-term bilateral arrangements h ave found it difficult to arrange contracts with base-load and mid-meri t generators at prices that reflect the generators' long-term total cost structure . Base-load and mid-merit generators may see relatively high profits when gas-fueled generators are th e marginal units, particularly when natural gas prices rise. Natural gas-fueled generators in a uniform price auction may see lower profits as their fuel costs rise, to the extent other genera tion becomes relatively more ec onomical.209 When natural gas units set the market price, these units may recover only a smal l margin over their operating cost s, while nuclear and coal unit s recover larger margins. Under the competitive model, entry will occur if l ong-term prices exceed long-term costs. In fact, recent proposals for new generation s how a significant number of proposals to build base-load and mid-merit ge neration.210 In addition, at least some wholesale customers may have the option o f investing in their own generation projects - either directly or th rough affiliates or joint ventur es with other interested parties - if they are dissa tisfied with the terms offered by incumbent suppliers. Indeed, in some re gions, public power and cooperative utilities ha ve announced plans to participate in ne w base-load generating plants. Because of the long lead times and consider able uncertainties involved, it will be some years before electricity from any of th ese plants can enter the market.

There are additional theoretical problems with the effectiveness of competition in provi ding investment incentives in that the very competitiveness of these markets cannot be assumed. For example, over 10 years ago, FE RC requested comments on a wholesale “PoolCo” proposal, the prede cessor to today’s organized electricity market with open tran smission access.211 At the time, the U.S. Department of Justice generally supported the emerging market form but
warned:

The existence of a PoolCo cannot guarantee competitive pricing, since there may be only a small number of significant sellers into or buyers from the pool. The Co mmission should not approve a PoolCo unless it finds that the level of competition in the relevant geographic mark ets would be sufficient to reasonably assure that the benefits of eliminating traditional ra te regulation exceed the costs.212

These concerns are heightened by the fact that the market-clearing price in organized exchange markets may be established by a changing subset of generators depending upon fluctuations in consumer demand and transmission congestion.213 Indeed , some commenters specifically cited rece nt studies that argue that electricity markets need a larger number of suppliers to sustain competitive prici ng than are needed for other commodities.214

A second explanation for the perceived lack of long-term purchase contracts may be related to limited trading opportunities to hedge the potential costs of longterm commitments. Long-term contracts in other commodities are often priced with refere nce to a “forward price curve.” A for ward price curve graphs the price of contracts with different maturities. The forward prices graphed are instrument s that can be used to hedge (or limit) the risk that market prices at the time of delivery may differ from the price in a long-term contract. In a market with liquid forward or futures contracts, parties t o a long-term contract can buy or sell products of various types and durations to limit their price ri sk. Currently, liquid electricity forward or futures markets of ten do not extend beyond two to three years.215 In some markets, one-year contracts are the longest ava ilable. In markets where retail load is served by contracts of fixed durations, such as the threeyear obligations in New Jersey and Maryland, contracts for the duration of the obligation are growing slowly in number. But th e relative lack of liquidity may discourage parties from signing long-term c ontracts, because they lack the ability to "hedge" these longer-term obligations.

Finally, the availability of long-term purch ase contracts depends on the availability and certainty of long-term delivery optio ns (transmission). Box 3-2 above describes how transmission prices are set in organized exchange markets. Wholesale customers have argued that the inability to secure firm transmission rights for multiple years at a known price, particul arly in organized markets, introduces unacceptable uncertainty in resource plannin g, investment, and contracting.216 They say this financial uncertainty has hurt their ability to obtain financing for ne w generation projects, especially new base -load generation.

Congress addressed the issue of insufficient long-term contracting in the context of RT Os and ISOs in EPAct 2005. In particula r, section 1233 of EPAct 2005 provides that:

[FERC] shall exercise the authority of the Commission unde r this Act in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonab le needs of load-serving en tities to satisfy the serviceobligations of the load-serving entitie s, and enables load-serving entities to secure firm transmission rights (or equivalent tradable or financial ri ghts) on a long-term basis for long-ter m power supply arrangements made, or planned, to meet such needs .217

To implement this provision in RTOs and ISOs, FERC adopted new ru les regarding FTRs in July 2006. The rules require such organ izations to offer long-term firm transmission rights. FERC did not speci fy a particular type of long-term firm transmission right, but instead established guidelines for the design and administration of these rights, such as the length of terms and the allocation of those rights to transmission customers.

2. Unavailability of Long-Term Supply Cont racts – Generator/Investor Perspective

Commenters cited long-term contracts as a critical prerequisite in obtaining financing for new generators.218 Comments from ge neration investors suggested that their ability to arrange long-term cont racts is inhibited by several uncertainties. Most of these uncertainties arise fro m the unpredictability of state and federal regulation. Finally, the nascence of market structures for the sale of elect ricity can make it difficult for market pa rticipants to have settled expectations about the risk of long-term contracts. A description of the uncertainties associated w ith regulatory risk follows.

One type of regulatory uncertainty derives from the fact that mo st wholesale contracts are subject to regulation by FERC, and a party to a contract can ask FERC to change prices and terms, even if th e specific contract has been approved previ ously.219 For example, in 2001-2002, several wholesale power purchasers asked FERC to modify certain contracts entered into during the Ca lifornia energy crisis. They a lleged that problems in the Cal ifornia electricity exchange
markets had caused their contracts to be unreasonable. The selle rs argued that if FERC overrides existing contracts, market pa rticipants would not be able to rely on contracts when transacting for power and managing price risk. In declining to change the contracts,220 FERC cited its oblig ation to respect contracts except when other action is necessary to protect the public interest.221

A second type of regulatory uncertainty i nvolving bankruptcy may limit future market opportunities for merchant generators and thus reduce their ability to raise capital. In recent years, several merchant generators (NRG, Mirant and Calpine) have sought to use the bankruptcy process to b reak long-term power contracts.222 This bankruptcy risk may cr eate an additional incentive to favor constr uction of generation by load-serving enti ties or to purchase from utility affiliates over wholesale purchases from merc hant generators.223 These disputes have spawned conflicting rulings in the courts . In particular, these cases have centered on separate, but intertwined issues. First, there is a question of where jurisdiction over efforts to end power contr acts properly lies, as between FERC and the bankruptcy courts, and to what extent courts may enjoin FERC from acting to enforce power contracts. Second, there is an issue of what standard applies to such efforts (what showing must a party make to rid itself of a contract). The law remains unsettled, as do parties’ expect ations.

A third type of regulatory uncertainty concerns regulated reta il service in states with retail competition.224 The uncertainty over how much supply a distribution utility will need to serve its customers, who have the option to switch, can prevent or discourage utilities from signing long- term contracts.225 The extent of this disincentive is unclear if competitive op tions are available for distribution utilitie s to purchase needed supply or sell exces s supply.

A fourth type of uncertainty relates to a general concern about institutional instability . Some market participants argue that they cannot count on current rules and trading mechanisms because market rules and institutions change so frequently. This can serve to deter new entry.226 At t he same time, many market participants continue to advocate changes in regulatory policy, even long-settled policy.



# 3. Capital Requirements - Risk and Reward in the Face of Price and Cost Volatility

New generation construction in wholesale markets depends on the ability of a co mpany to acquire capital,
either from internal sources or ex ternal capital markets. There is no federal regulation of generation entry, and most states that have permitted retail competition have eliminated any “need-based” showing to build a generation plant.

In the United States, private capital has funded most el ectric generation investment . Under traditional costbase rate regulation, utility investme nt decisions were based in part on the promise of a regulated revenue
stream with little associated risk to the utility. Ratepaye rs often bore the risk, and money from capital markets was generally available when utilities needed to fund new infrastructure . One significant problem, however, was that regulators had lim ited ability to ensure that utilities spent their money wisely. 227 Investors view regulatory disallowances of imprudent expenditures as regulatory risk. Some believe that Integrated Resource Planning pro cesses with opportunities for public and regulator participati on in advance of resource procurement decisions will reduce the risks of later regulatory disal lowances.228

In competitive markets, project funding is based on anticipated mark et-based projections of costs, revenues, and relevant risks factors. The ability to obtain funding is impacted by the degree to which these projections co mpare with projected risks and returns for other investment oppo rtunities.229 Using this information, potential entrants to generation markets must be ab le to convince capital markets th at new generation is a viable profitable undertaking. In the late 1990s, investors appeared to prefer market i nvestments to cost-based rate -regulated investments, as merchant generators were ab le to finance numerous generation projects, even without a contractual co mmitment from a customer to buy the power.230

Recently, capital for large investment projects has flowed to tr aditional utilities more than to merchant generators.231 In pa rt, this preference reflects the reduced profitability of many merchant ge nerators in recent years and the relative financial strength of many traditional utili ties. It also may reflect a disproportionate impact of the collapse of credit and thus trading capability of nonutilities afte r Enron’s financial collapse. 232 As shown in the Table in Appendix G, virtually all electric companies rated A- or higher are traditional utilities, not merchant generators.

Investor preference for traditional utilities al so may be affected by increasing volatility in electric power markets. As whol esale markets opened to competition, investors recognized that income streams fr om the newly-built plants would not be as predictable as in the past.233 Under cost -based regulation, vertically integrated utilities’ monopoly service territori es significantly limited the risk of not recovering the costs of investments. Once generators had to compete for sales, generation plant investors were no l onger guaranteed that construction costs would be repaid or that the output from pla nts could be sold at a profit.234 Financing was easier to obtain for projects such as combined cycl e gas and particularly gas turb ines that can be built relative ly quickly. At the time, they were thought to have a cost advantage over ex isting generation, including less efficient ga s-fueled generators.235 In 1996, the EIA projected that 80 percent of electric generators between 1995 a nd 2015 would be combined cycle or combustion turb ines.236 Base-load units, such as coal pla nts, with construction andpayout periods that would put capital at risk fo r a much longer time, were harder to finance.237

The increasing amount of new generation fueled by natural gas, how ever, has caused electricity prices to vary more frequently a s natural gas is a commodity subject to wide swings in price.238 With input costs varying wi dely, but merchant re venues often limited by contract or by reg ulatory price mitigation, investors may worry that merchant generators may not recover their costs and provide an attrac tive rate of return. Commenters suggest th at competitive suppliers are beginning to focus on developing facilities fueled by other sour ces. They cite 2006 announcements by NRG Energy, Inc. (investi ng $16 billion to develop 10,500 MW of nuclear, wind, and coal facilitie s), TXU (investing in multiple coal-fired plants), Constellation Energy and Exelo n Corp. (developing a nuclear plant), BP and Edison Mission Group (inves ting $1 billion in a hydrogen-fueled plant) , and AES (investing $1 billion in renewab le technologies).239

4. Regulatory Intervention May Affect Investment Returns

Economic theory says that, in an unregulat ed world, needed generation investments w ill be made and generation investors will re cover not only their variable and fixed costs but also make an adequate return on these needed i nvestments to maintain long-term financial viability. The mechan ism for this cost recovery of the correct level of generation investment is allowing the highest co st generator being dispatched at a particular time and place t o determine the market clearing price. The mechanism works as follows: As resources become scarce relative to demand, market prices are set by more and more expensive resources.
Generators with variable costs below the market clearing price receive “scarcity rents” that cover their fixed costs and provid e a return on investment. If high prices in a particular energy market reflect scarcity, these economic rents generally are effici ent and serve to provide incent ives for construction.

However, regulators may limit recovery of high prices during these periods due to th e unpalatability of even temporarily high p rices and/or suspicion of inappropriate market gaming. Thus regulat ors may deter suppliers from making needed investments in new capacity by imposing pr ice caps and limiting recovery of legitimate costs and de livery of adequate returns.

This dynamic leads to a chicken-and-egg c onundrum: if there were efficient investment , wholesale price or bid caps might not be needed. More investment in capacity would lead to less scarcity, and t hus fewer or shorter episodes of high prices that may require mitigation. By contra st, it may be that price regulation during high-priced hours diminishes investors’ confidence that market forc es (rather than regulation) will set prices. That di minished confiden ce in their ability to earn sufficient investment returns thus deters entry of new generation supply, thereby li miting competition and giving cause for price caps.

Price mitigation through price or bi d caps has become an integral component of most organized markets. The use of price mitiga tion has led generators to seek adequate returns through implementation of su pplemental revenue streams (capacity credits ) to encourage entry of new supply. S ee Box 3-3 for a discussion of capacity credits. In practice, however, th e presence or absence of capacity credits has not always resulted in predicted outco mes. California did not have capacity credits and did not experience much new generation, but two regions (Southeast and Midwest) experienced significant ne w generation entry without capacity credits. Northeast RTOs with capacity credits continue to have some di fficulty attracting entry, especially in major metropolitan areas.

As noted, much of the new generation in the Southeast was nonu tility merchant generation that relied on the region’s proximity to natural gas supplies. In the Midwest, in the late 1990s, largely uncapped prices were allowed to send price signals for investment. In California, price ca ps of various kinds have been used for a number of years, limiting price signals for new entry. In the Northeast, organized market s have offered capacity payment s for long-term investments in addition to electric power prices that are sometimes capped in th e short term. There is no conclusive result from any of these approaches – no one model appears to be the perfect answer for how to spur efficient investment with acceptable levels of price volatility.

Box 3-3

The Use of Capacity Credits in Organized Wholesale Markets

In theory, capacity credits coul d support new investment because suppliers and their investors would be assured a certain leve l of return even on a marginal plant that ran only in times of high demand. Capacity credits might a llow merchant plants to be suff iciently profitable to survive e ven in competition with the generation of formerly-integrated local utilities that ma y have already recovered their fixed costs. Net revenue analyses for centralized market s with price mitigation suggest that price levels are inadequate for new generation projects to recover their full costs. For example, in the last several years, net revenues in the PJM markets have been, for the most part, too low to cover the full costs of new generation in the region.240 Based on 2004 data, net revenues in New England, PJM a nd California would have allowed a new combined-cycle plant t o recover no more than 70 percent of its fixed costs.

Regulation also may interfere with efficien t exit of generation plants due to the us e of reliability-must-run requirements. In some load pockets in organized markets, plant owners are paid above-market prices to run plants that are no longer economical at the market-clearing price. F or example, in its Reliability Pricing Model filing with FERC, PJM states, “PJM also has been forced to i nvoke its recently approved generation retirement rul es to retain in service units needed for reliability that had announced their retirement. As the Commission of ten has held, this is a temporary and suboptim al solution. Such compensation, like the RMR contracts allowed elsewhere, is outside the mark et, and permits no competition from , and sends no price signals to , other prospective solutions (such as new generation or demand resources) th at might be more cost effective.”241 To the extent that market rules allocate t he cost of keeping these plants running for customers outside of the load pocket, such payments may distort price signals that, in the long run, could elicit e ntry. Graduated capacity payments that favor entry of efficient plants may be a par tial solution to retiring inefficient old plants.

5. Investment in Transmission: A Ne cessary Adjunct to Generation Entry

Transmission access can be vital to supporting competitive options for market participants . For example, merchant generators d epend on the availability of transmission to sell power, and transmission constraints can limit their range of poten tial customers. Small utilities, such a s many municipal and cooperative utilities, depend on the availability of tran smission to buy wholesale power, and tran smission constraints can limit their rang e of potential supplie rs. Much of the transmission grid is owned by ve rtically-integrated, investor-o wned utilities. Some have alle ged that these utilities have an incentive to limit grid use by others
to the extent that such use conflicts with sales by their own generation. In short, the availability of tr ansmission is often key in determining whether a generating facility is likely to be profitable and, thus, elicit investment.

Since Order No. 888, questions have arisen concerning the efficacy of various terms and conditions governing transmission avail ability. For example, customers have raised concerns regarding the calcula tion of Available Transfer Capacity (ATC). Another concern has been a lack of coordi nated transmission planning between transmission providers and their customers. Finally, cust omers have raised concerns about some aspects of transmission pricing. Based on theseconcerns, in May 2006 FERC proposed modifi cations to Order 888 open access transmission tariffs to further limit undue discrimi nation in transmission services. FERC is soliciting public comments on its proposed modifications.

As discussed above, generation that is bu ilt where construction costs are low and fuel supplies readily available, but not nece ssarily near demand, relies heavily on readily available transmission. The Conn ecticut DPUC noted that, while generation gr owth may have been sufficient for some regions such as New England as a whole, some localized areas saw demand grow without increases in supply, raising prices in load pockets. If transmission access to the load pocket were available, a large base-load plant outside the load pocket might become an attractive investment.

Less regulatory intervention in wholesale ma rkets for generation may be necessary if transmission upgrades, rather than unrestr icted high prices or capacity credits, are used to address the concerns about future genera tion adequacy. Although capacity credits may spur generators with in a load pocket to add additional capacity, capacity credits may not be required for base-load plants outside the load pocket. T hose base-load plants would not have the problem of average revenues falling below average costs because they would have access to more load, and would be able to run profitably during mo re hours of the day. Similarly, price caps may be unnecessary if improved tr ansmission brought power from more base-loa d units into the congested areas. Price s would be lower because there would be less scarcity, and high-cost units would run for fewer hours.

6. Some Types of Generation Investment May No t Be Adequate without Government Intervention

System reliability, the prevention of netw ork collapse, is a public good.242 The ma rket may not elicit enough generation that has the technical capability (i.e., the ability to generate MWs within a very s hort period of time in a critical location) to prevent network collapse. An adminis trative process may be needed to

provide the correct level of generation tec hnically capable of responding to reliability needs. Some argue that perceived inad equate generation entry 243 may be due to competitive policies that are inadequate for eliciting appropriate levels of techni cally capable generation.

7. The Level of Investment in Demand Response Can Aff ect the Need for Generation and Transmission Investment

Chapter 2 described the typical disconnect between wholesale and re tail prices in electric market s. This disconnect can lead t o wider price fluctuations than would be the case if customers could easily reduce their demand when prices rise. There are several means to influence the lev el of demand for power, including energy efficiency and demand response. Examples of energy e fficiency include giving customers incentives to replace inefficien t refrigerators and air conditioners and imposing applian ce standards or more energy-efficient building codes. Tools for eliciting demand response inc lude time-based rates and incentive-based programs. Time-based rates include time-of-use pr icing (i.e., a peak price and an off-peak price), critical pea k pricing (i.e., similar to time-of-use rates, but with a critical peak component invoked during system emergencies or periods of high w holesale prices), and real-time pricing (e.g., Georgia Power's RTP tariff). Incentive-based demand response programs include interruptible rates, ai r-conditioner cycling, and independent sys tem operator emergency demand

response programs.

By influencing demand, energy efficiency and demand response programs can affect prici ng in the short term and in the long term by affecting the amount of generation and transmission needed as well as the composition (i .e., composition of base load, mid-merit and peaking generation ) of investment. For instance, programs that aim to reduce electricity consumption that is fairly constant – such as refrigerator efficiency programs – reduce the need for base-load plants. Similarly, programs that improve the efficiency of appliances that contribute to peaking load (i.e., air conditioners) can redu ce demand for mid-merit generation. Demand response programs that curtail demand at peak times may resolve constraints that cause load pockets. Even when constrai nts persist, demand response can also serve to reduce prices in load pockets whether these high prices are th e result of scarcity rents or market power. DS M also holds the potential to defer the need for new transmission enhancements. To date, energy e fficiency has provided important benefits, but additional capabili ty can be achieved. Demand response capability has been modest, between 3 and 7 percent in mo st regions.244 The use of energy efficiency and demand respo nse is expected to increase significantly in the next few years, especially after advanced smart metering is installed.

CHAPTER 4
COMPETITION IN RETAIL ELECTRIC POWER MARKETS

A. Introduction and Overview This chapter examines the develo pment of competition in retail electricity market s and discusses the status of competition in t he 16 states and District of Columbia that currently allow customers to choose their electricity supplier.245

Although it has been almost a decade since states started implemen ting retail competition, residential customers in most of the se states still have little choice among suppliers. In most of these states, few residential customers have a wide vari ety of alternative suppliers and pricing o ptions. Commercial and industrial (C&I) customers have more choices and options, but in several st ates large industrial customers have become increasingly dissat isfied with retail prices.

The lack of incentives for altern ative suppliers and marketers to enter the market at the retail level has been a major impedim ent to market-based competition. Most states required the distribution utility to offer electricity at a regulated price as a backstop or default if the custome r did not choose an alternative supplier or if the chosen supplier went out of busine ss.246 States argued that this was needed to ensure universal access to affordable an d reliable electricity.

States often set the price for the regulat ed service at a discount be low then-existing rates and capped the price for multi-yea r periods. In some states, these initial discounts sought to approximate anticipated be nefits of competition for residential cust omers. Since then, wholesale prices ha ve increased. More than any other policy, this requirement that distribution utilities offer servi ce at low prices unwittingly impeded entry by alternative suppl iers to serve retail customers. New entrants cannot compete against a below-market regulated price.

States with prices regulated at below-market levels now face “r ate shock.” On the one hand, rate caps for the regulated servic e most residential customers use expired or will expire within a few years, and states are faced with raising their regulated customer rates. These higher pric es are particularly painful to customers that have limited ability to adju st consumption in response to price incr eases and also lack competitive supply optio ns (other than po ssibly to install their own onsite generation). On the other hand, if states c ontinue to require distribution utilities to offer regulated servi ce at below-market rate s, then retail entry – and thus competition – will not occur. Moreover, below-market rates put the distribution utility’s solvency at risk and do n ot provide appropriate incentives for
conservation.247

This conundrum is further complicated by the fact that most distribution utilities offering regul ated service no longer own gen eration assets. Most of the supply contracts that were part of the agreements under which they divested gene rating assets were set to expire at the end of a finit e transition period.248 Many
distribution utilities sold or transferred th eir generation assets to unregulated aff iliates when retail competition began. If they offer regulated service, they must purchase supply in wholesale markets. Their former generation asse ts may be more expensive now than when they were divested. If the utility repurchases these assets at current prices, it is likely to have “sold low and bought high.”The competitiveness of wholesale prices directly affects retail prices,249 except where retail prices are set by regulation wit hout regard to current wholesale prices. For example, retail prices usually will reflect imperfec tions in the wholesale market, su ch as some wholesale supplier s’ ability to exercise market power,250 problems in market design that increase wholesale supp liers’ costs, government subsidies to some suppliers for reason s other than addressing market failures, transmission discrimination that prev ents low-cost suppliers from reaching cust omers, or restrictions that delay or p revent entry and diffusion of lowcost generation technologies. Distortions in wholesale prices that lead to distortions in retail prices can cause economic ine fficiencies both in retail customers’ consumption patterns and in investment deci sions. Ultimately these distortions can reduce consumer welfare and raise private a nd social costs of producing goods made with electricity as an input.

This chapter addresses the status and impact of retail competiti on in seven states that the Task Force examined in detail: Ill inois, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, and Texas.251 These states repr esent the various approaches to retail competition.252 The cha pter also discusses why it is difficult to determine whether retail prices are higher or lower th an they would have been abse nt the move to retail competitio n. Also included are several observations based on experiences of states that have implemente d retail competition, with an emphasis on how states can minimi ze market distortions once rate caps expire.

B. Background on Provision of Electric Service and the Emergence of Retail Competition

For most of the 20 th century, local distribution utilities typically offered electric service at rates that varied among customer classes (e.g., re sidential, commercial, and industrial). State regulatory bodies set these rates based on the utility’s costs. Locally elected boards oversaw the rat es for customers of public power and cooperative utilities. For investor-owned syst ems, the regulated rate included an opport unity to earn an authorized rate of re turn on investments in utility plants needed to serve customers. Public power and cooperative syst ems operate under a nonprofit, cost-of-service structure. Their ra tes typically include a margin to cover unanticipated costs a nd support new investment.

With minor variations, monopoly distribution u tilities deliver electricity to retail customers. 253 Industrial customers sometimes can choose from more options
than can small business and residential customers for service and rate structures (e.g., “time-of-use” rates, which are lower w hen demand is lower during “offpeak” periods).254

Beginning in the early 1990s, several states with high electricity prices began to e xplore opening retail electric service to c ompetition. As discussed in Chapter 1 and Figure 4-1, rates varied substantially among utilities, even within a single state. Some of the disparity was due to diffe rent natural resource endowments across regions, the most important of which are the hydroelectric resources in the Northwest and the abundant coal reserves in such states as Kentucky and Wyoming. Moreover, some states required utilities to enter into PURPA contracts at prices much higher than the utilities’ avoi ded costs. In addition to these rate disparities, some industrial customers contended that thei r rates subsidized lower rates for residential customers.

Figure 4-1. U.S. Electric Power Industry, Aver age Retail Price of Electricity by State, 1995

Cents per kWh

Source : EIA, The Changing Structure of the Electric Power Industry , Figure 11 (Dec. 1996). 

# Retail competition allowed customers to choose their el ectric supplier or market er, but their electricity

# would still be delivered by th e local distribution utility. 255 The idea was that customers could obtain electric service at lower prices if they could choose among suppliers. For example, they could buy from suppliers outside their local market, from new entrants into generation, or from power marketers, any of which might charge lowe r prices than the local distribution utility. The ability to choose among alternative suppliers was intended to reduce market power that local suppliers might otherwise have, so that customers might see lower prices from local suppliers. Also, i t was thought that new suppliers might offer innovative price and other terms to purchase el ectricity that could improve the quality of service.

In 1996, California enacted a comprehensive electric restructuring plan to allow customers to choose their electricity supplier . To accommodate retail choice, California extensively restructured its elect ric power industry. The legislation:

(1) established an Independent System Operator (ISO) to operate the transmission grid thr oughout much of the state, so that all sup pliers could access the transmission grid to serv e their retail customers;

(2) established a separate wholesale trading market for electricity supply, so that utilities and alternative suppliers could purch ase electricity to serve their retail customers; (3) mandated an immediate 10 percent rate reducti on for residential and small commercial cu stomers that did not choose an alternati ve supplier; (4) authorized utilities to collect stranded costs related to generation investments that were unlikely to be as valuable in a comp etitive retail environment; and (5) implemented an extensive public benefits program funded by retail ratepayers.256

Other states also enacted comprehensive retail competition le gislation: New Hampshire (May 1996), Rhode Island (August 1996), P ennsylvania (December 1996), Montana (April 1997), Oklahoma (May 1997), and Maine (May 1997) . By January 2001, 22 states and the District of Columbi a had adopted retail competition legislation. Regulatory commi ssions in four other states (including Ariz ona, which also enacted legislation) had i ssued orders requiring or endorsing
retail choice for retail electric customers.

Several states – primarily those with low-cost electricity gene ration, such as Alabama, Colorado, North Carolina, and Wisconsin – concluded that retail competition would not benefit their customers.257 For example, Colorado was concerned that limitations on transmission access and high concentration among generation suppliers would lead suppliers to exercise market power to the detriment of customers. These states opted to keep t raditional utility service.

States adopting retail competition plans generally did so to advance several goals, including:

lower electricity prices than under traditional regulation thr ough access to lower-cost power in competitive wholesale markets where generators compete on price and performance; better service and more options for custom ers through competition from new suppliers; innovation in generating technologies, grid ma nagement, use of information technology, and new products and services for consum ers; and improvements in the environment through displacement of dirtier, more expensive generating plants with cleaner, cheaper natural -gas-fired and renewable generation.

Under the restructured model, legislatures and regulators affirmed their support for making electricity available to all custom ers at reasonable rates, with
continued safe and reliable service and c onsumer protections under regulatory oversight . Boxes 4-1 and 4-2 describe the Pennsy lvania and New Jersey legislatures’ findings and the expect ed results of retail competition.Box 4-1

Findings of the Pennsylvania Legislature

The findings of the Pennsylvania General A ssembly demonstrate these varied goals:

(1) Over the past 20 years, the federal government and state government have introduced competition in several industries that previously had been regulated as natural monopolies.

(2) Many state governments are implementing or studying policies that would create a co mpetitive market for the generation of e lectricity.

(3) Because of advances in electric generation technology and fe deral initiatives to encourage gr eater competition in the whole sale electric market, it is now in the public interest to permit retail customers to obtain direct access to a competitive generation market as long as safe and a ffordable transmission and distribution is available at levels of reliability that are cu rrently enjoyed by the citizens a nd businesses of this Commonweal th.

(4) Rates for electricity in this commonw ealth are on average higher than the nationa l average, and significant differences exi st among the rates of Pennsylvania
electric utilities.

(5) Competitive market forces ar e more effective than economic regulation in c ontrolling 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.HTM

Box 4-2

Findings of the New Jersey Legislature

“The [New Jersey] Legislature finds and declares that it is the policy of this State to:

(1) Lower the current high cost of energy, and improve th e quality and choices of service, fo r all of this State's residential, business and institutional consumers, and thereby improve the quality of life and place this State in an improved competitive position in regional, national and inte rnational markets;

(2) Place greater reliance on competitive mark ets, where such markets exis t, to deliver energy servi ces to consumers in greater variety and at lower cost than traditional, bundled public utility service; . . .

(4) Ensure universal access to affordable and re liable electric power and natural gas service;

(5) Maintain traditional regulatory authority over non-competitive energy delivery or othe r energy services, subject to alterna tive forms of traditional regulation authorized by the Legislature;

(6) Ensure that rates for non-competitive public utility services do not subsidize the provision of competitive services by pub lic utilities; . . .”

C. Meltdown and Retrenchment

From late spring 2000 and into the spring of 2001, California e xperienced high natural gas prices, a strained transmission syst em, and generation shortages (due to hydro shortages and operating re strictions) that resulted in blackouts. Wholes ale electricity prices soared during this tim e. Existing state law had capped residential “provider of last resort” (POLR) service rates at le vels that were soon below the market price for wholesale electric power. After a large investorowned utility declared bankruptcy because it was unable to increase its retail rates to cover high wholesale power prices, the state stepped in to buy electricity on
behalf of two of the state’s three IOUs. 258 California eventually suspended retail co mpetition for most customers while it rec onsidered how to assure adequate electric supplies and continuation of service at affordable rate s in a competitive wholesale market environment. Although that suspension continues today, 12percent of load in the state is supplied by alternative suppliers, some additional cons umers remain eligible to switch to alter native suppliers, and new initiatives for municipal aggregation are being pursued .259 Box 4-3 describes California’s role in purchasing electricity and the all-time -high prices it paid, and continues
to pay.

The California experience sent ripple effects throughout the Wester n region and prompted several states to defer or abandon eff orts to implement retail competition. No new states have adopted retail competition si nce 2000, and some states – including Arkansas and New Mexico – r epealed retail competition plans they previously had adopted.

Other populous states, such as Illinois, New Jersey, New York, Penns ylvania, and Texas, moved ahead with retail competition. S ome of these states ended, or are about to end, their POLR service rate caps and will soon purch ase wholesale supplies for POLR service at market prices (alt hough several of these states are developing approaches to slow the adjustment to market-based procurement). States such as New York and Texas, which have adjus ted POLR prices to approximate market rates on an ongoing basis, do not face a potentially significant increase in POLR service prices.

Box 4-3

California’s Electricity Purchases at All-Time-High Prices

In 2001, California spent over $10.7 billion to purchase electricity on the spot market to supply customer’s daily needs. The state also signed long-term contracts worth approximately $43 billion for10 years. These contracts re presented about one-third of the three utilities’ requirements for the same period (2001–2011). Viewed with the benefit of perfect hindsight, the state entered th ese long-term contracts when prices were at an all-time high. Future prices hovered in the range of $350-$550 per MWh during the time Californi a negotiated its long-term contracts, and in April future prices peaked at $750/M Wh as the state finalized its last contract. By August 2001, future prices ha d dropped below $100. Thus, as of May 2006, the state is obligated to pay well over market prices for at least five

more years. See Southern California Edison.

As shown in Figure 4-2, 16 states and the District of Columbia have restructured at least some electric utilities in their stat es and allow at least some retail customers to purchase electricity directly from competitive reta il suppliers. Restructured states as of April 2006 include Con necticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampsh ire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, and Vi rginia, as well as the
District of Columbia.

Figure 4-2. United States Map Depicting States with Retail Competition, 2003Source : EIA, available at http://www.eia.doe.gov/cneaf/elect ricity/chg_str/restructure.pdf



# D. Experience with Retail Competition

With the expected benefits of retail competition in mind, the Task Force examined seven states in depth. These “profiled states” – Illinois, Maryland, Massachusetts, New Jers ey, New York, Pennsylvania, and Texas – represent the different a pproaches to retail competition.

In most profiled states, competition has not developed as expected for all customer classes. In general, few alternative suppliers currently serve residential customers. Where there are multiple suppliers, prices have not decreased as expected, and the range of new opti ons and services often is limited. Development of retail competition has been impeded to a considerable extent by the fact th at several states still have capped residential POLR rates. C&I customers generally have more choices in both suppliers and of customized services, than do re sidential customers. 260 However, most large C&I customers do not have the option to take POLR service at discounted, regulated rates. Alternative suppliers may find C&I customers to be more attractive because the ratio of sales to marketing co sts is often perceived to be higher
for these customers.

This section reviews the status of retail competition in the pr ofiled states, with an emphasis on entry of new suppliers, migra tion of customers to alternative suppliers,261 and the difficulty of drawing conclusions about the effect of retail competition on prices due to the capped POLR service.262 It then discusses how regulated POLR service has distorted entr y decisions by alternative suppliers. Lessons learned from the use of POLR that m ay assist states as they decide
how to structure future POLR service are included.

1. States Have Allowed Distant Supp liers to Access Local Customers and Have Encouraged Distribution Utilities to Divest Generation

Each profiled state adopted measures to enc ourage entry of new suppliers to compete w ith the incumbent utility. Each adopted p olicies to allow suppliers other than the local distribution utility to gain access to retail customers by requiring the u tilities to join an ISO or an RTO. As discussed in Chapter 3, larger geographic markets for wholesale electricity enable retail supplie rs and marketers to buy generation supplies from a wider rang e of local and distant sources (e.g., neighboring utilities with excess genera tion, independent power producers, cogenerators, etc. ). Even if no new generati on facilities are built, independent operation and management of the transmission grid increases reta il customers’ choices and makes it more difficult for local gen erators to exercise market power.

Some states, including Massachusetts, New Jersey, and New York, or dered or encouraged utilities to divest generation assets to independent power producers

(IPP) to eliminate possible transmission discrimination or to secure accurate stranded cost valuations. 263 Although these divestitures generally did not require a utility to sell its generation assets to more than one company to elimin ate the potential for the exer cise of market power, gen erating facilities frequently have
been sold to more than one IPP.264 In other states, such as Illinois and Pennsylvania, several utilities voluntarily sold or t ransferred generation assets to unregulated affiliates.265

As a result of these divestitures, regulated distribution utilities in profiled states operate fewer generation plants than in the past. Distribution utilities that are required to serve customers must purchase generation in the wholes ale market to serve their customers. Table 4-1 shows the amo unt of a state’s generation operated by the state’s utilities (i.e., not ope rated by IPPs or as combined heat a nd power facilities), both before and after the start of retail competition.

Table 4-1. Percentage of Utility Owners hip of Generation Assets by State



# State Prior to Restructuring (1997) 2002

Illinois 97.0 9.1
Maryland 95.4 0.1

Massachusetts 86.6 9.0
New Jersey 81.2 6.8

New York 84.3 32.4
Pennsylvania 92.3 12.3

Texas 88.3 41.2

Note : The utility ownership percentage for New Yo rk in 2002 is higher than for other stat es with divestiture policies because it in cludes the hydroelectric and nuclear facilities of the Power Authority of the State of New York (even though that body is not a retail distribution utility)

.

Source : EIA, State Profiles , Table 4 in each state profile, available at http://www.eia.doe.gov/cneaf/electricity/s t_profiles/e_profiles_sum.html.

# Other states, such as Texas, limited the market shar e any one generation supplie r can hold in a region, to provide opportunities for ot her suppliers to enter. 266 Still others, such as New York, helped organize introductory temporary discounts from alternative suppliers, thus providing customer s an incentive to try out these new suppliers.267

2. Alternative Suppliers Serving Reta il Customers and Migration Statistics

Many generation suppliers serve large industrial and large commerci al customers in the profiled st ates. For example, in Massac husetts, over 20 direct suppliers provide service to C&I customers, along with over 50 licensed elect ricity brokers or marketers.268 However, only four active s uppliers serve residential

customers in the state. 269 In New Jersey, C&I customers can choose among nearly 20 suppliers , but residential customers only have a choice of one or two competitive suppliers.270

Texas and New York have more opt ions for residential customers. In Texas, re sidential customers can c hoose from approximately 15 suppliers.271 In New York, between six and nine suppliers offer services to residen tial customers in each service te rritory.272 With the notable ex ception of the Ohio municipal aggregation program described in Box 4-4, fe w if any suppliers have provided continuous service to residential customers in the other profiled states or in other retail competition states prior to the e nd of the respective transition periods.

The percentage of residential customers sw itching from the POLR service to an alte rnative competitive supplier is greatest wher e there are more available generation suppliers. For example, in Massachusetts, 8.5 percen t of residential customers had migrated to a competitive suppli er as of December 2005.273 Approximately 41 percent of large C&I customers switched to a lternative suppliers, representing 57.5 percent of the C&I load.27 4 In states with several suppliers serving residential customers, higher percentages of residential cust omers switched to a new supplier (e.g.

, approximately 26 percent chose a new supplier in Texas).275

Box 4-4

Customer Choice through Municipal Aggregation in Ohio

In New York, Texas, and most other states, retail customer sw itching occurs primarily through i ndividual customer decisions to pick a specific alternative retail supplier. In Ohio, however, most switching activity has occu rred through aggregations of customers seeking a supplier under th e statewide “Community Choice” aggregation option. The Ohio retail competition law provide s for municipal referendums to seek an alternative supplier and allows municipalities to work together to find an alternative supplier. The largest a ggregation pool, the Northeast Ohio Public Energy Council, has 100 member communities and served approximately 500,000 residents at its peak. The Ohio program allows individual customer s to opt out of the aggregation. In m ost other states, aggregation programs require customers to specifically opt in to participate. Participation rate s generally are much higher in opt-out tha n in opt-in programs. (NOPEC recently had to contract for supply with an affiliate of the distributi on utility after the original supplier withdrew from the market).

3. Retail Price Patterns by Type of Customer

Figure 4-3 shows average revenues per kilowatt hour for all custom er types in the profiled states against the national average for 1990-2005. The U.S. national average was generally flat at 8 cents per kWh during this period. Rates in New York, Massachusetts, and New Jersey generally h ave been higher than the national average, while those in Texas, Pennsylvania, Maryland, and Illinois have been lower. In 2004 and 2005, retail prices in all states began to increase.

Figure 4-3. Average Revenues pe r kWh for Retail Customers, 1990-2005

Profiled States and National AverageSource : EIA Form 861 data, and Monthly Electricity Report for average electric revenues per kWh all sect ors, all retail providers.



# a. Residential and Commercial Customers

It is difficult to draw conclusions about how competi tion has affected retail prices for residential customers
in states in which a substantial share of such custom ers continues to take serv ice under capped POLR rates (e.g., Maryland, Illinois, Pennsylvania, and Texas). Comp arisons of regulated pric es shed little light on price patterns resulting from retail competition.

POLR prices have increased recently in states in which residential rate caps have expired. In New Jersey, residential rate caps on POLR service expired in th e summer of 2003. Since then, the state has conducted an internet auction to procure POLR supply of various contract lengths (one- and three-ye ar contracts).
The state holds annual auctions to replace suppliers with expiring cont racts and to acquire additional supply. Rates for the generation portion of POLR serv ice were flat in 2003 a nd 2004 after adjusting for deferred charges, but increased in 2005 and 2006, with rates increasing approxima tely 13 percent between
2005 and 2006. 276

In Massachusetts, capped POLR rates expired in February 2005. Since then, customers who did not choose an alternative supplier still have been able to obtain POLR service. Massachusetts based the ge neration portion of its POLR service on the price of supply procured in wholesale mark ets through fixed-priced, shortterm (three- or six-month) supply contract s. Rates for the generation portion of POLR service in the Boston Edison (north) ter ritory increased from 7.5 to 12.7 cents per kWh from 2005 to 2006.277

b. Large Industrial Customers

Examining large industrial customers that continue to use a fi xed price POLR service also sheds little light on price patterns. A number of states have revised their POLR policies for large customers. Their POLR price fo r generation is a pass-through of the hourly wholesale price for e lectricity plus a fixed administrative fee. For example, Maryland, New Jersey, and New Yo rk have adopted this type of POLR pricing for large industria l customers.278 Many
customers have switched to alterna tive suppliers in these states.

Large industrial customers described how their rates have increas ed since the beginning of retail competition.279 Some comment ers suggested that the Task Force should compare prices of a utility operating in a state th at did not implement retail competition against prices of the s ame utility in a state that implemented retail competition.280

The difficulty with this comparison is that many factors unrelated to retail competition may simultaneously influence prices. For example, one state may have reduced cross-subsidies among customer classes while other states increased them. As a result, a price comparison between two states for a class of customers would conflate competition and cr oss-subsidization effects. Tr ansmission congestion also may a ffect access to different genera tors (with low or high prices), so that comparing two states as if they were in the same physical location would be misleading. The timing of rate adjustments ma y differ between states, so that a single snapshot of rates would show a lower price in one state at one point in time, but a lower price in the other state at a different point in time – even if the net present values of typical bills in the two states were identical over a long observation period. Finally, some states may defe r recovery of costs, whereas other states choose not to. Thus, without accoun ting for these and other factors, a simple price comparison between two states may n ot reveal whether retail competition has benefited customers. At this point the Task Force does not have sufficient data to provide a definitive explan ation of price differences between
states.2814. Results of Efforts to Bring Accurate Pric e Signals into Retail Electric Power Markets

There is mixed evidence concerning the degr ee to which retail competition has resulted in efficient price signals to customers. Residential POLR service rate caps have not increased customer exposure to time-based rates.282 In contrast, real-time pricing is the POLR service available to the largest customers in New Jersey, Maryland, and New York.283 The shift to real-time pricing has been eased by technical advances in metering that have i ncreased the sophistication (and decreased the prices) of meters th at record the volume of consumpti on in each small block of time.284

Commenters argue that POLR rate structure can significantly aff ect customer response to price, especially among larger customer s. A broad spectrum of

utilities, state regulators, and ISOs argue that variable rates pe rmit customers to react to pri ce changes by enabling them to see clearly how much they can save. 285

The experience of the largest customers in National Grid USA’s New York area suggests that customers using real-time pricing de monstrate price sensitivity.286

In states with traditional co st-based regulation, utilities have used various incentives to induce customers to reduce consumpt ion when demand is high or transmission is congested (e.g., hot summer days). In other instan ces, such as in New Yo rk State, ISOs have successfully imple mented demand response programs available to retail customers. In some instances, retail competition has discouraged these traditional types of progr ams, particularly when distributing

utilities are no longer responsible for POLR service. 287 When distribution utilities are required to maintain a por tfolio of resources to m eet POLR loads, they may no longer value these types of programs as a resource to ensure reliable and efficient grid operation. Shifting the responsibi lity of grid operation and reliability to regional organizations such as ISOs/RTOs further decreas es distribution utilities’ interest in these products.

5. Retail Competition in Rural America

Many rural areas are served by small non-profit electric cooperativ e and public power utilities. They were among the last to b e electrified and the most costly to serve. Customers are scattered over large geographic areas, with residential and small loads pr edominating. Although electric distribution cooperative service areas have been opened to competition under some state plans, no state has required municipal and/or public power utilities to implement retail competition.

Eight states with retail competition – Arizona, Delaware, Maine, Maryland, Michigan, New Hampshir e, Pennsylvania, and Virginia – required cooperatives to implement retail competition in their service territories. W ith the exception of Pennsylvania, state public utility commission s regulated electric cooperatives’ retail rates and approved their competition plans. Pennsylvania left the design and implementation of retail competition to th e individual distribution cooperatives. The Pennsylvania Public Utility Commission is res ponsible for licensing competitive retail providers in cooperat ive service territories. Cooperative retail competition plans have been fully implemented in Delaware, Maine, New Hampshir e, Pennsylvania, and Virginia. Some aspects of cooperative retail competition plans are still in administrative or j udicial proceedings in Arizona and Michigan. Michigan has allowed electric cooperatives to offer retail competition to a portion of their very large C&I customers, but has deferred extending competition to other custom ers.

Other states – including Illinois, Montana, New Jersey, Ohio, a nd Texas – allow electric cooperatives to opt into retail compet ition on a vote of their boards or membership. None of these states regulates cooperatives’ rates or services. They leave the de sign and implementation of retail competition to the individual cooperative. The state licenses competitive providers, but providers must enter into agreements with the cooperative to begin enrolling retail customers. A handful of individual cooperatives in Montana and Texas elect ed to provide retail competition options for their members.

It is difficult to track the progress of retail competition in rura l areas because most states do not make switching data avail able or maintain up-to-date information on active suppliers in cooperative service territories. Neverthele ss, the Task Force determined that there were few alternativ e competitive providers, if any, for residential customers of rural systems open to retail competition. No competitive providers were enrolling customers in cooper ative systems in Arizona, Maine, Maryland, New Hampshire, Pennsylvania, or Virginia in May 2006. In Delaware and M ontana, competitive providers had been licens ed to serve cooperative customers, but it is unclear whether any is currently enrolling customers. Licensed provider a nd switching information for Tex as cooperatives is not yet
available.

E. POLR Service Price Significantly Affects Entry of New Suppliers

Each profiled state required local distribu tion utilities to offer a POLR service for cu stomers who do not select an alternativ e generation provider or whose supplier has exited the market. The price that the distribution utility charges for re gulated POLR service is usually “fixed” for an extended period – that is, it does not vary with increases or decreases in wholesale prices . Generation accounts for the most significant portion of the POL R service price. This component constitutes the amount that the customer avoids paying to the distribution utility by choosing (a nd paying) an alternative prov ider. Many states denote this as the “price to beat” or the “shopping credit.”

Commenters say that the price of POLR se rvice is the most significant factor affec ting whether new suppliers will enter the mar ket and compete to serve customers.288 The POLR price is the price against which new suppliers, including unregulated affiliates of the distribution ut ility, must compete if they are to attract customers.289 The frequency with which the POLR service price changes, among other features of POLR service, can affec t the competitive dynamics between different suppliers.

1. Contrasting Visions of POLR Service

The comments revealed two visions of how POLR service should function in the long term .290 In the first vision, POLR is a long -term option for customers. Under this view, POLR service closely approximates traditional u tility service, but in a market place with other sources of sup ply. Under this vision, POLR service often features prices that are fi xed over extended periods. Gove rnment-regulated POLR servic e competes head-to-head wi th private, fo r-profit retail suppliers.291 (An analogy would be the U.S. Postal Service pr oviding parcel postage service in competition with for-profit pac kage delivery services by United Parcel Service, DHL, and FedEx) . Alternative suppliers may grow as they find a dditional approaches to attract customers, but P OLR service will likely retain a substantial portion of sales, particularly to residential customers. This type of PO LR service serves as a yardstick against w hich alternative suppliers compete. Most states have adopted this vision of POLR service.292

In the second vision, POLR is a barebones, temporary service c onsisting of retail access to wholesale supply, primarily for cus tomers that are between suppliers. In this vision, alternative suppliers serv e the bulk of retail customers. They comp ete primarily against each other with a var iety of price and service offerings designed to attract different types of cust omers. This type of POLR service acts as a stopgap source of supply that ensures el ectric service is not interrupted when an alternative supplier leav es the market or is no longer willing to serve pa rticular customers. Wholesale spot market pr ices, or prices that vary with each billing cycle, may be acceptable as the price for POLR service.293 (A supply arrangement comparable to this version of POLR se rvice is the high-risk pool for automobile insurance operated in several states).294 Texas and Ma ssachusetts are current examples of this vision of POLR servi ce, as is Georgia in its designfor retail natural gas sales.295

Some profiled states incorporated aspects of both visions of POLR service for different types of customers. For example, New J ersey adopted the first approach for residential customers and the second approach for large C&I customers.296 Large C&I customers are generally expected to be well-informed buyers with wide energy procurement experience. Accordingly, some states dete rmined they are more likely to quickly obtain the benefits of retail competition without additional help from stat e regulators in the form of fixed POLR prices.

2. Key POLR Service Design Decisions

The profiled states took different approaches to designing their POLR service offerings. Key de sign decisions involved pricing of the POLR, duration of the POLR obligation, and how to acquire POLR supply. Each of thes e can affect entry conditions that alternative suppliers face. T his section describes each of the
decisions.

a. Pricing of POLR Service

The profiled states generally set the POLR price at the regulated price for electric pow er prevailing before the onset of retai l competition, less a discount. Discounts usually persist over a specified multi-year period. A ssuming that competition generally lowers prices, one rationale for the discounts was to provide a proxy for the effects of competition on customers less able to qui ckly obtain such savings for th emselves. The Illinois POLR s ervice discount, for example, was developed to bring local prices into line with regional prices. When retail competi tion began, Illinois customers in areas wit h relatively low prices before
customer choice did not receive discounts belo w the previously regulated rates. In c ontrast, customers in the Commonwealth Edi son territory – the area with the highest cost-based rates – received 20 percent discounts to bring retail POLR pr ices there into line with the regional aver age bundled service prices prevalent pri or to the restructuring legislation.297

b. The Extent and Timing of Pass-Through of Fuel Cost Changes

States also have considered the extent to which they should adju st the regulated POLR price to allow for changes in the cost of fuel to generate electricity. Some states separated fuel costs from other cost components, because fuel costs have been more volatile than other input prices. (F uel costs are the largest variable cost component and can be calculated for each type of generati on unit on the basis of public info rmation.) These factors also suggest that a generation firm has little control over its fuel costs once it has invested in generati on. For example, Texas institu ted twice-yearly adjustments in the POLR servic e (price to beat) price calculations. By adjusting POLR prices for changes in fuel costs, Texas regulators have prevented the POLR price from sl ipping too far away from competitive price levels, thus maintaining the POLR price as a closer proxy for the competitive price.298 If retail prices fal l too far below wholesale prices, the POLR supplier may have financial difficulties, and alternative suppliers will be unlikely to enter or remain as active retailer s.299

c. POLR Price and the Shopping Credit

When a retail customer picks an alternativ e supplier, the distribution utility with a PO LR obligation avoids the costs of procu ring generation supply for that customer. The distribution utility therefore “credits” th e customer’s bill so that the cust omer pays the alternative supplier (rather than th e utility) for the

electricity supplied. 300 This avoided charge – the “shopping credit” – equals the regulated POLR service price. States ha ve used two approaches to det ermine the level of the shopping credit. One view is that the shopping cred it equals the avoided cost or the proportion of POLR procureme nt costs attributable to a departing customer. Maine, for example, estimated avoided costs on this basis, with no additi onal estimated avoided costs.301 This appr oach results in a lower shopping credit and lower total POLR price.

An alternative perspective is th at the distribution utility also avoids “adders” (costs that are in addition to avoided procure ment costs), including marketing and administrative costs.302 This view results in a higher shoppi ng credit and higher total POLR price, creating “headroom” for p otential entrants. In Pennsylvania, the POLR shopping credit included several other elements, such as avoided marketing and administ rative costs.303 Some observer s attributed Pennsylvania’s early high volume of switching to the additional avoidable costs included in its shopping credit calculations.304

d. The Multi-Year Period for POLR Service

States that implemented retail competition also determined how l ong POLR service should continue at a discount from prior regul ated prices. This period generally corresponded to the distribution utility’s collection of stranded generation and other costs. In a competitive retai l environment, utilities no longer were assured they could recover costs of all of their state-approved generation investments. Most states faced claims of stranded c osts associated with generation facilities that were unlikely to earn enough re venues to recover fixed costs once customer s could seek out alternative, lower-p riced retail suppliers. States
allowed utilities to recover stranded co sts through charges on distribution se rvices that cannot be bypassed.305

Each state that authorized the collection of stranded costs had to determine these costs and the duration of the collection per iod. These decisions fundamentally altered the electric power industry and were at the center of some of the most contentious issu es state regulators faced. Some states (for example, Maine and New York) required some or all generation to be sold to obtain a market-based determ ination of the level of stranded costs.306 In other states, such as Illinois, utilities voluntarily divested generation assets. As noted above , the result of these divestitures is that generation no longe r is primarily in the hands of regulated
distribution utilities.307

e. Procurement for POLR Service

Because most distribution utilities no longer ow n generation to satisfy all of their PO LR obligations, they took different appr oaches to acquire generation supply. For example, New Jersey utilities that offer residential POLR service acquire generation supply through three overlapping three -year contracts, with each contract covering approximately one-third of the projected load.308 This “laddering” of supply contracts reduces the volatilit y of retail electricity prices but does not assure that the prices paid by POLR service consumers are competitive in the short term.309 Other states used different wa ys to hedge the volatility in shortterm energy prices. For example, New Yo rk distribution utilities have long-term suppl y contracts with the purchasers of their generation assets (vesting contracts) based on pre-divestitu re average generation prices.310

F. Observations on How POLR Service Policies Affect Competition

One of the most contentious issues state regulators currently f ace is how to price POLR service once rate caps expire. This si tuation is especially vexing for those states that had stranded cost recovery periods during which fixed POLR prices we re substantially lower than wholesale pri ces. Rate caps expire this year in Delaware, Illinois, Maryland, Ohio, and Rhode Island, and customers in those states th at did not choose an alternative supplier face potentially substantial priceincreases.

Rapid increases in fuel prices in recent ye ars – leading to increases in wholesale pr ices – have made it difficult fully to dis cern best practices regarding retail competition. The price increases interacted dramatically with POLR service rate cap s, clouding the experiences most states hav e had with other retail competition issues. As a result, the range of experience rega rding other aspects of retail competition is narrow, primarily li mited to what has occurred in New York, Texas (within ERCOT), the Duquesne di stribution area within Pennsylvania, Main e, Massachusetts (recently), and the large C&I customers in New Jersey, Illinois, and Maryland. Because each state faces different el ectricity supply and demand conditions, it is not possible to rec ommend a single approach for all states considering retail customer choice. Nonetheless, give n these limitations, the Task Fo rce offers the following observati ons on what appears to work well (and not to work well) in retail customer choice programs.

Minimum POLR Service: POLR service (or an equivalent provision) to serve customer s of a supplier that has left the market, while the customer obtains another supplier, is the least intrusive form of POLR se rvice, yet it is consistent with concerns about potentially lif e-threatening effects of unanticipated loss of electric service.

Treatment of Different Customer Risk Preferences: POLR service that goes beyond short-term access to the wholesale spot market involves providing a bundle of services that electricity marketers also can provide. States that embrace a more expansive version of PO LR service should recognize that this step may hamper the development of alterna tive suppliers. The economic rationale for taking this step usua lly is limited to trying to correct some identifiable and substantial market imperfections . If a state adopts a more expansive version of POLR service, it should periodically review the rationale for continuing it.

POLR Service Price Caps: It is difficult to establish a POLR serv ice price cap that will not distort retail electricity markets and the associated development of effective competition. The be st practice is to make frequent adjustment s to the cap (at least so as to reflect changes in fuel costs), or to abandon the cap altogether and use an objec tive, competitive process to procure supply.

Treatment of Different Customer Classes: Large customers are logical pioneers for retail c hoice because of their familiarity with energy procurement processes and because they are comfortable with decisions to adjust input use based on input prices. For smaller, less sophisticated customers, including residential customers, issues of awareness and access to compara tive pricing information should be address ed as retail customer
choice is introduced.

Switching Costs: Switching is important for retail electricity competition to work . States should strive to avoid rules that make switching mo re expensive or slower than is necessary to avoid unauthorized switching (slamming).

Consumer Education: Becoming an informed and responsive consumer in an unfamiliar market requires that the customer be informed that he or she has choices and be provided with inform ation about how to compare available choi ces and how to switch suppliers (including any constraints on switching). Texas maintains a well-organized website that appears to work well for residential pr ice comparisons. New York’s program to encourage customers to try out a lternative suppliers that agree to offer a temporary discount a ppears to educate many residenti al customers effectively about the ease of switching, w ithout subsidizing alternative suppliers.

Customer Aggregation: Customer aggregation is an approach that can reduce per-customer search and sw itching costs and thus generally can help to develop retail competition. Opt-out customer aggregations ma y be worth considering because they can minimize transaction co sts without limiting customer choice.

Entry: Entry is a key concept in retail electricity competition. States should attempt to avoid rules that make entry more expensiv e or slower than is required to avoid fraudulent marketing activitie s. Areas to consider include registra tion fees and delays, costs and delays in interacting with the distribution utility (metering, billing, treat ment of receivables), security deposits for suppliers, rules regarding disconnect ing retail customers for nonpayment, and exit penalties.

1. POLR Service Price to Approximate the Market Price

The POLR service price must closely approximate a competitive ma rket price if it is to provide economically efficient incentive s for consumption and supply decisions and thereby maximize welfare. This price will vary over time as supply and demand change.311 If the POLR service pr ice does not closely match the competitive price, it will distort consumpti on and investment decisions312 leading to an inferior allocation of resources.313 Competitive market prices align consumers’ willingness to pay for a service w ith the marginal cost of providing it (where , in the long run, the marginal cost i ncludes a competitive rate of return on investments). This alignment leads to the most economically efficient allocation of resources.314

Experience within the profiled states show s that it is not easy to approximate the competitive price. Not only does the compet itive price change when prices of inputs change, but the price also acts as an investment signal for new generation. The short-term competitive price for the el ectric generation component can move quickly and dramatically. Over the past several years, the initia l fixed discounts for POLR service have resulted in belo w-market prices or occasionally above market prices, but never at the shor t-term market price for long.315 When POLR prices are below competitive levels, even efficient alternative suppliers cannot profit by entering or continuing to serve retail customer s.316 Firms with the POLR obligation can become financially di stressed, as they did in California during its energy crisis.317

Fuel prices are responsible for a substantial percentage of the ch ange in the market price. A POLR service should adjust the r etail electricity price for changes in the prices of fuels used by generators (at the margin). This is more efficient than using a fixed price as a proxy for the mar ket price. Moreover, a POLR price that is adjusted only infrequently to in corporate underlying fuel price changes will usually be either above or below the compe titive market price.318 A fixed or infrequently updated price creates incentives for customers to move back and forth from POLR service to alternative suppliers, based on which offers a lower rate. This repeated switching may create additional costs for both POLR and alternative supplie rs. It also can reduce the cer tainty about procurement quantities which suppliers need to make long-term s upply arrangements. Including other identifia ble cost components that fluctuate widely in POLR service price adjustments will increase the likelihood that the POLR service price will be a reasona ble proxy for the competitive price.2. Lack of Market-Based Pricing Distorts Development of Competitive Retail Markets

A second issue arises when below-market PO LR service prices persist during a period of rising fuel prices and correspondingly i ncreasing wholesale supply prices. In these circumstances, customers are likely to experience a shock when POLR service prices are adjusted to reflect pr evailing wholesale prices. This can create public pressure to continue the fixed POLR rates at below- market levels. For example, some jurisdictions have considered a gradual phase-in of the price increase to bring POLR prices to the market level. The shortfall between the market POLR price and the price that customers ac tually pay is usually deferred and collected later from the POLR provider’s customers.

Although this approach reduces rate shock, it is likely to distor t retail electricity markets. First, a phase-in of the price increase continues to send inaccurate price signals and undermines incentives to reduce consumption. Second, it prevents entry of alternativ e suppliers by keeping the POL R rate below market levels for additional years. Third, it results in highe r prices in future years as the deferred revenues are recovered, so that customers who purchase electricity later are unfairly penalized (overcharged). Fourth, if surcharges to pay for deferred revenues are not designed carefully, the charges c an disrupt existing competition by forcing customers with alternative suppliers to pay for part of the deferred revenues. Fifth, if wholesale prices decline, cus tomers will choose alternative suppliers, and this migration will create a stranded cost problem as the POLR provider loses customers it had counted on to pay the higher prices. Moreover, if the state prevents the stranded cost problem by imposing large ex it fees, POLR service customers w ill be locked in to the POLR provider, so that competition may not develop even after POLR service prices rise to market le vels. Finally, continued POLR se rvice price caps in an environ ment of increasing wholesale prices can endanger the financial vi ability of the distribution utility.

3. Different POLR Services Designed for Different Classes of Customers

Some states have different POLR service de signs for different customer classes. POLR service prices offered to large C&I custo mers generally entail less discounting from regulated rates or competitive market-based procurement and have been based on wholesale spot market prices. Large C&I customers generally have a good understanding of price risk and of the means and costs required to reduce that risk. In addition, suppli ers often can customize service offerings to the unique needs of these large customers.319 With their larger loads, large C&I cu stomers also may be better equ ipped to respond to efficient price signals than other classes of customers. The result of this price response may be to improve system reliability and dissipate market power in peak demand periods.320

Large C&I customers have engaged in more switching to competitiv e providers in states that have implemented this division betwe en POLR service for large
C&I customers and for residential and small C&I customers.321 Ma ny alternative suppliers reportedl y have developed customized time-of-use contracts for large C&I customers.322 Moreover, the profiled states show that a substantial number of suppliers actively serve large C&I cus tomers. Box 4-5 describes Oregon’s unique sign-up period for its nonresidential customers.

It is not necessary to expose all customers to time-based prices to intr oduce price-responsiveness into retail markets. 323 As a first step, customers who are t he most price-sensitive could be exposed to time-based rates. Niag ara Mohawk in upstate New York took this approach for its large st customers, as did Maryland and New Jersey. California is considering setting real-time pricing as the default rate for medium-sized and larger C&I custom ers. Another means to introduce price responsiveness is to provide customers with voluntary time -based rate programs, along with assistance in equipment purcha ses or financing. For example, the New York State Public Service Commission requires voluntary ti me-of-use pricing for residential customers, and the Illinois Legislature requires that residential customers be offered real-time pricing as a vol untary tariff. Ideally, competiti on provides incentives for supplie rs to offer customers the mix of products and services that matches their potentially diverse preferences.

4. Use of Auctions to Procure POLR Service

As discussed above, New Jersey has used an auction process to procure POLR supply fo r both residential and C&I customers. Illi nois proposed a similar auction for when its rate caps expire. Auctions may bring retail cust omers the benefit of competition in wholesale markets as supplier s compete to supply load. However, as discussed in Chapter 3, if th ere is a load pocket, an auc tion is unlikely to help this process, resulting in fewer benefits of competition.

Box 4-5

Oregon’s Annual Window for Switching for Nonresidential Customers

Oregon has a unique process by which nonresid ential customers of the two large invest or-owned distribution utilities in Oregon can switch to an alternative supplier. Nonresidential customers must make their selections during a limited annual window. The window must extend at least five days in duration, but usually a month is allowed. In addition to picking the alterna tive supplier, the largest customers must select a contract dura tion. One option specifies a minimum duration of five years, with an annual rene wal after that. As of 2005, alternative s uppliers were anticipated to serve about 1 0 percent of load in one distribution area and about 2.1 percent in the other. One utility offered choice beginning in 2003, while the other began customer choice i n 2005. Detailed descriptions are available at http://www.oregon.gov/PUC/elect ric_restruc/indices/ORDArpt12-04.pdf.
5. Consumer Awareness of Customer Choice a nd Engendering Interest in AlternativeSuppliers

Experience with restructuring in other industries indicates that consumer switching from a traditional supplier to a new one ca n be a slow process. It took 15 years before AT&T lost half of its long-distance service cust omers to alternative suppliers. 324 One reason retail electric com petition could be sl ow to develop is that expected gains from learning more about market choices may be too small to make the learning worthwhile,325 particularly f or residential customers with
small loads.326

Pricing of POLR service and helping consumers compute the “shop ping credit” may encourage more rapid development of retail comp etition by motivating
residential consumers to search for market choices. Some states that have low “shopping credits” have had little retail entry. Some states with retail competition
have had substantial consumer education programs, including webs ites with orientation materials and price comparisons.327 Thes e initiatives help promote learning about market alternatives.

New York is encouraging retail competition by helping organize temporary discounts from alterna tive suppliers and ordering dist ribution utilities to make these discounts known to customers who contact the utility.328 These e fforts have increased residen tial switching and reduced prices , at least for the short term. Experience indicates that once residential customers switch to alte rnative suppliers, they seldom re turn to POLR service even a fter the temporary discounts expire.329
APPENDIX A LIST OF COMMENTERS WHO RESPONDED TO TASK FORCE NOTICES REQUESTING COMMENTS*

* Two notices were published in the Federal Register as FE RC Docket Number AD05-17-000: (1) Notice Requesting Comments on Wholesale and Retail Electricity Competition, issued on October 13, 2005, and (2) No tice Requesting Comments on Draft Report to Congress on Competi tion in the Wholesale and Retail Markets for Electric Energy, issued on June 5, 2006. The actual comment s can be found at FERC.gov

The following parties filed comments in respons e to the notice issued October 13, 2005:

Alcoa, Inc. (Alcoa)

Allegheny Energy Companies (Allegheny)

Alliance for Retail Energy Markets

Ameren Services Company (Ameren)

American Antitrust Institute (AAI)

American Public Power Association (APPA)

Association of Large Distribution Cooperativ es (Large Distribution Cooperatives)

BlueStar Energy Services, Inc. (BlueStar)

BP Energy Company (BP Energy)

California Independent System Operator Corporation (CAISO)

California Public Utilities Commission (CPUC)

Cape Light Compact

Carnegie Mellon Electricity Indus try Center (Carnegie Mellon)

CenterPoint Energy Houston Electric, LLC (CenterPoint)

Los Angeles Department of Water and Power (LADWP)

7-Eleven, Inc, Big Lots Stores, Inc., Crescent Real Estate Equities, Federated De partment Stores, Hines, JC Penney, Wal-Mart St ores, Inc. (collectively, Commercial End-Users)

COMPETE, Electric Power Supply Association (EPSA), Alliance for Retail Choice (ARC)

Connecticut Department of Public Utility Control (Connecticut DPUC)

Consolidated Edison Company of New York, Inc. and Orange and Rockland Utilitie s, Inc. (together, New York Companies)

Constellation Energy Group, Inc. (Constellation)

Council of Industrial Boiler Owners (CIBO)

Demand Response and Advanced Metering Coalition (DRAM Coalition)

Direct Energy Services, LLC (Direct Energy)

Dominion Resources Services, Inc. (Dominion)

Duke Energy Corporation (Duke)

Duquesne Light Company (Duquesne)Edison Electric Institute (EEI)

Electric Power Supply Association (EPSA)

Electricity Consumers Resource Council (ELCON) and American Chem istry Council, American Iron and Steel Institute, Coalition of Midwest Transmission Customers, PJM Industrial Customer Coaliti on, Illinois Industrial Energy Consumers, Industrial Energy Users - Ohio, and Multipl e Intervenors (collectively, Industrial Consumers)

EnerNOC, Inc. (EnerNOC)

Exelon Corporation (Exelon)

Governor of the State of Rhode Island

Idaho Public Utilities Commission (Idaho PUC)

Illinois Commerce Commission

Independent Power Producers of New York, Inc. (IPP NY)

Indiana Utility Regulatory Commission (IURC)

Industrial Consumers: Portland Cement Association, American Fo rest and Paper Association, Amer ican Iron and Steel Institute, C alifornia Large Energy Consumers Association, Coalition of Midwes t Transmission Customers, National Lime A ssociation, PJM Industrial Customer Coalitio n

ISO New England Inc. (ISO-NE or ISO New England)

ISO/RTO Council

Large Public Power Council (LPPC)

Lehigh Cement Company (Lehigh)

Maine Office of Public Advocate (Maine Public Advocate)

Midwest Independent Transmi ssion System Operator Inc. (Midwest ISO or MISO)

Midwest Stand-Alone Transmission Companies

Mike Holly; Sorgo Fuels, Inc.

Mirant Corporation (Mirant)

Missouri Public Service Commission (Missouri State Commission)

National Association of Regulatory Utility Commissioners (NARUC)

National Association of State Utility Consumer Advocates (NASUCA)

National Energy Marketers Asso ciation (National Energy)

National Grid USA (National Grid)

National Rural Electric Cooperative Association (NRECA)

New Mexico Attorney General

New York Independent System Operator , Inc. (NYISO or New York ISO)

New York State Department of Public Service (NYPSC or New York PSC)

New York State Electric & Gas Corporation (New York G&E) and Rochester Gas & El ectric Corporation (Rochester G&E)

North Carolina Utilities Commission, Public Staff - North Carolin a Utilities Commission, and the Attorney General of the State of North Carolina (collectively, North Carolina Agencies)

Northeast Utilities

NUCOR Corporation, Blue Ridge Power Agency, and the East Te xas Electric Cooperative (collectively, Large Power Buyers)

Orlando Utilities Commission (Orlando Utilities)

Pennsylvania Office of Consumer Advocate (PA Consumer Advocate)

Pepco Holdings, Inc. (Pepco)PJM Interconnection, LLC (PJM)

PNM Resources, Inc. (PNM)

PPL Companies (PPL)

Progress Energy, Inc. and South Carolina Public Serv ice Authority (together, Progress and Santee Cooper)

Public Utilities Commission of Ohio

Reliant Energy Inc. (Reliant)

Retail Energy Supply Association (RESA)

South Carolina Electric and Gas Company (South Carolina E&G)

Southern California Edison Company (SoCal Edison)

Southern Companies (Southern)

Southwest Transmission Dependent U tility Group (Southwest Transmission)

Steel Manufacturers Association (Steel Manufacturers)

Strategic Energy, LLC (Strategic Energy)

SUEZ Energy North America (SUEZ)

The Alliance of State Leaders Protecting Electri city Consumers (Alliance of State Leaders)

Transmission Access Policy Study Group (TAPS)

Transmission Agency of Northern California (TANC)

Virginia State Corporation Commission

Wal-Mart Stores, Inc. (Wal-Mart)

WPS Resources Corporation (WPS)

Xcel Energy Services, Inc. (Xcel)

The following parties filed comments in respons e to the notice issued June 5, 2006:



# Alcoa, Inc. (Alcoa)

Allegheny Power and Allegheny Energy Suppl y Company, LLC (together, Allegheny)

Alliance for Retail Energy Markets

Alliance of State Leaders Protecting Electricity Consumers

American Public Powe r Association (APPA)

Attorney General of California

Attorney General of New Mexico

California Department of Water Resources; State Water Project

Cape Light Compact

City of Seattle; City Light Department

Coalition of Midwest Transmission Customer, NEPOOL Industrial Customer Coalition, PJM Industrial Customer Coalition, Industrial Energy Users-Ohio, Industrial Energy Consumers of Pennsylvania, and

# West Virginia Energy Users Group (co llectively, Industr ial Coalitions)

Community Power Alliance

COMPETE, Electric Power Supply Association (E PSA), Alliance for Retail Choice (ARC)

Consolidated Edison Company of New York, Inc. and Orange and Rockland Utilities, Inc. (together, New York Companies)

Constellation Energy Group, Inc. (Constellation)

CP Consulting

Direct Energy Services, LLC (Direct Energy)

Duquesne Light Company (Duquesne)

Edison Electric Institute (EEI) and the Alliance of Energy Suppliers

Electric Power Supply Associati on (EPSA), Independent Power Pr oducers of New York (IPP NY), Independent Energy Producers of Maine (IEPM)

Electricity Consumers Resource Council (ELCON) and Am erican Iron and Steel Inst itute, Association of Businesses Advocating Tariff Equit y, Coalition of Midwest Transmi ssion Customers, PJM Industrial Customer Coalition, Industrial Energy Users – Ohi o, Multiple Intervenors, and Wisconsin Industrial Energy Group, Inc. (collectivel y, Industrial Consumers)

Industrial Consumers: Portland Cement Association, American Forest and Paper Association, American Iron and Steel Institute, Califor nia Large Energy Consumers Associ ation, Coalition of Midwest Transmission Customers, National Lime Associ ation, PJM Industrial Customer Coalition

ISO New England Inc. (I SO New England)
ISO/RTO Council

Mercatus Center; George Mason University (Mercatus Center)

Midwest Independent Transmission Sy stem Operator, Inc. (MISO)

Midwest Stand-Alone Transmission Companies

Mike Holly; Sorgo Fuels, Inc.

National Association of State Utility Consumer Advocates (NASUCA)

National Grid USA (National Grid)

National Rural Electric Coopera tive Association (NRECA)

New York State Electric & Gas Co rporation (New York G&E) and Ro chester Gas & Electric Corporation (Rochester G&E)

# OMB Professionals, Inc.

Pacific Gas & Electric Company (PG&E)

PJM Interconnection, LLC (PJM)

Portland Cement Association (Portland Cement)

PPL Companies (PPL)

Progress Energy, Inc. and South Caro lina Public Service Authority (toge ther, Progress and Santee Cooper)

Public Service Commission of New York (PSC New York)

Public Service Commission of Wisconsin (PSC Wisconsin)

Public Utility Law Project of New York

Public Utilities Commission of Texas

Reliant Energy Inc. (Reliant)

Strategic Energy, LLC (Strategic Energy)

SUEZ Energy North America (SUEZ)

Transmission Access Policy Study Group (TAPS)

William D. Steinmeier

Wisconsin Power & Light, Madison Gas & Electr ic Company, Wisconsin Electric Power Company, Wisconsin Public Power Incorporat ed, and WPS Resources Corporation (collectively, Wisconsin Load Serving Entities).

APPENDIX B
TASK FORCE MEETINGS WITH OUTSIDE PARTIES

American Public Power Asso ciation – October 27, 2005 ArcLight Capital Partners LLC– November 9, 2005 Compete Coalition – October 27, 2005
Edison Electric Institu te – October 26, 2005 Electric Power Supply Associ ation – October 27, 2005 Electricity Consumers Resource Council – October 26, 2005 Fitch Ratings – November 9, 2005 Lehman Brothers – November 9, 2005 Merrill Lynch Commodities, Inc. – November 9, 2005 Moody’s Investors Servi ce – November 9, 2005 National Association of Regulatory Utili ty Commissioners – October 27, 2005
National Association of State Ener gy Officials – October 27, 2005

# National Governors Association – October 26, 2005 National Rural Electric Cooperativ e Association – October 26, 2005 Public Utility Law Project – October 27, 2005 Standard & Poor’s – November 9, 2005 SUEZ Energy North America – December 8, 2005
APPENDIX C AN ANNOTATED BIBLIOGRAPHY OF QUANTITATIVE COST BENEFIT ASSESSMENTS OF
ELECTRIC INDUSTRY RESTRUCTURING PROPOSALS

Commenters on the section 1815 study highlighted a wide variety of cost-benefit studies that seek to evaluate the electric power industry. Both proponents and opponents of electric industry restructuring have armed themselves with these types of analyses to s upport their respective positions. It can be challenging
to understand these studies’ sometim es contradictory results.

The Task Force reviewed roughl y 30 cost-benefit analyses 330 in an attempt to better understand what they reveal. Based on this review, together with a review of the recent DOE Report (J. Eto, B. Lesieutre, and D. Hale, A Review of Recent RTO Benefit-Cost Studies: Toward More Comprehensive Assessments of FERC Electricity Restructuring Policies (December 2005) [hereinafter Eto]), the Task Force has made the following
observations:

1) Many of the existing studies address only the benefits of restructuring proposals . To the extent studies overlook the costs associated with institutional changes, they can provide an incomplete picture of impacts, and their results should be juxtaposed to cost estimates. ( See Appendix C: RTO West Benefits and Costs, Economic Assessment of RTO Policy , and Putting Competitive Power Markets to th e Test The Benefits of Competition in America’s Electric Grid: Cost Savings and Opera ting Efficiencies ).

2) The benefits associated with some of the most significant motivations behind restructuring – the maintenance of system reliability and the facilitation of lowest-cost electricity production (via incentives for innovation and low-cost construction) - are very difficult to quantify using current technology and are
often left out of benefit assess ments. “It is important that technically limited studies not be interpreted to suggest that im pacts that they do not analyze are not significant.” Eto at 21.

3) Existing methods and models used to estimate benefits are limited in what they can measure. Many of these models also employ simplistic and often misleading assumptions about market behavior . Improving the models used to derive quantitative benefits is technically difficu lt – significant improvements would involve marrying the complexity of ad equately modeling a 10,000+ bus transmission/ generation system to the complexity of modeling realistic human behavior in markets. The capabilities of ex isting models are likely to be fairly st atic until computer technology advances eno ugh to accommodate the memory needs associated with this complex modeling task.

4) Modeling energy transmission and markets necessarily requires making a great deal of assumptions given the significant limitations in data needed to "feed" these models. Thus, outputs of RTO modeling attempts vary widely based on the assumptions made by the parties doing the modeling – assumptions as to transmission configurations, weather, imports/expor ts, market behaviors, generation costs, etc. ( See Appendix C: Study of Costs, Benefits and Alternatives to
Grid West , versus The Estimated Benefits of Grid West ).

5) Another limitation of the studies is that they often only estima te the benefits to society as a whole. Determining the distrib ution of benefits and costs - who wins and who loses, or who wins the most - is an important piece of the decision making puzzle. Unfortunately, it is much more difficult to measure
the distribution of benefits than it is total social costs. Some efforts have b een made in this direction with estimates of th e end-use price impacts that restructuring has had or might ha ve and with estimates of benefits that indivi dual participants in electricity markets might ac crue ( See Appendix C: Beyond the Crossroads, the Future Direction of Power Industry Restructuring and Competition Has Not Lowered Electricity Prices ).

6) Characteristics of the best restructuring cost-benefit studies , given existing technology/data, include:

• Provision of clear and precise descriptions of assumpti ons, data sources, methods and technical detail.

• Where econometric models are used, study write-ups should provid e regression methods and equations , goodness of fit measures, a nd results of any tests done to detect analytical flaws.

• An attempt to address all potential costs and benefits.

• An effort to address the distribution of impacts.

STUDIES OF BENEFITS IN THE US

Beyond the Crossroads: The Future Direction of Power Industry Restructuring 

# Region US

# Report Date 2005
Sponsor Cambridge Energy Research Associates

Author/Contractor Cambridge Energy Research Associates

Model/Method CERA constructs average counterfactual pric es as an econometric function of fuel p r b ase, for residential and indus trial customers in four ge ographic territories based on 1

Scope of Inquiry Real price impacts on consumers of electric industry restructuring (study also addres policy issues on a non-quantitative basis)

Period Studied 1997-2004

Conclusion U.S. residential electric consumers paid about $34 billion less for the electricity they seven years than they would have paid if traditional regulati on had continued.

Regional distribution of these benefits: NE $ 8 billion Midwest: $ 8 billion South: $24 billion West: -$7 billion

Alternate Views

• APPA thinks figures are inflated: http://www.appanet.org/newsletters/wa shingtonreportdetail.cfm?ItemNumbe r

• Comments to Electric Energy Market Competition Task Force by NRECA,

• H. Spinner, A Response to Two Recent Studies that Purport to Calculate El e Benefits Captured by Consumers , ELECTRICITY JOURNAL, Volume 19, N 2006) at 42-47.

Electricity Markets: Consumers Could Benefit from Demand Programs, but Challenges Remain Region US
Report Date August, 2004
Sponsor Report to the Chairman, Committee on Governmental Affairs, U.S.
Senate

Author/Contractor US GAO

Model/Method Reviewed the literature, analyzed in dustry and participant data, and
conducted interviews with state and federal officials (in FERC, the DOE , and the GSA), industry experts, representatives from utilities, and customers

# Scope of Inquiry Examines the current and poten tial role for demand-response programs. Identifies (1) the t ypes of demand-response programs currently in use; (2) the benefits of these programs; (3) the barriers to their introduction and expansion; an d (4) where possible, instances in
which these barriers have been overcome.

Period Studied

# Conclusion Demand-response programs can benefit customers in regulated and restructured markets by improving market functions and enhancing
the reliability of the electricity system

Recent studies show that demand-response programs have saved millions of dollars—including about $13 million during a heat wave in New York State during 2001. A FERC-commissioned study reported that a moderate amount of demand-response could save about $7.5 billion annually in 2010.

Web Reference http://www.gao.gov/new.items/d04844.pdf

Staff Report on Cost Ranges for the Developmen t and Operation of a Day One RTO (FERC Docket No. PL04-16-000) Region Based on data from PJM, MISO, SWPP, and ERCOT
Report Date October, 2004
Sponsor FERC

Author/Contractor FERC Staff

Model/Method The analytical base for this Study rests largely on information gleaned from audit staff, FERC Form No. 1 data and interviews with and da ta responses from existing RTOs and Independent System Operators (ISOs).
Scope of Inquiry To estimate the cost of developing a Day One RTO that provides independent and non-discriminatory transmission service a nd satisfies the minimum requirements of Order No. 2000 to operate as an RTO. Also estimates operating cost of a Day One
RTO.

Period Studied Various

Conclusion

• The average annual operating expense of a new Day One RTO would impact the average retail customer by approximately 0.02¢/KWh, or less than 0.3 percent of the customer’s total bill.

• Day One RTOs have required an inve stment outlay of between $38 million and $117 million and an annual revenue requirement of between $35 million and $78 million

.

• Cost overruns can result from cha nging plans mid-course, poor project management and extensive delays.

• Cost data are not accounted for in a standardized way.

Web Reference http://www.ferc.gov/EventCalendar/F iles/20041006145934-rto-co st-report.pdf

# Alternate Views

• M. Lutzenhiser, RTO Dollars and Sense: Financial Data Raises Doubts About Whether Deregulation Benefits Outweigh Costs , PUBLIC UTILITIES FORTNIGHTLY (December, 2004).

• Alliance of State Leaders Protecting Electricity Consumers, Commentary o n FERC Staff Report on Day-1 RTO Cost (November, 2004), available at http://www.pacifier.com/~ppcpdx/Tx /Alliance%20Cost%20Study%20Report%2011 22-04%20FINAL.pdf

Impacts of the Federal Energy Regulatory Commiss ion’s Proposal for Sta ndard Market Design Region United States

# Report Date April 30, 2003
Sponsor US DOE Report to Congress

Author/Contractor In addition to DOE staff, partic ipants included contractors who supported the modeling (GE Power Systems Energy Consulting, OnLocation, Inc) and those who supported the analysis (Charles River Associates, Neenan Associat es, and Ken Rose of NARUC).

Model/Method DOE’s Policy Office Electricity Modeling System (POEMS) was
used to assess wholesale and reta il price impacts of SMD. GE
MAPS was used to assess how the use of transmission networks will change under SMD. POEMS is an amalgam of several economic models (including EIA’s Nationa l Energy Modeling System and TRADELEC) which forecasts trad ing volume and prices by NERC region. GE MAPS is an engineering model used to simulate the effects of a security constraine d LMP market model on transmission
patterns. Scope of Inquiry Assess the impacts of implementi ng FERC’s Standard Electricity Market Design (SMD), as presented in FERC’s July 31, 2002 proposed rule

Period Studied

Conclusion
1. Estimated annual cost of implementing FERC’s SMD Rule: $760 million ($.21/MWhr)

2. Average wholesale prices under SMD are estimated to decrease by 1 percent in 2005, in creasing to 2 percent by 2020,
relative to the non-SMD case.
3. The net benefit to all consumers of implementing SMD is estimated to be $1 billion/year fo r the first six years, dropping to $700 million by 2020. These figures are net of the $760 million estimated annual cost. (This implies tota l annual benefits of $1.46 to $1.76 billion, though this figure is not cited in the document).

4. Positive results are not consis tent across regions – modeling suggests that end-use prices would ri se in some regions and decrease
in others.

Alternate Views Alliance of State Leaders Protecting Electricity Consumers, Commentary on DOE’s Study of Standard Market Design (June, 2003), available at http://www.pulp.tc/Alliance_Commentary_on_DOE_Study.pdf

Impact of the Creation of a Si ngle MISO/PJM/SPP Power Market Region Midwest & Northeastern US
Report Date 2002
Sponsor MISO-PJM-Southwest Power pool

Author/Contractor Energy Security Analysis, Inc. (ESAI)

Model/Method ZPM

# Scope of Inquiry Analyzes the impact of establis hing a joint, common electricity market encompassing 26 states, the District of Columbia and the Canadian province of Manitoba (b aseline is 2002 mi x of ISOs and vertically integrated utilities

Period Studied 2002-2012

Conclusion Benefits : $1.7 billion/year

Economic Assessment of RTO Policy
Region United States
Report Date 2/26/2002
Sponsor FERC

Author/
Contractor ICF Consulting

Model/Method ICF’s IPM (Integrated Planning Model) computer simulator.

• Simulates current inefficiencies th rough cross-CA hurdle rates, then eliminates those hurdle rates and measures the efficiency impacts.

• Assumes 5 percent improvement in transmission transfer capability and measures production cost impacts.

• Capacity sharing benefits simulated.

• Decreased reserve requirements (from 15 percent to 13 percent)

• Assumes generator efficiency improvements in RTO Policy case.

Scope of Inquiry Assesses economic costs and benefits of a national move toward RTOs, including improvements in transmission system opera tions with resultin g enhancements to inter-regional trade, congestion management, reliability and coordination, and improved performance of Energy markets.

Period
Studied 2002-2021

Conclusion * $1-$10 billion/year in system production cost savings * NPV of production cost savings ov er 20 years: about $1 trillion

• About 4 percent savings off of base case for 20 year period

• NPV of start up costs: $4.2-$7.3 billion (based on start up comparison of operating ISO/RTOs). Net operating co sts (as compared with base case)
assumed to be near zero .

Web
Reference http://www.ksg.harvard.edu/hepg/Pape rs/FERC%20ICF%20rtostudy_final_0226.pdf

# Alternate
Views • Comments of the California Electric ity Oversight Board Proposed Pricing Policy for Efficient Operation and Expa nsion Of the Transmission Grid, FERC Docket No. PL03-01-000 (March 13, 2003), available at http://www.eob.ca.gov/attachments/PL03-1-000Comments.doc

• Comments of the New England Conferen ce of Public Utilities Commissioners on Electricity Market Design and St ructure, FERC Docket No. RM01-12-
000.

• Comment of the Staff of the Bure aus of Economics and Competition and
the Office of the General Counsel of th e Federal Trade Commission on Electricity Market Design and Structure, FERC Docket No. RM01-12-000, http://www.ftc.gov/be/v020014.pdf

STUDIES OF BENEFITS IN THE MIDWEST

# An RPM Case Study: Higher Costs for Consumers, Windfall Profits for Exelon Region PJM / Northern Illinois
Report Date October 18, 2005
Sponsor Illinois Citizens utility Board

Author/Contractor Synapse Energy Economics / Ezra Hausman, Paul Peterson, David White, and Bruce Biewald

Model/Method Comparison of baseline capacity reve nues (derived from historical market data) with proposed RPM PJM price
Scope of Inquiry Determine potential wealth transfer effects of proposed Reliability Pricing Model (RPM) by examining capacity revenues that might
accrue to Exelon’s Nuclear facilities in Northern Illinois if RPM is implemented.

Period Studied June 2004 – June 2005

Conclusion At the target RPM price, Exelon’s nuclear plants in northern Illinois stand to gain almost $390 million in additional capacity revenues, compared to the 2004 capacity market price, at ratepayers’ expense. At the maximum RPM pri ce, these plants would receive a $1.2 billion increase in capacity revenues.

At PJM’s target price, RPM would amount to a rate increase for PJM ratepayers as a whole of over $5 bi llion every year, paid mostly to existing base load generation.

Web Reference http://www.synapse-energy.com/Downloads/SynapseReport.2005- 10.IL-CUB.RPM-Study--Higher-Cos ts-Windfall-Profits-forExelon.04-20.pdf

The Benefits and Costs of Wisconsin Utilities Participating in Midwest ISO Energy Markets
Region Wisconsin
Report Date March 26, 2004
Sponsor MISO

Author/Contractor Science Applications Inte rnational Corporation

Model/Method Production Cost/ Power Flow Modeling: PROMOD IV
Scope of Inquiry Evaluates proposed financ ial transmission right a llocations and overall impact of market participation on Wisconsin consumers.

Period Studied 2005 Calendar Year

Conclusion Wisconsin and Michigan Upper Peninsula customers to save $51 million annually in wholesale power cost s, net of costs of participating
in markets.

Web Reference http://www.midwestmarket.org/publish/Document/573257_ffe0fcee0f_- 7f570a531528/_.pdf?action=download& _property=Attachment

Alternate Views See comments of Wisconsin Load Serving Entities to Draft EPAct 2005 Section 1815 Report on Compe tition – FERC Docket AD05-17 –
6/26/06

# STUDIES OF BENEFITS IN THE NORTHEAST

Putting Competitive Power Markets to the Test The Benefits of Competition in America’s Electric Grid: Cost Savings and Operating Efficiencies Region Eastern Interconnection
Report Date July, 2005
Sponsor BP Energy Company, Constellati on Energy, Exelon Corporation, Mirant Corporation, NRG Energy, In c., PSEG, Reliant Energy Inc., Shell Trading Gas and Power Company, Williams, and Suez Energy
North America

Author/Contractor Global Energy Decisions

Model/Method Global Energy calculated the benefits of wholesale competition for the Eastern Interconnection as they occu rred. Those results were compared
with a simulation of market conditio ns without the changes in market rules that enabled wholesale competition.

Consumers benefited if the study showed a positive difference between
current market conditions and the s imulation of the traditional market rules prior to wholesale competition.

Model: EnerPriseTM Strategic Planning powered by MIDAS Gold®
software
Scope of Inquiry To identify and quantify the existing and foreseeable consumer benefits of competitive electricity markets.

Period Studied 1999-2003

Conclusion Wholesale customers in the Easter n Interconnection have realized a $15.1 billion benefit during the time pe riod measured due to electricity competition. This benefit derives primarily from differences in the cost of generation construction unde r the two scenarios.

Web Reference http://www.globalenergy.com/compe titivepower/competitivepower.pdf

Alternate Views Global Energy Decision, Putting Competitive Power Markets to the Test: An Alternative View of the Evidence

, available at http://www.nreca.org/Documents/PublicPolicy/NRECAAD0517final.pdf

Electricity Prices in PJM: A Co mparison of Wholesale Power Cost s in the PJM Market to Indexed
Generation Service Costs Region PJM Interconnection
Report Date June 3, 2003
Sponsor PJM

Author/Contractor Synapse Energy (Biewald, Steinhurst, White, Roschelle)

# Model/Method estimates and compares two sets of annual prices: (1) the actual wholesale power costs (WPC) in the PJM market, and (2) prices in a scenario with economic regulation continued from the mid-1990s to today so that the generation serv ice costs (GSC) are the unbundled generation portion of the pre-rest ructuring cost-of-service rates

Scope of Inquiry To illuminate the effect of restructuring on prices in the PJM
interconnection.

Period Studied 1999-2003

# Conclusion while PJM deregulated costs fluctuate year-to-year, on average, the wholesale power costs over the five year period 1999 to 2004 have
been lower than the indexed generation service costs.

Web Reference http://www.pjm.com/documents/dow nloads/reports/synapse-reportpjm-electricity-prices.pdf

Erecting Sandcastles From Numbers: The CAEM Study of Restructuring Electricity Markets Region PJM
Report Date Dec. 3, 2003
Sponsor NRECA

Author/Contractor Christiansen Associates (Mora y, Kirsch, Braithwait, Eakin)

Model/Method Analysis of CAEM study assumptions/ inputs
Scope of Inquiry To review and critique the Center for Advancement of Energy Markets’ (CAEM) study entitled Estimating the Benefits of Restructuring Electricity Markets: An Application to the PJM Region (Sept. 22, 2003) (hereina fter CAEM Study).

Period Studied 1997-2002

Conclusion The CAEM Study’s quantitative results fa il to demonstrate any relationship between these price changes and the economic effects of restructuring.

Web Reference http://www.ksg.harvard.edu/hepg/Papers/Chr istensen.crit.restruct.mkts.in.pjm.03- Dec.03.pdf

Alternate Views See below: Estimating the Benefits of Restru cturing Electricity Markets: An Application to the PJM Region

, available at http://www.caem.org/website/pdf/PJM.pdf

# Market
Simulation –
GE MAPS

Scope of Inquiry Estimates the impact of implementi ng a Northeast RTO on regional spot market prices in the near term. Stephen Stoft Website Library:

Period
Studied Simulation year: 2001 Carnegie Mellon Electric Industry Center (CEIC): http://wpweb2.tepper.cmu.e du/ceic/publications.htm

# Conclusion

Books Net Benefits of $299 million. R ICHARD 

# F. H IRSH



# , P OWER 

# L OSS 

# : T HE 

# O RIGINS OF 

# D EREGULATION AND 

# R ESTRUCTURING IN THE 

# A MERICAN


# E LECTRIC 

# U TILITY 

# S YSTEM 

# (MIT Press 1999). $188 to PJM S ALLY 

# H UNT



# , M AKING 

# C OMPETITION 

# W ORK IN 

# E LECTRICITY 

# (Wiley Publishing 2002). <$22> to NYISO S TEVEN 

# S TOFT



# , P OWER 

# S YSTEM 

# E CONOMICS 

# : D ESIGNING 

# M ARKETS 

# F OR 

# E LECTRICITY 

# (IEEE Press, Wiley-Interscience 2002). $96 to NE

Assessing Short Run Benefits from a Combined Northeast Market Region Northeast
Report Date October 23, 2001
Sponsor NYISO

Author/Contractor A. Hartshorn, S Harvey – LECG Consulting

# Model/Method Replicated Mirant methods: Statis tical / econometric analysis using historic prices and flows. Looke d at unconstrained transmission to determine correlation between prices.

Extended the EEA analysis in time, improved on some elements of their methodology, and undertook some sensitivity analysis of Mirant
estimates.

Scope of Inquiry Potential benefits from implem enting an interregional real-time dispatch in the Northeast. (Response to Mirant study of 2001)

Period Studied 10/00-8/01

# Conclusion Found that improvements in data and assumptions in Mirant study led
to a material overstatement of the short-run benefits to New York consumers. Found large price impact benefits to PJM customers but little or negative price impacts fo r New York energy customers.

Found overall decrease in energy payments for the combined region of $139 million for New York and $50 million for PJM on an annual

basis.

Web Reference http://www.ksg.harvard.edu/ hepg/Papers/Assessing%20ShortRun%20Benefits%20from%20Co mbined%20NE%20Market%2010- 23-011.pdf

The higher proportion of long-term c ontracts at SERC may suggest more effective long-term price signals than at non-organized markets. However, many of th ese long-term contracts are legacy contracts entered into before competitive markets were introduced. Some of these contracts are pegged to index prices that are formed with few reported transactions and therefore questi onable liquidity. Estimating the Benefits of Rest ructuring Electricity Markets: An Application to the PJM Region Region The following graphs show the price patterns by contract vintage in 2005.

PJM Report Date

October, 2003 Sponsor CAEM This analysis shows that prices under long-ter m contracts were somewhat lower than short-term prices in MISO and SERC, but not in NYISO. The s hort-term price changes ar e reflected in sales under long-term contracts. These changes may occur because some long-term contracts use indexed prices (i.e., short term published reference prices).
Author/Contractor It is difficult to draw defi nite conclusions on prices w ith only a quarter’s worth of data. Furthermore, organized markets are evolving and will include capacity markets that could provide stronger price signals for long-term investment. R. Sutherland, CAEM
Model/Method A BIBLIOGRAPHY OF PRIMARY INFORMATION Measures decline in electricity prices during restructured period. ON ELECTRIC INDUSTRY
RESTRUCTURING IN THE U.S.

# Scope of Inquiry
Estimates benefits of restructuri ng the electricity market in the PJM region. The process of understanding the ins and outs of restructuring ma rkets for electricity and transmission in the U.S. has been running full bore since the early 1990s. Accordingly, a large numb er of documents have been published intending to explain the basic engineering, economi c and regulatory theories that su pport restructuri ng ideas. The
intended audience of these st udies has been various – from state re gulators and legislators, to academics, public power managers, and the general public.
Period Studied The Task Force members have not attempted to generate another primer on restructuring as part of its competition study. Instead, the Task Force refers the interested reader to a variety of sources
that will allow him/her to learn more about the subjects that are of the most interest.
1997-2002
Conclusion Ultimate customers in the PJM region saved about $3.2 billion in 2002 from current restructuring efforts
NOTE: Inclusion of articles does not indicate the Task Force’ s endorsement of the theories presented. Web Reference General Restructuring Info rmation Documents Available on the Web : http://www.caem.org/website/pdf/PJM.pdf
Alternate Views Erecting Sandcastles From Numbers: The CAEM Study of Restructuring Electricity Markets (see above at Matthew Brown and Richard P. Sedano, A Comprehensive View U.S. Elect ric Restructuring with Policy Options for the Future , National Council on Electricity Policy (2003), available at http://www.ksg.harvard.edu/hepg/ Papers/Christensen.crit.rest ruct.mkts.in.pjm.03-Dec.03.pdf) http://www.ncouncil.org/pdfs/restruc.pdf

Northeast Regional RTO Proposal: Anal ysis of Impact on Spot Energy Prices U.S. Department of Energy, Energy Information Administration, The Changing Structure of the El ectric Power Industry 2000: An Update (October, 2000), available at http://www.eia.doe.gov/cneaf/e lectricity/chg_stru_update/ Region Northeast William W. Hogan, Competitive Electricity Market Design: A Wholesale Primer (December, 1998) (working paper), available at http://stoft.com/metaPage/lib/Hogan-1998-Primer.pdf Report Date William W. Hogan, Market Design and Electricity Restructuring (November 1, 2005) (presentation at the Association of Power Exchanges 2005 Annual Conference in Orlando FL), available at http://ksghome.harvard.edu/~whogan/hogan_apex_110105.pdf April, 2002 Sponsor PJM Paul L. Joskow, Restructuring, Competition, and Regulatory Reform in the U.S. Electricity Sector , J.

E CON



# . P ERSPECTIVES 

# 11(3), at119-38.
Author/Contractor On-Line Libraries of El ectric Industry Restructuring Documents:

PJM
Model/Method http://www.ksg.harvard.edu/hepg/papers.htm

Mirant Study* Region Northeast
Report Date September 2001
Sponsor Mirant

Author/Contractor Energy and Environmental Analysis, Inc.

# Model/Method Statistical / econometric analysis us ing historic prices and flows.
Looked at unconstrained transmission to determine correlation between prices. Assumes central ized dispatch would eliminate
measured uneconomic flows.
Scope of Inquiry Potential efficiency benefits th at could be achieved by creating a single market for electricity in the Northeast. Model does not address net costs of establishing/operating a single Northeast RTO.

Period Studied 6/00-12/00

Conclusion Net benefit of $440 million. $76 to PJM, $256 to NYISO, $108 to NE ISO.

* Not publicly available. Review based on secondary references.

Competition Has Not Lowered U.S. Industrial Electricity Prices Region Connecticut, Massachusetts, Maine, New Hampshire, New York, and
Rhode Island
Report Date 2005 (Published in the Electricity Journal, Vol. 18, No. 2 (2005) at 52-61)
Sponsor Jay Apt

Author/Contractor Jay Apt, Carnegie Mellon University

Model/Method Used EIA price data to perform re gression analysis on prices before and after competition.
Scope of Inquiry Examines the effect of restructuri ng on prices paid by US industrial customers for electricity

Period Studied 1990-2004

# Conclusion Competition does not produce statistical ly significant price effects –
rates in all states studied other th an Maine increased an average of .8 percent per year prior to competition and they increased by 2 percent per year after competition.

Web Reference http://wpweb2.tepper.cmu.edu/ ceic/papers/ceic-05-01.asp

Economic Assessment of AEP’s Participation in PJM

# Region PJM combined with AEP
Report Date December, 2003
Sponsor AEP

Author/Contractor Cambridge Energy Research Associates

Model/Method ?
Scope of Inquiry Quantifies the costs and benefits of AEP’s integration into PJM
markets.

Period Studied ?

Conclusion $245 M in 2004 declining to $188M in 2008

Economic and Reliability Asse ssment of a Northeastern RTO Region NYISO, ISO-NE
Report Date August 23, 2002
Sponsor NYISO, ISO-NE

Author/Contractor NYISO/ISO-NE

Model/Method GE MAPS
Scope of Inquiry Assesses wholesale electricity ma rket impacts and organizational impacts of establishing a Northeastern RTO (NERTO), including expected costs of implementation, sa vings from market efficiencies, savings from operational consolidation.

Period Studied ?

Conclusion $220M/yr in 2005 $150M/yr in 2010

STUDIES OF BENEFITS IN THE NORTHWEST

Bonneville Power Administration Grid West Benefit Assessment for Decision Point 2 Region Northwest US
Report Date August 4, 2005
Sponsor Bonneville Power Administration

Author/Contractor Internal Bonneville Power Administration staff report

Model/Method Partially based on modeling conducted by Grid West (see “Estimated Benefits of Gr i
derive benefits of control area consolida tion and economic redispatch. Other analyti common regulation, reliability improvements, economic reserve markets, increased t model), etc.

Scope of Inquiry Potential benefits of adopting proposed Grid West design as compared with status q u

# Period Studied Various – primarily examined 1 year historical period.

Conclusion Reliability Benefits: $27 - $62 million annually Increased Transmission Capacity: $9 to $15 million annually Regulating Reserve benefits: $5-$8 million annually Redispatch Efficiencies: $41-$56 million annually Contingency Reserve Market Efficiencies: $20 to $30 million/year De-pancaking of transmission rate efficiencies: $4-$10 million
TOTAL : $106 to $108 million

Web Reference http://www.bpa.gov/corporate/business/rest ructuring/Docs/2005/benefit%20assessm

The Estimated Benefits of Grid West
Region Pacific Northwest
Report Date July, 2005
Sponsor Grid West Regional Representatives Group

Author/Contractor Grid West Risk Reward Workgroup

Model/Method PowerWorld, Gridview, miscellaneou s spreadsheet analyses, surveys
Scope of Inquiry Estimate the benefits related to Grid West formation

Period Studied Various

# Conclusion Results presented as a menu:

• The capacity cost savings associated with Grid Westmanaged contingency reserves range from $20 million to $73 million

per year.

• The estimated capacity cost savings associated with Grid West reducing the amount of re gulating reserves range from $5 million to $26 million per year

• The estimated production cost sa vings associated with Grid West-managed real-time energy ba lancing redispatch range from $41 million to $385 million per year

• The estimated annualized valu e to the region of avoiding cascading disturbances ranges fr om $27 million to $83 million per

year.

• Avoiding momentary (less than 5 minutes) or sustained events (longer than 5 minutes but shorter than 12 hours) related to non-cascading transmission events has an estimated annualized value to the region ranging from $17 million to $203 million per year

• The estimated increase in produc tion costs from the existing practice of charging multiple or pancaked rates ranges from $4 million to $61 million per year.

• The estimated reduction in production costs from more efficient prescheduled interchange facilitated by the RCS ranges from $18 million to $52 million per year.

• The estimated savings associat ed with energy conservation, non-wires expansion, and demand-side measures facilitated by Grid West range from $1 million to $61 million per year.

Study of Costs Benefits and Alternatives To Grid West

# Region Northwestern US
Report Date October 15, 2004
Sponsor Snohomish PUD

Author/Contractor Henwood Energy & Margot Lutzenhise r of the Public Power Council

Model/Method Benefits : MarketSym used to estimate the short term dispatch benefits associated wit rate de-pancaking and more liquid operating reserve markets

Costs : Applies apply the average cost/MWh of operating PJM, NYISO, ISO NE, C A and ERCOT to Grid West’s projected annual demand.

Scope of Inquiry Study the costs, benefits and altern atives to forming Grid West

Period Studied 2004

Conclusion Gross annual benefits to the region of $78 million Grid West Annual costs of $200 million.

Net Benefits of <122 million>

Web Reference http://www.snopud.com/content/external/doc uments/gridwest/hen wood_gridwestfin a

RTO West Benefit/Cost Study
Region Northwestern US
Report Date March 11, 2002
Sponsor RTO West

Author/Contractor Tabors Caramanis and Associates

Model/Method GE MAPS
Scope of Inquiry This study looked at the impacts that removing pancaked transmission rates and sharing rese rves would have on the cost of generation in the Northwest.

Period Studied 2004

Conclusion

• The net benefits of eliminating transmission rate pancakes and sharing reserves would be $305 million/year in the RTO West footprint, and $410 million for all of RTO West.

• 40 percent of this benefit can be attributed to the elimination of rate pancaking, 60 percent to reserves sharing.

RTO West Potential Benefits and Costs
Region Northwest
Report Date October 23, 2000
Sponsor RTO West

Author/Contractor RTO West Benefits/Cost Team

Model/Method Aurora for production cost modeling, sp readsheet analyses for others

# Scope of Inquiry Identify and quantify benefits and co sts to the regional electric power system that would occur as a re sult of implementing RTO West

Period Studied Various

Conclusion

• Inconclusive production cost savings

• Regulating reserve savings of $28 million annually over the RTO footprint.

• Reliability benefits of a nywhere from $33 million to $328 million annually

• RTO Annual Costs of $63-$76 million

• Misc. qualitative benefits

STUDIES OF BENEFITS IN THE SOUTHEAST

Cost Benefit Study of the Proposed GridFlorida RTO Region Peninsular Florida
Report Date December 12, 2005
Sponsor Grid Florida, LLC

Author/Contractor ICF Consulting

Model/Method Production cost modeling using GE MAPS
Scope of Inquiry Examined the costs and benefits to Peninsular Florida consumers of transforming the current decentralized market to a centrally organized market under two modes of operation – a Day-1 only RTO and a Delayed Day-2 RTO.

Period Studied 2004-2016

# Conclusion

• The quantitative benefits to Pe ninsular Florida consumers of Day-1 Only RTO operation is $71 million over this period, while the quantitative start-up and operating co sts of a “greenfield” Day-1 RTO is $775 million. Thus, the Day-1 RT O configuration reflects an estimated net loss of $704 million.

• Whereas the quantifiable benefits under Delayed Day-2 RTO operation were substantial, and ranged from approximately $810 million in the Market Imperfection Case to almost $968 million in the Reference Case, the cost of a “greenfield” Delayed Day-2 RTO with wholly new systems, physical facilities and personnel, designed along FERC’s Standard Market Desi gn principles, is also very significant at $1.25 billion.

• The GridFlorida Delayed Day- 2 RTO could breakeven under
the scenarios examined in this st udy if the net benefits from the qualitative factors and the change in utility operati onal costs should be within the range of $285 million and $443 million over the 13-year forecast period.

• This study also indicates th at the non-jurisdictional consumers would receive net positi ve benefits of $798 million from the implementation of a GridFl orida Delayed Day-2 RTO while jurisdictional consumers would r eceive a net loss of $1.1 billion.

Web Reference http://www.icfi.com/Markets/E nergy/doc_files/gridflorida-rtoreport.pdf

Cost Benefit Analysis Performed fo r the SPP Regional State Committee Region Southwest Power Pool
Report Date April 23 rd 

# , 2005, revised July 27, 2005 Sponsor SPP Regional State Committee

Author/Contractor Charles River Associates

# Model/Method a) Wholesale Energy Modeling using GE MAPS b) Allocation of Energy Market Impacts and Cost Impacts c) Qualitative Assessment of Energy Imbalance Impacts d) Qualitative Assessment of Market Power Impacts e) Aquila Sensitivity Cases

# Scope of Inquiry (1) an analysis of the probable co sts and benefits that would accrue
from consolidated services and f unctions (which include reliability coordination and regional tariff administration) and (2) the costs and benefits of SPP’s implementation of an Energy Imbalance Service (EIS) market.

Period Studied 2006-2015

Conclusion * In the Stand-Alone case, implementation of intra-SPP wheelingrates leads to a less efficient dispatch and thereby increases systemwide production costs in comparison with the Base case.

* The EIS market is estimated to provide considerably more benefits than costs, with the net bene fits being $373 m illion to the transmission owners under the SPP tariff over the 10-year study period

Web Reference http://www.spp.org/Publications/CBARevised.pdf

Electric Competition in the States of Arkans as, Louisiana and Mississippi - Is There An Opportunity? Region Arkansas, Louisiana and Mississippi
Report Date 2004
Sponsor Tractebel

Author/Contractor Tractebel

Model/Method Spreadsheet
Scope of Inquiry ?

Period Studied ?

Conclusion Fuel savings: $610M/yr Fixed O&M savings: $280M/yr

The Benefits and Costs of Domini on Virginia Power Joining PJM Region Virginia
Report Date June 25, 2003
Sponsor Dominion Virginia Power (DVP

Author/Contractor Charles River Associates

Model/Method GE MAPS
Scope of Inquiry Assesses net benefits (to VG retail customers & to all retail and
wholesale customers in DVP contro l) of DVP joining PJM to

Period Studied 2005-2014

Conclusion Net Benefit to Virginia Retail Customers: $110.3 million for ’05-’10: $476.6 million for ’05-’14.

Net Benefit to DVP customers: $127.4 million for ’05-’10: $557.2

million for ’05-’14.

# The Benefits and Costs of Regional Transmission Organizations and Standard Market Design in the
Southeast Region SE (SeTrans, Grid South, Grid Florida)
Report Date 11/6/02
Sponsor Southeastern Association of Regulatory Commissioners

Contractor Charles River Associates / GE Power Systems Engineering

Model/Method GE MAPS (OPF/Production cost mode l) and a Financial Evaluation
Module.
Scope of Inquiry Net benefits of instituting SMD in SE (GridSouth, SeTrans & GridFlorida) of the US.

Period Studied 2004 – 2013

Conclusion Mixed +150 to +$1,421for SeTrans; -$286 to +$84 for Grid South; -$25 to +248 for Grid Florida: ($ Million 2003 dollars, PV over 10 years) Note: Total Benefits are Net of Estimated Costs of Operating RTO

Web Reference http://www.crai.com/pubs/pub_2901.pdf

STUDIES OF BENEFITS IN TEXAS

Electric Reliability Council Of Texas, Mark et Restructuring Cost Benefit Analysis. Region ERCOT/ Texas
Report Date 11/30/2004
Sponsor ERCOT

Author/Contractor TCA/KEMA

Model/Method a) Energy Impact Assessment (EIA) —quantified impacts to the energy market, system dispatch, energy prices, a nd resulting production system costs. (GE MAPS) b) Backcast —quantified optimized generation dispatch results for the ERCOT system for 2003 for comparison with those actually experienced. c) Implementation Impact Assessment (IIA) —provided quantitative and qualitative treatment of implementation startup costs, ongoing costs, and other transition-related impacts for ERCOT and its market participants. d) Other Market Impact Assessment (OMIA) —provided qualitative treatment of a variety of other measures of impact of market designs not captured directly in the EIA.

Scope of Inquiry focused on two alternative market design choices: a zonal market design (extant at the time of the study) and a nodal market design

Period Studied 2005-2014

Conclusion Did not draw single conclusion – “the potential savings found in the Energy Impact Assessment, relative to th e Implementation costs found in the Implementation Impact Assessment, suggest that the benefits of the TNM could outweigh the costs for the ERCOT region as a whole.

Web Reference http://oldercot.ercot.com/TNT/defau lt.cfm?func=documents&intGroupId=83&b

# APPENDIX D
STATE RETAIL COMPETITION PROFILES 331

Illinois: Overview of Retail Compet ition Plan and Market Response

Administrator and Start Date : Customer choice in Illinois began in December 1997 with the en actment of the Electric Service Customer Choice and Rate Relie f Act of 1997 (HB 362). HB 362 required a phase-in of retail competiti on, with larger customers able to choose an alternate gene ration supplier earlier in the transition. Specifically, customers eligible to choose their electric supplier as of October 1, 1999, included industrial and commercial customers with a demand of greater than 4 MW,332 commercial customers with businesses at ten or more sites with an aggregate coincident peak demand of 9.5 MWs or greater, and nonresidential customers accounting for one-third of the remaining el ectricity use of their customer class. All other non-residen tial customers were allowed to choose a supplier as of December 31, 2000, and all residential cu stomers as of May 1, 2002.333 The mandatory transition period ends January 1, 2007.334

The Illinois Commerce Commission (ICC) oversees the transition to competition in the electric industry. On January 24, 2006, t he ICC approved proposals from Commonwealth Edison, the Ameren companies, Central Illinois Pub lic Service, Central Illinois Light Company and Illinois Power, to procure generation (for retail customers who do not switch to an alternative retail supp lier) through a joint competitive reverse auction process. In order to reduce price increases after the transition period ends, the utilities have offered to phase in price increases at the end of the transition period for resi dential customers.

Services Open to Competition : Generation and metering services: The I CC promulgated rules that permit non-reside ntial customers to choose a meter service provider other than the distribution utility.

The ICC permitted Commonwealth Edison to designate customers with a demand exceeding 3 MW as a competitive customer class.335 No other classes of customers have been declared competitive to date. Competitive services are defined as those services provided under special co ntract, not provided under tariff, and any tariffed service that the ICC decides is competitive. A service is declared competitive only if it is offered by a pro vider other than the utility or its affiliate, to a defined customer group or area, at a competitive pr ice, if the utility is likely to or has lost business to the competitor, and if there is adequate transmission system capacity.336

Consumer Options : Consumers have two options for service:

(1) They may either remain w ith the utility as a bundled custom er (i.e., receiving generation, transmission and distribution se rvices); or (2) They may choose to become a delivery services customer (i.e ., they only take distribution a nd transmission services from th e utility). Delivery services customers may purchase generation services from anothe r electric utility, from a competitive supplier, or from their o wn utility using the power purchase option (PPO).337

The PPO is a transitional option that is provided by distribu tion utilities as long as they are recovering stranded costs from customers ( see Recovery of Stranded Costs/Transition Costs). Under PPO service, a non-residential delivery services custom er (such as an industrial customer) can purchase electric power from the utility at a price that reflects wholesale costs. These custom ers may then assign the power pur chased under the PPO to an alte rnative supplier. Under this option, the suppliers to whom customers have assigned PPO rights are, in effect, purchasing electricity from the utility and selling it to their customers.

Alternative Suppliers Lice nsed to Provide Service : All suppliers wishing to provide competitive supply se rvice must have a certificate of service authority. In order to receive certification, a supplier must show techni cal, financial, and managerial capability.338 A competitive supplie r is required to maintain a license or permit bond in the amount of $30,000 if the supplier intends to serve only non-residential customers with maximum demand greate r than 1 MW; $150,000 if the supplier intends to serve non-residential customers with annual electric consumption greater than 15,000 kWh; or $300,000 if th e supplier wishes to be certified to serve all eligible retail customers.

In general, retail competition is much more active in the Comm onwealth Edison territory than else where in the state. In 2005, the number of active suppliers in each distribution utility’s territory ranged from zero for MidA merican, to nine for ComEd.339 Over the 2000 to 2005 period, th e number of suppliers increased in the AmerenCIPS service territory from 3 to 4. An alternative supplier entered the AmerenCILCO area for the first time in 20 03 and the only alternative supplier left the MidAmerican area in 2001. The reta ilers have focused only on non-residential customers.

Retail Pricing Trends : As Table 1 shows, retail prices for the residential sector rose about 7 percent from 1988 to 1997. Commercial and industria l prices rose by lesser amounts during that decade. Prices for all classes of customers declined after that decade through 2004, with the la rgest declines taking place in the residential sector due to mandatory rate reductions.

Price Changes for POLR Service for Residential Customers : In accord with the restructuring legislation, there were mandatory residential POLR service rate reductions instituted in 1998, which depended on how the utility’s re sidential rate compared to the residential rate for all la rge investor owned utilities in the region at the time of the restructuring legislation. The rati onale behind the restructuring le gislation was that competition w ould tend to bring higher local rates down to the regional average, but there wa s uncertainty about whether re sidential customers would obt ain these benefits of comp etition in a timely manner because of the relatively high expected mark eting costs associated with residential cu stomers. No mandated retail price reduct ions were applied to POLR service
for non-residential customers.

There are six major utilities in Illinois with required residential rate reductions for customers that have not selected an alt ernative supplier. Rate reductions were designed to bring residential rates in line with regional rates at the time of the re structuring legislation and are shown in T able 2.340 The larger discount rates were applied in two phases.



# Table 2. Price Reductions from 1997 Cost-Based Rates by Distribution Utility Distribution Utility Reduction from 1997 Regulated Prices

# Commonwealth Edison 20% (15% August 1999, 5% October 2001)

AmerenIP 20% (two increments)

AmerenCILCO 5%

AmerenCIPS 5%

AmerenUE 5%
MidAmerican Energy 1.7%

Non-residential customers were able to elect “real-time pricing” begi nning on October 1, 1998; residential
customers were able to elect real-t ime pricing beginni ng on October 1, 2000. 341 Real-time pricing is defined as pricing which varies hour by hour for non-residential customers, and on a periodic basis during the da y for residential customers.342 The largest residential real-time pricing effort is a pilot program involving 1,500 customers in the Commonwealth Edison territory operated by the Community Ener gy Cooperative.343 Some non-residential customers may also have real-time pricing or other time of use rates, but statistics are unavailable.

POLR Service Provider : Utilities must provide traditional, bundled service for those customers who choose not to shop for a competitive supplier.34 4 The POLR (standard offer) price is the price for bundled service (i .e., service including generation, transmission, and delivery), which was set by the utility’s last rate proceeding, less the amount of any rate reduc tion required in the restructuring law. This rate is frozen until January 1, 2007

.

Recovery of Stranded Costs/Transition Costs : Utilities collect stranded costs from both POLR service customers as part of the rates and through a separate charge from retail customers with an alternative supplier.345

Switching Restrictions and Minimum Stay Requirements : Customers purchasing power from an alternate supp lier are allowed to return to the utility after paying an administrative fee. A utility may require a returning customer with usage less than 15,000 kWh annually to stay with the ut ility for two years.346

Switching Activity : The degree to which customers have sw itched to delivery service from bundled servi ce varies greatly between distribution fra nchise territories and classes of customers. Table 2 provides the sw itching statistics for the largest utility franchise areas, separ ated by customer type, as of November 2005. As Table 3 indicates, the vast majority of switching ac tivity is centered on the Commonwealth Edison distribution territ ory (which also has the largest load in the state). Lower levels of switching have taken place in the AmerenCILCO and AmerenIP areas, and there has been very little switching outside of these
three areas.



# Table 3. Illinois Switching to Alte rnative Suppliers as of November 30, 2005 % of Customers and (% of Load)

Firm and Usage
In million kWh Residential Small C&I Large C&I Total

AmerenCILCO
461 0.0% (0.0%) 0.0% (0.1%) 2.2% (33.3%) 0.0% (15.4%)

AmerenCIPS
952 0.0% (0.0%) 0.2% (0.8%) 7.1% (4.1%) 0.0% (2.2%)

AmerenIP 1,496 0.0% (0.0%) 0.8% (8.9%) 29.8% (41.7%) 0.1% (23.2%)

AmerenUE
265 0.0% (0.0%) 0.0% (0.0%) 2.5% (0.2%) 0.0% (0.1%)

ComEd 91,508 0.0% (0.0%) 6.0% (36.6%) 73.9% (58.3%) 0.6% (32.8%)

MidAmerican
139 0.0% (0.0%) 0.0% (0.0%) 0.0% (0.0%) 0.0% (0.0%)

Source : Illinois Commerce Commission

# Table 4 shows the patterns of switching for the 2003 to 2006 period. Residential switching has remained dormant over the whole period while la rge non-residential customers have switched much of their load to alternative suppliers. Small non-residential customer s have been slower in switching to alternative suppliers and the load served declined slightly in 2006, but the share of al ternative suppliers continue to be
well above the levels in 2003.

Table 4. Illinois Retail A ggregate Customer Migration St atistics, 2003 to January 2006 % of Customers and (% of Load ) Served by Alternative Suppliers

2003 2004 January 2005 January 2006

Residential 0.0% (0.0%) 0.0% (0.0%) 0.0% (0.0%) 0.0% (0.0%)

Small C&I 3.8% (30.2%) 4.4% (31.5%) 5.7% (38.4%) 5.9%) (36.7%)
Large C&I 58.6% (54.6%) 64.1% (56.6%) 73.0% (58.3%) 71.9% (58.7%)

Note : The 2003 and 2004 figures are annual aggregates while the 2005 an d 2006 figures are for the month of January. The 2005 and 2 006 figures are estimated from the statistics for the Commonwea lth Edison territory. Load in Commonwealth Edison accounts for approximately 96.5 percent of the load of IOUs. To be conservative, it was assu med that there was no switching outside of Commonwealth Edison, hence the Commonwealth Edison statistics fo r 2005 and 2006 were reduced by 3.5 percent to create the proxy for
the state-wide value.

Source : Illinois Commerce Commission



# Public Benefits Programs : The restructuring act establishes three public benefits funds which are slated to expire at the end of 2006. Table 5 contains information about the public benefits program in Illinois.

Table 5. Illinois Public Benefits Programs*

Research & Development Energy Efficiency Low

Income Renewable Energy Total

Million $ 3.0 75.0 5.0 83.0

Mills/kWh 0.03 0.60 0.04 0.67

% revenue 0.03% 0.87% 0.06% 0.96%

Admin. DCEO DCEO DCEO

Note : Trust Funds are administered by the Illinois Depart ment of Commerce and Economic Opportunity (DCEO).

Source : American Council for an Energy-Efficient Economy, Summ ary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005) available at http://www.aceee.org/b riefs/mktabl.htm.



## * In December 1997, PA 9D-551 was signed. It provided funding for EE, RE, LI (a lthough EE and RE are at low levels) using non-bypassable, flat monthly charges on customer bills. (mills/k Wh) equiv. includes $ from gas & elect. Also one-time ComEd $250 million Clean Energy Trust Fund approved by legislature in May, 1999 (not in table).



# Separation of Generation and Transmission : Illinois did not require divestiture or functional separation. Thus, utilities may engage in both competitive and non- competitive services without forming a separate affiliate. All of the major utilities in Illinois chose to transfer generation assets to affiliates with the exception of Commonwealth Edison, which dive sted its fossil fuel generation plants.

State RTO Involvement : The restructuring legisla tion required Illinois utilities with transmission assets to join an RTO or ISO. Illinois utilities have joined either the Mid-West ISO or PJM West. Commonwealth Edison, for example, joined PJM West. The Ameren utilities joined the Mid-West ISO. MidAmerican has not joined an ISO, although it ha s received FERC authorization to e ngage an independent transmission
operator.

# Generation Capability : 347 Prior to the restructuring legisl ation (1997), utilities operated 97 percent of the generation capability in Illinois. By 2002, that figure dropped to 9.1 percent. The difference reflected the transfers and sale s of generation assets to utility-affiliate d entities and entry or expansion by independent power producers. Between 1997 and 2002, generation output in the state increased from 135 million MWhs to 188 mill ion MWhs, a nearly 40 percent increase. During the 1993 to 1997 period, output in the state had shrunk by more than 5 percent .

Use of Customer Information : No customer-specific information can be give n to a supplier without customer authorization.348

Standardized Labeling :349 “The 1997 Illinois restructuring law incl udes provisions for disclosing fuel mix and emissions by retail electricity suppliers . Final rules issued by the Illinois Commerce Commission (ICC) require re tail suppliers to provide a b ill insert to customers each quar ter with a table and pie chart representing the sources of electricity used in the previous y ear, beginning in January 1999. Supp liers must also provide a tab le showing total emissions of carbon dioxide, nitrogen oxides, and sulfur dioxide, as well as th e amount of high- and low-level nuclear waste attributable to the sources of electricity.”

Renewable Energy Portfolio Standard : On July 19, 2005, the ICC adopted a voluntary renewable portf olio standard target for bundled retail load starting at 3 percent in 2007 and rising by one percent each year until it reaches 8 percent in 2013. 

### 350 The ICC’s resolution also includes targeted reductions in future load growth.

Maryland: Overview of Retail Competition Plan and Market Response

Administrator and Start Date : The Maryland General Assembly enac ted the Maryland Electric Customer C hoice and Competition Act (SB 300) on April 8, 1999. The Act allowed for a three-year phase-in appr oach to electric competition, but the Maryland Public Services Co mmission (PSC) allowed the utilities to start electric competition all at once fo r all customers on July 1, 2000. The PSC oversees the custom er choice program. 351

Services Open to Competition : Generation, billing, and metering.

Consumer Options : Customers may choose to remain with the distribution utility at PSC regulated prices until the end of the transition period; they may choose a competitive supplier; or they may choose to be aggregated with other customers. The transition period ended for most consume rs in Maryland as of July 2006. In other areas, the period ends in 2008.

Alternative Suppliers Lice nsed to Provide Service : All alternative suppliers must be licensed by the PS C, and must show proof of technical and managerial competence, compliance with FERC requirements, and compliance with state and federal environmental laws.352 A supplier must al so give proof of financial integrity,353 and the PSC assesses each competitive supplier’s app lication for a license on a case-by-case basis to determine w hether a letter of guarantee, bond, or letter of credit is needed, a nd in what amount.354 Registered suppliers and registered suppliers seeking additional custome rs are available on the Maryland PSC’s website. There are numerous registered and active suppliers for C&I customers. For residential customers, there are num erous registered suppliers but only two suppliers in three of the four ma jor utility territories and none in the Alleghe ny Power territory before the end of t he transition period.

Pricing Trends : As Table 6 shows, prices rose throughout the early 1990s for a ll sectors, then declined until 200 2. Prices rose in 2003 and 2004. With the end of the transition period for most residential and small C&I customer s in the state, POLR service is scheduled to be priced at m arket rates. Procurement contracts for POLR service starting in July 2006 are scheduled to result in price increases above existing POLR rates. For example, the scheduled price increase for customers in the BG&E distribution territory is reported to be 72 percent.355 Because of concerns about the size of the expect ed price increase, a number of alternative proposals were developed to break the increase into sm aller steps. Legislation just prior to the end of the transi tion period included deferrals of
revenues and dismissal of the members of the PSC. At the time of this writing, litigation regarding the latter provision is ta king place.356



# Price Changes for POLR (or Regulated) Service : Individual distri bution utility plans va ry, but a cap for all distribution utilities was put into e ffect through 2004 and then extended fo r two to four years. During the initial four years, distributi on utilities were required to decrease prices 3-7.5 percent. 357 During this period, if the distribution utility’s POLR price increased, transition charges decreased by a corres ponding amount, so that standard offer cus tomers did not have an overall price increase.358

POLR Service Provider : The distribution utilities provide POLR service in their resp ective territories until the end of the transition period (or l onger if the PSC extends the period). A distribution utility can procure the elect ricity for its POLR customers from any supplier, including an affiliate. Individual utility settlements require the utility to be the POLR service provider fo r the entire rate cap/freeze period (which varies in length p er utility) unless the Commission orders otherwise. POLR service rates and the respective terms were set in the individual utility settlements and have been in effect for the entire rate cap/freeze period.

Recovery of Stranded Costs/Transition Costs: Distribution u tilities were given an opportunity to recover all prudently incurre d and verifiable net transition costs, subject to full mitigation.359 Transition co sts eligible for recovery include those that would be recoverable under rate-of-re turn regulation, but are not
recoverable in a restructured electric market and costs that result from the creation of customer choice.360 Stranded costs ha ve been recovered through a competitive transition charge, and may be recovered over differe nt lengths of time for each distribution utility. The PSC dete rmines the amount of recoverable transition costs, as well as the amount of the charge to be levied on customers.

Switching Activity: Table 7 shows the proporti on of customers and load taking service fr om alternative suppliers in each major utility distribution territory.

# Table 7. Retail Customers and Load Supplier by Alternative Providers in February
2006 % of Customers and (% of Load)
Firm Residential Small C&I Medium C&I Large C&I
Allegheny Power 0.0% (0.0%) 0.1% (0.9%) 18.0% (19.3%) 58.1% (29.5%)

Baltimore G&E 0.0% (0.0%) 0.9% (1.7%) 17.2% (19.8%) 87.1% (93.4%)

Delmarva P&L 0.0% (0.0%) 1.9% (4.1%) 22.5% (28.6%) 91.0% (95.7%)

Potomac El. 5.8% (7.1%) 10.8% (14.0%) 14.2% (13.2%) 75.8% (83.3%)

Source : Maryland PSC



# Table 8 shows the state aggregate level of switchi ng as of December for each year from 2000 to 2005.

Table 8. Maryland Retail Aggregate Cu stomer Migration Statistics, 2001-2005. % of Customers and (% of Load) Served by Alternative Suppliers

Dec. 2000 Dec. 2001 Dec. 2002 Dec. 2003 Dec. 2004 Dec.
2005

Residential 0.6% (0.7%) 2.6% (3.4%) 3.3% (4.1%) 3.1% (3.8%) 2.2% (2.9%) 1.5% (1.9%)

Small C&I 3.6% (4.2%) 2.8% (3.4%)

Medium C&I 21.7% (24.6%) 17.7% (21.0%)
Large C&I 1.2% (3.2%) 4.1% (9.8%) 6.2% (30.4%) 5.7% (27.8%)

58.0% (75.1%) 78.6% (87.4%)

Note : Prior to 2004, Non-residential data we re combined into a single category.

Source : Maryland PSC



# Public Benefits Programs: Funds fo r a Universal Service Program have been collected from all customers, and may not be assessed on a per kilowatt-hour basis. 361



# Table 9. Maryland Public Benefits Programs

# Research
& Develop. Energy Efficiency Low

Income Renewable Energy Total

Million $ Up to

1.0 34.0 34.0+

Mills/kWh 0.51 0.51+

% revenue 0.82 0.82+ MD’s restructuring law was signed in April 1999 including a $34 M/yr. tax
funded
Universal
Service Fund.
Additional
funds from
individual utility
settlements.

Admin. Utility State

# Source : American Council for an Energy-Efficient Economy, Summary Table of Public Benefi t Programs and Electric Utility Restructuring (December 2005), available at http://www.aceee.org/briefs/mktabl.htm.

Separation of Generation and Transmission: Dives titure of generation assets was not required, but functional, operational, st ructural or legal separation of regulat ed and non-regulated businesses or nonregulated affiliates was required by July 1, 2000. 362 Distribution utilities must provide a c ode of conduct to prevent their regulated service customers from subsidizing services of unregulated busin esses.363 A distribution utility can transfer any of its gener ation facilities or assets to an affiliate, if it desires.364 Power generation affiliates can only sell pow er on the wholesale market, except for st andard offer service suppliers. Retail sales affiliates may only buy power from the wholesale market.



# State RTO Involvement: Maryland bel ongs to the multi-state PJM RTO.

Generation Capability: Prior to th e restructuring legislation, utilitie s operated 95.4 percent of generating capability in Maryland. By 2002, that figure droppe d to 0.1 percent. Between 1997 and 2002, generation capability increased from 11,713 to 11,859 MW accompanie d by growth in the proportion of dual fired capacity.

Usage of Customer Information: Customer informati on cannot be released without a customer’s consent, except for bill collection and credit rating purposes. 365 Customer lists containing names, addresses, and telephone numbers of customers may be sold to competitive supplie rs. If a distribution utility intends to re lease such a list, it must inform its c ustomers, and advise customers of their opportunity to prevent disclosure of their identifying information.366

Standardized Labeling:

• Content: Distribution utilities and competitive suppliers must provide cust omers with a uniform set of in formation on fuel mix and emi ssions. When actual data is unavailable, a regional average may be used. Labels have to include comparis on of emissions and fuel mix t o the regional average when information is available. 

### 367



# • Timing: Labels must be provided to customers every six months. 368



# Renewable Energy Portfolio Standard: Maryland enact ed a renewable energy portf olio standard in 2004. The standard gradually increases to 7.5 percent in 2019. A separate standard of 2.5 percent including hydroelectric and waste-to-heat gene ration applies throughout the period.

Massachusetts: Overview of Retail Co mpetition Plan and Market Response

Administrator and Start Date: Electricity Restructuri ng in Massachusetts was init iated and is administered by the Department of Telecommunications and Energy (DTE). Retail competition began March 1, 1998, in
accordance with the restru cturing legislation enacted November 25, 1997.

Services Open to Competition: Generation only. Metering and billing are pr ovided by the distribution utility.

Consumer Options: During the transition to competi tion, consumers had three types of choices to obtain their electricity supply: a) standard offer service, b) service through an aggregator, or c) service from a competitive supplier. If a supplier was unable to provide services, c onsumers then received a “default” service. Unlike most states that provided POLR service, Massachusetts na med its POLR service as standard offer service, and devel oped another regulated price for thos e customers for which their supplier no longer provided service (default service). The tran sition ended in February 2005, at which time standard
offer service was discontinued for all customers. Cu rrently, customers who have not chosen a competitive supplier receive default service from the distribution utility that pr ocures generation services from

# wholesale suppliers. All retail customers are eligible for default service at any time, and may remain on default service indefinitely. Customers can also sele ct an alternative supplier or be part of a group of customers served by an aggregator. For purposes of this summary, default service will be referred to as a type of POLR service.

Alternative Suppliers Licensed to Provi de Service: All alte rnative suppliers must be licensed to provide
service to customers in Massachusetts. 369 Licensing regulations require a supplier to show technical and financial capability.370 Massachusetts maintains a roster of registered competitive el ectricity suppliers including brok ers and direct competitive suppl iers. The roster in February 2006 included 30 direct suppliers and twice as ma ny brokers.371 Ten of the suppliers offere d service to residential customers as di d a comparable number of brokers.

Pricing Trends: As Table 10 shows, prices for the residential and commercial sectors for the 1988 to 2004 period rose intermit tently before peaking in 1997 and then declined before peaking again in 2001. Prices for the industrial sector rose intermittently in the 1990s and also peaked in 2001.



# Table 10. Massachusetts Average Annual Price per KWh by Sector (nominal cents)

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Residential 8.5 9.1 9.7 10.4 10.6 11.0 11.1 11.3 11.3 11.6 10.6 10.1 10.8 12.5 10.9 11.7 11.75

Commercial 7.7 8.1 8.6 9.2 9.3 9.7 9.8 9.9 9.9 10.3 9.4 8.9 9.0 11.6 10.0 10.5 11.0

Industrial 6.8 7.3 7.9 8.5 8.6 8.7 8.5 8.4 8.4 8.8 8.2 7.7 8.1 9.4 8.3 9.1 8.5

All Sectors 7.8 8.3 8.8 9.5 9.7 10.0 10.0 10.1 10.1 10.5 9.6 9.1 9.5 11.6 10.1 10.6 10.8

Source: Energy Information Administration



# Price Changes for Standard Offer Service: Massachus etts set a minimum 10 percen t reduction of the entire bill for all customers receiving standard offer serv ice during the transition period. On September 1, 1999,
the reduction increased to at least 15 percent, in order to adjust for infl ation. These rate reductions applied
to all distribution utilities. 372 Distribution utilities were authorized to use securitization to meet the second rate reduction effective September 1,

1999.373

Standard Offer Service Provider: Standard offer service was provided until February 2005 for cust omers who had not chosen a co mpetitive supplier during the transition period. It was offered by the distribution utility, at rates which were set in advance, but subject to some adjustm ents.374



# POLR (default service) is offered currently to custom ers who are not receiving se rvice from a competitive supplier or aggregator. Former standard offer cust omers were offered POLR service at the end of the transition. The price for POLR serv ice is based on the price of proc uring it in the wholesale markets through fixed price short-term (three or six months) supply contracts. Distribution companies must procure electricity for default generation service through co mpetitive bidding, although the DTE also may authorize a competitive supplier to provide POLR service. 375



# POLR service prices cover the ener gy portion of the total bill. Distri bution rates, taxes, and fees are additional. POLR service prices foll ow wholesale prices. The default prices applicable to January of each year for the northern portion of the Boston Edison di stribution area (Table 11) illustrate the pattern.

Table 11. Default Prices Applicable in January by Year, Boston Edison (north)

1999 2000 2001 2002 2003 2004 2005 2006

Residential 3.7 4.5 7.0 6.4 5.0 6.5 7.5 12.7

Commercial 3.7 4.5 7.0 6.6 5.2 6.6 7.3 12.3

Industrial 3.7 4.5 7.0 6.5 5.1 6.6 9.0 18.1

DTE, Fixed Default Servic e Prices in cents/kWh



# Recovery of Stranded Costs/Transition Costs: The re structuring legislation provi ded for the recovery of

# stranded costs through a non-bypassabl e charge to all customers. 376 This charge was capped by the DTE, and the DTE determined, on a case-by-case basis, the time period for recovery.377

Switching Restrictions and Minimum Stay Requirements: Cust omers can switch to or from POLR (default/basic) service.378

Switching Activity: Table 12 shows the proporti on of customers and load taking service from alternative suppliers in each util ity distribution territory. In the Commonwealth territory, switching by residentia l customers is much higher than in any ot her area of the state. Much of this re sidential switching is attributable to community aggregations, principally the Cape Light Compact.379



# Table 12. Retail Customers and Load Supplie d by Alternative Providers in January
2006 % of Customers and (% of Load)
Firm and load in MWh Residential Small C&I Medium C&I Large C&I

Boston Edison 1,498,476 0.3% (0.6%) 2.0% (3.5%) 7.9% (13.6%) 34.0% (50.0%)
Cambridge 154,540 0.2% (0.3%) 6.7% (13.5%) 8.4% (12.4%) 33.6% (52.6%)

Commonwealth 403,108 54.2% (51.8%) 55.0% (57.5%) 44.3% (46.2%) 65.6% (70.5%)
Fitchburg 47,256 0.0% (0.0%) 3.8% (2.9%) 4.8%
15.5% 72.7% (86.6%)

Mass. Electric 1,995,096 2.1% (2.4%) 7.4% (12.2%) 31.1% (29.3%) 58.1% (66.2%)

Nantucket 12,547 0.2% (1.3%) 4.4% (6.6%) 23.6% (29.3%) 50.0% (53.2%)

Western Mass. 0.5% (0.7%) 6.6% (11.9%) 32.4% (36.8%) 60.2% (76.3%)

Source : Mass. Department of Telecommunications and Energy



# Table 13 shows the state aggregate levels of swit ching from January 2001 to January 2006. Although all
customers of Massachusetts distri bution utilities were eligible fo r retail access as of March 1, 1998, switching remained at minimum levels for residential and small C&I cust omers. Larger commercial and
industrial customers were more likel y to switch, but sometimes switched b ack to default service if default prices fell below prices from alte rnative suppliers. Subsequent to February 2005, the proportion of load served by alternative suppliers increa sed for all classes of customers.

Former standard offer customers either switched to competitive generation suppliers or started receiving POLR service at the end of February 2005. In December 2004, standard offer service applied to approximately 1.5 million customers with load of 1,959,705 MWh. The share of load served by competitive generators increased from 23.7 per cent to 30.4 percent between December 2004 and December 2005 following the end of the standard offer service.

Table 13. Massachusetts Retail Aggregat e Customer Migration Statistics, 2001-2006 % of Customers and (% of Load ) Served by Alternative Suppliers

Date Jan. 2001 Jan. 2002 Jan. 2003 Jan. 2004 Jan. 2005 Jan. 2006

Residential 0.1% (0.2%) 0.4% (0.4%) 2.8% (2.5%) 2.9% (2.6%) 2.7% (2.3%) 9.1% (7.6%)

Small C&I 0.6% (0.6%) 2.6% (4.4%) 8.8% (10.7%) 7.2% (11.3%) 6.8% (10.2%) 13.9% (21.2%)

Medium C&I 1.5% (2.1%) 7.4% (11.0%) 10.8% (17.2%) 11.3% (17.8%) 10.1% (16.5%) 14.9% (24.3%)
Large C&I 7.2% (13.3%) 20.1% (31.9%) 28.6% (43.1%) 32.4% (50.7%) 32.6% (48.9%) 45.7% (59.4%)Source : Massachusetts Department of Telecommunications and Energy



# Public Benefits Programs: The Ma ssachusetts Public Benefits Program s are summarized in Table 14.

Table 14. Massachusetts Public Benefits Programs

Research & Development Energy Efficiency Low

Income Renewable Energy Total

Million $ 130.0 Incl. 26.0 156.0

Mills/kWh 2.50 In 0.50 3.00

% revenue 2.81% EE 0.58% 3.38%
Admin. Utility Utility MTPC In Nov. 1997, comprehensive legislation was signed bringing
retail access to
all customers in 1996, included

a nonbypassable wires charge for EE, RE and LI. LI must get
at least .25
mills of the EE. In Feb. 2002, legislation was signed extending the
SBC for five years, through
Dec. 2007. Note : MTPC is part of the Massachusetts Technology Collaborative.

Source : American Council for an Energy-Efficient Economy, Summary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005), available at http://www.aceee.org/briefs/mktabl.htm.



# Separation of Generation and Transm ission: The Massachusetts restru cturing law required distribution utilities to divest their generation f acilities (either by sale or by transfer to an affiliated company), if they sought to recover stranded costs. 380 If a distribution utility opted to transfer its generation assets to an affiliate, the two companies had to be strictly separated,381 and distribution utilities were not be permitted to sell electricity at retail except to provide their customers with standard offer service (which has now ended).382 Almost all of the distribution co mpanies divested their assets to only one company.

State RTO Involvement: Massachusetts distribution utilities are with in the footprint of the Indepe ndent System Operator of New England. Established in 1997, ISO-NE is responsible for managing energy markets a nd operating the transmission system in New England.

Generation Capability:383 Prior to the restructuring legisla tion, utilities operated 86.6 percen t of generating capability in Massachusetts. By 2002, that figure dropped to 9.0 percent with 91 percent of generation belonging to independent power producers. Between 1997 and 2002, generati on capability increased from 11,328 MWs to 12,159 MWs. Most of the new capacity uses natural gas.384

Usage of Customer Information: The dist ribution utility cannot release proprietary cust omer information to the affiliate witho ut written consent of the customer. Historical usage information will be pr ovided to a supplier who has received custom er authorization to initiate service.385

Standardized Labeling: 

### 386 “In February 1998, the Massachusetts Department of Te lecommunications and Energy (DTE) issued final rules (220 CMR 11.06) requiring electric retailers to provide customers with a st andard disclosure label containing information on price, fuel mix, emissions, and labor characteristics of generating sources on a quar terly basis, beginning Septem ber 1, 1998. Suppliers must also issue notices in a ll advertisements stating that disclosure labels are available upon request. Supply mix in formation must be based on market settlement data or equivalent data provided by the ISO available for the most recent one-year period. Data on carbon dioxide, nitrogen oxides, and sulfur dioxide emissions must b e presented in a format comparing them to the regional average. El ectricity providers are also required to report the percentage of power generated fro m sources that have union contracts with their employees and the percentage generated fro m sources that use replacement labor during labor disputes. Supp liers must submit a report to the DTE annually containing "statements of verification by the ISO or an independent auditor." Massachusetts is worki ng with other New England states to develop a Generation Info rmation System that will supply data for imp lementing the disclosure requirement.”

# Renewable Energy Portfolio Standard: Massachuse tts enacted a minimum renewable energy portfolio standard on April 26, 2002. The standard started at 1 percent in 2003 and increases to 4 percent in 2009 in one half percent increments. After 2009, the standard is scheduled to in crease in 1 percent increments at least through 2014. 387

New Jersey: Overview of Retail Comp etition Plan and Market Response

Administrator and Start Date: The New Jersey Electric Discount and Energy Competition Act provided for retail choice to begin August 1, 1999, but the New Jersey Board of Public Utilities (BPU) delaye d the start date to November 14, 1999, to give utilities more time to modify their computer systems to interact with competitive retail suppliers in orde r to ease customer switching.

Services Open to Competition: Generation is open to competition. Work on a policy to permit competition for other customer se rvices, such as metering and billing, was suspended on June 23, 2004, for a minimum of two years.388



# Consumer Options: New Jersey consumers can pick th eir own alternative supplier or join an aggregation
of customers to contract with an alternative supplier. Customers received a “shopping credit” on their electric bill if they choose an al ternative supplier. The shopping cred it was also known as the “price to compare” and was the amount on a customer’s bill that was credited to the customer if he chose an alternate supplier and did not receive basic ge neration service from th e distribution utility. 389

Customers that are not served by an alte rnative supplier receive Basic Generation Serv ice (BGS), which is procured through peri odic auctions. Large industrial customers with BGS are charged hourly prices that track wholesale spot market prices. BGS for other customer classes is ladder ed on a three year cycle.

Alternative Suppliers Licensed to Provide Service: New Jersey licensing standards provide that before receiving a license, new suppliers must show financial integrity and maintain a surety bond of $25 0,000 for an initial license. For a renewed license, suppliers have to maintain a b ond at a level determined by the BPU.390 Competitive suppliers must renew their licenses annually. The BPU website provi des lists of alternative suppliers serv ing residential, commercial and industrial retail customers. As of February 2006, active alterna tive suppliers for residential customers range from 3 in the J CP&L territory, to 1 each in the
Conectiv and PSE&G territories. None offer service to residen tial customers in the Rockland terr itory. For C&I customers, the re are 6 active suppliers in the Rockland territory and 19 or 20 in each of the other territories.

Pricing Trends: As Table 15 show s, prices in all three sectors rose throughout th e early part of the decade, reaching a peak i n 1997. Prices for residential and commercial customers fell over the next several years before ri sing again, but not as high at the 1997 peak. For industrial cu stomers, the same pattern is evident except that the 2004 price exceeded the 1997 peak.

Price Changes for POLR (Basic Generation Service) Service: Al l customer classes were granted an initial 5 percent rate reducti on with an additional reduction of at least 5 percent over the first three years of the transiti on period for POLR service. Th is entailed a reduction of at le ast 10 percent from April 1997 levels. The reductions were from the distribution porti on of the customer’s bill, so that even those customers that switched to a new s upplier obtained the price reductions. Retail price caps expired in the summer of 2003.391

Beginning in 2002, New Jersey instituted th e Basic Generation Service (BGS) Auction “to meet the electric demands of customers who have not selected an alternative supplier and to make BGS available on a competitive basi s... The Internet BGS Auction, the first of its kind in the n ation, was a descending clock auction...”392 The bidding process for hourly pr iced electricity is separate from that for fixed price service and the latter in volves three year supply contracts that supply one third of the anticipated load of fixed BG S. Table 16 shows the auction results for 2003 to 2005.



# Table 16. Auction Results for Three Year Contracts Used to Ladder
Fixed BGS Rates

Feb. 2003 Feb. 2004 Feb. 2005

Conectiv 5.529 cent/kWh 5.513 6.648

JCP&L 5.587 5.478 6.570

PSE&G 5.560 5.515 6.541

Rockland 5.601 5.597 7.179

Source : BPU Press Releases of Feb. 5, 2003; Feb. 11, 2004; and Feb. 16, 2005. The Feb. 9, 2006, press release did not list the winn ing bid prices, but indicated that the averag e residential bill would increase 12% to 13. 7% as a result of increases in the 2006 co mponent of the laddered prices.



# POLR Service (BGS) Provider: Generation services we re provided by the distribution companies for three years following the opening of retail competition. 393 Through BGS, all customer classes are e ligible for generation service overseen by the BPU.394 Non-residential customers who return to BGS are gene rally required to remain with that service for one year.395 T he auction system for procuring BGS has been in place since 2002, although rate caps applied until mid-2003.Recovery of Stranded Costs/Transition Costs: The BPU determin ed the recoverable amount of stra nded costs, and distribution uti lities recovered most stranded costs over a maximum of 8 years, through a market transition charge (MTC).396 All customers were be assessed this charge, exce pt for off-grid customers who are exempt from exit fees.



# Switching Restrictions and Minimum St ay Requirements: Customers can sw itch suppliers or return to their distribution company at any time, in accordance with the terms and conditions of their service agreement with their supplier or dist ribution company. A customer may not be charged a fee for switching suppliers.

Switching Activity: The Table 17 provides the switching statistics for large C&I customers in the major
distribution territories as of December 2005.

Table 17. Customer Switching by Distribution Utility (December 2005) % of Customers and (% of Load ) Served by Alternative Suppliers

Combined Residential and NonResidential
Fixed Rate Residential Fixed

Rate Non-Residential Fixed

Rate Large
C&I Hourly

Conectiv 0.0% (12.4%) 0.0% 0.3% 87.2% (95.7%)

JCP&L 0.1% (11.6%) 0.0% 0.4% 62.7% (87.7%)

PSE&G 0.1% (15.3%) 0.0% 0.7% 64.0% (84.0%)

Rockland 0.0% (4.4%) 0.0% 0.3% 55.0% (70.3%)

Note : New Jersey does not report separate residential and small C&I load of alternative suppliers.

Source : New Jersey BPU and Restructuring Today (January 27, 2006), p. 3.



# The number of residential customers se rved by alternative suppliers is a nd has remained very low with the peak of less than 6 percent in the Conectiv (Atlantic) distribution area in December 2000. 397 As of December 2005,
less than 1,000 residential customers had a lternative suppliers in the entire state.398 As with the residential sector, the nu mber of small C&I customers served by alternative suppliers peaked in December 2000 with 8.6 percent of customers and 16. 3 percent of load for this class of customer served by alternative suppliers.399 As of December 2005, less than 1 percent of sma ll C&I customers had alternative suppliers, but they tended to be larger than average customers
because the share of lo ad exceeds the share of customer served by alternative suppliers.

The POLR service available to large C&I customers in New Jersey is priced on an hourly basis, CIEP, that tracks the wholesale s pot market prices. Hence, large C&I customers wishing to hedge price volatility must do so by se lecting an alternative supplier. New Jersey’s experience has b een that many large C&I customers prefer to buy from alternative suppliers when POLR service is priced on an hourly basis.

Table 18 provides aggregate switching data for residential and non-residential customers from 2003 to the end of 2005.



# Table 18. New Jersey Retail Aggregate Customers Migration Statistics, 2003-2005 % of Customers and (% of Load) Served by Alternative Suppliers

Year 2003 pre August November 2003 December 2004 December 2005

Residential and Small C&I (1 to 2%) 3.3% (12.5%) 0.3% (15.4%) 0.0% (13.6%)

Residential 3.6% 0.0% 0.0%

## Small C&I 0.8% 1.8% 0.6%
Large C&I ~ 10% 66% 64.7% (83.9%)

Note : Archives of New Jersey BPU switching statistics are not available.

Source : Restructuring Today various issues.



# Public Benefits Programs: Table 19 identifies the elements and New Jersey’s public benefit programs.

Table 19. New Jersey Public Benefits Programs

Research & Development Energy Efficiency Low

Income Renewable Energy Total

Million $ 89.5 10.1 30.0 129+

Mills/kWh 1.22 0.14 0.41 1.76

% revenue 1.31% 0.15% 0.44% 1.89%

Admin. NJ

BPU Utility NJ BPU Restructuring law passed in

Jan. 99. Requires funding for
EE/RE at same level as existing
DSM costs (approx. $235million/yr.)

Full SBC is 3.6
mills. Half would pay for costs from prior year, half for programs. 25%
of new must be
RE. Numbers
in table are new programs only
set in BPU
order Mar/01. LI separately funded at prior
levels. Source: American Council for an Energy-Efficient Economy, Summary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005), available at http://www.aceee.org/briefs/mktabl.htm.



# Separation of Generation and Transmi ssion: The restructuring act does not mandate divestiture, though the BPU may require a distribution utilit y to functionally separate its gene ration assets to the distribution utility’s holding company or a related competitive bus iness segment if there are market concentration

concerns. 400 Electric distribution utilities had three options: divestiture, structural separation or functional separation. Of the f our major distribution utilities in New Jersey, two divested nearly all of their generation, one divested most (but not all) of its generation, and th e fourth transferred its generation assets to an unregulated affiliate.401 In Augus t 2000, PSE&G transferred approximately 10,200 MW of its electric generating facilitie s to PSEG Power, LLC, an unregulated power generation affiliate. The BPU approved the sale of Rockland Utility’s generation assets to Southern Energy A ffiliates in June 1999.402

State RTO Involvement: New Jersey is with in the multi-state PJM region, an RTO that includes Pennsylvania, New Jersey, Marylan d, Delaware, the District of Columbia, and parts of Virginia. In recent years, the PJM RT O has significantly expanded its ge ographic scope to the West and South of its original footprint. The PJM region is responsible for the operation of the region’s wholesale electric market.

Generation Capability:403 Prior to the restructuring legisla tion, utilities operated 81.2 percen t of the generation capabilit y in New Jersey. By 2002, that figure dropped to 6.8 percent after divestitures, transfers, and entr y of new generators. Between 1997 and 2002, generation capabili ty in the state increased from 16,855 MWs to 18,384 MWs, an increase of 9.1 pe rcent . Nearly all of the increase was in dual fueled generators built by IPPs. During the 1993 to 1997 period, generating capability had increase d by less than 3 percent .Usage of Customer Information: Neither pow er suppliers nor distribution companies can disclose proprietary information, includi ng historical payment and energy usage information without the written consent of the customer. Any third party who receives such information can only u se it in order to provide
continued electric service to the customer.404



# Standardized Labeling: 405 “The New Jersey Board of Public Utilities (BPU) adopt ed an interim disclosure rule on July 26, 1999, in accordance with the state's restructuring la w. The rule requires electricity suppliers to provide consumers with a uniform disc losure label containing information on fuel mix, carbon dioxide, sulfur dioxide, and n itrogen oxides emissions, as well as energy-efficiency efforts tw ice a year, effective August 1, 1999. Air pollutant emissions must be compared to th e regional average. Suppliers should use data from the most recen t 12-month period with a 3-month lag, unless such data are unavailable (as in the ca se of a new market entrant). Information must be provided for each product offered and verified by an independent auditor.”



# Renewable Energy Portfolio Standard: The New Jers ey Board of Public Utilities adopted renewable energy portfolio standards on February 1, 2005. The sta ndard starts at 3.25 per cent for 2005 and rises to 6.5 percent by 2009. On August 31, 2005, the BPU authori zed specific standard s for two classes of renewable energy sources in addition to contin uation of the existing solar requirements.

New York: Overview of Retail Compet ition Plan and Market Response

Administrator and Start Date: Rest ructuring in New York State has ta ken place through orders of the New York State Public Service Commission (NYPSC), rather than through legislative initiatives. Because the PSC phased in restructuring through PSC-approved utility restructuring plans over a three year period, each utility had a different timetable to transition to retail competition.

In 2004, the NYPSC identified a number of “best practices” and ordered distribution utilities to submit plans to foster the development of retail competition. 406 Subsequently, the NYPSC adopted statewide guidelines, based on the program developed by Ora nge and Rockland (O&R).407 Under the guidelines, th e distribution utility notifies any customers who c ontact the utility that they may try an alternative supplier for a two-m onth period without any penalty for leaving or returning to POLR service after the t rial period. Alternative suppliers participating in the program offer a one-time 7 percent discount for the trial period. Customers can either pick an alternativ e supplier or have one randomly assigned and customers are can return to POLR service or to anot her alternative supplier at the end of the trial period. As th e table on retail switching indicates below, switching levels in the O&R distribution te rritory are higher than in other territories.

On September 23, 2005, the PSC determined that the pace of develo pment of real-time pricing was insufficient to moderate the ef fects of rising fuel costs.408 To speed the development of real-time pric ing, the PSC ordered that existing real-time pricing programs in some distribution te rritories be expanded to include all territories and that POLR service for large C&I customers be tied to real-time pricing.

Services Open to Competition: Generation, metering and billing. Distribution companies were required to file unbundled meteri ng tariffs and calculate a
“backout” credit for customers who choose a different meter service provider. The PSC ’s competitive metering and meter reading rules allow customers who choose a competitive supplier and customers who remain with th e distribution utility to choose competitive metering services. Customers who choose competitive metering services must procure both meter and mete r data services competitively. Distribution utilities are the pr oviders of last resort for metering
and meter data services.409

Consumer Options: New York retail electricity customers can select an alternative supplier or be part of an aggregation of con sumers that obtain electric power from an alternative supplier. Customers not served by an alternative supplier recei ve POLR service from the distribution utili ty. POLR service for large C&I customers is offered on an hourly price basis th at tracks wholesale spot market prices.

Alternative Suppliers Deemed Elig ible to Provide Service: The New York PSC website provides lists of alternative suppliers in each distribution territory. For example, in February 2006, the number of alternative suppliers serving residential customers range d from 6 in the Central Hudso n and O&R territories to 13 in the National Grid (Niagara Mohawk) distribution territory. C&I customers generally had more a lternative suppliers to choose fr om.

Pricing Trends: As shown in Table 20, prices generally incr eased through 1997 and then wavered before increasing to higher lev els in 2003 and 2004.



# Price Changes for POLR Service: Each distribution util ity’s restructuring plan laid out different POLR rate reduction plans:

• Central Hudson basic electric rates were fro zen at 1993 levels through June 30, 2001, for all customers. In addition, large i ndustrial customers who chose to remain with Central Hudson for their generation services rece ived 5 percent per year ra te reductions until mid-2001.

• Con Edison industrial customers received a 25 percent immediate rate decrease, which remained fixed for five years. All other customers receive d a 10 percent rate decrease, phased in over five

years.

# • Orange and Rockland residential customers receiv ed a 4 percent decrease in rates during 1995 and 1996, while industrial and commercial customers rece ived rate reductions of 4-14 percent . On December 1, 1997 and on December 1, 1998, residential ra tes were reduced an additional 1 percent . Large industrial customer rates were reduced by approximately 8.5 percent on December 1, 1997.

• Rochester Gas and Electric residential and small commercial customers received a 7.5 percent
rate decrease. Other commercial and most industrial cu stomers received an 8 percent decrease. Large industrial customers received an 11.2 percent decrease. All decreases are being phased in over 5 years.

• New York State Electric and Gas industrial and la rge commercial customers (greater than 500 kW capacity) received a 5 percent per year rate decr ease, for five years. Residential and small
commercial and industrial customers have had their rate s frozen at current levels for two years, bills reduced 1 percent in the third year of the plan, and a total decrease of 5 percent by the fifth year of the plan. Industrial and commercial customers who are not eligible for the 5 percent decrease received financial incentives for load grow th to encourage business expansion.

• National Grid (Niagara Mohawk) customers received an overall rate decrease of an average of 4.3 percent . Residential and commercial customers we re to have a 3.2 percent decrease phased in over three years. Industrial customers were to have decreases of approximately 13 percent . In addition, Niagara Mohawk rates fo r electricity and delivery were set until September 1, 2001. In 2001 and 2002, Niagara Mohawk was allowed to reque st limited rate increases for distribution services, and prices for some of the electricity sold to all customers will fluctuate with changes in market prices.

POLR Service Provider: The dist ribution companies provide regulated POLR service for customers who do not choose a competitive supplier or who return to POLR service. 410

Recovery of Stranded Costs/Transition Costs: Distribution utilities recover stranded costs (net of proceeds from selling gene ration assets) through a nonbypassable distribution charge. Distribu tion utilities were required to use creative means to reduce the amount of stranded co sts before they are considered for recovery. Stranded cost calculations and timing of recovery we re determined on a case-by-case basis for each distribution utili ty.411

Switching Restrictions and Minimum Stay Requi rements: The NY PSC is currently implem enting a number of policies designed to en courage consumers to try alternative suppliers.412 One of these, known at “ESCO Referral Programs,” plac es limits on the ability of alternative supplie rs to levy charges against departing customers.413

Switching Activity: The switching statistics for December 2005 in each distribution territory appear in the Table 21.



# Table 21. New York Retail Customers and Load Supplied b y Alternative Providers as of December, 2005 % of Customers and (% of Load)

## Firm and Load in MWh Residential Small C&I Large C&I Total

NY IOUs 8,614,367 6.7% (9.0%) 18.4% (45.4%) 55.6% (75.7%) 8.3%
38.5%

Central Hudson 465,350 .8% (1.0%) 3.0% (15.6%) 49.2% (74.7%) 1.2% (26.9%)

Con Ed 3,425,765 4.6% (5.5%) 14.1% (40.2%) 77.5% (85.1%) 5.9% (37.4%)

National Grid 2,644,403 6.0% (7.7%) 22.9% (53.6%) 69.2% (69.2%) 7.8% (38.4%)

NYSE&G 1,100,064 6.8% (9.6%) 23.1% (54.6%) 51.7% (88.3%) 9.1% (40.7%)

O&R 349,282 30.4% (34.6%) 32.4% (49.5%) 19.7% (27.5%) 30.6% (37.6%)

Rochester G&E 629,504 17.5% (21.5%) 39.5% (58.8%) 62.2% (71.5%) 20.0% (49.5%)

Source : NYPSC



# The aggregate switching statistics for the utility distribu tion territories in the state from 2000 to 2005 appear in Table 22. Load served by alternative suppliers has increased each year with the largest increases in 2004 and 2005. The percentage of customers served by alternative suppliers increased from 1999 to 2002, declined in 2003, and resumed growing in 2004 and 2005.

Table 22. New York Aggregate Cust omer Migration Statistics, 1999-2005 % of Customers and (% of Load ) Served by Alternative Suppliers

Year 1999 2000 2001 2002 2003 2004 2005

Residential ~1.6% 3.4% 4.8% (5.0%) 5.0% (5.6%) 4.2% (5.9%) 5.1% (7.2%) 6.7% (9.0%)

Small C&I 8.0% (26.0%) 13.0% (36.2%) 18.4% (45.4%)

Large C&I ~4.3% 5.3% 6.2% (26.0%) 7.1% (30.0%)

23.7% (45.1%) 48.1% (66.8%) 55.6% (75.7%)

Source : NYPSC, Electric Retail Access Migration Reports



# Public Benefits Programs: New York’s public be nefit programs are charted in Table 23 below.

Table 23. New York Public Benefits Programs

# Research & Development Energy Efficiency Low

Income Renewable Energy Total

Million $ 26.0 87.0 22.0 150.0

Mills/kWh 0.26 0.83 0.21 1.42

% revenue 0.20% 0.69% 0.17% 1.18%

Admin. NYSERDA NYSERDA NYSERDA In May95,
the PSC
issued Order
96-12 requiring all
IOUs to file restructuring plans. A July98
Order set $78 million/year for an SBC,
administered by
NYSERDA.
In Jan01 the
PSC raised
the SBC to $150 million/yr
and
extended it for 5 years. (Table
shows
allocation
minus 10% held open.)
R&D incl. $14 million/yr
for RE.
Table does
not include $100 million/yr EE by

Power
Authorities Notes : The administrator is the New York State Energy Research and Development Authority, supervised by
the PSC. On December 14, 2005, the PSC ordered that the System Benefit Charge be increased to $175 M annually and that the program be extended for five years. NYPSC, System Benefits Charge (Mar. 2, 2006), available at http://www.dps.state.ny.us/SBCI II_Amended_Plan_3-2-06.pdf.

Source : American Council for an Energy-Efficient Economy , Summary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005) availa ble at http://www.aceee.org/briefs/mktabl.htm.



# Separation of Generation and Transm ission: The PSC encouraged tota l divestiture of generation, and it instructed distribution utilities to separate generati on and energy service functions from transmission and distribution systems. 414 Each distribution utility company’s restructuring agreement established different requirements for separation of generatio n and transmission.415

State RTO Involvement: New York distribution utilities belong to th e New York ISO, formed in 1998. The New York ISO exercises operational control over most of New York’s transmission systems, administers the ISO tr ansmission tariff, and operates the New York Open Access Same Ti me Information System (OASIS).416

Generation Capability:417 Prior to the re structuring regulations, utilities in New Yo rk operated 84.3 percent of the generatio n capability in the state. By 2002, that figure dropped to 32.4 percen t. The difference reflected mandatory divestitu res of generation to i ndependent generation f irms and entry or expansion of independent power producers. Between 1997 and 2002, generation capability in the stat e increased from 35,576 MWs to 36,041 MWs . In the previous 5-yearperiod, generation capability had decreased. Dual fueled generation increased as a proportion of generati on from 34.1 percent to 39.5 percent.

Use of Customer Information: Historical customer data will be provided by distribution companie s to customers or their authori zed designees. All historical data that a competitive supplier receives from the distribution co mpany must be kept confidential, unless authorized for releas e by the customer. A distribution company cannot disclose customer information to competitive supp liers if the customer has notified the distribution company in writing that he does not authorize release. Thereafter, customer information can only be released to a competitive supplier with the customer’s written authorization.418

Standardized Labeling: 

### 419 On December 15, 1998, the New York Public Service Comm ission (PSC) issued an order re quiring electric suppliers to use a standardized label to provide information to customers rega rding the environmental impacts of electricity products semi-annua lly. Suppliers must disclose fuel mix compared to a statewide average and emissions of sulfur dioxide, nitrogen oxide s, and carbon dioxide. Fuel s ource and emissions information are calculated by the Department of Public Service (DPS) and provided to retail suppliers quarterly. Calculations a re based on a rolling annual average with data supplied from the Independent System Oper ator and the EIA and verified by the DPS. The most recent re ports of each load serving entity (2004) are available at http://www3.dps.state.ny. us/e/energylabel.nsf/ViewCat?ReadForm&View=LabelInfo&Cat=Januar y+2004+-
+December+2004&Count=80.

Renewable Energy Portfolio Standard: The New York PSC adopted a renewable energy portfolio sta ndard on September 24, 2004. Th e policy calls for an increase in renewable energy used in the state from the then current level of 19 percent (mostly hydro) to 25 percent by 201 3.

Pennsylvania: Overview of Retail Comp etition Plan and Market Response

Administrator and Start Date: The Electricity Generation Custom er Choice and Competition Act was enacted on December 3, 1996. The Pennsylvania Electric Choice Pilot Program began in the fall of 1997, with 230,000 customers particip ating. These customers were able to be gin shopping for their electric generation supplier beginning Septembe r 1, 1998. By January 2, 2000, electric choice was fully implemented in nearly all of Pennsylvania. 420 Retail competition is administered by the Pennsylvania Public Utility Commission (PUC).

Services Open to Competition: Generation. Generally the distribution company provides mete ring and billing services, although there are some areas in Pennsylvania in which the alternative supplier may provide these services.421 Pennsylvania’s efforts to allow licensed generation suppliers to provide metering and billing services to retail customer s were suspended on August 12, 2002.422

Consumer Options: Pennsylvania consumers can select an alternativ e supplier or be part of an a ggregation of consumers buying p ower from an alternative supplier. Consumers not served by an alternative supplier receive POLR service arranged by the local distribution utility.

Alternative Suppliers Licensed to Provide Service: Competitive suppliers must be licensed by the PUC to provide service to Pen nsylvania customers.423 As of February 2006, the Duquesne Light territory had 4 alternative suppliers serving reside ntial customers and 20 serving C&I custom ers. In the PECO territory, 6 alternative suppliers were available for residential customers a nd 28 for C&I customers. Outside of these two territories, res idential customers only have available premium priced green generation products while C&I cu stomers had several alternative suppliers offering service.

Pricing Trends: Table 24 displays average retail prices in Penns ylvania by customer class from 1988 to 2004. Residential, com mercial, and industrial retail prices have fluctuated within a narrow range since 1991.



# Price Changes for POLR Service: POLR rates fo r distribution service were capped at January 1, 1997 levels until July 1, 2001. Rates for generation, includi ng transition charges, were capped at January 1, 1997 levels until January 1, 2006. 424 In some distribution utility service areas, generati on caps are in place until 2008-2011 because these distribution utilities will be collecting stranded costs over these longer pe riods. Many distribution utilities also extended distribution rate caps until 2003-2005. Pennsylvania did not require rate reductions, although several distribution utilitie s agreed to reduce rates in the first year of retail cho ice. These reductions were to be lowered and phased out over a two to three year period.425

Overall rate reductions, Table 25 for the first year ranged from 2.5 percent to 8 percent for the major utilities operating in Pennsylvania:426



# Table 25. First Year Rate Reduc tions by Distribution Utility

Distribution Utility First Year Rate Reductions

APS 2.5%

MetEd 2.5%

PECO 8.0%

Penelec 3.0%

## PPL 4.0%



# Shopping credit rates are the rates that a customer pays for generation if he receives generation service from the utility rather than from a competitive supplie r. Shopping credit rates increased over time, but fuel cost increases have been greater a nd the base rates are not adjusted unde r the Pennsylvania settlements with
distribution utilities. This has resulted in the declini ng market shares for alternative suppliers and the exit of alternative suppliers.

POLR Service Provider: The di stribution company provides POLR service for customers who do not choose a competitive supplier, for those who are unable to obtain service from a competitive supplier, or for customers whose suppliers do not deliver service. Di stribution utilities must offer standard offer service as long as the distribution utility is collecting transition charges or unt il 100 percent of its customers have
electric choice. 427 In June 2000, the PUC issued a change in the provision of POLR service, in order to prevent “gaming” of the system by customer s who were returning to their distribution u tility. During the summer, market prices rose , while POLR rates remained stable, bel ow market rates. This caused
customers to be either returned to POLR service by their suppliers or to return themselves to PO LR service. Many distribution utilities require customers to remain with the distribution utility for a 12-month peri od after switching back to the POLR provider.

Competitive POLR Service: Some distribution utilities have a rranged for competitive bidding to supply the generation services portion of POLR service for customers who do not affirmatively choose an alternative supplier. This option is known as Competitive Default Service (CDS). The PUC approved additional consumer protections for the initial phase-i n of CDS, including bidder qualifications , established creditworthiness, and bond l imits. The PUC also reviewed the CDS annually to ensure that it is still benefited consumers.428 The largest CDS effort took place in the PECO territory. PECO awarded a contract for 20 percent of its POLR service customers to The New Power Company. Additionally, 50,000 PE CO customers were assigned to Green Mou ntain Energy, Inc. PECO customers assigned to the CDS provide r received a two-percent discount on the sh opping credit (the capped generation servi ce rate). The CDS provider also provided no less than two percent of its supply from renewa ble resources and increased the use of renewable resources by o ne-half of a percent annually.429 Due to concerns that POLR prices were insu fficient to cover procurement costs, the CDS suppliers withdrew from this service. N o alternative suppliers have been willing to supply on these terms at pr esent. On December 10, 2005, the PUC deci ded to reopen POLR service issues for comm ent in preparation for the end of the transition period in distribution areas in addition to Duquesne.430

Recovery of Stranded Costs/Transition Costs: Stranded costs ha ve been administratively determined by the PUC on a case-by-case basis. Utilities were not required to establish market-based va luation by selling generation assets. Stranded costs are fully recoverable through a non-bypassable charge to all consumers, collectible for up to nine years, unless the PUC orders an alternative payment period.431 Table 26 shows each utility’s allowa ble stranded costs recovery and the seven to 10 year recovery periods to collect there costs from customers.



# Table 26. Transition/Stranded Costs:

Company Allowable Stranded Cost Recovery Length of Recovery Allegheny Power $670 million 10 years Duquesne Light $1,331 million 7 years GPU Energy (Met Ed.) $975 million 10 years GPU Energy (Penelec) $ 858 million 8 years PECO $5,024 million 8 1⁄2 years Pennsylvania Power and Light $2,864 million 9 years Pennsylvania Power Company $234 million 9 years

UGI Utilities $32.5 million West Penn Power Company $524 million 7 years

Source : Company Restructuring Orders and Tables



# Switching Restrictions and Minimum Stay Requirements: Customers can switch suppliers at any time, although they are advised to check their supply agr eement for any penalties which may apply for early termination of a supply contract. If a customer leaves POLR service and then returns, some POLR service providers require a min imum stay of 12 months. 432



# Switching Activity: At this point in time, retail switc hing activities are largely limited to the Duquesne Light distribution territory and to a lesser degr ee the PECO territory, as shown in Table 27.

# Table 27. Penns y lvania Retail Customers and Load Supplied b y Alternative Providers as of January 1, 2006 % of Customers and (% of Load)

Firm and Load in MWh Residential Small C&I Large C&I Total

Allegheny Power 0.0% (0.0%) 0.0% (0.0%) 0.0% (0.0%) 0.0% (0.0%)
Duquesne Light 19.7% (18.5%) 20.3% (52.3%) 43.4% (83.6%) 19.8% (48.0%)

MetEd/Penelec 0.0% (0.0%) 0.0% (0.0%) (0.1%) (5.6%) 0.0% (1.6%)

PECO 0.9% (1.0%) 23.8% (13.2%) 2.0% (1.2%) 3.2% (4.9%)

PennPower 0.0% (0.0%) 0.0 (0.0%) 0.0 (0.0%) 0.0 (0.0%)

PPL 0.0 (0.0%) 0.2 (0.7%) 0.3 (0.3%) 0.1 (0.3%)

UGI 0.0 (0.0%) 0.0 (0.0%) 0.0 (0.0%) 0.0 (0.0%)

Source : Pennsylvania Office of the Consumer Advocate



# The first quarter aggregate switching st atistics for the utility distributi on territories in Pennsylvania from 2000 to 2006 appear in Table 28. Load served by alte rnative suppliers has decr eased since 2000 with the exception of an increase in 2004. Alternative suppliers served a declining numb er of customers from 2001 to the present (with the exception of 2004).

Table 28. Pennsylvania Retail Aggregate Customer Migration Statistics, 1999-2006 % of Customers and (% of Load ) Served by Alternative Suppliers

Year 2000 2001 2002 2003 2004 Oct. 2005 2006

Resident. ~7.8% (~7.6%) ~9.2% (~8.6%) ~10.3% (~9.1%) ~4.9% (~4.7%) ~8.2% (~7.9%) 2.9% (2.7%) ~2.3% (~2.1%)

C&I ~17.6% (~41.9% ~16.9% (~32.6%) ~3.7% (~7.8%) ~4.8% (~12.4%) ~13.5% (~13.9%) 9.6% (15.5%) ~8.9% (~14.5%)

Note : Keystone Connection (Autumn 2005) provides th e percentage of customers and load served by alternative suppliers as well as th e total number of customers and load for residential customers a nd C&I customers separately for Oc tober 2005. Calculations for t he other years take the number of shoppers or shoppers’ load reported in January of that year and divide s them by the related Pennsylvan ia totals from Oct. 2005. The resulting calculations ar e approximations because the total number of customers and the total load in the state may have changed from year to year.

Source : Pennsylvania Office of the Consumer Advocate



# Public Benefits Programs: Table 29 identifi es the Pennsylvania public benefit programs.

Table 29. Pennsylvania Public Benefits Programs

# Research & Development Energy Efficiency Low

Income Renewable Energy Total

Million $ 5.0 85.0 6.0 96.0

Mills/kWh 0.04 0.68 0.05 0.77

% revenue 0.05% 0.85% 0.06% 0.96% In Dec., 1995, a restructuring law was signed
with retail
access to be phased-in over 2 yrs starting in
Jan99. The restructuring
law resulted in PUC-approved restructuring
settlement agreements for
each electric

company. Each
settlement
agreement created a system benefits
fund for LI programs and a
Sustainable Energy Fund (except for Duquesne).

Admin. SEF Utility SEFNote : Administrators are Sustainable En ergy Funds in each area of the state.

Source : American Council for an Energy-Efficient Economy, Summary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005) available a t http://www.aceee.org/briefs/mktabl.htm.



# Separation of Generation and Transmission: Gene ration must be separated from transmission and distribution, but distribution utilities are not required to divest fac ilities or reorganize corporate structure. 433 However, several utilities voluntarily divested generation assets e ither to independent companies or to unregulated affiliates.



# State RTO Involvement: The restructuring legislation directs the PUC to encourage interstate power pools to enhance competition and to complement restructuri ng. Much of Pennsylvania belongs to the PJM RTO. In order to meet electric load in the PJM region , PJM coordinates with member companies and uses bilateral contracts and the spot market to secure power. 434 In March 2001, Allegheny Power a nd PJM filed with FERC a request to expand PJM by forming PJM-West.435

Generation Capability:436 Prior to the rest ructuring legislation, utilities in Pennsyl vania operated 92.3 pe rcent of generation capability in the state. By 2002, that figure dropped to 12.3 pe rcent, despite the lack of a requirement for genera tion divestitures or transf ers. The difference ref lected voluntary divestitures to independent generators and tran sfers of generation to affiliates as well as e xpansion and entry of i ndependent power producers. Between 1997 and 2002, generation capability in the state increase from 36,650 MWs to 39, 783 MWs. Most of increase cons isted of dual fueled generatio n.

Use of Customer Information: A customer can restrict the disc losure of his telephone number a nd his historical billing data. A distribution utility or supplier who intends to supply a third-party with th is information must provide a customer with the means of restricting the release of this information, either through a signed form, orally, or electronically.437 Customer information cannot be given preferentially by a distri bution utility to its affiliate.438 During the initial phase -in period of electric restructuring, a cust omer’s name, address, telephone number, rate class, account number and load data we re given to competitive suppliers
as a result of the customer’s enrollment into the electric choice program. The custom er had the option of restricting the rele ase of his telephone number and load data to suppliers. After this initial phase-in period, to assure that customers retain the ability to rest rict disclosure of c ertain information to suppliers, the PUC directed distribution utilities to send forms to customers to give them the opportunity to restrict the release of load data, o r of all information (name, address, rate class, and account number). Telephone numbers would not be released to suppliers under any circumstances.439

Standardized Labeling:440 The Pennsylvania Public Utility Comm ission (PUC) issued final rules in April 1998 requiring retail el ectricity suppliers to "respond to reasonable requests made by consumers for information concer ning generation energy sources." Suppliers must respond to such requests "by informing
consumers that this information is included in the annual licen sing report and that this report exists at the Commission." Requ ests for information on energy efficiency must be handled in a similar ma nner. Suppliers must verify fuel mix data through an independent auditor and submit t his information in an annual report to the Commission. Suppliers that mark et electricity as "having special characte ristics" such as being environmentally f riendly, must have information
available to substantiate their claims.

Renewable Energy: Pennsylvania enacted a renewable portfolio st andard through Act 213 in December 2004. The standard includes a gradual increase in generation from renewables to 18 percent over 15 years. Qualif ied renewables are divided into two groups: traditional (solar, wind, hydro, geothermal, biomass, and coal-mine methane) and other (waste coal, distributed genera tion, demand-side management, la rge-scale hydro, municipal wast e, wood processing waste, and integrated combined coal gasification) . Separate standards are set for the tw o groups– -8 percent and 10 percent respectiv ely.

Texas: Overview of Retail Competition Plan and Market Response

Administrator and Start Date: The Texas restructuring bill was signed June 18, 1999. The Public Utility Commission of Texas ( PUC) administers the transition to retail competition, which began with a pilot program on June 1, 2001. Retail competition for all customer classes within ER COT began January 1, 2002.441 Competition is not open as yet in areas outside of ERCOT because the PUC is not convinced that re tail competition is feasible w ithout a regional transmission organization in these areas.442

Services Open to Competition: Generation and billing (retail sa les). Competitive metering for certain commercial and industri al customers began January 1,
2004.

Consumer Options: Customers within ERCOT have the option of c hoosing a competitive supplier, choosing an aggregator, and, in t he case of residential and small commercial customers, choosing POLR servi ce (termed “price to beat” default service).

Alternative Suppliers Licensed to Provide Service: In order to be licensed to provide service in Texas, competitive suppliers must meet financial
creditworthiness and technical standards.443 There are numerous s uppliers marketing to all classes of customers in Texas that are open for retail customer
choice. In addition to the Texas POLR de fault service offer, there are several alte rnative suppliers actively serving retail r esidential customers in each distribution territory. The figure below is from the “August 2005 Report Card on Retail Competition”444 showing the number of alte rnative suppliers available to residential customers, the number of products offered by th ese suppliers, and the number of alternative “green” offers for r esidential customers in the major
distribution territories within ERCOT.

# Pricing Trends: Retail price averages in Texas have wavered over time with peaks occurring in 1994 and 2001, as shown in Table 30. Prices increased in 2003 and 2004 after declining in 2002.

Price Changes for POLR (Default) Service: Distribut ion utility rates were frozen from September 1, 1999, levels until January 1, 2002. 445 On January 1, 2002, rates for residential and small co mmercial customers were reduced approximately 6 percent from January 1, 1999, levels. The January 1, 2002, reduced rate is called the “price to beat.”446 It is subject to adjustment twice per year, to reflect changes in fuel costs. Because Texas primarily relies on natural gas fueled generation, the increases in natural gas prices have resulted in substantial increases in the “price to beat.” POLR (defau lt) service is available from the distribution u tility’s competitive retail aff iliate until January 1, 20 07. Prior to January 1, 2005, affiliates of
distribution utilities could offer services othe r than POLR (default) service only if at least 40 percent of residential or sma ll commercial customers chose a competitive supplier not affiliated with th e local distribution utility. Since January 1, 2005, affiliates of distribution uti lities have been allowed to offer any service they wish in addition to POLR (defau lt) service.

The Texas PUC provides information on the price to beat and on a lternative supplier’s prices in each distribution territory. T he information includes a comparison of each alternative supplier’s pric e to the POLR (default) pric e for different levels of consumption. Table 31 show s the POLR (default) price and the range of offers from alternative suppliers for a consumer us ing 1000 kWh or 2000 kWh. The premium price is generally for a 100 percent wind generation product.



# Table 31. Texas POLR Service Price Compared to Alternative Suppliers 1000 kWh Consumption (January 2006)

POLR Price (cents/kWh)
For 1000 kWh Lowest
Alternative
% discount Highest
Alternative

% premium POLR Price (cents/kWh)
For 2000 kWh Lowest
Alternative
% discount Highest
Alternative % premium

West Texas
Utilities 19.06 19% 4% 18.95

TXU-SESCO 14.62 8% 10% 13.97 11% 8%

Texas-NM

Power 14.48 8% 10% 14.77 11% 6%

Central

Power 17.67 18% 6% 17.48 20% 6%

Centerpoint Energy 16.04 15% 9% 15.89 17% 8%

Source : Texas PUC, Retail Electric Service Rate Comparisons (January 2006 bill comparison)



# The PUC also has produced an aggregate comparison between the price to beat , the average offer of alternative suppliers, and the lowest offer of alternative suppliers. The figure below, from the PUC report

to the 79 th 

# Texas Legislature, illustrates these comparisons. 447

# POLR (Default) Service Provider: Until December 31, 2001, POLR (default) se rvice was provided by the distribution utility. When competition for all cust omers began in 2002, POLR (default) customers were transferred to the retail affiliate of the distribution utility. The affiliates and independent retail suppliers are termed “retail electric provi ders” (REPs). Prices for POLR (default) service were fixed at the “price to beat” plus fuel adjustments until January 1, 2007. Affilia ted retail electric providers were allowed to offer only POLR (default) service (at the “price to beat”) un less alternative suppliers attained a market share of 40 percent of residential or small commercial cust omers. In 2004, all but one of the affiliated retail electric providers within ERCOT (the separate transmission interconnectio n system in Texas) were granted permission to offer additional products. 448 Starting in 2005, all affiliated retail electric s uppliers were allowed to offer other products in addition to POLR (default) serv ices to all residential and small commercial customers.

Analysis by the Texas PUC concluded that PO LR (default) service pricing has been belo w the pricing that would have prevailed un der the prior cost-of-service regulatory regime. The tables below summarize the estimated regul ated rates, the aver age of the five lowest competitive prices , the best competitive price, and
the Price to Beat for the Cent erPoint and TXU Service areas.Source : PUC legislative report # 32198, Electricity Pricing in Compe titive Retail Markets in Texas (March 3, 2006), available at http://interchange.puc.state.tx.us/WebApp/ Interchange/Documents/32198_7_504891.PDF



# POLR Service Provider for other than Default Service: POLR service customers have been divided into three classes: residential, small non- residential, and large non-residential. POLR service providers supply customers in any or all of the th ree classes who either request POLR service or are assigned to POLR service because they are not receiving service from a RE P, for any reason. The ra tes for this POLR service are established first through a compe titive bidding process an d, if no qualified bids are obtained, are then allocated to existing suppliers via a lottery process. A bidder to s upply POLR service may bid for any customer class, or for more than one class. An aff iliate of a distribution utility cannot bid to be the POLR service supplier in its own service territory during the period while the price to beat is in effect. 449

The Texas PUC is currently reviewing its POLR service rules.450

Recovery of Stranded Costs/Transition Costs: Distribution utilities can recover all of their net non-mitigated stranded costs through a transition charge. The PUC determines the amount of stranded costs eligible for rec overy, which includes uneconomic ge neration related assets, and pur chased power contracts.

Switching Restrictions and Minimum Stay Requi rements Process: A customer can switch su ppliers at any time subject to the terms of his contract with the competitive supplier. There are no switching fees unl ess a customer requests a special meter reading.451

Switching Activity: Retail customers have been migrating to alte rnative suppliers in all of th e distribution territories with the highest switching rates in the AEP Central and North areas, as shown in Table 32.



# Table 32: Retail Customers and Load Supplied b y Alternative Providers as of January 1, 2006 % of Customers and (% of Load)

Firm and Load in MWh Residential Small C&I Total

TXU 26.3% (26.2%) 30.7% (64.7%) 26.4% (50.4%)
Centerpoint 26.8% (27.3%) 34.5% (60.7%) 27.5% (47.8%)

AEP Texas Central 27.0% (31.3%) 45.8% (81.4%) 29.4% (63.8%)

AEP Texas North 33.2% (39.3%) 34.0% (78.7%) 31.9% (64.9%)

Texas NM Power 25.8% (29.9%) 35.0% (66.8%) 26.4% (56.0%)

Note : Texas does not provide separate distribu tion area statistics for large C&I customers.

Source : Texas Public Utility Commission



# Retail customers have switched to alternative supplie rs in increasing numbers and with an increasing proportion of load, as shown in Table 33.

# Table 33. Texas Retail Aggregate Cu stomer Migration Statistics, 2002-2005 % of Customers and (% of Load)

Year 2002 2003 2004 2005

Residential 7.4% (7.3%) 14.1% (15.0%) 19.9% (21.0%) 26.7% (27.5%)

Small C&I 11.5% (33.0%) 19.0% (44.1%) 26.7% (55.5%) 34.2% (65.1%)
Large C&I 19% (54%) 35% (60%) 42% (69% 53% (68%)

Note : The large C&I figures are for December 2002, December 2003, Se ptember 2004, and June 2005. The Residential and Small C&I figures are all from January except the 2005 figure which is from September.

Source : Texas Public Utility Commission



# Public Benefits Programs: The Texas public benefit programs are pr esented in Table 34.

Table 34. Texas Public Benefits Programs

Research & Development Energy Efficiency Low

Income Renewable Energy Total

Million $ 80.0 166.2 246.2

Mills/kWh 0.28 0.58 0.83

% revenue 0.43% 0.89% 1.28%
Admin. Utility PUCT Restructuring Law signed in
June 1999. Requires
utilities to
administer EE
programs to achieve saving equivalent to
10% of annual load growth by
2004. PUC has
established
rates and procedures.
Est. total
annual cost is
%80 million in
2003. Also a
10% LI rate
discount &
small SBC for
customer educ.
and LI
assistance.
Total LI is set
at statutory maximum of
.65
mills/kWh. 452 Source : American Council for an Energy-Efficient Economy, Summary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005), available at http://www.aceee.org/briefs/mktabl.htm.



# Separation of Generation and Transmission: By January 1, 2002, utilities were requ ired to separate their

# business activities into three units : a wholesale electric power gene ration company, a re tail electricity company (REP), and a transmission and distribution company. This separation could take place either through the sale of assets to a third party, or by th e creation of separate non-affiliated companies or separate affiliated companies owned by a common holding company. 453 After the beginning of retail competition, a distribution utility may not sell electricity or participate in the market for electrici ty except to procure electricity to ser ve its own needs.454 Wholesale electric power generation companies that are affilia ted with a distribution utility are required to auction off 15 percent of their inst alled generation capacity,455 and no wholesale generator can own more than 20 percent of the installe d capacity that can be sold in a region.456 Before 2005, REP a ffiliates of transmission and distribution utilities could not offer competitive rates to residen tial and small commercial custom ers in the territory of the distribution utility, except as the POLR (default) service provider, until 40 percent of the residential or small busine ss load in the territory is buying electricity from competitive suppliers.457 The transmission system for most of Texas is operated independently from the owners of the transmission assets by ERCOT under PUC s upervision.

State RTO Involvement: Most of Texas (approximately 85 percent) is in the ERCOT interconnecti on.458 ERCOT began operations as an independent system operator in 1996. It is regulated by the Texas PUC rather th an by FERC.459 Transmission ope rations of distribution utilities outside of ERCOT are regulated by
FERC.

Generation Capability:460 Prior to the restructuring legisla tion, utilities operated 88.3 percen t of generation capability in Texas. By 2002, that figure dropped to 41.2 percent, as divestitures, transfers to affiliates, and entry and e xpansion of independent gene rators took place. Between 1997 and 2002, generation capability in the state increased from 73,454 MWs to 94,488 MWs, an increase of 28.6 percent . Much of the growth in generation was fuele d by natural gas. The share of generation capability fueled by natural gas in creased from 21.4 percent to 38.5 percent . Natural gas fueled generation more t han doubled during the period.

Use of Customer Information: When the re tail market opened to competition, distribu tion utilities were required to include cust omer name, address, and usage information on a list of eligible cust omers given to competitive suppliers.461

Standardized Labeling:462 “On December 7, 2000, the Texas Public Utility Commissi on (PUC) issued rules requiring retail electr ic providers to use an Electricity Facts Label to disclose information twice a year on fuel mix and environmental impacts to their retail and small re sidential customers, in accordance with the state's restructuring law. The label must also be in cluded in promotional material so liciting new customers. Fuel mix data must be compared to the state average, with energy generated from renewable resources to be listed under a single category. Emissions of carbon dioxide, sulf ur dioxide, nitrogen oxides, and particulates, as well as the amount of nucl ear waste generated, must be presented relative to the statewide average. According to rules adopted in August 2001, the Commission is developing a "generator scor ecard" database with data on fuel mix a nd environmental impacts by generator to f acilitate implementation of the disclosure requirements. The label is to be updated each year. Re tail providers can also opt to purchase and retire "renewable energy credits" from generators to meet their disclosure requirements. Provide rs can project their fuel mix and emissions data for new products or products offere d during the first year of competition. Any product marketed as "renewable" must include the renewable fuel mix percentage, unless it is supplied exclusiv ely from renewable sources. Products marketed as "green" may contain some natural gas fuels along with renewable fuels if it can be shown that the natural gas was produced in Texas.”463

Renewable Energy Portfolio Standard: Texas adopted a renewable en ergy portfolio standard on February 24, 2004. The standard e stablishes yearly new generation from renewables levels through 2 019, rather than percentage requirements. The levels are 850 MW in 2004 and 2005, 1 400 MW in 2006 and 2007, and 2000 MW in 2009 through 2019. In 2005, the RPS requirements we re expanded to a total of 5,000 MW by 2015. Additional non- mandatory targets for renewables were established at the same time, along with a pro cess that will allow the PUC to prioritize transmission developme nt to facilitate delivery of energy
from renewable sources.464

The original electric restructuring bill in cluded many environmental protections, incl uding that 50 percent of new generating capacity must come from natural gas, and that a percentage of electricity sold in Texas must come from renewable resources. The bill requires 50 percent reduc tions in nitrous oxide emissions and 25 percent reduction in sulfur dioxide em issions from power plants that were gra ndfathered when air permits were introduced under the Federal Clean Air Act. There reductions must be achieved by 2003 by retrofitting or shutting down the gr andfathered units. In addition, distrib ution utilities that upgrade older generation facilities to meet emissions standards may recover th e costs from retrofitting as st randed costs.465 The PUC has ad opted a renewable energy credit trading program to encourage cost-effec tive new renewable generation facilities.



# APPENDIX E
ANALYSIS OF CONTRACT LE NGTH AND PRICE TERMS COMPARISON OF NYISO, MISO AND SE RC MARKETS USING 2005 EQR DATA

This analysis compares the short-term versus long-t erm sales volumes and prices in three regions using reported sales information from Electric Quarterly Re ports (EQR), which are filed electronically on a quarterly basis at FERC by all holders of market-based-rate authorizations (MBRA). EQR data is available to the public on FERC’s website. Howe ver, EQR data include only juri sdictional wholesale physical and booked out sales. The “physical” sale s are power sales by MBRA holders physically delivered during the quarter. “Booked out” sales are power quantities that are sold, then repurchased at a later date, effectively undoing the prior sale. Depending on changes in market prices in the interim, the repurchase may produce profits or limit losses for the seller.

EQR limitations are best explained w ith the help of the diagram below, which is conceptual, not scaled, where the sales reported to EQR represent only a subs et of all market transactions. Retail sales may be reportable to state commissions. Sales by non-jurisdic tional entities may appear in some EIA reports.

# Financial transactions done on NYMEX are reportable to CFTC, but othe r financial transactions do not need to be reported. Sales reportable to EQR could have been transacted bilaterally, on RTO/ISO’s, through ICE or through voice brokers, and credit cleared th rough ICE-LCH or NYMEX-ClearPort. Other transaction venues may develop. There is no complete aggregated market pi cture. Analysts can only try to make inferences from the partial market picture.

Though limited, this comparative analys is is informative. The Task Force selected NYISO, MISO and SERC as representative markets for the following reas ons. NYISO provides a consistent data set for sales in its established, single-state organi zed market. MISO provides a consistent data set for sales in its new, multi-state organized part of the market (sales in Q1 /05 occurred before the organized market started). SERC is an example of a purely bila teral wholesale market with rela tively few participants (which
increases the likelihood of consistent dataset).

The three graphs below show transaction volume s by vintage for each representative region.

# As noted earlier, EQR consists of sa les transactions for power delivered during each quar ter. Short term
transactions are defined as transactions under contracts of one year or less or sale s into organized markets,
such transactions include bilateral sales as well as sales to NYI SO and MISO. Long-term transactions occur under contracts lasting more than a year. For example, a cont ract initiated four years ago and still delivering power would be grouped under the 3 to 5 year vintage. A cont ract initiated 11 years ago would be grouped under the Longer than 10 y ears vintage. While there is a fiel d in the EQR form for termination date, it is often not relevant in this context becau se many contracts are either evergreen, effective until cancelled or master agreements (with no time limits) w ith attachments for term-limited transactions. Major observations on the reported volumes are:

a higher percentage of sales were short term in organized markets (91 percent in NYISO, 77 percent in MISO, 60 percent in SERC); relatively few contracts were older than 10 year s (0 percent in NYISO, 2 percent in MISO, 16 percent in SERC); quarterly variation in quantitie s occurred primarily in sales un der short term contracts.

Organized exchange markets like NYISO and MISO are designed to produce efficien t and reliable daily or real-time spot market prices, with heavy reliance on bilateral financia l and physical transactions to fill longer term needs between parties who would then se ttle these bilateral tran sactions using organized market spot prices as “index pric e.” The high visibility of the s pot markets, along with non-reportable
financial transactions would natura lly lead to a high percentage of short term transactions using EQR numbers in organized markets such as NYISO and MISO. The trend towa rds capacity or reliability pricing products in organized markets (e.g., RP M in PJM) also suggests that th at organized markets may not rely on short term markets alone to give l ong-term price signal for investment.

# APPENDIX F

Some of these sources are older and contain slightly outdated references – but their theoretical arguments remain applicable to current debates.

American Public Power Association, Restructuring at the Crossroads, FERC Electric Policy Reconsidered

, (December 2004), available at http://www.appanet.org/files/PDFs/APPAWh itePaperRestructuringatCrossroads1204.pdf Matthew Brown and Richard P. Sedano, Electricity Transmission, A Primer , National Council on Electricity Policy (June 2004), available at http://www.ncouncil.org/pdfs/primer.pdf

Center for the Study of Energy Markets (CSEM) at the University of Cali fornia Energy Institute (UCEI) at UC Berkeley: http://www.ucei .berkeley.edu/pubs-csemwp.html http://stoft.com/p/S2.html

Paul L. Joskow, Markets for Power in the United States: An Interim Assessment , ENERGY J. (forthcoming 2006), available at http://stoft.com/metaPage/lib/Joskow-2006-power-market-assessment.pdf

Harvard Electricity Policy Group
APPENDIX G

CREDIT RATINGS* OF MAJOR AMERICAN ELECTRIC GENERATION COMPANIES** AS OF JULY 24, 2006

## Name Credit Rating Sales ($bil) Profits ($bil) Assets ($bil) Market Value ($bil)
AES Corp. B+ 10.64 0.56 29.65 11.33
Allegheny Energy Inc BB+ 3.04 0.07 8.56 5.82
Alliant Energy Corp. no rating 3.28 -0.01 7.78 3.87
Ameren Corp. A- 6.78 0.63 18.16 10.33

American Electric Power Co., Inc. BBB 11.9 0.81 36.17 14.36

Atmos Energy Corp. BBB 5.89 0.15 6.62 2.13
CALPINE Corp. D 9.23 -0.24 27.09 0.13
CenterPoint Energy, Inc. BBB- 9.72 0.22 17.12 4.02
Cinergy Corp. BBB 5.41 0.49 17.2 8.75
CMS Energy Corp. B+ 6.41 -0.08 16.02 3.1

Consolidated Edison A 11.69 0.73 24.85 11.26
Constellation Energy BBB+ 17.13 0.63 21.47 10.48

Dominion Resources Inc BBB+ 18.04 1.04 52.58 25.59
DTE Energy Co. BBB 9.02 0.54 23.36 7.7
Duke Energy Corp. BBB 16.75 1.83 54.59 26.3

Edison International BB 11.2 1.24 35.51 14.45
Energy East Corp. BBB 5.3 0.26 11.45 3.7
Entergy-Koch BBB- 10.11 0.92 29.97 15.04
Exelon Corp. BBB+ 15.36 0.97 42.39 38.06
FirstEnergy Corp. BBB- 11.99 0.89 31.84 16.85
FPL Group, Inc. A 11.85 0.89 33 16.56
KeySpan Corp. A- 7.66 0.4 13.81 7.11
Kinder Morgan, Inc. BBB 1.59 0.55 17.38 11.34
MDU Resources Group,

Inc. A- 3.46 0.28 4.42 4.23

Mirant Group B+ 3.7 NA 12.88 7.38

NiSource Inc. BBB 7.89 0.31 17.96 5.6

Northeast Utilities BBB 7.4 -0.25 12.57 3
NRG Energy Inc B 2.36 0.11 7.8 3.76

NStar A- 3.24 0.2 7.65 3.14
OGE Energy A 6.98 0.17 5.72 2.6
Pepco Holdings, Inc. BBB 7.73 0.32 14.22 4.5

Pacific Gas & Electric BBB 11.7 0.92 34.07 13.02
Pinnacle West Capital Corp. BBB- 2.99 0.18 12.07 4.05
PPL Corp. BBB 6.22 0.69 18.04 12.09
Progress Energy Inc BBB- 10.11 0.7 27.07 11.14
Public Service Enterprise Group, Inc. BBB 12.43 0.68 29.82 17.43

Reliant Energy B 9.73 -0.35 13.54 3.07
SCANA Corp. A- 4.78 0.33 9.32 4.65
Sempra Energy A 11.74 0.92 29.21 12.29

Sierra Pacific Resources B+ 2.96 0.09 8.12 2.61

Southern Co. A 13.55 1.59 39.88 25.24
TECO Energy, Inc. BB+ 3.01 0.27 7.17 3.55
TXU Corp. BBB- 10.44 1.78 24.91 25.17
Williams Companies, Inc. BB+ 12.58 0.32 33.66 12.36
Wisconsin Energy Corp. A- 3.82 0.31 10.46 4.78
Wisconsin Public Service no rating 6.96 0.16 5.45 1.99

## Resources
Xcel Energy Inc. BBB 9.63 0.51 21.65 7.49
*credit rating is the "Long Term Issuer Default Rating" from Fitch Ratings (www.fitchratings.com)

**list drawn from United States-based generation companies on Forbes list of the top 2000 global firms (http://www.forbes.com/2006/03/29/06f2k_worlds- largest-public-companies_land.html)