# 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 En ergy Regulatory Commission John H. Seesel, Federal Trade Commission David Meyer, Department of Energy Karen Larsen, Department of Agriculture

Report Contributors :

Robin Allen – Department of Justice
Kathleen Barrón – Federal Energy Regulatory Commission Tracey Chambers – Department of Justice
Lee-Ken Choo – Federal En ergy 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 Energy Regulatory Commission Steven Reich – Federal Energy Regulatory Commission Janelle Schmidt – Department of Energy Harry Singh – Federal En ergy Regulatory Commission
Michael Wroblewski – Federal Trade Co mmission (left the FTC in June 2006) David Zlotlow – Department of Justice

This report was prepared by the Task Force with the assistance of the Department of Justice, Federal Energy Regulatory Commission, Fede ral Trade Commission, Department of Energy, and Department of Agriculture. The Task Force assumes full responsibil ity 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 Wholes ale 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 Bibliograp hy 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 Primar y Information on Electric Competition .........................182 Appendix G. Credit Ratings of Major Am erican 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 Ge neration Capacity, 2004 ................................................................ 16
Table 1-6. Power Generation Asset Divestitures by Invest or-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 Restructuring Activity and Retail Competition, July 2006 ......................................................................................... 28 Figure 1-3. RTO Configurations in 2006 ................................................................................. 32 Figure 1-4. Utility and Nonutility Gene ration Capacity Additions, 1995-2004....................... 35 Figure 1-5. Transmission Construction Expe nditures by Investor-Owned Utilities, Actual and Projected, 1975-2009........................................................................... 36 Figure 1-6. National Average Reta il Prices of Electricity fo r Residential Customers,
1960-2005 ............................................................................................................. 38 Figure 1-7. Natural Gas Plants Domina te New Generating Unit Additions ............................ 39 Figure 1-8. Net Generation Sh ares by Energy Source ............................................................. 40 Figure 1-9. Fossil Fuel Costs for Electric Generators, 2001-2006 .......................................... 41

iFigure 3-1. U.S. Electric Generating Capacity Additions, 1960-2005 .................................... 60 Figure 3-2. Estimate of Annual New York Capacity Values .................................................. 65 Figure 4-1. U.S. Electric Power Industry, Average Retail Price of Electricity by State, 1995............................................................................... 87 Figure 4-2. States Retail Co mpetition Status, 2003 ................................................................. 91 Figure 4-3. Average Revenues per kW h for Retail Customers, 1990-2005 ............................ 95

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

iiEXECUTIVE SUMMARY

A. Congressional Request

The Energy Policy Act of 2005 (EPAct 2005) 1 was designed to provide a comprehensive longrange energy plan for the United States. Section 1815 of the Act 2 created an “Electric Energy Market Competition Task Force” 3 (Task Force) to conduct a st udy of competition 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 for public co mment at least 60 days prior to submitting the final report to Congress. The Task Force publis hed the draft final report in June 2006 and sought comment on the preliminary observations contained in the draft. Based on those comments, and other input received earlier, the Task Force hereby submits this final report to Congress.

B. Task Force Activities

In preparing this report, the Task For ce undertook several activities, as follows:

 Section 1815(c) of the EPAct 2005 required th e Task Force to “cons ult with and solicit comments 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 Register notice seeking comment on a variety of issues related to competition in
wholesale and retail electric power markets. Over 80 commenters provided a variety of opinions and analyses in response. Thes e comments are available online for public
review in the Task Force docket main tained by the Federal Energy Regulatory Commission (FERC) under Docket No. AD05-17 -000. The list of parties who submitted comments is attached as Appendix A. 4

 The Task Force met and discussed compe tition-related issues with a variety of representatives of the states , the electric power industry, and other stakeholders in October-December 2005. These groups are listed in Appendix B.

 The Task Force prepared an annotated biblio graphy of the public cos t/benefit studies that have attempted to analyze the status of wholesale and retail co mpetition. Appendix C contains this bibliography.

 The Task Force reviewed the status of retail competition in the states and examined in detail the experiences of seven states with active retail competition programs: Illinois, Maryland, Massachusetts, New Jersey, New Yo rk, Pennsylvania, and Texas. These

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 Commissi on, 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, ap pointed by the Secretary of Energy; and (5) one empl oyee of the Rural Utilities Service, appoi nted by the Secret ary of Agriculture.

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

1states have taken a variety of approaches to introducing retail competition. Appendix D profiles these retail competition programs, updating information prepared by the Federal Trade Commission (FTC) staff.

 The Task Force published the draft final re port 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 entities provided comments and suggestions on the draft report. These commen ters are listed in Appendix A. Draft report comments are ava ilable for public review online in the Task Force docket maintained by FERC under Docket No. AD05-17-000.

 In preparing the draft report, the Task Force conducted further resear ch and reviewed the
information from comments and interviews.

C. The Goal of Increasing Compet ition in Electric Power Markets

Federal and several state policymakers generall y introduced competition in the electric power industry to overcome perceived shortcomings of traditional cost-based regulation. In competitive markets, prices are expected to guide consumption and investment decisions, leading to more economically efficient investments and lower prices than under traditional cost of service monopoly regulation. More specifically, market-based, as compared to regulated, pricing of electricity would be expected to more accura tely reflect the underlying costs of production. These prices should thus ali gn the price of electricity wi th the value customers place on electricity, leading to a more e fficient allocation of electrical resources and lower overall prices
than would be the case in the absence of market -based prices. These price signals should also serve to increase price during periods of scarci ty, thereby eliciting reductions in consumption, moderating market power and improving reliability.

D. Observations on Competition in Wholesale Electric Power Markets

Congress has taken a number of steps to faci litate competition in wholesale electric power markets. The Public Utility Re gulatory 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 transmission access. Federal electr icity policies have sought to strengthen competition but continue to rely on a combination of competition and regulation.

In assessing wholesale competition, the Task Force addressed the following question: Has competition in wholesale markets for electricit y resulted in sufficient generation supply and transmission to provide wholesal e customers with the kind of choi ce that generally is associated with competitive markets?

To answer this question, the Task Force examined whether competition has elicited the consumption and investment decisions generally a ssociated with competitive wholesale markets.

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

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

2The Task Force found this question challenging to address due to a number of complicating factors. The various U.S. regional wholesale el ectric power markets deve loped differently since the introduction of widespread wholesale co mpetition. There were significant regional regulatory and structural differe nces in the electric power in dustry when Congress enacted EPAct 1992 and when FERC adopted Order No. 888 7 in 1996, mandating nondiscriminatory access to the transmission grid. Even today, th e regional markets have different features and characteristics. As discussed in Chapter 3, th ese differences make it difficult to identify and separate the determinants driv ing consumption and investment decisions and thus make it
difficult for the Task Force to evaluate the de gree to which more competitive markets have
influenced such decisions.

Despite the difficulty of directly answering the question at hand, th e Task Force’s examination of wholesale competition did yield useful observations, as outlined below.

1. Wholesale Market Structures

Wholesale markets exhibit regional differences a nd generally rely on one of two types of market structures to support wh olesale transactions.

a . One approach to competition in wholesale markets is to base trades exclusively on bilateral sales negotiate d directly between suppliers and scheduled through individual, nonregionalized transmission owners. This approach predominates in the Northwest and Southeast. This traditional trading format allows for somewhat independent operation of transmission control areas and, in the view of some market participants, better accommodates historical contracts. However, prices and terms are more transaction-specific and, for some timeframes, less publicly availabl e than in organized markets, which ma y result in less efficient generation dispatch. It can be difficult for system operators to coordinate transmission efficiently in these systems, as congestion costs and impacts are not r eadily 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 mark ets, wholesale customers have difficulty gaining unqualified access to the transmission needed to access competitively 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 tr ansmission facilities across a wide region and to operate trading markets – regiona l transmission organizations (R TOs) or independent system operators (ISOs). Variations of this approach predominate in the Northeast, Mid-Atlantic, Midwest, Texas, and California. The market desi gns in these regions prov ide participants with guaranteed physical access to the transmission system (subject to transmission security constraints). These customers are responsible fo r the cost of that access (if they choose to

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. Transmission Access Policy Study Group v. FERC , 225 F. 3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC , 535 U.S. 1 (2002) [hereinafter Order No. 888].

3participate), and thus are exposed to conges tion price risks. This more open access to transmission can increase competitive options for wholesale customers and suppliers as compared to most bilateral markets. The price transparency in these regional organized markets can increase the efficiency of the trading proce ss for sellers and buyers and can give clear price signals indicating the best place and time to build new generation. Concerns have been raised, however, about the inability to obtain long-term tr ansmission access at predictable prices in these markets and the impact that this can have on acc ess to competing suppliers and incentives to construct new generation. Some customers have raised concerns about high and sometimes volatile commodity price levels in these markets.

2. Generation Investment in Co mpetitive Wholesale Markets

New generation investment has varied significantly by region si nce the adoption of open access transmission and the growth of competiti on. The Task Force examined comments on how competition policy choices have affected invest ment decisions of both buyers and sellers in wholesale markets. A number of issues emerge d. One was the difficulty of raising capital to
build facilities whose revenue streams are affect ed 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 long-term cont racting options for generation and transmission. Overall, the Task Force identified several factors that affect investment decisions in wholesale power markets.

a. Availability of Long-Term Contracts. Both generators and wholesale customers cited long-term contracts as critical in obtaining financing for new ge neration and ensuring adequate supplies for retail loads at predictable prices. Se veral explanations were offered for a perceived lack of long-term contracting opportunities. First, short-term market conditions, particularly in organized markets with uniform price auctions, may be affecti ng the availability, pricing, and terms for long-term power supplies under bilate ral contracts. Base-load and mid-merit generators may see relatively high profits in shor t-term markets where clearing prices are often set by higher cost mid-merit and/or peaking plants reliant on oil or natural gas, particularly when fuel prices rise. Second, generators and mark eters may be unwilling to enter into long-term supply contracts because of limited opportunities to hedge the poten tial risks of long-term commitments in highly volatile electricity market s. Third, both generators and customers cited continuing uncertainties over availability a nd certainty of long-term delivery options (transmission). Fourth, long-term contracts may be difficult to arrange because of inherent
uncertainties associated with federal a nd state regulation of these contracts. Finally, the uncertainty that distribution utilities face over ho w much supply they will need to procure for customers that have an option to switch can also discourage utilitie s from signing long-term

contracts.

b. Capital Investment. Potential entrants to generation markets must be able to convince capital markets that generation is a viable profit able undertaking. The ava ilability of long-term contracts, as noted above, is critical to the ab ility of nonutility generato rs to secure capital for
new investment. Transmission access can be vita l to supporting competitive options for market participants. Recently, capital for large investme nt projects has flowed to traditional utilities

4more than to merchant generators. This shift in part reflects reduced profitability of many 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, th us, elicit investment. Despite legislative and regulatory efforts to expand tran smission access for competitive generation and to reduce the potential for discrimination, the perc eption of discrimination persists. Commenters reported that such discrimination can increase delivery risk because purchasers fear their
transmission transactions could be terminated fo r anticompetitive reasons. One response to this risk is to turn over operation of the regional transmission grid to ISOs and RTOs. Another is to adopt additional reforms to the Order 888 Op en Access Transmission Tariff (OATT). New federal authorities provided by EPAct 2005 also address transmi ssion infrastructure issues.

3. Pricing and Entry in Wholesale Markets for Electricity

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

a. One possible, but controversial, way to spur entry is to allo w wholesale price spikes when supply is short. The profits realized during these price spikes can provide incentives for generators to invest in new cap acity. However, if wholesale customers have not hedged (or cannot hedge) against price spikes, then these sp ikes 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 pr ice spikes have caused regulators and various wholesale market operators to adopt price caps in certain mark ets. Although price caps may limit price spikes and some forms of market manipul ation, they can also lim it legitimate 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 appropriate levels.

b. “Capacity payments” also can help elicit ne w supply and help modera te price volatility. Wholesale customers pay suppliers to assure the availability of generation when needed. Where there are capacity payments in organized w holesale markets, however, it is difficult for regulators to determine the appropr iate level of capacity payments to spur entry without overtaxing market participants and customers. Al so, capacity payments may elicit new generation when transmission or other responses to price changes might be more affordable and equally effective. Depending on their format, capacity payments also may discourage entry by paying uneconomical generation to continue running when market conditions otherwise would have led to not running, or even decommissioning.

c. Expanding transmission capacity may encourage entry of new generation and/or the more efficient use of existing gene ration. However, 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 cha llenge is that it is often difficult to assess the beneficiaries of transmission upgrades, who s hould pay for the upgrades, and how regulators should provide for recovery of the investment through rates. This re gulatory challenge may cause uncertainty about the price for transmissi on and about return on investment both for new generators and for transmission providers.

5d. Another option for ensuring adequate gene ration supply is to exercise traditional regulatory authority over electric ity generators/suppliers. In this situation, regulated monopoly utility providers operate under an obligation to plan and secure adequate generation to meet the needs of their customers. Regulators allow the ut ilities 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 l ead to overinvestment, unde rinvestment, excessive spending and unnecessarily high costs. Thes e methods can distort both investment and consumption decisions.

E. Observations on Retail Market Competition

In the early 1990s, several states with high elec tricity prices began e xploring opening retail electric service to competition. While cust omers would choose their supplier, the local distribution utility would still ha ndle the delivery of electricity. Retail competition was expected to result in lower retail prices, innovative services and pricing opti ons. It also was expected to shift the risks of assuring adequate new generation construction from ratepayers to competitive market providers. By 2006, 16 states and the Distri ct of Columbia had rest ructured 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 require d the local utility to continue to offer service under regulated “provider of last resort” (POLR) rates for all retail customers who did not switch suppliers or who lost or discontinued competitive service. These POLR rates were typically fixed for extended periods of time. In many of these states , vertically integrated utilities divested or transferred their generation assets as part of restructuring plans. As a result, in these states the retail load serving utilities obtai n electricity from wholesale mark ets to meet the needs of their retail customers, including POLR ob ligations. Some states also re quired that the utilities join
RTOs.

1. Retail Competition Experience in Profiled States

The Task Force examined in detail the implem entation of retail competition in Illinois, Maryland, Massachusetts, New Jers ey, New York, Pennsylvania, a nd Texas. Common goals for retail competition included:

 lower electricity prices than under traditional cost of service regulation through retail suppliers’ (and eligible customers’) acce ss 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 expected for all customer classes.
Few residential customers have switched to alternative providers. (Exceptions include Massachusetts, New York, and Texas.) In most of the profiled states, few residential customers

6have a wide variety of alternative suppliers and pricing options. Co mmercial and industrial (C&I) customers have more choices and options, but in several st ates large industrial customers have become increasingly dissatisfied with retail market prices. To the extent that multiple suppliers serve 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 suppliers have offered new retail products, including “green” products that are more environmenta lly friendly for residential and
non-residential customers 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 profiled states, regulat ors often capped the POLR electricity price for “transitional” multi-year periods that are now ju st ending. Several states also required price reductions for POLR service below existing regulated rates (in order to proxy the expected benefits of competition). Over time, these capped and discounted POLR prices fell below prevailing wholesale market price levels. These POLR price caps have th e unintended effect of dampening competitive price signals and di scouraging entry by competitive suppliers.

The POLR rate caps and the sharp increase in foss il fuel costs affecting all retail suppliers across the country, complicate Task Force efforts to discern any price di fferences attributable to the introduction of competition. The implementation of retail competition is a relatively new exercise, and retail competition policies invol ve a number of unresol ved issues (including regulatory issues) that can inhibi t vigorous competition. It sh ould be easier to evaluate the impact of restructuring in retail electricity markets 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 2007. When the ra te caps expire, states mu st decide whether to continue POLR for all customer classes, how POLR providers will secure adequate generation supplies, and how to price POLR service for each cla ss. The Task Force 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 servi ce price does not closely match the competitive price, it is likely to distort cons umption and investment decisions.

b. Adjustments to POLR Rates . If POLR prices remain fi xed while prices for fuel and wholesale power are rising, customers may experi ence rate shock when the transition period ends. This can create public pressure to conti nue the fixed POLR rates at below-market levels. One regulatory response may be to phase in the price increase gradually, by deferring recovery of part of the supplier’s costs. This approach reduces rate shock, but it is likely to distort retail electricity markets both in the short term (whe n costs are deferred) and in the long term (when

7the deferred costs are recovered). The better practice is to make frequent adjustments to the cap (at least to reflect changes 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 po licy 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) that is limited to an obligation to serve customers of a supplier that has left the market, while the customer obtains another supplier, is the least intrus ive form of POLR service. It al so is consistent with protecting consumers against unanticipated loss of electric service. POLR servi ce that goes beyond shortterm access to the wholesale spot market involve s providing a bundle of services that electricity marketers also could provide. A more expa nsive version of POLR service may hamper development of alternative suppliers. The econo mic 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 peri odically review the ratio nale for continuing the
service.

d. Treatment of Different Customer Classes . States may find th at effective retail competition programs require different POLR servi ce 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 comfor table with decisions to adjust input use based on input prices. State policies have allowed PO LR rates for these large customers to reflect wholesale spot market prices more than POLR ra tes for residential customers. This approach generally has led large customers to switch suppl iers more than small customers have. Also, more suppliers have tried to so licit these large customers.

e. Consumer Education . Customers may find it difficult to find competitive 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. Fo r these smaller, less sophisticated shoppers, issues of awareness and access to comparative pric ing information should be addressed as retail customer choice is implemented.

f. Customer Aggregation . Competitive provider interest in residential and small business customers has been slow to develop in most st ates. While POLR policies have dampened price signals, the higher per-unit costs of marketing and switching for small customers may also be a disincentive for providers. Retail aggregat ion programs can reduce shopping burdens and
uncertainties for individual customers and lo wer customer acquisition costs for competitive providers. Several states have approved customer aggregation plans as an alternative approach to developing retail competition. Opt-out cust omer aggregations may be worth considering because they can minimize transaction costs without limiting customer choice.

8g. Procurement of POLR Supply . In all retail competition states, a substantial number of retail customers continue to depend on POLR serv ice. Some states have used, or are proposing to use, auctions to procure POLR supply. Aucti ons may allow retail customers to get the benefit of competition in wholesale markets as suppliers compete to supply the necessary load. Various auction processes have been suggested.

h. Switching Costs . Switching is important for retail el ectricity competition to work. Rules and procedures for switching should allow cu stomers to switch easily but should deter unauthorized switching (slamming).

Section E of Chapter 4 presents a description of various approaches to overcoming some of the above-mentioned difficulties and to encouraging competition in retail electricity markets.

9CHAPTER 1 INDUSTRY STRUCTURE, LEG AL AND REGULATORY BACKGROUND, TRENDS AND DEVELOPMENTS

For almost all of the 20th Century, the electr ic power industry was dominated by regulated monopoly utilities. Beginning in the late 1960s, a number of technological, economic, regulatory, and political developm ents led to fundamental cha nges in the structure of the industry.

In the 1970s, vertically integrated utility compan ies (investor-owned, municipal, or cooperative) controlled over 95 percent of the electric gene ration in the United States. Typically, a single local utility sold and delivere d electricity to retail custom ers under an exclusive franchise regulated under state law. T oday, the electric power industry includes both utility and nonutility entities, including many new companies that prod uce, market and deliver electric energy in
wholesale and retail markets. As a result of industry changes, by 2004 electric utilities owned less than 60 percent of electric generating capacity. Increasing ly, decisions affecting retail customers and electricity rates ar e split among federal, state, and ne w private, regional entities. This chapter highlights structural changes in the industry since the late 1960s. It provides an overview of the important legislative and regulat ory changes, as well as trends that have contributed to increased competition.

A. Industry Structure and Regulation

Participants in the electric power sector in the United States include investor-owned utilities and electric cooperatives; federal, state, and municipa l utilities, public utility districts and irrigation districts; cogenerators and ons ite generators; and nonu tility independent power producers (IPPs), affiliated power producers, power marketers, and independent transmission companies that generate, distribute, transmit, or sell electricity at whol esale or retail.

In 2004, 3,276 regulated retail electric provide rs supplied electricity to over 136 million customers, with retail sales to taling almost $270 billion. Retail customers purchased more than 3.5 billion megawatt hours (MWhs) of electricity. Active reta il electric providers include utilities, federal agencies, and power marketers selling directly to re tail customers. These entities differ greatly in size, ownershi p, regulation, customer load ch aracteristics, and regional conditions. These differences are reflected in pol icy and regulation. Tables 1-1 to 1-5 provide selected statistics for the electric power s ector by type of ownership in 2004 based on information reported to the Department of En ergy (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 cu stomers. Most IOUs are or are part of a vertically integrated system th at owns or controls generati on, transmission, and distribution

10facilities/resources to meet the needs of retail customers in their franch ise service areas. Many IOUs have undergone significant restructuring and reorganizati on under state retail competition plans over the past decade. As a result, many I OUs 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 major presence. In 2004 ther e were 220 IOUs serving approximately 94 million retail distribution customers, accounting for 68.9 percent of all retail cu stomers and 60.8 percent of retail electricity sales. IOUs directly owned about 39.6 per cent of total elec tric generating capacity and accounted for 44.8 percent of genera tion for retail and wholesale sales in 2004. IOUs provide service to retail customers unde r state regulation of territories, finances, operations, services, and rates. States that have not restructured retail service generally regulate
retail rates under tr aditional bundled cost-of- service rate methods. In states that have restructured IOUs, distribution services continue to be prov ided under monopoly cost-of-service rates, and retail customers obtai n generation service either at market rates from alternative competitive providers or at regulated “provider of last resort” (POLR) rates from the distribution utility or another designated PO LR service provider. IOUs serve retail customers in every state
but Nebraska.

Under the Federal Power Act (FPA), 8 the Federal Energy Regul atory Commission (FERC) regulates wholesale electricity transactions (sales for resale) and unbundled transmission activities of IOUs as “public utilities” engaged in interstate commerce. The exceptions are IOUs
that do not have direct in terconnections 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 generally 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 systems. These providers range from tiny municipal distribution companies to large systems such as the Los Angeles Department of Water and Power. Publicly owned systems operate in every state but Hawaii. About 1,840 of these systems are cities and municipal governments that own and contro l the day-to-day operation of their electric utilities. 9 Public power systems served over 19.6 million retail customers in 2004, or about 14.4 percent of all customers. Together, they generated 10.3 percen t of the nation’s power in 2004, accounted for 16.7 percent of total electricity sales and owned about 9.6 percent of total generating capacity. Many public systems are distribution-only utilities that purchase, rather than generate, power. According to the American Public Power Associ ation, about 70 percent of public power retail sales were met from wholesale power purchases, including purchases 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 load. 10 Publicly owned utilities, thus, depend overwhe lmingly on transmission and the wholesale market to bring electricity to their retail customers.

8 16 U.S.C. §§ 791a et seq. (2000).

9 APPA comments.

10 Id.

11Regulation of public power system s 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 systems are regulated by local governments or are self-regulated. Municipal systems usually are governed by a local city council or an independent board elected by voters or appointed by city o fficials. Other public power syst ems are operated by public utility districts, irrigation districts, or special state authorities.

On the whole, state retail restructuring initiatives di d not affect retail servi ces in public systems. However, some states allow public systems to adopt retail choice al ternatives voluntarily.

3. Electric Cooperatives

Electric cooperatives are priv ately-owned, non-profit electric sy stems owned and controlled by the members they serve. Members vote directly for the board of directors. In 2004, 884 electric distribution cooperatives provided retail electric service to almost 16.6 million customers. In addition, another 65 generation and transmi ssion cooperatives (G&Ts) own and operate generation and transmission and secure wholesale power and transmission services from others
to meet the needs of their di stribution coopera tive members’ retail customers and other rural native load customers. G&T systems and thei r members engage in joint planning and power supply operations to achieve some of the savings available under a vertica lly integrated utility structure. Electric cooperatives operate in 47 states. Most were originally organized and financed under the federal rural electrification program and oper ate in primarily rural areas. Cooperatives provide electric serv ice in all or parts of 83 percent of the counties in the United
States. 11

In 2004, electric cooperatives sold more than 345 million MWhs, served 12.2 percent of retail customers, and accounted for 9.7 percent of electr icity sold at retail. Nationwide electric cooperatives generate about 4.7 percent of total electric gene ration and own approximately 4.2 percent of generating capacity.

While some cooperative systems generate their own power and sell power in excess of their members’ needs, most G&Ts and distributi on cooperatives are net buyers. Cooperatives nationwide generated only about half of the power needed by th eir retail customers. They secured approximately half of their power n eeds from other wholesale suppliers in 2004. Although cooperatives own and operate transmission f acilities, almost all rely to some extent on transmission owned by others to de liver power to their customers.

Regulatory jurisdiction over coopera tives varies among stat es. Some states exercise considerable authority over rates and operations , while others exempt cooperati ves from state regulation. In addition to state regulation, cooperatives with outstanding loans under the Rural Electrification
Act of 1936 12 are subject to financial a nd operating requirements of the Rural Utilities Service (RUS), Department of Agriculture. RUS must approve borrowers’ long-term wholesale power

11 NRECA comments.

12 7 U.S.C. 901 et seq.

12contracts, operating agreements, a nd transfers of assets. Cooperativ es that have repaid their RUS loans and that engage in wholes ale 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 servi ces provided by larger electric cooperatives.

4. Federal Power Systems

Federally-owned or chartered power syst ems include the federal power marketing administrations (PMAs), the Tennessee Valley Authority (TVA), and facilities operated by the U.S. Army Corps of Engineers, the Bureau of R eclamation, the Bureau of Indian Affairs, and the International Water and Boundary Commission. Wholesale power from federal facilities (primarily hydroelectric dams) is marketed th rough four federal power marketing agencies: Bonneville Power Administration, Western Area Power Administration, Southeastern Power Administration, and Southwestern Power Ad ministration. The PMAs own and control transmission to deliver power to wholesale and di rect service customers. They also may purchase power from others to meet contractual need s and may sell surplus power as available to wholesale markets. Existing legislation require s that the PMAs and TVA give preference in selling their generation to public power syst ems and to rural electric cooperatives.

Together, federal systems have an installed generating capacity of approximately 71.4 gigawatts (GW) or about 6.9 percent of total capacity. Fe deral systems provided 7.2 percent of the nation’s power generation in 2004. Although most federal pow er sales are at the wholesale level, some are made to end users. Federal systems nati onwide directly served 39,845 retail customers in 2004, mostly industrial customers and about 1.2 percent of retail load.

5. Nonutilities

Nonutilities are entities that genera te, transmit, or sell electric pow er but do not operate regulated
retail distribution franchises. 13 They include wholesale nonutility affiliates of regul ated utilities, merchant generators, and qualifying facilities (QFs). 14 They also include power marketers that buy and sell power at wholesal e or retail but that do not own generation, transmission, or distribution facilities. Indepe ndent transmission companies that own and operate transmission facilities but do not own generation or retail dist ribution facilities or sell electricity to retail
customers are also included in this category for EIA reporting purposes.

Non-QF wholesale generators engaged in wholes ale power sales in interstate commerce are subject to FERC regulation under the FPA. Powe r marketers selling at wholesale are also subject to FERC oversight. Power marketers selling only at retail are subject to state jurisdiction and oversight in states where th ey operate. FERC regulates inters tate transmission services of independent transmission companies under the FPA. Such companies also may be organized and regulated as utilities where they are located for planning, siting, permitting, and other purposes.

13 “Nonutilities” – as that term is defined 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 industrial and commercial cogene rators (combined heat and power producers) th at have special status under PURPA.

13As retail electric providers, 152 power market ers reporting to EIA served about 6 million retail customers or about 4.4 percent of all retail customers and reporte d 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 per cent of all electric generation capacity, compared to about 8 percent in 1993. About ha lf of nonutility generatio n capacity is owned by nonutility affiliates or subsidiaries of holding co mpanies that also own a regulated electric utility. 15 Nonutilities accounted for about 33 percent of generati on in 2004. 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-service customers of retail electric providers (REPs), w hich are classified by the Energy Information Admini stration as power marketers. The REPs bill cust omers for full-service a nd then pay the IOU for the delivery portion. REPs include the regulated distribution utility’s succe ssor affiliated retail electric provider that assumed service for all retail customers that did not select an alternative provid er. 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.

15 EEI comments.

14Table 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 utilities represents revenue fr om energy procured for California’s investor-owned utilities by th e California Department of Water Resources Electric Fund. Ninety-eight percent of power
marketers’ full-service sales and revenues occur in Texas. I OUs in the ERCOT region of Texa s no longer report 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

15Table 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 EIA-906/920 for genera tion. Data are for 2004, 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 fo r joint ownership. Data are for 2004.

B. Growth of the Electric Power Industry

For a variety of legal, economic, and technological reasons, the electric utility industry in the United States developed as a collection of se parate, mostly vertically-integrated monopoly franchises with wholesale and retail prices a nd services extensively regulated under state and federal law. Many states have elected to maintain this model. The legacy of this verticallyintegrated monopoly structure creates substantia l challenges for state and federal efforts to

16restructure the industry and to create new institutional arrangem ents to facilitate increased reliance on competitive market prices. This section provides a brief overview of the evolutionary changes in th e electric power industry.

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

In the late 19 th Century, electric utilities developed as small central station power plants with
limited local distribution networks. Franchise ri ghts granted by manufactur ers and by municipal governments allowed use of public streets and ri ghts of ways. These franchises were often exclusive, 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 altern atives – natural gas lighti ng or self-generation in the case of street railway, comme rcial, and industrial customers. 17 Many municipalities elected to create and operate their own electric utility systems.

Certain characteristics of providi ng electric service were recogni zed early on. Utility systems incurred high fixed costs for investments in gene rating plants needed to meet peak load and to extend the delivery system. Because they had re latively low operating costs, their profits were determined by the percent of time the power plant was in use. Complementary load diversity – such as balancing daytime traction and electric motor loads with evenin g lighting loads – could raise generating plant use and revenues to offset fixed costs and boost profits. The high capital costs of electric generating plants made inve stments risky. Steady gains in generation, transmission, and distribution economies of s cale provided incentives to expand the electric networks. Larger plants produced cheaper electr icity than many smaller plants. The substantial investment required for electric utility plants also spurred cr eation of long-term financing structures and the corresponding inte rest in providing assurances to investors that the entity would be profitable and would remain financiall y viable long enough to repay the debt.

These characteristics led some to suggest th at a single monopoly pr ovider of integrated generation, transmission and distribution service could provide electric service most economically and safely. To avoid abuses of this monopoly power, it was suggested that impartial state agencies should be created to aw ard franchises and esta blish rates and service standards. An early associate of Thomas Edison, Samuel Insull of Chicago Edison was among them and proposed state regulation of private util ities in a speech befo re the National Electric Light Association in 1898. 18 Insull characterized electri city production as a “natural monopoly.” 19 Initially, the proposal for state regula tion was poorly received, but as private

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 differ ent electric franchises between 1882 and 1905; three 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/el ectricity/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 costs where a single provider can supply produc t 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 t he electric utility industry. Economists have debated whether the electric utility industry or segments of it are natural monopolies for several d ecades. This debate

17electric companies began to grow and consolidate and concerns we re raised over trusts in many industries, the concept began to gain support. In 1907, Wisconsin adopted legislation regulating electric utilities and was quickly joined by two other states. By 1916, 33 states had established state agencies to oversee private electric utilities. 20

Generally, under this approach, the state regulatory commission gr anted exclusive retail electric franchises to private companies within speci fied territories, protecting the utility from competition. In return, the utility assumed an obligation to provide safe and adequate service to all retail customers within its territory under ju st and reasonable rates, terms and conditions overseen by the state. Often the utility was aut horized to use public ri ghts of way and eminent
domain for electric facilities. To meet this ob ligation to serve, most private utilities built and controlled the generation, transmi ssion, and distribution facilities needed to provide service to customers. Rates were set to cover the companies' reasonable costs plus a fair return on shareholders’ investment. The utility could e xpect a right to reasona ble compensation for its services, although a specific rate of return was no t guaranteed. Retail rates (price) were based on the average historical system cost of producti on (including the investor s’ fair return on investment).

In the early 20 th Century, private electric utilities con tinued to expand under this system of state regulation. Most continued to build their own generation plan ts and transmission systems, primarily due to the cost and technological lim itations of transmitting electricity over distances. 21 Initially, there was little whol esale trade among utilities. As the industry grew, continued improvements in technology allowed expansion beyond central cities, and pr ices for electricity fell at the same time that demand increased substantially.

Over the same period, electric utility holding comp anies were created and began to acquire local private and municipal utilities. While a holdi ng company’s local utility operating companies were regulated by the state, the holding company and its other affiliates and subsidiaries were not, and often did business in several states. The proliferation, consolidat ion, and complexity of such companies coincided with a number of financial and securities abuses that were documented in an investigation by the Fede ral Trade Commission (FTC). These holding companies often became the sole providers of va rious services and products to their affiliated utilities, and their sometimes inflated costs we re passed through to the retail customers. By 1932, the eight largest util ity holding companies controlled 73 percent of the investor-owned electric industry. 22

This pattern of consolidated ownership and hol ding company abuses led to calls for federal involvement in the electric power industry. As a result of the FTC fi ndings, Congress passed the Public Utility Holding Co mpany Act of 1935 (PUHCA 1935), 23 which required the breakup and

focuses on the economic theory rationalization for regulation and not the public policy or legal basis for electric power regul ation. See, e.g.

, Vernon Smith, Regulatory Reform in the Electric Power Industry (1995) (working paper, on file with th e Department of Economics, 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).

18stringent federal oversight of the large utility holding companies. The FPA expanded the Federal Power Commission’s authority to include oversight and regulation of in terstate sales of wholesale power (e.g., sales of power between utility systems) and interstate electricity transmission at wholesale by “publ ic utilities” (i.e., investor-own ed utilities). FPA jurisdiction
over interstate sales cl osed a gap in electric industry regu lation that the Su preme Court had
identified in 1927. 24

When the FPA was enacted, wholesale and interstate sales of electricity were limited. Most wholesale transactions were long- term power supply contracts by investor-owned utilities to sell and deliver power to neighboring pu blic power and cooperative uti lities. Over time, utilities became more interconnected via high-voltage tran smission networks. Constructed primarily for reliability, these networks also facilitated more opport unities for inte rstate trade. However, wholesale trade was slow to develop.

Until the late 1960s, the vertically integrated monopoly utility model appeared to work reasonably well. Utilities were able to meet increasing demand for electricity at decreasing prices as advances in genera tion technology and transmission pr ovided increased economies of scale with larger units and decreased costs. 25

2. The Energy Crisis of the 1970s, PURPA, a nd the Expansion of Nonutility Generation
and Wholesale Power Markets

The shift toward a more competitive marketplace for electricity was precipitated by industry changes that began in the late 1960s and accele rated throughout the 1970s. Resulting financial stresses challenged the continued pr ofitability of the large vertical ly integrated utility model. They also provoked criticisms of the traditional cost-of-service regulatory model that allowed the pass-through of higher costs and risk s of construction to consumers.

By the end of the 1960s, electricity demand and generation were increasing at an annual rate of 7.5 percent, and residential rate s were declining at an aver age annual rate of 1.5 percent. 26 At the same time, the new large nuclear and co al plants built in th e 1970s did not yield the dramatic improvements in economies of scale that earlier technological a dvances in generating plant size had produced. The industry’s characteriz ation as a long-term d ecreasing cost industry came into question. Periods of rapid inflation and higher interest rates subs tantially increased the completion costs of large, ba se load generating plants. 27 New environmental and safety regulations required addition of pollution controls and design feat ures that added to costs and construction time. Moreover, once in operation, many of the new, larger units required more maintenance and longer downtimes than expecte d. Thus, by the late 1970s, a newer, larger, generation facility no longer coul d be assumed to be more cost-efficient than a smaller plant. 28

24 In Public Utilities Commission of Rhode Is land v. Attleboro Steam & Electric Co ., 273 U.S. 83 (1927), the Supreme Court ruled that state regulators were barred by the Commerce Clause from setti ng the prices 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.

19This experience stimulated interest in smaller, modular, more energy-efficient generating units. One expression of this interest resulted in commercialization of aeroderivative gas turbine technology. This technology allowed smaller genera tion units to be constructed at lower costs, more quickly, and at less financial risk th an large base-load coal and nuclear plants. 29 Thus, construction of low-cost generation became an opti on 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 util ities’ generation construction pr ograms were playing out, utility fuel prices were escalating rapidly in response to the Arab oil embargo of 1973-1974 and subsequent world oil market disruptions. Signi ficantly higher energy prices added to inflation
and increased electric rates. 30 Other developments also substa ntially contributed to the growing interest in electric utility refo rms. First, the 1965 Northeast po wer blackout raised concerns about the reliability of weakly coordinate d bulk power system operating arrangements among
utilities. 31 The nuclear accident at the Three Mi le Island plant in Pennsylvania on March 28, 1979, heightened concerns over safety and led to stringent new regul atory requirements for nuclear plants.

Criticism of the traditional cost-of-service utility regulation model by economists and policy analysts also increased during th e 1970s with suggestions for alte rnate approaches to regulation and changes in industry structure. Critics of cost-based regulation argued that the industry structure limited opportunities for more efficient suppliers to expand, place d insufficient pressure on less efficient suppliers to improve performance, and insulated customers from the cost impacts of energy use. 32

Congress enacted the Public Ut ility Regulatory Policies Act (P URPA) as a response to the energy crises of the 1970s. PURPA’s major goa l was to promote energy conservation and alternative energy technologies and to reduce oil and gas consumption through use of improved technology and regulatory reforms. A perhaps unanticipated side e ffect was that PURPA prompted a number of parties to see potential profits in developing competitive generating plants, creating an opportunity fo r nonutilities to emerge as im portant electric power producers. 33

PURPA required electric utilitie s to interconnect with and purc hase power from cogeneration facilities and small power producers that met statut ory criteria for a qualifying facility (QF). A utility had to pay the QF at the utility’s incremen tal cost of production. In a departure from costbased rate approaches, FERC defined this as the utility’s avoi ded cost of power. 34 Box 1-1

29 Id. at 31,641.

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

31 The response to the blackout included the formation of regiona l reliability councils and the North American Electric Reliabili ty Council (NERC) to promote the reliability a nd 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. for Regulatory Studies, Working Paper No. 03-13, 2003), available at http://www.aei-brookings.org/admin/authorpdfs/ page.php?id=271 [her einafter 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 seque ntially produce electric energy and another form of energy (such as heat or steam ) using the

20discusses how implementation of PURPA encouraged nonutility generation suppliers by guaranteeing a market for the electricity produced. 35 PURPA changed prevailing views that vertically integrated public utilities were the only reliable sources of power 36 and showed that nonutilities could build and operate generation facilities effectiv ely and without disrupting the reliability of the electric grid. PURPA contribute d substantially, both directly and indirectly, to the creation of an independent competitive generation sector. 37

Box 1-1 State Implementation of PURPA

PURPA required states to determine each utility ’s avoided costs of production. This cost was used to set the price for purchasing a QF’s power. To encourage renewable and alternative energy generation, several st ates, including California, New York, Massachusetts, Maine, and New Jersey, required utilities to sign long- term contracts with QFs at prices that eventually ended up be ing much higher than the utilities’ actual marginal savings of not producing the power itself (avoided costs). As a result, many utilities in these states entered into long-term purchase contracts at prices higher than those available in the competitive wholesale market s. The costs of these QF contracts were reflected in retail rates as cost pass-throughs . The experience added to the dissatisfaction with retail rate regulation.

Before passage of PURPA, nonutility generation was confined primarily to commercial and
industrial facilities that generated heat and power for onsite use where it was advantageous to do so. Although nonutility generation facilities were located across the country, development was heavily concentrated geographically, with about two-thirds of such facilities located in California and Texas. Nonutility generation development advanced in states where avoided costs were high enough to attract interest and wh ere natural gas supplies were av ailable. Federal law largely precluded electric utilities from constructing ne w natural gas plants during the decade following enactment of PURPA, but nonutility generators faced no such restriction and quickly turned to the new smaller gas turbines as the preferred generating technology.

The response to PURPA was dramatic. Annual QF filings at FERC rose from 29 applications covering 704 MW in 1980 to 979 in 1986 tota ling over 18,000 MW. From 1980 to 1990, FERC received a total of 4,610 QF a pplications 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 entrants in whol esale markets. They c ould sell electric power

same fuel source, and small power 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).

21profitably with smaller scale generators, incl uding renewable energy technologies and more efficient, modular gas turbines. 39 Other nonutilities that could not meet QF criteria began building new capacity to compete in bulk power markets to meet the needs 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 per cent of the electric generating capacity and produced about 9 percent of the total electricity generated in the United States. 42 Nonutility
facilities accounted for one-fif th of all additions to ge nerating capacity in the 1980s. 43 Beginning in the 1980s, FERC allowed many new utility and nonutility generators to sell electricity at rates negotiated in wholesale market s, rather than established under cost-of-service
formulas. 44

In 1988, FERC solicited public comments on thr ee notices of proposed rulemaking (NOPRs) dealing with electricity pricing in wholesale transactions. These NOPRs addressed the following issues: (1) competitive bidding for new power requi rements; (2) treatment of independent power producers; and (3) determinati on of avoided costs under PURPA. 45 These proposals would have moved FERC towards greater use of a “non-trad itional” market-based pricing approach in ratemaking as opposed to the agency’s “traditiona l” cost-based approach. The NOPRs, however, proved controversial, and efforts to establish fo rmal rules or policies were abandoned. However, the overall policy goals were still pursued on a case-by-case basis.

Between 1983 and 1991, FERC was asked to approve more than 30 non-traditional market-based rate proposals. These proposals were brought by IPPs, power brokers/marketers, utility-affiliated power producers, and traditional franchised utilities. FERC approved all but four. 46 In explaining its approach, FERC st aff wrote: “The Co mmission has accepted non-traditional rates
where the seller or its affiliate lacked or had mitigated market power over the buyer, and there was no potential abuse of affiliate relationships which might directly or indirectly influence the market price and no potential abuse of recipr ocal dealing between the buyer and seller.” 47 In determining whether the seller could exercise market power over the buyer, FERC considered

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 adopted competitive bidding into the process of acquiring and pricing power from QFs and would have largely abandoned the 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 proposal would have relaxed rate review and regula tion of wholesale sales by independent power producers, and other public utilities that di d 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 St ats. & Regs. ¶ 32,457 (1988) (modified by 53 Fed. Reg. 16882 (Ma y 12, 1988)). This proposal would have revised th e elements used in making administrative determinations of avoided costs for rates for utilities’ PURPA QF purchases.

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. Marl ette, Associate General Counsel for Hydroelectri c and Electric, Federal Energy Regulatory Commissi on).

47 Id. at 100.

22whether the seller or its affiliates owned or c ontrolled transmission that might prevent the buyer from accessing other power sources. A seller with transmission control might be able to force the buyer to purchase from the seller, thus lim iting competition and significantly influencing price. The FPA does not allow rates to re flect an exercise of such market power. 48

FERC recognized the potential fo r control of transmission to create market power and the challenge such control created in moving to greater reliance on ma rket-based rates. FERC staff told Congress, “Because the Commission’s very premise of finding market-based rates just and
reasonable under the FPA is the absence or miti gation of market power, or the existence of a workably competitive market, and because th e FPA mandates that the Commission prevent undue preference and undue discrimination, we belie ve the Commission is legally required to prevent abuse of transmission control and affiliate or any other relationships which may influence the price ch arged 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 transmi ssion grid to reach potential customers. 50 Under the FPA as then written, FERC had limited authorit y to order access. FERC would subsequently find that "intervening" transmitting utilities would deny or limit transmission service to competing suppliers of generati on to protect demand for wholes ale power supplied by their own
facilities. 51 Second, unlike QFs that enjoyed a statutory exemption under PURPA, IPPs were subject to PUHCA 1935, which discouraged nonu tilities from entering 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 a ddress what were then seen as the two major limitations to the development of a competitive ge neration sector.

First, EPAct 1992 created a new category of power producers, called exempt wholesale generators (EWGs). 53 An EWG is an entity that direct ly, or indirectly through one or more affiliates, owns or operates facili ties dedicated exclusively to produc ing electric power for sale in
wholesale markets. 54 EWGs are exempted from PUHCA 1935 regulations, thus eliminating a

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 companie s that did not qualify for an exemption were subject to extensive regulation of their financial activities and operations. These regulations limited the availability of exemptions an d the growth and expansion of electric utility companies. PUHCA 1935 restricted utility operations to a single integrated public-utility system and prevented utility holding companies from owning other businesses that were not reasonably incidental or functionally related to the utili ty business. Further, registered holding companies had to obtain Securities and Exchange Commissi on (SEC) approval for the sale and issuance of securities, for transactions among their affiliates and subsidiaries and for se rvices, sales, and construction contracts, and they were req uired to file 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 PUHCA 1935 have largely been by other domestic and forei gn utilities. Investment by entities outside the industry has been limited, as these entities avoid the extensive regulations imposed by PUHC A 1935.

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

54 Joskow, Deregulation at 24.

23major barrier for utility-affiliated and nonaffiliate d 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 provide transmission service for wholesale power sales to any electric utility, federal power marketing agency, or any person generating electric energy. 56 It provided for orders to be issued on a caseby-case basis following a hearing if certain pr otective conditions were met. Although FERC implemented this new mandatory wheeling authorit y, it ultimately concl uded that procedural
limitations restricted its reach and a broader remedy was needed to eliminate pervasive undue discrimination in transmission service that hindered competition in wholesale markets.

In April 1996, FERC adopted Order No. 888 in exerci se of its statutory ob ligation under the FPA to remedy undue transmission discrimination. The goal was to ensure that transmission owners do not use their transmission facility monopoly to unduly discriminate against IPPs and other sellers of electric power in wholesale mark ets. In Order No. 888, FERC found that undue discrimination and anti-competitive practices exis ted in transmission service provided by public
utilities in interstate commerce. FERC determined that non-discriminatory open access transmission service was an appropriate remedy and one of the most critical components of a successful transition to competitive wholesale el ectricity markets. Accordingly, FERC required all public utilities that own, contro l or operate facilities used for transmitting electric energy in
interstate commerce to file open access transmission tariffs (OATTs) containing certain nonprice terms and conditions. They also were required to “functionally unbundle” wholesale power
services from transmission services. 57 This meant that a public util ity was required to: (1) take
wholesale transmission services under the same tariff of general applicability as it offered its customers; (2) define separate rates for whol esale generation, transmission and ancillary services; and (3) rely on the same electronic info rmation network that its transmission customers rely on to obtain information abou t 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 u tility’s transmission and wholesale power functions to prevent the utility from giving it s power marketing arm preferential access to transmission information. Order No. 889 require s each public utility that owns, controls, or operates facilities used for the tran smission of electric energy in inte rstate commerce to create or participate in an Open Access Same-Time Inform ation System (OASIS). OASIS must provide information regarding available transmission capac ity, prices, and other in formation that will

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 bound aries over transmission and local distribution. While it reaffirmed that FERC has exclusive jurisdiction over th e rates, terms, and conditions of unbundled retail transmission in interstate commerce by public utilities, it nevertheless recognized the legitimate concerns of state regul atory authorities for the develo pment of competition
within their states. FERC therefore declin ed to extend its unbundling requirement to the transmission component of bundled ret ail sales and reserved judgment on whether its jurisdiction extends to such tr ansactions. The United States Supreme Court affirmed this elem ent 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 Networks) 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).

24enable transmission customers to obtain open access to non-discriminatory transmission
service. 60

In Order No. 888, FERC also encouraged gr id regionalization thr ough the formation of independent system operators (ISOs). Participa ting utilities would volunt arily transfer operating
control of their transmission facilities to th e ISO to ensure indepe ndent operation of the transmission grid. 61 The expectation was that ISO regi onal control would lead to improved coordination, reliabilit y, and efficient operation. 62 However, ISO participation was voluntary and was not embraced in all regions. 63 Together, Order Nos. 888 and 889 serve as the primary federal regulatory foundation for providing nondi scriminatory transmission service and
information about the availabil ity of transmission service. 64

4. Retail Electricity Competition and Stat e Electric Restructuring Initiatives

In the early 1990s, several states with high elec tricity prices began e xploring opening retail electric service to competition. While customer s would choose their supplier, the delivery of electricity would still be done by the local distribution utility. Retail competition was expected to result in lower retail prices, innovative services and pricing opti ons. It also was expected to shift the risks of new generation construction from ratepayers to competitive market providers. The substantial rate disparity among and between util ities in different states spurred state interest in retail competition. For example, in 1998, cu stomers in New York paid more than two and one-half times the rates paid by customers in Kentucky. Rates in California were well over twice the rates in Washington. 65 Some of this disparity can be at tributed to different natural resource endowments across regions, such as the availabili ty of hydroelectric resources in the Northwest and of abundant coal reserves in Kentucky and Wyoming– which were refl ected in the low cost of electricity in these states. In contrast, in more urban states without these res ources, utilities invested heavily in large, new nuclear and coal plants, which 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 cont racts that subsequently resulted in higher prices than in the wholesale power market. 66 These QF contract costs were ul timately reflected in the regulated
retail rates. 67

Many large industrial customers viewed these ra te disparities among states as a competitive disadvantage and looked to retail competition as a wa y to secure lower cost electricity supplies. Many industrial customers had long objected that they subsidized lower rates for residential customers under state regulated rates. For ex ample, a survey by the Electricity Consumers
Resource Council in 1986 contende d that industrial electricity consumers paid more than $2.5

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.

25billion annually in subsidies to other electr icity customers (e.g., commercial and residential customers). 68 It was presumed that allowing indust rial customers to choose a new supplier would avoid these subsidies, ther eby resulting in lower electricity prices for such customers.

Thus, it was not surprising that many states adopti ng plans to restructure re tail electric service were those with higher prices. 69 (Figure 4-1 in Chapter 4 shows average retail electricity prices in 1995.) States with high electr icity rates, such as California and those in New England and the mid-Atlantic region, were among the most aggr essive in adopting retail competition and restructuring electric service in the hope of lo wering retail rates. As of 2004, the disparity in retail prices among the states persisted, as il lustrated in Figure 1-1, below.

Figure 1-1. U.S. Electric Power Industry, Average Retail Price of Electr icity by State, 2004

Cents per kWh

AL
6.08

AK
10.99 AZ
7.45 AR
5.67 CA
11.45 CO
6.95 DE
7.53

DC
7.47

FL
8.16 GA
6.58

HI
15.70 ID
4.97

IL
6.80 IN
5.58 IA
6.40

KS
6.37 KY
4.63

LA
7.13 ME
9.69

MD
7.15 MA
10.77 MI
6.94 MN
6.24

MO
6.07 MT
6.40

NE
5.70 NV
8.56 NH
11.37

NM
7.10 NY
12.55

NC
6.97 ND
5.69

OH
6.89

OK
6.50 OR
6.21

PA
8.00 RI
10.96 SD
6.44

TN
6.14

TX
7.95 UT
5.69 VT
11.02

VA
6.43 WA
5.80

WV
5.13 WI
6.88 WY
4.98

U.S. Average
7.62 SC
6.22 CT
10.26 NJ
10.29

MS
7.00 7.10 to 9.69 6.44 to 7.00 6.07 to 6.43 4.63 to 5.80 10.26 to 15.70

Source : EIA, Electric Power Annual 2004 , Figure 7.4

Most states considered the merits and implicatio ns of competition and in dustry restructuring, but not all adopted retail competition plans. As of July 2000, 24 states and the District of Columbia had enacted legislation or passed re gulatory orders to restructure th eir electric power industries. Two states had legislation or regulatory orde rs pending, while 16 states had ongoing legislative or regulatory investigations. Only eight states did not formally initiate restructuring studies. 70

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.

26The meltdown of California’s elect ricity markets and the ensuing Western Energy market crisis of 2000-2001 are widely perceived to have halted interest by states in restructuring retail markets. Since 2000, no additional states have announced plans to implement retail competition programs, and several states that had introduced such programs have delayed, scaled back, or repealed their programs enti rely (see Figure 1-2 below). 71

In 2006, retail customers in 30 states continue to receive service almost exclusively under a traditional regulated monopoly utility service franch ise. These states include 44 percent of all U.S. retail customers, representing 49 percent of electricity demand. Howe ver, 20 states and the District of Columbia have state restructuring plans in force that allow competitive retail providers to provide service to so me if not all retail customers at prices set in the market.

State retail restructuring plans of ten involved divestiture of generating assets by local vertically integrated utilities. As a result, the distribution utilities that sell electric ity to retail customers must procure power from wholes ale markets under long- or shor t-term bilateral contracts and from wholesale spot markets. These jurisdic tions include many of the most populous states, accounting for over half of all retail customers and loads. With some exceptions, retail competition has been slow to develop in many of these states, particularly for residential customers. Without a competitive provider op tion, most customers continue service under regulated “provider of last resort” (POLR) rates. In some states, freezes and caps on POLR rates approved by state regulators unde r retail restructuring cases ar e expiring, and POLR rates are being revised sharply upward to reflect higher ma rket-based wholesale elect ricity costs. State experience with electric competition and relate d issues is discussed in Chapter 4, Retail Competition, and in Appendix D.

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 ].

27Figure 1-2. Status of Stat e Electric Industry Restructuring Activity and Retail Competition, July 2006

Note: 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 electrici ty from alternative suppliers if the contr act is found to be in the public interes t.

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 pl an, the three major investor-owned utilities
divested most of their non-nucle ar generation and turned over opera tion of transmission facilities to the new California Independent System Operator (CAISO). The IOUs were required to sell into and purchase power through the new California Power Excha nge (CalPX) and the CAISO.
Retail rates were reduced but remained well above the national average. Rates were then frozen
until the utilities recovered thei r stranded costs. At that point, competitive markets were expected to drive prices lower. San Die go Gas and Electric (SDG&E) fully recovered its stranded costs by summer of 1999, and its retail rate s were then allowed to reflect the utility’s cost of obtaining power in the wholesale markets. Retail rates for the ot her 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 Ap ril 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 Electri c (PG&E) and Southern California Edison (SCE), were forced to pay th e unexpectedly higher PX wholesale prices, but could not pass increases on to retail custom ers as they were still under a rate freeze.

28Price spikes were not California’s only probl ems. On June 14, 2000, the CAISO imposed rolling
blackouts in PG&E’s San Francisco service ar ea because of shortage s attributed to the maintenance shutdown of several generating pl ants. These were the first of many power emergencies and blackouts affecting the state that did not end until July 2001.

Responding to public concern, the California Public Utilities Commission, the 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 markets and asked for a price cap of $250. 72 FERC opened a formal investigation of wholesale pricin g in California and the West in general. A preliminary FERC staff report in November 2000 found that the market rules and structure were “seriously flawed” and, coupled with supply and demand imbalance, could result in rates that were not “just and reasonable.” 73 The staff report concluded that the state’s market structure created the potential for abus e of market power when suppl ies were tight. FERC proposed interim emergency remedies that were instituted in December 2000. 74

As the state’s market problems continued and spread, price spikes affected electricity pricing hubs and utilities across the West, 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
tens of billions and le d to retail rate increases in many Western states. 75 California declared multiple power emergencies in December 2000, followed by blackouts in January and March 2001. High wholesale market prices that utilities were not allowed to recover thr ough retail rates threatened the solvency of the state’s thr ee 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 behalf of the utilities and to preserve se rvice to retail customers. Contract prices were set at some of the highest pr ices prevailing over this period. 76 As a condition of assuming responsibility for power procurement, the state suspended retail competition for all but large customers that already had contra cts with competitive suppliers. In April, PG&E’s retail electric utility subsidiary, one of the largest in the nati on, filed for bankruptcy pr otection, later joined by
a number of wholesale selle r-creditors, because the financially distressed distribution utilities did not make timely payments to these generators. Power prices did not return to “normal” ranges
until fall of 2001.

Over this period, FERC issued a number of orde rs setting and lowering price caps, establishing market monitoring requirements, and opening an investigation of possibl e market manipulation in the run-up of natural gas pr ices in the West. State, fede ral, and private investigations ultimately uncovered a number of market abuses and regulatory gaps. 77 Many FERC and other

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 powe r 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 Perspective on the Californ ia Energy Crisis, Recommendations for Improving Enforcement and Protec ting Consumers in Deregulated Energy Markets (April 2004), available at http://ag.ca.gov/publications/energyw hitepaper.pdf [hereinafter Ca l. Atty Gen. White Paper]; Federal Energy Regulatory Commission, Final Report on Price Manipulation in Western Energy Markets: Fact Finding Investigation of Potential Manipulation of Electric and Na tural Gas

29proceedings arising out of the dysfuncti onal California markets continue today. 78 A number of energy traders eventually faced criminal ch arges. The 2000-2001 Western Energy Crisis had wide repercussions as other regions adapted th eir market rules and structures to avoid the problems encountered in the West.

6. Development of Regional Transmission Orga nizations and Regional Wholesale Markets

After issuing Order Nos. 888 and 889, FERC continue d to receive complaints about transmission owners discriminating against independent ge nerating companies. Transmission customers remained concerned that implementation of functional unbundling did not produce complete separation between operating the transmission syst em and marketing and selling electric power
in wholesale markets. There were also concer ns 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 electri c industry continued to evolve in response to competitive pressures and state retail restruct uring initiatives. Utilities today purchase more wholesale power to meet load than in the past an d are relying more on availability of other utility transmission facilities to deliver power. Reta il competition increased significantly, and state initiatives brought about the divestiture of generati on plants by traditional electric utilities. In addition, there were a number of mergers among tr aditional electric utilit ies and among electric utilities and gas pipeline companies. The number of power marketers and independent generation developers increased dramatically, and ISOs were established to manage large parts of the transmission system. Trade in wholesal e power markets has increased significantly, and the nation's transmission grid is now used more heavily and in new ways.

In December 1999, responding to continuing comp laints 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 mark ets, but did not eliminate the potential to engage in undue discrimination and pref erence in providing transmission service. 80 FERC concluded that regional transmi ssion organizations (RTOs) coul d eliminate transmission rate pancaking, 81 increase region-wide reli ability, and eliminate any residual discrimination in transmission services where operation of the tr ansmission system remains in the control of a vertically integrated utility. Accordingly, FERC encouraged voluntary formation of RTOs.

Prices , Docket No. PA02-2-000 (March 26, 2003); U.S. General Accounting Office, Restructured Electricity Mar kets, California Market Design Enabled Exercise of Market Power (June 2002), available at http://www.gao.gov/new.items/d02828.pdf; Lockyer v. FERC, 383 F.3d 1006 (9th Cir., 2004); U.S. Senate, Commi ttee on Governmental Affairs, Committee Staff Investigation of the Fe deral Energy Regulatory Commission’s Oversight of Enron Corp (November 2002), available at http://hsgac.senate.gov/_f iles/111202fercmemo.pdf.

78 For more on FERC proceedings, see the FERC webpage, “Addressing the 2000-2001 Western Energy Crisis,” at http://www.ferc.gov/industries/electric/indus-act/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 circumstances in which a transmission customer must pay separate access charges for each utility service territory crossed by the customer's contract path.

30RTOs are entities set up in response to FERC Order Nos. 888 and 2000 encouraging utilities to voluntarily enter into arrangements to operate and plan regional transmission systems on a nondiscriminatory open access basis. RTOs are i ndependent entities that control and operate regional electric transmission grids for the purpose of promoting efficiency and reliability in the operation and planning of the transmission grid and for ensuring non-discrimination in the provision of electric transmi ssion services. RTOs currently do not own transmission. 82

FERC has approved RTOs or ISOs in several re gions including the Northeast (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 activity in the United States had chosen the RTO option. 83 In 2004 and 2005, the PJM RTO grid expanded substantially to include several additional service territo ries in the Midwest. In 2004, the territories served by Commonwealth Edison (C omEd), American Electric Power (AEP), and Dayton Power and Light joined PJM. The expa nsion continued in 2005 with the addition of Duquesne Light and Dominion Resour ces. PJM now covers about 18 percent of total electricity consumption 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 the amount of available transfer capability (ATC) for wholesale trades for member systems across the footprint of the RTO. RTOs also are responsible for c oordinating regional planning, at least for facilities necessary for reliability above a certain voltage. As of 2004, a ll RTOs coordinate dispatch of generators in their systems and provide transmission servic es under a single RTO open access tariff. In addition to operating the regional transmission grid, RTOs operate regi onal organized energy markets, including a short-term ma rket which prices energy, congest ion, and losses. RTOs in the East offer day-ahead and real-time markets, wh ile California and Texas offer real-time markets alone. All current RTOs use or plan to use some form of locational pricing to manage transmission congestion and have independent mark et monitors that assess and report on market
activities. 85 RTOs and regional wholesale markets are described in more detail in Chapter 3.

82 Although RTOs do not now own tran smission facilities, they are not precluded by regulation from doing so. FERC’s Order No. 20 00 allows RTOs that are independent transcos – tr ansmission-owning RTOs that do not own or operate generati on and are not affiliated wit h generation owners or operators. Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,036-37.

83 Federal Energy Regulatory Commission, Office 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.

31Figure 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 athttp://www.ferc.gov/industries/electric/indusact/rto/rto-map.asp

The RTO model and regional organized wholesal e markets have been voluntarily adopted by utilities and market participants in the North east, Mid-Atlantic, Califor nia, and parts of the Midwest and Southwest. Some states required RTO participation as part of restructuring under the state retail competitio n plan. RTO members incl ude utilities in states that have not adopted retail competition. State regulators often serve on RTO advisory bodies and have been active in FERC proceedings involving RTOs. Although RTOs enjoy broad participation by utilities and competitive power suppliers, some comm ents filed with the Task Force 86 raised concerns over perceived high costs of RTO implementation a nd operations and oversight of RTO markets.

In other regions, including most of the Southeast, the West outside of California, and other parts of the Midwest, RTOs have been considered, but formation has stalle d. State regulators and utilities in these regions have found it difficult to assess the po tential benefits and costs of establishing RTOs. They have been reluctant to create new institutional arrangements that could
diminish local control over tr ansmission facilities and could im pose additional costs on retail

customers.

86 See, e.g. , APPA comments (2); NRECA comments (2); Alliance of State Leaders Protecting Electricity Consumers comments (2); Wisconsin Load Serving Entities comments (2); Progress and Santee Cooper comments (2).

327. August 2003 Blackout

On August 14, 2003, an electrical outage in Ohio precipitated a cascadin g blackout across seven other states and as far north as Ontario, Cana da, leaving more than 50 million people without

power. 87 The August 2003 blackout was the largest in United States histor y, leaving some parts of the nation without power for up to four days and costing between $4 billion and $10 billion. 88 It affected large portions of the Midwest and Northeast United States and Ontario and an estimated 61,800 MWs of load. It was the eight h 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 tr ees; (2) overestimation of dynamic reactive output of system generators; (3) inability of system operators or coord i nators to visualize events on the entire system; (4) failure to ensure that system operation was within safe limits; (5) lack of coordination on system protection; (6) ineffective communication; (7) lack of “safety nets;” and (8) inadequate training of operating personnel. 89

In addition to the Joint Study, affected states and NERC 90 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 power industr y. Among the notable provisions of EPAct 2005 are the following:

 Reliability : Section 1211 authorizes FERC to certif y an Electric Reliability Organization to propose and enforce reliability standa rds for the bulk power system. EPAct 2005 authorized penalties for violati on of these mandatory standards.

 Transmission Siting : Section 1221 requires the Secretar y of Energy to conduct a study of electricity congestion within one year of the enactment of EPAct 2005 and every three years thereafter. It authorizes the Secr etary of Energy to designate certain areas experiencing congestion as “National Interest Electric Transmission Corridors” based on
these studies. In certain limited circum stances, FERC is authorized to approve construction permits for transmission facilities in designated corridors when states either lack such authority, or wit hhold approval for more than one year after filing of an application or corridor designa tion. Proponents of this new fede ral authority argue that it

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 lo ad 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.

33will facilitate construction of new transmissi on and help alleviate transmission congestion that can impair competition in electric markets.

 Transmission Investment Incentives : Section 1241 requires FE RC to establish incentivebased rate treatments for public utilities’ tr ansmission infrastructure to promote capital investment in transmission infrastructure, attr act new investment with an attractive return on equity, encourage improvement in transmi ssion technology, and allow for recovery of prudently incurred costs related to reliability and improved transmission infrastructure. Proponents contend this will encourage the expa nsion of transmission capacity and, thus, help foster greater competition in electric markets.

 PURPA Reform : Section 1253 permits FERC to terminate, prospectivel y, the obligation of electric utilities to buy pow er from QFs, such as indus trial cogenerators. FERC may do so when the QFs in the relevant area have adequate opportunities to make competitive sales, as defined by EPAct 2005. The premise is that growth in competitive opportunities in electric markets negates the need fo r PURPA’s “forced sale” requirements.

 PUHCA 1935 Repeal : Title XVII, subtitle F repeal s 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 also provide s that certain holding companies or states may obtain FERC-authorized cost allocations for non-power goods or services provided by an associate company to public utility members in the holding company. PUHCA 2005 also contains a mandatory exemption fr om the federal books and records access provisions for entities that ar e holding companies solely with respect to EWGs, QFs or foreign utility companies. The goal is to reduce legal obstacles to investment in the electric utility industry and, thereby, help facilitate the construction of adequate
infrastructure.

C. Recent Trends Related to Competit ion in the Electric Energy Industry

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

1. Increases in Generation and Growth of Nonutility Generation Suppliers

Electric power industry restructuring has been sustained largely by t echnological improvements in gas turbines. It is no longe r necessary to build a larger ge nerating plant to gain operating efficiencies. Combined-cycle gas turbines re ach maximum efficiency at 400 MW, while aeroderivative 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 than 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, avoiding the need for additional transmission. Coupled with greater transmission access as a result of Order No. 888, it became feasible for generating plants hundreds of miles apart to compete with each other, giving cust omers more choices in electricity suppliers. 92

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

92 Id.

34The market participation of utili ties and other generation suppliers began changing in response to increases in energy costs in the 1970-1990s and th e passage of PURPA, which facilitated entry of nonutility QFs as energy-efficient, environmenta lly-friendly, alternativ e sources of electric power. The change continued through Order N o. 888, which opened up the transmission grid to competing wholesale electricity suppliers. 93 Until the early 1980s, elec tric utilities’ share of electric power production increased steadily, reaching 97 percent in 1979. 94 By 1991, however, the trend had reversed itself, and the u tilities’ share declined to 91 percent. 95 By 2004, regulated electric utilities' share of total generation c ontinued to decline (63.1 percent in 2004 versus 63.4 percent in 2003) as non utilities’ share increased (28.2 perc ent versus 27.4 pe rcent in 2003). 96

This trend is illustrated by comparing increases in capacity additions for utility and nonutility generation suppliers, as shown in Figure 1-4 below. While most of the existing capacity and most of the additions to capacity through the late 1980s were built by electric utilitie s, their share 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, 1995-2004

0 10 20 30 40 50 60 70

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004Capacity Addition (GW) NON-UTILITY

UTILITY

Source : FERC analysis of Platts PowerDat data.

However, the pattern of merchant generation in vestment outpacing utility investment may be shifting. Traditional regulated utilities, in cluding public power and cooperative utilities,

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 ].

35accounted for about 60 percent of capacity additions from 2005 through May 2006. In California, six new power plants began operations , including four owned by public utilities and two owned by IOUs. 97

2. Transmission Investment

Despite these increased investment s in new generation, the Edison El ectric Institut e (EEI) reports
that IOU investment in transmission declin ed from 1975 through 1999. See Figure 1-5. Over that period, electricity demand more than doubl ed, resulting in a significant decrease in transmission capacity relative to demand. Box 1-2 suggests reas ons for this trend. Since 1999, according to EEI surveys, transmission investme nt has increased annually. From 1999 to 2003, IOU investment increased 12 percent annually. 98 For 2004 to 2008, IOUs expect to invest about $28 billion in transmission, an almost 60 perc ent increase over the prior five-year period.

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

97 APPA comments (2).

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

36Box 1-2
Decline in Transmission Investment

Transmission is the physical link between electricity supply and demand. Without adequate transmission capacity, wholesale competition cannot function effectively.

Some reasons suggested for the decline in transmission investment between 1975 and 1997 (see Figure 1-5) are a decline in investme nt in large base-load generating plants requiring associated new large transmission additions, an overbuilt system prior to 1975, lack of available capital due to other investment activities by vertically integrated utilities, the protection of ve rtically integrated utility generation from competition, and regulatory uncertainty over recovery of new transmission investment.

Another explanation for the decline in inve stment is the difficulty of siting new transmission lines. Siting can bring long delays and nega tive publicity. Local opposition can be significant. Also, some states may require a showing of benefits to the state for approval of a transmission line. This crea tes challenges for interstate transmission facilities proposed to primarily benefit interstate commerce.

3. Retail Prices of Residential Electricity

As seen in Figure 1-6 below, between 1970 a nd 1985, national average residential electricity prices more than tripled in nominal terms and in creased by 25 percent in real terms (adjusting for inflation). 99 U.S. real retail electricity prices be gan to fall after the mid-1980s until 2000-2001 as fossil fuel prices and interest rates d eclined and inflation moderated significantly. 100 Real retail prices stayed flat thr ough 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 pr ices in 2005 averaged 9.43 cents per kilowatthour (kWh), an increase of about 5 percent from 2004. Retail electric prices continue to increase, and the national average price for residential cu stomers in April 2006 was 10.31 cents per kWh, up 12 percent from a year earlier. 101 These increases reflect substantially higher fuel and purchased power costs. 102

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 r oughly 95 percent of increases in total operations and maintenan ce (O&M) costs experienced by electric utilities in the last five years.” Peter Fox-Penner, et al.

, Behind the Rise in Prices: Electricity Price Increases Are Occurring Across the Country, Among all ty pes of Electricity Providers. Why? , E LEC

. P ERSPECTIVES 53 (July/August 2006).

37Figure 1-6. National Average Retail Prices of Electricity for Resi dential Customers, 1960-
2005

0 2 4 6 8 10 12 14

1960 1965 1970 1975 1980 1985 1990 1995 2000Cents per kWh

Nominal

Real

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 Electricity, 1960-2004, and EIA, Monthly Energy Review, July 2006, Table 5-3.

4. Changing Patterns of Fuel Use for Generati on – Reaction to Increased Oil Prices and Clean-Air Environmental Regulations

For many years, coal was the fuel most common ly used to generate electricity, providing 46 percent of utilities’ generation in 1970 and more than 50 percent since 1980. As world oil prices escalated in the 1970s, oil-fired and gasoline-fired generation’s sh are 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 electric power, but its share has declined relative to other major fuels mainly beca use there are a limited number of suitable sites for hydroelectric projects. Nuclear power emerge d as the second largest fuel source in 1991 but was not expected to increase. 103

103 EIA 1970-1991 at 20.

38For nonutilities, natural ga s has been the major fuel for new plant additions. 104 Indeed, in recent years, new capacity additions refl ect 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 problems cause d by hydrocarbons and nitrogen oxides, both of which are prevalent with traditional coal and petroleum-based generation. The CAA fundamenta lly changed the generation business because emission of air pollutants would no longer be cost-free. As a result, many generation 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 specific air quality
standards. 106

Figure 1-7. Natural Gas Plants Domina te New Generating Unit Additions

0 10 20 30 40 50 60 70

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005Capacity (GW) Other Oil Nuclear Coal Renewable Natural Gas Other Natural Gas - Gas Turbine Natural Gas - Combined Cycle

Source : FERC analysis of Platts PowerDat data.

104 During the 1990s, with natural gas prices at an all time low and availability of efficient, modular gas turbines, many nonutil ities built naturalgas generation facilities to enter wholesale markets. Today, as a result of restructuring-related asset sales and divestitures , nonutilities own and operate a broad mix of nuclear, coal, natural- gas and renewable generation facilities that supply wholesale markets. Natural- gas-fired generating capacity was 57 percent of nonutility generating capacity in 2004. According to EPSA, based on EIA data, 36 percent of electr icity produced by competitive generators was coal-fired, 30 percent natural gas, 24 percent nuclear, 6 percent hydroelectric and other renewables , 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 /indus-act/wec/chron/chronology.pdf.

39The result of these plant additions through D ecember 2005 is that 49.9 percent of the nation's electric power was generated at coal-fired plan ts (Figure 1-8). Nuclear plants contributed 19.3 percent; 18.6 percent was generated by natural gas-fired plants , and 2.5 percent was generated at petroleum liquid-fired plants. Conventional hydroele ctric power provided 6.6 pe rcent of the total, while other renewables (primarily biomass, but also geothermal, solar, and wind) and other miscellaneous energy sources genera ted the remaining electric power.

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

Coal, 49.9%

Natural Gas, 18.6%

Petroleum, 3.0%

Nuclear, 19.3%

Hydroelectric, 6.4% Renewables, 2.3% Other, 0.5% Coal

Natural Gas

Petroleum

Nuclear Hydroelectric

Renewables

Other

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

The trend toward gas-fueled capac ity 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 expl ain coal’s resurgence: (1) the relative price of natural gas compared to coal has increased substantially and (2) the cost of environmental equipment for coal plants, such as scrubbers , has decreased. “Over the past decade, many merchant combined-cycle gas-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 na tural gas prices in recent years have challenged these assumptions.” DOE’s EIA estimated th at 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 adde d that year, whereas only 5,451 MWs of gasfired generation additions are predicted. 107 DOE predicts a resurgence of coal-fired generation
as far into the future as 2025. 108

107 See EIA Electric Power Annual 2004 at 17, table 2.4, available at http://www.eia.doe.gov/cneaf/electricity/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/ ncp.pdf (predicting 85 GWs of ne w coal capacity created by 2025).

40Higher gas prices and environmen tal concerns have also spurre d renewed interest in nuclear generation. EPAct 2005 includes a number of provi sions intended to encour age and facilitate a new and improved generation of nuclear power plants.

5. Fuel Price Trends

Natural gas prices have been increasing in recent y ears, due in part to historically high petroleum prices. Natural gas prices increased 51.5 pe rcent 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 as natural gas production disrup tions in the Gulf of Mexico, c ontributed to these increases. As shown in Figure 1-9, for December 2005 the overa ll price of fossil fuels was influenced by the price increases in natural gas. In December 2005, the aver age price for fossil fuels was $3.71 per million Btu (MMBtu), 10.1 percent higher th an for November 2005, and 44.4 percent higher than in December 2004. As natural gas prices in crease relative to coal prices, the change may make development of clean-burning coal plants more economically attrac tive than they were when natural gas fuel prices were lower.

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

Dollars per Million Btu

0 2 4 6 8 10 12 14Jan-01Jan-02Jan-03Jan-04Jan-05Jan-06Dollars per Million Btu

Coal

Petroleum

Natural Gas

All Fossil Fuel

Source : EIA, Monthly Energy Review , July 2006, Table 9.10. Cost of Fossil-Fu el Receipts at Electric Generating Plants.

416. Mergers, Acquisitions, and Power Plant Di vestitures of Inve stor-Owned Electric
Utilities 109

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

IOUs also have divested a substa ntial number of ge neration assets to IPPs or transferred them to an unregulated nonutility subs idiary within the company. 111 Even though FERC-regulated IOUs have functionally unbundled generation from tr ansmission, and some have formed RTOs and ISOs, many utilities have divested their power plants because of state requirements. Some states that opened the electric market to retail compe tition view the separation of power generation ownership from power transmission and distributi on ownership as a prerequisite for retail competition. For example, California, Connecticut, Maine, New Hampshire, and Rhode Island enacted laws requiring utilities to divest their powe r plants. In other states , the state public utility commission may encourage divestit ure to arrive at a quantifiabl e level of stranded costs for purposes of recovery during th e transition to competition. 112

Since 1997, IOUs have divested power gene ration assets at unprecedented levels, 113 and these power plant divestitures have also reduced the total number of IOUs that own generation capacity. 114 A few utilities have decided to sell their power plants, as a business strategy, deciding that they cannot compete in a competitive power market. In a few instances, an IOU has divested power generation capacity to mitigate potential market power resulting from a

merger. 115 As described in Table 1-6 belo w, between 1998 and 2001, over 300 plants, representing nearly 20 percent of U.S. inst alled generating capaci ty, changed ownership.

Since 2001 the merger trends have shifted sligh tly, as financial difficulties of the merchant generating sector have prompted th e sale or transfer of a substant ial share of the merchant fleet. Some purchasers have been traditional utili ties, including public power and cooperative
utilities. 116

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: Tec hnological Considerations for Increasing Competition , at 47, OTA-E-409 (Washington, DC: U.S. Government 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.

42There were no significant el ectric power company mergers from 2001 to 2004, but in 2004
utilities and financial institutions exhibited growing interest in mergers and acquisitions, prompting many analysts to herald 2004 as a ne w round of consolidation in the power sector. 117 One utility-to-utility acquisition closed, 118 and three were announced. 119 Most electric acquisitions in 2004 involved the purchase of spec ific 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 capacity, changed hands in 2004. 120

Table 1-6. Power Generation Asset 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.

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

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

119 In January 2004, Black Hills Corp announced the acquisition of Cheyenne Light, Fuel & Power from Xcel Energy. In July 2004, P NM Resources, the parent of Public Service Company of New Mexico, announced the intention to acquire TNP Enterprises, the parent o f Texas New Mexico Power Company from a group of private equity investors. Id. at 31-32. In December 2004, Exelon announced its intent to merge with PSEG, a plan that would create the nation’s largest utility comp any by generation ownership, market capitalization, revenues, a nd net income. Id.

at 32.

120 Id. at 30.

43CHAPTER 2
CONTEXT FOR THE TASK FORCE’S STUDY OF COMPETITION IN
WHOLESALE AND RETAIL E LECTRIC POWER MARKETS

This chapter provides context a nd theoretical underpinnings to the Task Force’s study of competition in wholesale and retail electric pow er markets. It describes (1) perceived shortcomings of traditional cost-based regulati on that motivated restru cturing 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 expect ed benefits of shifting from costbased rate regulation to market -based pricing of electricity.

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

State and federal policymakers regulated providers of the generation, transmission, and distribution of electric power as vertically-integrated monopolies for approximately 70 years. For much of this period it was considered economically inefficient and technologically challenging to have multiple sources of genera tion, transmission, and distribution facilities serving customers in the same geographic area. Competition was considered impractical and not in the public interest because it would require costly duplication of fac ilities and likely engender competition that would not be sustainable due to economies of scale. Under this model, competition was expected eventually to result in ratepayers paying for fail ed facilities without benefiting from alternative sources of supply.

The traditional “regulatory compact” required an electric power utility to serve all retail
customers in a defined franchise area in excha nge both for the opportunity to earn a reasonable
return on its investment and for protection against entry by potentia l rivals. Consumer prices or “rates” were based on the regulated utilities’ average historic cost of production plus an adder for a fair return on investment and often adjustments for changing fuel prices . Regulators used this “cost-based” regulation to try to ensure adequate supplies at reas onable prices for consumers, as required by state laws. Under mo st state regulatory policies, utilities could not recover new investments in rates until regulators determined that the investment was “prudent” and 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 ra te 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 changes – improvements in smaller-scale generati on technology, transmissi on, communications and control technologies, rising ener gy prices, environmental policy concerns, increased concerns
about the effectiveness of tradit ional utility rate regulation, a nd favorable experience with the introduction of increased competition in other network industries – began to transform the structure and regulation of the electric power sector.

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).

441. Effects on Electricity Demand and Prices

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

The average cost-based pricing formula precl udes economically accurate price signals from guiding consumption decisions. 122 Inefficiency has resulted as consumers purchased either too much electricity (when the average price was below the efficient price) or too little electricity (when the average price exceeded the efficient pri ce). Inefficient resource use can translate to higher production costs and prices. Historical average cost electr icity prices, for example, gave
consumers no economic reason to conserve electr icity when supplies were short or demand was high. Similarly, suppliers did not receive econo mically accurate price signals to guide their short- and long-term sales of generation. In addition, many industrial cu stomers among others have objected that retail rate structures frequently containe d cross-subsidies among customer classes and thus, further distorted prices. 123

2. Effect on Investment Decisions

Regulators’ influence over ge neration construction decisions likely also contributed to inefficiency. Historically, regulators had encouraged local utilit ies to build or contract for sufficient generation to serve customers within their territories. Regul ators blocked entry by independent generators or allowed the utilities to do so. This resu lted in utilities owning nearly all generation assets within their service territories and discouraged competition among generators. While the intent of these policies was partly to keep pr ice down, the unintended effect was to dampen incentives for cost reduction, investment in new capacity and
innovation. 124 More competition might have led earl ier to technological innovation and lower generation costs.

The fact that regulators had to agree that a cap ital investment was necessary and prudent before rate recovery was allowed 125 further discouraged innovation. U tilities were reluctant to take investment risks that might end up being unreco verable if regulators deemed their cost unreasonable. Thus, long-term planners and regu lators had significant influence over when and where generation would be built. In making decisions, regulators struggled to strike a balance between reasonable rates and provi ding utilities with incentives to make necessary and sufficient
investments.

122 From an economic perspective, retail elect ricity prices (or rates) that do not closely track wholesale price trends do not sen d economically “accurate” price signals when they do not reflect temporal varia tions in production costs and wholesale market prices within da ys, across seasons, 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 REGULAT ION OF ANTITRUST 6-7 (MIT Press, 4th ed. 2005) [hereinafter VISCUSI, ET AL.].

125 Most states also regulate the siting of major electric power facilities.

45This regulatory oversight also possibly encour aged an overcapitalizati on of the industry, as generators were assured a rate of return on any approved capital proj ect. It might also have led to undercapitalization if a regulat or was too conservative. Furthe r, if rates were set too high, utilities could earn a higher return on new ge neration investments than would be warranted by the cost of capital. If regulators were unlik ely or unable to identify and disallow excessive construction costs, utilities had little incentive to design new generation pl ants cost-effectively. At the same time, regulatory disallowances of so me costs imposed risk on utility decisions to elicit capital and build new generation, and inve stors sought compensation for this risk when they supplied capit al to utilities. 126

Ultimately, ratepayers were left to bear much of the investment risk, as they had to pay for regulator-approved projects resul ting in overinvestment as well as any subsequent higher costs from underinvestment (for example, costs of runn ing higher cost generati on more often than is economically efficient).

A 1983 DOE analysis of electric power generati on plant construction showed that electric utilities (regulated under a cost-based regul atory 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 build a nuclear plant varied by nearly 400 percent and by 300 percent for coal plants. The study showed that some companies were not co mpetent to manage such large-scale, capitalintensive projects. In ad dition, 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 regulator caps the price a firm is allowed to charge. 128 This alternative may remedy some of the incentive problems of cost-bas ed regulation, but comes with its own costs.
Another alternative is the addi tion of an open, transparent Inte grated Resource Planning process by utilities to consider and support choices a bout building new generati on procuring supplies from wholesale markets, and/or investing in demand-side options to meet projected load growth. In some states, regulators are involved in the utility IRP process and ma y approve the resulting plan. Even with this oversight mechanism, regulators have few re ference points to determine if a builder’s choices about design, e fficiency, and materials for the IRP selected plant are prudent.

126 In the academic literature, the risk of utility overinvestment has been explaine d by the Averch-Johnson Effect. The Averch-Jo hnson Effect reflects that “a firm that is attempting to maximize profits is given, by the form of regulation itself, incentives to be ineff icient. Furthermore, the aspects of monopoly control that regulation is intended to address, such as high pri ces, are not necessarily mitigated, and cou ld be made worse, by the regulation.” K ENNETH E. T RAIN

, O PTIMAL R EGULATION 19 (1991) [hereinafter T RAIN ]. The Averch-Johnson Effect also predicts that if a regulator attempts to reduce a firm’s profits by reducing its rate of return, the firm will have an incentive to further increa se its relative use of capital. Id. at 56. Thus, the most obvious regulatory control within cost-base rate regulation creates further distortions. The Averch-Jo hnson Effect is sometimes thought to explain why a regulated firm 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 Amer ica: Economic Supply for Economic Growth (June 1983) (DOE/PE-0045).

128 Under price cap regulation, a firm can th eoretically “produce with the cost-minimizi ng input mix [and] invest in cost-effectiv e innovation.”

T RAIN at 318. However, this dynamic only occurs where the price cap is fixed over time and the u tility receives the benefit of cost reductions and cost-effective innovations. Further, the benefit of this incr eased efficiency “accrues entirely to the firm: consumers do not benefit from the production efficiency.” Id. Where the price cap is adjust ed over time, firms are induced to engage in st rategic behavior. Additionally, “if, as . . . expected, the review of price caps is conducted like the price re views under cost-base rate regulation, then the distinction bl urs between price-cap regulation and cost-base rate regulation.” Id. at 319. One way for consumers under a rate cap system to share the benefits of efficiency improvements without eliciting strategic behavi or from the regulated firm is to include periodic, automatic reductions in rates based on general trends in productivity.

463. Motivation for Change

In part, the struggles of regulator s to ensure adequate supplies of power at reasonable rates led policymakers to examine whether competition could provide more timely and efficient
incentives for what to consume and build. Adva nces in technology also allowed the entry of a variety of new, nonutility generators and de mand response alternatives and weakened the argument for preserving utilities’ monopolies on ge neration services. These developments set the stage for considering competitive pricing as an option for eliciting entry by new generators or expansion by existing generators. Generally, tran smission and distribution have continued to be regulated services.

B. Overview of the Role of Price in Comp etitive Wholesale and Retail Electric Power
Markets

How much a supplier will produce at a given pric e is determined by many things, including (in the long run) how much it must pay for the labor it hires, the land and resources it uses, the capital it employs, the fuel i nputs it must purchase to gene rate the electric power, the transmission it must use to deliver the electric po wer to end users, and the risks associated with
its investment. Consumers’ overa ll willingness to pay for a product also is determined by a large variety of factors, such as the existence and prices of substitutes, income, and individual preferences.

The following is a review of expectations base d on economic theory of how competition might determine prices and discipline investment in th e electric utility industry. Chapters 3 and 4
examine how well actual wholesale and retail electricity market structures are meeting these expectations.

1. Price Affects Customer Consumption

Price changes play an important economic func tion by encouraging customers and suppliers to respond to changing market conditions. Price changes signal to customers in wholesale and retail markets that they should change their decisions about how much and when to consume electric power. Price increases signal customers to reduce consumption. The more consumers reduce their consumption in respons e to an increase in prices, th e less market power sellers are likely to have. Lower prices encourage custom ers to increase consumption. Consumer price responsiveness is often referre d to as “demand response.” 129

The primary purpose of incorporating market driv en prices into wholesale and retail electric power markets is to provide price signals that accurately reflect underlying costs of production and thereby encourage efficient consumption patterns. Economi c analysis suggests that the market dynamics of this type of pricing will result in lower overall production costs, which will translate into lower consumer prices.

129 U.S. Department of Energy, Benefits of Demand Response in Electricity Markets and Recommendations for Achieving Them: A Report to the United States Congress Pursuant to Secti on 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 res ponse in electric power markets and makes
recommendations to ach ieve these benefits.

47Accurate price signals are expected to improve the efficiency of electric power production by more closely aligning the price that customers pay for and the value they place on electricity. In particular, by exposing customers to prices base d on marginal production costs, resources can be allocated more efficiently. 130 Accurate price signals also reduce cross subsidies between customers and among customer classes. 131 Flat electricity prices based on average costs can lead customers to “over-consume – relative to an optim ally efficient system in hours when electricity prices are higher than the aver age rates, and under-consume in hours when the cost of producing electricity is lower than average rates.” 132 Efficient price signals also have the benefit of increasing price response during periods of scarci ty and high prices, which can help moderate generator market power and improve reliability.

Box 2-1
Market Prices

Market prices reflect myriad individual decisions 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 consumers to purchase more a nd 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.

When there are many close substitutes for a pa rticular commodity, a re latively small price
increase will result in a relati vely large reduction in consumpti on. For example, if natural gas were a very good substitute for el ectric power at prevailing prices , then even a relatively small increase in electricity prices could persuade many consumers to switch in part or entirely to natural gas. To induce those cons umers to return to electricity, el ectricity prices would not need to fall by very much. However, where there are no close substitutes for electric power, the price of electricity may have to ri se substantially to reduce consumption by a significant amount.

Empirical literature shows that, even if the re tail price of electricity increases by a large percentage, consumption of electri city does not decline much. In economic terms, it is said that
the short-run demand for electricit y is “inelastic” with respect to price. See Box 2-2. This inability to substitute other products for electricit y in the short run means that changes in supply conditions (price of input fuels, etc.) are likely to cause wider price fluc tuations than would be the case if customers could easily reduce consumpti on when prices rise. Furthermore, electric power has few viable substitutes for key end uses such as refrigeration and lighting, and thus the

130 There is substantial literature on setting rates based 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 margin al 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 indi cates that marginal-cost pricing may result in a revenue shortfall or excess, and standard ra te-making practice is to require an adjust ment (presumably to an inelastic componen t) to reconcile
with embedded cost-of-service. Various ra te structures to accomplish marginal-cost pr icing 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 s een as having both positive and negative imp lications for society as a whole – depend ing on one’s perspective and whether the cross-subsidy supports pub licly acceptable goals, such as rural electrification.

132 DOE EPAct Demand Response Report at 7.

48consequences for supply shor tfalls can be significant. 133 In the long run, this effect may be somewhat muted as customers may have more abili ty to adjust consumption and fuel sources in response to price changes.

Box 2-2 Price Elasticity of Demand

The desire and ability of consumers to cha nge the amount of a product they will purchase when its price increases is at the core of the conc ept 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 percent decrease in the quantity demanded, the price elasticity of de mand equals -0.5 (-5 percent ÷ 10 percent). If the ratio is close to zero, demand is considered "inelastic," and
demand is more "elastic" as the ratio increases. Short-run elasticities are typically lower than long-run elasticities.

Experience with retail pricing experiments in New York, Georgia, California, and other states have demonstrated that customers are able to adju st their electricity cons umption and are at least somewhat responsive to short-run price changes (i.e., have a non- zero short-run price elasticity of demand). Georgia Power's Real Time Pric ing (RTP) tariff option found that certain large
industrial customers who receive RTP based on an hour-ahead market are somewhat priceresponsive (short-run price elasti cities ranging from approximately -0.2 at moderate prices, to - 0.28 at prices of $1/kWh or more). Among day-ahead RTP customers, short-run price elasticities range from approximately -0.04 at mode rate prices to -0.13 at high prices. National Grid also found limited responsiveness to price in its pricing program. 134 A critical peak pricing (CPP) experiment in California in 2004 determin ed that a test group of residential and small business customers responded to price and sign ificantly reduced consumption (13 percent on average, and as much as 27 percent when automa ted controls such as controllable thermostats were installed) during critical peak periods. In addition, the Californi a pilot found that most customers on the CPP tariffs had a favorable opin ion of the rates and would be interested in continuing in the program. 135

Customer response to prices requires the followi ng conditions: (1) that time-differentiated price signals are communicated to custom ers; (2) that customers have th e ability to respond to price signals (e.g., by reducing consump tion and/or turning on an on-s ite generator); and (3) that customers have interval meters (i.e., so the ut ility can determine how mu ch power was used at

133 Estimates of the total costs in the United 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 Hopper, 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, which incorpor ates automated response to CPP events.

49what time and bill accordingly). 136 Most conventional meteri ng and billing systems are inadequate for charging time-varying rates, and mo st customers are not used to considering price changes in making consumption decisions on a da ily or hourly basis. There is, however, a significant effort underway to improve metering tec hnology and infrastructure to better facilitate end-use price responsiveness. 137

2. Supplier Responses Interact with Custom er Demand Responses to Drive Production

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

If the cost of increasing production is small, a relatively small price increase may be enough to encourage producers to increase production in re sponse to increased demand. If the cost of increasing electricity output is high, however, suppliers will not increase production unless the price increases enough to c over the higher costs. In that case , customers would be compelled to pay significantly higher prices for additional su pply. Additionally, when suppliers are already delivering as much electric power as they phys ically can, increased demand can be met only from new capacity. If prices ar e to provide incentives for resour ce additions, suppliers must be confident that prices will remain high enough for long enough to justify building a new generating plant.

These supply decisions are complicated because electric power cannot be stored economically, thus there are generally no invent ories of electricity. Therefor e, electricity generation must always exactly match electricity consumption. 138 The lack of inventories means that wholesale demand is nearly completely determined by end-use demand. 139 Moreover, any distant generation must “travel” over a transmi ssion system with its own limiting physical
characteristics. 140 Transmission capability must allow customers access to distant generation sources. The system is further complicated by the dynamics of the AC transmission grid, which can create network effects and can produce posit ive externalities (depending on the method used in accounting for tr ansmission costs). 141 That is to say, where tran smission 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 dyna mic can distort the effect of price signals on dispatch efficiencies.

136 See EEI comments. Pepco cautions that many cu stomers, particularly residential and comm ercial 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 en ergy in wholesale markets can vary as a functi on of the cost of owned generation and existing c ontracts, the ultimate demand for energy is entir ely a function of end-use load.

140 Alcoa comments.

141 TAPS comments.

50Another complication derives from the fact that aggregate retail dema nd fluctuates throughout the day and over seasons, with t ypically higher demand during the day than at night. System operators must maintain a suffi cient mix of generating capacity and demand response (plus a margin of 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 ye ar. Thus, load-serving entities must supply or procure (through long-term contr acts and/or short-term “spot” market purchases) sufficient “energy” and demand response to meet varying loads. Generating resources designed to meet these load changes are generally categorized as “base” load, “i ntermediate” load 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., large coal and nuclear plan ts). Intermediate load plants are designed to be brought online and shut down qui ckly to meet fairly predictable daily changes in load above the base level and below peak. A variety of generating plants can be used for intermediate loads, including gas turbines, gas- and oil-fired steam boilers and hydro-electric plants. Peak load generation te nds to come from units such as combustion turbines that can respond rapidly to changes in load, are quick and inexpensive to build, but are often expensive to run. The costs of generating elect ricity for these different applic ations can differ substantially.

In any case, a higher price driven by resource scarcity should si gnal a legitimate opportunity for economic profit, attracting new resource construc tion where it is most highly valued. At the same time customer demand may decrease in respons e to rising prices. The increase in resources coupled with a demand response should wo rk together to br ing prices down.

3. Customer and Supplier Behavior Responding to Price Changes in Markets

In sum, the combined impact of consumer and supplier responses to changed market conditions should produce a new market equili brium price. Current prices must change when they create an imbalance between the quantity demanded an d the quantity supplied. For example, when demand spikes, short-run prices might have to swing sharply higher to provide incentives for short-run supply increases. However, consumer s do not have many good substitutes for electric power, and suppliers usually cannot increase outpu t instantly or trans port distant available generation to increase the quantity supplied to a market. Even if hi gher prices give incentives to change behavior, consumers and producers may have little ability to do so in the short term. Over longer time frames, however, they have more op tions to react to higher prices. The result is that long-run price increases usually will be much smaller than the short-run price increases
needed to induce a dditional 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 toward competitive electricity market structures, some ma rket participants question whether the benefits outweigh the costs associated with establishing such markets. So me question whether electricity markets are, by nature, sufficiently competitive to warrant expected price reductions. 142 They note the cost of operating ISOs a nd the cost to consumers of mark et manipulations and failures. Respondents to these concerns suggest that thes e markets are too new to warrant passing such

142 APPA comments.

51judgment. They note that these failures may be a result of ill-advised market designs, and they find benefits despite such failures.

As various regulatory bodies considered whethe r to deregulate electr icity markets, some
conducted formal cost-benefit studie s to address the relative benef its of the status quo versus proposed policy changes. The Task Force re ceived many comments identifying, endorsing, or criticizing such studies. The Task Force did no t, however, have the reso urces or time to fully examine, critique, or draw definitive conclusi ons from these widely varying studies. An annotated bibliography of many of these studies is attached as A ppendix C. The Task Force also refers the reader to the summary conclusion of a recent 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 reviewing recent RTO Cost/Benefit analyses. This study provides a review of the state of the art in RTO Cost/Benefit studies and suggests methodologi cal improvements for future studies. Following is a summary of th is study’s conclusions.

In recent years, government and private organizations have issued numerous studies of
the benefits and costs of re gional transmission organizations (RTOs) and other electric market restructuring efforts. Most studies have focused on benefits that can be readily estimated using traditional production-cost simulation tec hniques, which compare the cost of centralized dispatch under an RTO to dispatch in the region without an RTO,
and on the costs associated with RTO start- up and operation. Taken as a whole, it is
difficult to draw definitive conclusions fr om these studies because they have not examined potentially much larger benefits (and costs) resulting from the impacts of RTOs on reliability management, generation and transmission investment and operation, and on wholesale electricity market operation.

Existing studies should not be criticized fo r often failing to consider these additional areas of impact, because for the most part neither data nor methods yet exist on which to base definitive analyses. The primary objective of future studies should be to establish a more robust empirical basi s for ongoing assessment of the electric industry’s evolution. These efforts shoul d focus on impacts that have not been adequately examined to date, including reliability management, generation and transmission investment and operational efficiencies, and wholesale electricity markets. Systematic consideration of th ese impacts is neither straightforward nor possible without improved data collection and analysis.

J. Eto, B. Lesieutre, & D. Hale, A Review of Recent RTO Benefit-Cost Studies: Toward More Comprehensive Assessments of FERC Electricity Restructuring Policies (December 2005) (prepared for the Department of Energy).

52CHAPTER 3
COMPETITION IN WHOLESA LE ELECTRIC POWER MARKETS

A. Introduction and Overview

As described in the preceding chapters, pr ior to the introduction of wholesale market competition, vertically integrated utilities sold th eir excess electric power to other utilities and to wholesale customers such as municipalities and cooperatives that had little or no generating capacity of their own. 143 FERC and its predecessor agency, the Federal Power Commission, regulated prices, terms and conditi ons of interstate whol esale sales by investor -owned utilities. Wholesale purchasers’ desire to escape being captive to a ve rtically integrated monopoly supplier of electricity was a fundamental impetus to openi ng the generation sector to competition. 144 Sellers of wholesale power were also in terested in accessing more customers. This desire for competition to play a greater role in determining supply and demand is consistent with standard economic theory, which asserts th at 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 th at reflect market conditions (abunda nce, scarcity, etc.). These market-based prices are an essential component of effective competition, as they discipline both consumption and production such that the cost of generating electricity is minimized. However, the demand for wholesale power is de rived entirely from consumption choices at the retail level. In electricity there has been an impediment to effi ciency in that prices of electricity to retail customers often are not directly connected to the wholesale prices in the market in which supplies are sold. This is because states have jurisdiction over retail prices, and state regulators generally set retail rates based on average costs. Thus, unlike wholesale market-based prices, retail prices did not vary with cons umption or the cost of production. 145

The effects of this regulated price disconnect are heightened by one of the shortcomings of costbased rate regulation: its diffi culty in providing incentives for investors to make economically
efficient decisions concer ning when, where, and how to build new generation. 146 If competition is to allocate resources in an economically e fficient manner, customers must have access to a sufficient number of competing suppliers eith er via transmission, incumbent generation, demand response, or new local generation. 147

143 Wholesale markets involve sales of electric power among gene rators, marketers, and load se rving entities (i.e., distribution utilities and competitive retail providers) that ultimately resell the electric power to end-use customers (e.g., residential, commercial, an d industrial customers).

144 U.S. v. Otter Tail Power Company , 410 U.S. 366 (1973) (the United States sued a vertically integrated utility when it refused to deal with the Town of Elbow Lake, MI, a town that was seeking alternative s ources of wholesale power for a pl anned municipal distribution sys tem).

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 with in the electric industry, such as allowing a greater number of sellers and buyers o f electricity to enter the market”).

53Competitive policies in electricity markets we re introduced to alleviate these disconnects between retail demand, wholesale demand, and i nvestment incentives and to create more
efficient markets. 148 In EPAct 1992, Congress determined th at competition in wholesale electric markets would benefit from two changes to the tr aditional regulatory land scape: (1) expansion of FERC’s authority to order util ities to transmit, or “wheel,” el ectric power on behalf of others over their own transmission lines and (2) reducti on of entry barriers so additional nonutilities could enter the market. The former change permitted wholesale customers to purchase supply from distant generators, while th e latter provided customers with competitive alternatives from independent entrants. 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 competitive markets. This is the primary questi on the Task Force attempts to address in this chapter. Answering this question has been challenging due to difficulties in identifying
determinants of investment decisions. Each re gion was at a different re gulatory and structural point when Congress enacted EPAct 1992. For exam ple, some regions began with tight power pools, while others operated transmission and generation in a less centralized manner. Some regions had higher population densi ties and thus more tightly conf igured transmission networks than did others. Some regions had access to fu el sources unavailable or less available in other regions (e.g., natural gas supply in the Southeast, hydropower in the Northwest). Currently, some regions operate under a transmission open- access regime that has not changed since the early days of open access, while other regions have well developed independent providers of transmission services and organized day-ahead exchange markets for electric power and ancillary services.

This chapter discusses the question at hand an ecdotally – by addressing whether and how entry has occurred in several regions w ith different forms of competiti on (i.e., the Midwest, Southeast, California, the Northwest, Texas, and the Northeas t). It includes a disc ussion of how long-term purchase and supply contracts, cap ital requirements, re gulatory intervention, and transmission investment affect supplier and customer decision s. The chapter concludes with observations on various regional experiences with wholesale competition. 150 These observations highlight the trade-offs involved 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 advance en ergy security goals and to protect consumers.” 151 Policymakers recognized that vertically integr ated utilities had ma rket power in both

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” asp ects to the delivery of a good or service, such as with reliab ility, regulation may be the best way to ensure that the correct level of the good or service is provided. In some circumstances, however, market re medies may be available that 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 quan tify this effect, given the constraints of the Report.

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

54transmission and generation because they owned a ll transmission and nearly all generation plants within certain geographic areas. Congress e nhanced FERC’s ability to reduce monopoly power by enhancing its authority to or der utilities, case by case, to transmit power for alternative sources of generation supply.

Today, vertically integrated utilities and ot her entities that operat e transmission systems generally are required to offer transmission serv ice under the terms of th e standard Open Access Transmission Tariff (OATT) a dopted by FERC in Order No. 888. 152 Transmission providers offer two types of long-term transmission se rvice under the OATT: network integration transmission service (network service) and point-to-point transmissi on 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 access – making competition more viable. Price has been predictable and stable for bot h OATT services over the long term. 153

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

153 The demand charge for long-term point-to-point transmission serv ice is known in advance. For network service, the transmissio n customer pays a load-ratio share of the transmission provider’s FERC-appr oved transmission revenue requirement. Thus, even if redispatc h to relieve transmission congestion occurs and the costs are charged to custom ers, or expansion is necessary and the expansion costs are ad ded to the revenue requirement, the distribution over th e whole system has allowed the charges to individual customers to remain relativel y stable.
Customers who take either service have a right to continue taking service when thei r contract expires, although point-to-point customers may have to pay a different rate (up to the maximum rate in the tr ansmission provider’s tariff) if another customer offers a higher rate.

55Box 3-1
How Transmission Services Are Provided Under the OATT

OATT contracts can be for point-to-point (PTP) or “network” transmission service. Network integration transmission service allows transm ission customers (e.g., load-serving entities) to integrate their generation supply and load dema nd with that of the transmission provider.

A transmission customer taking network serv ice designates “network resources,” which include all generation owned, purchased or l eased by the network customer to serve its designated load, and individual network loads to which the transmission provider will provide transmission service. The transmission provi der then provides transmission service as necessary from the customer’s network resources to its network load. The customer pays a monthly charge for this basic service, based on a “load ratio share” (i.e., the percentage share of the total load on the system that the customer’s load represents) of the transmission-owning and operating utility’s “revenue requirement” (i.e., FERC- approved cost-of-service plus a reasonable rate of return).

In addition to this basic charge, there may be additional charges. For example, when a
transmission customer takes netw ork service, it agrees to “r edispatch” its generators as requested by the transmission provider. Redisp atch occurs when a utility, due to congestion, changes the output of its generato rs (either by producing more or less energy) to maintain the energy balance on the system. If the transmi ssion provider redispatches its system due to congestion to accommodate a network customer’s needs, the costs of that redispatch are passed through to all of the transmission provide r’s network customers, as well as to its own customers, on the same load-ratio share basis as the basic monthly charge.

The transmission provider must plan, construct, operate and maintain its transmission system
to ensure that its network customers can continue to receive service over the system. To the extent that upgrades or expans ions are needed to maintain se rvice to a network customer, the costs are included in the transmission-owning utility’s revenue requirement, thus impacting the load-ratio share paid by network customers.

Point-to-point transmission serv ice, which is available on a firm or non-firm basis and on a long-term (one year or longer) or short-te rm basis, provides for transmission between designated points of receipt and designated points of delivery. Transmission customers that take this kind of service specify a contract path. A customer ta king firm point-to-point transmission service pays a monthly demand ch arge based on the amount of capacity it reserves. Generally, the demand charge may be the higher of the transmission provider’s embedded costs to provide the service, or th e incremental costs of any system expansion needed to provide the service. If the transm ission system is constrained, the demand charge may reflect the higher of the embedded costs or the transmission provider’s “opportunity” costs, with the latter capped at incremental expansion costs.

Comments to the Task Force raised several c oncerns over transmission-dependent customers’ access to alternative generator suppliers via OATTs . In particular, some commenters noted the

56continued possibility of transmission discrimina tion in their regions and that the ability for transmission suppliers to discriminate can block access to alternative suppliers. 154 Commenters
concluded that transmission discrimination can increase delivery risk because purchasers fear their transmission transactions might be terminat ed for anticompetitive reasons by their vertically integrated rival, if they purchase from a gene rator that is not affiliated with the transmission provider. The facts that electr icity cannot be stored economically and electricity demand is very
inelastic in the short term heighten delivery risk.

One response to this risk is to turn over operation of the regi onal transmission grid to an independent operator, such as the ISOs and RT Os that now operate in New England, New York, the Mid-Atlantic, the Midwest, Texas, and California (organized markets). 155 RTOs address deliverability concerns in several ways. 156 The market designs in these regions provide participants with guaranteed phys ical access to the transmission sy stem (subject to transmission security constraints). See Box 3-2 for a discussi on of how transmission is provided in organized
wholesale markets.

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 th e vertically integrated utility members.

156 For example, RTOs using LMP pricing a ddress physical deliverability co ncerns by giving physical ac cess to all users willing to pay the market-determined price. The potential for high LMPs due to li mited transmission availability presents a risk that many market participants prefer to hedge. Financial transmission ri ghts (FTRs) have been developed as a mean s for transmission users to hedge against t ransmission pricing risk. The amount of FTR MWs available for hedging are determined by the tr ansmission capabilities of the grid, so that a holder of an FTR generally can depend on being ab le to use the transmission service covered by th e FTR. In some RTOs, FTRs are allocated on the basis of historic transmission use. In others, FTRs are allocated either through an auction or through a process that awards FTRs in pr oportion to the total requests for FTRs for a particular transmi ssion service. Under the latt er two approaches, some historic transmission users may have to acquire additional FTRs from other parties in order to hedge their previous levels of transmi ssion use. In particular, in circumstanc es where certain transmission paths have become highly congest ed, historic transmission users may have to make significant expenditures to maint ain traditional levels of transmission rights.

57Box 3-2
How Transmission Is Priced in an ISO or RTO

ISOs and RTOs (hereinafter RT Os) provide transmission servi ce across a region under a single transmission tariff. They also operate orga nized electricity market s for the trading of wholesale electric power and/or ancillary services. Transmission customers in these regions schedule with the RTO injections and withdrawals of electric power on the system, instead of signing contracts for a specific ty pe of transmission service w ith the transmission owner under
an OATT. The pricing for transmission service is substant ially different in thes e regions than under a standard OATT. RTOs generally manage c ongestion on the transmission grid through a pricing mechanism called Locational Marginal Pricing (LMP). Under LMP, the price to withdraw electric power (whether bought in the exchange mark et or obtained through some other method) at each location in the grid at any given time reflect s the cost of making
available an additional unit of el ectric power for purchase at that location and time. In other words, congestion may require the additional uni t of energy to come from a more expensive generating unit than the one th at cannot be accessed due to the system congestion. In the absence of transmission congestion, all prices wi thin a given area are the same at any given time. However, when congestion is present, th e prices at various locations typically will not be the same, and the difference between any tw o locational prices represents the cost of transmission system congestion between those lo cations. This congestion cost constitutes the only significant “variable cost” of transmission – the fixed costs of infr astructure investment are recovered through a standard transmission access fee.

Because congestion on the grid changes constant ly, a transmission customer may be unable to determine beforehand the price for electric power at any location. To reduce this uncertainty,
RTOs make a financial form of transmission ri ghts available to transmission customers, as well as other market participan ts. Generally known as financ ial transmission rights (FTRs), they confer on the holder the right to receive certain congestion payments. Generally, an FTR allows the holder to collect the congestion cost s paid by any user of the transmission system and collected by the RTO for electricity deliver ed over the specific path. In short, if a transmission customer holds an FTR for the path it takes service over, it will pay on net either no congestion charges (if the FTR matches the pa th exactly) or lower congestion charges (if the FTR partially matches), providing a fi nancial “hedge” against the uncertainty.

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

In regions with RTOs, wholesale electricity can be bought and sold thro ugh negotiated bilateral contracts, through “standard comm ercial products” available in al l regions, and through various products offered by the organized exchange market.

For bilateral contracts, the contract can be i ndividually negotiated with terms and conditions unique to a single transaction. Standard products are availa ble through brokers and over-the58counter (OTC) exchanges such as the NYMEX and InterContinental Exchange (ICE). 157 Standard products have a standard set of specificatio ns so that the main variant is price. Finally, some RTOs also operate organized exchange markets that offer various products including electric power and ancillary services. These ma rkets typically involve both real-time and dayahead sales. Ancillary services include vari ous categories of generation reserves such as spinning and non-spinning reserves in addition to Automatic Generation Control (AGC) for frequency control.

As described above, there is a question as to wh ether the price signals described in Chapter 2 have functioned to elicit the consumption and inve stment decisions that were expected to occur with wholesale market competition.

C. Wholesale Electric Power Markets a nd Generation Investment by Region

New generation investment has varied significantly by region si nce the adoption of open access transmission and the growth of competition. Figure 3-1 shows the overall pattern of new investment by region. There has been substantial new investment in the Southeast, Midwest, and Texas, while other regions have not experienced as much investment. Each region has different pricing formats for transmission services. Moreov er, regions that operate exchange markets for electric power and ancillary services use differe nt forms of locational pricing, price mitigation, and capacity markets.

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 price leve l of a commodity. If the actual price for p ower at a given time and location is higher than a financial cont ract price, Party A pays Party B the diffe rence; if the price is lower, Party B pa ys Party A the difference. In fact, in the United States electricity markets, such agreements are sometimes called “contracts for differences .” Purely financial contracts involve no obligation to deliver physical power. In this report, the Task Force discusses contracts for physical de livery rather than financial contracts, unless otherwise noted.

59Figure 3-1. U.S. Electric Generati ng Capacity Additions, 1960 – 2005



### 0 10 20 30 40 50 60 70

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005Capacity (GW) 

### Northeast (NEPOOL and NYPP) MAAC SPP ERCOT WECC Midwest (ECAR, MAIN, MRO) Southeast (SERC and FRCC)

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 competition and to allocate resources efficiently.

1. Midwest

a. Wholesale Market Organization

In 2004, the Midwest RTO began providing transmissi on services to wholesale customers in its footprint. On April 1, 2005, the Midwest Indepe ndent System Operator (MISO) commenced its organized electric power market operations. Prio r to that, there were no centralized electric power exchange markets and wholesale custom ers obtained transmission 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

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).

60new 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 region as a wh ole relies primarily on coal-fired generation. 160 More recently, new generation has b een coal fired, in part because of rising natural gas prices. 161 This entry and the subsequent dr op in wholesale power prices has resulted in (1) merchant generators in the region declaring bankruptcy and (2) vertically integrated utilities returning certain generation assets from unregulated wholesale affiliates to
rate-base.

2. Southeast

a. Wholesale Market Organization

Wholesale customers in the region obtain tr ansmission under each utility’s OATT (e.g., Entergy or Southern Companies). There are no centralized electric powe r markets specific to the region.

b. New Generation Investment

Due to the Southeast’s proximity to natural gas in the Gulf of Mexico and pipelines to transport it, natural gas is a popular fuel choice for those bu ilding plants in the region. The Southeast has seen considerable new generation construction, as shown in Figure 3-1. More than 23,000 MW of capacity were added in the Sout hern control area between 2000 and 2005, 162 and several generation units owned by merchants or load-servi ng entities have been built in the Carolinas in the past few years.

A significant portion of the regi on’s new generation was nonutility merchant generation, and a number of merchant companies that built plants in the 1990s have sought bankruptcy protection. Often, the plants of bankrupt companies have be en purchased by local vertically integrated utilities and cooperatives, such as Mirant’s sale of its Wri ghtsville plant to Arkansas Electric Cooperative Corporation and NRG’s sale of its Audrain plant to Ameren. 163 Even apart from bankruptcies, some independent power produc ers have withdrawn from the region.

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&marketsector=1&detail=&body_content=spl_rpt.

613. California

a. Wholesale Market Organization

The California ISO began operation in 1998 to provi de transmission services. Concurrently, a separate Power Exchange (PX) operated electric power exchange s. After the 2000-2001 energy crisis, the PX was dissolved. 164

b. New Generation Investment

Even before the California energy crisis, Calif ornia depended on imported electric power from neighboring states. Much of the generation capacity that serves load in Southern California was built a substantial distance away from the population it serves, making the region heavily dependent upon transmission. In th e past few years, much of th e generation in California has operated under long-term cont racts negotiated by the stat e during the energy crisis. 165 Since 2000-2001, California’s demand has increased, but cons truction of local generation has not kept pace. Over 6,000 MW of new generation capac ity entered California in 2002-2003, but very little was built in congested, urban areas such as San Francisco, Los Angeles, and San Diego. 166 Most new generation projects have been in Northern California. 167 In the past five years, transmission investments have improved links be tween Southern 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 transmissi on services as well as a centralized electric power market. Under the electr ic power pricing mechanism a dopted by ISO-NE, certain units used to maintain local resource adequacy must bid into the energy markets at marginal costs under must-run reliability contract s. The fixed costs of these high-priced units are recovered from users in the pertinent reliability zone.

b. New Generation Investment

Much of New England’s net new generation has b een built in less populated areas of the region, such as Maine, while most of the demand for po wer 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 which 212 MW are deactivated reserves.

164 Currently, the CAISO operates onl y 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.

62Demand growth in the organized New England mark ets has led to “load pockets,” areas of high population density and high peak de mand that lack adequate local supply to meet demand and for which transmission congestion prevents use of distant generation. These pockets have not seen entry of generation to meet local demand, a nd transmission has not alwa ys been adequate to bridge this gap. In general, New England need s new generation in the congested areas of Boston and Southwest Connecticut, increased demand respons e, or increased transmission investment to reduce congestion. Signif icant transmission upgrades were e xpected to go into operation in Boston and Southwest Connecticut during 2006. 169

Theoretically, locational prices should elicit generation investment where needed, but this has been inadequate in load pockets. The ISO- NE pricing methodology often did not allow the market clearing price to reflect the cost of generation used to serve the congested areas. 170 The resulting locational prices were not sufficient to attract significant new entry. Several policies have been adopted to provide the needed incenti ves. In 2003, ISO-NE implemented a temporary measure known as the Peaking Unit Safe Harbor (PUSH) mechanism, which was intended to enable greater cost recovery for high-cost, low-use units in designated congestion areas; however, PUSH units were not able to recover all their fixed costs. 171 In June 2006, FERC approved a settlement establishing a forward capacity market in New England that will project demand three years in advance and hold annual au ctions to purchase power resources for the region’s needs. 172 The forward capacity market includes a locational component to account for areas where transmission congestion limits the ab ility to import capacity ne cessary 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 against wholesale pr ice spikes, but, in contrast to early ISO-NE practice, it includes high-cost generato rs 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 example, the New York Power Authority was created, in part, to get hydroelectric power from the Niagara Falls area in to more congested areas of the state. From January 2002 through June 2003, NYISO added 316 MW in capacity. 173 Three generating plants

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 locationa l prices in 2004, probably because the cost of expensive units used to ensure resource adequacy and transmission 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 Engla nd Inc., ISO New England Announces Broad 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.

63with 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 aroun d New York City limit competition in the city and lead to greater use of expensive local genera tion, which results in high prices. NYISO uses price mitigation measures designed to avoid mitig ating prices resulting from genuine scarcity. NYISO has separate mitigation rules for New York City. In an effort to lessen distortion of market signals, NYISO includes the cost of runni ng generators to serve load pockets in its calculation of locational prices. Thus, potential entrants get a more accurate price signal regarding investment in the load pocket.

In a further effort to spur new construction, NYI SO also sets a more generous “reference price” for new generators in their firs t three years of operation (bids above the reference prices may trigger price 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 entered 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 i nvestment is likely due to New York’s clearer market price signals, both in energy markets and capacity markets. However, the Public Utility Law Project of New York comme nted that it is the public po wer agencies and traditional
investor-owned utilities – rath er 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 average results of three types of auctions run by the NYISO. Capacity prices are higher in the tigh ter supply areas of NYC and Long Island.

174 FERC State of the Markets Report 2004 at 97.

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

64Figure 3-2. Estimate of Annual NY Capacity Values

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

0.00 20.00 40.00 60.00 80.00 100.00 120.00

2003 2004 2005 2006 YTD (results through 7/28/06)Weighted Average ICAP ($/kw-yr) LI

NYC

ROS

Source: FERC analysis of NYISO data

6. PJM

a. Wholesale Market Operation

The PJM Interconnection provides tr ansmission services as well as a centralized electric power market. PJM has both energy and capacity markets. Its energy market has locational prices, and FERC recently approved, in principle, PJM’s proposal to shift to locational prices 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 expansion into new territories has added significant low-cost coal resources to PJM’s overall ge neration mix, although the National Rural Electric Cooperative A ssociation (NRECA) commented th at other parts of PJM lack sufficient generation as a result of inadequate capacity additions. From January 2002 through June 2003, PJM added 7,458 MW in capacity. 177 Capacity additions in 2004 were lower than in the two previous years, especially considering that PJM added significant new territory in 2004. In 2004, 4,202 MW of new generation was complete d in PJM. During the year, 78 MW of generation was mothballed and 2,742 MW was retired. 178

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.

65Like other areas, PJM depends on transmission to move power from areas of low-cost generation to areas of high demand. The flow is generally from the western part of PJM, an area with significant low-cost coal-fired generation, to eastern PJM. The easternmost part of PJM is limited by transmission line capacity constraints, which at times limit the deliverability of generation from the west. This means that higher-cost generation must be run in the eastern region to meet local demand. Furthermore, with in the eastern region, th ere are areas of even more limited transmission. As a result, in some ar eas generation that is not economical to run is given reliability must-run (RMR) contracts to prev ent it from retiring and possibly reducing local reliability. 179 Recently, three utilities in PJM propos ed major transmission expansions to increase capacity for moving power into eastern parts of PJM. 180 In its comments, PJM contends that it is experiencing a “robust” level of new transmission investment for reliability upgrades.

7. Texas

a. Wholesale Market Operation

The Electric Reliability Council of Texas (ERCO T) manages power scheduling on an electric grid consisting of about 77,000 MWs of genera tion capacity and 38,000 miles of transmission lines. It also manages financia l settlement for market partic ipants in Texas's deregulated wholesale bulk power and retail electric mark et. The Public Utility Commission of Texas regulates ERCOT. ERCOT generally is not subj ect to FERC jurisdiction because its operations are not integrated with other elect ric systems outside of Texas (i.e., there is no interstate electric transmission). ERCOT is the only market in which regulatory oversight of the wholesale and retail markets is performed by the same governmental entity.

Each year, ERCOT determines the set of transmission constraints within its system that it deems Commercially Significant Cons traints (CSCs). Once approved by the ERCOT Board, the CSCs and the resulting Congestion Zones are used by th e ERCOT dispatch process for the next year. In 2005, ERCOT had six CSCs and five Congestion Zones. When the CSCs bind, ERCOT economically dispatches generation units’ bids agai nst load within each zone. To balance the system in real time, ERCOT issues unit-specifi c 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 or der of lowest to highest bid. 181

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/doc s/AEP_InterstateProjectSummary.pdf. Allegheny Power (Allegheny) proposes to construct a new 500-kV transmission line, w ith a targeted completion date of 2011, whic h will extend from southwestern Pennsylvania to existing su bstations in West Virginia and Virginia and continue east to Dominion Virginia Pow er’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 Northern Virginia , across the Delmarva Peninsula and into New Jersey.

181 ERCOT Response to the DOE Question Regarding the Energy Policy Act 2005

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

66At least one study asserts that when there is loca l congestion, local market power is mitigated in ERCOT by ad hoc procedures aimed at keepi ng prices relatively low while maintaining transmission flows within limits. The study conclude s that, as a result, prices may be too low to elicit 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 essentially entrenched. 182

b. New Generation Investment

In the late 1990s, developers added more than 16,000 MW of new capacity to the Texas
market. 183 Certain aspects of this market may ma ke it attractive to new investment. Texas consumers directly pay (via their electricity bills) for transmission system updates made to accommodate new plants. In other states, FERC often requires developers to pay for system upgrades upfront and recoup the cost over time through credits against their transmission

rates. 184 In addition, the Texas PUC plans to im plement an energy-only resource adequacy market design in the fall of 2006 that requires in crementally raising 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 cust omers, to respond to market-b ased price signals. Under the Load Acting As a Resource Program (LAAR), customers bid demand response into ERCOT's ancillary services market for responsiv e reserves through their scheduling agent. 186 If needed by ERCOT, the load is then paid the market-cle aring price for responsiv e reserve. The LAAR program is fully subscribed at 1,150 MWs.

8. The Northwest

a. Wholesale Market Organization

Wholesale customers obtain transmission servic e through agreements executed pursuant to individual utility OATTs. There are no centralized exch ange markets specific to the region, but
there is an active bilateral market for short-term sales within the Northw est and to the Southwest and California, which makes use of centralized electronic exchange platforms (such as the InterContinental Exchange). Seve ral trading hubs with significan t levels of liquidity provide price information. Multiple attempts to establ ish a centralized Northw est transmission operator have proven unsuccessful for a variety of reas ons, including difficulties in applying standard restructuring ideas to a system dominated by cas cading (i.e., interdependent nodes) hydroelectric generation and difficulties in understanding the po tential cost shifts th at might result in

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 Accounting 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/services/programs/load/laar.

67restructuring contract-based transmission rights . A nascent organization created to enhance coordinated regional reli ability and planning, ColumbiaGrid, has recently seated a board and begun development of various “functional agreements.” 187

b. New Generation Investment

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

The Northwest’s hydroelectric base allows the region to meet almost any capacity demands within the region, but the region is susceptible to energy limita tions (given the finite amount of water available to flow through dams). This abil ity to meet peak demand buffers incentives for building new generation, which might be needed to assure sufficient energy supplies during times of drought. In three out of four years, hyd ro generation can displace 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, some utilities have added thermal resources as insurance against drought-induced energy shortages and high prices. Altogether, over 3,800 MWs of new generation has been added to the Northwest Power Pool since 1995. Of that, 75 percent was commissioned in 2001 or later.

D. Observations on Curren t Wholesale Market Options

One of the most diffiult questions federal regulat ors currently face is whether the different forms of competition in wholesale markets have resulted in an efficient allocation of resources. The various 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 genera tion options available to wholesale customers. No centralized transmission operator or exchange market for electric power operates in regions that rely on this option (the Northwest and Southe ast). However, active trading platforms can be found in these regions. These platforms provide liquidity and price tran sparency in some dayahead or longer-term markets – a lthough the prices do not directly reflect the costs of congestion. For long-term sales in these mark ets, wholesale customers shop for alternatives th rough bilateral contracts with suppliers. In both cases, custom ers separately arrange for transmission via the OATT. With a range of supply opt ions to choose from, long-term bilateral contracts for physical supply can provide price stabilit y for wholesale customers and send them a rough price signal so they can determine whether to build or buy. However, prices and terms can be unique to each transaction and may not be publicly available. Furthermore, the lack of centralized information
about trades leaves transmission operators with system security risks that constrain transmission

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.

68capacity. The lack of price transparency can add to the difficulty of pricing long-term contracts
in these markets.

This model depends significantly on the availability of transmission capacity that is sufficient to allow buyers and sellers to connect. Thus, it also depends on the accurate calculation and reporting of available transmission capacity. Short-term availability is not sufficient, even if accurately 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 also must be seen to be available on a nondiscriminatory basis. As FERC noted in Order 2000, persis tent allegations of discrimination 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 only a few sellers, because they cannot access competitive options supplied by more distant generation. Sim ilarly, 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 reference to suppl y offers by generators and demand by wholesale customers (including Load-Serving Entities or LSEs ). While prices can be set by a number of mechanisms, all U.S. exchange markets have a uni form price auction to determine the price of electric power. Uniform price au ctions theoretically provide supp liers an incentive to bid their marginal costs, to maximize their chance of getting dispatched.

The principal alternative to uniform pr ice auctions is a pay-as-bid market. 189 Research on whether pay-as-bid auctions result in lower pr ices than do uniform price auctions has been evolving and the results are, at best, mixed. Theoretically, pay-as -bid auctions do not result in lower market-clearing prices and may even raise prices as supplie rs base their bids on forecasts of market-clearing prices instead of their marginal costs. Recentresearch suggests that pay-asbid can sometimes result in lower costs for customers. 190 But the pay-as-bid approach may reduce dispatch efficiency, to the extent gene rator bids deviate from their marginal costs. 191 From a practical perspective, academics and market designers generally agree that uniform price auctions in competitively structured mark ets 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 ear ning 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 whether, and by how much, its pr oduction costs are below the market clearing price. A uniform price auction thus may produce very high prices compared with the costs of

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

190 Par Holmberg, Comparing Supply Function Equilibria of Pay-as-Bid and Uniform Price Auctions (2005) (Uppsala University, Sweden 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 Prici ng: A Dilemma for California and Beyond (Blue Ribbon Panel Report, study commissioned by the California Power Exchange, 2001).

69some generators and yet not high enough to give investors an incentive to build new generation that could moderate prices going forward. The uniform price auction cr eates strong incentives for entry by low-cost generators that will be able to displace high-cost generators in the merit dispatch order. The sufficiency of entry in un iform price auction 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, wa y to spur entry is to let whol esale market prices rise with scarcity. 192 As discussed in Chapter 2, the market li kely will respond in two ways. First, the resulting price spikes will attract capital and invest ment. To assure that the price signals elicit appropriate investment and consump tion decisions, they must reflec t the differences in prices of electricity available to serve pa rticular 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 regional ma rket. Without locational prices , investors may not make wise
choices about where to i nvest in new generation.

Unfortunately, it is difficult to distinguish high pri ces due to the exercise of market power from those due to genuine scarcity. Hi gh prices due to scarcity are cons istent with the existence of a competitive market, and therefore perhaps suggest less need for regulatory intervention. High prices stemming from the exerci se of market power in the fo rm of withholding capacity may justify regulatory intervention. Being able to dis tinguish between the two situations is therefore important in markets with market-based pricing. 193

Second, higher prices likely will influence cu stomer decisions about how much and when to consume. Price increases signal customers to reduce the amount they consume. Indeed, during the Midwest wholesale price spikes in the summer of 1998, consumption fell when prices rose as customers purchased little supply during those periods. 194 To reduce consumption efficiently, retail customers must have the ability to react to accurate price signals. As discussed in Chapter 4, customers often have limited incentive, even in markets with retail competition, to reduce their consumption when the marginal cost of electricity is high. This is because retail
rates in the short term do not vary to account for the costs of providing the electricity at the
actual time it was consumed.

b. Moderation of Price Volatility wi th Caps and Capacity Payments

To date, the alternative to unmitigated exchange market pricing has been price and bid caps in wholesale exchange markets. Although price and bid caps may moderate wide swings in

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 Te xas describes a plan it expects to adopt in summer 2006, to ra ise offer caps incrementally in its energy-only market. The Public Utilities Commission of Texas expects to ultimately 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 we re tied to the market price paid higher prices for electric power during those
hours.

70market-clearing prices, there is disagreement as to the 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 wher e capital is required and can recover its full 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 actually ensure that investors will recover the cost of new investment. 195 Thus prices can rise significan tly and yet not attract additiona l supply that could eventually moderate price.

Capacity payments are one way to ensure that in vestors recover fixed costs. Such payments can provide a regular payment stream that, when adde d to power market income, can make a project more economically viable. Like any regulatory construct, however, capacity payments have limitations. It is difficult to determine the appr opriate level of capacity payments to spur entry without over-taxing market participants and consum ers. In addition, because capacity payments include a reserve margin added on to demand, cap acity markets may be more susceptible to market power than energy markets. These mark ets may not be viable unless there is some mitigation policy, but determining the appropriate mitigation policy is a challenge. 196

To the extent that capacity rule s change, there is a pe rception of risk about capacity payments that may limit their effectivene ss in promoting investment and ultimately new generation. When rules change, builders and investors may take a dvantage of short-term capacity payment spikes
in a manner that is inefficient fr om a longer-term perspective.

If capacity payments are provided for genera tion, they may prompt generation entry when transmission or demand response would be more affordable and equally effective. Capacity payments also may reward traditi onal utilities and their affiliates disproportionately by providing significant revenues for units that are fully deprec iated. Capacity payments also may discourage entry by paying uneconomical units to keep running instead of exiting the market. These concerns can be addressed somewhat by appropria te rules – e.g., NYISO’s rules giving capacity payment preference to newly-entered units. In gene ral, however, it is difficult to tell whether capacity payments alone would s pur economically efficient entry.

One issue is whether capacity prices should be locational, similar to locational electric power prices. PJM, ISO-NE and NYISO have either proposed or implemented locational capacity markets that may increase incentives for build ing in transmission-constrained, high-demand areas. The combination of high electric power prices and high capacity prices in these areas may create adequate incentive to bu ild generation in load pockets. 197

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 soci ety as a whole to pay the higher prices rath er than pay the high investment costs to build lower cost gene ration, institute price-responsive demand programs, or invest in transmission access t o 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 populate d areas significantly bounded by topographical barriers such as oce ans – land prices, environmental restrictions, aesthetic considerations, and other factors may make new generation more (or even prohibitively) ex pensive. In fact,
there are some environmental restrictions that se rve as de facto bars to new generation entry.

71c. Encouraging Additional Transmission Investment

Building the right transmission facilities may encourage entr y of new generation or more efficient use of existing generation located near , but outside, load pocke ts. But transmission expansion to serve increased or new load raises th e difficulty of creating a rate structure that ties the economic and reliability benefits of transm ission to particular consumers. Because transmission investments can benefit multiple mark et participants, it is difficult to assess who should pay for the upgrade, particularly when so me market participants do not require the transmission to meet their needs. This regul atory challenge may cause uncertainty about the price for transmission and about return on i nvestment both for new generators and for transmission providers.

Merchant transmission lines, built by nonutilities, once were thought to be a solution to the need for long distance transmission lines. Howeve r, few merchant lines have been built. Uncertainties about revenue have made financing difficult. In additi on, difficulties in obtaining needed rights-of-way and environmental approvals have chilled potential merchant projects. 198 Provisions of EPAct 2005 that allow for federal pe rmitting of transmission projects under certain circumstances appear to have encouraged in terest in new transmission projects, including merchant projects. 199

Building or expanding transmission capacity, wher e possible, may remove the congestion that contributes to higher elec tricity prices in load pockets and ot her transmission-constrained areas. However, the potential for building new transm ission may reduce the incentive to build new generation in the load pockets or develop dema nd response and thus may sustain the high prices there. Once new transmission capacity is built, it will increase supply op tions and decrease or dampen prices just as newly built generation or demand response would. Building or expanding transmission may increase supply more cost eff ectively than building new generation in load pockets and other constrained areas.

Both generation and merchant transmission build ers must deal with an existing transmission owner or an RTO/ISO to obtain pe rmission to interconnect their f acilities. Moreover, there are substantial difficulties in siting new transmission li nes. It is difficult to assess whether these risks are higher for transmission builders th an for generation builders or demand response

programs.

d. Governmental Control of Generation Planning and Entry

The final alternative is a regulat ory, rather than market, mechanism to assure that adequate generation is available to wholesale customers. As a method to spur investment, regulatory oversight of planning has some positive aspects, but it also has costs. Using regulation through governmentally determined resource planning to encourage entry co uld result in more entry than through market-based solutions, but that entry may not occur where, when, or in a way that most

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

, at 20 (2006), available athttp://www.pjm.com/planning/reg-transexp-plan.html

.

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

72benefits customers. Regulatory oversight of i nvestment also means regulators can bar entry for reasons other than efficiency. The stable rate of return on invested cap ital under rate regulation can encourage investment. On the other hand, rate regulation can l ead to overinvestment, excessive spending and unnecessarily high costs. Regulation also does not provide the same market discipline that effective competition prov ides. Under regulation, ra tepayers may bear the risk of mistakes resulting from where and how investments are made. In competitive markets, the penalties for such mistakes fall on manageme nt and shareholders. Future accountability for
investment decisions can lead to better decision-making at the outset. 200

Some commenters strongly suppor ted Integrated Resource Pla nning or other governmentally supervised planning processes to provide optimal fuel diversity. 201 In particular, they were concerned that the market acting alone creates boom-bust cycles where investors overreact to market signals and too many parties invest in one region. This creates overcapacity, which in turn leads to lower prices. Regulatory oversight 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 pr ices, it is difficult to determine in advance the appropriate mix of fuels given the difficulty of pr ojecting fuel prices. Regulators and planners
too can make flawed resource decisi ons and have done so in the past.

3. Market Oversight of Wholesale Energy Markets

Under current law, market oversi ght to prevent 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 el ectricity markets function efficiently and provide
benefits to consumers. FERC’s Office of Enforcement and state re gulators perform this service by reviewing wholesale electricity markets and th e reports of internal and independent market
monitors. 202 Organized markets also are subject to ongoing scrutiny by state regulators and the independent market mon itoring arms of RTOs. 203 In sum, market oversight continues to be a vital element of organized w holesale markets, and efforts are ongoing to strengthen the oversight

process.

E. Factors that Affect Investment Deci sions in Wholesale Electric Power Markets

The Task Force examined comments on how co mpetition policy choices have affected investment decisions of buyers and sellers in wh olesale 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 investment dampening effects of a perceived lack of long-term contracting options. Some commenters asserted that significant problems sti ll exist in organized markets, including steep price increases in some locations without the moderating effect of long-term

200 Regulatory solutions, more so than mark et-based outcomes, may outlive the circumst ances that made them seem reasonable.

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

202 FERC’s efforts are not limited to the organized markets, and extend to other markets as well. Also, federal and state antitrust enforcement agencies have jurisdiction to challenge an ticompetitive conduct in electricity markets.

203 NYPSC comments.

73contracting and new construction. 204 Alternately, the comment was made that in some markets prices are so low that they discourage entry by new suppliers, despite growing projected demand relative to supply. 205 Overall, the Task Force identified six factors that affect investment decisions in wholesale power markets.

Commenters cited long-term contracts as a critic al prerequisite in obtai ning financing for new
generators. 206 Both generators and consumers said they were unable to arrange long term

contracts.

1. Unavailability of Long-Term Supply Cont racts - Wholesal e Buyer Perspective

Many wholesale buyers said they had sought to en ter into long-term contracts but found few or
no offers. 207 The Task Force attempted to determine whether the available data supported these allegations by examining 2004-2005 data colle cted by FERC through its Electric Quarterly Reports for three regions – New York, the Midwes t, and the Southeast. Appendix E contains this analysis. Although inconclusive (due to data limitations described 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 obser ved to be associated with lower contract prices on a per MWh basis.

Three reasons may explain why buyers perceive they cannot enter l ong-term purchase power

contracts. 208

First, the APPA commented that its members in RTO regions who attempt to procure power under long-term bilateral arrangements have found it difficult to arrange c ontracts with base-load and mid-merit generators at prices that reflect the generators' long-term total cost structure. Base-load and mid-merit generators may see rela tively high profits when gas-fueled generators are the marginal units, particularly when natural ga s prices rise. Natural ga s-fueled generators in a uniform price auction may see lower profits as their fuel costs rise, to the extent other generation becomes relatively more economical. 209 When natural gas units set the market price, these units may recover only a small margin over their operating costs, while nuclear and coal units recover larger margins. Under the compe titive model, entry will occur if long-term prices exceed long-term costs. In fact, recent propos als for new generation sh ow a significant number of proposals to build base-l oad and mid-merit generation. 210 In addition, at least some wholesale customers may have the option of investing in their own generation projects - either directly or through affiliates or joint ventures with other interested parties - if they are dissatisfied with the

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 shows that of the 165, 163 MW of generation that is permitted, proposed, application-pen ding or has had a feasibility study performed, 110,964 MW, about two-thirds, is nuclear, combined cycl e, coal-fired steam or integrated coa l gasification technology (generation types typically considered base-load or mid-merit).

74terms offered by incumbent suppliers. Indeed, in some regions, public power and cooperative utilities have announced plans to participate in new base-load gene rating plants. Because of the long lead times and considerable uncertainties i nvolved, it will be some years before electricity from any of these plants can enter the market.

There are additional theoretical problems with the effectiveness of competition in providing investment incentives in that the very competitiv eness of these markets cannot be assumed. For example, over 10 years ago, FERC requested co mments on a wholesale “PoolCo” proposal, the predecessor to today’s organized electric ity market with open transmission 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 num ber of significant sellers into or buyers from the pool. The Commission should not approve a PoolCo unless it finds that the level of competition in the relevant geographic markets would be suffici ent to reasonably assure that the benefits of eliminating traditional rate 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 comment ers specifically cited recent studies that argue that el ectricity markets need a larger number of suppliers to sustain competitive pricing 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 lo ng-term commitments. Long-term
contracts in other commodities ar e often priced with reference to a “forward price curve.” A forward price curve graphs the price of contracts with different maturities. The forward prices graphed are instruments 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-ter m contract. In a market with liquid forward or futures contracts, parties to a long-term contract ca n buy or sell products of various types and durations to limit their price ris k. Currently, liquid electricity fo rward or futures markets often do not extend beyond two to three years. 215 In some markets, one-yea r contracts are the longest
available. In markets where retail load is serv ed by contracts of fixed durations, such as the three-year obligations in New Jersey and Mary land, contracts for the duration of the obligation are growing slowly in number. But the relative lack of liquidity may discourage parties from

211 See Inquiry Concerning Alternative Power Pooling 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 Pooling 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 Alternative 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/com ments/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.e du/econ/na47/JMP.pdf.

75signing long-term contracts, be cause they lack the ability to "hedge" thes e longer-term obligations.

Finally, the availability of long-term purchase co ntracts depends on the availability and certainty of long-term delivery options (transmission). Box 3-2 above describes how transmission prices are set in organized exchange markets. Wholesal e customers have argued that the inability to secure firm transmission rights for multiple year s at a known price, particularly in organized markets, introduces unacceptable uncertain ty in resource planning, investment, and contracting. 216 They say this financial uncertainty has hurt their ability to obtain financing for new generation projects, especia lly new base-load generation.

Congress addressed the issue of insufficient long-term contracti ng in the context of RTOs and ISOs in EPAct 2005. In particular, s ection 1233 of EPAct 2005 provides that:

[FERC] shall exercise the author ity of the Commission under this
Act in a manner that facilitate s the planning and expansion of
transmission facilities to meet the reasonable needs of loadserving entities to satisfy the service obligations of the loadserving entities, and enables load-serving en tities to secure firm transmission rights (or equivalent tradable or financial rights) on a long-term basis for long-term pow er supply arrangements made, or planned, to meet such needs

. 217

To implement this provision in RTOs and ISOs, FERC adopted new rules regarding FTRs in July 2006. The rules require such organizations to o ffer long-term firm transmission rights. FERC did not specify a particular type of long-term firm transmission right, but instead established guidelines for the design and administration of th ese rights, such as the length of terms and the allocation of those rights to transmission customers.

2. Unavailability of Long-Term Supply Contr acts – Generator/Investor Perspective

Commenters cited long-term contracts as a critic al prerequisite in obtai ning financing for new
generators. 218 Comments from generation investors sugge sted that their abil ity to arrange longterm contracts is inhibited by se veral uncertainties. Most of these uncertainties arise from the unpredictability of state and federa l regulation. Finally, the nascence of market structures for the sale of electricity can make it difficult for market participants to have se ttled expectations about the risk of long-term contracts. A description of the uncertainties associated with regulatory risk
follows.

One type of regulatory uncertainty derives from th e fact that most wholesale contracts are subject to regulation by FERC, and a part y to a contract can ask FERC to change prices and terms, even

216 APPA comments; TAPS comments.

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

218 Constellation comments; Mirant comments.

76if the specific contract has been approved previously. 219 For example, in 2001-2002, several wholesale power purchasers asked FERC to modify certain contracts en tered into during the California energy crisis. They alleged that pr oblems in the California electricity exchange
markets had caused their contracts to be unreasonable. The sellers argued that if FERC overrides existing contracts, market participants would not be able to rely on contracts when transacting for power and managing pri ce risk. In declining to change the contracts, 220 FERC cited its obligation to respect contracts except when other action is ne cessary 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 re duce their ability to ra ise capital. In recent years, several merchant generators (NRG, Mi rant and Calpine) have sought to use the bankruptcy process to break long-term power contracts. 222 This bankruptcy risk may create an additional incentive to favor construction of generation by load-ser ving entities or to purchase from utility affiliates over wholesale purchases from merchant generators. 223 These disputes have spawned conflicting rulings in the courts . In particular, thes e cases have centered on separate, but intertwined issues. First, there is a question of where jurisdiction over efforts to end power contracts properly lie s, as between FERC and the ba nkruptcy courts, and to what extent courts may enjoin FERC fr om acting to enforce power contra cts. Second, there is an issue of what standard applies to such efforts (wha t showing must a party make to rid itself of a contract). The law remains unsettl ed, as do parties’ expectations.

A third type of regulatory uncerta inty concerns regulated retail se rvice 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 options are available for distribution utilities to purc hase needed supply or sell excess supply.

A fourth type of uncertainty relates to a gene ral concern about institutional instability. Some market participants argue that they cannot count on current rules and trading mechanisms

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 tran smission tariff as provided f or under Order No. 888, and under the Natural Gas Act, except agreements for th e transportation of natural gas executed pursuant to the standa rd form of service agreement in pipeline tariffs. Standard of Review for Modific ations to Filed Agreements , Notice of Proposed Rulemaking, 71 Fed. Reg. 303 (January 4, 2006), FERC Stats. & Regs. ¶ 61,317 (2005) (Comm’r Ke lly, dissenting). Specifically, FERC proposed that, in the ab sence of specified contractual language pe rmitting the Commission to act on proposed modifi cations to an agreement on its own motion or on behalf of a signatory or non-signatory under the “just a nd reasonable” standard, the Commission, a signatory or a non-signatory seeking to change a contract must show that the change is necessary to protect the public interest. FERC expl ained that its proposal recognized the importa nce of providing certainty and stability in energy markets, and helped promote the sanctity of c ontracts. 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. F ERC- 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 u tility’s self-built generation is treated as an asset but long-ter m purchase contracts are treated as imputed debt, it may cause utilities and state re gulators to favor constructing and owning 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.

77because market rules and institutions change so frequently. This can serve to deter new entry. 226 At the same time, many market participants con tinue to advocate change s 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 market s depends on the ability of a company to acquire capital, either from intern al sources or external capital markets. There is no federal regulation of generation entry, and most states that have permitted retail competition have eliminated any “need-based” showin g to build a generation plant.

In the United States, private capital has funded most electric generation investment. Under traditional cost-base rate regula tion, utility investment decision s were based in part on the promise of a regulated revenue stream with little a ssociated risk to the u tility. Ratepayers often bore the risk, and money from capital markets was generally available when utilities needed to
fund new infrastructure. One si gnificant problem, however, was that regulators had limited ability to ensure that utiliti es spent their money wisely. 227 Investors view regulatory disallowances of imprudent expenditures as re gulatory risk. Some be lieve that Integrated Resource Planning processes with opportunities for public and regulator participation in advance of resource procurement decisions will reduce th e risks of later regulatory disallowances. 228

In competitive markets, project funding is base d on anticipated market-b ased projections of costs, revenues, and relevant risks factors. The ability to obtain f unding is impacted by the degree to which these projections compare with projected risks a nd returns for other investment opportunities. 229 Using this information, potential entrants to generation markets must be able to convince capital markets that new generation is a viable profitable undertaking. In the late 1990s, investors appeared to prefer market investments to cost-bas ed rate-regulated investments, as merchant generators were able to finan ce numerous generation pr ojects, even without a
contractual commitment from a customer to buy the power. 230

Recently, capital for large investment projects has flowed to traditional utilities more than to merchant generators. 231 In part, this preference reflects the reduced profitability of many merchant generators in recent years and the re lative financial strength of many traditional utilities. 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.

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 ?index=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/bro chures/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.

78Investor preference for traditional utilities also may be affected by increasing volatility in electric power markets. As wholesale markets opened to competition, investors recognized that income streams from the newly-built plants would not be as pr edictable as in the past. 233 Under costbased regulation, vertically integrated utilities’ monopoly service territories significantly limited the risk of not recovering the costs of investme nts. Once generators had to compete for sales, generation plant investors were no longer guaranteed that construction cost s would be repaid or that the output from plants could be sold at a profit. 234 Financing was easier to obtain for projects such as combined cycle gas and particul arly gas turbines that can be built relatively quickly. At the time, they were thought to have a cost advantage over existing generation, including less efficient gas-fueled generators. 235 In 1996, the EIA projected that 80 percent of electric generators between 1995 and 2015 would be combined cycle or combustion turbines. 236 Base-load units, such as coal plants, with cons truction and payout periods that would put capital at risk for a much longer tim e, were harder to finance. 237

The increasing amount of new generation fueled by natural gas, however, has caused electricity prices to vary more frequently as natural gas is a commodity subject to wide swings in price. 238 With input costs varying wide ly, but merchant revenues ofte n limited by contract or by regulatory price mitigation, investors may worry th at merchant generators may not recover their costs and provide an attractive rate of return. Commenters suggest that competitive suppliers are beginning to focus on developi ng facilities fueled by othe r sources. They cite 2006 announcements by NRG Energy, Inc. (investing $ 16 billion to develop 10,500 MW of nuclear, wind, and coal facilities), TXU (investing in mu ltiple coal-fired plants), Constellation Energy and Exelon Corp. (developing a nuclear plan t), BP and Edison Mission Group (investing $1 billion in a hydrogen-fueled plant), and AES (i nvesting $1 billion in re newable technologies). 239

4. Regulatory Intervention May A ffect Investment Returns

Economic theory says that, in an unregulated wo rld, needed generation investments will be made and generation investors will recover not only thei r variable and fixed costs but also make an adequate return on these needed investments to maintain long-term financial viability. The mechanism for this cost recovery of the correct level of genera tion investment is allowing the highest cost generator being dispatched at a pa rticular time and place to 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 e xpensive resources. Gene rators with variable

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/electrici ty/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 Power 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.

79costs below the market clearing price receive “scar city rents” that cover their fixed costs and provide a return on investment. If high prices in a particular ener gy market reflect scarcity, these economic rents generally are efficient and se rve to provide incentiv es for construction.

However, regulators may limit recovery of hi gh prices during these periods due to the unpalatability of even temporarily high prices an d/or suspicion of inappropriate market gaming. Thus regulators may deter suppliers from maki ng needed investments in new capacity by imposing price caps and limiting recovery of legitimat e costs and delivery of adequate returns.

This dynamic leads to a chicken-and-egg conund rum: if there were efficient investment, wholesale price or bid caps might not be needed. More investment in capacity would lead to less scarcity, and thus fewer or shorter episodes of high prices that may require mitigation. By contrast, it may be that pri ce regulation during high-priced hours diminishes investors’ confidence that market forces (rather than re gulation) will set pri ces. That diminished confidence in their ability to earn sufficient investment returns thus deters entry of new generation supply, thereby limiting compe tition and giving cause for price caps.

Price mitigation through price or bid caps has beco me an integral component of most organized markets. The use of price mitigation has led generators to seek adequate returns through implementation of supplemental revenue streams ( capacity credits) to en courage entry of new supply. See Box 3-3 for a discussion of capacity cr edits. In practice, however, the presence or absence of capacity credits has not always resulted in predicte d outcomes. California did not have capacity credits and did not experience mu ch new generation, but two regions (Southeast and Midwest) experienced significant new genera tion entry without capacity credits. Northeast RTOs with capacity credits conti nue to have some difficulty attracting entry, especially in major metropolitan areas.

Box 3-3 The Use of Capacity Credits in Organized Wholesale Markets

In theory, capacity credits could support new investment because suppliers and their
investors would be assured a certain level of return even on a marginal plant that ran only in times of high demand. Capacity credits mi ght allow merchant plants to be sufficiently profitable to survive even in competition with the generation of formerly-integrated local utilities that may have already recovered their fixed costs.

As noted, much of the new generation in the So utheast was nonutility merchant generation that relied on the region’s proximity to natural gas su pplies. In the Midwest, in the late 1990s, largely uncapped prices were allowed to send pri ce signals for investment. In California, price caps of various kinds have been used for a number of years, limiting price signals for new entry. In the Northeast, organized markets have offere d capacity payments for long-term investments in addition to electric power prices that are sometimes capped in the 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 w ith acceptable levels of price volatility.

80Net revenue analyses for centralized markets with price mitigation suggest that price levels are inadequate for new generation projects to recove r their full costs. For example, in the last several years, net revenues in th e 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 and California would have allowed a new comb ined-cycle plant to recover no more than 70 percent of its fixed costs.

Regulation also may interfere with efficient exit of generation plants due to the use of reliabilitymust-run requirements. In some load pockets in organized markets, plant owners are paid abovemarket prices to run plants that are no longer economical at the market-clearing price. For example, in its Reliability Pricing Model fili ng with FERC, PJM states, “PJM also has been forced to invoke its recently approved generation retirement rules to retain in service units needed for reliability that had announced their retirement. As the Commission often has held, this is a temporary and suboptimal solution. Such compensation, like the RMR contracts allowed elsewhere, is outside the market, and permits no competition from, and sends no price signals to, other prospective solu tions (such as new generation or demand resources) that might
be more cost effective.” 241 To the extent that market rules allocate the 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 entry. Graduate d capacity payments that favor entry of efficient plants may be a partial solution to retiring inefficient old plants.

5. Investment in Transmission: A Nece ssary Adjunct to Generation Entry

Transmission access can be vital to supporting comp etitive options for market participants. For example, merchant generators depend on the av ailability of transmission to sell power, and
transmission constraints can limit their range of potential customers. Small utilities, such as many municipal and cooperative utilities, depe nd on the availability of transmission to buy wholesale power, and transmission constraints can limit their range of potential suppliers. Much of the transmission grid is owned by vertically-int egrated, investor-owned utilities. Some have alleged that these utilities have an incentive to lim it grid use by others to the extent that such use conflicts with sales by their own generation. In s hort, the availability of transmission 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 c oncerning the efficacy of various terms and conditions governing transmission availability. For example, cu stomers have raised concerns regarding the calculation of Available Transfer Capacity (ATC). Another concern has been a
lack of coordinated transmissi on planning between transmission providers and their customers. Finally, customers have raised concerns about some aspects of transmission pricing. Based on these concerns, in May 2006 FERC proposed modifications to Order 888 open access
transmission tariffs to further limit undue discrimination in transmission services. FERC is soliciting public comments on its proposed modifications.

240 Occasionally in the past few years net re venues have been sufficient to cover the co sts 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.

81As discussed above, generation that is built wher e construction costs are low and fuel supplies readily available, but not necessarily near demand, relies heavily on readily available
transmission. The Connecticut DPUC noted th at, while generation growth may have been sufficient for some regions such as New Engla nd as a whole, some localized areas saw demand grow without increases in supply, raising prices in load pockets. If tr ansmission 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 unrestricted high prices or capacity credits, are used to address the concerns about future generation adequacy. Although capacity credits may spur generators within a load pocket to add addition al capacity, capacity credits may not be required for base-load plants outside the load pocket. Those base-load pl ants 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 more hours of the day. Similarly, price caps may be unnecessary if improved transmission brought po wer from more base-l oad units into the congested areas. Prices would be lower because there would be less scarcity, and high-cost units
would run for fewer hours.

6. Some Types of Generation Investment Ma y Not Be Adequate without Government
Intervention

System reliability, the prevention of network collapse, is a public good. 242 The market may not elicit enough generation that has th e technical capability (i.e., the ability to generate MWs within a very short period of time in a critical location) to prevent netw ork collapse. An administrative process may be needed to provide the correct level of generation t echnically capable of responding to reliability needs. Some argue that perceived inadequate generation entry 243 may be due to competitive policies that are inadequate for eliciting appropriate levels of technically capable generation.

7. The Level of Investment in Demand Respons e Can Affect the Need for Generation and
Transmission Investment

Chapter 2 described the typical disconnect between wholesale a nd retail prices in electric markets. This disconnect can lead to wider pr ice fluctuations than would be the case if customers could easily reduce their demand when prices rise. There are several means to influence the level of demand for power, incl uding energy efficiency and demand response. Examples of energy efficiency include giving customers incentives to replace inefficient refrigerators and air conditioners and imposing appliance standards or more energy-efficient

242 Public goods have two characteristics – “nonexclusiveness” and “n onrivalry.” Nonexclusiveness m eans that others cannot be exc luded from the use of the good (e.g., if one person re fuses to pay taxes, that person still can enjoy public parks) and nonrivalry implies that one person’s consumption of the good does not diminish anot her person’s consumption (e.g., the fact that one person enjoys the increased saf ety engendered by military spending doesn’t decrease anothe r person’s safety.) “Preve nting network collapse” is nonexclusive because if the n etwork collapses there is nothing one can do to escape it (unless one constructs freestanding on-site generation) and it is nonrivalrous because one person being protected from collapse does not preclude another person’s being protected.

243 Joskow, op. cit.

82building codes. Tools for eliciting demand resp onse include time-based rates and incentivebased programs. Time-based rates include time-of- use pricing (i.e., a peak price and an off-peak price), critical peak pricing (i.e ., similar to time-of-use rates, but with a critical peak component invoked during system emergencies or periods of high wholesale 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 system operator emergency demand

response programs.

By influencing demand, energy efficiency and de mand response programs can affect pricing in the short term and in the long term by aff ecting the amount of generation and transmission needed as well as the composition (i.e., com position of base load, mid-merit and peaking generation) of investment. Fo r 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 effici ency of appliances that contribute to peaking load (i.e., air conditioners) can reduce dema nd for mid-merit generation. Demand response programs that curtail demand at peak times may re solve constraints that cause load pockets. Even when constraints persist, demand response can also serve to reduce prices in load pockets whether these high prices are the result of scarc ity rents or market power. DSM also holds the potential to defer the need for new transmissi on enhancements. To date, energy efficiency has provided important benefits, but additional capability can be achieved. Demand response capability has been modest, between 3 and 7 percent in most regions. 244 The use of energy efficiency and demand response is expected to increase significantly in the next few years, especially after advanced smart metering is installed.

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

83CHAPTER 4
COMPETITION IN RETAIL ELECTRIC POWER MARKETS

A. Introduction and Overview

This chapter examines the development of compet ition in retail electricity markets and discusses the status of competition in the 16 states and Dist rict of Columbia that currently allow customers to choose their electricity supplier. 245

Although it has been almost a decade since st ates started implementing retail competition,
residential customers in most of these states stil l have little choice among suppliers. In most of these states, few residential customers have a wi de variety of alternativ e suppliers and pricing options. Commercial and industrial (C&I) custom ers have more choices and options, but in several states large industrial cu stomers have become increasingly dissatisfied 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 impediment to market-b ased competition. Most states required the distribution utility to offe r electricity at a regulated price as a backstop or default if the customer
did not choose an alternativ e supplier or if the chosen supplier went out of business. 246 States argued that this was needed to ensure universal access to affordable and reliable electricity.

States often set the price for th e regulated service at a discount below then-existing rates and capped the price for multi-year periods. In so me states, these initial discounts sought to approximate anticipated benefits of competition fo r residential customers. Since then, wholesale prices have increased. More th an any other policy, th is requirement that distribution utilities offer service 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 le vels now face “rate shock.” On the one hand, rate caps for the regulated service most residential cu stomers use expired or will expire within a few years, and states are faced with raising their regulated customer rates. These higher prices are particularly painful to customers that have limite d ability to adjust consumption in response to price increases and also lack competitive supply op tions (other than possibly to install their own onsite generation). On the other hand, if states c ontinue to require distri bution utilities to offer

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, geogr aphically dispersed customers. An even broader potential definition of retail com petition 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 generation project s – often referred to
as “Distributed Generation” or “Distribut ed Resources” projects – are gaining popularity as well. Many states that do not have retail choice in the conventional sense do have provisions for vari ous forms of onsite generation and net mete ring. Another broader form of retail competition involves municipal utilities or cooperatives. NRECA comments (2). These entities can be carved out of existing private utilit y 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 basis of this form of retail competiti on. If these broader definitions of “retail 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 se rvice. Some states have more than one fo rm of mandated service or have changed the form of POLR service over time. In many states, POLR se rvice originated as an element in arrangeme nts to pay the stranded ( i.e ., non-recovered) costs of vertically inte grated utilities – costs that may have beco me unrecoverable when the state adopted a retail customer choice approach.

84regulated service at below-market rates, then retail entry – and thus competition – will not occur. Moreover, below-market rates put the distribution utility’s solven cy at risk and do not provide appropriate incentives for conservation. 247

This conundrum is further complicated by the fa ct that most distribution utilities offering regulated service no longer own gene ration assets. Most of the suppl y contracts that were part of the agreements under which they divested generati ng assets were set to e xpire at the end of a finite transition period. 248 Many distribution utilities sold or transferred their generation assets to unregulated affiliates when retail competition began. If they offer regulated service, they must purchase supply in wholesale markets. Their fo rmer generation assets may be more expensive now than when they were divested. If the utilit y repurchases these assets at current prices, it is likely to have “sol d low and bought high.”

The competitiveness of wholesale prices directly affects retail prices, 249 except where retail prices are set by regulation without regard to current wholesale pr ices. For example, retail prices usually will reflect imperfections in the wholes ale market, such as some wholesale suppliers’ ability to exercise market power, 250 problems in market design that increase wholesale suppliers’ costs, government subsidies to some suppliers fo r reasons other than addressing market failures, transmission discrimination that prevents lo w-cost suppliers from reaching customers, or restrictions that delay or prev ent entry and diffusion of low-co st generation technologies.
Distortions in wholesale prices that lead to distortions in retail prices can cause economic inefficiencies both in retail customers’ consump tion patterns and in i nvestment decisions. Ultimately these distortions can reduce consumer welfare and raise private and social costs of producing goods made with el ectricity as an input.

This chapter addresses the status and impact of retail competition in seven states that the Task Force examined in detail: Illinois, Ma ryland, Massachusetts, New Jersey, New York, Pennsylvania, and Texas. 251 These states represent the various approaches to retail competition. 252 The chapter also discusses why it is di fficult to determine whether retail prices

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 repor tedly has downgraded the creditworthiness of utilities in Maryland – in particular, Ba ltimore Gas & Electric, due to that firm’s inability to pass on increased input costs to consumers, which “leaves BGE in a weakened state tha t makes it vulnerable to further downgrades and even in solvency if it faces further energy price shocks or other costs that the legislatur e 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 /print.php?StoryID=20060711-103048-5690r.

248 In most retail customer choice states, supply contracts (ves ting contracts) have been used to enable distribution utilities to offer POLR service at the capped price level after they have divested generating plants or transferred th em to unregulated affiliates. The “rate shock” anticipated in these states is due in part to the lack of laddering in the vesting contracts beyond the end of the transition period, as defin ed in the legislation. There are two exceptions worth noting. In California, vesting ag reements were de-emphasized in favor of procurement at spot ma rket prices. In upstate New York, vesting agreements were longer term and continue to have a modera ting effect on average procurement prices fo r POLR service. Public Utility Law Project of New York comments (2) at 36.

249 Several commenters emphasized the potential spillovers from pr oblems 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 Companies co mments (2) at 2, 4-5; Direct Energy comments (2) at 7; Alliance for Retail Energy Markets comments (2) at 3-4; Industrial Consumers commen ts (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 selfgeneration, if the customer’s present supplier tr ies 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, Te xas, and Virginia, plus the Dist rict of Columbia. The states profiled in Appendix D display a range of conditions that are similar to the other states with retail competition. Virginia is similar to Pennsylvania in that its transition to retail competition evolved over a 10-year period. Maine and Rhode Island are similar to New York and Texas in th at prices for

85are higher or lower than they would have been absent the move to retail competition. Also
included are several observations based on experiences of states that have implemented retail competition, with an emphasis on how states ca n minimize market distortions once rate caps expire.

B. Background on Provision of Electri c 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 cl asses (e.g., residential, commerc ial, and industrial). State regulatory bodies set these rates based on the utili ty’s costs. Locally el ected boards oversaw the rates for customers of public pow er and cooperative utilities. For investor-owned systems, the regulated rate included an opportunity to earn an authorized rate of re turn on investments in utility plants needed to serve customers. P ublic power and cooperative systems operate under a nonprofit, cost-of-service structure. Their rates typically include a margin to cover unanticipated costs and support new investment.

With minor variations, monopoly distribution utilities deliver el ectricity to retail customers. 253

Industrial customers sometimes can choose from more options than can small business and
residential customers for service and rate struct ures (e.g., “time-of-use” rates, which are lower when demand is lower during “off-peak” periods). 254

Beginning in the early 1990s, several states with high electricity prices began to explore opening retail electric service to competition. As discussed in Chapter 1 and Figure 4-1, rates varied substantially among utilities, even within a single state. Some of th e disparity was due to
different natural resource endowments across re gions, 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 util ities’ avoided costs. In addition to these rate disparities, some
industrial customers contended that their rates subsidized lower rates for residential customers.

“provider of last resort” (POLR) service have been adjusted re gularly to reflect changes in wholesale prices. Delaware, the Di strict of Columbia, Illinois, Michigan, New Hampshir e, Ohio, and Rhode Island share the situation f aced by Maryland, where the transition period of fixed prices for
residential and small C&I POLR service will end in the near futu re. Massachusetts’s rate cap period ended recently. Many of t he states poised to end the transition period are developing appro aches to bring POLR prices for residentia l and small C&I customers up to market r ates in stages
rather than all at once. Several of thes e states also share Maryland’s and New Jersey ’s interest in auctions for procuring POL R service supplies. Oregon’s situation differs from the other states in that only nonresidential customers can shop, and that shopping is limited t o 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. re tail customers, 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-tim e selection from among competing eligible electric suppliers. Southern comments.

86Figure 4-1. U.S. Electric Power Industry, Average Retail Price of Electr icity by State, 1995

Cents per kWh

AL
5.5

AK
10.2 AZ
7.6 AR
6.3 CA
9.9 CO
6.1 DE
6.9

DC
7.1

FL
7.0 GA
6.6

HI
11.3 ID
4.1

IL

7.7 IN
5.2 IA
6.0

KS
6.6 KY
4.1

LA
5.8 ME
9.5

MD
7.1 MA
10.1 MI
7.1 MN
5.6

MO
6.3 MT
4.7

NE
5.4 NV
6.1 NH
11.7

NM
6.8 NY
11.1

NC
6.6 ND
5.7

OH
6.2

OK
5.6 OR
4.7

PA
7.9 RI
10.4 SD
6.2

TN
5.2

TX
6.1 UT
5.3 VT
9.5

VA
6.3 WA
4.1

WV
5.3 WI
5.4 WY
4.3 8 - <9 7 - <8 6 - <7 0 - <6 9 and above

U.S. Average
6.9 SC
5.7 CT
10.5 NJ
10.4

MS
6.0

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

Retail competition allowed customers to choose th eir electric supplier or marketer, but their electricity would still be delivered by the local distribution utility. 255 The idea was that
customers could obtain electric se rvice 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 market ers, any of which might charge lower prices than the local distribution utility. The ability to choose among alternative s uppliers was intended to reduce market power that local suppliers might otherwise have, so that customers might see lower prices from local suppliers. Also, it was thought that new suppliers might offe r innovative price and other terms to purchase electricity that could improve the qua lity of service.

In 1996, California enacted a comprehensive electr ic restructuring plan to allow customers to choose their electricity supplier. To accomm odate retail choice, Ca lifornia extensively restructured its electric powe r industry. The legislation:

(1) established an Independent System Operator (ISO) to operate the transmission grid throughout much of the state, so that all suppliers could access the transmission grid to serve their retail customers;

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 which generation supplier the customer chooses.

87(2) established a separate wholesale trading mark et for electricity supply, so that utilities and alternative suppliers could purchase elect ricity to serve thei r retail customers; (3) mandated an immediate 10 percent rate reduction for residential and small
commercial customers that did not choose an alternative supplier; (4) authorized utilities to collect stranded co sts related to generation investments that were unlikely to be as valuable in a competitive retail environment; and (5) implemented an extensive public benefits program funded by retail ratepayers. 256

Other states also enacted comprehensive retail competition legislation: New Hampshire (May 1996), Rhode Island (August 1996), Pennsylva nia (December 1996), Montana (April 1997), Oklahoma (May 1997), and Maine (May 1997). By January 2001, 22 states a nd the District of Columbia had adopted retail competition legisl ation. Regulatory commissions in four other states (including Arizona, which also enacted legislation) had issued orders requiring or endorsing retail choice for retail electric customers.

Several states – primarily those with low-cost electricity genera tion, 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 exer cise market power to
the detriment of customers. These states opted to keep traditional utility service.

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

 lower electricity prices than under tradit ional regulation through access to lower-cost power in competitive wholesale markets where generators compete on price and performance;  better service and more options for customers through competition from new suppliers;  innovation in generating technologies, grid management, use of information technology, and new products and services for consumers; and  improvements in the environment through disp lacement of dirtier, more expensive generating plants with clean er, cheaper natural-gas-fire d and renewable generation.

Under the restructured model, legislatures a nd regulators affirmed their support for making electricity available to all custom ers at reasonable rates, with con tinued safe and re liable service and consumer protections under regulatory ove rsight. Boxes 4-1 and 4-2 describe the Pennsylvania and New Jersey legislatures’ fi ndings and the expected results of retail competition.

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 competition might increase the cost of capital for new generation and tra nsmission projects. PSC Wisconsin Comments (2) at 3.

88Box 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 previous ly had been regulated as natural monopolies. (2) Many state governments are implementing or studying policies that would create a competitive market for the generation of electricity. (3) Because of advances in electric gene ration technology and federal initiatives to encourage greater competition in the wholesal e 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 affordable transmission and distribution is ava ilable at levels of reliability that are currently enjoyed by the citizens and businesses of this Commonwealth. (4) Rates for electricity in this commonwea lth are on average higher than the national average, and significant differences exist among th e rates of Pennsylvania electric utilities. (5) Competitive market forces are more effec tive than economic regulation in controlling 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

(6) Ensure that rates for non-competitive pub lic utility services do not subsidize the provision of competitive services by public utilities; . . .” (5) Maintain traditional regulatory authorit y over non-competitive energy delivery or other energy services, subject to alternative forms of traditional regula tion authorized by the Legislature; (4) Ensure universal access to affordable and reliable electric power a nd natural gas service; (2) Place greater reliance on competitive market s, where such markets exist, to deliver energy services to consumers in greater variety and at lower cost than traditional, bundled public utility service; . . . (1) Lower the current high cost of energy, and improve the quality and choices of service, for all of this State's residential, business and institutional consumers, and thereby improve the quality of life and place this State in an improved competitive position in regional, national and international markets; Box 4-2 Findings of the New Jersey Legislature

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

89C. Meltdown and Retrenchment

From late spring 2000 and into the spring of 2001, California experien ced high natural gas prices, a strained transmission system, and gene ration shortages (due to hydro shortages and operating restrictions) that resulted in blackouts. Wholesale electricity pr ices soared during this time. Existing state law had cappe d residential “provider of last resort” (POLR) service rates at levels that were soon below the market pri ce for wholesale electric power. After a large investor-owned utility declared bankruptcy because it was unable to increase its retail rates to cover high wholesale power prices, the state stepped in to buy elec tricity on behalf of two of the
state’s three IOUs. 258 California eventually suspended retail competition for most customers while it reconsidered how to assure adequate electric supplies and continuation of service at affordable rates in a competitive wholesale ma rket environment. Although that suspension continues today, 12 percent of lo ad in the state is supplied by alternative suppliers, some additional consumers remain eligible to switch to alternative suppliers, and new initiatives for municipal aggregation are being pursued. 259 Box 4-3 describes Califor nia’s role in purchasing electricity and the all-time-high pri ces it paid, and continues to pay.

Box 4-3 California’s Electricity Purchas es at All-Time-High Prices

In 2001, California spent over $10.7 billion to pu rchase electricity on the spot market to supply customer’s daily needs. The stat e also signed long-term contracts worth approximately $43 billion for10 years. These contracts represented about one-third of the three utilities’ requirements for the same period (2001–2011). Viewed with the benefit of perfect hindsight, the state ente red these long-term c ontracts when prices were at an alltime high. Future prices hovered in th e range of $350-$550 per MWh during the time California negotiated its long-term contracts, and in April future prices peaked at $750/MWh as the state finalized its last co ntract. By August 2001, future prices had dropped below $100. Thus, as of May 2006, the st ate is obligated to pay well over market prices for at least five more years. See Southern California Edison.

The California experience sent ripple effects throughout the Western region and prompted
several states to defer or abandon efforts to im plement retail competition. No new states have adopted retail competition since 2000, and some st ates – including Arkansas and New Mexico – repealed retail competition plan s they previously had adopted.

Other populous states, such as Illinois, New Jers ey, New York, Pennsylvania, and Texas, moved ahead with retail competition. Some of these states ended, or are about to end, their POLR

258 See, e.g. , Cal. Atty Gen. White Paper ; Federal Energy Regulatory Commission, Final Report on Price Manipulation in Western Energy Markets: Fact Finding Investigation of Potential Manipulation 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/ne w.items/d02828.pdf.

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

90service rate caps and will soon purchase wholesal e supplies for POLR service at market prices (although several of these states are developing approaches to sl ow the adjustment to marketbased procurement). States such as New York and Texas, which have adjusted POLR prices to approximate market rates on an ongoing basis, do not face a potentially significant increase in POLR service prices.

As shown in Figure 4-2, 16 states and the District of Columbia have restru ctured at least some
electric utilities in their states and allow at least some retail customers to purchase electricity directly from competitive retail suppliers. Restructured states as of April 2006 include Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Or egon, Pennsylvania, Rhode Island, Texas, and Virginia, as well
as the District of Columbia.

Figure 4-2. United States Map Depictin g States with Retail Competition, 2003

Restructuring Suspended Restructuring Delayed

Restructuring Active Restructuring Not Active

AL

AK AZ AR CA CO DE

FL GA

HI ID

IL IN IA

KS KY

LA ME

MD MA
MI MN

MO MT

NE NV NH

NM NY

NC ND

OH

OK OR

PA RI SD

TN

TX UT VT

VA WA

WV WI

WY

SC CT

NJ

MS DC

Source : 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 competiti on in mind, the Task Force examined seven states in depth. These “profiled states” – Illinois, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, and Texas – represent the diffe rent approaches 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 options and services often is limited. Development of retail competition has been impeded to a considerable extent by the

91fact that several states still have capped resident ial POLR rates. C&I customers generally have more choices in both suppliers and of custom ized services, than do residential customers. 260 However, most large C&I customers do not have the option to take POLR service at discounted, regulated rates. Alternative s uppliers may find C&I customers to be more attractive because the ratio of sales to marketing costs is often perceived to be higher for these customers.

This section reviews the status of retail competit ion in the profiled states , with an emphasis on entry of new suppliers, migration 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 entry decisions by alternative suppliers. Lessons lear ned from the use of POLR that ma y assist states as they decide
how to structure future POLR service are included.

1. States Have Allowed Distant Supplie rs to Access Local Customers and Have Encouraged Distribution Ut ilities to Divest Generation

Each profiled state adopted measures to encourag e entry of new suppliers to compete with the incumbent utility. Each adopted policies to al low suppliers other than the local distribution utility to gain access to retail cu stomers by requiring the utilities to join an ISO or an RTO. As discussed in Chapter 3, larger geographic markets for wholesale electricity enable retail suppliers and marketers to buy generation supplies from a wider range of local a nd distant sources (e.g., neighboring utilities with excess generation, independent power producers, cogenerators, etc.). Even if no new generation facilities are built, independent operation and management of the transmission grid increases retail customers’ choices and makes it more difficult for local
generators to exer cise market power.

Some states, including Massac husetts, New Jersey, and New York, ordered or encouraged utilities to divest generation a ssets to independent power produc ers (IPP) to eliminate possible
transmission discrimination or to secu re accurate stranded cost valuations. 263 Although these divestitures generally did not requ ire a utility to sell its genera tion assets to more than one company to eliminate the potential for the ex ercise of market power, generating facilities frequently have been sold to more than one IPP. 264 In other states, such as Illinois and

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

261 The degree to which customers switch to alternative 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 service provider is obstructing switching, or that certain features of regulation (including lack of in formation about the retail choic e process and belowmarket pricing of POLR service) are discouraging entry and activ e consumer shopping for electricity service. Another way to ga uge the success of retail competition policy is to survey c onsumers about their awareness of retail c hoices and perceptions of the difficulty o f switching between suppliers. However, surveys are expensive and results are not ava ilable systematically. More ge nerally, consumers can obtain t he benefits of competition if existing competition, entry, or the threat of entry prev ents incumbent suppliers from exercising market power ma nifested in the form of higher prices, lower product quality, or reduced innovation. In this sense, retail competition could be effective even without any switching to alternative supplie rs. NASUCA comments (2).

262 There is no reason to believe, however, that retail competition in this market will not functio n 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 Po wer Regulation 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 been volatile since thes e 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 location of the asset on the transmission grid.

92Pennsylvania, several utilities voluntarily sold or transferred generation assets to unregulated
affiliates. 265

As a result of these divestitures, regulated dist ribution utilities in prof iled states operate fewer generation plants than in the past . Distribution utilities that are required to serve customers must purchase generation in the wholesale market to serve their customers. Table 4-1 shows the amount of a state’s generation ope rated by the state’s utilities (i .e., not operated by IPPs or as combined heat and 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 York 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 th e 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 share any one generati on supplier can hold in a region, to provide opportunities for other suppliers to enter. 266 Still others, such as New York, helped organize introductory te mporary discounts from altern ative suppliers, thus providing customers an incentive to try out these new suppliers. 267

2. Alternative Suppliers Serving Retail Customers and Migration Statistics

Many generation suppliers serve large industrial a nd large commercial customers in the profiled states. For example, in Massachusetts, over 20 direct suppliers pr ovide service to C&I customers, along with over 50 license d electricity brokers or marketers. 268 However, only four active suppliers serve resident ial customers in the state. 269 In New Jersey, C&I customers can

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#Licensed%20Competitive%20Suppliers%20and%20Electricity%20Brokers.

93choose among nearly 20 suppliers, but residentia l customers only have a choice of one or two competitive suppliers. 270

Texas and New York have more options for resi dential customers. In Texas, residential customers can choose from approximately 15 suppliers. 271 In New York, between six and nine suppliers offer services to residential customers in each service territory. 272 With the notable exception of the Ohio municipal aggregation prog ram described in Box 4-4, few if any suppliers have provided continuous service to residential cu stomers in the other profiled states or in other retail competition states prior to the e nd of the respective transition periods.

Box 4-4 Customer Choice through Municipal Aggregation in Ohio

In New York, Texas, and most other states , retail customer switching occurs primarily through individual customer decisions to pick a specific alternative reta il supplier. In Ohio, however, most switching activity has occurred through aggregations of customers seeking a supplier under the statewide “Community C hoice” aggregation option. The Ohio retail competition law provides for municipal referend ums to seek an alternative supplier and allows municipalities to work together to find an alternative supplier. The largest aggregation pool, the Northeas t Ohio Public Energy Council, has 100 member communities and served approximately 500,000 residents at its peak. The Ohio program allows individual customers to opt out of the aggr egation. In most othe r states, aggregation programs require customers to specifically opt in to participate. Participation rates generally are much higher in opt-out than in opt-in pr ograms. (NOPEC recently had to contract for supply with an affiliate of the distribution util ity after the original supplier withdrew from the market).

The percentage of residential customers switching from the POLR service to an alternative competitive supplier is greatest where there are more availabl e generation suppliers. For example, in Massachusetts, 8.5 percent of reside ntial customers had migr ated to a competitive supplier as of December 2005. 273 Approximately 41 percent of large C&I customers switched to alternative suppliers, representi ng 57.5 percent of the C&I load. 274 In states with several

270 New Jersey Board of Public Utilities, List of Licensed Suppliers of Electric

, available at http://www.bpu.state.nj.us/ho me/supplierlist.shtml. For example, in the Connectiv territory, th ere are 18 C&I suppliers and only one resi dential supplier. Eighteen suppliers serv e 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/. Th e NYPSC reports that this range has move d to between 6 and 16 alternative supplier s, and the agency expects the number and variety of services offered by a lternative suppliers to increase as New York State moves forward with retail competition. NYPSC comments (2). Some listed suppliers may not be actively marketing to residential customers. Public Utilit y 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.

94suppliers serving residential cust omers, higher percentages of resi dential customers switched to a new supplier (e.g.

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

3. Retail Price Patterns by Type of Customer

Figure 4-3 shows average revenues pe r kilowatt hour for all customer 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 have been higher than the national average, wh ile 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 per kWh for Retail Customers, 1990-2005

Profiled States and National Average

Average Electric Revenues per kWh

for All Customer Sectors 1990-2005

- 2.00 4.00 6.00 8.00 10.00 12.00 14.001990199119921993199419951996199719981999200020012002200320042005Cents per kWh US

Texas

New York
Pennsylvania
New Jersey

Massachusetts

Illinois
Maryland

Source : EIA Form 861 data, and Monthly Electricity Report for averag e electric revenues per kWh all s ectors, all retail providers.

a. Residential and Commercial Customers

It is difficult to draw conclusions about how comp etition has affected reta il prices for residential
customers in states in which a s ubstantial share of such customer s continues to take service under capped POLR rates (e.g., Maryland, Illinois, Pe nnsylvania, and Texas). Comparisons of regulated prices shed little light on price patterns resulting from retail competition.

POLR prices have increased recen tly in states in which residen tial rate caps have expired. In New Jersey, residential rate caps on POLR servi ce expired in the summer of 2003. Since then,

275 See infra Texas profile, Appendix D. There likely is a “chicken-or-egg” problem a bout whether more switching over time is attributable to a prior increase in suppliers or vice-vers a (or whether both effects interact).

95the state has conducted an internet auction to procure POLR suppl y of various contract lengths (one- and three-year contracts) . The state holds annual auctio ns to replace suppliers with expiring contracts and to acquire additional supply. Rates for the generation portion of POLR
service were flat in 2003 and 2004 after adjusting for deferred char ges, 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 generation portion of its POLR service on the price of supply procured in wholesale markets through fixed-priced, short-term (three- or six-month) supply contracts. Rates for the generation portion of POLR service in the Bost on Edison (north) territo ry 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 fixed price POLR service also sheds little light on price patterns. A number of stat es have revised their POLR policies for large customers. Their POLR price for generation is a pass-through of the hour ly wholesale price for electricity plus a fixed admini strative fee. For example, Maryland, New Jersey, and New York have adopted this type of POLR pr icing for large industrial customers. 278 Many customers have switched to alternative suppliers in these states.

Large industrial customers describe d how their rates have increased since the beginning of retail competition. 279 Some commenters suggest ed that the Task Force s hould compare prices of a utility operating in a state that did not implemen t retail competition against prices of the same 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 incr eased them. As a result, a price comparison
between two states for a class of customers w ould conflate competition and cross-subsidization effects. Transmission congestion also may affect access to different generators (with low or high prices), so that comparing two states as if th ey were in the same physical location would be misleading. The timing of rate adjustments may di ffer between states, so that a single snapshot of rates would show a lower price in one state at one poi nt 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. Fina lly, some states may defer recovery of costs, whereas other states choose not to. Thus, w ithout accounting for these and other factors, a

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 Barbose, Charles Goldman, a nd Bernie Neenan, The Role of Demand Response in Default Service Pricing , 19:3 ELEC. J. 64 (Apr. 2006) [her einafter Barbose et al.].

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

280 Portland Cement comments; Lehigh Cement comments.

96simple price comparison between two states ma y not reveal whether retail competition has benefited customers. At this point the Task Force does not have sufficient data to provide a definitive explanation of price differences between states. 281

4. Results of Efforts to Bring Accurate Pri ce Signals into Retail Electric Power Markets

There is mixed evidence concerning the degree to which retail competition has resulted in efficient price signals to customers. Resident ial POLR service rate caps have not increased customer exposure to time-based rates. 282 In contrast, real-time pr icing is the POLR service available to the largest customers in New Jersey, Maryland, and New York. 283 The shift to realtime pricing has been eased by technical adva nces in metering that have increased the sophistication (and decreased the prices) of mete rs that record the vol ume of consumption in
each small block of time. 284

Commenters argue that POLR rate structure can si gnificantly affect customer response to price, especially among larger customers. A broad sp ectrum of utilities, stat e regulators, and ISOs argue that variable rates permit customers to react to price changes by enabling them to see clearly how much they can save. 285 The experience of the larges t customers in National Grid USA’s New York area suggests that customers using real-time prici ng demonstrate price sensitivity. 286

In states with traditional cost-based regulation, utilities have used various incentives to induce customers to reduce consumption when demand is high or transmission is congested (e.g., hot summer days). In other instances, such as in New York State, ISOs have successfully implemented demand response programs available to retail customers. In some instances, retail competition has discouraged these traditional types of programs, particularly when distributing utilities are no longer res ponsible for POLR service. 287 When distribution util ities are required to maintain a portfolio of resources to meet POLR loads, they ma y no longer value these types of programs as a resource to ensure reliable and e fficient grid operation. Shifting the responsibility of grid operation and reliability to regional orga nizations such as ISOs/RTOs further decreases
distribution utilities’ in terest in these products.

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. P ublic 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 customer s, rather than just the cus tomers still taking POLR service, see Barbose et al.; Hopper, et al. The authors report that although most customer s 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 repor t that the proportion of customers accepting hourly price aspects in their supply contract s – over 90 percent – is far higher when the price is set on t he day-ahead spot market. The authors believe that the higher participation rate s in hourly pricing under this circumstance are due to the early warning that customers get in the day-ahead market a nd the customers’ consequently greater ab ility to respond to these pricing signals.

284 Direct Energy comments (2) at 7; Mercatus Center comments at 2; CP Consulting comm ents 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 ot her uses, particularly 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; EEI comments; IURC comments; NYPSC comments; ISO-NE comments.

286 National Grid comments.

287 For example, Pepco stopped actively supporti ng its air-conditioner direct load control program when it divested its generation assets.

975. Retail Competition in Rural America

Many rural areas are served by small non-profit elect ric cooperative and public power utilities. They were among the last to be electrified and the most costly to serve. Customers are scattered over large geographic areas, with residential a nd small loads predominating. Although electric distribution cooperative service ar eas have been opened to competition under some state plans, no state has required municipal a nd/or public power utilities to implement retail competition.

Eight states with retail competition – Arizona, Delaware, Maine, Maryland, Michigan, New Hampshire, Pennsylvania, and Virginia – requir ed cooperatives to implement retail competition in their service territories. With the exception of Pennsylvania, state public utility commissions regulated electric cooperatives’ re tail rates and approved their competition plans. Pennsylvania left the design and implementation of retail competition to the individual distribution cooperatives. The Pennsylvania Public Uti lity Commission is responsible for licensing competitive retail providers in c ooperative service territories. Cooperative retail competition plans have been fully implemented in Delawa re, Maine, New Hampshire, Pennsylvania, and Virginia. Some aspects of cooperative retail competition plans are still in administrative or judicial 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 customers.

Other states – including Illinois, Montana, New Jersey, Ohio, and Texas – allow electric cooperatives to opt into retail competition on a vo te of their boards or membership. None of these states regulates cooperatives’ rates or se rvices. They leave the design and implementation of retail competition to the i ndividual cooperative. The state li censes competitive providers, but providers must enter into agreements with the co operative to begin enrol ling retail customers. A handful of individual cooperatives in Montana and Texas elected to provide retail competition options for their members.

It is difficult to track the progress of retail co mpetition in rural areas because most states do not make switching data available or maintain up -to-date information on active suppliers in cooperative service te rritories. Nevertheless, the Task Force determined that there were few alternative competitive providers, if any, for residential customers of rural systems open to retail competition. No competitive providers were enrolling customers in cooperative systems in Arizona, Maine, Maryland, New Hampshire, Pe nnsylvania, or Virginia in May 2006. In Delaware and Montana, competitive providers had been licensed to serve cooperative customers, but it is unclear whether any is currently enrolling customers. Licensed provider and switching information for Texas cooperati ves is not yet available.

E. POLR Service Price Sign ificantly Affects Entry of New Suppliers

Each profiled state required loca l distribution utilities to offer a POLR service for customers who do not select an alternative 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 increas es or decreases in wholesale prices.

98Generation accounts for the most si gnificant portion of the POLR se rvice price. This component
constitutes the amount that the customer avoids paying to the distribu tion utility by choosing (and paying) an alternative provi der. Many states denote this as the “price to beat” or the “shopping credit.”

Commenters say that the price of POLR service is the most signi ficant factor affecting whether new suppliers will enter the market and compete to serve customers. 288 The POLR price is the price against which new suppliers, including unre gulated affiliates of the distribution utility, must compete if they are to attract customers. 289 The frequency with which the POLR service price changes, among other featur es of POLR service, can af fect the competitive dynamics between different suppliers.

1. Contrasting Visions of POLR Service

The comments revealed two visi ons of how POLR service shoul d function in the long term. 290 In the first vision, POLR is a long-term option fo r customers. Under th is view, POLR service closely approximates traditional utility service, but in a market place with other sources of supply. Under this vision, POLR service often features prices that are fixed over extended periods. Government-regulated PO LR service competes head-to-head with private, for-profit retail suppliers. 291 (An analogy would be the U.S. Post al Service providing parcel postage service in competition with for-profit package de livery services by United Parcel Service, DHL, and FedEx). Alternative suppliers may grow as they find additional approaches to attract customers, but POLR service will likely retain a substantial portion of sales, particularly to residential customers. This type of POLR servic e serves as a yardstick against which alternative suppliers compete. Most states have adopted this vision of POLR service. 292

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 Advocate identified several factors that depressed retail entry by supp liers to serve residential customers, including “the acquis ition costs associated with marketing progr ams to reach residential customers, the costs of serving such customers once acquired, and the rising prices for generation supply service in the wholesale market.” PA Consumer Advoca te comments at 3. The Maine Office of Public Advocate ec hoed these factors and also identified the “m iscalculation by some suppliers as to th e risks and rewards for retail electricity competition.” Maine Public Advocate comments at 3. The Industrial Consumers observed that reta il markets are not fully competitive because of insuff icient generation divestitures that left supplie rs with market power. ELCON comments at 2. Another factor identified by Industrial Consumers is the in ability of alternative supplie rs to gain access to necessa ry transmission services to serve their customers. ELCON comments at 6. Others customers suggested that the lack of uniform rules throughout every service territory hinders entry for suppliers. Wal-Mart comments at 13. Other commenters argue d that alternative suppliers need access to customer use data f rom utilities to be able to market to prospective customer s. Constellation comments at 43. Still others argued for no minimum stay requirement s at POLR and constrained shopping windows, which can dampen entry. RESA commen ts at 30-31; Strategic comments at 10; Wal-Mart comments at 1 3. The lack of entry in most states makes it di fficult for the Task Force to evaluate which 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 servi ce be provided or procured by the incumbent distribution utilit y, the task of providing or procuring POLR serv ice could be carried out by other entities. New Yo rk Companies comments (2). For example, it could be assigned to one or more alternative suppliers, awarded through a competitive bidding process, or assumed directly by the state utility regulator (as in Maine). In any case, the firm assigned to provide or procur e POLR service may be exposed to the risk that this responsibili ty will be unprofitable because costs and demand are vol atile or because state utility regulators impose costs on the provider of POLR ser vice (such as switching incentives) during the transition to retail customer choice. This risk can create financial difficulties for the distribution utility or another entity with this responsibility. New York Companies 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.

99In the second vision, POLR is a barebones, temporary service consisting of retail access to wholesale supply, primarily for customers that are between suppliers. In this vision, alternative suppliers serve the bulk of retail customers. They compete primarily against each other with a variety of price and service offeri ngs designed to attract different types of customers. This type of POLR service acts as a stopgap source of supply that ensures elec tric service is not interrupted when an alternative supplier leaves the market or is no longer willing to serve particular customers. Wholesale spot market prices, or pr ices that vary with each billing cycle, may be acceptable as the price for POLR service. 293 (A supply arrangement co mparable to this version of POLR service is the high-ri sk pool for automobile insurance operated in several states). 294 Texas and Massachusetts are current examples of th is vision of POLR servi ce, as is Georgia in its design for retail natural gas sales. 295

Some profiled states incorporated aspects of both visions of POLR service for different types of customers. For example, New Jersey 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 procur ement experience. Acco rdingly, some states determined they are more likely to quickly obta in the benefits of retail competition without additional help from state 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 design decisions involved pricing of the POLR, duration of the POLR obligation, and how to acquire POLR supply. Each of these can affect en try conditions that alternative suppliers face.
This section describes each of the decisions.

a. Pricing of POLR Service

The profiled states generally se t the POLR price at the regulat ed price for electric power prevailing before the onset of retail competition, less a discount. Discounts usually persist over a specified multi-year period. Assuming that comp etition generally lowers prices, one rationale for the discounts was to provide a proxy for the e ffects of competition on customers less able to quickly obtain such savings for themselves. The Illinois POLR service discount, for example, was developed to bring local prices into line with regional prices. When retail competition began, Illinois customers in areas with relatively low prices before customer choice did not receive discounts below the prev iously regulated rates. In contrast, customers in the

293 See, e.g. , RESA comments; Wal-Mart comments; Na tional Energy comments; SUEZ comments.

294 Most states have a mechanism by which high-risk drivers can obt ain insurance. Often insurers in a state are assigned a portio n of the pool of high-risk drivers based on each firm’s shar e of drivers outside the pool. AIPSO mana ges many of the pools and maintains links with individual state programs at https://www.aipso.com/adc/De sktopDefault.aspx?tabindex=0&tabid=1. Si milar plans are available in many states for individuals with prior health conditions w ho 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 ended its rate-capped POLR service in February 2005 ( See infra Massachusetts profile, Appendix D). In the Atlanta Gas Light distribution territory, th e distribution utility petitioned the Georgia Public Service Commission to w ithdraw from retail sales. In Georgia, under the amende d Natural Gas Competition and Deregulation Act of 1997, a customer who does not choose an alternative supplie r is randomly assigned an alternative supplier. Discussion a nd documentation about the Georgia natural gas retail competition program are available at h ttp://www.psc.state.ga.u s/gas/ngdereg.asp.

296 See infra New Jersey profile, Appendix D.

100Commonwealth Edison territory – the area with the highest cost-based rates – received 20 percent discounts to bring re tail POLR prices there into line with the re gional average bundled service prices prevalent prio r 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. So me states separated fuel costs from other cost components, because fuel costs ha ve been more volatile than other input prices. (Fuel costs are the largest variable cost com ponent and can be calculated for each type of generation unit on the basis of public information.) These factors also suggest that a generation firm has little control over its fuel costs once it has invested in generation. For example, Texas instituted twice-yearly adjustments in the POLR service (price to beat) price calculations. By adjusting POLR prices for changes in fuel cost s, Texas regulators have prevented the POLR price from slipping too far away from competitive price levels, thus maintaining the POLR price as a closer proxy for the competitive price. 298 If retail prices fall too far below wholesale prices, the POLR supplier may have financ ial difficulties, and alternativ e suppliers will be unlikely to
enter or remain as active retailers. 299

c. POLR Price and the Shopping Credit

When a retail customer picks an alternative supplier, the distributi on utility with a POLR obligation avoids the co sts of procuring generation supply fo r that customer. The distribution utility therefore “credits” the cu stomer’s bill so that the custom er pays the alternative supplier (rather than the utility) fo r the electricity supplied. 300 This avoided charge – the “shopping credit” – equals the regulated POLR service price. States have us ed two approaches to determine the level of the shopping credit. On e view is that the shopping cred it equals the avoided cost or the proportion of POLR procuremen t costs attributable to a depa rting customer. Maine, for example, estimated avoided costs on this basi s, with no additional estimated avoided costs. 301 This approach results in a lower shop ping credit and lower total POLR price.

An alternative perspective is that the distribution utility also avoi ds “adders” (costs that are in addition to avoided procurement costs), in cluding marketing and administrative costs. 302 This view results in a higher shopping credit and higher total POLR pr ice, creating “headroom” for

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 a bove market rates during periods of declining fuel prices. A single snapshot 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, capped POLR rates were substan tially below wholesale prices.

300 The distribution utility continues to charge the customer a delivery charge (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 at http://mainegov-images.informe.org/mpuc/staying_i nformed/about_mpuc/commissioners/ph-welch.pdf.

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

101potential entrants. In Pennsylvania, the POLR shopping credit included several other elements, such as avoided marketing and administrative costs. 303 Some observers attributed Pennsylvania’s early high volume of switching to the additional a voidable costs included in its shopping credit calculations. 304

d. The Multi-Year Period for POLR Service

States that implemented reta il competition also determined how long POLR service should
continue at a discount from prior regulated prices. This period generally corresponded to the distribution utility’s collection of stranded genera tion and other costs. In a competitive retail environment, utilities no longer were assured th ey could recover costs of all of their stateapproved generation investments. Most states f aced claims of stranded costs associated with generation facilities that were unlikely to earn en ough revenues to recover fixed costs once customers could seek out alternative, lower-price d retail suppliers. States allowed utilities to recover stranded costs through charges on dist ribution services that cannot be bypassed. 305

Each state that authorized the collection of stra nded costs had to determine these costs and the duration of the collection period. These decisi ons fundamentally alte red the electric power industry and were at the center of some of the most contentious issues state regulators faced. Some states (for example, Main e and New York) required some or all generation to be sold to
obtain a market-based determinati on of the level of stranded costs. 306 In other states, such as Illinois, utilities voluntarily di vested generation assets. As no ted above, the result of these divestitures is that generation no longer is primarily in the hands of regulated distribution
utilities. 307

e. Procurement for POLR Service

Because most distribution utilities no longer own generation to satisfy all of their POLR obligations, they took different approaches to acquire generation suppl y. For example, New Jersey utilities that offer residential POLR service acquire generation supply through three overlapping three-year contracts, with each cont ract covering approximately one-third of the projected load. 308 This “laddering” of supply contracts re duces the volatility 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 ways to hedge the volatility in short-term energy prices. For example, New York distribution utilities have long-term supply contracts with the purchasers of their generation assets (vesting contracts) based on pre-divestiture average generation prices. 310

303 Id.

304 Over time, the shopping credit in Pennsylvania faded in significan ce as the competitive rates incr eased relative 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.

102F. Observations on How POLR Service Policies Affect Competition

One of the most contentious issues state regulato rs currently face is how to price POLR service once rate caps expire. This situation is especia lly vexing for those states that had stranded cost recovery periods during which fixed POLR pri ces were substantially lower than wholesale prices. Rate caps expire this year in Delaware, Illinois, Ma ryland, Ohio, and Rhode Island, and
customers in those states that did not choose an alternative supplier face potentially substantial price increases.

Rapid increases in fuel prices in recent years – leadi ng to increases in wholesale prices – have made it difficult fully to discern best practices regarding retail competition. The price increases interacted dramatically with PO LR service rate caps, clouding the experiences most states have had with other retail competition issues. As a result, the range of e xperience regarding other aspects of retail competition is narrow, prim arily limited to what has occurred in New York, Texas (within ERCOT), the Duquesne distri bution area within Pe nnsylvania, Maine, Massachusetts (recently), and the large C&I cust omers in New Jersey, Illinois, and Maryland.
Because each state faces different electricity supply and demand conditions, it is not possible to recommend a single approach for all states considering retail customer choice. Nonetheless, given these limitations, the Task Force offers the following observations on what appears to work well (and not to work well) in retail customer choice programs.

 Minimum POLR Service: POLR service (or an equi valent provision) to serve customers of a supplier that has left the market, while the customer obtains another supplier, is the least intrusive form of POLR service, yet it is consistent with concerns about potentially life-threaten ing effects of unanticipated loss of electric service.

 Treatment of Different Cu stomer Risk Preferences: POLR service that goes beyond
short-term access to the wholes ale spot market involves providing a bundle of services that electricity marketers also can provide. States that embrace a more expansive version
of POLR service should r ecognize that this step may hamper the development of alternative suppliers. The economic rationale for taking this step usually is limited to trying to correct some identifiable and substant ial 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 PO LR service price cap that will
not distort retail electricit y markets and the associated development of effective competition. The best practice is to make fre quent adjustments to the cap (at least so as to reflect changes in fuel costs), or to ab andon the cap altogether and use an objective, competitive process to procure supply.

 Treatment of Different Customer Classes: Large customers are logical pioneers for retail choice because of their familiarity w ith energy procurement processes and because they are comfortable with decisions to ad just input use based on input prices. For smaller, less sophisticated customers, in cluding residential cu stomers, issues of

103awareness and access to compara tive pricing information should be addressed 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 more 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 information about how to compare availabl e choices and how to switch suppliers (including any constraints on switc hing). Texas maintains a well-organized website that appears to work well for re sidential price comparisons. New York’s program to encourage customers to try out al ternative suppliers that agree to offer a temporary discount appears to educate many re sidential customers effectively about the ease of switching, without subs idizing alternat ive suppliers.

 Customer Aggregation: Customer aggregation is an approach that can reduce percustomer search and switching costs and t hus generally can help to develop retail competition. Opt-out customer aggregations may be worth considering because they can minimize transaction costs without limiting customer choice.

 Entry: Entry is a key concept in retail electric ity competition. States should attempt to avoid rules that make entry more expensiv e or slower than is required to avoid fraudulent marketing activities. Areas to cons ider include registration fees and delays, costs and delays in interacting with the dist ribution utility (meteri ng, billing, treatment of receivables), security deposits for supp liers, rules regardi ng disconnecting retail customers for non-payment, and exit penalties.

1. POLR Service Price to Approximate the Market Price

The POLR service price must closely approximate a competitive market price if it is to provide economically efficient incentives for consump tion and supply decisions and thereby maximize welfare. This price will vary ove r time as supply and demand change. 311 If the POLR service

311 Because the marginal cost of supplying electricity varies over the course of the day 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 r egulation. Electricity prices under traditional regulation typically reflect average cost s for electricity and risk mana gement over extended periods. In a retail choice environment, alternative suppliers can offer a variety of risk management (hedging) le vels that range from full, immediate pass -through of wholesale spot market prices to fixed ra tes for extended periods. For a discussion of how much hedging is required to eliminat e portions of volatility, see Severin Borenstein, Customer Risk from Real-Time Retail El ectricity 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 ma nagement also can constitute efficient retail prices, although t hey contain a cost component associated with the risk manageme nt services. If POLR service prices beco me more volatile, a customer who prefers le ss risk will
have incentives to search for an alternative supplier that offers a price/risk tradeoff – slightly higher prices but less volat ility.

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 upstream vertical in tegration offer a preferable price/risk combination.

In general, so long as customers are served by alternative supp liers or upstream vertical integration 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 in terruptible service rates would allow more customers to improve the match between t heir risk preferences and their electric service. Industrial Coalitions comments (2) at 25.

104price does not closely match the competitive pr ice, it will distort consumption and investment
decisions 312 leading to an inferior allocation of resources. 313 Competitive market prices align consumers’ willingness to pay for a service with the marginal cost of providing it (where, in the long run, the marginal cost includes a competitive ra te of return on investments). This alignment leads to the most economically e fficient allocation of resources. 314

Experience within the profiled st ates shows that it is not easy to approximate the competitive price. Not only does the competitive price change when prices of inputs change, but the price also acts as an investment signal for new gene ration. The short-term competitive price for the electric generation component can move quickly and dramatically. Over the past several years,
the initial fixed discounts for POLR service have resulted in belo w-market prices or occasionally above market prices, but never at th e short-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 customers. 316 Firms with the POLR oblig ation can become financially distressed, as they did in Calif ornia 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 retail electricity price for changes in the prices of fuels used by generators (at the margin). This is more effi cient than using a fixed price as a proxy for the market price. Moreover, a POLR price that is adjusted only infre quently to incorporate underlying fuel price changes will usually be e ither above or below the competitive market price. 318 A fixed or infrequently updated price creat es incentives for customers to move back and forth from POLR service to alternative supplie rs, based on which offers a lower rate. This repeated switching may create additional costs fo r both POLR and alternativ e suppliers. It also can reduce the certainty about procurement quantiti es which suppliers need to make long-term supply arrangements. Including other identifiable cost components that fluctuate widely in POLR service price adjustments will increase th e likelihood that the POLR service price will be a reasonable proxy for the competitive price.

2. Lack of Market-Based Pricing Distorts De velopment of Competitive Retail Markets

A second issue arises when below-market POLR service prices persist during a period of rising fuel prices and correspondingly increasing wholesale s upply prices. In these circumstances,

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

313 The electricity industry has traditionally provided discounts or ot her forms of assistance to low-income families. States may need to examine
whether the level of this assistance shoul d be increased in response to price incr eases or greater price volatility. National Association of State Utility Consumer Advocates (2). Similarly, firms whose competitors are in areas with stable or declining prices or diminishing price volatility could face financial distress, just as if th ey experienced other types of increased or more volatile input costs relative to th eir rivals. Firms with electricity-intensive production processes are likely to be partic ularly sensitive to increased prices or price volatility. Al coa 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.

105customers are likely to experience a shock when POLR service prices are adjusted to reflect prevailing wholesale prices. This can create public pressure to continue th e fixed POLR rates at below-market levels. For example, some jurisdicti ons have considered a gr adual 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 customer s actually pay is usually deferre d and collected later from the POLR provider’s customers.

Although this approach reduces rate shock, it is likely to distort retail electric ity markets. First, a phase-in of the price increase continues to send inaccurate price si gnals and undermines incentives to reduce consumption. Second, it prevents entry of a lternative supplie rs by keeping
the POLR rate below market levels for additiona l years. Third, it results in higher prices in future years as the deferred revenues are recove red, so that customers who purchase electricity later are unfairly penalized (overcharged). Fourt h, if surcharges to pay for deferred revenues are not designed carefully, the charges can disrupt existing comp etition by forcing customers with alternative suppliers to pay for part of the deferre d revenues. Fifth, if wh olesale prices decline, customers 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 exit fees, POLR
service customers will be locked in to the POLR provider, so that competition may not develop even after POLR service prices rise to market levels. Finally, continued POLR service price caps in an environment of increas ing wholesale prices can endanger the financial viability of the distribution utility.

3. Different POLR Services Designed fo r Different Classes of Customers

Some states have differe nt POLR service designs for different customer classes. POLR service prices offered to large C&I customers generally entail less discounting fr om regulated rates or competitive market-based procurement and have b een based on wholesale spot market prices. Large C&I customers generally have a good understa nding of price risk and of the means and costs required to reduce that ris k. In addition, suppliers often can customize service offerings to the unique needs of these large customers. 319 With their larger loads, large C&I customers also may be better equipped to respond to efficient price signals than other classe s of customers. The result of this price response may be to improve system reliability and di ssipate market power in peak demand periods. 320

Large C&I customers have engaged in more swit ching to competitive providers in states that have implemented this division between POLR service for large C&I customers and for
residential and small C&I customers. 321 Many alternative suppliers reportedly have developed

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 file tariffs for mandatory real -time pricing (RTP) for large C&I customers. The order observed that “average energy pricing reduces customers’ awareness of the relationshi p between their usage and the actual cost of electricity, and obscures opportunitie s to save on electric bills that would become apparent if RT P were used to reveal varying price signals.” It further notes that “if a sufficient number of customers re duced load in response to RTP, besides be nefiting themselves, the reduction in peak period usage would ameliorate extr emes in electricity costs for all other customers.”

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

106customized time-of-use contracts for large C&I customers. 322 Moreover, the profiled states
show that a substantial number of suppliers activel y serve large C&I customers. Box 4-5 describes Oregon’s unique sign-up period for its nonresidential customers.

Box 4-5 Oregon’s Annual Window for Switching for Nonresidential Customers

Oregon has a unique process by which nonresiden tial customers of the two large investorowned distribution utilities in Oregon can switc h to an alternative s upplier. Nonresidential
customers must make their selections duri ng a limited annual window . The window must extend at least five days in duration, but usuall y a month is allowed. In addition to picking the alternative supplier, the la rgest customers must select a contract duration. One option specifies a minimum duration of five years, w ith an annual renewal after that. As of 2005, alternative suppliers were anticipated to serv e about 10 percent of lo ad in one distribution area and about 2.1 percent in the other. On e utility offered choice beginning in 2003, while the other began customer choice in 2005. Detailed descriptions are available at http://www.oregon.gov/PUC/electric_re struc/indices/O RDArpt12-04.pdf.

It is not necessary to expose all customers to time-based prices to introduce pri ce-responsiveness
into retail markets. 323 As a first step, customers who are the most price-sensitive could be exposed to time-based rates. Niagara Mohawk in upstate New York took this approach for its largest customers, as did Maryland and New Jerse y. California is consid ering setting real-time pricing as the default rate for medium-sized and larger C&I customers. Another means to introduce price responsiveness is to provide cust omers with voluntary time-based rate programs, along with assistance in equipment purchases or financing. For example, the New York State Public Service Commission requires voluntary time-of-use pricing for residential customers, and the Illinois Legislature requires that residentia l customers be offered real-time pricing as a voluntary tariff. Ideally, competition provides incen tives for suppliers to offer customers the mix of products and services that matche s their potentially diverse preferences.

4. Use of Auctions to Procure POLR Service

As discussed above, New Jersey has used an au ction process to procur e POLR supply for both
residential and C&I customers. Il linois proposed a similar auction fo r when its rate caps expire. Auctions may bring retail customers the benefit of competition in wholesale markets as suppliers compete to supply load. However, as discussed in Chapter 3, if there is a load pocket, an auction is unlikely to help this process, resulting in fewer benefits of competition.

322 See, e.g. , New York Companies comments; Alliance for Retail Energy Ma rkets comments; Constellation comments; PPL comments; RESA comments; NYPSC comments; Direct Energy co mments; Reliant comments; PA Office Consum er Advocate comments; Wal-Mart comments;
Commercial End-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).

1075. Consumer Awareness of Customer Choice and Engendering Interest in Alternative Suppliers

Experience with restructuring in other industries indicates that consumer switching from a traditional supplier to a new one can be a slow pro cess. It took 15 years before AT&T lost half of its long-distance service customers to alternative suppliers. 324 One reason retail electric competition could be slow to develop is that ex pected gains from learning more about market choices may be too small to make the learning worthwhile, 325 particularly for residential
customers with small loads. 326

Pricing of POLR service and helping consum ers compute the “shopping credit” may encourage more rapid development of retail competition by motivating residential consumers to search for
market choices. Some states that have low “sho pping credits” have had lit tle retail entry. Some states with retail competition have had subs tantial consumer education programs, including
websites with orientation mate rials and price comparisons. 327 These initiatives help promote learning about market alternatives.

New York is encouraging retail competition by helping organize temporary discounts from alternative suppliers and orde ring distribution utilities to make these discounts known to customers who contact the utility. 328 These efforts have increas ed residential switching and reduced prices, at least for the short term. E xperience indicates that once residential customers switch to alternative suppliers, they seldom retu rn to POLR service ev en after the temporary discounts expire. 329

324 James Zolnierek, Katie Rangos, and James Eisner, Industry Anal ysis Division, Common Carrier Burerau, Federal Communications Commission, Long Distance Market Shares, Second Quarter 1998 , at 19-20 (Sept. 1998), available at http://www.fcc.gov/Bureaus/Common_Carrier/Re ports/FCC-State_Link/IAD/mksh2q98.pdf; 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.

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 comments; Pepco comments; PA Office Consumer Advocate

comments.

328 In Case 05-M-0858, the New York State Public Service Commission adopted the “Power Switch” alternative supplier referral progra m (first developed by Orange & Rockland) as th e 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 Protection Board indicated that retail customer s who have participated in “PowerSwitch” are returning to POLR service at a rate of less than 0. 1 percent per month. The Board applauded PowerSwitch because it is completely voluntary and provi des assured initial savings to consumers.

108APPENDIX A
LIST OF COMMENTERS WHO RESPONDED TO TASK FORCE NOTICES REQUESTING COMMENTS*

* Two notices were published in the Federal Register as FERC Docket Number AD05-17-000: (1) Notice Requesting Comments on Wholesale and Retail Electricity Competition, issued on October 13, 2005, and (2) Notice Requesting Co mments on Draft Report to Congress on Competition in the Wholesale and Retail Markets for Electric En ergy, issued on June 5, 2006. The actual comments can be found at FERC.gov

The following parties filed comments in res ponse 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 Powe r Association (APPA)

Association of Large Distri bution Cooperatives (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 El ectric, LLC (CenterPoint)

Los Angeles Department of Water and Power (LADWP)

7-Eleven, Inc, Big Lots Stores, Inc., Crescent Real Estate Equiti es, Federated Department Stores, Hines, JC Penney, Wal-Mart Stores, Inc. (collectively, Commercial End-Users)

COMPETE, Electric Power Supply Association (EPSA), Alliance for Retail Choice (ARC)

109Connecticut Department of Public Utility Control (Connecticut DPUC)

Consolidated Edison Company of New York, Inc. and Orange and Rockland Utilities, 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 Chemistry Council, American Iron and Steel Institute, Coalit ion of Midwest Transmission Cust omers, PJM Industrial Customer Coalition, Illinois Industrial Energy Consumers, Industrial Energy Users - Ohio, and Multiple 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 Regulat ory Commission (IURC)

110Industrial Consumers: Portland Cement Associ ation, American Forest and Paper Association, American Iron and Steel Institute, California La rge Energy Consumers Association, Coalition of Midwest Transmission Customers, National Li me Association, PJM Industrial Customer
Coalition

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 Advocat e (Maine Public Advocate)

Midwest Independent Transmission System Operator Inc. (Midwest ISO or MISO)

Midwest Stand-Alone Transmission Companies

Mike Holly; Sorgo Fuels, Inc.

Mirant Corporation (Mirant)

Missouri Public Service Commissi on (Missouri State Commission)

National Association of Regulator y Utility Commissioners (NARUC)

National Association of State Utili ty Consumer Advocates (NASUCA)

National Energy Marketers Asso ciation (National Energy)

National Grid USA (National Grid)

National Rural Electric Coope rative 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 (N ew York G&E) and Rochester Gas & Electric Corporation (Rochester G&E)

North Carolina Utilities Commission, Public St aff - North Carolina Utilities Commission, and the Attorney General of the State of North Ca rolina (collectively, North Carolina Agencies)

111Northeast Utilities

NUCOR Corporation, Blue Ridge Power Agenc y, and the East Texas 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 Service Aut hority (together, Progress and Santee Cooper)

Public Utilities Commission of Ohio

Reliant Energy Inc. (Reliant)

Retail Energy Supply Association (RESA)

South Carolina Electric and Ga s Company (South Carolina E&G)

Southern California Edison Company (SoCal Edison)

Southern Companies (Southern)

Southwest Transmission Dependent Utili ty Group (Southwest Transmission)

Steel Manufacturers Associat ion (Steel Manufacturers)

Strategic Energy, LLC (Strategic Energy)

SUEZ Energy North America (SUEZ)

The Alliance of State Leaders Protecting Electricity Consumers (Alliance of State Leaders)

Transmission Access Policy Study Group (TAPS)

Transmission Agency of Northern California (TANC)

112Virginia State Corporation Commission

Wal-Mart Stores, Inc. (Wal-Mart)

WPS Resources Corporation (WPS)

Xcel Energy Services, Inc. (Xcel)

The following parties filed comments in re sponse 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 Ener gy Users-Ohio, Industrial Energy Consumers of Pennsylvania, and West Virginia Energy User s Group (collectively, I ndustrial Coalitions)

Community Power Alliance

COMPETE, Electric Power Supply Association (EPSA), 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)

113Duquesne Light Company (Duquesne)

Edison Electric Institute (EEI) a nd the Alliance of Energy Suppliers

Electric Power Supply Associat ion (EPSA), Independent Powe r Producers of New York (IPP NY), Independent Energy Producers of Maine (IEPM)

Electricity Consumers Resource Council (ELCON ) and American Iron an d Steel Institute, Association of Businesses Advocating Tariff Equity, Coalition of Midwest Transmission Customers, PJM Industrial Customer Coaliti on, Industrial Energy Users – Ohio, Multiple Intervenors, and Wisconsin Industrial Energy Gr oup, Inc. (collectively, Industrial Consumers)

Industrial Consumers: Portland Cement Associ ation, American Forest and Paper Association, American Iron and Steel Institute, California La rge Energy Consumers Association, Coalition of Midwest Transmission Customers, National Li me Association, PJM Industrial Customer
Coalition

ISO New England Inc. (ISO New England)

ISO/RTO Council

Mercatus Center; George Mason University (Mercatus Center)

Midwest Independent Transmission System Operator, Inc. (MISO)

Midwest Stand-Alone Transmission Companies

Mike Holly; Sorgo Fuels, Inc.

National Association of State Utili ty Consumer Advocates (NASUCA)

National Grid USA (National Grid)

National Rural Electric Coope rative Association (NRECA)

New York State Electric & Gas Corporation (N ew York G&E) and Rochester Gas & Electric Corporation (Rochester G&E)

OMB Professionals, Inc.

Pacific Gas & Electric Company (PG&E)

PJM Interconnection, LLC (PJM)

Portland Cement Association (Portland Cement)

114PPL Companies (PPL)

Progress Energy, Inc. and South Carolina Public Service Aut hority (together, 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 & El ectric Company, Wisconsin Electric Power Company, Wisconsin Public Power Incorporated, and WPS Resources Corpor ation (collectively, Wisconsin Load Serving Entities).

115APPENDIX B
TASK FORCE MEETINGS WITH OUTSIDE PARTIES

American Public Power A ssociation – 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 Asso ciation – 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 Service – November 9, 2005 National Association of Regulatory U tility Commissioners – October 27, 2005
National Association of State En ergy 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

116APPENDIX 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 a nd opponents of electric industry restructuring have armed themselves with these types of analyses to support their respective positions. It can be challenging to understand these studies’ sometimes 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 For ce 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 w ith 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 the Test The Benefits of Competition in America’s Electric Grid: Cost Savings and Operating Efficiencies ).

2) The benefits associated with some of the most significant motivations behind restructuring – the maintenance of system reliabili ty 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 le ft out of benefit assessments. “It is important that technically lim ited studies not be interpreted to suggest that impacts that they do not analyze are not si gnificant.” Eto at 21.

3) Existing methods and models used to estima te benefits are limited in what they can

measure. Many of these models also employ simplis tic and often misleading assumptions about market behavior. Improving the models used to derive quantitative be nefits is technically difficult – significant improvements would involve marrying the complexity of adequately modeling a 10,000+ bus transmission/generation syst em to the complexity of modeling realistic human behavior in markets. The capabilities of ex isting models are likely to be fairly static until computer technology advances enough to accommodate the memory needs associated with this complex modeling task.

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

1174) Modeling energy transmission and markets ne cessarily 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/exports, 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 studi es is that they often only estimate the benefits to society as a whole. Determining the distribut ion of benefits and costs - who wins and who loses, or who wins the most - is an im portant piece of the decision making puzzle. Unfortunately, it is much more difficult to measur e the distribution of benefits than it is total
social costs. Some efforts have been made in this direction wi th estimates of the end-use price impacts that restructuring has ha d or might have and with estima tes of benefits that individual participants in electricity markets might accrue ( See Appendix C: Beyond the Crossroads, the Future Direction of Powe r 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 assumptions, data sources, methods and
technical detail.

• Where econometric models are used, study wr ite-ups should provide regression methods and equations, goodness of fit measures, and resu lts 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.

118STUDIES OF BENEFITS IN THE US

Beyond the Crossroads: The Future Direc tion 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 counterf actual prices as an econometric function of fuel prices and return on the rate base, for residential and industrial customers in four geogr aphic territories based on 1992-1197
data. Scope of Inquiry Real price impacts on consumers of elec tric industry restructuring (study also addresses other restructuring 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 consumed over the past seven years than they would have paid if traditional re gulation 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/newsletter s/washingtonreportdetail.cfm?It
emNumber=14977&sn.ItemNumber=0

• Comments to Electric Energy Market Competition Task Force by NRECA, November 18, 2005

• H. Spinner, A Response to Two Recent Studies that Purport to Calculate Electric Utility Restru cturing Benefits Captured by
Consumers , ELECTRICITY JOURNAL, Volume 19, No. 1 (January/February 2006) at 42-47.

Electricity Markets: Consum ers Could Benefit from Demand Programs, but Challenges
Remain Region US Report Date August, 2004 Sponsor Report to the Chairman, Committee on G overnmental Affairs, U.S. Senate
Author/Contractor US GAO
Model/Method Reviewed the literature, analyzed industry and participant data, and
conducted interviews with state a nd federal officials (in FERC, the DOE , and the GSA), industry experts, representatives from utilities, and customers

Scope of Inquiry Examines the current and potential role for demand-response programs.

119Identifies (1) the types of demand-res ponse programs currently in use; (2) the benefits of these programs; (3) th e barriers to their introduction and expansion; and (4) where possible, in stances in which these barriers have
been overcome.
Period Studied
Conclusion Demand-response programs can benefit customers in regulated and restructured markets by improving ma rket 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-co mmissioned 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 Development 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 re sts largely on information gleaned from audit staff, FERC Form No. 1 da ta and interviews with and data responses from existing RTOs and Inde pendent System Operators (ISOs). Scope of Inquiry To estimate the cost of developi ng a Day One RTO that provides independent and non-discriminatory tran smission service and 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 investment outlay of between $38 million and $117 million and an a nnual revenue requirement of between $35 million and $78 million

.

• Cost overruns can result from changing 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/EventCale ndar/Files/20041 006145934-rto-costreport.pdf
Alternate Views • M. Lutzenhiser, RTO Dollars and Sense: Financial Data Raises

120Doubts About Whether Deregulat ion Benefits Outweigh Costs

, PUBLIC UTILITIES FORTNI GHTLY (December, 2004).

• Alliance of State Leaders Protecting Electricity Consumers, Commentary on FERC Staff Report on Day-1 RTO Cost (November, 2004), available at http://www.pacifier.com/~ppc pdx/Tx/Alliance%20Cost%20Study %20Report%2011-22-04%20FINAL.pdf

Impacts of the Federal Energy Regulatory Co mmission’s Proposal for Standard Market Design Region United States Report Date April 30, 2003 Sponsor US DOE Report to Congress
Author/Contractor In addition to DOE staff, participan ts included contractors who supported the modeling (GE Power Systems Energy Consulting, OnLocation, Inc) and those who supported the analysis (Charles River Associates, Neenan Associates, and Ken Rose of NARUC).
Model/Method DOE’s Policy Office Electricity Modeling System (POEMS) was used to assess wholesale and retail price impact s 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 National Energy Modeling System and TRADELEC) which forecasts trading volume and prices by NERC re gion. GE MAPS is an engineering
model used to simulate the effects of a security constrained LMP market model on transmission patterns. Scope of Inquiry Assess the impacts of implementing FE RC’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, increasing to 2 percent by 2020, relative to the nonSMD case.
3. The net benefit to all consumers of implementing SMD is estimated to be $1 billion/year for the first six years, dropping to $700 million by 2020. These figures are net of the $760 million estimated annual cost. (This implies total a nnual benefits of $1.46 to $1.76 billion, though this figure is not cited in the document).
4. Positive results are not consistent across regions – modeling suggests that end-use prices would rise in some regions and decrease in others.

Alternate Views Alliance of State Leaders Protecting Electricity Consumers, Commentary on DOE’s Study of St andard Market Design (June, 2003), available at http://www.pulp.tc/Alliance_Commentary_on_DOE_Study.pdf

121Impact 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 establishing a joint, common electricity market encompassing 26 states, the District of Columbia and the Canadian province of Manitoba (baseline is 2002 mix 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 through cross-CA hurdle rates,
then eliminates those hurdle rate s 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 (f rom 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 operations with resulting enhancements to inter-regional trade, congestion management, reliability and coordination, and improved pe rformance of Energy markets.
Period Studied 2002-2021
Conclusion * $1-$10 billion/year in system production cost savings * NPV of production cost savings over 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 costs (as compared with base case) assumed to be near zero .
Web Reference http://www.ksg.harvard.edu/hepg/ Papers/FERC%20ICF%20rtostudy_fin al_0226.pdf
Alternate Views • Comments of the California Electricity Oversight Board Proposed Pricing Policy for Effici ent Operation and Expansion Of the Transmission Grid, FERC Docket No. PL03-01-000 (March 13, 2003), available at

122http://www.eob.ca.gov/attachments/PL03-1-000Comments.doc

• Comments of the New England Conference of Public Utilities Commissioners on Electricity Ma rket Design and Structure,
FERC Docket No. RM01-12-000.

• Comment of the Staff of th e Bureaus of Economics and Competition and the Office of the General Counsel of the Federal Trade Commission on Electricity Market Design and Structure, FERC Docket No. RM01-12-000, http://www.ftc.gov/be/v020014.pdf

123STUDIES 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 f acilities 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 price, 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/D ownloads/SynapseReport.2005-10.ILCUB.RPM-Study--Higher-Costs-Windf all-Profits-for-Exelon.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 In ternational 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 costs, net of costs of participating in markets.
Web Reference http://www.midwestmarket.org/publish/Document/573257_ffe0fcee0f_- 7f570a531528/_.pdf?action=downloa d&_property=Attachment
Alternate Views See comments of Wisconsin Load Serving Entities to Draft EPAct 2005 Section 1815 Report on Competition – FERC Docket AD05-17 – 6/26/06

124STUDIES 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, Constellat ion Energy, Exelon Corporation, Mirant Corporation, NRG Energy, Inc ., 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 simulation 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 a nd foreseeable consumer benefits of competitive electricity markets.
Period Studied 1999-2003
Conclusion Wholesale customers in the Eastern Interconnection have realized a $15.1 billion benefit during the time peri od measured due to electricity competition. This benefit derives primarily from differences in the cost of generation construction under 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 Comparison of Wholesale Power Costs 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 a nnual prices: (1) the actual wholesale power costs (WPC) in the PJM market, and (2) prices in a scenario with economic regulation continued from th e mid-1990s to today so that the

125generation service costs (GSC) are the unbundled ge neration portion of the pre-restructuring 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/downl oads/reports/synapse-report-pjmelectricity-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 A pplication to the PJM Region (Sept. 22, 2003) (hereinafter CAEM Study).
Period Studied 1997-2002
Conclusion The CAEM Study’s quantitative resu lts fail to demonstrate any relationship between these price ch anges and the economic effects of restructuring.
Web Reference http://www.ksg.harvard.edu/hepg/Papers/Christensen.crit.restruct.mkts.in .pjm.03-Dec.03.pdf
Alternate Views See below: Estimating the Benefits of Rest ructuring Electricity Markets: An Application to the PJM Region

, available at http://www.caem.org/website/pdf/PJM.pdf

126Estimating the Benefits of Re structuring Electricity Markets: An Application to the PJM Region Region PJM Report Date October, 2003 Sponsor CAEM
Author/Contractor R. Sutherland, CAEM
Model/Method Measures decline in electricity prices during restructured period. Scope of Inquiry Estimates benefits of rest ructuring the electricity ma rket in the PJM region.
Period Studied 1997-2002
Conclusion Ultimate customers in the PJM region saved about $3.2 billion in 2002 from current restructuring efforts
Web Reference http://www.caem.org/website/pdf/PJM.pdf
Alternate Views Erecting Sandcastles From Numbers: The CAEM Study of Restructuring Electricity Markets (see above at http://www.ksg.harvard.edu/hepg/Papers/Christensen.crit.restruct.mkts.in. pjm.03-Dec.03.pdf)

Northeast Regional RTO Proposal: Anal ysis of Impact on Spot Energy Prices
Region Northeast Report Date April, 2002 Sponsor PJM
Author/Contractor PJM
Model/Method 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.
Period Studied Simulation year: 2001
Conclusion Net Benefits of $299 million. $188 to PJM <$22> to NYISO $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: Statistical / 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

127estimates. Scope of Inquiry Potential benefits from implementing an interregional real-time dispatch in the Northeast. (Resp onse 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

Mirant Study* Region Northeast Report Date September 2001 Sponsor Mirant
Author/Contractor Energy and Environmental Analysis, Inc.
Model/Method Statistical / econometric analysis using historic prices a nd flows. Looked
at unconstrained transmission to dete rmine correlation between prices. Assumes centralized dispatch woul d eliminate measured uneconomic
flows. Scope of Inquiry Potential efficiency benefits that could be achieved by creating a single market for electricity in the Northeas t. 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 regr ession 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 statistically significant price effects – rates

128in all states studied other than Maine increased an average of .8 percent per year prior to competition and th ey 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 market impacts and organizational impacts of establishing a Northeastern RTO (NERTO), including expected costs of implementation, savings from ma rket efficiencies, savings from operational consolidation.
Period Studied ?
Conclusion $220M/yr in 2005 $150M/yr in 2010

129STUDIES 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/Cont

ractor Internal Bonneville Power Administration staff report

Model/Meth
od Partially based on modeling conducted by Gr id West (see “Estimated Benefits of Grid West”) – Power World model used to derive benefits of control area consolidation and economic redispatch. Other analytical methods used to determine value of common regulation, reliability improvements, economic reserve markets, increased transmission usage, (measured in Gridview model),

etc. Scope of Inquiry Potential benefits of adopting proposed Grid West design as compared with
status quo.
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/re structuring/Docs/2005/benefit%20ass essment/BPA_Grid_West_B enefit_Assessment.pdf

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 West-managed contingency reserves range from $20 million to $73 million per

year.

• The estimated capacity cost savings associated with Grid West reducing the amount of regulating re serves range from $5 million to

130$26 million per year

• The estimated production cost savi ngs associated with Grid Westmanaged real-time energy balanci ng redispatch range from $41 million to $385 million per year

• The estimated annualized value to the region of avoiding cascading disturbances ranges from $27 million to $83 million per year.

• Avoiding momentary (less than 5 minutes) or sustained events (longer than 5 minutes but shorte r than 12 hours) related to noncascading transmission events has an estimated annualized value to the region ranging from $17 m illion 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 productio n 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, nonwires 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 with rate de-pancaki ng and more liquid operating reserve
markets
Costs : Applies apply the average cost/MWh of operating PJM, NYISO, ISO NE, CAISO and ERCOT to Grid West’s projected annual demand. Scope of Inquiry Study the costs, benefits and alte rnatives 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/externa l/documents/gri dwest/henwood_g ridwestfinal.pdf

RTO West Benefit/Cost Study
Region Northwestern US Report Date March 11, 2002 Sponsor RTO West
Author/Contractor Tabors Caramanis and Associates

131Model/Method GE MAPS Scope of Inquiry This study looked at the impacts th at removing pancaked transmission rates and sharing reserves 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 attr ibuted 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, spreadsheet analyses for others Scope of Inquiry Identify and quantify benefits and co sts to the regional electric power system that would occur as a result 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 anywhe re from $33 million to $328 million annually

• RTO Annual Costs of $63-$76 million

• Misc. qualitative benefits

132STUDIES 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 Peni nsular Florida consumers of Day1 Only RTO operation is $71 million over this period, while the quantitative start-up and operating costs of a “greenfield” Day-1 RTO is $775 million. Thus, the Day- 1 RTO configuration reflects an estimated net loss of $704 million.

• Whereas the quantifiable benef its 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 Ma rket Design principles, is also very significant at $1.25 billion.

• The GridFlorida Delayed Day-2 RTO could breakeven under the scenarios examined in this study if the net benefits from the qualitative factors and the cha nge in utility operational costs should be within the range of $285 million and $443 million over the 13-year forecast period.

• This study also indicates that the non-jurisdictional consumers would receive net positive bene fits of $798 million from the implementation of a GridFlorida Delayed Day-2 RTO while jurisdictional consumers would r eceive a net loss of $1.1 billion.

Web Reference http://www.icfi.com/Markets/Energy/ doc_files/gridflorida-rto-report.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

133b) Allocation of Energy MarketImpacts 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 costs and benefits that would accrue from
consolidated services and functions (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, implem entation of intra-SPP wheeling rates leads to a less efficient dispatch and thereby increases system-wide production costs in comparison with the Base case.

* The EIS market is estimated to provide considerably more benefits than costs, with the net benefits being $373 million 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 Arka nsas, 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 cont rol) 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.

134The Benefits and Costs of Re gional Transmission Organizat ions 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

135STUDIES 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, en ergy prices, and 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 st udy) and a nodal market design
Period Studied 2005-2014
Conclusion Did not draw single conclusion – “t he potential savings found in the Energy Impact Assessment, relative to the Implementation costs found in the Implementation Impact Assessme nt, 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/de fault.cfm?func=documents&intGroupI
d=83&b

136APPENDIX D
STATE RETAIL COMPETITION PROFILES 331

Illinois: Overview of Retail Competition Plan and Market Response

Administrator and Start Date : Customer choice in Illinois began in December 1997 with the
enactment of the Electric Service Customer Choice and Rate Relief Act of 1997 (HB 362). HB 362 required a phase-in of retail competition, with larger customers able to choose an alternate generation supplier earlie r in the transition. Specificall y, 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 p eak demand of 9.5 MWs or greater, and non-residential customers accounting for one-third of the remaining electricity use of their customer class. All other nonresidential customers were allowed to choos e a supplier as of December 31, 2000, and all residential customers as of May 1, 2002. 333 The mandatory transition period ends January 1,
2007. 334

The Illinois Commerce Comm ission (ICC) oversees the transition to competition in the electric industry. On January 24, 2006, the ICC appr oved proposals from Commonwealth Edison, the Ameren companies, Central Illinois Public Serv ice, Central Illinois Li ght Company and Illinois Power, to procure generation (f or retail customers who do not sw itch to an alternative retail supplier) 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 residential customers.

Services Open to Competition : Generation and metering services: The ICC promulgated rules that permit non-residential customers to choos e a meter service provi der other than the distribution utility.

The ICC permitted Commonwealth Edison to desi gnate 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 de fined as those services provided under special contract, not provided under tariff, and any tariffed service that th e ICC decides is competitive. A service is declared competitive only if it is o ffered by a provider other than the utility or its affiliate, to a defined customer group or area, at a competitive price, if the u tility is likely to or has lost business to the competitor, and if th ere is adequate transmission system capacity. 336

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, re gulatory authorities in each state and market participants shou ld be consulted for more detailed and up-to-date inform ation on state retail choice programs.

332 Average monthly maximum electrical demand on the electric utility’ s system during the 6 months e quals 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 the 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 at http://eweb.icc.state.il.us/e -docket/reports/view_file.a sp?intIdfile= 83392&strc=bd.

336 220 I LL

. C OMP

. S TAT . 5/16-113.

137Consumer Options : Consumers have two options for service:

(1) They may either remain with the uti lity as a bundled customer (i.e., receiving generation, transmission and di stribution services); or (2) They may choose to become a delivery se rvices customer (i.e ., they only take
distribution and transmission services from the utility). Delivery services customers may purchase generation services from another electric utility, from a competitive supplier, or from their own utility using the power purchase option (PPO). 337

The PPO is a transitional option that is provided by distribution utilities as long as they are recovering stranded costs from customers ( see Recovery of Stranded Co sts/Transition Costs). Under PPO service, a non-resident ial delivery services customer (such as an industrial customer) can purchase electric power from the utility at a price that reflects wholesale costs. These customers may then assign the power purchased unde r the PPO to an alternative 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 Licen sed to Provide Service : All suppliers wishing to provide competitive supply service must have a certific ate of service authority. In or der to receive certification, a supplier must show technical, fina ncial, and managerial capability. 338 A competitive supplier 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 ma ximum demand greater 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 the supplie r wishes to be certified to serve all eligible retail

customers.

In general, retail competition is much more active in the Commonwealth Edison territory than elsewhere in the state. In 2005, the number of active suppliers in each distribution utility’s territory ranged from zero for MidAmerican, to nine for ComEd. 339 Over the 2000 to 2005 period, the number of suppliers in creased in the AmerenCIPS servic e territory from 3 to 4. An alternative supplier entered the AmerenCILCO area for the first time in 2003 and the only alternative supplier left the MidAmerican area in 2001. The re tailers have focused only on nonresidential customers.

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.

138Retail Pricing Trends : As Table 1 shows, retail prices fo r the residential sector rose about 7 percent from 1988 to 1997. Commercial and industr ial prices rose by le sser amounts during that
decade. Prices for all classe s of customers declined after that decade through 2004, with the largest declines taking place in the residentia l sector due to mandatory rate reductions.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Residential 9.7 10 9.9 9.9 10.3 10.3 10 10.4 10.3 10.4 9.9 8.8 8.8 8.7 8.4 8.4 8.4

Commercial 7.5 7.8 7.8 7.9 8.1 8 7.7 7.9 8 7.9 7.8 7.4 7.2 7.4 7.5 7.3 7.5
Industrial 5.2 5.4 5.4 5.5 5.5 5.5 5.2 5.3 5.2 5.3 5.1 5 4.2 4.7 4.9 4.9 4.7
All Sectors 7.3 7.5 7.5 7.6 7.7 7.8 7.4 7.7 7.7 7.7 7.5 7 6.6 6.9 6.9 7.1 6.8 Table 1. Average Annual Price per KWh by Sector (nominal cents)

Source: Energy Information Administration

Price Changes for POLR Servi ce 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 residential rate compared to the residential rate for all large
investor owned utilities in the re gion at the time of th e restructuring legislation. The rationale behind the restructuring legislation was that co mpetition would tend to bring higher local rates down to the regional average, but there was un certainty about whether residential customers would obtain these benefits of competition in a timely manner because of the relatively high expected marketing costs associated with resi dential customers. No mandated retail price reductions were applied to POLR serv ice for non-residential customers.

There are six major utilities in I llinois with required residential rate reductions for customers that
have not selected an alte rnative supplier. Rate reductions were designed to bri ng residential rates in line with regional rates at the time of the re structuring legislation a nd are shown in Table 2. 340 The larger discount rates we re 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 pricin g” beginning on October 1, 1998; residential customers were able to elect real-time pricing beginning on October 1, 2000. 341 Real-

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

341 220 I LL

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139time pricing is defined as pricing which varies hour by hour for non-residential customers, and on a periodic basis during the day for residential customers. 342 The largest residential real-time pricing effort is a pilot program involvi ng 1,500 customers in the Commonwealth Edison territory operated by the Co mmunity Energy Cooperative. 343 Some non-residential customers may also have real-time pricing or other time of use rates, but st atistics are unavailable.

POLR Service Provider : Utilities must provide traditional, bundled service for those customers who choose not to shop for a competitive supplier. 344 The POLR (standard offer) price is the price for bundled service (i.e., service including gene ration, transmission, and delivery), which was set by the utility’s last rate proceeding, less the amount of any rate reduction 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 supplier are allowed to return to the uti lity after paying an administrative fee. A utility may require a returning customer with usage less than 15,000 kWh annually to stay with the utility for two years. 346

Switching Activity : The degree to which customers have switched to delivery service from bundled service varies greatly between distribution fr anchise territories and classes of customers. Table 2 provides the switching statistics for the largest utility franchise areas, separated by customer type, as of November 2005. As Table 3 indicates, the vast majority of switching activity is centered on the Commonwealth Edis on distribution territory (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 litt le switching outside of these three areas.

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.raabassociat es.org/Articles/Lieb erman_10.28.05.ppt#299.

344 220 I LL

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345 Id . at 5/16-108.

346 See 220 I LL

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140Table 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 large non-residential customers have switched much of their load to alternative suppliers. Sm all non-residential customers have been slower in switching to alternative s uppliers and the load served declined slightly in 2006, but the share of alternative suppliers co ntinue to be well a bove 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 Commonwealth Edison te rritory. Load in Commonwealth Edison accounts for approximatel y 96.5 percent of the load of IOUs. To be c onservative, it was assumed that there was no switching outside of Commonwealth Edison, he nce the Commonwealth Edison statistics for 2005 and 2006 were reduced by 3. 5 percent to create the proxy for the state-wide value.
Source : Illinois Commerce Commission

141Public 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 Depa rtment of Commerce and Economic Opportunity (DCEO).

Source : American Council for an Energy-Efficient Economy, Su mmary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005) availabl e at http://www.aceee.org /briefs/mktabl.htm. * In December 1997, PA 9D-551 was si gned. It provided funding for EE, RE , LI (although EE and RE are at low levels) using non-bypassable, flat monthly charges on cu stomer bills. (mills/kWh) 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 divested its fossil fuel generation plants.

State RTO Involvement : The restructuring legi slation required Illinois ut ilities 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 join ed an ISO, although it has received FERC authorization to engage an i ndependent transmission operator.

Generation Capability : 347 Prior to the restructuring legi slation (1997), util ities operated 97 percent of the generation capability in Illinois. By 2002, that figure dropped to 9.1 percent. The difference reflected the transfers and sales of ge neration assets to utility-affiliated entities and entry or expansion by independe nt power producers. Between 1997 and 2002, generation output
in the state increased from 135 million MWhs to 188 million 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 informa tion can be given to a supplier
without customer authorization. 348

Standardized Labeling : 349 “The 1997 Illinois restructuring law includes provisions for disclosing

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

348 220 I LL

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349 Department of Energy, Energy Information Administration, Disclosure Policies

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

142fuel mix and emissions by retail electricity suppliers. Final rules issued by the Illinois Commerce Commission (ICC) require retail suppliers to provide a bill insert to customers each quarter with a table and pie chart representing the s ources of electricity used in the previous year, beginning in January 1999. Suppliers must also provide a table showing total emissions of carbon dioxide, nitrogen oxides, a nd 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 a dopted a voluntary renewable portfolio standard target for bundled retail load st arting 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 enacted the Maryland Electric Customer Choice and Competition Act (SB 300) on April 8, 1999. The Act allowed for a threeyear phase-in approach to electric competiti on, but the Maryland Public Services Commission (PSC) allowed the utilities to st art electric competition all at once for all customers on July 1, 2000. The PSC oversees the customer choice program. 351

Services Open to Competition : Generation, billing, and metering.

Consumer Options : Customers may choose to remain w ith 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 cu stomers. The transition period ended for most consumers in Maryland as of July 2006. In other areas, the period ends in 2008.

Alternative Suppliers Licen sed to Provide Service : All alternativ e suppliers must be licensed by the PSC, and must show proof of technical a nd managerial competence, compliance with FERC requirements, and compliance with state and federal environmental laws. 352 A supplier must also give proof of financial integrity, 353 and the PSC assesses each competitive supplier’s application for a license on a case-by-case basis to determine whether a letter of guarantee, bond, or letter of credit is needed, and in what amount. 354 Registered suppliers and registered suppliers seeking additional customers are available on the Maryland PSC’s website. There are numerous registered and active suppliers for C&I customers. For residential customers, there are numerous registered suppliers but only two suppliers in three of the four major utility territories and none in the Allegheny Power territory before the end of the transition period.

Pricing Trends : As Table 6 shows, prices rose thr oughout the early 1990s for all sectors, then

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

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352 Id. at § 7-507(b).

353 Id. at § 7-507(c).

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

143declined until 2002. Prices rose in 2003 and 2004. With the end of the transition period for most residential and small C&I customers in the state, POLR service is scheduled to be priced at
market rates. Procurement contracts for POLR service starting in July 2006 are scheduled to result in price increases above existing POLR rates. For exampl e, the scheduled price increase
for customers in the BG&E distribution te rritory is reported to be 72 percent. 355 Because of
concerns about the size of the expected price increase, a numbe r of alternative proposals were developed to break the increase into smaller step s. Legislation just prior to the end of the transition period included deferrals of revenues and dismissal of the members of the PSC. At the time of this writing, litigation regard ing the latter provi sion is taking place. 356

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Residential 6.7 6.9 7.2 7.9 8.0 8.2 8.4 8.4 8.3 8.3 8.4 8.4 8.0 7.7 7.7 7.7 7.8

Commercial 6.5 6.6 6.7 7.0 7.1 7.2 7.2 6.9 6.8 6.9 6.8 6.8 6.6 6.4 6.3 7.0 7.6

Industrial 4.4 4.7 5.1 5.5 5.4 5.5 5.3 4.2 4.2 4.2 4.1 4.3 4.1 4.4 4.0 4.9 6.0

All Sectors 5.8 6.0 6.3 6.8 6.8 7.0 7.0 7.1 7.0 7.0 7.0 7.0 6.8 6.6 6.2 6.5 7.2 Table 6. Maryland Average Annual Price per KWh by Sector
(nominal cents)

S ource : Energy Information Administration

Price Changes for POLR (or Regulated) Service : Individual distribution utility plans vary, but a cap for all distribution utilities was put into effect through 2004 and then extended for two to four years. During the initial four years, distribution 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 corresponding amount, so that standard offer customers did not have an overall price increase. 358

POLR Service Provider : The distribution util ities provide POLR serv ice in their respective territories until the end of the transition period (or longer if the PSC extends the period). A distribution utility can procure the electricity for its POLR customers from any supplier, including an affiliate. Individual utility settleme nts require the utility to be the POLR service provider for the entire rate cap/freeze period (w hich varies in length per utility) unless the
Commission orders otherwise. POLR service rates and the resp ective terms were set in the individual utility settlements and have been in effect for the entir e rate cap/freeze period.

Recovery of Stranded Costs/Transition Costs : Distribution utilities were given an opportunity to recover all prudently incurred and verifiable ne t transition costs, subject to full mitigation. 359 Transition costs eligible for recovery include those that woul d be recoverable under rate-ofreturn regulation, but are not recoverable in a restructured el ectric market and costs that result

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

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. C OS ., § 7-505(d) (2000).

358 Maryland Public Service Commission, Maryland Electric Choice FAQ

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

359 M D

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144from the creation of customer choice. 360 Stranded costs have been recovered through a competitive transition charge, and may be reco vered over different lengths of time for each distribution utility. The PSC determines 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 proportion of cu stomers and load taking service from 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 switc hing 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 were combined into a single category.
Source : Maryland PSC

Public Benefits Programs : Funds for a Universal Service Program have been collected from all customers, and may not be asse ssed on a per kilowatt-hour basis. 361

Table 9. Maryland Public Benefits Programs

Research &

Develop. Energy Efficiency Low
Income Renewable Energy Total MD’s restructuring law was signed in Million $ Up to 1.0 34.0 34.0+

360 Id. at § 7-501(p).

361 Id. at § 7-512.1 (2000).

145Mills/kWh 0.51 0.51+

% revenue 0.82 0.82+
Admin. Utility State April 1999 including a $34 M/yr. tax funded
Universal Service
Fund. Additional
funds from individual utility
settlements. 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 : Divestiture of generation assets was not required, but functional, operational, structural or le gal separation of regul ated and non-regulated businesses or non-regulated aff iliates was required by July 1, 2000. 362 Distribution utilities must provide a code of conduct to prev ent their regulated service custom ers from subsidizing services of unregulated businesses. 363 A distribution utility can transfer any of its generation facilities or assets to an affiliate, if it desires. 364 Power generation affiliates can only sell power on the wholesale market, except for standard offer serv ice suppliers. Retail sa les affiliates may only buy power from the wholesale market.

State RTO Involvement : Maryland belongs to the multi-state PJM RTO.

Generation Capability : Prior to the restructuring legislat ion, utilities operate d 95.4 percent of generating capability in Maryland. By 2002, that figure dropped to 0.1 percent. Between 1997 and 2002, generation capability increased fr om 11,713 to 11,859 MW accompanied by growth in the proportion of dual fired capacity.

Usage of Customer Information : Customer information cannot be released without a customer’s consent, except for bill colle ction and credit rating purposes. 365 Customer lists containing names, addresses, and telephone numbers of custom ers may be sold to co mpetitive suppliers. If a distribution utility intends to release such a list, it must inform its customers, and advise customers of their opportunity to prevent di sclosure of their identifying information. 366

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 Service Commission, In the Matter of the Commission’s Inquiry into th e Provision and Regulation of Electric Service , Order No. 76110 (Apr. 25, 2000).

146Standardized Labeling :

• Content: Distribution utilities and competitive s uppliers must provide customers with a
uniform set of information on fuel mix and em issions. When actual da ta is unavailable, a regional average may be used. Labels have to include comparison of emissions and fuel mix to the regional average when information is available. 367

• Timing: Labels must be provided to customers every six months. 368

Renewable Energy Portfolio Standard : Maryland enacted a renewable energy portfolio 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 generation applies throughout the period.

Massachusetts: Overview of Retail Co mpetition Plan and Market Response

Administrator and Start Date : Electricity Restructuring in Massachusetts was initiated and is administered by the Department of Telecommun ications and Energy (DTE). Retail competition began March 1, 1998, in accordance with the rest ructuring legislation enacted November 25,
1997.

Services Open to Competition : Generation only. Metering an d billing are provided by the distribution utility.

Consumer Options : During the transition to competition, 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 s upplier was unable to provide services, consumers
then received a “default” service. Unlike most states that pr ovided POLR service, Massachusetts
named its POLR service as standard offer serv ice, and developed anot her regulated price for those customers for which their supplier no long er provided service (default service). The transition ended in February 2005, at which time st andard offer service was discontinued for all customers. Currently, customers who have not chosen a competitive supplier receive default
service from the distribution util ity that procures generation serv ices from wholesale suppliers. All retail customers are eligible for default service at any time, and may remain on default service indefinitely. Customers can also select an alternative supplier or be part of a group of customers served by an aggregat or. For purposes of this summ ary, default service will be referred to as a type of POLR service.

Alternative Suppliers Licen sed to Provide Service : All alternativ e 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 electricity suppliers including brokers and direct comp etitive suppliers. The roster

367 Maryland Public Service Commission, In the Matter of the Commission’s Inquiry into th e Provision and Regulation of Electric Service , Order No. 76241 (June 15, 2000). See section below on advertising restrictions for supplier re quirements to disclose pricing informa tion to customers.

368 M D

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369 M ASS

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. L AWS ch. 164, § 1F(1) (2001).

370 220 M ASS

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

147in February 2006 included 30 direct suppliers and twice as many brokers. 371 Ten of the suppliers
offered service to residential customers as did a comparable nu mber of brokers.

Pricing Trends : As Table 10 shows, prices for the re sidential and commercial sectors for the 1988 to 2004 period rose intermittently 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)

198
8 1989 199
0 1991 1992 1993 199
4 1995 199

6 1997 199
8 199
9 2000 200
1 2002 200
3 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

Commercia
l 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 : Massachusetts set a mini mum 10 percent reduction of the entire bill for all customers receiving standa rd offer service during the transition period. On September 1, 1999, the reduction increased to at least 15 percent, in order to adjust for inflation. These rate reductions applied to all distribution utilities. 372 Distribution utilities were authorized
to use securitization to meet the second rate reducti on effective September 1, 1999. 373

Standard Offer Service Provider : Standard offer service was provided until February 2005 for customers who had not chosen a competitive supp lier during the transition period. It was offered by the distribution utility, at rates which were se t in advance, but subject to some adjustments. 374

POLR (default service) is offered currently to customers who are not receiving service from a competitive supplier or aggregator. Former standa rd offer customers were offered POLR service
at the end of the transition. Th e price for POLR service is base d on the price of procuring it in the wholesale markets through fixed price short-te rm (three or six months) supply contracts. Distribution companies must pr ocure electricity for defau lt generation service through competitive bidding, although the DTE also may au thorize a competitive supplier to provide

POLR service. 375

POLR service prices cover the ener gy portion of the total bill. Dist ribution rates, taxes, and fees are additional. POLR service prices follow wholes ale prices. The default prices applicable to

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

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. L AWS ch. 164, § 1B(b) (2001).

373 Id. at § 1G(c)(2).

374 Id. at § 1B(b).

375 Id. at § 1B(d).

148January of each year for the northern portion of the Boston Edis on distribution 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 Service Prices in cents/kWh

Recovery of Stranded Costs/Transition Costs : The restructuring legislation provided for the recovery of stranded costs through a non-bypassable 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 : Customers can switch to or from POLR (default/basic) service. 378

Switching Activity : Table 12 shows the proportion of customers and load taking service from alternative suppliers in each utility distribution territory. In the Commonwealth territory, switching by residential customers is much higher than in any othe r area of the state. Much of this residential switching is attributable to co mmunity 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

376 Id. at § 1G(a).

377 Id. at § 1G(e).

378 David L. O’Connor (Commissioner, Mass. 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.

149Table 13 shows the state aggregate levels of switching from January 2001 to January 2006. Although all customers of Massachusetts distribution utilities were eligible for retail access as of March 1, 1998, switching remained at minimum leve ls for residential and small C&I customers. Larger commercial and industrial customers were more likely to switch, but sometimes switched back to default service if default prices fell belo w prices from alternative suppliers. Subsequent to February 2005, the proportion of load served by alternative suppliers increased 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 percent 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 Massachusetts Public Benefits Programs 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 in1996, 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 Transmission : The Massachusetts re structuring law required

150distribution utilities to divest their generation facilities (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 companies divested their assets to only one company.

State RTO Involvement : Massachusetts distribution utilities are within the footprint of the Independent System Operator of New England. Established in 1997, ISO-NE is responsible for managing energy markets and operating the transmission system in New England.

Generation Capability : 383 Prior to the restructuring legislat ion, utilities operate d 86.6 percent of generating capability in Massachusetts. By 2002, that figure dropped to 9.0 percent with 91 percent of generation belongi ng to independent power producers. Between 1997 and 2002, generation capability increased from 11,328 MWs to 12,159 MWs. Most of the new capacity uses natural gas. 384

Usage of Customer Information : The distribution utility canno t release proprietary customer
information to the affiliate without written consen t of the customer. Historical usage information will be provided to a supplier who has received customer authorization to initiate service. 385

Standardized Labeling : 386 “In February 1998, the Massachusetts Department of Telecommunications and Energy (DTE) issued fi nal rules (220 CMR 11.06) requiring electric retailers to provide customers with a standard disclosure label containi ng information on price, fuel mix, emissions, and labor characteristics of generating sources on a quarterly basis, beginning September 1, 1998. Suppliers must also issu e notices in all advertisements stating that
disclosure labels are availabl e upon request. Supply mix informa tion 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, nitrog en oxides, and sulfur dioxide emissions must be presented in a format comparing them to the regional averag e. Electricity providers are also required to report the percentage of power generated from sources that have union contracts with their employees and the percentage generated from so urces that use replacem ent labor during labor disputes. Suppliers must submit a report to the DTE annually containing "statements of verification by the ISO or an independent audito r." Massachusetts is wo rking with other New England states to develop a Generation Inform ation System that will supply data for implementing the disclosure requirement.”

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/electric ity/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 En ergy 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.

151Renewable Energy Portfolio Standard : Massachusetts 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 per cent increments. After 2009, the sta ndard is scheduled to increase 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 Di scount and Energy Competition Act provided for retail choice to begin August 1, 1999, but the New Jersey Board of Public Utilities (BPU) delayed the start date to November 14, 1999, to give utilities more time to modify their computer systems to interact with competitive retail suppliers in order to ease customer switching.

Services Open to Competition : Generation is open to competition. Work on a policy to permit competition for other customer services, 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 thei r own alternative supplier or join an aggregation of customers to c ontract with an alternative supplier. Customers received a “shopping credit” on their electric bill if they choo se an alternative supplie r. The shopping credit 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 alte rnate supplier and did not receive basic generation service from the distribution utility. 389

Customers that are not served by an alternative supplier receive Basic Generation Service (BGS), which is procured through periodic auctions. Large industrial customers with BGS are charged hourly prices that track wholes ale spot market prices. BGS for other customer classes is laddered on a three year cycle.

Alternative Suppliers Licen sed to Provide Service : New Jersey licensing standards provide that before receiving a license, new suppliers must s how financial integrity and maintain a surety bond of $250,000 for an initial license. For a renewe d license, suppliers have to maintain a bond at a level determined by the BPU. 390 Competitive suppliers must renew their licenses annually. The BPU website provides lists of alternative suppliers serving residential, commercial and
industrial retail customers. As of February 2006, activ e alternative supplie rs for residential customers range from 3 in the JCP&L territory, to 1 each in the Conectiv and PSE&G territories.
None offer service to residentia l customers in the Rockland territory. For C&I customers, there are 6 active suppliers in the Rock land territory and 19 or 20 in each of the other territories.

387 225 Mass. Code Regs. 14.00.

388 New Jersey Board of Public Utilities, In the Matter of the Electric Discount and Energy Competition Act of 1999 Cust omers Account Services Proceeding: Consolidated Billing, Customer Data Card, & Competitive Metering. Energy Consultant: Amendment to Customer Usage Information Process (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/e nergy/licensstands.pdf.

152Pricing Trends : As Table 15 shows, prices in all three sectors rose throughout the early part of the decade, reaching a peak in 1997. Prices fo r residential and commercial customers fell over the next several years before rising again, but not as high at the 1997 peak. For industrial customers, the same pattern is evident ex cept that the 2004 price exceeded the 1997 peak.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 Residential 9.8 10.1 10.4 10.8 10.9 11.4 11.5 12.0 12.0 12.1 11.4 11.4 10.8 10.2 10.4 10.7 11.2

Commercial 8.4 8.8 8.9 9.3 9.3 9.7 9.8 10.2 10.3 10.4 10.1 9.7 8.6 9.1 8.9 9.3 10.0

Industrial 6.8 7.2 7.4 7.7 7.7 8.1 7.9 8.2 8.2 8.1 7.9 7.7 6.8 8.3 7.7 7.5 9.0

All Sectors 8.5 8.8 9.1 9.5 9.5 10.0 10.1 10.4 10.5 10.5 10.2 10.0 9.1 9.3 9.3 9.5 10.9 Table 15. New Jersey Average Annual Price per KWh by Sector
(nominal cents)

Source: Energy Information Administration

Price Changes for POLR (Basic Generation Service) Service : All customer classes were granted an initial 5 percent rate reduction with an addition al reduction of at least 5 percent over the first three years of the transition period for POLR servi ce. This entailed a reduction of at least 10 percent from April 1997 levels. The reductions were from the distribution portion of the customer’s bill, so that even those customers th at switched to a new supplier obtained the price reductions. Retail price caps e xpired in the summer of 2003. 391

Beginning in 2002, New Jersey instituted the Basi c 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 basis... The Intern et BGS Auction, the first of its kind in the nation, was a descending clock auction...” 392 The bidding process for hour ly priced electricity is separate from that for fixed price service and th e latter involves three ye ar supply contracts that supply one third of the anticipated load of fixe d BGS. 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 winning bid prices, but indicated that the av erage residential bill would increase 12% to 13.7% as a result of increases in the 2006 component of the laddered prices.

POLR Service (BGS) Provider : Generation services were provided by the distribution companies for three years following the opening of retail competition. 393 Through BGS, all

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 Prices 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).

153customer classes are eligible for generation service overseen by the BPU. 394 Non-residential customers who return to BGS are generally requir ed to remain with that service for one year. 395 The 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 determined the recoverable amount of stranded costs, and distribution utilities recovered most strand ed costs over a maximum of 8 years, through a market transition charge (MTC). 396 All customers were be assessed this charge, except for off-grid customers who are exempt from exit fees.

Switching Restrictions and Minimum Stay Requirements : Customers can switch suppliers or return to their distribution company at any time , in accordance with the terms and conditions of their service agreement with th eir supplier or distri bution company. A customer may not be charged a fee for switching suppliers.

Switching Activity : The Table 17 provides the switching st atistics for large C&I customers in the major distribu tion 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
Non-Residential
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 residentia l 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 served by al ternative suppliers is and has remained very low with the peak of less than 6 percent in th e Conectiv (Atlantic) dist ribution area in December
2000. 397 As of December 2005, less than 1,000 residen tial customers had alternative 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

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.

154than 1 percent of small C&I customers had alterna tive suppliers, but they te nded to be larger than average customers because the shar e of load exceeds the share of customer served by alternative suppliers.

The POLR service available to la rge C&I customers in New Jersey is priced on an hourly basis, CIEP, that tracks the wholesale spot market pr ices. Hence, large C&I customers wishing to hedge price volatility must do so by selecting an alternative supplie r. New Jersey’s experience has been 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-reside ntial 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 Transmission : The restructuring act doe s not mandate divestiture,

155though the BPU may require a distribu tion utility to functionally sepa rate its generation assets to the distribution utility’s holding company or a re lated competitive business segment if there are
market concentration concerns. 400 Electric distribution utilities had three options: divestiture, structural separation or functiona l separation. Of the four major distribution utilities in New Jersey, two divested nearly all of their generation, one divested most (but not all) of its generation, and the fourth transferred its gene ration assets to an unregulated affiliate. 401 In August 2000, PSE&G transferred approximately 10,200 MW of its electric generating facilities to PSEG Power, LLC, an unregulated power genera tion affiliate. The BPU approved the sale of Rockland Utility’s generation assets to Southern Energy Affiliates in June 1999. 402

State RTO Involvement : New Jersey is within the multi-state PJM region, an RTO that includes Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia, a nd parts of Virginia. In recent years, the PJM RTO has significantly expanded its geographic sc ope to the West and South of its original f ootprint. The PJM region is responsib le for the operation of the region’s
wholesale electric market.

Generation Capability : 403 Prior to the restructuring legislat ion, utilities operate d 81.2 percent of the generation capability in New Jersey. By 2002, that figure dropped to 6.8 percent after divestitures, transfers, an d entry of new generators. Between 1997 and 2002, generation capability in the state increased from 16,855 MW s to 18,384 MWs, an increase of 9.1 percent . Nearly all of the increase was in dual fueled ge nerators built by IPPs. During the 1993 to 1997 period, generating capability had increased by less than 3 percent .

Usage of Customer Information : Neither power suppliers nor dist ribution companies can disclose proprietary information, including historical pa yment and energy usage information without the written consent of the customer. Any third part y who receives such information can only use it in order to provide continued el ectric service to the customer. 404

Standardized Labeling : 405 “The New Jersey Board of Public Utilities (BPU) a dopted an interim disclosure rule on July 26, 1999, in accordance with the state's restructuring law. The rule requires electricity suppliers to provide consumers with a unifo rm disclosure label containing information on fuel mix, carbon dioxide, sulfur dioxide, and nitrogen oxides emissions, as well as energy-efficiency efforts twice a year, eff ective August 1, 1999. Air pollutant emissions must be compared to the regional average. Suppliers should use data from the most recent 12-month period with a 3-month lag, unless such data are unavailable (as in the case of a new market

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 Ne w 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 Or ange and Rockland Utilities, Inc.’s Generating A ssets and Certain related Property, a Tra nsition Power Sales Agreement, and a Protective Order (June 24, 1999), available at http://www.state.nj.us/bpu/wwwroo t/energy/recodivestord.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.

156entrant). Information must be provided for each product offered and verified by an independent

auditor.”

Renewable Energy Portfolio Standard : The New Jersey Board of Public Utilities adopted renewable energy portfolio sta ndards on February 1, 2005. The st andard starts at 3.25 percent for 2005 and rises to 6.5 percent by 2009. On August 31, 2005, the BPU authorized specific standards for two classes of renewable energy sour ces in addition to continuation of the existing solar requirements.

New York: Overview of Retail Compet ition Plan and Market Response

Administrator and Start Date : Restructuring in New York St ate has taken place through orders
of the New York State Public Service Commi ssion (NYPSC), rather than through legislative initiatives. Because the PSC phased in restru cturing through PSC-approved utility restructuring plans over a three year period, e ach utility had a different timet able to transition to retail competition.

In 2004, the NYPSC identified a numb er of “best practices” and orde red 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 Orange and Rockland (O&R). 407 Under the guidelines, the distribution ut ility notifies any customers who contact the utility that they may try an alternative supplie r for a two-month period without any penalty for leaving or returning to POLR serv ice after the trial period. Altern ative suppliers participating in the program offer a one-time 7 percent discount fo r the trial period. Customers can either pick an alternative supplier or have one randomly assigned and customers are can return to POLR
service or to another al ternative supplier at the end of the trial period. As the table on retail switching indicates below, switching levels in the O&R distribu tion territory are higher than in
other territories.

On September 23, 2005, the PSC determined that th e pace of development of real-time pricing
was insufficient to moderate th e effects of rising fuel costs. 408 To speed the development of realtime pricing, the PSC ordered that existing r eal-time pricing programs in some distribution territories 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 metering 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 the distribution utility to choose competitive metering services. Customers who choose competitive

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-M-0504).

407 New York Public Service Commission, Order Adopting ESCO Referral Program Guide lines 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-E-0641).

157metering services must procure both meter and me ter data services competitively. Distribution utilities are the providers 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 consumers that obtai n electric power from an alternative supplier. Customers not served by an alternative suppl ier receive POLR service from the distribution utility. POLR service for larg e C&I customers is offered on an hourly price basis that tracks wholesale spot market prices.

Alternative Suppliers Deemed Eligible 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 ranged from 6 in the Central
Hudson 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 from.

Pricing Trends : As shown in Table 20, prices gene rally increased through 1997 and then wavered before increasing to higher levels in 2003 and 2004.

Residential 10.5 10.9 11.4 12.0 12.4 13.2 13.6 13.9 14.0 14.1 13.7 13.3 14.1 14.0 13.6 14.3 14.5

Commercial 9.6 9.9 10.5 10.9 11.2 11.7 11.7 11.9 12.1 12.1 11.6 11.2 12.5 12.9 12.3 12.9 13.0

Industrial 4.9 5.3 5.8 6.2 6.5 6.7 6.8 5.8 5.6 5.2 5.0 4.8 4.9 5.6 5.2 7.1 7.0

All Sectors 8.5 8.9 9.4 9.6 10.2 10.7 10.9 11.1 11.1 11.1 10.7 10.4 11.2 8.8 8.7 12.4 12.6 2003 2004

Source: Energy Information Administration 1999 2000 2001 2002 1995 1996 1997 1998 Table 20. New York Average Annual Price per KWh by Sector
(nominal cents)

1988 1989 1990 1991 1992 1993 1994

Price Changes for POLR Service : Each distribution u tility’s restructuring pl an laid out different POLR rate reduction plans:

• Central Hudson basic electric rates were frozen at 1993 levels through June 30, 2001, for all customers. In addition, la rge industrial customers who ch ose to remain with Central Hudson for their generation services received 5 percent per year rate reductions until
mid-2001.

• Con Edison industrial customers received a 25 percent immediate ra te decrease, which remained fixed for five years. All other cu stomers received a 10 pe rcent rate decrease, phased in over five years.

• Orange and Rockland residential customers recei ved a 4 percent decrease in rates during 1995 and 1996, while industrial and commercial cu stomers received rate reductions of 4- 14 percent . On December 1, 1997 and on December 1, 1998, residential rates were reduced an additional 1 percent . Large industrial customer rates were reduced by approximately 8.5 percent on December 1, 1997.

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).

158• Rochester Gas and Electric residential a nd small commercial customers received a 7.5 percent rate decrease. Ot her commercial and most industr ial customers received an 8 percent decrease. Large i ndustrial customers received an 11.2 percent decrease. All decreases are being phased in over 5 years.

• New York State Electric and Gas industrial a nd large commercial customers (greater than 500 kW capacity) received a 5 percent per year ra te decrease, for five years. Residential
and small commercial and industrial customers have had their rates 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 decr ease received financial incentives for load growth to encourage business expansion.

• National Grid (Niagara Mohawk) customers received an overall ra te decrease of an average of 4.3 percent . Re sidential and commercial cu stomers were 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 for electricity and delivery were set until September 1, 2001. In 2001 and 2002, Niagara Mohawk was allowed to request limited rate increases for di stribution services, and prices for some of the electricity sold to all customers will fluctuate with changes in market prices.

POLR Service Provider : The distribution companies prov ide regulated POLR service for customers who do not choose a competitive s upplier or who return to POLR service. 410

Recovery of Stranded Costs/Transition Costs : Distribution utilities recover stranded costs (net of proceeds from selling genera tion assets) through a non-bypassable distribution charge. Distribution utilities were require d to use creative means to redu ce the amount of stranded costs before they are considered for recovery. Stranded cost calculations and timing of recovery were determined on a case-by-case basis for each distribution utility. 411

Switching Restrictions and Minimum Stay Requirements : The NY PSC is currently implementing a number of policies designed to encourage consumers to try alternative suppliers. 412 One of these, known at “ESCO Referral Pr ograms,” places limits on the ability of alternative suppliers to levy char ges against departing customers. 413

Switching Activity : The switching statistics for Decembe r 2005 in each distribution territory appear in the Table 21.

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.

159Table 21. New York Retail Customers and Load Supplied by 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 distri bution territories in the state from 2000 to 2005 appear in Table 22. Load served by alternat ive 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 benefit progra ms are charted in Table 23 below.

160Table 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 Developmen t Authority, supervised by the PSC. On December 14, 2005, the PSC ordered that the System Be nefit 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_Pla n_3-2-06.pdf.

Source : American Council for an Energy-Efficient Economy, Su mmary Table of Public Benefit Programs and Electric Utility Restructuring (December 2005) available at http://www.aceee.org/b riefs/mktabl.htm.

Separation of Generation and Transmission : The PSC encouraged tota l divestiture of generation,
and it instructed distribu tion 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 generation and transmission. 415

State RTO Involvement : New York distribution utilities belo ng to the New York ISO, formed in 1998. The New York ISO exercises operational c ontrol over most of New York’s transmission systems, administers the ISO transmission tariff , and operates the New York Open Access Same Time Information System (OASIS). 416

Generation Capability : 417 Prior to the restructuring regula tions, utilities in New York operated 84.3 percent of the generation capability in th e state. By 2002, that figure dropped to 32.4 percent. The difference reflected mandatory divestitures of generation to independent generation firms and entry or expansion of indepe ndent power producers. Between 1997 and 2002,

414 New York Public Service Commission , Opinion and Order Regarding Competitive 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/custo mer_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/electri city/st_profiles/new_york.pdf.

161generation capability in the state increased from 35,576 MWs to 36,041 MWs. In the previous 5-year period, generation capability had decreased. Dual fueled generation increased as a proportion of generation from 34.1 percent to 39.5 percent.

Use of Customer Information : Historical customer data will be provided by distribution companies to customers or their authorized desi gnees. All historical da ta that a competitive supplier receives from the distri bution company must be kept conf idential, unless authorized for release by the customer. A distribution company cannot disclose customer information to competitive suppliers if the cust omer has notified the distribution company in writing that he
does not authorize release. Th ereafter, customer information can only be released to a competitive supplier with the cust omer’s written authorization. 418

Standardized Labeling : 419 On December 15, 1998, the New York Public Service Commission (PSC) issued an order requiring electric suppliers to use a st andardized label to provide information to customers regarding the envir onmental impacts of elect ricity products semiannually. Suppliers must disclose fuel mix comp ared to a statewide av erage and emissions of sulfur dioxide, nitrogen oxides, and carbon dioxide. Fuel source and emissions information are calculated by the Department of Public Service (DPS) and provide d to retail suppliers quarterly. Calculations are based on a rolling annual average with data supplied from the Independent System Operator and the EIA and verified by the DPS. The most recent reports of each load serving entity (2004) are available at http://www3.dps.state.ny.us/e/energylabel.nsf /ViewCat?ReadForm&View=LabelInfo&Cat=Jan uary+2004+-+December+2004&Count=80.

Renewable Energy Portfolio Standard : The New York PSC adopted a renewable energy portfolio standard on September 24, 2004. The polic y 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 2013.

Pennsylvania: Overview of Retail Comp etition Plan and Market Response

Administrator and Start Date : The Electricity Generation Customer Choice and Competition Act was enacted on December 3, 1996. The Pennsylvani a Electric Choice Pilot Program began in the fall of 1997, with 230,000 customers participa ting. These customers were able to begin shopping for their electric generation supplie r beginning September 1, 1998. By January 2, 2000, electric choice was fully implemen ted 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 metering and billing services, although there are some areas in Pennsylvania in which the

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.

162alternative supplier may provide these services. 421 Pennsylvania’s efforts to allow licensed generation suppliers to provide metering and billi ng services to retail customers were suspended on August 12, 2002. 422

Consumer Options : Pennsylvania consumers can select an alternative supplier or be part of an aggregation of consumers buying power from an a lternative supplier. Consumers not served by an alternative supplier receive POLR servic e arranged by the local distribution utility.

Alternative Suppliers Licen sed to Provide Service : Competitive suppliers must be licensed by the PUC to provide service to Pennsylvania customers. 423 As of February 2006, the Duquesne Light territory had 4 al ternative suppliers serving reside ntial customers and 20 serving C&I customers. In the PECO territory, 6 alternative suppliers were available for residential customers
and 28 for C&I customers. Outside of these tw o territories, residential customers only have available premium priced green generation product s while C&I customers had several alternative suppliers offering service.

Pricing Trends : Table 24 displays average retail prices in Pennsylvania by customer class from 1988 to 2004. Residential, commercial, and industri al retail prices have fluctuated within a narrow range since 1991.

Residential 8.7 8.9 9.2 9.6 9.7 9.6 9.6 9.7 9.7 9.9 9.9 9.2 9.1 9.7 9.7 9.6 9.6

Commercial 7.5 7.8 8.1 8.3 8.5 8.3 8.3 8.3 8.3 8.4 8.3 7.9 6.3 8.6 8.5 8.1 8.5

Industrial 5.5 5.8 6.0 6.3 6.2 6.0 5.9 5.9 5.9 5.9 5.6 5.2 4.3 5.8 5.8 6.1 5.9

All Sectors 7.1 7.4 7.7 8.0 8.0 7.9 7.9 7.9 8.0 8.0 7.9 7.4 6.6 8.0 8.1 8.0 8.0 2003 2004

Source: Energy Information Administration 1999 2000 2001 2000 1995 1996 1997 1998 Table 24. Pennsylvania Average Annual Price per KWh by Sector
(nominal cents)

1988 1989 1990 1991 1992 1993 1994

Price Changes for POLR Service : POLR rates for distribution se rvice were capped at January 1, 1997 levels until July 1, 2001. Rates for generation, including transition charges, were capped at January 1, 1997 levels until January 1, 2006. 424 In some distribution utility service areas, generation caps are in place until 2008-2011 because these distribution utilities will be collecting stranded costs over these longer periods. Many distribution utilities also extended distribution rate caps until 2003-2005. Pennsylvania did no t require rate reductions, although several
distribution utilities agreed to reduce rates in the first ye ar of retail choice. These reductions were to be lowered and phased out over a two to three year period. 425

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 Energy Association of Pennsylvani a approving an extension of a s uspension of work of the Electronic Data Exchange Working Group as it relates to the implementation of compet itive metering, Docket No. P-00 021957 (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).

163Overall 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 Reductions 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 ge neration if he receives generation service from the utility rather than from a competitive supplier. Shopping credit rates increased over time, but fuel cost increases have been grea ter and the base rates are not adjusted under the Pennsylvania settlements with distribution utilities. This has resulted in the declining market shares for alternative suppliers and the exit of alternative suppliers.

POLR Service Provider : The distribution company provides POLR service for customers who do not choose a competitive supplier, for thos e who are unable to obtain service from a competitive supplier, or for customers whose s uppliers do not deliver service. Distribution utilities must offer standard offer service as long as the distribution utility is collecting transition charges or until 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 customers who were returning to their distribution u tility. During the summer, market prices rose, while POLR rates remained stable, below mark et rates. This caused customers to be either returned to POLR service by thei r suppliers or to return themse lves to POLR service. Many distribution utilities require cu stomers to remain with the di stribution utility for a 12-month period after switching back to the POLR provider.

Competitive POLR Service : Some distribution utilities have arranged for competitive bidding to supply the generation services po rtion of POLR servic e for customers who do not affirmatively choose an alternative supp lier. This option is known as Co mpetitive Default Service (CDS). The PUC approved additional cons umer protections for the initi al phase-in of CDS, including bidder qualifications, established creditworthiness, and bond limits. 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 aw arded a contract for 20 percent of its POLR service customers to The New Power Company. Additionally, 50,0 00 PECO customers were assigned to Green Mountain Energy, Inc. PECO customers assigne d to the CDS provider received a two-percent discount on the shopping credit (t he capped generation service ra te). The CDS provider also provided no less than two percent of its supply from renewable resources and increased the use of renewable resources by one -half of a percent annually. 429 Due to concerns that POLR prices

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.

164were insufficient to cover procurement costs, the CDS suppliers withdrew from this service. No alternative suppliers have been willing to s upply on these terms at present. On December 10, 2005, the PUC decided to reopen POLR service issues for comment in preparation for the end of the transition period in distributi on areas in addition to Duquesne. 430

Recovery of Stranded Costs/Transition Costs : Stranded costs have been administrativelydetermined by the PUC on a case-by-case basis. Utilities were not required to establish marketbased valuation by selling generation assets. Stranded costs are fully recoverable through a nonbypassable charge to all consumers, collectible fo r up to nine years, unless the PUC orders an alternative payment period. 431 Table 26 shows each utility’s a llowable 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 agreement 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 minimum stay of 12 months. 432

Switching Activity : At this point in time, retail switchi ng activities are largely limited to the Duquesne Light distribution territo ry and to a lesser degree the PECO territory, as shown in
Table 27.

Table 27. Pennsylvania Retail Customers and Load Supplied by 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%)

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 (Are there any penalties for changing suppliers?)

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

165Table 27. Pennsylvania Retail Customers and Load Supplied by 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 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 switc hing statistics for the utility distribution territories in Pennsylvania from 2000 to 2006 appear in Table 28. Load served by alternative suppliers has decreased since 2000 with the exception of an incr ease in 2004. Alternative suppliers served a declining number of custom ers 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 and C&I customers separately for October 2005. Calculations for the oth er years take the number of shoppers or shoppers’ load reported in January of that year and divides them by the re lated Pennsylvania totals from Oct. 2005. The resulting calculations are approximations because the total number of customers and the total load in the state may have change d from year to

year.

Source : Pennsylvania Office of the Consumer Advocate

Public Benefits Programs : Table 29 identifies the Penns ylvania 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 Admin. SEF Utility SEF

1662 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). Note : 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 : Generation must be separated from transmission and distribution, but distribution utilities are not requi red to divest facilit ies or reorganize
corporate structure. 433 However, several utilities voluntarily divested generation assets either to independent companies or to unregulated affiliates.

State RTO Involvement : The restructuring legislation dire cts the PUC to encourage interstate power pools to enhance competition and to comple ment restructuring. Much of Pennsylvania belongs to the PJM RTO. In order to meet elect ric load in the PJM regi on, PJM coordinates with member companies and uses bilateral contra cts and the spot market to secure power. 434 In March 2001, Allegheny Power and PJM filed with FERC a request to expand PJM by forming

PJM-West. 435

Generation Capability : 436 Prior to the restructuring legislat ion, utilities in Pennsylvania operated 92.3 percent of generation capability in the state. By 2002, that figure dropped to 12.3 percent, despite the lack of a requirement for generation divestitures or tran sfers. The difference reflected voluntary divestitures to independent generators and transfers of generation to affiliates as well as expansion and entry of independent pow er producers. Between 1997 and 2002, generation capability in the state increase from 36,650 MWs to 39,783 MWs. Most of increase consisted of dual fueled generation.

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 a nd 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 Administration, Pennsylvania State Profile, Table 4, available at http://www.eia.doe.gov/cneaf/electric ity/st_profiles/pennsylvania.pdf.

167Use of Customer Information : A customer can restrict the di sclosure of his telephone number and his historical billing data. A distribution utility or supplie r who intends to supply a thirdparty with this information must provide a custom er with the means of re stricting the release of this information, either through a signed form, orally, or electronically. 437 Customer information cannot be given preferentially by a di stribution utility to its affiliate. 438 During the initial phase - in period of electric restructuring, a customer’s name, address, telephone number, rate class, account number and load data were given to comp etitive suppliers as a result of the customer’s enrollment into the electric choice program. The customer had the opt ion of restricting the release of his telephone number and load data to suppliers. After this initial phase-in period, to
assure that customers retain the ability to restrict disclosure of certain information to suppliers,
the PUC directed distribution utilities to send form s to customers to give them the opportunity to
restrict the release of load data , or of all information (name, a ddress, rate class, and account number). Telephone numbers would not be re leased to suppliers under any circumstances. 439

Standardized Labeling : 440 The Pennsylvania Public Utility Co mmission (PUC) issued final rules in April 1998 requiring retail electricity supplie rs to "respond to reasonable requests made by consumers for information concerning generatio n energy sources." Suppliers must respond to such requests "by informing consumers that this information is included in the annual licensing report and that this re port exists at the Co mmission." Requests for information on energy efficiency must be handled in a similar manner. Suppliers must verify fuel mix data through an independent auditor and submit this informa tion in an annual repor t to the Commission. Suppliers that market electricity as "hav ing special characteristics" such as being environmentally friendly, must have informa tion available to substantiate their claims.

Renewable Energy : Pennsylvania enacted a renewable portfolio standard through Act 213 in December 2004. The standard includes a gradual increase in generation from renewables to 18 percent over 15 years. Qualified renewables are divided into two groups: traditional (solar, wind, hydro, geothermal, biomass, and coal-mine me thane) and other (waste coal, distributed generation, demand-side management, large-s cale hydro, municipal waste, wood processing waste, and integrated combined coal gasification) . Separate standards ar e set for the two groups– -8 percent and 10 percent respectively.

Texas: Overview of Retail Compet ition Plan and Market Response

Administrator and Start Date : The Texas restructuring bill was signed June 18, 1999. The Public Utility Commission of Te xas (PUC) administers the transi tion to retail competition, which began with a pilot program on June 1, 2001. Retail competition for all customer classes within ERCOT began January 1, 2002. 441 Competition is not open as ye t in areas outside of ERCOT

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).

168because the PUC is not convinced that retail competition is feasible without a regional transmission organization in these areas. 442

Services Open to Competition : Generation and billing (retail sa les). Competitive metering for certain commercial and industrial customers began January 1, 2004.

Consumer Options : Customers within ERCOT have the option of choosing a competitive supplier, choosing an aggregator, and, in the case of residential and small commercial customers, choosing POLR service (termed “pri ce to beat” default service).

Alternative Suppliers Licen sed to Provide Service : In order to be license d to provide service in Texas, competitive suppliers must meet fina ncial creditworthiness a nd technical standards. 443 There are numerous suppliers mark eting to all classes of customers in Texas that are open for
retail customer choice. In addition to the Texa s POLR default service offer, there are several alternative suppliers actively serving retail reside ntial customers in each distribution territory. The figure below is from the “August 2005 Report Card on Retail Competition” 444 showing the
number of alternative suppliers available to residential customers, the number of products offered by these suppliers, and the number of alte rnative “green” offers fo r residential customers in the major distribution te rritories within ERCOT.

TDSP # of REPs Serving

Residential

Customers # of Residential

Products (Incl. PTB) # of Renewable

Products

TXU ED 13 20 5

Center Point 14 21 6 AEP Texas Central (CPL 13 17 5

TNMP 11 16 6 AEP Texas North (WTU) 10 12 3

Pricing Trends : Retail price averages in Texas have wavered over time with peaks occurring in 1994 and 2001, as shown in Table 30. Prices incr eased in 2003 and 2004 after declining in 2002.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2030 2004

Residential 6.9 7.0 7.2 7.6 7.7 8.0 8.1 7.7 7.8 7.8 7.7 7.5 7.9 8.9 8.1 9.2 9.7

Commercial 6.0 6.1 6.2 6.6 6.7 6.9 7.0 6.6 6.7 6.7 6.6 6.5 6.8 7.7 7.0 7.8 7.9

Industrial 4.1 4.1 4.0 4.1 4.2 4.3 4.3 4.0 4.0 3.9 3.9 4.0 4.5 5.3 4.7 5.3 5.9

All Sectors 5.6 5.7 5.8 6.1 6.2 6.4 6.4 6.1 6.2 6.1 6.1 6.0 6.5 7.6 6.6 7.5 8.0

Source: Energy Information Administration Table 30. Texas Average Annual Price per KWh by Sector
(nominal cents)

Price Changes for POLR (Default) Service : Distribution utility ra tes were frozen from

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/repo rts/scope/2005/2005s cope_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/ aug05rptcrd.pdf.

169September 1, 1999, levels until January 1, 2002. 445 On January 1, 2002, rates for residential and small commercial 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 cost s. 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 (default) service is available from the distribut ion utility’s competitive retail affiliate until January 1, 2007. Prior to Ja nuary 1, 2005, affiliates of distribution utilities could offer services other than POLR (default) serv ice only if at least 40 pe rcent of residential or small commercial customers chose a competitive supplier not affiliated with the local distribution utility. Since January 1, 2005, affiliates of distribution ut ilities have been allowed to offer any service they wish in a ddition to POLR (default) service.

The Texas PUC provides information on the price to beat and on alternativ e supplier’s prices in each distribution territory. The information incl udes a comparison of each alternative supplier’s price to the POLR (default) pric e for different levels of consum ption. Table 31 shows the POLR (default) price and the ra nge of offers from alternative s uppliers for a consumer using 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 lo west offer of alterna tive suppliers. The fi gure below, from the PUC report to the 79 th Texas Legislature, illustrates these comparisons. 447

445 Tex. Util. Code Ann. 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/repo rts/scope/2005/2005s cope_elec.pdf.

170POLR (Default) Service Provider : Until December 31, 2001, POLR (default) service was provided by the distribution utilit y. When competition for all customers 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 el ectric providers” (REPs) . Prices for POLR (default) service were fixed at the “price to be at” plus fuel adjustments until January 1, 2007. Affiliated retail electric providers were allowe d to offer only POLR (default) service (at the “price to beat”) unless alternative suppliers attain ed a market share of 40 percent of residential or small commercial customers. In 2004, all but one of the affiliated re tail electric providers within ERCOT (the separate transmission inte rconnection system in Texas) were granted permission to offer additional products. 448 Starting in 2005, all affiliate d retail electric suppliers were allowed to offer other products in addition to POLR (default) services to all residential and
small commercial customers.

Analysis by the Texas PUC concluded that POLR (default) service pricing has been below the pricing that would have prevailed under the prio r cost-of-service regulatory regime. The tables below summarize the estimated regulated rates, the average of the five lowest competitive prices, the best competitive price, and the Price to Beat for the CenterPoint and TXU Service areas.

448 Id. at 24.

171CenterPoint Energy Services Area 2002 2003 2004 2005

Estimated Regulated Price 11.1 12.0 12.7 1 Average of Lowest 5 Competetive Prices (actual) 8.2 9.0 9.8 11.4 Percentage Difference from Estimated Regulated price 26% 25% 23% 18% Best Competetive Price 8.0 8.5 9.4 10.6 Percentage Difference from Estimated Regulated price 28% 29% 26% 24% Reliant Energy Price to Beat 8.8 10.3 11.1 1 3.9

2.9

TXU Electric Delivery Service Area 2002 2003 2004 2005

Estimated Regulated Price 9.4 10.5 10.7 1 Average of Lowest 5 Competetive Prices (actual) 8.0 8.7 9.1 10.7 Percentage Difference from Estimated Regulated price 15% 17% 15% 12% Best Competetive Price 7.8 8.4 8.7 10.1 Percentage Difference from Estimated Regulated price 17% 20% 19% 17% TXU Energy Price to Beat 8.4 9.6 10.5 11.9 2.1

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/WebA pp/Interchange/Docum ents/32198_7_504891.PDF

POLR Service Provider for other than Default Service : POLR service customers have been
divided into three classes: resi dential, small non-residential, a nd large non-residential. POLR service providers supply customer s in any or all of the three cl asses who either request POLR service or are assigned to POLR service because they are not receiving service from a REP, for any reason. The rates for this POLR service are established first through a competitive bidding process and, if no qualified bids ar e obtained, are then al located to existing suppliers via a lottery process. A bidder to supply POLR service may bid for any customer class, or for more than one class. An affiliate of a distribution utility cannot bid to be the POLR se rvice supplier in its own service territory during th e 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

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 Customers and Review of Rules Relating to the Price to Beat and Provider of Last Resort ; Reliant comments.

172stranded costs eligible for recovery, which incl udes uneconomic generation related assets, and purchased power contracts.

Switching Restrictions and Minimum Stay Requirements Process : A customer can switch suppliers at any time subject to th e terms of his contract with the competitive supplier. There are no switching fees unless a customer requests a special meter reading. 451

Switching Activity : Retail customers have been migrating to alternative suppliers in all of the
distribution territories with th e highest switching rates in the AEP Central and North areas, as
shown in Table 32.

Table 32: Retail Customers and Load Supplied by 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 suppliers in increasing numbers and with an increasing proportion of loa d, 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, Sept ember 2004, and June 2005. The Residential and Small C&I fig ures are all from January except the 2005 figure which is from September.

Source : Texas Public Utility Commission

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

, available at http://www.powertochoose.org/y ourrights/q_changing.asp.

173Public Benefits Programs : The Texas public benefit progr ams are presented 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, util ities were required to separate their business activities into three uni ts: a wholesale electr ic power generation company, a retail electricity comp any (REP), and a transmission and distribution company. This separation could take place either through the sale of assets to a third party, or by the creation of separate non-affiliated companies or separate affiliated companies owned by a common holding

company. 453 After the beginning of retail compe tition, a distribution ut ility may not sell electricity or participate in the market for electricity except to pr ocure electricity to serve its own
needs. 454 Wholesale electric power generation compan ies that are affiliated with a distribution utility are required to auction off 15 percen t of their installed generation capacity, 455 and no wholesale generator can own more than 20 percent of the installed capacity that can be sold in a region. 456 Before 2005, REP affiliates of transmission and distribution utilities could not offer competitive rates to residential and small comm ercial customers in the territory of the distribution utility, except as the POLR (defau lt) service provider, until 40 percent of the
residential or small business load in the te rritory is buying electricity from competitive

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 cus tomers on a voluntary basis. Funding will be reconsidered in the 2007 legislative session; Reliant comments.

453 Tex. Util. Code Ann. at § 39.051.

454 Id. at § 39.105.

455 Id. at § 39.153.

456 Id. at § 39.154.

174suppliers. 457 The transmission system for most of Texas is operated independently from the
owners of the transmission assets by ERCOT under PUC supervision.

State RTO Involvement : Most of Texas (approximatel y 85 percent) is in the ERCOT
interconnection. 458 ERCOT began operations as an indepe ndent system operator in 1996. It is regulated by the Texas PUC rather than by FERC. 459 Transmission operations of distribution utilities outside of ERCOT are regulated by FERC.

Generation Capability : 460 Prior to the restructuring legisl ation, utilities opera ted 88.3 percent of generation capability in Texas. By 2002, that figure dropped to 41.2 percent, as divestitures, transfers to affiliates, and entry and expansion of independent generators took place. Between 1997 and 2002, generation capability in the st ate increased from 73,454 MWs to 94,488 MWs, an increase of 28.6 percent . Much of the growth in generation wa s fueled by natural gas. The share of generation capability fueled by natural ga s increased from 21.4 per cent to 38.5 percent . Natural gas fueled generation more than doubled during the period.

Use of Customer Information : When the retail market opened to competition, distribution utilities were required to incl ude customer name, address, and usage information on a list of eligible customers given to competitive suppliers. 461

Standardized Labeling : 462 “On December 7, 2000, the Texas P ublic Utility Commission (PUC) issued rules requiring retail electric providers to use an Electricity Facts Label to disclose information twice a year on fuel mix and envi ronmental impacts to their retail and small residential customers, in accordance with the stat e's restructuring law. The label must also be included in promotional material soliciting new customers. Fuel mi x 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, sulfur dioxi de, nitrogen oxides, and particulates, as well as the amount of nuclear waste generated, must be presented relative to the statewide average. According to rules adopted in August 2001, th e Commission is devel oping a "generator
scorecard" database with data on fuel mix and environmental impacts by generator to facilitate implementation of the disclosure requirements. The label is to be updated each year. Retail providers can also opt to purchase and retire "renewable energy credits" from generators to meet their disclosure requirements. Providers can proj ect their fuel mix and emissions data for new products or products offered during the first year of competition. Any product marketed as
"renewable" must include the renewable fuel mi x percentage, unless it is supplied exclusively
from renewable sources. Products marketed as "green" may contain some natural gas fuels along

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 w ith 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/electricity/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/pub lications/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.

175with renewable fuels if it can be shown th at the natural gas was produced in Texas.” 463

Renewable Energy Portfolio Standard : Texas adopted a renewable energy portfolio standard on February 24, 2004. The standard establishes ye arly new generation from renewables levels through 2019, rather than percentage requirements. The levels are 850 MW in 2004 and 2005, 1400 MW in 2006 and 2007, and 2000 MW in 2009 through 2019. In 2005, the RPS requirements were 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 development to facilita te delivery of energy from renewable sources. 464

The original electric restructuring bill include d many environmental prot ections, including that 50 percent of new generating capacity must come from natural gas, and that a percentage of electricity sold in Texas must come from rene wable resources. The bill requires 50 percent reductions in nitrous oxide emissions and 25 per cent reduction in sulfur dioxide emissions from power plants that were grandfathered when air permits were introduced under the Federal Clean Air Act. There reductions must be achieved by 2003 by retrofitting or shutting down the grandfathered units. In addition, distribution utilities that upgrad e older generati on facilities to meet emissions standards may recover the co sts from retrofitting as stranded costs. 465 The PUC has adopted a renewable energy credit tradi ng program to encourage cost-effective new renewable generation facilities.

463 The consumer brochure on electricity offer labeling is available at http://www.powertochoose.org/pub lications/efl_br ochure.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.

176APPENDIX E
ANALYSIS OF CONTRACT LE NGTH AND PRICE TERMS COMPARISON OF NYISO, MISO AND SERC MARKETS USING 2005 EQR DATA

This analysis compares the short-term versus lo ng-term sales volumes and prices in three regions using reported sales information from Electri c Quarterly Reports (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. However, EQR data include only jurisdictional wholesale physical and booked out sales. The “physical” sales are power sales by MBRA holders physically delivered during the quarter. “Booked out” sales are power quantities that are sold, then re purchased at a later date, eff ectively undoing the prior sale. Depending on changes in market prices in the in terim, the repurchase may produce profits or
limit losses for the seller.

EQR limitations are best explained with the help of the diagram below, wh ich is conceptual, not scaled, where the sales reported to EQR represent only a subset of all market transactions. Retail sales may be reportable to state commissions. Sa les by non-jurisdictional en tities may appear in some EIA reports. Financial transactions done on NYMEX are reportabl e to CFTC, but other financial transactions do not need to be repor ted. Sales reportable to EQR could have been transacted bilaterally, on RTO/ISO’s, through IC E or through voice broker s, and credit cleared through ICE-LCH or NYMEX-ClearPort. Other tr ansaction venues may develop. There is no complete aggregated market picture. Analysts can only try to make infe rences from the partial market picture.

Retail Sales to Native Load

“Financial” Transactions (virtual market, options, & financially settled bilateral transactions) Sales Reported in the EQR Wholesale Sales by Non-Jurisdictional Entities (federal power administrations, munis, QFs w/o MBRs) Power Sold in Region X*

- Retail Sales to Native Load
- Wholesale Sales by Non-Jurisdictional Entities

- “Financial” Transactions
= Sales Reported in the EQR Use of EQR data must recognize that EQR captures only a subset of all market
transactions

Though limited, this comparative an alysis is informative. The Task Force selected NYISO,

177MISO and SERC as representative markets for the following reasons. NYISO provides a
consistent data set for sales in its establishe d, single-state organized market. MISO provides a consistent data set for sales in its new, multi-stat e organized part of the market (sales in Q1/05 occurred before the organized market starte d). SERC is an example of a purely bilateral wholesale market with relatively few participan ts (which increases the likelihood of consistent dataset).

The three graphs below show transaction volu mes by vintage for each representative region.

NYISO Regional Energy Sales by Contract Term

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

1 to 3 3 to 5 5 to 10 Longer than 10

Short Term Long-Term (yrs since contract commenced)(000 MWH) Q1/05

Q2/05

Q3/05

Q4/05

Source: FERC Electric Quarterly Reports

MISO Regional Energy Sales by Contract Term

- 50,000 100,000 150,000 200,000 250,000 300,000

1 to 3 3 to 5 5 to 10 Longer than 10

Short Term Long-Term (yrs since contract commenced)(000 MWH) Q4/04

Q1/05

Q2/05

Q3/05

Q4/05

S ource: FERC Electric Quarterly Reports

178SERC Regional Energy Sales by Contract Term

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

1 to 3 3 to 5 5 to 10 Longer than 10

Short Term Long-Term (yrs since contract commenced)(000 MWH) Q1/05

Q2/05

Q3/05

Q4/05

Source: FERC Electric Quarterly Reports

As noted earlier, EQR consists of sales transactions for power delivered during each quarter.
Short term transactions are defi ned as transactions unde r contracts of one year or less or sales into organized markets, such transactions includ e bilateral sales as well as sales to NYISO and MISO. Long-term transactions occur under contract s lasting more than a year. For example, a contract initiated four years ago and still delivering power w ould be grouped under the 3 to 5 year vintage. A contract initiated 11 years a go would be grouped under the Longer than 10 years vintage. While there is a field in the EQR form for termination date, it is often not relevant in this context because many contracts are either evergreen, effective until cancelled or master agreements (with no time limits) with 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 y ears (0 percent in NYISO, 2 percent in MISO, 16 percent in SERC);

 quarterly variation in quantitie s occurred primarily in sales under short term contracts.

Organized exchange markets like NYISO and MISO are designed to produce efficient and reliable daily or real-time spot market prices , with heavy reliance on bilateral financial and physical transactions to fill l onger term needs between partie s who would then settle these bilateral transactions using organized market spot prices as “index price.” The high visibility of the spot markets, along with non-reportable financia l transactions would na turally lead to a high percentage of short term transa ctions using EQR numbers in or ganized markets such as NYISO and MISO. The trend towards capacity or reliab ility pricing products in organized markets (e.g., RPM in PJM) also suggests that that organized markets may not rely on short term markets alone to give long-term price signal for investment.

179The higher proportion of long-term contracts at SERC may suggest more effective long-term price signals than at non-organized markets. However, many of these long-term contracts are legacy contracts entered into before compe titive markets were introduced. Some of these contracts are pegged to index prices that are formed with few reported transactions and therefore questionable liquidity.

The following graphs show the price patterns by contract vintage in 2005.

MISO Regional Energy Price by Contract Term

- 10.00 20.00 30.00 40.00 50.00 60.00 70.00

1 to 3 3 to 5 5 to 10 Longer than 10

Short Term Long-Term (yrs since contract commenced)($/MWH) Q1/05

Q2/05

Q3/05

Q4/05

Source: FERC Electric Quarterly Reports

SERC Regional Energy Price by Contract Term

- 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00

1 to 3 3 to 5 5 to 10 Longer than 10

Short Term Long-Term (yrs since contract commenced)($/MWH) Q1/05

Q2/05

Q3/05

Q4/05

Source: FERC Electric Quarterly Reports

180This analysis shows that prices under long-term contracts were somewhat lower than short-term prices in MISO and SERC, but not in NYISO. The short-term price ch anges are 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).

It is difficult to draw definite conclusions on prices with 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.

181APPENDIX F
A BIBLIOGRAPHY OF PRIMARY INFORMATION
ON ELECTRIC INDUSTRY RESTRUCTURING IN THE U.S.

The process of understanding the ins and outs of restructuring markets for electricity and transmission in the U.S. has been running full bore since the early 1990s. Accordingly, a large number of documents have been published intend ing to explain the basic engineering, economic and regulatory theories that s upport restructuring ideas. The in tended audience of these studies has been various – from state regulators and le gislators, to academics, public power managers, and the general public.

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 re ader to a variety of
sources that will allow him/her to learn more about the subjects that are of the most interest.

Some of these sources are older and contain slightly outdated refe rences – but their theoretical arguments remain applicable to current debates.

NOTE: Inclusion of articles does not indicate th e Task Force’s endorsement of the theories presented.

General Restructuring Information Documents Available on the Web :

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, A Comprehensive View U.S. El ectric Restructuring with Policy Options for the Future , National Council on Electricity Policy (2003), available at http://www.ncouncil.org/pdfs/restruc.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

U.S. Department of Energy, En ergy Information Administration, The Changing Structure of the Electric Power Industry 2000: An Update (October, 2000), available at http://www.eia.doe.gov/cneaf /electricity/chg_stru_update/

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

William W. Hogan, Market Design and Electricity Restructuring (November 1, 2005) (presentation at the Association of Power Ex changes 2005 Annual Conference in Orlando FL),
available at http://ksghome.harvard.edu/~whogan/hogan_apex_110105.pdf

182Paul L. Joskow, Markets for Power in the United States: An Interim Assessment , ENERGY J. (forthcoming 2006), available athttp://stoft.com/metaPage/lib/Joskow-2006-power-marketassessment.pdf

Paul L. Joskow, Restructuring, Competition, and Regulator y Reform in the U.S. Electricity
Sector , J. E CON

. P ERSPECTIVES 11(3), at119-38.

On-Line Libraries of Electric Industry Restructuring Documents:

Harvard Electricity Policy Group http://www.ksg.harvard.edu/hepg/papers.htm

Center for the Study of Energy Markets (CSEM) at the University of California Energy Institute (UCEI) at UC Berkeley: http:// www.ucei.berkeley.edu/pubs-csemwp.html

Stephen Stoft Website Library : http://stoft.com/p/S2.html

Carnegie Mellon Electric Industry Center (CEIC) : http://wpweb2.tepper.cm u.edu/ceic/publications.htm

Books

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).

S ALLY H UNT

, M AKING C OMPETITION W ORK IN E LECTRICITY (Wiley Publishing 2002).

S TEVEN S TOFT

, P OWER S YSTEM E CONOMICS : D ESIGNING M ARKETS F OR E LECTRICITY (IEEE Press, Wiley-Interscience 2002).

183APPENDIX 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

184Name Credit Rating Sales ($bil) Profits ($bil) Assets Market Value ($bil) ($bil) 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 Resources no rating 6.96 0.16 5.45 1.99 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)

185