REPORT TO CONGRESS ON COMPETITION 

IN WHOLESALE AND RETAIL MARKETS 

FOR ELECTRIC ENERGY 

Pursuant to Section 1815 of the 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 Energy 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 Energy 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 Energy 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 Energy Regulatory Commission 

Michael Wroblewski – Federal Trade Commission (left the FTC in June 2006) 

David Zlotlow – Department of Justice 

This report was prepared by the Task Force with the assistance of the Department of Justice, 

Federal Energy Regulatory Commission, Federal Trade Commission, Department of Energy, 

and Department of Agriculture. The Task Force assumes full responsibility for the report and 

the views expressed herein. 

TABLE OF CONTENTS 

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

Executive Summary ................................................................................................................. 1 

Chapter 1. Industry Structure, Legal and Regulatory Background, Trends 

 and Developments ................................................................................................... 10 

Chapter 2. Context for the Task Force’s Study of Competition in Wholesale and Retail 

Electric Power Markets ........................................................................................... 44 

Chapter 3. Competition in Wholesale Electric Power Markets ............................................... 53 

Chapter 4. Competition in Retail Electric Power Markets ....................................................... 84 

Appendix A. Index of Comments Received ...........................................................................109 

Appendix B. Task Force Meetings with Outside Parties ........................................................116 

Appendix C. Annotated Bibliography of Cost Benefit Studies ..............................................117 

Appendix D. State Retail Competition Profiles .....................................................................137 

Appendix E. Analysis of Contract Length and Price Terms....................................................177 

Appendix F. Bibliography of Primary Information on Electric Competition .........................182 

Appendix G. Credit Ratings of Major American Electric Generation Companies..............184 

Table 1-1. U.S. Retail Electric Providers, 2004 ....................................................................... 14 

Table 1-2. U.S. Retail Electric Sales, 2004 .............................................................................. 15 

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

 Ultimate Consumers ............................................................................................... 15 

Table 1-4. U.S. Electricity Generation, 2004 ........................................................................... 16 

Table 1-5. U.S. Electric Generation Capacity, 2004 ................................................................ 16 

Table 1-6. Power Generation Asset Divestitures by Investor-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, Average 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 Generation Capacity Additions, 1995-2004....................... 35 

Figure 1-5. Transmission Construction Expenditures by Investor-Owned Utilities, 

 Actual and Projected, 1975-2009........................................................................... 36 

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

 1960-2005 ............................................................................................................. 38 

Figure 1-7. Natural Gas Plants Dominate New Generating Unit Additions ............................ 39 

Figure 1-8. Net Generation Shares by Energy Source ............................................................. 40 

Figure 1-9. Fossil Fuel Costs for Electric Generators, 2001-2006 .......................................... 41 

i 
Figure 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 Competition Status, 2003 ................................................................. 91 

Figure 4-3. Average Revenues per kWh for Retail Customers, 1990-2005 ............................ 95 

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

ii 
EXECUTIVE 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 Act2

 created an “Electric Energy 

Market Competition Task Force”3

 (Task Force) to conduct a study 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 comment at least 60 days prior to submitting the 

final report to Congress. The Task Force published 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 Force undertook several activities, as follows: 

 Section 1815(c) of the EPAct 2005 required the Task Force to “consult 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. These comments are available online for public 

review in the Task Force docket maintained 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 competition-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 bibliography of the public cost/benefit studies that 

have attempted to analyze the status of wholesale and retail competition. 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 York, 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, appointed by the Attorney General of the United 

States; (2) one employee of the Federal Energy Regulatory Commission, appointed by the Chairperson of that Commission; (3) one employee of 

the Federal Trade Commission, appointed by the Chairperson of that Commission; (4) one employee of the Department of Energy, appointed by 

the Secretary of Energy; and (5) one employee of the Rural Utilities Service, appointed by the Secretary of Agriculture. 

4

 Abbreviations for those parties are also listed in Appendix A. 

1 
states 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 report in the Federal Register for public 

comment on June 13, 2006, 71 Fed. Reg. 34,083 (2006). The notice accompanying the 

draft requested comments on the Task Force observations. About 80 different entities 

provided comments and suggestions on the draft report. These commenters are listed in 

Appendix A. Draft report comments are available 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 research and reviewed the 

information from comments and interviews. 

C. The Goal of Increasing Competition in Electric Power Markets 

Federal and several state policymakers generally 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 accurately reflect the underlying costs of production. 

These prices should thus align the price of electricity with the value customers place on 

electricity, leading to a more efficient 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 scarcity, 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 facilitate competition in wholesale electric power 

markets. The Public Utility Regulatory Policies Act of 1978 (PURPA),5

 the Energy Policy Act 

of 1992 (EPAct 1992),6 and EPAct 2005 promoted competition by lowering entry barriers and 

increasing transmission access. Federal electricity 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 electricity resulted in sufficient generation supply and 

transmission to provide wholesale customers with the kind of choice 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 associated 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). 

2 
The Task Force found this question challenging to address due to a number of complicating 

factors. The various U.S. regional wholesale electric power markets developed differently since 

the introduction of widespread wholesale competition. There were significant regional 

regulatory and structural differences in the electric power industry when Congress enacted 

EPAct 1992 and when FERC adopted Order No. 8887 in 1996, mandating nondiscriminatory 

access to the transmission grid. Even today, the regional markets have different features and 

characteristics. As discussed in Chapter 3, these differences make it difficult to identify and 

separate the determinants driving consumption and investment decisions and thus make it 

difficult for the Task Force to evaluate the degree to which more competitive markets have 

influenced such decisions. 

Despite the difficulty of directly answering the question at hand, the Task Force’s examination of 

wholesale competition did yield useful observations, as outlined below. 

 

1. Wholesale Market Structures

Wholesale markets exhibit regional differences and generally rely on one of two types of market 

structures to support wholesale transactions. 

a. One approach to competition in wholesale markets is to base trades exclusively on 

bilateral sales negotiated directly between suppliers and scheduled through individual, 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 available than in organized markets, which may 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 readily apparent. A lack of centralized, shared 

information about generation dispatch and trades on interconnected systems requires a 

transmission owner to hold part of its transmission capacity as unused “reserves” to ensure 

reliable system operation. In some of these markets, wholesale customers have difficulty gaining 

unqualified access to the transmission needed to access 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 transmission facilities across a wide region and to 

operate trading markets – regional transmission organizations (RTOs) or independent system 

operators (ISOs). Variations of this approach predominate in the Northeast, Mid-Atlantic, 

Midwest, Texas, and California. The market designs in these regions provide participants with 

guaranteed physical access to the transmission system (subject to transmission security 

constraints). These customers are responsible for the cost of that access (if they choose to 

 

7 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded 

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].

3 
participate), and thus are exposed to congestion 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 process 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 transmission access at predictable prices in these 

markets and the impact that this can have on access 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 Competitive Wholesale Markets

New generation investment has varied significantly by region since the adoption of open access 

transmission and the growth of competition. The Task Force examined comments on how 

competition policy choices have affected investment decisions of both buyers and sellers in 

wholesale markets. A number of issues emerged. One was the difficulty of raising capital to 

build facilities whose revenue streams are affected by changing fuel prices, demand fluctuations, 

and the potential for regulatory intervention. A related theme was the investment dampening 

effects of a perceived lack of long-term contracting 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 generation and ensuring adequate 

supplies for retail loads at predictable prices. Several 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 affecting the availability, pricing, and 

terms for long-term power supplies under bilateral contracts. Base-load and mid-merit 

generators may see relatively high profits in short-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 marketers may be unwilling to enter into long-term 

supply contracts because of limited opportunities to hedge the potential risks of long-term 

commitments in highly volatile electricity markets. Third, both generators and customers cited 

continuing uncertainties over availability and certainty of long-term delivery options 

(transmission). Fourth, long-term contracts may be difficult to arrange because of inherent 

uncertainties associated with federal and state regulation of these contracts. Finally, the 

uncertainty that distribution utilities face over how much supply they will need to procure for 

customers that have an option to switch can also discourage utilities 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 profitable undertaking. The availability of long-term 

contracts, as noted above, is critical to the ability of nonutility generators to secure capital for 

new investment. Transmission access can be vital to supporting competitive options for market 

participants. Recently, capital for large investment projects has flowed to traditional utilities 

4 
more 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, thus, elicit investment. Despite 

legislative and regulatory efforts to expand transmission access for competitive generation and to 

reduce the potential for discrimination, the perception of discrimination persists. Commenters 

reported that such discrimination can increase delivery risk because purchasers fear their 

transmission transactions could be terminated for anticompetitive reasons. One response to this 

risk is to turn over operation of the regional transmission grid to ISOs and RTOs. Another is to 

adopt additional reforms to the Order 888 Open Access Transmission Tariff (OATT). New 

federal authorities provided by EPAct 2005 also address transmission infrastructure issues. 

3. Pricing and Entry in Wholesale Markets for Electricity

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

a. One possible, but controversial, way to spur entry is to allow wholesale price spikes when 

supply is short. The profits realized during these price spikes can provide incentives for 

generators to invest in new capacity. However, if wholesale customers have not hedged (or 

cannot hedge) against price spikes, then these spikes can lead to adverse customer reactions. 

Unfortunately, it can be difficult to distinguish high prices due to the exercise of market power 

from those due to genuine scarcity. Past price spikes have caused regulators and various 

wholesale market operators to adopt price caps in certain markets. Although price caps may 

limit price spikes and some forms of market manipulation, they can also limit 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 new supply and help moderate price volatility. 

Wholesale customers pay suppliers to assure the availability of generation when needed. Where 

there are capacity payments in organized wholesale markets, however, it is difficult for 

regulators to determine the appropriate level of capacity payments to spur entry without overtaxing market participants and customers. Also, 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 generation. 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 challenge is that it is often difficult to assess the 

beneficiaries of transmission upgrades, who should pay for the upgrades, and how regulators 

should provide for recovery of the investment through rates. This regulatory challenge may 

cause uncertainty about the price for transmission and about return on investment both for new 

generators and for transmission providers. 

5 
d. Another option for ensuring adequate generation supply is to exercise traditional 

regulatory authority over electricity 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 utilities to earn a fair rate of return on their 

investment, thereby encouraging utility investment. This approach is not without risk to the 

utility, as regulators have authority to disallow excessive costs. Furthermore, these traditional 

methods are imperfect and can in some cases lead to overinvestment, underinvestment, excessive 

spending and unnecessarily high costs. These methods can distort both investment and 

consumption decisions. 

E. Observations on Retail Market Competition

In the early 1990s, several states with high electricity prices began exploring opening retail 

electric service to competition. While customers would choose their supplier, the local 

distribution utility would still handle the delivery of electricity. Retail competition was expected 

to result in lower retail prices, innovative services and pricing options. 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 District of Columbia had restructured retail electric 

service and allowed competitive suppliers to provide service to some, if not all, retail customers 

at prices set in the market. 

Most restructured states required the local utility to continue to offer service under regulated 

“provider of last resort” (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 obtain electricity from wholesale markets to meet the needs of their 

retail customers, including POLR obligations. Some states also required that the utilities join 

RTOs. 

1. Retail Competition Experience in Profiled States

The Task Force examined in detail the implementation of retail competition in Illinois, 

Maryland, Massachusetts, New Jersey, New York, Pennsylvania, and Texas. Common goals for 

retail competition included: 

 lower electricity prices than under traditional cost of service regulation through retail 

suppliers’ (and eligible customers’) access to competitive wholesale markets; 

 better service and more options for customers; 

 technological innovation and new products and services for consumers; and 

 environmental improvements. 

In most profiled states, retail competition has not developed as 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 

6 
have a wide variety of alternative suppliers and pricing options. Commercial and industrial 

(C&I) customers have more choices and options, but in several states 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 environmentally 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, regulators often capped the POLR electricity price for 

“transitional” multi-year periods that are now just ending. Several states also required price 

reductions for POLR service below existing regulated rates (in order to proxy the expected 

benefits of competition). Over time, these capped and discounted POLR prices fell below 

prevailing wholesale market price levels. These POLR price caps have the unintended effect of 

dampening competitive price signals and discouraging entry by competitive suppliers. 

The POLR rate caps and the sharp increase in fossil fuel costs affecting all retail suppliers across 

the country, complicate Task Force efforts to discern any price differences attributable to the 

introduction of competition. The implementation of retail competition is a relatively new 

exercise, and retail competition policies involve a number of unresolved issues (including 

regulatory issues) that can inhibit vigorous competition. It should 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 rate caps expire, states must 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 class. 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 service price does not closely match the competitive 

price, it is likely to distort consumption and investment decisions. 

b. Adjustments to POLR Rates. If POLR prices remain fixed while prices for fuel and 

wholesale power are rising, customers may experience rate shock when the transition period 

ends. This can create public pressure to continue the fixed POLR rates at 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 (when costs are deferred) and in the long term (when 

7 
the 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 policy goals for establishing and 

maintaining POLR service in competitive retail markets. These policies can affect entry of 

competitive retail suppliers. POLR service (or an equivalent provision) 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 intrusive form of POLR service. It also is consistent with protecting 

consumers against unanticipated loss of electric service. POLR service that goes beyond shortterm access to the wholesale spot market involves providing a bundle of services that electricity 

marketers also could provide. A more expansive version of POLR service may hamper 

development of alternative suppliers. The economic rationale for maintaining a POLR service 

obligation usually is limited to trying to correct market imperfections. If a state adopts a more 

expansive version of POLR service, it should periodically review the rationale for continuing the 

service.

d. Treatment of Different Customer Classes. States may find that effective retail 

competition programs require different POLR service designs for different customer classes. 

Large C&I customers are logical leaders for retail choice because of their familiarity with energy 

procurement processes and because they are comfortable with decisions to adjust input use based 

on input prices. State policies have allowed POLR rates for these large customers to reflect 

wholesale spot market prices more than POLR rates for residential customers. This approach 

generally has led large customers to switch suppliers more than small customers have. Also, 

more suppliers have tried to solicit these large customers. 

e. Consumer Education. Customers may find it difficult to find competitive supplier offers 

in the first place and to understand the terms and conditions of those offers. It also is unclear 

whether the perceived potential cost savings are sufficient to give customers incentives to 

undertake the effort to find this information. For these smaller, less sophisticated shoppers, 

issues of awareness and access to comparative pricing information should be addressed as retail 

customer choice is implemented. 

f. Customer Aggregation. Competitive provider interest in residential and small business 

customers has been slow to develop in most states. 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 aggregation programs can reduce shopping burdens and 

uncertainties for individual customers and lower customer acquisition costs for competitive 

providers. Several states have approved customer aggregation plans as an alternative approach 

to developing retail competition. Opt-out customer aggregations may be worth considering 

because they can minimize transaction costs without limiting customer choice. 

8 
g. Procurement of POLR Supply. In all retail competition states, a substantial number of 

retail customers continue to depend on POLR service. Some states have used, or are proposing 

to use, auctions to procure POLR supply. Auctions 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 electricity competition to work. Rules 

and procedures for switching should allow customers 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. 

9 
CHAPTER 1 

INDUSTRY STRUCTURE, LEGAL AND REGULATORY 

BACKGROUND, TRENDS AND DEVELOPMENTS 

For almost all of the 20th Century, the electric power industry was dominated by regulated 

monopoly utilities. Beginning in the late 1960s, a number of technological, economic, 

regulatory, and political developments led to fundamental changes in the structure of the 

industry. 

In the 1970s, vertically integrated utility companies (investor-owned, municipal, or cooperative) 

controlled over 95 percent of the electric generation in the United States. Typically, a single 

local utility sold and delivered electricity to retail customers under an exclusive franchise 

regulated under state law. Today, the electric power industry includes both utility and nonutility 

entities, including many new companies that produce, 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. Increasingly, decisions affecting retail 

customers and electricity rates are split among federal, state, and new private, regional entities. 

This chapter highlights structural changes in the industry since the late 1960s. It provides an 

overview of the important legislative and regulatory changes, as well as trends that have 

contributed to increased competition. 

A. Industry Structure and Regulation 

Participants in the electric power sector in the United States include investor-owned utilities and 

electric cooperatives; federal, state, and municipal utilities, public utility districts and irrigation 

districts; cogenerators and onsite generators; and nonutility independent power producers (IPPs), 

affiliated power producers, power marketers, and independent transmission companies that 

generate, distribute, transmit, or sell electricity at wholesale or retail. 

In 2004, 3,276 regulated retail electric providers supplied electricity to over 136 million 

customers, with retail sales totaling almost $270 billion. Retail customers purchased more than 

3.5 billion megawatt hours (MWhs) of electricity. Active retail electric providers include 

utilities, federal agencies, and power marketers selling directly to retail customers. These entities 

differ greatly in size, ownership, regulation, customer load characteristics, and regional 

conditions. These differences are reflected in policy and regulation. Tables 1-1 to 1-5 provide 

selected statistics for the electric power sector by type of ownership in 2004 based on 

information reported to the Department of Energy (DOE), Energy Information Administration 

(EIA). 

1. Investor-Owned Utilities

Investor-owned utility operating companies (IOUs) are private, shareholder-owned companies 

ranging from small local operations serving a retail customer base of a few thousand to giant 

multi-state holding companies serving millions of customers. Most IOUs are or are part of a 

vertically integrated system that owns or controls generation, transmission, and distribution 

10 
facilities/resources to meet the needs of retail customers in their franchise service areas. Many 

IOUs have undergone significant restructuring and reorganization under state retail competition 

plans over the past decade. As a result, many IOUs no longer own generation, but those that sell 

electric power to retail customers 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 there were 220 IOUs serving approximately 94 million 

retail distribution customers, accounting for 68.9 percent of all retail customers and 60.8 percent 

of retail electricity sales. IOUs directly owned about 39.6 percent of total electric generating 

capacity and accounted for 44.8 percent of generation for retail and wholesale sales in 2004. 

IOUs provide service to retail customers under state regulation of territories, finances, 

operations, services, and rates. States that have not restructured retail service generally regulate 

retail rates under traditional bundled cost-of-service rate methods. In states that have 

restructured IOUs, distribution services continue to be provided under monopoly cost-of-service 

rates, and retail customers obtain generation service either at market rates from alternative 

competitive providers or at regulated “provider of last resort” (POLR) rates from the distribution 

utility or another designated POLR service provider. IOUs serve retail customers in every state 

but Nebraska. 

Under the Federal Power Act (FPA),8 the Federal Energy Regulatory Commission (FERC) 

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 interconnections with utilities in other states that allow unimpeded flow of 

electricity across systems. Thus, IOUs in Alaska, Hawaii, and the Electric Reliability Council of 

Texas (ERCOT) region of Texas 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 control 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 percent 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 Association, 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 overwhelmingly 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.

11 
Regulation of public power systems varies among states. In some, 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 officials. Other public power systems are operated by public utility 

districts, irrigation districts, or special state authorities. 

On the whole, state retail restructuring initiatives did not affect retail services in public systems. 

However, some states allow public systems to adopt retail choice alternatives voluntarily. 

3. Electric Cooperatives 

Electric cooperatives are privately-owned, non-profit electric systems 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 transmission cooperatives (G&Ts) own and operate 

generation and transmission and secure wholesale power and transmission services from others 

to meet the needs of their distribution cooperative members’ retail customers and other rural 

native load customers. G&T systems and their members engage in joint planning and power 

supply operations to achieve some of the savings available under a vertically integrated utility 

structure. Electric cooperatives operate in 47 states. Most were originally organized and 

financed under the federal rural electrification program and operate in primarily rural areas. 

Cooperatives provide electric service 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 electricity sold at retail. Nationwide electric 

cooperatives generate about 4.7 percent of total electric generation 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 distribution cooperatives are net buyers. Cooperatives 

nationwide generated only about half of the power needed by their retail customers. They 

secured approximately half of their power needs from other wholesale suppliers in 2004. 

Although cooperatives own and operate transmission facilities, almost all rely to some extent on 

transmission owned by others to deliver power to their customers. 

Regulatory jurisdiction over cooperatives varies among states. Some states exercise considerable 

authority over rates and operations, while others exempt cooperatives from state regulation. In 

addition to state regulation, cooperatives with outstanding loans under the Rural Electrification 

Act of 193612 are subject to financial and 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.

12 
contracts, operating agreements, and transfers of assets. Cooperatives that have repaid their RUS 

loans and that engage in wholesale sales or provide transmission services to others have been 

regulated by FERC as public utilities under the FPA. EPAct 2005 gave FERC additional 

discretionary jurisdiction over transmission services provided by larger electric cooperatives. 

4. Federal Power Systems

Federally-owned or chartered power systems include the federal power marketing 

administrations (PMAs), the Tennessee Valley Authority (TVA), and facilities operated by the 

U.S. Army Corps of Engineers, the Bureau of Reclamation, the Bureau of Indian Affairs, and the 

International Water and Boundary Commission. Wholesale power from federal facilities 

(primarily hydroelectric dams) is marketed through four federal power marketing agencies: 

Bonneville Power Administration, Western Area Power Administration, Southeastern Power 

Administration, and Southwestern Power Administration. The PMAs own and control 

transmission to deliver power to wholesale and direct service customers. They also may purchase 

power from others to meet contractual needs and may sell surplus power as available to 

wholesale markets. Existing legislation requires that the PMAs and TVA give preference in 

selling their generation to public power systems 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. Federal systems provided 7.2 percent of the nation’s 

power generation in 2004. Although most federal power sales are at the wholesale level, some 

are made to end users. Federal systems nationwide 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 generate, transmit, or sell electric power but do not operate regulated 

retail distribution franchises.13 They include wholesale nonutility affiliates of regulated utilities, 

merchant generators, and qualifying facilities (QFs).14 They also include power marketers that 

buy and sell power at wholesale or retail but that do not own generation, transmission, or 

distribution facilities. Independent transmission companies that own and operate transmission 

facilities but do not own generation or retail distribution facilities or sell electricity to retail 

customers are also included in this category for EIA reporting purposes. 

Non-QF wholesale generators engaged in wholesale power sales in interstate commerce are 

subject to FERC regulation under the FPA. Power 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 they operate. FERC regulates interstate 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 here – may still be characterized as “utilities” 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 electric generating technologies and industrial and commercial cogenerators 

(combined heat and power producers) that have special status under PURPA. 

13 
As retail electric providers, 152 power marketers reporting to EIA served about 6 million retail 

customers or about 4.4 percent of all retail customers and reported revenues of over $28 billion, 

on about 11.6 percent of retail electricity sold. 

Nonutilities are a growing presence in the industry. In 2004, nonutilities owned or controlled 

approximately 408,699 megawatts (MWs) or 39.6 percent of all electric generation capacity, 

compared to about 8 percent in 1993. About half of nonutility generation capacity is owned by 

nonutility affiliates or subsidiaries of holding companies that also own a regulated electric 

utility.15 Nonutilities accounted for about 33 percent of generation 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 alternative supplier. 

** Ninety-eight percent of all power marketers’ full-service customers are in Texas. Investor-owned utilities in the ERCOT region of Texas no 

longer report ultimate customers. Their customers are counted as full-service customers of retail electric providers (REPs), which are classified 

by the Energy Information Administration as power marketers. The REPs bill customers for full-service and then pay the IOU for the delivery 

portion. REPs include the regulated distribution utility’s successor affiliated retail electric provider that assumed service for all retail customers 

that did not select an alternative provider. Does not include U.S. territories. 

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

EIA-861, 2004, data. 

 

15 EEI comments. 

14 
Table 1-2. U.S Retail Electric Sales, 2004 

Sales to Ultimate Consumers in Thousands of MWhs 

Ownership Full-Service Energy only Total Percent 

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

Investor-owned utilities 2,148,351 3,359 2,151,720 60.8 

Cooperatives 344,267 890 345,157 9.7 

Federal Power Agencies 41,169 352 41521 1.2 

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

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

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

EIA-861, 2004 data. 

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

Consumers 

Ownership Sales in $ millions 

Full-Service Energy only * Delivery Total ** 

Publicly-owned utilities $37,734 $5,787 $27 $43,548 

Investor-owned utilities $162,691 $128 $8,746 $171,565 

Cooperatives $25,448 $37 $7 $25,492 

Federal Power Agencies $1,211 $13 $1 $1,224 

Power Marketers $17,163 $11,000 0 $28,162 

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

Notes: 

* Energy-only revenue represents revenue from a utility’s sales of energy outside 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 from energy procured 

for California’s investor-owned utilities by the California Department of Water Resources Electric Fund. Ninety-eight percent of power 

marketers’ full-service sales and revenues occur in Texas. IOUs in the ERCOT region of Texas no longer 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 

15 
Table 1-4. U.S. Electricity Generation, 2004 

Thousands of MWhs and Percent of Total 

Ownership Generation Percent of Total 

(thousands of MWhs) 

Publicly-owned 

utilities 

397,110 10.3 

Investor-owned 

utilities 

1,734,733 44.8 

Cooperatives 181,899 4.7 

Federal Power 

Agencies 

278,130 7.2 

Power Marketers 42,599 1.1 

Nonutilities 1,235,298 31.9 

Total 3,869,769 100.0 

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

EIA-861 and EIA-906/920 for generation. 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 for 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 separate, mostly vertically-integrated monopoly 

franchises with wholesale and retail prices and services extensively regulated under state and 

federal law. Many states have elected to maintain this model. The legacy of this verticallyintegrated monopoly structure creates substantial challenges for state and federal efforts to 

16 
restructure the industry and to create new institutional arrangements to facilitate increased 

reliance on competitive market prices. This section provides a brief overview of the 

evolutionary changes in the electric power industry. 

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

In the late 19th Century, electric utilities developed as small central station power plants with 

limited local distribution networks. Franchise rights granted by manufacturers and by municipal 

governments allowed use of public streets and rights of ways. These franchises were often 

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 alternatives – natural gas lighting or self-generation in 

the case of street railway, commercial, and industrial customers.17 Many municipalities elected 

to create and operate their own electric utility systems. 

Certain characteristics of providing electric service were recognized early on. Utility systems 

incurred high fixed costs for investments in generating plants needed to meet peak load and to 

extend the delivery system. Because they had relatively low operating costs, their profits 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 evening 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 investments risky. Steady gains in generation, 

transmission, and distribution economies of scale provided incentives to expand the electric 

networks. Larger plants produced cheaper electricity than many smaller plants. The substantial 

investment required for electric utility plants also spurred creation of long-term financing 

structures and the corresponding interest in providing assurances to investors that the entity 

would be profitable and would remain financially viable long enough to repay the debt. 

These characteristics led some to suggest that a single monopoly provider 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 award franchises and establish rates and service 

standards. An early associate of Thomas Edison, Samuel Insull of Chicago Edison was among 

them and proposed state regulation of private utilities in a speech before the National Electric 

Light Association in 1898.18 Insull characterized electricity production as a “natural 

monopoly.”19 Initially, the proposal for state regulation was poorly received, but as private 

 

16 LEONARD S. HYMAN, AMERICA’S ELECTRIC UTILITIES: PAST, PRESENT AND FUTURE 64 (Public Utility Reports, Inc. 1988) [hereinafter 

HYMAN]. In the City of Chicago, the city council granted 29 different 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/electricity/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/electricity/chg_stru_update/update2000.html [hereafter EIA 

Update 2000]. 

18 HYMAN at 68. 

19 In economic literature, the concept of a “natural monopoly” developed over time as a rationalization for the regulation of electric utilities. In 

brief, a “natural monopoly” is an industry characterized by long-run decreasing costs where a single provider can supply product or service at a 

lower cost than competition. ALFRED E. KAHN, THE ECONOMICS OF REGULATION: PRINCIPLES AND INSTITUTIONS, Volume 1, at 11-12 (John 

Wiley & Sons, Inc. 1970). Kahn also notes the substantial legal and historical “public interest” rationale for regulation of the electric utility 

industry. Economists have debated whether the electric utility industry or segments of it are natural monopolies for several decades. This debate 

17 
electric companies began to grow and consolidate and concerns were raised over trusts in many 

industries, the concept began to gain support. In 1907, Wisconsin adopted legislation regulating 

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 granted exclusive retail electric 

franchises to private companies within specified 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 just and reasonable rates, terms and conditions 

overseen by the state. Often the utility was authorized to use public rights of way and eminent 

domain for electric facilities. To meet this obligation to serve, most private utilities built and 

controlled the generation, transmission, 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 expect a right to reasonable compensation for its 

services, although a specific rate of return was not guaranteed. Retail rates (price) were based on 

the average historical system cost of production (including the investors’ fair return on 

investment). 

In the early 20th Century, private electric utilities continued to expand under this system of state 

regulation. Most continued to build their own generation plants and transmission systems, 

primarily due to the cost and technological limitations of transmitting electricity over distances.21 

Initially, there was little wholesale trade among utilities. As the industry grew, continued 

improvements in technology allowed expansion beyond central cities, and prices for electricity 

fell at the same time that demand increased substantially. 

Over the same period, electric utility holding companies were created and began to acquire local 

private and municipal utilities. While a holding 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, consolidation, and complexity of 

such companies coincided with a number of financial and securities abuses that were 

documented in an investigation by the Federal Trade Commission (FTC). These holding 

companies often became the sole providers of various services and products to their affiliated 

utilities, and their sometimes inflated costs were passed through to the retail customers. By 

1932, the eight largest utility holding companies controlled 73 percent of the investor-owned 

electric industry.22

This pattern of consolidated ownership and holding company abuses led to calls for federal 

involvement in the electric power industry. As a result of the FTC findings, Congress passed the 

Public Utility Holding Company 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 regulation. See, e.g., 

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

of Arizona); RICHARD F. HIRSCH, POWER LOSS: THE ORIGINS OF DEREGULATION AND RESTRUCTURING IN THE AMERICAN UTILITY SYSTEM

(MIT Press 1999); SHARON BEDER, POWER PLAY: THE FIGHT TO CONTROL THE WORLD’S ELECTRICITY (W.W. Norton 2003). 

20 HYMAN at 68. 

21 See EIA Update 2000. 

22 HYMAN at 74. 

23 15 U.S.C. §§ 79a et seq. (2000). 

18 
stringent federal oversight of the large utility holding companies. The FPA expanded the Federal 

Power Commission’s authority to include oversight and regulation of interstate sales of 

wholesale power (e.g., sales of power between utility systems) and interstate electricity 

transmission at wholesale by “public utilities” (i.e., investor-owned utilities). FPA jurisdiction 

over interstate sales closed a gap in electric industry regulation that the Supreme Court had 

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 public power and cooperative utilities. Over time, utilities 

became more interconnected via high-voltage transmission networks. Constructed primarily for 

reliability, these networks also facilitated more opportunities for interstate trade. However, 

wholesale trade was slow to develop. 

Until the late 1960s, the vertically integrated monopoly utility model appeared to work 

reasonably well. Utilities were able to meet increasing demand for electricity at decreasing 

prices as advances in generation technology and transmission provided increased economies of 

scale with larger units and decreased costs.25 

2. The Energy Crisis of the 1970s, PURPA, and 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 accelerated throughout the 1970s. Resulting financial 

stresses challenged the continued profitability of the large vertically integrated utility model. 

They also provoked criticisms of the traditional cost-of-service regulatory model that allowed the 

pass-through of higher costs and risks 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 rates were declining at an average annual rate of 1.5 percent.26 

At the same time, the new large nuclear and coal plants built in the 1970s did not yield the 

dramatic improvements in economies of scale that earlier technological advances in generating 

plant size had produced. The industry’s characterization as a long-term decreasing cost industry 

came into question. Periods of rapid inflation and higher interest rates substantially increased the 

completion costs of large, base load generating plants.27 New environmental and safety 

regulations required addition of pollution controls and design features that added to costs and 

construction time. Moreover, once in operation, many of the new, larger units required more 

maintenance and longer downtimes than expected. Thus, by the late 1970s, a newer, larger, 

generation facility no longer could be assumed to be more cost-efficient than a smaller plant.28 

 

24 In Public Utilities Commission of Rhode Island v. Attleboro Steam & Electric Co., 273 U.S. 83 (1927), the Supreme Court ruled that state 

regulators were barred by the Commerce Clause from setting the 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 1975 and 

1980. EIA Update 2000 at 114-15. 

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

19 
This 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 generation units to be constructed at lower costs, 

more quickly, and at less financial risk than large base-load coal and nuclear plants.29 Thus, 

construction of low-cost generation became an option for utilities that were formerly captive to 

high-cost generators and emerged as a viable path for new nonutility generators to enter the 

market. 

As the difficulties plaguing utilities’ generation construction programs 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. Significantly higher energy prices added to inflation 

and increased electric rates.30 Other developments also substantially contributed to the growing 

interest in electric utility reforms. First, the 1965 Northeast power blackout raised concerns 

about the reliability of weakly coordinated bulk power system operating arrangements among 

utilities.31 The nuclear accident at the Three Mile Island plant in Pennsylvania on March 28, 

1979, heightened concerns over safety and led to stringent new regulatory requirements for 

nuclear plants. 

Criticism of the traditional cost-of-service utility regulation model by economists and policy 

analysts also increased during the 1970s with suggestions for alternate 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, placed insufficient pressure 

on less efficient suppliers to improve performance, and insulated customers from the cost 

impacts of energy use.32 

Congress enacted the Public Utility Regulatory Policies Act (PURPA) as a response to the 

energy crises of the 1970s. PURPA’s major goal 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 effect was that PURPA 

prompted a number of parties to see potential profits in developing competitive generating 

plants, creating an opportunity for nonutilities to emerge as important electric power producers.33 

PURPA required electric utilities to interconnect with and purchase power from cogeneration 

facilities and small power producers that met statutory criteria for a qualifying facility (QF). A 

utility had to pay the QF at the utility’s incremental cost of production. In a departure from costbased rate approaches, FERC defined this as the utility’s avoided 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 regional reliability councils and the North American Electric Reliability Council 

(NERC) to promote the reliability and adequacy of bulk power supply. EIA Update 2000 at 109. 

32 Paul L. Joskow, The Difficult Transition to Competitive Electricity Markets in the U.S. 6-7 (AEI-Brookings Joint Ctr. for Regulatory Studies, 

Working Paper No. 03-13, 2003), available at http://www.aei-brookings.org/admin/authorpdfs/page.php?id=271 [hereinafter Joskow, Difficult 

Transition]. 

33 See EIA 1970-1991 at 22. 

34 PURPA specifically set forth criteria on who and what could qualify as QFs (mainly technology, size, and ownership criteria). Two types of 

QFs were recognized: cogenerators, which sequentially produce electric energy and another form of energy (such as heat or steam) using the 

20 
discusses 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 power36 and showed that 

nonutilities could build and operate generation facilities effectively and without disrupting the 

reliability of the electric grid. PURPA contributed 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 states, including California, New York, 

Massachusetts, Maine, and New Jersey, required utilities to sign long-term contracts with 

QFs at prices that eventually ended up being 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 markets. 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 where natural gas supplies were available. Federal law largely 

precluded electric utilities from constructing new 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 totaling over 18,000 MW. From 1980 to 1990, FERC 

received a total of 4,610 QF applications for a total of 86,612 MW of generating capacity.38

Following PURPA, continued improvement in generating technology lowered costs and further 

contributed to an influx of new entrants in wholesale markets. They could 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 CONG. RESEARCH SERV., COMM. ON ENERGY AND COMMERCE, 102D CONG., ELECTRICITY: A NEW REGULATORY ORDER? 92 (Comm. Print 

1991). 

21 
profitably with smaller scale generators, including 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 percent 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-fifth of all additions to generating 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 markets, rather than established under cost-of-service 

formulas.44

In 1988, FERC solicited public comments on three notices of proposed rulemaking (NOPRs) 

dealing with electricity pricing in wholesale transactions. These NOPRs addressed the following 

issues: (1) competitive bidding for new power requirements; (2) treatment of independent power 

producers; and (3) determination of avoided costs under PURPA.45 These proposals would have 

moved FERC towards greater use of a “non-traditional” market-based pricing approach in 

ratemaking as opposed to the agency’s “traditional” cost-based approach. The NOPRs, however, 

proved controversial, and efforts to establish formal 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 staff wrote: “The Commission 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 reciprocal 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 regulation of 

wholesale sales by independent power producers, and other public utilities that did not operate retail distribution systems. 

See Administrative Determination of Full Avoided Costs, Sales of Power to Qualifying Facilities, and Interconnection Facilities, Notice of 

Proposed Rulemaking, 53 Fed. Reg. 9,331 (Mar. 22 1988), FERC Stats. & Regs. ¶ 32,457 (1988) (modified by 53 Fed. Reg. 16882 (May 12, 

1988)). This proposal would have revised the 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. Marlette, Associate General Counsel for Hydroelectric and Electric, Federal Energy Regulatory Commission). 

47 Id. at 100. 

22 
whether the seller or its affiliates owned or controlled 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 limiting competition and significantly influencing 

price. The FPA does not allow rates to reflect an exercise of such market power.48

FERC recognized the potential for control of transmission to create market power and the 

challenge such control created in moving to greater reliance on market-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 mitigation of market power, or the existence of a 

workably competitive market, and because the FPA mandates that the Commission prevent 

undue preference and undue discrimination, we believe the Commission is legally required to 

prevent abuse of transmission control and affiliate or any other relationships which may 

influence the price charged a ratepayer.”49

Despite these developments, two limitations at that time were perceived to discourage 

competitive wholesale generation markets. First, IPPs and other generators of cheaper electric 

power could not easily access the transmission grid to reach potential customers.50 Under the 

FPA as then written, FERC had limited authority to order access. FERC would subsequently 

find that "intervening" transmitting utilities would deny or limit transmission service to 

competing suppliers of generation to protect demand for wholesale power supplied by their own 

facilities.51 Second, unlike QFs that enjoyed a statutory exemption under PURPA, IPPs were 

subject to PUHCA 1935, which discouraged nonutilities 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 address what were then seen as the two 

major limitations to the development of a competitive generation sector. 

First, EPAct 1992 created a new category of power producers, called exempt wholesale 

generators (EWGs).53 An EWG is an entity that directly, or indirectly through one or more 

affiliates, owns or operates facilities dedicated exclusively to producing 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 companies 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 and 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 utility business. 

Further, registered holding companies had to obtain Securities and Exchange Commission (SEC) approval for the sale and issuance of securities, 

for transactions among their affiliates and subsidiaries and for services, sales, and construction contracts, and they were required to file extensive 

financial reports with the SEC. 

Although PUHCA 1935 provided for limited exemptions, it was long criticized as discouraging new investment in the electric utility industry by 

nonutility entities. Mergers and acquisitions of utilities subject to PUHCA 1935 have largely been by other domestic and foreign utilities. 

Investment by entities outside the industry has been limited, as these entities avoid the extensive regulations imposed by PUHCA 1935. 

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

54 Joskow, Deregulation at 24. 

23 
major barrier for utility-affiliated and nonaffiliated power producers that wanted to build or 

acquire new non-rate-based power plants to sell electricity at wholesale.55

Second, EPAct 1992 expanded FERC’s authority to order transmitting utilities to 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 protective conditions were met. Although FERC 

implemented this new mandatory wheeling authority, it ultimately concluded 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 exercise of its statutory obligation 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 markets. In Order No. 888, FERC found that undue 

discrimination and anti-competitive practices existed 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 electricity markets. Accordingly, FERC required 

all public utilities that own, control 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 utility 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 wholesale generation, transmission and ancillary 

services; and (3) rely on the same electronic information network that its transmission customers 

rely on to obtain information about the utility’s transmission system.58

Concurrent with Order No. 888, FERC issued Order No. 88959 that imposed standards of 

conduct governing communications between a utility’s transmission and wholesale power 

functions to prevent the utility from giving its power marketing arm preferential access to 

transmission information. Order No. 889 requires each public utility that owns, controls, or 

operates facilities used for the transmission of electric energy in interstate commerce to create or 

participate in an Open Access Same-Time Information System (OASIS). OASIS must provide 

information regarding available transmission capacity, prices, and other information 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 boundaries over transmission and local distribution. 

While it reaffirmed that FERC has exclusive jurisdiction over the rates, terms, and conditions of unbundled retail transmission in interstate 

commerce by public utilities, it nevertheless recognized the legitimate concerns of state regulatory authorities for the development of competition 

within their states. FERC therefore declined to extend its unbundling requirement to the transmission component of bundled retail sales and 

reserved judgment on whether its jurisdiction extends to such transactions. The United States Supreme Court affirmed this element of Order No. 

888. New York v. FERC, 535 U.S. 1 (2002). 

59 Open Access Same-Time Information System (Formerly Real-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). 

24 
enable transmission customers to obtain open access to non-discriminatory transmission 

service.60 

In Order No. 888, FERC also encouraged grid regionalization through the formation of 

independent system operators (ISOs). Participating utilities would voluntarily transfer operating 

control of their transmission facilities to the ISO to ensure independent operation of the 

transmission grid.61 The expectation was that ISO regional control would lead to improved 

coordination, reliability, and 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 nondiscriminatory transmission service and 

information about the availability of transmission service.64

4. Retail Electricity Competition and State Electric Restructuring Initiatives

In the early 1990s, several states with high electricity prices began exploring opening retail 

electric service to competition. While customers would choose their supplier, the delivery of 

electricity would still be done by the local distribution utility. Retail competition was expected 

to result in lower retail prices, innovative services and pricing options. 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 utilities in different states spurred state interest 

in retail competition. For example, in 1998, customers 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 attributed to different natural resource 

endowments across regions, such as the availability of hydroelectric resources in the Northwest 

and of abundant coal reserves in Kentucky and Wyoming– which were reflected in the low cost 

of electricity in these states. In contrast, in more urban states without these resources, 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 contracts that subsequently resulted in higher prices than in the 

wholesale power market.66 These QF contract costs were ultimately reflected in the regulated 

retail rates.67 

Many large industrial customers viewed these rate disparities among states as a competitive 

disadvantage and looked to retail competition as a way 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 example, a survey by the Electricity Consumers 

Resource Council in 1986 contended 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. 

25 
billion annually in subsidies to other electricity customers (e.g., commercial and residential 

customers). 68 It was presumed that allowing industrial customers to choose a new supplier 

would avoid these subsidies, thereby resulting in lower electricity prices for such customers. 

Thus, it was not surprising that many states adopting plans to restructure retail electric service 

were those with higher prices.69 (Figure 4-1 in Chapter 4 shows average retail electricity prices 

in 1995.) States with high electricity rates, such as California and those in New England and the 

mid-Atlantic region, were among the most aggressive in adopting retail competition and 

restructuring electric service in the hope of lowering retail rates. As of 2004, the disparity in 

retail prices among the states persisted, as illustrated in Figure 1-1, below. 

Figure 1-1. U.S. Electric Power Industry, Average Retail Price of Electricity 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

NJ 10.26

10.29

MS

7.00

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

Source: EIA, Electric Power Annual 2004, Figure 7.4 

Most states considered the merits and implications of competition and industry restructuring, but 

not all adopted retail competition plans. As of July 2000, 24 states and the District of Columbia 

had enacted legislation or passed regulatory orders to restructure their electric power industries. 

Two states had legislation or regulatory orders 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. 

26 
The meltdown of California’s electricity markets and the ensuing Western Energy market crisis 

of 2000-2001 are widely perceived to have halted interest by 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 entirely (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 franchise. These states include 44 percent of all 

U.S. retail customers, representing 49 percent of electricity demand. However, 20 states and the 

District of Columbia have state restructuring plans in force that allow competitive retail 

providers to provide service to some if not all retail customers at prices set in the market. 

State retail restructuring plans often involved divestiture of generating assets by local vertically 

integrated utilities. As a result, the distribution utilities that sell electricity to retail customers 

must procure power from wholesale markets under long- or short-term bilateral contracts and 

from wholesale spot markets. These jurisdictions 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 option, 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 under retail restructuring cases are expiring, and POLR rates are 

being revised sharply upward to reflect higher market-based wholesale electricity costs. State 

experience with electric competition and related 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, ENERGY J. 2 (forthcoming 2006), available at

http://stoft.com/metaPage/lib/Joskow-2006-power-market-assessment.pdf [hereinafter Joskow, Interim Assessment]. 

27 
Figure 1-2. Status of State Electric Industry Restructuring Activity and Retail 

Competition, July 2006 

Note: Nevada repealed its retail choice legislation in 2001. It subsequently enacted legislation allowing state regulators to approve requests from 

very lareg C&I customers to procure electricity from alternative suppliers if the contract is found to be in the public interest. 

Source: Task Force Comments and EIA, Status of State Electricity Industry Restructuring Activity 2003, February 2003, available at

http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf. 

5. The Western Energy Market Crisis 2000-2001.

California opened its retail markets to competition and started spot markets for wholesale 

electricity in 1998. In response to the state plan, the three major investor-owned utilities 

divested most of their non-nuclear generation and turned over operation 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 Exchange (CalPX) and the CAISO. 

Retail rates were reduced but remained well above the national average. Rates were then frozen 

until the utilities recovered their stranded costs. At that point, competitive markets were 

expected to drive prices lower. San Diego Gas and Electric (SDG&E) fully recovered its 

stranded costs by summer of 1999, and its retail rates were then allowed to reflect the utility’s 

cost of obtaining power in the wholesale markets. Retail rates for the other two major utilities 

remained frozen. 

In late May 2000, the CAISO called its first Stage 2 power alert as system reserves fell below 5 

percent. PX prices that had averaged about $27 per MWh in April spiked to over $50 in May 

and continued upwards, eventually reaching a high of $450 per MWh in January 2001. These 

higher prices were quickly passed through in San Diego, where average customer bills tripled by 

mid-summer. California’s other major utilities, Pacific Gas and Electric (PG&E) and Southern 

California Edison (SCE), were forced to pay the unexpectedly higher PX wholesale prices, but 

could not pass increases on to retail customers as they were still under a rate freeze. 

28 
Price spikes were not California’s only problems. On June 14, 2000, the CAISO imposed rolling 

blackouts in PG&E’s San Francisco service area because of shortages attributed to the 

maintenance shutdown of several generating plants. 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 pricing 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 abuse of market power when supplies 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 led 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 through retail rates 

threatened the solvency of the state’s three major IOUs. California sought to end the 

procurement difficulties faced by IOUs in the state by entering into long-term contracts to secure 

power on behalf of the utilities and to preserve service to retail customers. Contract prices were 

set at some of the highest prices 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 contracts with competitive suppliers. In April, PG&E’s retail electric 

utility subsidiary, one of the largest in the nation, filed for bankruptcy protection, later joined by 

a number of wholesale seller-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 orders setting and lowering price caps, establishing 

market monitoring requirements, and opening an investigation of possible market manipulation 

in the run-up of natural gas prices in the West. State, federal, 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 power cost adjustment portion of retail rates increased between 30 to 50 percent 

as a direct result of the impacts of the Western energy crisis. Idaho PUC comments. 

76 See discussion infra, Box 4-3. 

77 See, e.g., California Attorney General, Energy White Paper: A Law Enforcement Perspective on the California Energy Crisis, 

Recommendations for Improving Enforcement and Protecting Consumers in Deregulated Energy Markets (April 2004), available at

http://ag.ca.gov/publications/energywhitepaper.pdf [hereinafter Cal. Atty Gen. White Paper]; Federal Energy Regulatory Commission, Final 

Report on Price Manipulation in Western Energy Markets: Fact Finding Investigation of Potential Manipulation of Electric and Natural Gas 

29 
proceedings arising out of the dysfunctional California markets continue today.78 A number of 

energy traders eventually faced criminal charges. The 2000-2001 Western Energy Crisis had 

wide repercussions as other regions adapted their market rules and structures to avoid the 

problems encountered in the West. 

6. Development of Regional Transmission Organizations and Regional Wholesale Markets

After issuing Order Nos. 888 and 889, FERC continued to receive complaints about transmission 

owners discriminating against independent generating companies. Transmission customers 

remained concerned that implementation of functional unbundling did not produce complete 

separation between operating the transmission system and marketing and selling electric power 

in wholesale markets. There were also concerns that Order No. 888 made some discriminatory 

behavior in transmission access more subtle and difficult to identify and document. 

After FERC issued Order Nos. 888 and 889, the electric industry continued to evolve in response 

to competitive pressures and state retail restructuring initiatives. Utilities today purchase more 

wholesale power to meet load than in the past and are relying more on availability of other utility 

transmission facilities to deliver power. Retail competition increased significantly, and state 

initiatives brought about the divestiture of generation plants by traditional electric utilities. In 

addition, there were a number of mergers among traditional electric utilities 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 wholesale 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 complaints of discrimination and lack of 

transmission availability, FERC issued Order No. 2000.79 This order recognized that Order No. 

888 set up the foundation for competitive electric markets, but did not eliminate the potential to 

engage in undue discrimination and preference in providing transmission service.80 FERC 

concluded that regional transmission organizations (RTOs) could eliminate transmission rate 

pancaking,81 increase region-wide reliability, and eliminate any residual discrimination in 

transmission services where operation of the transmission 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 Markets, 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, Committee on Governmental Affairs, Committee Staff Investigation of the Federal Energy Regulatory Commission’s 

Oversight of Enron Corp (November 2002), available at http://hsgac.senate.gov/_files/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 discrimination continue to exist that may not be remedied adequately 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.

30 
RTOs 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 independent 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 transmission services. RTOs currently do not own transmission.82

FERC has approved RTOs or ISOs in several regions 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 territories in the Midwest. In 2004, 

the territories served by Commonwealth Edison (ComEd), American Electric Power (AEP), and 

Dayton Power and Light joined PJM. The expansion continued in 2005 with the addition of 

Duquesne Light and Dominion Resources. 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 coordinating regional planning, at least for facilities necessary for 

reliability above a certain voltage. As of 2004, all RTOs coordinate dispatch of generators in 

their systems and provide transmission services under a single RTO open access tariff. In 

addition to operating the regional transmission grid, RTOs operate regional organized energy 

markets, including a short-term market which prices energy, congestion, and losses. RTOs in the 

East offer day-ahead and real-time markets, while 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 market 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 transmission facilities, they are not precluded by regulation from doing so. FERC’s Order No. 2000 allows 

RTOs that are independent transcos – transmission-owning RTOs that do not own or operate generation and are not affiliated with 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. 

31 
Figure 1-3. RTO Configurations in 2006 

Note: The above map shows the general location of approved RTOs. Not all transmitting utilities within the shaded area of an RTO are 

necessarily members of the RTO and some RTO members are not shown in this map. 

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

The RTO model and regional organized wholesale markets have been voluntarily adopted by 

utilities and market participants in the Northeast, Mid-Atlantic, California, and parts of the 

Midwest and Southwest. Some states required RTO participation as part of restructuring under 

the state retail competition plan. RTO members include 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 comments filed with the Task Force86 raised concerns over 

perceived high costs of RTO implementation and 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 stalled. State regulators and 

utilities in these regions have found it difficult to assess the potential benefits and costs of 

establishing RTOs. They have been reluctant to create new institutional arrangements that could 

diminish local control over transmission facilities and could impose 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). 

32 
7. August 2003 Blackout

On August 14, 2003, an electrical outage in Ohio precipitated a cascading blackout across seven 

other states and as far north as Ontario, Canada, leaving more than 50 million people without 

power.87 The August 2003 blackout was the largest in United States history, leaving some parts 

of the nation without power for up to four days and costing between $4 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 eighth major blackout in North America since the 

1965 Northeast Blackout. A Joint U.S.-Canada Power System Outage Task Force issued a final 

Blackout Report in April 2004. The report identified factors that were common to some of the 

eight major outages from 1965 through the 2003, as shown below: 

(1) conductor contact with trees; (2) overestimation of dynamic reactive output of 

system generators; (3) inability of system operators or coordinators 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 NERC90 carried out their own investigations. 

8. The Energy Policy Act of 2005 

In August 2005, Congress passed EPAct 2005, which amended the core statutes (FPA, PURPA, 

PUHCA 1935) governing the electric power industry. Among the notable provisions of EPAct 

2005 are the following: 

 Reliability: Section 1211 authorizes FERC to certify an Electric Reliability Organization 

to propose and enforce reliability standards for the bulk power system. EPAct 2005 

authorized penalties for violation of these mandatory standards. 

 Transmission Siting: Section 1221 requires the Secretary 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 Secretary of Energy to designate certain areas 

experiencing congestion as “National Interest Electric Transmission Corridors” based on 

these studies. In certain limited circumstances, FERC is authorized to approve 

construction permits for transmission facilities in designated corridors when states either 

lack such authority, or withhold approval for more than one year after filing of an 

application or corridor designation. Proponents of this new federal 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 load and affected 30 million people. 

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. 

33 
will facilitate construction of new transmission and help alleviate transmission congestion 

that can impair competition in electric markets. 

 Transmission Investment Incentives: Section 1241 requires FERC to establish incentivebased rate treatments for public utilities’ transmission infrastructure to promote capital 

investment in transmission infrastructure, attract new investment with an attractive return 

on equity, encourage improvement in transmission technology, and allow for recovery of 

prudently incurred costs related to reliability and improved transmission infrastructure. 

Proponents contend this will encourage the expansion of transmission capacity and, thus, 

help foster greater competition in electric markets. 

 PURPA Reform: Section 1253 permits FERC to terminate, prospectively, the obligation 

of electric utilities to buy power from QFs, such as industrial 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 for PURPA’s “forced sale” requirements. 

 PUHCA 1935 Repeal: Title XVII, subtitle F repeals PUHCA 1935 and replaces it with 

new PUHCA 2005. It provides FERC and state access to books and records of holding 

companies and their members. It also provides 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 from the federal books and records access 

provisions for entities that are 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 Competition in the Electric Energy Industry 

This section discusses several 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 technological improvements 

in gas turbines. It is no longer necessary to build a larger generating plant to gain operating 

efficiencies. Combined-cycle gas turbines reach 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 customers more choices in electricity suppliers.92

 

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

92 Id.

34 
The market participation of utilities and other generation suppliers began changing in response to 

increases in energy costs in the 1970-1990s and the passage of PURPA, which facilitated entry 

of nonutility QFs as energy-efficient, environmentally-friendly, alternative sources of electric 

power. The change continued through Order No. 888, which opened up the transmission grid to 

competing wholesale electricity suppliers.93 Until the early 1980s, electric utilities’ share of 

electric power production increased steadily, reaching 97 percent in 1979.94 By 1991, however, 

the trend had reversed itself, and the utilities’ share declined to 91 percent.95 By 2004, regulated 

electric utilities' share of total generation continued to decline (63.1 percent in 2004 versus 63.4 

percent in 2003) as nonutilities’ share increased (28.2 percent versus 27.4 percent in 2003).96 

This trend is illustrated by comparing increases in capacity additions for utility and nonutility 

generation suppliers, as 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 utilities, 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 Generation Capacity Additions, 1995-2004 

0

10

20

30

40

50

60

70

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Capacity Addition (GW)

NON-UTILITY

UTILITY

Source: FERC analysis of Platts PowerDat data.

However, the pattern of merchant generation investment outpacing utility investment may be 

shifting. Traditional regulated utilities, including 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/electricity/epa/epa.pdf [hereinafter EIA Electric Power Annual 2004]. 

35 
accounted 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 investments in new generation, the Edison Electric Institute (EEI) reports 

that IOU investment in transmission declined from 1975 through 1999. See Figure 1-5. Over 

that period, electricity demand more than doubled, resulting in a significant decrease in 

transmission capacity relative to demand. Box 1-2 suggests reasons for this trend. Since 1999, 

according to EEI surveys, transmission investment 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 percent increase over the prior five-year period. 

Figure 1-5. Transmission Construction Expenditures by Investor-Owned Utilities, Actual 

and Projected, 1975-2009 

 

97 APPA comments (2). 

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

36 
Box 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 investment 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 vertically integrated utility generation from competition, and 

regulatory uncertainty over recovery of new transmission investment. 

Another explanation for the decline in investment is the difficulty of siting new 

transmission lines. Siting can bring long delays and negative 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 creates 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 and 1985, national average residential electricity 

prices more than tripled in nominal terms and increased by 25 percent in real terms (adjusting for 

inflation).99 U.S. real retail electricity prices began to fall after the mid-1980s until 2000-2001 

as fossil fuel prices and interest rates declined and inflation moderated significantly.100 Real 

retail prices stayed flat through 2004, but have begun to increase in all regions reflecting higher 

fuel prices and operating costs. 

According to the latest information from EIA, residential electric prices in 2005 averaged 9.43 

cents per kilowatthour (kWh), an increase of about 5 percent from 2004. Retail electric prices 

continue to increase, and the national average price for residential customers in April 2006 was 

10.31 cents per kWh, up 12 percent from a year earlier.101 These increases reflect 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 substantially and are by far the largest cause of recent electricity 

price increases. On an industry-wide basis, these account for roughly 95 percent of increases in total operations and maintenance (O&M) costs 

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 types of Electricity Providers. Why?, ELEC. PERSPECTIVES 53 (July/August 2006). 

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

2005 

0

2

4

6

8

10

12

14

1960 1965 1970 1975 1980 1985 1990 1995 2000

Cents 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 Generation – Reaction to Increased Oil Prices and 

Clean-Air Environmental Regulations

For many years, coal was the fuel most commonly 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 share of electricity supply began 

decreasing and utilities’ use of oil and gas for new generation was restricted by federal law. 

Hydroelectric power also has played a large role in the supply of electric power, but its share has 

declined relative to other major fuels mainly because there are a limited number of suitable sites 

for hydroelectric projects. Nuclear power emerged as the second largest fuel source in 1991 but 

was not expected to increase.103 

 

103 EIA 1970-1991 at 20. 

38 
For nonutilities, natural gas has been the major fuel for new plant additions.104 Indeed, in recent 

years, new capacity additions reflect the prevalence of natural gas.105 As shown in Figure 1-7, 

recent plant additions illustrate this change. The Clean Air Act Amendments of 1990 (CAA) and 

state clean air requirements also contributed to increased use of natural gas. The CAA sought to 

address the most widespread and persistent pollution problems caused by hydrocarbons and 

nitrogen oxides, both of which are prevalent with traditional coal and petroleum-based 

generation. The CAA fundamentally 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 Dominate New Generating Unit Additions 

0

10

20

30

40

50

60

70

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Capacity (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 nonutilities 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 electricity 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. 

39 
The result of these plant additions through December 2005 is that 49.9 percent of the nation's 

electric power was generated at coal-fired plants (Figure 1-8). Nuclear plants contributed 19.3 

percent; 18.6 percent was generated by natural gas-fired plants, and 2.5 percent was generated at 

petroleum liquid-fired plants. Conventional hydroelectric power provided 6.6 percent of the total, 

while other renewables (primarily biomass, but also geothermal, solar, and wind) and other 

miscellaneous energy sources generated 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 capacity additions may be changing. There is renewed interest in 

coal-fired generation as reflected in utilities’ and nonutilities’ announcements of new coal plant 

construction projects. Two major reasons may explain coal’s resurgence: (1) the relative price 

of natural gas compared to coal has increased substantially and (2) 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 cleaning technology for coal plants would drive the price of coal 

plants significantly higher. Sharp increases in natural gas prices in recent years have challenged 

these assumptions.” DOE’s EIA estimated that 573 MWs of new coal generation would be 

added nationally in 2005, which compares with an estimate of 15,216 MWs of gas-fired 

additions for the same year. For 2009, however, predicted trends shift; the EIA projects that 

8,122 MWs of new coal generation will be added that year, whereas 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 new coal capacity created by 2025). 

40 
Higher gas prices and environmental concerns have also spurred renewed interest in nuclear 

generation. EPAct 2005 includes a number of provisions intended to encourage and facilitate a 

new and improved generation of nuclear power plants. 

5. Fuel Price Trends

Natural gas prices have been increasing in recent years, due in part to historically high petroleum 

prices. Natural gas prices increased 51.5 percent between 2002 and 2003, 10.5 percent between 

2003 and 2004, and 37.6 percent between 2004 and 2005. Strong demand for natural gas, as 

well as natural gas production disruptions in the Gulf of Mexico, contributed to these increases. 

As shown in Figure 1-9, for December 2005 the overall price of fossil fuels was influenced by 

the price increases in natural gas. In December 2005, the average price for fossil fuels was $3.71 

per million Btu (MMBtu), 10.1 percent higher than for November 2005, and 44.4 percent higher 

than in December 2004. As natural gas prices increase relative to coal prices, the change may 

make development of clean-burning coal plants more economically attractive than they were 

when natural gas fuel prices were lower. 

 

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

Dollars per Million Btu 

0

2

4

6

8

10

12

14

Jan-01Jan-02Jan-03Jan-04Jan-05Jan-06

Dollars per Million Btu

Coal

Petroleum

Natural Gas

All Fossil Fuel

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

41 
6. Mergers, Acquisitions, and Power Plant Divestitures of Investor-Owned Electric 

Utilities109

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 the late 1990s between 

traditional electric utilities and between electric utilities and gas pipeline companies. 

IOUs also have divested a substantial number of generation assets to IPPs or transferred them to 

an unregulated nonutility subsidiary within the company.111 Even though FERC-regulated IOUs 

have functionally unbundled generation from transmission, 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 competition view the separation of power generation 

ownership from power transmission and distribution ownership as a prerequisite for retail 

competition. For example, California, Connecticut, Maine, New Hampshire, and Rhode Island 

enacted laws requiring utilities to divest their power plants. In other states, the state public utility 

commission may encourage divestiture to arrive at a quantifiable level of stranded costs for 

purposes of recovery during the transition to competition.112 

Since 1997, IOUs have divested power generation 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 below, between 1998 and 2001, over 300 plants, 

representing nearly 20 percent of U.S. installed generating capacity, changed ownership. 

Since 2001 the merger trends have shifted slightly, as financial difficulties of the merchant 

generating sector have prompted the sale or transfer of a substantial share of the merchant fleet. 

Some purchasers have been traditional utilities, 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: Technological 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 transfers. 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. 

42 
There were no significant electric 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 new 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 specific generation assets. Many companies strove 

to stabilize financial profiles through asset sales. In aggregate, almost 36 GW of generation, or 

nearly 6 percent of installed 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, PNM 

Resources, the parent of Public Service Company of New Mexico, announced the intention to acquire TNP Enterprises, the parent of 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 company by generation ownership, market capitalization, revenues, and net income. Id.

at 32. 

120 Id. at 30. 

43 
CHAPTER 2 

CONTEXT FOR THE TASK FORCE’S STUDY OF COMPETITION IN 

WHOLESALE AND RETAIL ELECTRIC POWER MARKETS

This chapter provides context and theoretical underpinnings to the Task Force’s study of 

competition in wholesale and retail electric power markets. It describes (1) perceived 

shortcomings of traditional cost-based regulation that motivated restructuring and regulatory 

reform, (2) the theoretical role competitive market price signals play in guiding consumption and 

investment decisions,121 and (3) a brief discussion of expected benefits of shifting from 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 generation, 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 facilities 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 failed 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 exchange both for the opportunity to earn a reasonable 

return on its investment and for protection against entry by potential 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 reasonable prices for consumers, as 

required by state laws. Under most 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 rate base, while other states did 

not. In general, disallowances of investments have been rare. 

As described in Chapter 1, beginning in the 1970s, the combined effects of a number of changes 

– improvements in smaller-scale generation technology, transmission, communications and 

control technologies, rising energy prices, environmental policy concerns, increased concerns 

about the effectiveness of traditional utility rate regulation, and 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 STEVEN STOFT, POWER SYSTEM ECONOMICS: 

DESIGNING MARKETS FOR ELECTRICITY (IEEE Press 2002). 

44 
1. 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 marginal cost of generation. These 

rates were stable and often only varied by season. Although time-based rates and certain 

regulated products such as interruptible or curtailable services had been used within the electric 

power industry for decades, they had not been applied to the vast majority of retail customers. 

The average cost-based pricing formula precludes economically 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 price). Inefficient resource use can translate to 

higher production costs and prices. Historical average cost electricity prices, for example, gave 

consumers no economic reason to conserve electricity when supplies were short or demand was 

high. Similarly, suppliers did not receive economically accurate price signals to guide their 

short- and long-term sales of generation. In addition, many industrial customers among others 

have objected that retail rate structures frequently contained cross-subsidies among customer 

classes and thus, further distorted prices.123

2. Effect on Investment Decisions

Regulators’ influence over generation construction decisions likely also contributed to 

inefficiency. Historically, regulators had encouraged local utilities to build or contract for 

sufficient generation to serve customers within their territories. Regulators blocked entry by 

independent generators or allowed the utilities to do so. This resulted 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 price down, the unintended 

effect was to dampen incentives for cost reduction, investment in new capacity and 

innovation.124 More competition might have led earlier to technological innovation and lower 

generation costs. 

The fact that regulators had to agree that a capital investment was necessary and prudent before 

rate recovery was allowed125 further discouraged innovation. Utilities were reluctant to take 

investment risks that might end up being unrecoverable if regulators deemed their cost 

unreasonable. Thus, long-term planners and regulators had significant influence over when and 

where generation would be built. In making decisions, regulators struggled to strike a balance 

between reasonable rates and providing utilities with incentives to make necessary and sufficient 

investments. 

 

122 From an economic perspective, retail electricity prices (or rates) that do not closely track wholesale price trends do not send economically 

“accurate” price signals when they do not reflect temporal variations in production costs and wholesale market prices within days, 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 REGULATION 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. 

45 
This regulatory oversight also possibly encouraged an overcapitalization of the industry, as 

generators were assured a rate of return on any approved capital project. It might also have led 

to undercapitalization if a regulator was too conservative. Further, if rates were set too high, 

utilities could earn a higher return on new generation investments than would be warranted by 

the cost of capital. If regulators were unlikely or unable to identify and disallow excessive 

construction costs, utilities had little incentive to design new generation plants cost-effectively. 

At the same time, regulatory disallowances of some costs imposed risk on utility decisions to 

elicit capital and build new generation, and investors sought compensation for this risk when 

they supplied capital to utilities.126

Ultimately, ratepayers were left to bear much of the investment risk, as they had to pay for 

regulator-approved projects resulting in overinvestment as well as any subsequent higher costs 

from underinvestment (for example, costs of running higher cost generation more often than is 

economically efficient). 

A 1983 DOE analysis of electric power generation plant construction showed that electric 

utilities (regulated under a cost-based regulatory regime) had limited ability to control 

construction costs of coal and nuclear plants. During the 1970s and early 1980s, the cost range 

per MW to build a nuclear plant varied by nearly 400 percent and by 300 percent for coal plants. 

The study showed that some companies were not competent to manage such large-scale, capitalintensive projects. In addition, they tended to custom design plants, as opposed to using a basic 

design and then refining it.127 

One alternative to traditional cost-based rate-of-return regulation is price cap regulation. Under 

this approach, the regulator caps the price a firm is allowed to charge.128 This alternative may 

remedy some of the incentive problems of cost-based regulation, but comes with its own costs. 

Another alternative is the addition of an open, transparent Integrated Resource Planning process 

by utilities to consider and support choices about building new generation 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 may approve the resulting 

plan. Even with this oversight mechanism, regulators have few reference points to determine if a 

builder’s choices about design, efficiency, and materials for the IRP selected plant are prudent. 

 

126 In the academic literature, the risk of utility overinvestment has been explained by the Averch-Johnson Effect. The Averch-Johnson Effect 

reflects that “a firm that is attempting to maximize profits is given, by the form of regulation itself, incentives to be inefficient. Furthermore, the 

aspects of monopoly control that regulation is intended to address, such as high prices, are not necessarily mitigated, and could be made worse, 

by the regulation.” KENNETH E. TRAIN, OPTIMAL REGULATION 19 (1991) [hereinafter TRAIN]. 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 increase its relative use of 

capital. Id. at 56. Thus, the most obvious regulatory control within cost-base rate regulation creates further distortions. The Averch-Johnson 

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 America: Economic Supply for Economic Growth (June 1983) (DOE/PE-0045). 

128 Under price cap regulation, a firm can theoretically “produce with the cost-minimizing input mix [and] invest in cost-effective innovation.” 

TRAIN at 318. However, this dynamic only occurs where the price cap is fixed over time and the utility receives the benefit of cost reductions and 

cost-effective innovations. Further, the benefit of this increased efficiency “accrues entirely to the firm: consumers do not benefit from the 

production efficiency.” Id. Where the price cap is adjusted over time, firms are induced to engage in strategic behavior. Additionally, “if, as . . . 

expected, the review of price caps is conducted like the price reviews under cost-base rate regulation, then the distinction blurs 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 behavior from the regulated firm is to include periodic, automatic reductions in rates based on general 

trends in productivity. 

46 
3. Motivation for Change

In part, the struggles of regulators 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. Advances in technology also allowed the entry of a 

variety of new, nonutility generators and demand response alternatives and weakened the 

argument for preserving utilities’ monopolies on generation 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, transmission and distribution have continued to be 

regulated services. 

B. Overview of the Role of Price in Competitive Wholesale and Retail Electric Power 

Markets 

How much a supplier will produce at a given price is determined by many things, including (in 

the long run) how much it must pay for the labor it hires, the land and resources it uses, the 

capital it employs, the fuel inputs it must purchase to generate the electric power, the 

transmission it must use to deliver the electric power to end users, and the risks associated with 

its investment. Consumers’ overall 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 based on economic theory of how competition might 

determine prices and discipline investment in the 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 function 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 response to an increase in prices, the less market power sellers are 

likely to have. Lower prices encourage customers to increase consumption. Consumer price 

responsiveness is often referred to as “demand response.”129

The primary purpose of incorporating market driven prices into wholesale and retail electric 

power markets is to provide price signals that accurately reflect underlying costs of production 

and thereby encourage efficient consumption patterns. Economic 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 Section 1252 of the Energy Policy Act of 2005 (February 2006) [hereinafter DOE EPAct Demand Response 

Report]. The DOE EPAct Demand Response Report discusses the benefits of demand response in electric power markets and makes 

recommendations to achieve these benefits. 

47 
Accurate 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 based 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 optimally efficient system in hours when electricity 

prices are higher than the average 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 scarcity 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 and producers to supply less. Prices will stop 

rising or falling when they reach the new equilibrium price: the price at which the 

quantity that consumers demand matches the quantity that producers supply. 

When there are many close substitutes for a particular commodity, a relatively small price 

increase will result in a relatively large reduction in consumption. For example, if natural gas 

were a very good substitute for electric 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 consumers to return to electricity, electricity 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 rise substantially to reduce consumption by a significant amount. 

Empirical literature shows that, even if the retail price of electricity increases by a large 

percentage, consumption of electricity does not decline much. In economic terms, it is said that 

the short-run demand for electricity is “inelastic” with respect to price. See Box 2-2. This 

inability to substitute other products for electricity in the short run means that changes in supply 

conditions (price of input fuels, etc.) are likely to cause wider price fluctuations than would be 

the case if customers could easily reduce consumption 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. CREW & P. KLEINDORFER, PUBLIC 

UTILITY ECONOMICS (St. Martin’s Press 1979); B. MITCHELL, W. MANNING, & J. PAUL ACTON, PEAK–LOAD PRICING (Ballinger 1978). 

Other papers suggest that setting rates based on marginal costs will result in a misallocation of resources. See S. Borenstein, The Long-Run 

Efficiency of Real-Time Pricing, 26:3 ENERGY J. (2005). Nevertheless, the literature also indicates that marginal-cost pricing may result in a 

revenue shortfall or excess, and standard rate-making practice is to require an adjustment (presumably to an inelastic component) to reconcile 

with embedded cost-of-service. Various rate structures to accomplish marginal-cost pricing include two-part tariffs and allocation of shortfalls to 

rate classes. See VISCUSI, ET AL. 

131 The reduction of cross subsidies can be seen as having both positive and negative implications for society as a whole – depending on one’s 

perspective and whether the cross-subsidy supports publicly acceptable goals, such as rural electrification. 

132 DOE EPAct Demand Response Report at 7. 

48 
consequences for supply shortfalls can be significant.133 In the long run, this effect may be 

somewhat muted as customers may have more ability 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 change the amount of a product they will purchase 

when its price increases is at the core of the concept of price elasticity of demand for that 

product. The price elasticity of demand is the 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 demand 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 adjust their electricity consumption and are at least 

somewhat responsive to short-run price changes (i.e., have a non-zero short-run price elasticity 

of demand). Georgia Power's Real Time Pricing (RTP) tariff option found that certain large 

industrial customers who receive RTP based on an hour-ahead market are somewhat priceresponsive (short-run price elasticities 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 moderate 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 determined that a test group of residential and small 

business customers responded to price and significantly reduced consumption (13 percent on 

average, and as much as 27 percent when automated controls such as controllable thermostats 

were installed) during critical peak periods. In addition, the California pilot found that most 

customers on the CPP tariffs had a favorable opinion of the rates and would be interested in 

continuing in the program.135

Customer response to prices requires the following conditions: (1) that time-differentiated price 

signals are communicated to customers; (2) that customers have the ability to respond to price 

signals (e.g., by reducing consumption and/or turning on an on-site generator); and (3) that 

customers have interval meters (i.e., so the utility can determine how much 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 billion. 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 ELECTRICITY 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/documents/group3_final_reports/2005-03-24_SPP_FINAL_REP.PDF. Customers on a similar CPP 

program at Gulf Power also have high satisfaction with the program, which incorporates automated response to CPP events. 

49 
what time and bill accordingly).136 Most conventional metering and billing systems are 

inadequate for charging time-varying rates, and most customers are not used to considering price 

changes in making consumption decisions on a daily or hourly basis. There is, however, a 

significant effort underway to improve metering technology and infrastructure to better facilitate 

end-use price responsiveness.137

2. Supplier Responses Interact with Customer Demand Responses to Drive Production

Generation supply responses are equally important in the theoretical determination of an 

appropriate market price. The extent of supply responses will depend on the cost of increasing 

or decreasing output. Generally, the longer industry has to adjust to a change in demand, the 

lower the cost of expanding output will be. With more time, firms have more opportunity to 

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 response to increased demand. If the cost of 

increasing electricity output is high, however, suppliers will not increase production unless the 

price increases enough to cover the higher costs. In that case, customers would be compelled to 

pay significantly higher prices for additional supply. Additionally, when suppliers are already 

delivering as much electric power as they physically can, increased demand can be met only 

from new capacity. If prices are to provide incentives for resource 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 inventories of electricity. Therefore, 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 transmission 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 positive externalities (depending on the method used 

in accounting for transmission costs).141 That is to say, where transmission users are not charged 

for the congestion impacts of their use patterns, users’ actions can cause costs to others which the 

causal party is not obligated to pay. This dynamic can distort the effect of price signals on 

dispatch efficiencies. 

 

136 See EEI comments. Pepco cautions that many customers, particularly residential and commercial customers, are relatively inflexible 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 energy in wholesale markets can vary as a function of the cost of owned generation and existing contracts, the 

ultimate demand for energy is entirely a function of end-use load. 

140 Alcoa comments. 

141 TAPS comments. 

50 
Another complication derives from the fact that aggregate retail demand fluctuates throughout 

the day and over seasons, with typically higher demand during the day than at night. System 

operators must maintain a sufficient 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 year. Thus, load-serving entities must supply or 

procure (through long-term contracts 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, “intermediate” 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 plants). Intermediate load plants 

are designed to be brought online and shut down quickly 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 tends 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 electricity for these different applications can differ substantially. 

In any case, a higher price driven by resource scarcity should signal a legitimate opportunity for 

economic profit, attracting new resource construction where it is most highly valued. At the 

same time customer demand may decrease in response to rising prices. The increase in resources 

coupled with a demand response should work together to bring 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 equilibrium price. Current prices must change when they create 

an imbalance between the quantity demanded and 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, consumers do not have many good substitutes for electric 

power, and suppliers usually cannot increase output instantly or transport distant available 

generation to increase the quantity supplied to a market. Even if higher 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 options 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 additional generation. 

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

While the shortcomings of cost-based regulation played a major role in the shift toward 

competitive electricity market structures, some market participants question whether the benefits 

outweigh the costs associated with establishing such markets. Some question whether electricity 

markets are, by nature, sufficiently competitive to warrant expected price reductions.142 They 

note the cost of operating ISOs and the cost to consumers of market manipulations and failures. 

Respondents to these concerns suggest that these markets are too new to warrant passing such 

 

142 APPA comments. 

51 
judgment. 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 whether to deregulate electricity markets, some 

conducted formal cost-benefit studies to address the relative benefits of the status quo versus 

proposed policy changes. The Task Force received many comments identifying, endorsing, or 

criticizing such studies. The Task Force did not, however, have the resources or time to fully 

examine, critique, or draw definitive conclusions from these widely varying studies. An 

annotated bibliography of many of these studies is attached as Appendix C. The Task Force also 

refers the reader to the summary conclusion of a 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 methodological improvements for future studies. 

Following is a summary of this study’s conclusions. 

In recent years, government and private organizations have issued numerous studies of 

the benefits and costs of regional 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 techniques, 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 from 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 for 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 basis for ongoing assessment of the electric 

industry’s evolution. These efforts should 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 these 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). 

52 
CHAPTER 3 

COMPETITION IN WHOLESALE ELECTRIC POWER MARKETS 

A. Introduction and Overview

As described in the preceding chapters, prior to the introduction of wholesale market 

competition, vertically integrated utilities sold their 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 conditions of interstate wholesale sales by investor-owned utilities. 

Wholesale purchasers’ desire to escape being captive to a vertically integrated monopoly 

supplier of electricity was a fundamental impetus to opening the generation sector to 

competition.144 Sellers of wholesale power were also interested 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 that effective competition ensures an economically 

efficient allocation of resources. 

As described in Chapter 2, an important effect of a competitive market operation is that it 

provides customers with prices that reflect market conditions (abundance, scarcity, etc.). These 

market-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 derived entirely from consumption choices at the retail level. 

In electricity there has been an impediment to efficiency 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 consumption 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 difficulty in providing incentives for investors to make economically 

efficient decisions concerning when, where, and how to build new generation.146 If competition 

is to allocate resources in an economically efficient manner, customers must have access to a 

sufficient number of competing suppliers either via transmission, incumbent generation, demand 

response, or new local generation.147 

 

143 Wholesale markets involve sales of electric power among generators, marketers, and load serving entities (i.e., distribution utilities and 

competitive retail providers) that ultimately resell the electric power to end-use customers (e.g., residential, commercial, and industrial 

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 sources of wholesale power for a planned municipal distribution system). 

145 See discussion infra Chapter 1. 

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

147 In a 2002 report, the then-named General Accounting Office made a related point, connecting increasing competition to structural changes. 

U.S. General Accounting Office, GAO-03-271, Lessons Learned From Electric Industry Restructuring, at 21 (2002) (“Increasing the amount of 

competition requires structural changes within the electric industry, such as allowing a greater number of sellers and buyers of electricity to enter 

the market”). 

53 
Competitive policies in electricity markets were introduced to alleviate these disconnects 

between retail demand, wholesale demand, and investment incentives and to create more 

efficient markets.148 In EPAct 1992, Congress determined that competition in wholesale electric 

markets would benefit from two changes to the traditional regulatory landscape: (1) expansion 

of FERC’s authority to order utilities to transmit, or “wheel,” electric power on behalf of others 

over their own transmission lines and (2) reduction of entry barriers so additional nonutilities 

could enter the market. The former change permitted wholesale customers to purchase supply 

from distant generators, while the 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 question 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 region was at a different regulatory and structural 

point when Congress enacted EPAct 1992. For example, some regions began with tight power 

pools, while others operated transmission and generation in a less centralized manner. Some 

regions had higher population densities and thus more tightly configured transmission networks 

than did others. Some regions had access to fuel 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 anecdotally – by addressing whether and how entry 

has occurred in several regions with different forms of competition (i.e., the Midwest, Southeast, 

California, the Northwest, Texas, and the Northeast). It includes a discussion of how long-term 

purchase and supply contracts, capital requirements, regulatory intervention, and transmission 

investment affect supplier and customer decisions. The chapter concludes with observations on 

various regional experiences with wholesale 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 energy security goals and to protect consumers.”151 

Policymakers recognized that vertically integrated utilities had market power in both 

 

148 It is important to note that competition in wholesale electric markets may not lead to an efficient allocation of resources involving the services 

that prevent network collapse. Where there are “public good” aspects to the delivery of a good or service, such as with reliability, regulation may 

be the best way to ensure that the correct level of the good or service is provided. In some circumstances, however, market remedies may be 

available 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 Commission correctly commented that another metric with which to measure competition is its effect on 

production efficiencies. The Task Force did not seek to quantify this effect, given the constraints of the Report. 

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

54 
transmission and generation because they owned all transmission and nearly all generation plants 

within certain geographic areas. Congress enhanced FERC’s ability to reduce monopoly power 

by enhancing its authority to order utilities, case by case, to transmit power for alternative 

sources of generation supply. 

Today, vertically integrated utilities and other entities that operate transmission systems 

generally are required to offer transmission service under the terms of the standard Open Access 

Transmission Tariff (OATT) adopted by FERC in Order No. 888.152 Transmission providers 

offer two types of long-term transmission service under the OATT: network integration 

transmission service (network service) and point-to-point transmission 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 both 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 service is known in advance. For network service, the transmission customer 

pays a load-ratio share of the transmission provider’s FERC-approved transmission revenue requirement. Thus, even if redispatch to relieve 

transmission congestion occurs and the costs are charged to customers, or expansion is necessary and the expansion costs are added to the 

revenue requirement, the distribution over the whole system has allowed the charges to individual customers to remain relatively stable. 

Customers who take either service have a right to continue taking service when their contract expires, although point-to-point customers may 

have to pay a different rate (up to the maximum rate in the transmission provider’s tariff) if another customer offers a higher rate. 

55 
Box 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 transmission customers (e.g., load-serving entities) to 

integrate their generation supply and load demand with that of the transmission provider. 

A transmission customer taking network service designates “network resources,” which 

include all generation owned, purchased or leased by the network customer to serve its 

designated load, and individual network loads to which the transmission provider will provide 

transmission service. The transmission provider 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 network service, it agrees to “redispatch” its generators as 

requested by the transmission provider. Redispatch occurs when a utility, due to congestion, 

changes the output of its generators (either by producing more or less energy) to maintain the 

energy balance on the system. If the transmission provider redispatches its system due to 

congestion to accommodate a network customer’s needs, the costs of that redispatch are 

passed through to all of the transmission provider’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 expansions are needed to maintain service 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 service, which is available on a firm or non-firm basis and on a 

long-term (one year or longer) or short-term basis, provides for transmission between 

designated points of receipt and designated points of delivery. Transmission customers that 

take this kind of service specify a contract path. A customer taking firm point-to-point 

transmission service pays a monthly demand charge 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 the incremental costs of any system expansion 

needed to provide the service. If the transmission 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 concerns over transmission-dependent customers’ 

access to alternative generator suppliers via OATTs. In particular, some commenters noted the 

56 
continued possibility of transmission discrimination 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 terminated for anticompetitive reasons by their vertically 

integrated rival, if they purchase from a generator that is not affiliated with the transmission 

provider. The facts that electricity 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 regional transmission grid to an 

independent operator, such as the ISOs and RTOs 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 physical access to the transmission system (subject to transmission 

security constraints). See Box 3-2 for a discussion 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 listed had “power pools” of utilities that undertook some central economic dispatch of 

plants and divided the cost savings among the vertically integrated utility members. 

156 For example, RTOs using LMP pricing address physical deliverability concerns by giving physical access to all users willing to pay the 

market-determined price. The potential for high LMPs due to limited transmission availability presents a risk that many market participants 

prefer to hedge. Financial transmission rights (FTRs) have been developed as a means for transmission users to hedge against transmission 

pricing risk. The amount of FTR MWs available for hedging are determined by the transmission capabilities of the grid, so that a holder of an 

FTR generally can depend on being able to use the transmission service covered by the 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 proportion to the total 

requests for FTRs for a particular transmission service. Under the latter two approaches, some historic transmission users may have to acquire 

additional FTRs from other parties in order to hedge their previous levels of transmission use. In particular, in circumstances where certain 

transmission paths have become highly congested, historic transmission users may have to make significant expenditures to maintain traditional 

levels of transmission rights. 

57 
Box 3-2 

How Transmission Is Priced in an ISO or RTO 

ISOs and RTOs (hereinafter RTOs) provide transmission service across a region under a single 

transmission tariff. They also operate organized electricity markets 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 type of transmission service with the transmission owner under 

an OATT. 

The pricing for transmission service is substantially different in these regions than under a 

standard OATT. RTOs generally manage congestion 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 market or obtained through some 

other method) at each location in the grid at any given time reflects the cost of making 

available an additional unit of electric power for purchase at that location and time. In other 

words, congestion may require the additional unit of energy to come from a more expensive 

generating unit than the one that cannot be accessed due to the system congestion. In the 

absence of transmission congestion, all prices within a given area are the same at any given 

time. However, when congestion is present, the prices at various locations typically will not 

be the same, and the difference between any two locational prices represents the cost of 

transmission system congestion between those locations. This congestion cost constitutes the 

only significant “variable cost” of transmission – the fixed costs of infrastructure investment 

are recovered through a standard transmission access fee. 

Because congestion on the grid changes constantly, a transmission customer may be unable to 

determine beforehand the price for electric power at any location. To reduce this uncertainty, 

RTOs make a financial form of transmission rights available to transmission customers, as 

well as other market participants. Generally known as financial 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 costs paid by any user of the transmission system 

and collected by the RTO for electricity delivered over the specific path. In short, if a 

transmission customer holds an FTR for the path it takes service over, it will pay on net either 

no congestion charges (if the FTR matches the path exactly) or lower congestion charges (if 

the FTR partially matches), providing a financial “hedge” against the uncertainty. 

In general, FTRs are now available for one-year terms (or less) and are allocated to entities 

that pay access charges or fixed transmission rates. Pursuant to EPAct 2005, FERC has 

adopted rules to ensure the availability of long-term FTRs. 

In regions with RTOs, wholesale electricity can be bought and sold through negotiated bilateral 

contracts, through “standard commercial products” available in all regions, and through various 

products offered by the organized exchange market. 

For bilateral contracts, the contract can be individually negotiated with terms and conditions 

unique to a single transaction. Standard products are available through brokers and over-the58 
counter (OTC) exchanges such as the NYMEX and InterContinental Exchange (ICE).157 

Standard products have a standard set of specifications 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 markets typically involve both real-time and dayahead sales. Ancillary services include various 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 whether the price signals described in Chapter 2 

have functioned to elicit the consumption and investment decisions that were expected to occur 

with wholesale market competition. 

C. Wholesale Electric Power Markets and Generation Investment by Region 

New generation investment has varied significantly by region since 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. Moreover, regions that operate exchange markets for 

electric power and ancillary services use different forms of locational pricing, price mitigation, 

and capacity markets. 

 

157 Companies can also limit their exposure to price swings through financial instruments rather than contracts for physical delivery of electricity. 

Such contracts are essentially a bet between two parties as to the future price level of a commodity. If the actual price for power at a given time 

and location is higher than a financial contract price, Party A pays Party B the difference; if the price is lower, Party B pays Party A the 

difference. In fact, in the United States electricity markets, such agreements are sometimes called “contracts for differences.” Purely financial 

contracts involve no obligation to deliver physical power. In this report, the Task Force discusses contracts for physical delivery rather than 

financial contracts, unless otherwise noted. 

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

0

10

20

30

40

50

60

70

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Capacity (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 transmission services to wholesale customers in its 

footprint. On April 1, 2005, the Midwest Independent System Operator (MISO) commenced its 

organized electric power market operations. Prior to that, there were no centralized electric 

power exchange markets and wholesale customers obtained transmission under each utility’s 

OATT. 

b. New Generation Investment 

Wholesale prices spiked in the 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). 

60 
new generation was built in response to the price spike, as shown in Table 3-1. For example, 

from January 2002 through June 2003, the Midwest added 14,471 MW in capacity.159

Most of the new generation was gas-fired, even though the region as a whole relies primarily on 

coal-fired generation.160 More recently, new generation has been coal fired, in part because of 

rising natural gas prices.161 This entry and the subsequent drop in 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 transmission under each utility’s OATT (e.g., Entergy 

or Southern Companies). There are no centralized electric power 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 building 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 Southern control area between 2000 and 2005,162 and several 

generation units owned by merchants or load-serving entities have been built in the Carolinas in 

the past few years. 

A significant portion of the region’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 been purchased by local vertically integrated 

utilities and cooperatives, such as Mirant’s sale of its Wrightsville plant to Arkansas Electric 

Cooperative Corporation and NRG’s sale of its Audrain plant to Ameren.163 Even apart from 

bankruptcies, some independent power producers 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/sectors/special_reports.cfm?sector_flag=2&marketsector=1&detail=&body_content=spl_rpt. 

61 
3. California

a. Wholesale Market Organization 

The California ISO began operation in 1998 to provide transmission services. Concurrently, a 

separate Power Exchange (PX) operated electric power exchanges. After the 2000-2001 energy 

crisis, the PX was dissolved.164

b. New Generation Investment 

Even before the California energy crisis, California depended on imported electric power from 

neighboring states. Much of the generation capacity that serves load in Southern California was 

built a substantial distance away from the population it serves, making the region heavily 

dependent upon transmission. In the past few years, much of the generation in California has 

operated under long-term contracts negotiated by the state during the energy crisis.165 Since 

2000-2001, California’s demand has increased, but construction of local generation has not kept 

pace. Over 6,000 MW of new generation capacity 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 between 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 transmission services as well as a centralized electric 

power market. Under the electric power pricing mechanism adopted by ISO-NE, certain units 

used to maintain local resource adequacy must bid into the energy markets at marginal costs 

under must-run reliability contracts. 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 been built in less populated areas of the region, 

such as Maine, while most of the demand for power is in southern New England. From January 

2002 through June 2003, ISO-NE added 4,159 MW in capacity.168 There were fewer capacity 

additions in 2004 than in the two previous years. In 2004, four generation projects came on line. 

Generation retirements in 2004 totaled 343 MW, of which 212 MW are deactivated reserves. 

 

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

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

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

167 CAISO comments. 

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

62 
Demand growth in the organized New England markets has led to “load pockets,” areas of high 

population density and high peak demand 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, and transmission has not always been adequate to 

bridge this gap. In general, New England needs new generation in the congested areas of Boston 

and Southwest Connecticut, increased demand response, or increased transmission investment to 

reduce congestion. Significant transmission upgrades were expected 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 incentives. 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 auctions 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 ability to import capacity necessary to meet local 

demand. 

5. New York

a. Wholesale Market Operation 

NYISO provides transmission services as well as a centralized electric power market. NYISO 

uses price mitigation to guard against wholesale price spikes, but, in contrast to early ISO-NE 

practice, it includes high-cost generators in marginal locational pricing. 

b. New Generation Investment 

New York traditionally has built generation in less populated areas and transmitted the power to 

more populated areas. For example, the New York Power Authority was created, in part, to get 

hydroelectric power from the Niagara Falls area into more congested areas of the state. From 

January 2002 through June 2003, NYISO added 316 MW in capacity.173 Three generating plants 

 

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

170 FERC State of the Markets Report 2002-2003 at 83 (“These load pockets did not exhibit materially higher locational prices in 2004, probably 

because the cost of expensive units used to ensure resource adequacy and 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 England 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. 

63 
with a total summer capacity of 1,258 MW came on line in 2004. Three plants totaling 170 MW 

retired in 2004.174 

Currently, transmission constraints in and around New York City limit competition in the city 

and lead to greater use of expensive local generation, which results in high prices. NYISO uses 

price mitigation measures designed to avoid mitigating 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 running 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, NYISO also sets a more generous “reference price” 

for new generators in their first 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 investment 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 commented that it is the public power agencies and traditional 

investor-owned utilities – rather than merchants responding to NYISO prices – that have 

invested in new infrastructure. 

The effect of load pockets on prices is shown in Figure 3-2, which estimates the annual value of 

capacity based on weighted average results of three types of auctions run by the NYISO. 

Capacity prices are higher in the tighter 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. 

64 
Figure 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

Weighted Average ICAP ($/kw-yr)

through 7/28/06)

LI

NYC

ROS

Source: FERC analysis of NYISO data 

6. PJM

a. Wholesale Market Operation 

The PJM Interconnection provides transmission 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 generation mix, although the National 

Rural Electric Cooperative Association (NRECA) commented that 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 completed 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. 

65 
Like 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, within the eastern region, there are areas of even 

more limited transmission. As a result, in some areas generation that is not economical to run is 

given reliability must-run (RMR) contracts to prevent it from retiring and possibly reducing local 

reliability.179 Recently, three utilities in PJM proposed 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 (ERCOT) manages power scheduling on an electric 

grid consisting of about 77,000 MWs of generation capacity and 38,000 miles of transmission 

lines. It also manages financial settlement for market participants in Texas's deregulated 

wholesale bulk power and retail electric market. The Public Utility Commission of Texas 

regulates ERCOT. ERCOT generally is not subject to FERC jurisdiction because its operations 

are not integrated with other electric 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 Constraints (CSCs). Once approved by the ERCOT Board, the CSCs 

and the resulting Congestion Zones are used by the 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 against load within each zone. To balance the 

system in real time, ERCOT issues unit-specific instructions to manage Local (intra-zonal) 

Congestion, then clears the zonal Balancing Energy Market. The balancing energy bids from all 

the generators are cleared in order of lowest to highest bid.181 

 

179 Id. at 188. 

180 AEP proposes to build a new 765-kilovolt (kV) transmission line stretching from West Virginia to New Jersey, with a projected in-service date 

of 2014. AEP Interstate Project Summary, available at http://www.aep.com/newsroom/resources/docs/AEP_InterstateProjectSummary.pdf. 

Allegheny Power (Allegheny) proposes to construct a new 500-kV transmission line, with a targeted completion date of 2011, which will extend 

from southwestern Pennsylvania to existing substations in West Virginia and Virginia and continue east to Dominion Virginia Power’s Loudoun 

Substation. Allegheny Power Transmission Expansion Proposal, available at http://www.alleghenypower.com/TrAIL/TrAIL.asp. More 

recently, Pepco has proposed to build a 500-kv transmission line from 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/DocumentsandMedia/ercot2.pdf. 

66 
At least one study asserts that when there is local congestion, local market power is mitigated in 

ERCOT by ad hoc procedures aimed at keeping prices relatively low while maintaining 

transmission flows within limits. The study concludes 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 make 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 implement an energy-only resource adequacy 

market design in the fall of 2006 that requires incrementally 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 customers, to respond to market-based price signals. Under the 

Load Acting As a Resource Program (LAAR), customers bid demand response into ERCOT's 

ancillary services market for responsive reserves through their scheduling agent.186 If needed by 

ERCOT, the load is then paid the market-clearing price for responsive reserve. The LAAR 

program is fully subscribed at 1,150 MWs. 

8. The Northwest 

a. Wholesale Market Organization 

Wholesale customers obtain transmission service through agreements executed pursuant to 

individual utility OATTs. There are no centralized exchange markets specific to the region, but 

there is an active bilateral market for short-term sales within the Northwest and to the Southwest 

and California, which makes use of centralized electronic exchange platforms (such as the 

InterContinental Exchange). Several trading hubs with significant levels of liquidity provide 

price information. Multiple attempts to establish a centralized Northwest transmission operator 

have proven unsuccessful for a variety of reasons, including difficulties in applying standard 

restructuring ideas to a system dominated by cascading (i.e., interdependent nodes) hydroelectric 

generation and difficulties in understanding the potential cost shifts that might result in 

 

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

183 U.S. General Accounting Office, GAO-02-427, Restructured Electricity Markets, Three States' 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. 

67 
restructuring contract-based transmission rights. A nascent organization created to enhance 

coordinated regional reliability 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 resources in the region on an energy basis.188 Coal and natural gas 

resources make up most of the remaining generation, with smaller contributions from wind, 

nuclear, and other resources. The hydroelectric share has decreased steadily since the 1960s. 

The Northwest’s hydroelectric base allows the region to meet almost any capacity demands 

within the region, but the region is susceptible to energy limitations (given the finite amount of 

water available to flow through dams). This ability 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, hydro 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 Current Wholesale Market Options 

One of the most diffiult questions federal regulators currently face is whether the different forms 

of competition in wholesale markets have resulted in an efficient allocation of resources. The 

various approaches used by the different regions show the range of available options. 

1. Open Access Transmission without an Organized Exchange Market 

One option is to rely on the OATT to make generation options 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 Southeast). However, active trading platforms can be 

found in these regions. These platforms provide liquidity and price transparency in some dayahead or longer-term markets – although the prices do not directly reflect the costs of congestion. 

For long-term sales in these markets, wholesale customers shop for alternatives through bilateral 

contracts with suppliers. In both cases, customers separately arrange for transmission via the 

OATT. With a range of supply options to choose from, long-term bilateral contracts for physical 

supply can provide price stability 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. 

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

in these markets. 

This model depends significantly on the 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, persistent allegations of 

discrimination can discourage investment even if they are not proven. Without the assurance of 

long-term transmission rights, wholesale customers 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. Similarly, new suppliers may have no means of competing with 

incumbent generators located close to traditional load. 

2. Organized Wholesale Markets

In organized markets, market participants have access to an exchange market where prices for 

electric power are set in reference to supply 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 uniform price auction to determine the price of 

electric power. Uniform price auctions theoretically provide suppliers an incentive to bid their 

marginal costs, to maximize their chance of getting dispatched. 

The principal alternative to uniform price auctions is a pay-as-bid market.189 Research on 

whether pay-as-bid auctions result in lower prices than do uniform price auctions has been 

evolving and the results are, at best, mixed. Theoretically, pay-as-bid auctions do not result in 

lower market-clearing prices and may even raise prices as suppliers base their bids on forecasts 

of market-clearing prices instead of their marginal costs. Recent research suggests that pay-asbid can sometimes result in lower costs for customers.190 But the pay-as-bid approach may 

reduce dispatch efficiency, to the extent generator bids deviate from their marginal costs.191 

From a practical perspective, academics and market designers generally agree that uniform price 

auctions in competitively structured markets produce economically efficient prices. 

Currently, in uniform price auction markets some generators (e.g., coal- or nuclear-fueled units) 

may be earning a return above those typically allowed under cost-based regulation. But other 

generators (e.g., natural gas-fueled units) are earning 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 production 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 prices, 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 Pricing: A Dilemma for California and Beyond (Blue Ribbon Panel Report, study 

commissioned by the California Power Exchange, 2001). 

69 
some 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 creates 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 uniform 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, way to spur entry is to let wholesale market prices rise with 

scarcity.192 As discussed in Chapter 2, the market likely will respond in two ways. First, the 

resulting price spikes will attract capital and investment. To assure that the price signals elicit 

appropriate investment and consumption decisions, they must reflect the differences in prices of 

electricity available to serve particular locations. The costs of supplying customers within the 

region may vary where transmission capacity limits the availability of electric power from some 

generators within a regional market. Without locational prices, investors may not make wise 

choices about where to invest in new generation. 

Unfortunately, it is difficult to distinguish high prices due to the exercise of market power from 

those due to genuine scarcity. High prices due to scarcity are consistent with the existence of a 

competitive market, and therefore perhaps suggest less need for regulatory intervention. High 

prices stemming from the exercise of market power in the form of withholding capacity may 

justify regulatory intervention. Being able to distinguish between the two situations is therefore 

important in markets with market-based pricing.193

Second, higher prices likely will influence customer 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 with 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 Texas describes a plan it expects to adopt in summer 2006, to raise 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 PUB. UTIL. FORTNIGHTLY 40 (1999). 

Wholesale customers with supply contracts for which the prices were tied to the market price paid higher prices for electric power during those 

hours. 

70 
market-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 where 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 significantly and yet not attract additional supply that could eventually 

moderate price. 

Capacity payments are one way to ensure that investors recover fixed costs. Such payments can 

provide a regular payment stream that, when added to power market income, can make a project 

more economically viable. Like any regulatory construct, however, capacity payments have 

limitations. It is difficult to determine the appropriate level of capacity payments to spur entry 

without over-taxing market participants and consumers. In addition, because capacity payments 

include a reserve margin added on to demand, capacity markets may be more susceptible to 

market power than energy markets. These markets 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 rules change, there is a perception of risk about capacity payments 

that may limit their effectiveness in promoting investment and ultimately new generation. When 

rules change, builders and investors may take advantage of short-term capacity payment spikes 

in a manner that is inefficient from a longer-term perspective. 

If capacity payments are provided for generation, they may prompt generation entry when 

transmission or demand response would be more affordable and equally effective. Capacity 

payments also may reward traditional utilities and their affiliates disproportionately by providing 

significant revenues for units that are fully depreciated. 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 appropriate rules – e.g., NYISO’s rules giving capacity 

payment preference to newly-entered units. In general, however, it is difficult to tell whether 

capacity payments alone would spur economically efficient entry. 

One issue is whether capacity prices should be locational, similar to locational electric power 

prices. PJM, ISO-NE and NYISO have either proposed or implemented locational capacity 

markets that may increase incentives for building 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 build generation in load pockets.197

 

195 Sometimes, in fact, entry may not be justified, even in the face of high prices. Potential entrants must consider the benefits as well as the costs 

of entry. Some areas may be so costly to enter, that it is more efficient for society as a whole to pay the higher prices rather than pay the high 

investment costs to build lower cost generation, institute price-responsive demand programs, or invest in transmission access to lower-cost 

generation. 

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

197 In the areas that need capacity the most – densely populated areas significantly bounded by topographical barriers such as oceans – land prices, 

environmental restrictions, aesthetic considerations, and other factors may make new generation more (or even prohibitively) expensive. In fact, 

there are some environmental restrictions that serve as de facto bars to new generation entry. 

71 
c. Encouraging Additional Transmission Investment 

Building the right transmission facilities may encourage entry of new generation or more 

efficient use of existing generation located near, but outside, load pockets. But transmission 

expansion to serve increased or new load raises the difficulty of creating a rate structure that ties 

the economic and reliability benefits of transmission to particular consumers. Because 

transmission investments can benefit multiple market participants, it is difficult to assess who 

should pay for the upgrade, particularly when some market participants do not require the 

transmission to meet their needs. This regulatory challenge may cause uncertainty about the 

price for transmission and about return on investment 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. However, few merchant lines have been built. 

Uncertainties about revenue have made financing difficult. In addition, difficulties in obtaining 

needed rights-of-way and environmental approvals have chilled potential merchant projects.198 

Provisions of EPAct 2005 that allow for federal permitting of transmission projects under certain 

circumstances appear to have encouraged interest in new transmission projects, including 

merchant projects.199

Building or expanding transmission capacity, where possible, may remove the congestion that 

contributes to higher electricity prices in load pockets and other transmission-constrained areas. 

However, the potential for building new transmission may reduce the incentive to build new 

generation in the load pockets or develop demand response and thus may sustain the high prices 

there. Once new transmission capacity is built, it will increase supply options and decrease or 

dampen prices just as newly built generation or demand response would. Building or expanding 

transmission may increase supply more cost effectively than building new generation in load 

pockets and other constrained areas. 

Both generation and merchant transmission builders must deal with an existing transmission 

owner or an RTO/ISO to obtain permission to interconnect their facilities. Moreover, there are 

substantial difficulties in siting new transmission lines. It is difficult to assess whether these 

risks are higher for transmission builders than for generation builders or demand response 

programs. 

d. Governmental Control of Generation Planning and Entry 

The final alternative is a regulatory, rather than market, mechanism to assure that adequate 

generation is available to 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 could 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 at http://www.pjm.com/planning/reg-transexp-plan.html.

199 See supra note 180. AEP and Allegheny are both requesting that their proposed transmission projects be designated as a National Interest 

Electric Transmission Corridor under EPAct 2005. 

72 
benefits customers. Regulatory oversight of investment also means regulators can bar entry for 

reasons other than efficiency. The stable rate of return on invested capital under rate regulation 

can encourage investment. On the other hand, rate regulation can lead to overinvestment, 

excessive spending and unnecessarily high costs. Regulation also does not provide the same 

market discipline that effective competition provides. Under regulation, ratepayers may bear the 

risk of mistakes resulting from where and how investments are made. In competitive markets, 

the penalties for such mistakes fall on management and shareholders. Future accountability for 

investment decisions can lead to better decision-making at the outset.200

Some commenters strongly supported Integrated Resource Planning 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 prices, it is difficult to determine in advance the 

appropriate mix of fuels given the difficulty of projecting fuel prices. Regulators and planners 

too can make flawed resource decisions and have done so in the past. 

3. Market Oversight of Wholesale Energy Markets 

Under current law, market oversight to prevent anticompetitive behavior is an important feature 

of organized wholesale electricity markets. There is consensus about the need for market 

oversight and rules to ensure that wholesale electricity markets function efficiently and provide 

benefits to consumers. FERC’s Office of Enforcement and state regulators perform this service 

by reviewing wholesale electricity markets and the reports of internal and independent market 

monitors.202 Organized markets also are subject to ongoing scrutiny by state regulators and the 

independent market monitoring arms of RTOs.203 In sum, market oversight continues to be a 

vital element of organized wholesale markets, and efforts are ongoing to strengthen the oversight 

process. 

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

The Task Force examined comments on how competition policy choices have affected 

investment decisions of buyers and sellers in wholesale markets. A number of issues emerged. 

One was the difficulty of raising capital to build facilities whose revenue streams are affected by 

changing fuel prices, demand fluctuations, and the potential for regulatory intervention. A 

related theme was the investment dampening effects of a perceived lack of long-term contracting 

options. Some commenters asserted that significant problems still exist in organized markets, 

including steep price increases in some locations without the moderating effect of long-term 

 

200 Regulatory solutions, more so than market-based outcomes, may outlive the circumstances 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 anticompetitive conduct in electricity markets. 

203 NYPSC comments. 

73 
contracting 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 critical prerequisite in obtaining financing for new 

generators.206 Both generators and consumers said they were unable to arrange long term 

contracts. 

1. Unavailability of Long-Term Supply Contracts - Wholesale Buyer Perspective

Many wholesale buyers said they had sought to enter into long-term contracts but found few or 

no offers.207 The Task Force attempted to determine whether the available data supported these 

allegations by examining 2004-2005 data collected by FERC through its Electric Quarterly 

Reports for three regions – New York, the Midwest, 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 observed to be associated 

with lower contract prices on a per MWh basis. 

Three reasons may explain why buyers perceive they cannot enter long-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 contracts 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 relatively high profits when gas-fueled generators 

are the marginal units, particularly when natural gas prices rise. Natural gas-fueled generators in 

a uniform price auction may see lower profits as their fuel costs rise, to the extent other 

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 competitive model, entry will occur if long-term prices 

exceed long-term costs. In fact, recent proposals for new generation show a significant number 

of proposals to build base-load 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 have the ability to build their own generation facility if they are unable to obtain the 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-pending or has 

had a feasibility study performed, 110,964 MW, about two-thirds, is nuclear, combined cycle, coal-fired steam or integrated coal gasification 

technology (generation types typically considered base-load or mid-merit). 

74 
terms offered by incumbent suppliers. Indeed, in some regions, public power and cooperative 

utilities have announced plans to participate in new base-load generating plants. Because of the 

long lead times and considerable uncertainties involved, 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 competitiveness of these markets cannot be assumed. For 

example, over 10 years ago, FERC requested comments on a wholesale “PoolCo” proposal, the 

predecessor to today’s organized electricity 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 number 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 sufficient 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 commenters specifically cited 

recent studies that argue that electricity 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 long-term commitments. Long-term 

contracts in other commodities are 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-term contract. In a market with liquid forward or 

futures contracts, parties to a long-term contract can buy or sell products of various types and 

durations to limit their price risk. Currently, liquid electricity forward or futures markets often 

do not extend beyond two to three years.215 In some markets, one-year contracts are the longest 

available. In markets where retail load is served by contracts of fixed durations, such as the 

three-year obligations in New Jersey and Maryland, 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/comments/ferc/v040021.pdf. 

214 APPA comments; Carnegie Mellon comments. 

215 Nodir Adilov, Forward Markets, Market Power, and Capacity Investment (2005) (Cornell Univ. Dep’t of Econ. Job Mkt. Papers), available at

http://www.arts.cornell.edu/econ/na47/JMP.pdf.

75 
signing long-term contracts, because they lack the ability to "hedge" these longer-term 

obligations. 

Finally, the availability of long-term purchase contracts 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. Wholesale customers have argued that the inability to 

secure firm transmission rights for multiple years at a known price, particularly in organized 

markets, introduces unacceptable uncertainty in resource planning, investment, and 

contracting.216 They say this financial uncertainty has hurt their ability to obtain financing for 

new generation projects, especially new base-load generation. 

Congress addressed the issue of insufficient long-term contracting in the context of RTOs and 

ISOs in EPAct 2005. In particular, section 1233 of EPAct 2005 provides that: 

[FERC] shall exercise the authority of the Commission under this 

Act in a manner that facilitates 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 entities to secure firm 

transmission rights (or equivalent tradable or financial rights) on a 

long-term basis for long-term power 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 offer 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 these rights, such as the length of terms and the 

allocation of those rights to transmission customers. 

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

Commenters cited long-term contracts as a critical prerequisite in obtaining financing for new 

generators.218 Comments from generation investors suggested that their ability to arrange longterm contracts is inhibited by several uncertainties. Most of these uncertainties arise from the 

unpredictability of state and federal regulation. Finally, the nascence of market structures for the 

sale of electricity can make it difficult for market participants to have settled 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 the fact that most wholesale contracts are subject 

to regulation by FERC, and a party 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. 

76 
if the specific contract has been approved previously.219 For example, in 2001-2002, several 

wholesale power purchasers asked FERC to modify certain contracts entered into during the 

California energy crisis. They alleged that problems 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 price risk. In declining to change the contracts,220 FERC cited its 

obligation to respect contracts except when other action is necessary to protect the public 

interest.221

A second type of regulatory uncertainty involving bankruptcy may limit future market 

opportunities for merchant generators and thus reduce their ability to raise capital. In recent 

years, several merchant generators (NRG, Mirant and Calpine) have sought to use the 

bankruptcy process to break long-term power contracts.222 This bankruptcy risk may create an 

additional incentive to favor construction of generation by load-serving 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, these cases have centered on 

separate, but intertwined issues. First, there is a question of where jurisdiction over efforts to 

end power contracts properly lies, as between FERC and the bankruptcy courts, and to what 

extent courts may enjoin FERC from acting to enforce power contracts. Second, there is an issue 

of what standard applies to such efforts (what showing must a party make to rid itself of a 

contract). The law remains unsettled, as do parties’ expectations. 

A third type of regulatory uncertainty concerns regulated retail service in states with retail 

competition.224 The uncertainty over how much supply a distribution utility will need to serve 

its customers, who have the option to switch, can prevent or discourage utilities from signing 

long-term contracts.225 The extent of this disincentive is unclear if competitive options are 

available for distribution utilities to purchase needed supply or sell excess supply. 

A fourth type of uncertainty relates to a general concern about institutional instability. Some 

market participants argue that they cannot count on current rules and trading mechanisms 

 

219 In December 2005, FERC proposed to adopt a general rule on the standard of review that must be met to justify proposed modifications to 

contracts under the FPA, except transmission service agreements executed under an open access transmission tariff as provided for under Order 

No. 888, and under the Natural Gas Act, except agreements for the transportation of natural gas executed pursuant to the standard form of service 

agreement in pipeline tariffs. Standard of Review for Modifications to Filed Agreements, Notice of Proposed Rulemaking, 71 Fed. Reg. 303 

(January 4, 2006), FERC Stats. & Regs. ¶ 61,317 (2005) (Comm’r Kelly, dissenting). Specifically, FERC proposed that, in the absence of 

specified contractual language permitting the Commission to act on proposed modifications to an agreement on its own motion or on behalf of a 

signatory or non-signatory under the “just and reasonable” 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 explained that its proposal recognized the importance of providing 

certainty and stability in energy markets, and helped promote the sanctity of contracts. A final rule is pending. 

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

v. Sellers of Long Term Contracts, 103 FERC ¶ 61,354, order on reh’g, 105 FERC ¶ 61,182 (2003); PacifiCorp v. Reliant Energy Services, Inc., 

103 FERC ¶ 61,355, order on reh’g, 105 FERC ¶ 61,184 (2003). 

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

222 See Howard L. Siegel, The Bankruptcy Court vs. FERC- The Jurisdictional Battle, 144 PUB. UTILS. FORTNIGHTLY 34 (2006). 

223 Another factor creating a potential preference for self-built generation as opposed to long-term purchases is the treatment by some credit rating 

agencies of power purchase contracts as imputed debt. If a utility’s self-built generation is treated as an asset but long-term purchase contracts 

are treated as imputed debt, it may cause utilities and state regulators 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. 

77 
because market rules and institutions change so frequently. This can serve to deter new entry.226 

At the same time, many market participants continue to advocate changes in regulatory policy, 

even long-settled policy.

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

New generation construction in wholesale markets depends on the ability of a company to 

acquire capital, either from internal 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” showing to build a generation plant. 

In the United States, private capital has funded most electric generation investment. Under 

traditional cost-base rate regulation, utility investment decisions were based in part on the 

promise of a regulated revenue stream with little associated risk to the utility. Ratepayers often 

bore the risk, and money from capital markets was generally available when utilities needed to 

fund new infrastructure. One significant problem, however, was that regulators had limited 

ability to ensure that utilities spent their money wisely.227 Investors view regulatory 

disallowances of imprudent expenditures as regulatory risk. Some believe that Integrated 

Resource Planning processes with opportunities for public and regulator participation in advance 

of resource procurement decisions will reduce the risks of later regulatory disallowances.228

In competitive markets, project funding is based on anticipated market-based projections of 

costs, revenues, and relevant risks factors. The ability to obtain funding is impacted by the 

degree to which these projections compare with projected risks and 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-based rate-regulated investments, 

as merchant generators were able to finance numerous generation projects, 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 relative financial strength of many traditional 

utilities. It also may reflect a disproportionate impact of the collapse of credit and thus trading 

capability of nonutilities after 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 Investment in New Generating Capacity (April 28, 2006) (MIT Working Paper). 

227 CONG. BUDGET OFFICE, FINANCIAL CONDITION OF THE U.S. ELECTRIC UTILITY INDUSTRY (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/brochures/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. 

78 
Investor 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 predictable as in the past.233 Under costbased regulation, vertically integrated utilities’ monopoly service territories significantly limited 

the risk of not recovering the costs of investments. Once generators had to compete for sales, 

generation plant investors were no longer guaranteed that construction costs 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 particularly 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 construction and payout periods that would put capital 

at risk for a much longer time, 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 widely, but merchant revenues often limited by contract or by 

regulatory price mitigation, investors may worry that merchant generators may not recover their 

costs and provide an attractive rate of return. Commenters suggest that competitive suppliers are 

beginning to focus on developing facilities fueled by other 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 multiple coal-fired plants), Constellation Energy 

and Exelon Corp. (developing a nuclear plant), BP and Edison Mission Group (investing $1 

billion in a hydrogen-fueled plant), and AES (investing $1 billion in renewable technologies).239

4. Regulatory Intervention May Affect Investment Returns

Economic theory says that, in an unregulated world, needed generation investments will be made 

and generation investors will recover not only their 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 generation investment is allowing the 

highest cost generator being dispatched at a particular 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 expensive resources. Generators 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/FTPROOT/electricity/056296.pdf. 

236 Id. 

237 Hearing on Nuclear Power, Before the Subcomm. on Energy of the S. Comm. on Energy & Nat’l Res. (Mar. 4, 2004) (statement of Mr. James 

Asselstine, Managing Director, Lehman Brothers). See also Nuclear Energy Institute, Investment Stimulus for New Nuclear Power Plant 

Construction: Frequently Asked Questions, available at http://www.nei.org/documents/New_Plant_Investment_Stimulus.pdf. 

238 Natural Gas Factors Affecting Prices and Potential Impacts on Consumers: Testimony Before the Permanent Subcommittee on Investigations, 

Committee on Homeland Security and Governmental Affairs, United States Senate; GA-06-420T (Feb. 13, 2006), at 7. 

239 EPSA comments. 

79 
costs below the market clearing price receive “scarcity rents” that cover their fixed costs and 

provide a return on investment. If high prices in a particular energy market reflect scarcity, these 

economic rents generally are efficient and serve to provide incentives for construction. 

However, regulators may limit recovery of high prices during these periods due to the 

unpalatability of even temporarily high prices and/or suspicion of inappropriate market gaming. 

Thus regulators may deter suppliers from making needed investments in new capacity by 

imposing price caps and limiting recovery of legitimate costs and delivery of adequate returns. 

This dynamic leads to a chicken-and-egg conundrum: 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 price regulation during high-priced hours diminishes investors’ 

confidence that market forces (rather than regulation) will set prices. That diminished 

confidence in their ability to earn sufficient investment returns thus deters entry of new 

generation supply, thereby limiting competition and giving cause for price caps. 

Price mitigation through price or bid caps has become 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 encourage entry of new 

supply. See Box 3-3 for a discussion of capacity credits. In practice, however, the presence or 

absence of capacity credits has not always resulted in predicted outcomes. California did not 

have capacity credits and did not experience much new generation, but two regions (Southeast 

and Midwest) experienced significant new generation entry without capacity credits. Northeast 

RTOs with capacity credits continue 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 might 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 Southeast was nonutility merchant generation that 

relied on the region’s proximity to natural gas supplies. In the Midwest, in the late 1990s, 

largely uncapped prices were allowed to send price signals for investment. In California, price 

caps of various kinds have been used for a number of years, limiting price signals for new entry. 

In the Northeast, organized markets have offered 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 with acceptable levels of price volatility. 

80 
Net revenue analyses for centralized markets with price mitigation suggest that price levels are 

inadequate for new generation projects to recover their full costs. For example, in the last 

several years, net revenues in the PJM markets have been, for the most part, too low to cover the 

full costs of new generation in the region.240 Based on 2004 data, net revenues in New England, 

PJM and California would have allowed a new combined-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 filing 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 solutions (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. Graduated capacity payments that favor entry of efficient 

plants may be a partial solution to retiring inefficient old plants. 

 

5. Investment in Transmission: A Necessary Adjunct to Generation Entry

Transmission access can be vital to supporting competitive options for market participants. For 

example, merchant generators depend on the availability of transmission to sell power, and 

transmission constraints can limit their range of potential customers. Small utilities, such as 

many municipal and cooperative utilities, depend 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-integrated, investor-owned utilities. Some have 

alleged that these utilities have an incentive to limit grid use by others to the extent that such use 

conflicts with sales by their own generation. In short, the availability of 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 concerning the efficacy of various terms and 

conditions governing transmission availability. For example, customers have raised concerns 

regarding the calculation of Available Transfer Capacity (ATC). Another concern has been a 

lack of coordinated transmission 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 revenues have been sufficient to cover the costs of new peaking units, and in 2005 they were enough to 

cover the costs of a new coal plant. PJM Interconnection, LLC, Market Monitoring Unit, 2005 State of the Market Report, at 118 (2006), 

available at http://www.pjm.com/markets/market-monitor/som.html 

241 PJM Interconnection, 115 FERC at 61,236. 

81 
As discussed above, generation that is built where construction costs are low and fuel supplies 

readily available, but not necessarily near demand, relies heavily on readily available 

transmission. The Connecticut DPUC noted that, while generation growth may have been 

sufficient for some regions such as New England as a whole, some localized areas saw demand 

grow without increases in supply, raising prices in load pockets. If transmission access to the 

load pocket were available, a large base-load plant outside the load pocket might become an 

attractive investment. 

Less regulatory intervention in wholesale markets 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 additional capacity, capacity credits may not be required 

for base-load plants outside the load pocket. Those base-load plants would not have the problem 

of average revenues falling below average costs because they would have access to more load, 

and would be able to run profitably during more hours of the day. Similarly, price caps may be 

unnecessary if improved transmission brought power from more base-load 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 May 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 the technical capability (i.e., the ability to generate MWs within 

a very short period of time in a critical location) to prevent network collapse. An administrative 

process may be needed to provide the correct level of generation technically 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 Response Can Affect the Need for Generation and

Transmission Investment

Chapter 2 described the typical disconnect between wholesale and retail prices in electric 

markets. This disconnect can lead to wider price fluctuations than would be the case if 

customers could easily reduce their demand when prices rise. There are several means to 

influence the level of demand for power, including 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 “nonrivalry.” Nonexclusiveness means that others cannot be excluded from 

the use of the good (e.g., if one person refuses to pay taxes, that person still can enjoy public parks) and nonrivalry implies that one person’s 

consumption of the good does not diminish another person’s consumption (e.g., the fact that one person enjoys the increased safety engendered 

by military spending doesn’t decrease another person’s safety.) “Preventing network collapse” is nonexclusive because if the network 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.

82 
building codes. Tools for eliciting demand response 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, air-conditioner cycling, and independent system operator emergency demand 

response programs. 

By influencing demand, energy efficiency and demand response programs can affect pricing in 

the short term and in the long term by affecting the amount of generation and transmission 

needed as well as the composition (i.e., composition of base load, mid-merit and peaking 

generation) of investment. For instance, programs that aim to reduce electricity consumption 

that is fairly constant – such as refrigerator efficiency programs – reduce the need for base-load 

plants. Similarly, programs that improve the efficiency of appliances that contribute to peaking 

load (i.e., air conditioners) can reduce demand for mid-merit generation. Demand response 

programs that curtail demand at peak times may resolve 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 scarcity rents or market power. DSM also holds the 

potential to defer the need for new transmission 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). 

83 
CHAPTER 4 

COMPETITION IN RETAIL ELECTRIC POWER MARKETS 

A. Introduction and Overview 

This chapter examines the development of competition in retail electricity markets and discusses 

the status of competition in the 16 states and District of Columbia that currently allow customers 

to choose their electricity supplier.245 

 

Although it has been almost a decade since states started implementing retail competition, 

residential customers in most of these states still have little choice among suppliers. In most of 

these states, few residential customers have a wide variety of alternative suppliers and pricing 

options. Commercial and industrial (C&I) customers have more choices and options, but in 

several states large industrial customers have become increasingly dissatisfied with retail prices. 

The lack of incentives for alternative suppliers and marketers to enter the market at the retail 

level has been a major impediment to market-based competition. Most states required the 

distribution utility to offer electricity at a regulated price as a backstop or default if the customer 

did not choose an alternative 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 the regulated service at a discount below then-existing rates and 

capped the price for multi-year periods. In some states, these initial discounts sought to 

approximate anticipated benefits of competition for residential customers. Since then, wholesale 

prices have increased. More than any other policy, this requirement that distribution utilities 

offer service at low prices unwittingly impeded entry by alternative suppliers to serve retail 

customers. New entrants cannot compete against a below-market regulated price. 

States with prices regulated at below-market levels now face “rate shock.” On the one hand, rate 

caps for the regulated service most residential customers 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 limited ability to adjust consumption in response to 

price increases and also lack competitive supply options (other than possibly to install their own 

onsite generation). On the other hand, if states continue to require distribution utilities to offer 

 

245 The Task Force adopts the convention of designating states as permitting retail competition on the basis of whether a state allows alternative 

suppliers to enter and obtain multiple, geographically dispersed customers. An even broader potential definition of retail competition would take 

into account policies that allow individual retail customers to provide some or all of their own generation needs (i.e., to make rather than buy 

electricity). Onsite generation is common in some industries in some sections of the country. Small onsite generation projects – often referred to 

as “Distributed Generation” or “Distributed Resources” projects – are gaining popularity as well. Many states that do not have retail choice in the 

conventional sense do have provisions for various forms of onsite generation and net metering. Another broader form of retail competition 

involves municipal utilities or cooperatives. NRECA comments (2). These entities can be carved out of existing private utility distribution areas, 

or can be added back into them if the municipality decides 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 competition. 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 programs as POLR 

service. A broad range of terms is used in different states to denote this type of service. Some states have more than one form of mandated 

service or have changed the form of POLR service over time. In many states, POLR service originated as an element in arrangements to pay the 

stranded (i.e., non-recovered) costs of vertically integrated utilities – costs that may have become unrecoverable when the state adopted a retail 

customer choice approach. 

84 
regulated service at below-market rates, then retail entry – and thus competition – will not occur. 

Moreover, below-market rates put the distribution utility’s solvency at risk and do not provide 

appropriate incentives for conservation.247

This conundrum is further complicated by the fact that most distribution utilities offering 

regulated service no longer own generation assets. Most of the supply contracts that were part of 

the agreements under which they divested generating assets were set to expire 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 former generation assets may be more expensive 

now than when they were divested. If the utility repurchases these assets at current prices, it is 

likely to have “sold low and bought high.” 

The competitiveness of wholesale prices directly affects retail prices,249 except where retail 

prices are set by regulation without regard to current wholesale prices. For example, retail prices 

usually will reflect imperfections in the wholesale 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 for reasons other than addressing market failures, 

transmission discrimination that prevents low-cost suppliers from reaching customers, or 

restrictions that delay or prevent entry and diffusion of low-cost generation technologies. 

Distortions in wholesale prices that lead to distortions in retail prices can cause economic 

inefficiencies both in retail customers’ consumption patterns and in investment decisions. 

Ultimately these distortions can reduce consumer welfare and raise private and social costs of 

producing goods made with electricity as an input. 

This chapter addresses the status and impact of retail competition in seven states that the Task 

Force examined in detail: Illinois, Maryland, 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 difficult to determine whether retail prices 

 

247 Debt rating agencies may downgrade the creditworthiness of utilities in states that require utilities to sell at prices below their costs. For 

example, Moody’s Investors Services reportedly has downgraded the creditworthiness of utilities in Maryland – in particular, Baltimore Gas & 

Electric, due to that firm’s inability to pass on increased input costs to consumers, which “leaves BGE in a weakened state that makes it 

vulnerable to further downgrades and even insolvency if it faces further energy price shocks or other costs that the legislature deems cannot be 

passed on to customers.” Patricia Hill, Maryland Utilities Designated Near Junk, WASH. TIMES (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 (vesting 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 them 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 defined in the legislation. 

There are two exceptions worth noting. In California, vesting agreements were de-emphasized in favor of procurement at spot market prices. In 

upstate New York, vesting agreements were longer term and continue to have a moderating effect on average procurement prices for POLR 

service. Public Utility Law Project of New York comments (2) at 36. 

249 Several commenters emphasized the potential spillovers from problems at the wholesale level to the retail level, including NYPSC comments 

(2) at 3-4; APPA comments (2) at 4, 21-25; New York Companies comments (2) at 2, 4-5; Direct Energy comments (2) at 7; Alliance for Retail 

Energy Markets comments (2) at 3-4; Industrial Consumers comments (2) at 9-10, 21-22; Allegheny comments (2) at 15, 19. 

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

251 See Appendix D infra for each state profile. 

252 Restructured states as of May 2006 include Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, 

New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia, plus the District 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 that prices for 

85 
are 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 can minimize market distortions once rate caps 

expire. 

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

Competition 

For most of the 20th century, local distribution utilities typically offered electric service at rates 

that varied among customer classes (e.g., residential, commercial, and industrial). State 

regulatory bodies set these rates based on the utility’s costs. Locally elected boards oversaw the 

rates for customers of public power and cooperative utilities. For investor-owned systems, the 

regulated rate included an opportunity to earn an authorized rate of return on investments in 

utility plants needed to serve customers. Public 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 electricity to retail customers.253 

Industrial customers sometimes can choose from more options than can small business and 

residential customers for service and rate structures (e.g., “time-of-use” rates, which are lower 

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 the disparity was due to 

different natural resource endowments across regions, the most important of which are the 

hydroelectric resources in the Northwest and the abundant coal reserves in such states as 

Kentucky and Wyoming. Moreover, some states required utilities to enter into PURPA contracts 

at prices much higher than the utilities’ 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 regularly to reflect changes in wholesale prices. Delaware, the District of Columbia, 

Illinois, Michigan, New Hampshire, Ohio, and Rhode Island share the situation faced by Maryland, where the transition period of fixed prices for 

residential and small C&I POLR service will end in the near future. Massachusetts’s rate cap period ended recently. Many of the states poised to 

end the transition period are developing approaches to bring POLR prices for residential and small C&I customers up to market rates in stages 

rather than all at once. Several of these states also share Maryland’s and New Jersey’s interest in auctions for procuring POLR service supplies. 

Oregon’s situation differs from the other states in that only nonresidential customers can shop, and that shopping is limited to a short window of 

time each year. 

253 Retail electric customers in 30 states continue to receive service almost exclusively under a traditional regulated monopoly utility service 

franchise. These states include 44 percent of all U.S. retail customers, accounting for 49 percent of electricity demand. 

254 For example, Georgia law allows any new customers with loads of 900 kilowatts or more to make a one-time selection from among

competing eligible electric suppliers. Southern comments. 

86 
Figure 4-1. U.S. Electric Power Industry, Average Retail Price of Electricity 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

9 and above 8 - <9 7 - <8 6 - <7 0 - <6

U.S.

Average

6.9

SC

5.7

CT

NJ 10.5

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 their 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 service at lower prices if they could choose among suppliers. For 

example, they could buy from suppliers outside their local market, from new entrants into 

generation, or from power marketers, any of which might charge lower prices than the local 

distribution utility. The ability to choose among alternative suppliers was intended to reduce 

market power that local suppliers might otherwise have, so that customers might see lower prices 

from local suppliers. Also, it was thought that new suppliers might offer innovative price and 

other terms to purchase electricity that could improve the quality of service. 

In 1996, California enacted a comprehensive electric restructuring plan to allow customers to 

choose their electricity supplier. To accommodate retail choice, California extensively 

restructured its electric power 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 distribution 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 market for electricity supply, so that utilities 

and alternative suppliers could purchase electricity to serve their 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 costs 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), Pennsylvania (December 1996), Montana (April 1997), 

Oklahoma (May 1997), and Maine (May 1997). By January 2001, 22 states and the District of 

Columbia had adopted retail competition legislation. 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 generation, such as Alabama, Colorado, 

North Carolina, and Wisconsin – concluded that retail competition would not benefit their 

customers.257 For example, Colorado was concerned that limitations on transmission access and 

high concentration among generation suppliers would lead suppliers to exercise market power to 

the detriment of customers. These states opted to keep traditional utility service. 

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

 lower electricity prices than under traditional 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 displacement of dirtier, more expensive 

generating plants with cleaner, cheaper natural-gas-fired and renewable generation. 

Under the restructured model, legislatures and regulators affirmed their support for making 

electricity available to all customers at reasonable rates, with continued safe and reliable service 

and consumer protections under regulatory oversight. Boxes 4-1 and 4-2 describe the 

Pennsylvania and New Jersey legislatures’ findings 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 transmission 

projects. PSC Wisconsin Comments (2) at 3. 

88 
Box 4-1 

Findings of the Pennsylvania Legislature 

The findings of the Pennsylvania General Assembly demonstrate these varied goals: 

(1) Over the past 20 years, the federal government and state government have introduced 

competition in several industries that previously had been regulated as natural monopolies. 

(2) Many state governments are implementing or studying policies that would create a 

competitive market for the generation of electricity. 

(3) Because of advances in electric generation technology and federal initiatives to 

encourage greater competition in the wholesale 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 available at levels of 

reliability that are currently enjoyed by the citizens and businesses of this Commonwealth. 

(4) Rates for electricity in this commonwealth are on average higher than the national 

average, and significant differences exist among the rates of Pennsylvania electric utilities. 

(5) Competitive market forces are more effective 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 public utility services do not subsidize the 

provision of competitive services by public utilities; . . .” 

(5) Maintain traditional regulatory authority over non-competitive energy delivery or other 

energy services, subject to alternative forms of traditional regulation authorized by the 

Legislature; 

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

(2) Place greater reliance on competitive markets, 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 declares that it is the policy of this State to: 

89 
C. Meltdown and Retrenchment 

From late spring 2000 and into the spring of 2001, California experienced high natural gas 

prices, a strained transmission system, and generation shortages (due to hydro shortages and 

operating restrictions) that resulted in blackouts. Wholesale electricity prices soared during this 

time. Existing state law had capped residential “provider of last resort” (POLR) service rates at 

levels that were soon below the market price 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 electricity 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 market environment. Although that suspension 

continues today, 12 percent of load 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 California’s role in purchasing 

electricity and the all-time-high prices it paid, and continues to pay. 

Box 4-3 

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

In 2001, California spent over $10.7 billion to purchase electricity on the spot market to 

supply customer’s daily needs. The state also signed long-term contracts worth 

approximately $43 billion for10 years. These contracts represented about one-third of the 

three utilities’ requirements for the same period (2001–2011). Viewed with the benefit of 

perfect hindsight, the state entered these long-term contracts when prices were at an alltime high. Future prices hovered in the 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 contract. By August 2001, future prices had 

dropped below $100. Thus, as of May 2006, the state is obligated to pay well over market 

prices for at least five more years. See Southern California Edison. 

The California experience sent ripple effects throughout the Western region and prompted 

several states to defer or abandon efforts to implement retail competition. No new states have 

adopted retail competition since 2000, and some states – including Arkansas and New Mexico – 

repealed retail competition plans they previously had adopted. 

Other populous states, such as Illinois, New Jersey, 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 Markets, California Market Design Enabled Exercise of Market Power (June 2002), 

available at http://www.gao.gov/new.items/d02828.pdf. 

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

90 
service rate caps and will soon purchase wholesale supplies for POLR service at market prices 

(although several of these states are developing approaches to slow 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 restructured 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, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia, as well 

as the District of Columbia. 

Figure 4-2. United States Map Depicting 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/electricity/chg_str/restructure.pdf

D. Experience with Retail Competition 

With the expected benefits of retail competition in mind, the Task Force examined seven states 

in depth. These “profiled states” – Illinois, Maryland, Massachusetts, New Jersey, New York, 

Pennsylvania, and Texas – represent the different 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 

91 
fact that several states still have capped residential POLR rates. C&I customers generally have 

more choices in both suppliers and of customized 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 suppliers 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 competition 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 learned from the use of POLR that may assist states as they decide 

how to structure future POLR service are included. 

1. States Have Allowed Distant Suppliers to Access Local Customers and 

Have Encouraged Distribution Utilities to Divest Generation

Each profiled state adopted measures to encourage entry of new suppliers to compete with the 

incumbent utility. Each adopted policies to allow suppliers other than the local distribution 

utility to gain access to retail customers 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 and 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 exercise market power. 

Some states, including Massachusetts, New Jersey, and New York, ordered or encouraged 

utilities to divest generation assets to independent power producers (IPP) to eliminate possible 

transmission discrimination or to secure accurate stranded cost valuations.263 Although these 

divestitures generally did not require a utility to sell its generation assets to more than one 

company to eliminate the potential for the exercise 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-Users 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 information about the retail choice process and belowmarket pricing of POLR service) are discouraging entry and active consumer shopping for electricity service. Another way to gauge the success 

of retail competition policy is to survey consumers about their awareness of retail choices and perceptions of the difficulty of switching between 

suppliers. However, surveys are expensive and results are not available systematically. More generally, consumers can obtain the benefits of 

competition if existing competition, entry, or the threat of entry prevents incumbent suppliers from exercising market power manifested 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 suppliers. NASUCA comments (2). 

262 There is no reason to believe, however, that retail competition in this market will not function as competition does in any market, by reducing 

quality-adjusted prices. 

263 See infra Massachusetts, New Jersey, and New York profiles, Appendix D. See also Federal Trade Commission, Staff Report on Competition 

and Consumer Protection Perspectives on Electric Power Regulation Reform: Focus on Retail Competition, at 43 (2001), available at

http://www.ftc.gov/reports/elec/electricityreport.pdf [hereinafter FTC Retail Competition Report]. 

264 The prices of generation assets have been volatile since these divestitures occurred. Asset prices often are keyed not only to the cost of the 

fuel necessary to generate the electricity, but also to the location of the asset on the transmission grid. 

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

affiliates.265

As a result of these divestitures, regulated distribution utilities in profiled states operate fewer 

generation plants than in the past. Distribution utilities that are required to serve customers must 

purchase generation in the wholesale market to serve their customers. Table 4-1 shows the 

amount of a state’s generation operated 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 Ownership 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 states with divestiture policies because it includes the 

hydroelectric and nuclear facilities of the Power Authority of the State of New York (even though that body is not a retail distribution utility). 

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

Other states, such as Texas, limited the market share any one generation supplier can hold in a 

region, to provide opportunities for other suppliers to enter.266 Still others, such as New York, 

helped organize introductory temporary discounts from alternative 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 and large commercial customers in the profiled 

states. For example, in Massachusetts, over 20 direct suppliers provide service to C&I 

customers, along with over 50 licensed electricity brokers or marketers.268 However, only four 

active suppliers serve residential 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. 

93 
choose among nearly 20 suppliers, but residential customers only have a choice of one or two 

competitive suppliers.270

Texas and New York have more options for residential 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 program described in Box 4-4, few if any suppliers 

have provided continuous service to residential customers in the other profiled states or in other 

retail competition states prior to the end 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 retail supplier. In Ohio, 

however, most switching activity has occurred through aggregations of customers seeking a 

supplier under the statewide “Community Choice” aggregation option. The Ohio retail 

competition law provides for municipal referendums to seek an alternative supplier and 

allows municipalities to work together to find an alternative supplier. The largest 

aggregation pool, the Northeast Ohio Public Energy Council, has 100 member communities 

and served approximately 500,000 residents at its peak. The Ohio program allows 

individual customers to opt out of the aggregation. In most other states, aggregation 

programs require customers to specifically opt in to participate. Participation rates generally 

are much higher in opt-out than in opt-in programs. (NOPEC recently had to contract for 

supply with an affiliate of the distribution utility 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 available generation suppliers. For 

example, in Massachusetts, 8.5 percent of residential customers had migrated to a competitive 

supplier as of December 2005.273 Approximately 41 percent of large C&I customers switched to 

alternative suppliers, representing 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/home/supplierlist.shtml. 

For example, in the Connectiv territory, there are 18 C&I suppliers and only one residential supplier. Eighteen suppliers serve C&I customers 

and one serves residential customers in the PSE&G service territory. 

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

http://www.powertochoose.org/default.asp. 

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

http://www3.dps.state.ny.us/e/esco6.nsf/. The NYPSC reports that this range has moved to between 6 and 16 alternative suppliers, and the 

agency expects the number and variety of services offered by alternative 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 Utility Law Project of 

New York comments (2) at 41-42. 

273 A substantial number of these switches are the result of community aggregations (principally the Cape Light Compact) rather than individual 

residential switches. Cape Light Compact comments (2) at 1-2. 

274 See infra Massachusetts profile, Appendix D. 

94 
suppliers serving residential customers, higher percentages of residential 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 per 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, while those in Texas, Pennsylvania, Maryland, and 

Illinois have been lower. In 2004 and 2005, retail prices in all states began to increase. 

Figure 4-3. Average Revenues 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

14.00

1990199119921993199419951996199719981999200020012002200320042005

Cents per kWh

US

Texas

New York

Pennsylvania

New Jersey

Massachusetts

Illinois

Maryland

Source: EIA Form 861 data, and Monthly Electricity Report for average electric revenues per kWh all sectors, all retail providers. 

a. Residential and Commercial Customers

It is difficult to draw conclusions about how competition has affected retail prices for residential 

customers in states in which a substantial share of such customers continues to take service under 

capped POLR rates (e.g., Maryland, Illinois, Pennsylvania, and Texas). Comparisons of 

regulated prices shed little light on price patterns resulting from retail competition. 

POLR prices have increased recently in states in which residential rate caps have expired. In 

New Jersey, residential rate caps on POLR service expired in the summer of 2003. Since then, 

 

275 See infra Texas profile, Appendix D. There likely is a “chicken-or-egg” problem about whether more switching over time is attributable to a 

prior increase in suppliers or vice-versa (or whether both effects interact). 

95 
the state has conducted an internet auction to procure POLR supply of various contract lengths 

(one- and three-year contracts). The state holds annual auctions 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 charges, but increased in 2005 and 

2006, with rates increasing approximately 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 Boston Edison (north) territory 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 states have revised their POLR policies for large 

customers. Their POLR price for generation is a pass-through of the hourly wholesale price for 

electricity plus a fixed administrative fee. For example, Maryland, New Jersey, and New York 

have adopted this type of POLR pricing for large industrial customers.278 Many customers have 

switched to alternative suppliers in these states. 

Large industrial customers described how their rates have increased since the beginning of retail 

competition.279 Some commenters suggested that the Task Force should compare prices of a 

utility operating in a state that did not implement 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 increased them. As a result, a price comparison 

between two states for a class of customers would 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 they were in the same physical location would be 

misleading. The timing of rate adjustments may differ between states, so that a single snapshot 

of rates would show a lower price in one state at one point in time, but a lower price in the other 

state at a different point in time – even if the net present values of typical bills in the two states 

were identical over a long observation period. Finally, some states may defer recovery of costs, 

whereas other states choose not to. Thus, without 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 who purchase 

this service are unaware of the price until they consume the power or until they are billed. Galen Barbose, Charles Goldman, and Bernie Neenan, 

The Role of Demand Response in Default Service Pricing, 19:3 ELEC. J. 64 (Apr. 2006) [hereinafter Barbose et al.]. 

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

280 Portland Cement comments; Lehigh Cement comments. 

96 
simple price comparison between two states may 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 Price 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. Residential POLR service rate caps have not increased 

customer exposure to time-based rates.282 In contrast, real-time pricing is the POLR service 

available to the largest customers in New Jersey, Maryland, and New York.283 The shift to realtime pricing has been eased by technical advances in metering that have increased the 

sophistication (and decreased the prices) of meters that record the volume of consumption in 

each small block of time.284

Commenters argue that POLR rate structure can significantly affect customer response to price, 

especially among larger customers. A broad spectrum of utilities, state 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 largest customers in National Grid 

USA’s New York area suggests that customers using real-time pricing 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 responsible for POLR service.287 When distribution utilities are required to 

maintain a portfolio of resources to meet POLR loads, they may no longer value these types of 

programs as a resource to ensure reliable and efficient grid operation. Shifting the responsibility 

of grid operation and reliability to regional organizations such as ISOs/RTOs further decreases 

distribution utilities’ interest 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. Public Utility Law Project of New York comments (2) at 35-36. 

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

POLR service, see Barbose et al.; Hopper, et al. The authors report that although most customers switch away from POLR service when it is an 

hourly price, they often select offers from alternative suppliers that contain elements of hourly pricing. Further, they report that the proportion of 

customers accepting hourly price aspects in their supply contracts – over 90 percent – is far higher when the price is set on the day-ahead spot 

market. The authors believe that the higher participation rates in hourly pricing under this circumstance are due to the early warning that 

customers get in the day-ahead market and the customers’ consequently greater ability to respond to these pricing signals. 

284 Direct Energy comments (2) at 7; Mercatus Center comments at 2; CP Consulting comments at 2. Results from trial programs using 

advanced meters for residential customers indicate that residential demand for air conditioning is more price sensitive than other uses, particularly 

if the response is automated. Robert Earle and Ahmad Faruqui, Toward a New Paradigm for Valuing Demand Response, 19:4 ELEC. 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 supporting its air-conditioner direct load control program when it divested its generation assets. 

97 
5. Retail Competition in Rural America

Many rural areas are served by small non-profit electric 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 and small loads predominating. Although electric 

distribution cooperative service areas have been opened to competition under some state plans, 

no state has required municipal and/or public power utilities to implement retail competition. 

Eight states with retail competition – Arizona, Delaware, Maine, Maryland, Michigan, New 

Hampshire, Pennsylvania, and Virginia – required cooperatives to implement retail competition 

in their service territories. With the exception of Pennsylvania, state public utility commissions 

regulated electric cooperatives’ retail rates and approved their competition plans. Pennsylvania 

left the design and implementation of retail competition to the individual distribution 

cooperatives. The Pennsylvania Public Utility Commission is responsible for licensing 

competitive retail providers in cooperative service territories. Cooperative retail competition 

plans have been fully implemented in Delaware, 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 vote of their boards or membership. None of 

these states regulates cooperatives’ rates or services. They leave the design and implementation 

of retail competition to the individual cooperative. The state licenses competitive providers, but 

providers must enter into agreements with the cooperative to begin enrolling retail customers. A 

handful of individual cooperatives in Montana and Texas elected to provide retail competition 

options for their members. 

It is difficult to track the progress of retail competition in rural areas because most states do not 

make switching data available or maintain up-to-date information on active suppliers in 

cooperative service territories. 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, Pennsylvania, 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 cooperatives is not yet available. 

E. POLR Service Price Significantly Affects Entry of New Suppliers 

Each profiled state required local 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 regulated POLR service is usually “fixed” for an 

extended period – that is, it does not vary with increases or decreases in wholesale prices. 

98 
Generation accounts for the most significant portion of the POLR service price. This component 

constitutes the amount that the customer avoids paying to the distribution utility by choosing 

(and paying) an alternative provider. Many states denote this as the “price to beat” or the 

“shopping credit.” 

Commenters say that the price of POLR service is the most significant 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 unregulated 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 features of POLR service, can affect the competitive dynamics 

between different suppliers. 

1. Contrasting Visions of POLR Service

The comments revealed two visions of how POLR service should function in the long term.290 

In the first vision, POLR is a long-term option for customers. Under this view, POLR service 

closely approximates traditional 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 POLR service competes head-to-head with private, for-profit 

retail suppliers.291 (An analogy would be the U.S. Postal Service providing parcel postage 

service in competition with for-profit package delivery 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 service 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 identified other factors that depress or delay entry into 

retail markets. For example, the Pennsylvania Consumer Advocate identified several factors that depressed retail entry by suppliers to serve 

residential customers, including “the acquisition costs associated with marketing programs 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 Advocate comments at 

3. The Maine Office of Public Advocate echoed these factors and also identified the “miscalculation by some suppliers as to the risks and 

rewards for retail electricity competition.” Maine Public Advocate comments at 3. The Industrial Consumers observed that retail markets are not 

fully competitive because of insufficient generation divestitures that left suppliers with market power. ELCON comments at 2. Another factor 

identified by Industrial Consumers is the inability of alternative suppliers to gain access to necessary 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 argued that alternative suppliers need access to customer use data from utilities to 

be able to market to prospective customers. Constellation comments at 43. Still others argued for no minimum stay requirements at POLR and 

constrained shopping windows, which can dampen entry. RESA comments at 30-31; Strategic comments at 10; Wal-Mart comments at 13. The 

lack of entry in most states makes it difficult for the Task Force to evaluate which additional factors are the most important.

289 There is one potential exception: a supplier that offers a substantially 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 service be provided or procured by the incumbent distribution utility, the task of 

providing or procuring POLR service could be carried out by other entities. New York 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 procure POLR service may be exposed to the risk that this responsibility will be 

unprofitable because costs and demand are volatile or because state utility regulators impose costs on the provider of POLR service (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. 

99 
In 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 offerings designed to attract different types of customers. This type 

of POLR service acts as a stopgap source of supply that ensures electric 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 prices that vary with each billing cycle, may be 

acceptable as the price for POLR service.293 (A supply arrangement comparable to this version 

of POLR service is the high-risk pool for automobile insurance operated in several states).294 

Texas and Massachusetts are current examples of this vision of POLR service, 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 procurement experience. Accordingly, some states 

determined they are more likely to quickly obtain 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 entry conditions that alternative suppliers face. 

This section describes each of the decisions. 

a. Pricing of POLR Service

The profiled states generally set the POLR price at the regulated price for electric power 

prevailing before the onset of retail competition, less a discount. Discounts usually persist over 

a specified multi-year period. Assuming that competition generally lowers prices, one rationale 

for the discounts was to provide a proxy for the effects of competition on customers less able to 

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 previously regulated rates. In contrast, customers in the 

 

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

294 Most states have a mechanism by which high-risk drivers can obtain insurance. Often insurers in a state are assigned a portion of the pool of 

high-risk drivers based on each firm’s share of drivers outside the pool. AIPSO manages many of the pools and maintains links with individual 

state programs at https://www.aipso.com/adc/DesktopDefault.aspx?tabindex=0&tabid=1. Similar plans are available in many states for 

individuals with prior health conditions who are seeking health insurance coverage. See COMMUNICATING FOR AGRICULTURE AND THE SELFEMPLOYED, COMPREHENSIVE HEALTH INSURANCE OF HIGH-RISK INDIVIDUALS (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, the distribution utility petitioned 

the Georgia Public Service Commission to withdraw from retail sales. In Georgia, under the amended Natural Gas Competition and Deregulation 

Act of 1997, a customer who does not choose an alternative supplier is randomly assigned an alternative supplier. Discussion and documentation 

about the Georgia natural gas retail competition program are available at http://www.psc.state.ga.us/gas/ngdereg.asp. 

296 See infra New Jersey profile, Appendix D. 

100 
Commonwealth Edison territory – the area with the highest cost-based rates – received 

20 percent discounts to bring retail POLR prices there into line with the regional average 

bundled service prices prevalent prior 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 adjust the regulated POLR price to 

allow for changes in the cost of fuel to generate electricity. Some states separated fuel costs 

from other cost components, because fuel costs have been more volatile than other input prices. 

(Fuel costs are the largest variable cost component 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 costs, 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 financial difficulties, and alternative 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 distribution utility with a POLR 

obligation avoids the costs of procuring generation supply for that customer. The distribution 

utility therefore “credits” the customer’s bill so that the customer pays the alternative supplier 

(rather than the utility) for the electricity supplied.300 This avoided charge – the “shopping 

credit” – equals the regulated POLR service price. States have used two approaches to determine 

the level of the shopping credit. One view is that the shopping credit equals the avoided cost or 

the proportion of POLR procurement costs attributable to a departing customer. Maine, for 

example, estimated avoided costs on this basis, with no additional estimated avoided costs.301 

This approach results in a lower shopping credit and lower total POLR price. 

An alternative perspective is that the distribution utility also avoids “adders” (costs that are in 

addition to avoided procurement costs), including marketing and administrative costs.302 This 

view results in a higher shopping credit and higher total POLR price, 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 adjustments would have retail prices well below market 

rates during periods of increasing fuel prices, and prices well above 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 which one of the state’s utilities declared bankruptcy because, among other reasons, 

capped POLR rates were substantially below wholesale prices. 

300 The distribution utility continues to charge the customer a delivery charge (a “wires” charge) to cover the transmission and distribution 

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_informed/about_mpuc/commissioners/ph-welch.pdf. 

302 See Kenneth Rose, Electric Restructuring Issues for Residential and Small Business Customers, National Regulatory Research Institute Report 

NRRI 00-10 (June 2000), available at http://www.nrri.ohio-state.edu/dspace/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. 

101 
potential 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 avoidable costs included in its 

shopping credit calculations.304

d. The Multi-Year Period for POLR Service 

States that implemented retail competition also determined how long POLR service should 

continue at a discount from prior regulated prices. This period generally corresponded to the 

distribution utility’s collection of stranded generation and other costs. In a competitive retail 

environment, utilities no longer were assured they could recover costs of all of their stateapproved generation investments. Most states faced claims of stranded costs associated with 

generation facilities that were unlikely to earn enough revenues to recover fixed costs once 

customers could seek out alternative, lower-priced retail suppliers. States allowed utilities to 

recover stranded costs through charges on distribution services that cannot be bypassed.305

Each state that authorized the collection of stranded costs had to determine these costs and the 

duration of the collection period. These decisions fundamentally altered the electric power 

industry and were at the center of some of the most contentious issues state regulators faced. 

Some states (for example, Maine and New York) required some or all generation to be sold to 

obtain a market-based determination of the level of stranded costs.306 In other states, such as 

Illinois, utilities voluntarily divested generation assets. As noted above, the result of these 

divestitures is that generation no 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 supply. For example, New 

Jersey utilities that offer residential POLR service acquire generation supply through three 

overlapping three-year contracts, with each contract covering approximately one-third of the 

projected load.308 This “laddering” of supply contracts reduces the 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 significance as the competitive rates increased relative to POLR service 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. 

102 
F. Observations on How POLR Service Policies Affect Competition 

One of the most contentious issues state regulators currently face is how to price POLR service 

once rate caps expire. This situation is especially vexing for those states that had stranded cost 

recovery periods during which fixed POLR prices were substantially lower than wholesale 

prices. Rate caps expire this year in Delaware, Illinois, Maryland, 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 – leading to increases in wholesale prices – have 

made it difficult fully to discern best practices regarding retail competition. The price increases 

interacted dramatically with POLR service rate caps, clouding the experiences most states have 

had with other retail competition issues. As a result, the range of experience regarding other 

aspects of retail competition is narrow, primarily limited to what has occurred in New York, 

Texas (within ERCOT), the Duquesne distribution area within Pennsylvania, Maine, 

Massachusetts (recently), and the large C&I customers 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 equivalent 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-threatening effects of unanticipated loss of electric service. 

 Treatment of Different Customer Risk Preferences: POLR service that goes beyond 

short-term access to the wholesale spot market involves providing a bundle of services 

that electricity marketers also can provide. States that embrace a more expansive version 

of POLR service should recognize 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 substantial market imperfections. If a state adopts 

a more expansive version of POLR service, it should periodically review the rationale 

for continuing it. 

 POLR Service Price Caps: It is difficult to establish a POLR service price cap that will 

not distort retail electricity markets and the associated development of effective 

competition. The best practice is to make frequent adjustments to the cap (at least so as 

to reflect changes in fuel costs), or to abandon 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 with energy procurement processes and because 

they are comfortable with decisions to adjust input use based on input prices. For 

smaller, less sophisticated customers, including residential customers, issues of 

103 
awareness and access to comparative 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 available choices and how to switch 

suppliers (including any constraints on switching). Texas maintains a well-organized 

website that appears to work well for residential price comparisons. New York’s 

program to encourage customers to try out alternative suppliers that agree to offer a 

temporary discount appears to educate many residential customers effectively about the 

ease of switching, without subsidizing alternative suppliers. 

 Customer Aggregation: Customer aggregation is an approach that can reduce percustomer search and switching costs and thus 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 electricity competition. States should attempt to 

avoid rules that make entry more expensive or slower than is required to avoid 

fraudulent marketing activities. Areas to consider include registration fees and delays, 

costs and delays in interacting with the distribution utility (metering, billing, treatment of 

receivables), security deposits for suppliers, rules regarding 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 consumption and supply decisions and thereby maximize 

welfare. This price will vary over 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 sometimes are volatile, 

efficient retail prices for electricity are more volatile than the prices that customers are used to paying under traditional regulation. Electricity 

prices under traditional regulation typically reflect average costs for electricity and risk management over extended periods. In a retail choice 

environment, alternative suppliers can offer a variety of risk management (hedging) levels that range from full, immediate pass-through of 

wholesale spot market prices to fixed rates for extended periods. For a discussion of how much hedging is required to eliminate portions of 

volatility, see Severin Borenstein, Customer Risk from Real-Time Retail Electricity Pricing: Bill Volatility and Hedgability, (June 6, 2006) 

(University of California Energy Institute CSEM Working Paper 155), available at http://www.ucei.berkeley.edu/PDF/csemwp155.pdf. It is 

important to note that these bundles of electricity and risk management also can constitute efficient retail prices, although they contain a cost 

component associated with the risk management services. If POLR service prices become more volatile, a customer who prefers less risk will 

have incentives to search for an alternative supplier that offers a price/risk tradeoff – slightly higher prices but less volatility. 

Alternative suppliers will have incentives to offer preferable price/risk alternatives to gain customers. Retail customers can also consider whether 

onsite generation or other forms of upstream vertical integration offer a preferable price/risk combination. 

In general, so long as customers are served by alternative suppliers or upstream vertical integration is an option, the POLR price is only one 

component of the average market price. 

In a traditional regulatory setting, utilities sometimes offer customers a discount if they agree to have their service interrupted during peak 

demand periods. Removing restrictions to interruptible service rates would allow more customers to improve the match between their risk 

preferences and their electric service. Industrial Coalitions comments (2) at 25. 

104 
price does not closely match the competitive price, it will distort consumption and investment 

decisions312 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 rate of return on investments). This alignment 

leads to the most economically efficient allocation of resources.314

Experience within the profiled states 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 generation. 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 below-market prices or occasionally 

above market prices, but never at the 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 obligation can become financially 

distressed, as they did in California during its energy crisis.317

Fuel prices are responsible for a substantial percentage of the change 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 efficient than using a fixed price as a proxy for the 

market price. Moreover, a POLR price that is adjusted only infrequently to incorporate 

underlying fuel price changes will usually be either above or below the competitive market 

price.318 A fixed or infrequently updated price creates incentives for customers to move back 

and forth from POLR service to alternative suppliers, based on which offers a lower rate. This 

repeated switching may create additional costs for both POLR and alternative suppliers. It also 

can reduce the certainty about procurement quantities which suppliers need to make long-term 

supply arrangements. Including other identifiable cost components that fluctuate widely in 

POLR service price adjustments will increase the likelihood that the POLR service price will be 

a reasonable proxy for the competitive price. 

2. Lack of Market-Based Pricing Distorts Development 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 supply prices. In these circumstances, 

 

312 Some commenters observed that cost averaging, cost deferrals, inaccurate cost allocations, double counting of costs, and price caps all can 

distort consumption and investment that result in loss of consumer welfare. Strategic Energy comments (2) at 6; Constellation comments (2) at 8. 

313 The electricity industry has traditionally provided discounts or other forms of assistance to low-income families. States may need to examine 

whether the level of this assistance should be increased in response to price increases 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 they experienced other types of increased or more volatile input costs relative to their rivals. Firms with 

electricity-intensive production processes are likely to be particularly sensitive to increased prices or price volatility. Alcoa comments (2); 

Industrial Coalitions comments (2) at 26. 

314 This statement would need to be qualified to the extent there is market power and to the extent there are unpriced externalities 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. 

105 
customers are likely to experience a shock when POLR service prices are adjusted to reflect 

prevailing wholesale prices. This can create public pressure to continue the fixed POLR rates at 

below-market levels. For example, some jurisdictions have considered a gradual phase-in of the 

price increase to bring POLR prices to the market level. The shortfall between the market POLR 

price and the price that customers actually pay is usually deferred and collected later from the 

POLR provider’s customers. 

Although this approach reduces rate shock, it is likely to distort retail electricity markets. First, a 

phase-in of the price increase continues to send inaccurate price signals and undermines 

incentives to reduce consumption. Second, it prevents entry of alternative suppliers by keeping 

the POLR rate below market levels for additional years. Third, it results in higher prices in 

future years as the deferred revenues are recovered, so that customers who purchase electricity 

later are unfairly penalized (overcharged). Fourth, if surcharges to pay for deferred revenues are 

not designed carefully, the charges can disrupt existing competition by forcing customers with 

alternative suppliers to pay for part of the deferred revenues. Fifth, if wholesale 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 increasing wholesale prices can endanger the financial viability of the 

distribution utility. 

3. Different POLR Services Designed for Different Classes of Customers

Some states have different POLR service designs for different customer classes. POLR service 

prices offered to large C&I customers generally entail less discounting from regulated rates or 

competitive market-based procurement and have been based on wholesale spot market prices. 

Large C&I customers generally have a good understanding of price risk and of the means and 

costs required to reduce that risk. In addition, 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 classes of customers. The 

result of this price response may be to improve system reliability and dissipate market power in 

peak demand periods.320

Large C&I customers have engaged in more switching to 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 Commission 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 relationship between their 

usage and the actual cost of electricity, and obscures opportunities to save on electric bills that would become apparent if RTP were used to reveal 

varying price signals.” It further notes that “if a sufficient number of customers reduced load in response to RTP, besides benefiting themselves, 

the reduction in peak period usage would ameliorate extremes in electricity costs for all other customers.” 

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

106 
customized time-of-use contracts for large C&I customers.322 Moreover, the profiled states 

show that a substantial number of suppliers actively serve large C&I 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 nonresidential customers of the two large investorowned distribution utilities in Oregon can switch to an alternative supplier. Nonresidential 

customers must make their selections during a limited annual window. The window must 

extend at least five days in duration, but usually a month is allowed. In addition to picking 

the alternative supplier, the largest customers must select a contract duration. One option 

specifies a minimum duration of five years, with an annual renewal after that. As of 2005, 

alternative suppliers were anticipated to serve about 10 percent of load in one distribution 

area and about 2.1 percent in the other. One utility offered choice beginning in 2003, while 

the other began customer choice in 2005. Detailed descriptions are available at 

http://www.oregon.gov/PUC/electric_restruc/indices/ORDArpt12-04.pdf. 

It is not necessary to expose all customers to time-based prices to introduce price-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 Jersey. California is considering 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 customers 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 residential customers be offered real-time pricing as a 

voluntary tariff. Ideally, competition provides incentives for suppliers to offer customers the mix 

of products and services that matches their potentially diverse preferences. 

4. Use of Auctions to Procure POLR Service

As discussed above, New Jersey has used an auction process to procure POLR supply for both 

residential and C&I customers. Illinois proposed a similar auction for 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 Markets comments; Constellation comments; PPL comments; RESA 

comments; NYPSC comments; Direct Energy comments; Reliant comments; PA Office Consumer 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, PUB. UTILS.

FORTNIGHTLY (Mar. 15, 2001). 

107 
5. 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 process. 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 expected 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 consumers 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 “shopping credits” have had little retail entry. Some 

states with retail competition have had substantial consumer education programs, including 

websites with orientation materials 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 ordering distribution utilities to make these discounts known to 

customers who contact the utility.328 These efforts have increased residential switching and 

reduced prices, at least for the short term. Experience indicates that once residential customers 

switch to alternative suppliers, they seldom return to POLR service even after the temporary 

discounts expire.329

 

324 James Zolnierek, Katie Rangos, and James Eisner, Industry Analysis 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/Reports/FCC-State_Link/IAD/mksh2q98.pdf; Thomas L. Welch, Chairman, Maine Public 

Utilities Commission, UtiliPoint PowerHitters interview (Jan. 24, 2003) available at http://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 “PowerSwitch” alternative supplier referral program (first 

developed by Orange & Rockland) as the model for all utilities in the state. 

329 New York State Consumer Protection Board, Comment to the New York State 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 customers 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 provides assured initial savings to consumers. 

108 
APPENDIX 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 Comments on Draft Report to Congress on 

Competition in the Wholesale and Retail Markets for Electric Energy, issued on June 5, 2006. 

The actual comments can be found at FERC.gov 

 

The following parties filed comments in response to the notice issued October 13, 2005: 

Alcoa, Inc. (Alcoa) 

Allegheny Energy Companies (Allegheny) 

 

Alliance for Retail Energy Markets 

Ameren Services Company (Ameren) 

American Antitrust Institute (AAI) 

American Public Power Association (APPA) 

Association of Large Distribution 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 Industry Center (Carnegie Mellon) 

CenterPoint Energy Houston Electric, LLC (CenterPoint) 

Los Angeles Department of Water and Power (LADWP) 

7-Eleven, Inc, Big Lots Stores, Inc., Crescent Real Estate Equities, Federated Department Stores, 

Hines, JC Penney, Wal-Mart Stores, Inc. (collectively, Commercial End-Users) 

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

109 
Connecticut 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, Coalition of Midwest Transmission Customers, 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 Regulatory Commission (IURC) 

110 
Industrial Consumers: Portland Cement Association, American Forest and Paper Association, 

American Iron and Steel Institute, California Large Energy Consumers Association, Coalition of 

Midwest Transmission Customers, National Lime 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 Advocate (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 Commission (Missouri State Commission) 

National Association of Regulatory Utility Commissioners (NARUC) 

National Association of State Utility Consumer Advocates (NASUCA) 

National Energy Marketers Association (National Energy) 

National Grid USA (National Grid) 

National Rural Electric Cooperative Association (NRECA) 

New Mexico Attorney General 

New York Independent System Operator, Inc. (NYISO or New York ISO) 

New York State Department of Public Service (NYPSC or New York PSC) 

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

Corporation (Rochester G&E) 

North Carolina Utilities Commission, Public Staff - North Carolina Utilities Commission, and 

the Attorney General of the State of North Carolina (collectively, North Carolina Agencies) 

111 
Northeast Utilities 

NUCOR Corporation, Blue Ridge Power Agency, 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 Authority (together, Progress and 

Santee Cooper) 

Public Utilities Commission of Ohio 

Reliant Energy Inc. (Reliant) 

Retail Energy Supply Association (RESA) 

South Carolina Electric and Gas Company (South Carolina E&G) 

Southern California Edison Company (SoCal Edison) 

Southern Companies (Southern) 

Southwest Transmission Dependent Utility Group (Southwest Transmission) 

Steel Manufacturers Association (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) 

112 
Virginia State Corporation Commission 

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

WPS Resources Corporation (WPS) 

Xcel Energy Services, Inc. (Xcel) 

The following parties filed comments in response to the notice issued June 5, 2006: 

Alcoa, Inc. (Alcoa) 

Allegheny Power and Allegheny Energy Supply Company, LLC (together, Allegheny) 

Alliance for Retail Energy Markets 

Alliance of State Leaders Protecting Electricity Consumers 

American Public Power Association (APPA) 

Attorney General of California 

Attorney General of New Mexico 

California Department of Water Resources; State Water Project 

Cape Light Compact 

City of Seattle; City Light Department 

Coalition of Midwest Transmission Customer, NEPOOL Industrial Customer Coalition, PJM 

Industrial Customer Coalition, Industrial Energy Users-Ohio, Industrial Energy Consumers of 

Pennsylvania, and West Virginia Energy Users Group (collectively, Industrial 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) 

113 
Duquesne Light Company (Duquesne) 

Edison Electric Institute (EEI) and the Alliance of Energy Suppliers 

Electric Power Supply Association (EPSA), Independent Power Producers of New York (IPP 

NY), Independent Energy Producers of Maine (IEPM) 

Electricity Consumers Resource Council (ELCON) and American Iron and Steel Institute, 

Association of Businesses Advocating Tariff Equity, Coalition of Midwest Transmission 

Customers, PJM Industrial Customer Coalition, Industrial Energy Users – Ohio, Multiple 

Intervenors, and Wisconsin Industrial Energy Group, Inc. (collectively, Industrial Consumers) 

Industrial Consumers: Portland Cement Association, American Forest and Paper Association, 

American Iron and Steel Institute, California Large Energy Consumers Association, Coalition of 

Midwest Transmission Customers, National Lime 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 Utility Consumer Advocates (NASUCA) 

National Grid USA (National Grid) 

National Rural Electric Cooperative Association (NRECA) 

New York State Electric & Gas Corporation (New 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) 

114 
PPL Companies (PPL) 

Progress Energy, Inc. and South Carolina Public Service Authority (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 & Electric Company, Wisconsin Electric Power 

Company, Wisconsin Public Power Incorporated, and WPS Resources Corporation (collectively, 

Wisconsin Load Serving Entities). 

115 
APPENDIX B 

TASK FORCE MEETINGS WITH OUTSIDE PARTIES 

American Public Power Association – October 27, 2005 

ArcLight Capital Partners LLC– November 9, 2005 

Compete Coalition – October 27, 2005 

Edison Electric Institute – October 26, 2005 

Electric Power Supply Association – 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 Utility Commissioners – October 27, 2005 

National Association of State Energy Officials – October 27, 2005 

National Governors Association – October 26, 2005 

National Rural Electric Cooperative Association – October 26, 2005

Public Utility Law Project – October 27, 2005 

Standard & Poor’s – November 9, 2005 

SUEZ Energy North America – December 8, 2005 

116 
APPENDIX C 

AN ANNOTATED BIBLIOGRAPHY OF QUANTITATIVE COST BENEFIT 

ASSESSMENTS OF ELECTRIC INDUSTRY RESTRUCTURING PROPOSALS 

Commenters on the section 1815 study highlighted a wide variety of cost-benefit studies that 

seek to evaluate the electric power industry. Both proponents and opponents of electric industry 

restructuring have armed themselves with these types of analyses to support their respective 

positions. It can be challenging to understand these studies’ sometimes contradictory results. 

The Task Force reviewed roughly 30 cost-benefit analyses330 in an attempt to better understand 

what they reveal. Based on this review, together with a review of the recent DOE Report (J. Eto, 

B. Lesieutre, and D. Hale, A Review of Recent RTO Benefit-Cost Studies: Toward More 

Comprehensive Assessments of FERC Electricity Restructuring Policies (December 2005) 

[hereinafter Eto]), the Task Force has made the following observations: 

1) Many of the existing studies address only the benefits of restructuring proposals. To 

the extent studies overlook the costs associated with institutional changes, they can provide an 

incomplete picture of impacts, and their results should be juxtaposed to cost estimates. ( See

Appendix C: RTO West Benefits and Costs, Economic Assessment of RTO Policy, and Putting 

Competitive Power Markets to 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 reliability and the facilitation of lowest-cost 

electricity production (via incentives for innovation and low-cost construction) - are very 

difficult to quantify using current technology and are often left out of benefit assessments. “It 

is important that technically limited studies not be interpreted to suggest that impacts that they do 

not analyze are not significant.” Eto at 21. 

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

measure. Many of these models also employ simplistic and often misleading assumptions about 

market behavior. Improving the models used to derive quantitative benefits is technically 

difficult – significant improvements would involve marrying the complexity of adequately 

modeling a 10,000+ bus transmission/generation system to the complexity of modeling realistic 

human behavior in markets. The capabilities of existing 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 critiques to these studies are listed under the “Alternate Views” table category. 

117 
4) Modeling energy transmission and markets necessarily requires making a great deal 

of assumptions given the significant limitations in data needed to "feed" these models. Thus, 

outputs of RTO modeling attempts vary widely based on the assumptions made by the parties 

doing the modeling – assumptions as to transmission configurations, weather, imports/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 studies is that they often only estimate the benefits to 

society as a whole. Determining the distribution of benefits and costs - who wins and who 

loses, or who wins the most - is an important piece of the decision making puzzle. 

Unfortunately, it is much more difficult to measure the distribution of benefits than it is total 

social costs. Some efforts have been made in this direction with estimates of the end-use price 

impacts that restructuring has had or might have and with estimates of benefits that individual 

participants in electricity markets might accrue (See Appendix C: Beyond the Crossroads, the 

Future Direction of Power Industry Restructuring and Competition Has Not Lowered Electricity 

Prices). 

6) Characteristics of the best restructuring cost-benefit studies, given existing 

technology/data, include: 

• Provision of clear and precise descriptions of assumptions, data sources, methods and 

technical detail. 

• Where econometric models are used, study write-ups should provide regression methods 

and equations, goodness of fit measures, and results of any tests done to detect analytical 

flaws. 

• An attempt to address all potential costs and benefits. 

• An effort to address the distribution of impacts. 

118 
STUDIES OF BENEFITS IN THE US

Beyond the Crossroads: The Future Direction of Power Industry Restructuring 

Region US 

Report Date 2005 

Sponsor Cambridge Energy Research Associates 

Author/Contractor Cambridge Energy Research Associates 

Model/Method CERA constructs average counterfactual prices as an econometric 

function of fuel prices and return on the rate base, for residential and 

industrial customers in four geographic territories based on 1992-1197 

data. 

Scope of Inquiry Real price impacts on consumers of electric 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 regulation had continued. 

Regional distribution of these benefits: 

NE $ 8 billion 

Midwest: $ 8 billion 

South: $24 billion 

West: -$7 billion 

Alternate Views • APPA thinks figures are inflated: 

http://www.appanet.org/newsletters/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 Restructuring Benefits Captured by 

Consumers, ELECTRICITY JOURNAL, Volume 19, No. 1 

(January/February 2006) at 42-47. 

Electricity Markets: Consumers Could Benefit from Demand Programs, but Challenges 

Remain 

Region US 

Report Date August, 2004 

Sponsor Report to the Chairman, Committee on Governmental Affairs, U.S. Senate 

Author/Contractor US GAO 

Model/Method Reviewed the literature, analyzed industry and participant data, and 

conducted interviews with state and federal officials (in FERC, the 

DOE , and the GSA), industry experts, representatives 

from utilities, and customers 

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

119 
Identifies (1) the types of demand-response programs currently in use; (2) 

the benefits of these programs; (3) the barriers to their introduction and 

expansion; and (4) where possible, instances in which these barriers have 

been overcome. 

Period Studied 

Conclusion Demand-response programs can benefit customers in regulated and 

restructured markets by improving market functions and enhancing the 

reliability of the electricity system 

Recent studies show that demand-response programs have saved millions 

of dollars—including about $13 million during a heat wave in New York 

State during 2001. A FERC-commissioned study reported that a moderate 

amount of demand-response could save about $7.5 billion annually in 

2010. 

Web Reference http://www.gao.gov/new.items/d04844.pdf 

Staff Report on Cost Ranges for the 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 rests largely on information gleaned 

from audit staff, FERC Form No. 1 data and interviews with and data 

responses from existing RTOs and Independent System Operators (ISOs). 

Scope of Inquiry To estimate the cost of developing a Day One RTO that provides 

independent and non-discriminatory transmission service 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 annual 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/EventCalendar/Files/20041006145934-rto-costreport.pdf 

Alternate Views • M. Lutzenhiser, RTO Dollars and Sense: Financial Data Raises 

120 
Doubts About Whether Deregulation Benefits Outweigh Costs, 

PUBLIC UTILITIES FORTNIGHTLY (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/~ppcpdx/Tx/Alliance%20Cost%20Study

%20Report%2011-22-04%20FINAL.pdf 

Impacts of the Federal Energy Regulatory Commission’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, participants 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 impacts of SMD. GE MAPS was used to 

assess how the use of transmission networks will change under SMD. 

POEMS is an amalgam of several economic models (including EIA’s 

National Energy Modeling System and TRADELEC) which forecasts 

trading volume and prices by NERC region. 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 FERC’s Standard Electricity Market 

Design (SMD), as presented in FERC’s July 31, 2002 proposed rule 

Period Studied 

Conclusion 1. Estimated annual cost of implementing FERC’s SMD Rule: $760 

million ($.21/MWhr) 

2. Average wholesale prices under SMD are estimated to decrease by 1 

percent in 2005, 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 annual 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 Standard Market Design (June, 2003), available at

http://www.pulp.tc/Alliance_Commentary_on_DOE_Study.pdf 

121 
Impact of the Creation of a Single 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 rates and measures the efficiency 

impacts. 

• Assumes 5 percent improvement in transmission transfer 

capability and measures production cost impacts. 

• Capacity sharing benefits simulated. 

• Decreased reserve requirements (from 15 percent to 13 percent) 

• Assumes generator efficiency improvements in RTO Policy case. 

Scope of Inquiry Assesses economic costs and benefits of a national move toward RTOs, 

including improvements in transmission system operations with resulting 

enhancements to inter-regional trade, congestion management, reliability 

and coordination, and improved performance of Energy markets. 

Period Studied 2002-2021 

Conclusion * $1-$10 billion/year in system production cost savings 

* NPV of production cost savings 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 Efficient Operation and Expansion Of 

the Transmission Grid, FERC Docket No. PL03-01-000 (March 

13, 2003), available at 

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

• Comments of the New England Conference of Public Utilities 

Commissioners on Electricity Market Design and Structure, 

FERC Docket No. RM01-12-000. 

• Comment of the Staff of the 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 

123 
STUDIES OF BENEFITS IN THE MIDWEST

An RPM Case Study: Higher Costs for Consumers, Windfall Profits for Exelon 

Region PJM / Northern Illinois 

Report Date October 18, 2005 

Sponsor Illinois Citizens utility Board 

Author/Contractor Synapse Energy Economics / Ezra Hausman, Paul Peterson, David 

White, and Bruce Biewald 

Model/Method Comparison of baseline capacity revenues (derived from historical 

market data) with proposed RPM PJM price 

Scope of Inquiry Determine potential wealth transfer effects of proposed Reliability 

Pricing Model (RPM) by examining capacity revenues that might accrue 

to Exelon’s Nuclear facilities in Northern Illinois if RPM is 

implemented. 

Period Studied June 2004 – June 2005 

Conclusion At the target RPM price, Exelon’s nuclear plants in northern Illinois 

stand to gain almost $390 million in additional capacity revenues, 

compared to the 2004 capacity market price, at ratepayers’ expense. At 

the maximum RPM 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 billion every year, paid mostly to 

existing base load generation. 

Web Reference http://www.synapse-energy.com/Downloads/SynapseReport.2005-10.ILCUB.RPM-Study--Higher-Costs-Windfall-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 International Corporation 

Model/Method Production Cost/ Power Flow Modeling: PROMOD IV 

Scope of Inquiry Evaluates proposed financial transmission right allocations 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=download&_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 

124 
STUDIES OF BENEFITS IN THE NORTHEAST

Putting Competitive Power Markets to the Test The Benefits of Competition in America’s 

Electric Grid: Cost Savings and Operating Efficiencies 

Region Eastern Interconnection 

Report Date July, 2005 

Sponsor BP Energy Company, Constellation 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 occurred. Those results were compared 

with a simulation of market conditions 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 and 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 period 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/competitivepower/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 annual prices: (1) the actual wholesale 

power costs (WPC) in the PJM market, and (2) prices in a scenario with 

economic regulation continued from the mid-1990s to today so that the 

125 
generation service costs (GSC) are the unbundled generation 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/downloads/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 (Moray, Kirsch, Braithwait, Eakin) 

Model/Method Analysis of CAEM study assumptions/ inputs 

Scope of Inquiry To review and critique the Center for Advancement of Energy Markets’ 

(CAEM) study entitled Estimating the Benefits of Restructuring 

Electricity Markets: An Application to the PJM Region (Sept. 22, 2003) 

(hereinafter CAEM Study). 

Period Studied 1997-2002 

Conclusion The CAEM Study’s quantitative results fail to demonstrate any 

relationship between these price changes 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 Restructuring Electricity Markets: 

An Application to the PJM Region, available at

http://www.caem.org/website/pdf/PJM.pdf

126 
Estimating the Benefits of Restructuring 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 restructuring the electricity market 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: Analysis 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 implementing 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. Looked 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 

127 
estimates. 

Scope of Inquiry Potential benefits from implementing an interregional real-time dispatch 

in the Northeast. (Response to Mirant study of 2001) 

Period Studied 10/00-8/01 

Conclusion Found that improvements in data and assumptions in Mirant study led to 

a material overstatement of the short-run benefits to New York 

consumers. Found large price impact benefits to PJM customers but 

little or negative price impacts for 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%20Combined%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 and flows. Looked 

at unconstrained transmission to determine correlation between prices. 

Assumes centralized dispatch would eliminate measured uneconomic 

flows. 

Scope of Inquiry Potential efficiency benefits that could be achieved by creating a single 

market for electricity in the Northeast. Model does not address net costs 

of establishing/operating a single Northeast RTO. 

Period Studied 6/00-12/00 

Conclusion Net benefit of $440 million. 

$76 to PJM, $256 to NYISO, $108 to NE ISO. 

* Not publicly available. Review based on secondary references.

Competition Has Not Lowered U.S. Industrial Electricity Prices 

Region Connecticut, Massachusetts, Maine, New Hampshire, New York, and 

Rhode Island 

Report Date 2005 (Published in the Electricity Journal, Vol. 18, No. 2 (2005) at 52-

61) 

Sponsor Jay Apt 

Author/Contractor Jay Apt, Carnegie Mellon University 

Model/Method Used EIA price data to perform regression analysis on prices before and 

after competition. 

Scope of Inquiry Examines the effect of restructuring on prices paid by US industrial 

customers for electricity 

Period Studied 1990-2004 

Conclusion Competition does not produce statistically significant price effects – rates 

128 
in all states studied other than Maine increased an average of .8 percent 

per year prior to competition and they increased by 2 percent per year 

after competition. 

Web Reference http://wpweb2.tepper.cmu.edu/ceic/papers/ceic-05-01.asp 

Economic Assessment of AEP’s Participation in PJM 

Region PJM combined with AEP 

Report Date December, 2003 

Sponsor AEP 

Author/Contractor Cambridge Energy Research Associates 

Model/Method ? 

Scope of Inquiry Quantifies the costs and benefits of AEP’s integration into PJM markets. 

Period Studied ? 

Conclusion $245 M in 2004 

declining to $188M in 2008 

Economic and Reliability Assessment 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 market efficiencies, savings from 

operational consolidation. 

Period Studied ? 

Conclusion $220M/yr in 2005 

$150M/yr in 2010 

129 
STUDIES OF BENEFITS IN THE NORTHWEST

Bonneville Power Administration Grid West Benefit Assessment for Decision Point 2 

Region Northwest US 

Report Date August 4, 2005 

Sponsor Bonneville Power Administration 

Author/Cont

ractor 

Internal Bonneville Power Administration staff report 

Model/Meth

od 

Partially based on modeling conducted by Grid 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/restructuring/Docs/2005/benefit%20ass

essment/BPA_Grid_West_Benefit_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, miscellaneous 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 reserves range from $5 million to 

130 
$26 million per year 

• The estimated production cost savings associated with Grid Westmanaged real-time energy balancing 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 shorter than 12 hours) related to noncascading transmission events has an estimated annualized value to 

the region ranging from $17 million to $203 million per year 

• The estimated increase in production costs from the existing 

practice of charging multiple or pancaked rates ranges from $4 

million to $61 million per year. 

• The estimated reduction in production costs from more efficient 

prescheduled interchange facilitated by the RCS ranges from $18 

million to $52 million per year. 

• The estimated savings associated 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 Lutzenhiser of the Public Power Council 

Model/Method Benefits: MarketSym used to estimate the short term dispatch benefits 

associated with rate de-pancaking 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 alternatives to forming Grid West 

Period Studied 2004 

Conclusion Gross annual benefits to the region of $78 million 

Grid West Annual costs of $200 million. 

Net Benefits of <122 million> 

Web Reference http://www.snopud.com/content/external/documents/gridwest/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 

131 
Model/Method GE MAPS 

Scope of Inquiry This study looked at the impacts that 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 attributed to the elimination of rate 

pancaking, 60 percent to reserves sharing. 

RTO West Potential Benefits and Costs 

Region Northwest 

Report Date October 23, 2000 

Sponsor RTO West 

Author/Contractor RTO West Benefits/Cost Team 

Model/Method Aurora for production cost modeling, spreadsheet analyses for others 

Scope of Inquiry Identify and quantify benefits and costs 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 anywhere from $33 million to $328 million 

annually 

• RTO Annual Costs of $63-$76 million 

• Misc. qualitative benefits 

132 
STUDIES OF BENEFITS IN THE SOUTHEAST

Cost Benefit Study of the Proposed GridFlorida RTO 

Region Peninsular Florida 

Report Date December 12, 2005 

Sponsor Grid Florida, LLC 

Author/Contractor ICF Consulting 

Model/Method Production cost modeling using GE MAPS 

Scope of Inquiry Examined the costs and benefits to Peninsular Florida consumers of 

transforming the current decentralized market to a centrally organized 

market under two modes of operation – a Day-1 only RTO and a Delayed 

Day-2 RTO. 

Period Studied 2004-2016 

Conclusion • The quantitative benefits to Peninsular 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 benefits under Delayed Day-2 RTO 

operation were substantial, and ranged from approximately $810 

million in the Market Imperfection Case to almost $968 million 

in the Reference Case, the cost of a “greenfield” Delayed Day-2 

RTO with wholly new systems, physical facilities and personnel, 

designed along FERC’s Standard Market 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 change 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 benefits of $798 million from the 

implementation of a GridFlorida Delayed Day-2 RTO while 

jurisdictional consumers would receive 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 for the SPP Regional State Committee 

Region Southwest Power Pool 

Report Date April 23rd, 2005, revised July 27, 2005 

Sponsor SPP Regional State Committee 

Author/Contractor Charles River Associates 

Model/Method a) Wholesale Energy Modeling using GE MAPS 

133 
b) Allocation of Energy Market Impacts and Cost Impacts 

c) Qualitative Assessment of Energy Imbalance Impacts 

d) Qualitative Assessment of Market Power Impacts 

e) Aquila Sensitivity Cases 

Scope of Inquiry (1) an analysis of the probable 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, implementation 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 Arkansas, 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 Dominion 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 control) 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. 

134 
The Benefits and Costs of Regional Transmission Organizations and Standard Market 

Design in the Southeast 

Region SE (SeTrans, Grid South, Grid Florida) 

Report Date 11/6/02 

Sponsor Southeastern Association of Regulatory Commissioners 

Contractor Charles River Associates / GE Power Systems Engineering 

Model/Method GE MAPS (OPF/Production cost model) 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 

135 
STUDIES OF BENEFITS IN TEXAS

Electric Reliability Council Of Texas, Market Restructuring Cost Benefit Analysis. 

Region ERCOT/ Texas 

Report Date 11/30/2004 

Sponsor ERCOT 

Author/Contractor TCA/KEMA 

Model/Method a) Energy Impact Assessment (EIA)—quantified impacts to the 

energy market, system dispatch, energy prices, 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 study) and a nodal market design 

Period Studied 2005-2014 

Conclusion Did not draw single conclusion – “the potential savings found in the 

Energy Impact Assessment, relative to the Implementation costs found 

in the Implementation Impact Assessment, suggest that the benefits of 

the TNM could outweigh the costs for the ERCOT region as a whole. 

Web Reference http://oldercot.ercot.com/TNT/default.cfm?func=documents&intGroupI

d=83&b 

136 
APPENDIX D 

STATE RETAIL COMPETITION PROFILES331

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 earlier in the transition. Specifically, customers eligible to choose 

their electric supplier as of October 1, 1999, included industrial and commercial customers with 

a demand of greater than 4 MW,332 commercial customers with businesses at ten or more sites 

with an aggregate coincident peak demand of 9.5 MWs or greater, and non-residential customers 

accounting for one-third of the remaining electricity use of their customer class. All other nonresidential customers were allowed to choose 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 Commission (ICC) oversees the transition to competition in the electric 

industry. On January 24, 2006, the ICC approved proposals from Commonwealth Edison, the 

Ameren companies, Central Illinois Public Service, Central Illinois Light Company and Illinois 

Power, to procure generation (for retail customers who do not switch 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 choose a meter service provider other than the 

distribution utility. 

The ICC permitted Commonwealth Edison to designate customers with a demand exceeding 3 

MW as a competitive customer class.335 No other classes of customers have been declared 

competitive to date. Competitive services are defined as those services provided under special 

contract, not provided under tariff, and any tariffed service that the ICC decides is competitive. 

A service is declared competitive only if it is offered by a provider other than the utility or its 

affiliate, to a defined customer group or area, at a competitive price, if the utility is likely to or 

has lost business to the competitor, and if there is adequate transmission system capacity.336

 

331 Information in this appendix is derived in large part from – and updates information contained in the FTC Retail Competition Report. Because 

economic circumstances and state laws and regulations change, regulatory authorities in each state and market participants should be consulted 

for more detailed and up-to-date information on state retail choice programs. 

332 Average monthly maximum electrical demand on the electric utility’s system during the 6 months equals the customer’s highest monthly 

maximum demands in the 12 months ending June 30, 1999. 

333 220 ILL. COMP. STAT. 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.asp?intIdfile=83392&strc=bd.

336 220 ILL. COMP. STAT. 5/16-113. 

137 
 

Consumer Options: Consumers have two options for service: 

(1) They may either remain with the utility as a bundled customer (i.e., receiving 

generation, transmission and distribution services); or 

(2) They may choose to become a delivery services 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 Costs/Transition Costs). 

Under PPO service, a non-residential 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 under 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 Licensed to Provide Service: All suppliers wishing to provide competitive 

supply service must have a certificate of service authority. In order to receive certification, a 

supplier must show technical, financial, 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 maximum 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 supplier 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 increased in the AmerenCIPS service 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 retailers 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. 

138 
Retail Pricing Trends: As Table 1 shows, retail prices for the residential sector rose about 7 

percent from 1988 to 1997. Commercial and industrial prices rose by lesser amounts during that 

decade. Prices for all classes of customers declined after that decade through 2004, with the 

largest declines taking place in the residential 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 Service for Residential Customers: In accord with the restructuring 

legislation, there were mandatory residential POLR service rate reductions instituted in 1998, 

which depended on how the utility’s residential rate compared to the residential rate for all large 

investor owned utilities in the region at the time of the restructuring legislation. The rationale 

behind the restructuring legislation was that competition would tend to bring higher local rates 

down to the regional average, but there was uncertainty about whether residential customers 

would obtain these benefits of competition in a timely manner because of the relatively high 

expected marketing costs associated with residential customers. No mandated retail price 

reductions were applied to POLR service for non-residential customers. 

There are six major utilities in Illinois with required residential rate reductions for customers that 

have not selected an alternative supplier. Rate reductions were designed to bring residential rates 

in line with regional rates at the time of the restructuring legislation and are shown in Table 2.340 

The larger discount rates were applied in two phases. 

Table 2. Price Reductions from 1997 Cost-Based Rates by Distribution Utility 

Distribution Utility Reduction from 1997 Regulated 

Prices 

Commonwealth Edison 20% (15% August 1999, 5% October 

2001)

AmerenIP 20% (two increments)

AmerenCILCO 5%

AmerenCIPS 5%

AmerenUE 5%

MidAmerican Energy 1.7%

Non-residential customers were able to elect “real-time pricing” 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 ILL. COMP. STAT. 5/16-107. 

139 
time 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 involving 1,500 customers in the Commonwealth Edison 

territory operated by the Community Energy Cooperative.343 Some non-residential customers 

may also have real-time pricing or other time of use rates, but statistics are unavailable. 

POLR Service Provider: Utilities must provide traditional, bundled service for those customers 

who choose not to shop for a competitive supplier.344 The POLR (standard offer) price is the 

price for bundled service (i.e., service including generation, transmission, and delivery), which 

was set by the utility’s last rate proceeding, less the amount of any rate 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 utility after paying an administrative fee. A utility 

may require a returning customer with usage less than 15,000 kWh annually to stay with the 

utility for two years.346

Switching Activity: The degree to which customers have switched to delivery service from 

bundled service varies greatly between distribution franchise 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 Edison 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 little 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.raabassociates.org/Articles/Lieberman_10.28.05.ppt#299. 

344 220 ILL. COMP. STAT. at 5/16-103. 

345 Id. at 5/16-108. 

346 See 220 ILL. COMP. STAT. 5/16/-103(d). 

140 
Table 3. Illinois Switching to Alternative 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. Small non-residential customers have been slower in 

switching to alternative suppliers and the load served declined slightly in 2006, but the share of 

alternative suppliers continue to be well above the levels in 2003. 

Table 4. Illinois Retail Aggregate Customer Migration Statistics, 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 and 2006 figures are for the month of January. The 2005 and 2006 figures 

are estimated from the statistics for the Commonwealth Edison territory. Load in Commonwealth Edison accounts for approximately 96.5 

percent of the load of IOUs. To be conservative, it was assumed that there was no switching outside of Commonwealth Edison, hence 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

141 
Public Benefits Programs: The restructuring act establishes three public benefits funds which are 

slated to expire at the end of 2006. Table 5 contains information about the public benefits 

program in Illinois. 

Table 5. Illinois Public Benefits Programs* 

Research & 

Development 

Energy 

Efficiency 

Low 

Income 

Renewable 

Energy 

Total 

Million $ 3.0 75.0 5.0 83.0 

Mills/kWh 0.03 0.60 0.04 0.67 

% revenue 0.03% 0.87% 0.06% 0.96% 

Admin. DCEO DCEO DCEO 

Note: Trust Funds are administered by the Illinois Department of Commerce and Economic Opportunity (DCEO). 

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.

* In December 1997, PA 9D-551 was signed. It provided funding for EE, RE, LI (although EE and RE are at low 

levels) using non-bypassable, flat monthly charges on customer 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 legislation required Illinois utilities with transmission 

assets to join an RTO or ISO. Illinois utilities have joined either the Mid-West ISO or PJM 

West. Commonwealth Edison, for example, joined PJM West. The Ameren utilities joined the 

Mid-West ISO. MidAmerican has not joined an ISO, although it has received FERC 

authorization to engage an independent transmission operator. 

Generation Capability:

347 Prior to the restructuring legislation (1997), utilities operated 97 

percent of the generation capability in Illinois. By 2002, that figure dropped to 9.1 percent. The 

difference reflected the transfers and sales of generation assets to utility-affiliated entities and 

entry or expansion by independent power producers. Between 1997 and 2002, generation output 

in the state increased from 135 million MWhs to 188 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 information 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 Information Administration, Illinois State Profile, Table 4, available at

http://www.eia.doe.gov/cneaf/electricity/st_profiles/illinois.pdf. 

348 220 ILL. COMP. STAT. at 5/16-122. 

349 Department of Energy, Energy Information Administration, Disclosure Policies, available at

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 

142 
fuel 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 sources 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, and sulfur dioxide, as well as the amount of high- and low-level 

nuclear waste attributable to the sources of electricity.” 

Renewable Energy Portfolio Standard: On July 19, 2005, the ICC adopted a voluntary renewable 

portfolio standard target for bundled retail load starting at 3 percent in 2007 and rising by one 

percent each year until it reaches 8 percent in 2013.350 The ICC’s resolution also includes 

targeted reductions in future load growth. 

Maryland: Overview of Retail Competition Plan and Market Response 

Administrator and Start Date: The Maryland General Assembly 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 competition, but the Maryland Public Services Commission 

(PSC) allowed the utilities to start 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 with the distribution utility at PSC 

regulated prices until the end of the transition period; they may choose a competitive supplier; or 

they may choose to be aggregated with other customers. The transition period ended for most 

consumers in Maryland as of July 2006. In other areas, the period ends in 2008. 

Alternative Suppliers Licensed to Provide Service: All alternative suppliers must be licensed by 

the PSC, and must show proof of technical and managerial competence, compliance with FERC 

requirements, and compliance with state and federal environmental laws.352 A supplier must 

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 throughout 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 MD. CODE ANN., PUB. UTIL. COS., §'7-509 (2000). 

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/electric/supplierauthorization.htm. 

143 
declined 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 example, the scheduled price increase 

for customers in the BG&E distribution territory is reported to be 72 percent.355 Because of 

concerns about the size of the expected price increase, a number of alternative proposals were 

developed to break the increase into smaller steps. 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 regarding the latter provision 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)

Source: 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 utilities provide POLR service 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 settlements require the utility to be the POLR service 

provider for the entire rate cap/freeze period (which varies in length per utility) unless the 

Commission orders otherwise. POLR service rates and the respective terms were set in the 

individual utility settlements and have been in effect for the entire rate cap/freeze period. 

Recovery of Stranded Costs/Transition Costs: Distribution utilities were given an opportunity to 

recover all prudently incurred and verifiable net transition costs, subject to full mitigation.359 

Transition costs eligible for recovery include those that would be recoverable under rate-ofreturn regulation, but are not recoverable in a restructured electric market and costs that result 

 

355 Andrew Green, Legislators Not Close on Rates, BALT. SUN (Apr. 4, 2006). 

356 Patrice Hill, Maryland Utilities Designated Near Junk, WASH. TIMES (July 12, 2006), available at

http://www.washingtontimes.com/functions/print.php?StoryID=20060711-103048-5690r. 

357 MD. CODE ANN., PUB. UTIL. COS., § 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 MD. CODE ANN., PUB. UTIL. COS., § 7-513 (2000). 

144 
from the creation of customer choice.360 Stranded costs have been recovered through a 

competitive transition charge, and may be recovered 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 customers 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 switching as of December for each year from 2000 to 

2005. 

Table 8. Maryland Retail Aggregate Customer 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 assessed 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). 

145 
Mills/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 legal separation of regulated and non-regulated 

businesses or non-regulated affiliates was required by July 1, 2000.362 Distribution utilities must 

provide a code of conduct to prevent their regulated service customers 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 service suppliers. Retail sales 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 legislation, utilities operated 95.4 percent of 

generating capability in Maryland. By 2002, that figure dropped to 0.1 percent. Between 1997 

and 2002, generation capability increased from 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 collection and credit rating purposes.365 Customer lists containing 

names, addresses, and telephone numbers of customers may be sold to competitive suppliers. If 

a distribution utility intends to release such a list, it must inform its customers, and advise 

customers of their opportunity to prevent disclosure 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 the Provision and Regulation of Electric Service, Order 

No. 76110 (Apr. 25, 2000). 

146 
Standardized Labeling: 

• Content: Distribution utilities and competitive suppliers must provide customers with a 

uniform set of information on fuel mix and emissions. When actual data 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 Competition Plan and Market Response

Administrator and Start Date: Electricity Restructuring in Massachusetts was initiated and is 

administered by the Department of Telecommunications and Energy (DTE). Retail competition 

began March 1, 1998, in accordance with the restructuring legislation enacted November 25, 

1997. 

Services Open to Competition: Generation only. Metering and 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 supplier was unable to provide services, consumers 

then received a “default” service. Unlike most states that provided POLR service, Massachusetts 

named its POLR service as standard offer service, and developed another regulated price for 

those customers for which their supplier no longer provided service (default service). The 

transition ended in February 2005, at which time standard offer service was discontinued for all 

customers. Currently, customers who have not chosen a competitive supplier receive default 

service from the distribution utility that procures generation services from wholesale suppliers. 

All retail customers are eligible for default service at any time, and may remain on default 

service indefinitely. Customers can also select an alternative supplier or be part of a group of 

customers served by an aggregator. For purposes of this summary, default service will be 

referred to as a type of POLR service. 

 

Alternative Suppliers Licensed to Provide Service: All alternative 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 competitive suppliers. The roster 

 

367 Maryland Public Service Commission, In the Matter of the Commission’s Inquiry into the Provision and Regulation of Electric Service, Order 

No. 76241 (June 15, 2000). See section below on advertising restrictions for supplier requirements to disclose pricing information to customers. 

368 MD. CODE ANN., PUB. UTIL. COS., § 7-505(b) (2000). 

369 MASS. GEN. LAWS ch. 164, § 1F(1) (2001). 

370 220 MASS. CODE REGS. 11.05(2) (2001). 

147 
in 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 number of brokers. 

Pricing Trends: As Table 10 shows, prices for the residential 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 minimum 10 percent reduction of 

the entire bill for all customers receiving standard 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 reduction 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 supplier during the transition period. It was offered 

by the distribution utility, at rates which were set 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 standard offer customers were offered POLR service 

at the end of the transition. The price for POLR service is based on the price of procuring it in 

the wholesale markets through fixed price short-term (three or six months) supply contracts. 

Distribution companies must procure electricity for default generation service through 

competitive bidding, although the DTE also may authorize a competitive supplier to provide 

POLR service.375

 

POLR service prices cover the energy portion of the total bill. Distribution rates, taxes, and fees 

are additional. POLR service prices follow wholesale 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 MASS. GEN. LAWS ch. 164, § 1B(b) (2001). 

373 Id. at § 1G(c)(2). 

374 Id. at § 1B(b). 

375 Id. at § 1B(d). 

148 
January of each year for the northern portion of the Boston Edison 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 other area of the state. Much of 

this residential switching is attributable to community aggregations, principally the Cape Light 

Compact.379

Table 12. Retail Customers and Load Supplied 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. 

149 
Table 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 levels 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 below 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 Aggregate 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 in 

1996, included a nonbypassable wires 

charge for EE, RE and 

LI. LI must get at least 

.25 mills of the EE. In 

Feb. 2002, legislation 

was signed extending 

the SBC for five years, 

through Dec. 2007. 

Note: MTPC is part of the Massachusetts Technology Collaborative. 

Source: American Council for an Energy-Efficient Economy, Summary Table of Public Benefit Programs 

and Electric Utility Restructuring (December 2005), available at http://www.aceee.org/briefs/mktabl.htm. 

Separation of Generation and Transmission: The Massachusetts restructuring law required 

150 
distribution 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 legislation, utilities operated 86.6 percent of 

generating capability in Massachusetts. By 2002, that figure dropped to 9.0 percent with 91 

percent of generation belonging to independent power producers. Between 1997 and 2002, 

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 cannot release proprietary customer 

information to the affiliate without written consent 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 final rules (220 CMR 11.06) requiring electric 

retailers to provide customers with a standard disclosure label containing information on price, 

fuel mix, emissions, and labor characteristics of generating sources on a quarterly basis, 

beginning September 1, 1998. Suppliers must also issue notices in all advertisements stating that 

disclosure labels are available upon request. Supply mix information must be based on market 

settlement data or equivalent data provided by the ISO available for the most recent one-year 

period. Data on carbon dioxide, nitrogen oxides, and sulfur dioxide emissions must be presented 

in a format comparing them to the regional average. 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 sources that use replacement labor during labor 

disputes. Suppliers must submit a report to the DTE annually containing "statements of 

verification by the ISO or an independent auditor." Massachusetts is working with other New 

England states to develop a Generation Information System that will supply data for 

implementing the disclosure requirement.” 

 

380 MASS. GEN. LAWS 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 Administration, Massachusetts State Profile, Table 4, available at

http://www.eia.doe.gov/cneaf/electricity/st_profiles/massachusetts.pdf. 

384 U.S. Department of Energy, Energy Information Administration, State Electricity Profiles 2002, Massachusetts Electric Power Industry 

Generating Capability by Primary Energy Sources, 1993, 1997, and 2002. 

385 220 MASS. CODE REGS. 11.04(12). 

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

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 

151 
Renewable 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 percent increments. After 2009, the standard is scheduled to increase 

in 1 percent increments at least through 2014.387

New Jersey: Overview of Retail Competition Plan and Market Response

Administrator and Start Date: The New Jersey Electric Discount and Energy Competition Act 

provided for retail choice to begin August 1, 1999, but the New Jersey Board of Public Utilities 

(BPU) 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 their own alternative supplier or join an 

aggregation of customers to contract with an alternative supplier. Customers received a 

“shopping credit” on their electric bill if they choose an alternative supplier. 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 alternate 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 wholesale spot market prices. BGS for other customer classes is 

laddered on a three year cycle. 

Alternative Suppliers Licensed to Provide Service: New Jersey licensing standards provide that 

before receiving a license, new suppliers must show financial integrity and maintain a surety 

bond of $250,000 for an initial license. For a renewed 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, active alternative suppliers 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 residential customers in the Rockland territory. For C&I customers, there 

are 6 active suppliers in the Rockland 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 Customers 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/wwwroot/energy/EX99090676_20040624.pdf. 

389 N.J. STAT. ANN. § 48:3-51.3 (2001). 

390 New Jersey Board of Public Utilities, Interim Licensing and Registration Standards § 4.e, available at

www.state.nj.us/bpu/wwwroot/energy/licensstands.pdf. 

152 
Pricing Trends: As Table 15 shows, prices in all three sectors rose throughout the early part of 

the decade, reaching a peak in 1997. Prices for 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 except 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 additional reduction of at least 5 percent over the first 

three years of the transition period for POLR service. 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 that switched to a new supplier obtained the price 

reductions. Retail price caps expired in the summer of 2003.391 

Beginning in 2002, New Jersey instituted the Basic Generation Service (BGS) Auction “to meet 

the electric demands of customers who have not selected an alternative supplier and to make 

BGS available on a competitive basis... The Internet BGS Auction, the first of its kind in the 

nation, was a descending clock auction...”392 The bidding process for hourly priced electricity is 

separate from that for fixed price service and the latter involves three year supply contracts that 

supply one third of the anticipated load of fixed 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 average 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, PUB. UTILS. FORTNIGHTLY 

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/wwwroot/communication/04-02.pdf. 

393 N.J. STAT. ANN. § 48:3-57.9.a (2001). 

153 
customer classes are eligible for generation service overseen by the BPU.394 Non-residential 

customers who return to BGS are generally required 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 stranded 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 their supplier or distribution company. A customer may not be 

charged a fee for switching suppliers. 

Switching Activity: The Table 17 provides the switching statistics for large C&I customers in 

the major distribution territories as of December 2005. 

Table 17. Customer Switching by Distribution Utility (December 2005) 

% of Customers and (% of Load) Served by Alternative Suppliers

Combined Residential and 

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 residential and small C&I load of alternative suppliers. 

Source: New Jersey BPU and Restructuring Today (January 27, 2006), p. 3.

The number of residential customers served by alternative suppliers is and has remained very 

low with the peak of less than 6 percent in the Conectiv (Atlantic) distribution area in December 

2000.397 As of December 2005, less than 1,000 residential customers had alternative suppliers in 

the entire state.398 As with the residential sector, the number 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. STAT. ANN. § 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. 

154 
than 1 percent of small C&I customers had alternative suppliers, but they tended to be larger than 

average customers because the share of load exceeds the share of customer served by alternative 

suppliers. 

The POLR service available to large C&I customers in New Jersey is priced on an hourly basis, 

CIEP, that tracks the wholesale spot market prices. Hence, large C&I customers wishing to 

hedge price volatility must do so by selecting an alternative supplier. 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-residential customers from 

2003 to the end of 2005. 

Table 18. New Jersey Retail Aggregate Customers Migration Statistics, 2003-2005 

% of Customers and (% of Load) Served by Alternative Suppliers

Year 2003 pre August November 2003 December 2004 December 2005 

Residential and 

Small C&I (1 to 2%) 

3.3% 

(12.5%) 

0.3% 

(15.4%) 

0.0% 

(13.6%) 

Residential 3.6% 0.0% 0.0% 

Small C&I 0.8% 1.8% 0.6% 

Large C&I ~ 10% 66% 64.7% 

(83.9%) 

Note: Archives of New Jersey BPU switching statistics are not available. 

Source: Restructuring Today various issues.

Public Benefits Programs: Table 19 identifies the elements and New Jersey’s public benefit 

programs. 

Table 19. New Jersey Public Benefits Programs 

Research & 

Development

Energy 

Efficiency

Low 

Income 

Renewable 

Energy 

Total 

Million $ 89.5 10.1 30.0 129+ 

Mills/kWh 1.22 0.14 0.41 1.76 

% revenue 1.31% 0.15% 0.44% 1.89% 

Admin. NJ BPU Utility NJ BPU 

Restructuring law 

passed in Jan. 99. 

Requires funding for 

EE/RE at same level as 

existing 

DSM costs (approx. 

$235million/yr.) Full 

SBC is 3.6 mills. Half 

would pay for costs 

from prior year, half 

for programs. 25% of 

new must be RE. 

Numbers in table are 

new programs only set 

in BPU order Mar/01. 

LI separately funded at 

prior levels. 

Source: American Council for an Energy-Efficient Economy, Summary Table of Public Benefit Programs 

and Electric Utility Restructuring (December 2005), available at http://www.aceee.org/briefs/mktabl.htm. 

Separation of Generation and Transmission: The restructuring act does not mandate divestiture, 

155 
though the BPU may require a distribution utility to functionally separate its generation assets to 

the distribution utility’s holding company or a related competitive business segment if there are 

market concentration concerns.400 Electric distribution utilities had three options: divestiture, 

structural separation or functional 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 generation 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 generation 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, and parts of Virginia. 

In recent years, the PJM RTO has significantly expanded its geographic scope to the West and 

South of its original footprint. The PJM region is responsible for the operation of the region’s 

wholesale electric market. 

Generation Capability:

403 Prior to the restructuring legislation, utilities operated 81.2 percent of 

the generation capability in New Jersey. By 2002, that figure dropped to 6.8 percent after 

divestitures, transfers, and entry of new generators. Between 1997 and 2002, generation 

capability in the state increased from 16,855 MWs to 18,384 MWs, an increase of 9.1 percent . 

Nearly all of the increase was in dual fueled generators 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 distribution companies can disclose 

proprietary information, including historical payment and energy usage information without the 

written consent of the customer. Any third party who receives such information can only use it 

in order to provide continued electric service to the customer.404 

Standardized Labeling:

405 “The New Jersey Board of Public Utilities (BPU) adopted 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 uniform disclosure label containing 

information on fuel mix, carbon dioxide, sulfur dioxide, and nitrogen oxides emissions, as well 

as energy-efficiency efforts twice a year, effective 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. STAT. ANN. at § 48:3-59.11.a. 

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

402 New Jersey Board of Public Utilities, Summary Order Including Protective Order in Docket No. EM99030195, Petition of Rockland Electric 

Company for Approval of the Sale of Orange and Rockland Utilities, Inc.’s Generating Assets and Certain related Property, a Transition Power 

Sales Agreement, and a Protective Order (June 24, 1999), available at http://www.state.nj.us/bpu/wwwroot/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/electricity/st_profiles/new_jersey.pdf. 

404 N.J. STAT. ANN. § 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/disclosure.shtml?print. 

156 
entrant). 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 standards on February 1, 2005. The standard 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 sources in addition to continuation of the existing 

solar requirements. 

New York: Overview of Retail Competition Plan and Market Response 

Administrator and Start Date: Restructuring in New York State has taken place through orders 

of the New York State Public Service Commission (NYPSC), rather than through legislative 

initiatives. Because the PSC phased in restructuring through PSC-approved utility restructuring 

plans over a three year period, each utility had a different timetable to transition to retail 

competition. 

In 2004, the NYPSC identified a number of “best practices” and ordered distribution utilities to 

submit plans to foster the development of retail competition.406 Subsequently, the NYPSC 

adopted statewide guidelines, based on the program developed by Orange and Rockland 

(O&R).407 Under the guidelines, the distribution utility notifies any customers who contact the 

utility that they may try an alternative supplier for a two-month period without any penalty for 

leaving or returning to POLR service after the trial period. Alternative suppliers participating in 

the program offer a one-time 7 percent discount for 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 alternative supplier at the end of the trial period. As the table on retail 

switching indicates below, switching levels in the O&R distribution territory are higher than in 

other territories. 

On September 23, 2005, the PSC determined that the pace of development of real-time pricing 

was insufficient to moderate the effects of rising fuel costs.408 To speed the development of realtime pricing, the PSC ordered that existing real-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 toward Competition in Retail Energy Markets (Aug. 25, 2004) 

(Case No. 00-M-0504). 

407 New York Public Service Commission, Order Adopting ESCO Referral Program Guidelines and Approving an ESCO Referral Program 

Subject to Modifications (Dec. 22, 2005) (Case No. 05-M-0858, et al.); NYPSC comments at 17. 

408 New York Public Service Commission, Order Instituting Further Proceedings and Requiring the Filing of Draft Tariffs (Sept. 23, 2005) (Case 

No. 03-E-0641). 

157 
metering services must procure both meter and meter 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 obtain electric power from an alternative supplier. 

Customers not served by an alternative supplier receive POLR service from the distribution 

utility. POLR service for large 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 alternative suppliers to choose from. 

Pricing Trends: As shown in Table 20, prices generally 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

1995 1996 1997 1998 1999 2000 2001 2002

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 utility’s restructuring plan 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, large industrial customers who chose 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 rate decrease, which 

remained fixed for five years. All other customers received a 10 percent rate decrease, 

phased in over five years. 

• Orange and Rockland residential customers received a 4 percent decrease in rates during 

1995 and 1996, while industrial and commercial customers 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 and small commercial customers received a 7.5 

percent rate decrease. Other commercial and most industrial customers received an 8 

percent decrease. Large industrial customers received an 11.2 percent decrease. All 

decreases are being phased in over 5 years. 

• New York State Electric and Gas industrial and large commercial customers (greater than 

500 kW capacity) received a 5 percent per year rate 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 decrease received financial incentives for load 

growth to encourage business expansion. 

• National Grid (Niagara Mohawk) customers received an overall rate decrease of an 

average of 4.3 percent . Residential and commercial customers 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 distribution 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 provide regulated POLR service for 

customers who do not choose a competitive supplier or who return to POLR service.410

Recovery of Stranded Costs/Transition Costs: Distribution utilities recover stranded costs (net 

of proceeds from selling generation assets) through a non-bypassable distribution charge. 

Distribution utilities were required to use creative means to reduce 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 Programs,” places limits on the ability of 

alternative suppliers to levy charges against departing customers.413

Switching Activity: The switching statistics for December 2005 in each distribution territory 

appear in the Table 21. 

 

410 New York Public Service Commission, Opinion and Order Regarding Competitive 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 Markets: Progress to Date and Future Opportunities

(Mar. 2, 2006) (Electric and Natural Gas Retail Markets sections I to III). 

413 NYPSC comments at 18. 

159 
Table 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 distribution territories in the state from 2000 to 

2005 appear in Table 22. Load served by alternative suppliers has increased each year with the 

largest increases in 2004 and 2005. The percentage of customers served by alternative suppliers 

increased from 1999 to 2002, declined in 2003, and resumed growing in 2004 and 2005. 

Table 22. New York Aggregate Customer 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 programs are charted in Table 23 below. 

160 
Table 23. New York Public Benefits Programs 

Research & 

Development 

Energy 

Efficiency 

Low 

Income 

Renewable 

Energy 

Total 

Million $ 26.0 87.0 22.0 150.0 

Mills/kWh 0.26 0.83 0.21 1.42 

% revenue 0.20% 0.69% 0.17% 1.18%

Admin. NYSERDA NYSERDA NYSERDA 

In May95, the PSC 

issued Order 96-12 

requiring all IOUs 

to file restructuring 

plans. A July98 

Order set $78 

million/year for an 

SBC, administered 

by NYSERDA. In 

Jan01 the PSC 

raised the SBC to 

$150 million/yr 

and extended it for 

5 years. (Table 

shows allocation 

minus 10% held 

open.) R&D incl. 

$14 million/yr for 

RE. Table does 

not include $100 

million/yr EE by 

Power Authorities 

Notes: The administrator is the New York State Energy Research and Development Authority, supervised by the PSC. 

On December 14, 2005, the PSC ordered that the System Benefit Charge be increased to $175 M annually and that the 

program be extended for five years. NYPSC, System Benefits Charge (Mar. 2, 2006), available at

http://www.dps.state.ny.us/SBCIII_Amended_Plan_3-2-06.pdf. 

Source: American Council for an Energy-Efficient Economy, Summary Table of Public Benefit Programs and Electric 

Utility Restructuring (December 2005) available at http://www.aceee.org/briefs/mktabl.htm. 

Separation of Generation and Transmission: The PSC encouraged total divestiture of generation, 

and it instructed distribution utilities to separate generation 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 belong to the New York ISO, formed in 

1998. The New York ISO exercises operational control 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 regulations, utilities in New York operated 

84.3 percent of the generation capability in the 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 independent 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/customer_relations/faqs/index.jsp. 

417 U.S. Department of Energy, Energy Information Administration, New York State Profile, Table 4, available at

http://www.eia.doe.gov/cneaf/electricity/st_profiles/new_york.pdf. 

161 
generation 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 designees. All historical data that a competitive 

supplier receives from the distribution company must be kept confidential, unless authorized for 

release by the customer. A distribution company cannot disclose customer information to 

competitive suppliers if the customer has notified the distribution company in writing that he 

does not authorize release. Thereafter, customer information can only be released to a 

competitive supplier with the customer’s written authorization.418

Standardized Labeling:

419 On December 15, 1998, the New York Public Service Commission 

(PSC) issued an order requiring electric suppliers to use a standardized label to provide 

information to customers regarding the environmental impacts of electricity products semiannually. Suppliers must disclose fuel mix compared to a statewide average 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 provided 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 policy calls for an increase in renewable energy 

used in the state from the then current level of 19 percent (mostly hydro) to 25 percent by 2013. 

Pennsylvania: Overview of Retail Competition Plan and Market Response 

Administrator and Start Date: The Electricity Generation Customer Choice and Competition Act 

was enacted on December 3, 1996. The Pennsylvania Electric Choice Pilot Program began in 

the fall of 1997, with 230,000 customers participating. These customers were able to begin 

shopping for their electric generation supplier beginning September 1, 1998. By January 2, 

2000, electric choice was fully implemented in nearly all of Pennsylvania.420 Retail competition 

is administered by the Pennsylvania Public Utility Commission (PUC). 

Services Open to Competition: Generation. Generally the distribution company provides 

metering and billing services, although there are some areas in Pennsylvania in which the 

 

418 New York Public Service Commission , Uniform 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 business 

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/disclosure.shtml?print. 

420 Pennsylvania Public Utility Commission, Pennsylvania Electric Choice, Q&A, available at http://www.puc.state.pa.us/utilitychoice. 

162 
alternative supplier may provide these services.421 Pennsylvania’s efforts to allow licensed 

generation suppliers to provide metering and billing 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 alternative supplier. Consumers not served by 

an alternative supplier receive POLR service arranged by the local distribution utility. 

Alternative Suppliers Licensed to Provide Service: Competitive suppliers must be licensed by 

the PUC to provide service to Pennsylvania customers.423 As of February 2006, the Duquesne 

Light territory had 4 alternative suppliers serving residential 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 two territories, residential customers only have 

available premium priced green generation products 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 industrial 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

1995 1996 1997 1998 1999 2000 2001 2000

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 service 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 not require rate reductions, although several 

distribution utilities agreed to reduce rates in the first year 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 Pennsylvania approving an extension of a suspension of 

work of the Electronic Data Exchange Working Group as it relates to the implementation of competitive metering, Docket No. P-00021957 (Feb. 

5, 2004). 

423 66 PA. CONS. STAT. § 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). 

163 
Overall rate reductions, Table 25 for the first year ranged from 2.5 percent to 8 percent for the 

major utilities operating in Pennsylvania:426

Table 25. First Year Rate 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 generation 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 greater 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 those who are unable to obtain service from a 

competitive supplier, or for customers whose suppliers 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 utility. During the summer, market prices 

rose, while POLR rates remained stable, below market rates. This caused customers to be either 

returned to POLR service by their suppliers or to return themselves to POLR service. Many 

distribution utilities require customers to remain with the distribution 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 portion of POLR service for customers who do not affirmatively 

choose an alternative supplier. This option is known as Competitive Default Service (CDS). 

The PUC approved additional consumer protections for the initial phase-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 awarded a contract for 20 percent of its POLR service customers 

to The New Power Company. Additionally, 50,000 PECO customers were assigned to Green 

Mountain Energy, Inc. PECO customers assigned to the CDS provider received a two-percent 

discount on the shopping credit (the capped generation service rate). 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 PA. CONS. STAT. § 2807.E (2001). 

428 Id.

429 Id.

164 
were insufficient to cover procurement costs, the CDS suppliers withdrew from this service. No 

alternative suppliers have been willing to supply 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 distribution areas in addition to Duquesne.430

Recovery of Stranded Costs/Transition Costs: Stranded costs have been administratively 

determined 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 for up to nine years, unless the PUC orders an 

alternative payment period.431 Table 26 shows each utility’s allowable 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 switching activities are largely limited to the 

Duquesne Light distribution territory 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 PA. CONS. STAT. § 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/utilitychoice/faq.aspx?ut=ec#4. 

165 
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 

Duquesne Light 19.7% 

(18.5%) 

20.3% 

(52.3%) 

43.4% 

(83.6%) 

19.8% 

(48.0%) 

MetEd/Penelec 0.0% 

(0.0%) 

0.0% 

(0.0%) 

(0.1%) 

(5.6%) 

0.0% 

(1.6%) 

PECO 0.9% 

(1.0%) 

23.8% 

(13.2%) 

2.0% 

(1.2%) 

3.2% 

(4.9%) 

PennPower 0.0% 

(0.0%) 

0.0 

(0.0%) 

0.0 

(0.0%) 

0.0 

(0.0%) 

PPL 0.0 

(0.0%) 

0.2 

(0.7%) 

0.3 

(0.3%) 

0.1 

(0.3%) 

UGI 0.0 

(0.0%) 

0.0 

(0.0%) 

0.0 

(0.0%) 

0.0 

(0.0%) 

Source: Pennsylvania Office of the Consumer Advocate 

The first quarter aggregate switching 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 increase in 2004. Alternative suppliers served a 

declining number of customers from 2001 to the present (with the exception of 2004). 

Table 28. Pennsylvania Retail Aggregate Customer Migration Statistics, 1999-2006 

% of Customers and (% of Load) Served by Alternative Suppliers

Year 2000 2001 2002 2003 2004 Oct. 2005 2006 

Resident. ~7.8% 

(~7.6%) 

~9.2% 

(~8.6%) 

~10.3% 

(~9.1%) 

~4.9% 

(~4.7%) 

~8.2% 

(~7.9%) 

2.9% 

(2.7%) 

~2.3% 

(~2.1%) 

C&I ~17.6% 

(~41.9% 

~16.9% 

(~32.6%) 

~3.7% 

(~7.8%) 

~4.8% 

(~12.4%) 

~13.5% 

(~13.9%) 

9.6% 

(15.5%) 

~8.9% 

(~14.5%) 

Note: Keystone Connection (Autumn 2005) provides the percentage of customers and load served by alternative suppliers as well as the total 

number of customers and load for residential customers and C&I customers separately for October 2005. Calculations for the other years take the 

number of shoppers or shoppers’ load reported in January of that year and divides them by the related 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 changed from year to 

year. 

Source: Pennsylvania Office of the Consumer Advocate 

Public Benefits Programs: Table 29 identifies the Pennsylvania public benefit programs. 

Table 29. Pennsylvania Public Benefits Programs 

Research & 

Development 

Energy 

Efficiency 

Low 

Income 

Renewable 

Energy 

Total 

Million $ 5.0 85.0 6.0 96.0 

Mills/kWh 0.04 0.68 0.05 0.77 

% revenue 0.05% 0.85% 0.06% 0.96%

In Dec., 1995, a 

restructuring 

law was signed 

with retail 

access to be 

phased-in over Admin. SEF Utility SEF 

166 
2 yrs starting in 

Jan99. The 

restructuring 

law resulted in 

PUC-approved 

restructuring 

settlement 

agreements for 

each electric 

company. Each 

settlement 

agreement 

created a 

system benefits 

fund for LI 

programs and a 

Sustainable 

Energy Fund 

(except for 

Duquesne). 

Note: Administrators are Sustainable Energy 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 at 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 required to divest facilities 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 directs the PUC to encourage interstate 

power pools to enhance competition and to complement restructuring. Much of Pennsylvania 

belongs to the PJM RTO. In order to meet electric load in the PJM region, PJM coordinates with 

member companies and uses bilateral contracts and the spot market to secure power.434 In 

March 2001, Allegheny Power and PJM filed with FERC a request to expand PJM by forming 

PJM-West.435

Generation Capability:

436 Prior to the restructuring legislation, 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 transfers. The difference reflected 

voluntary divestitures to independent generators and transfers of generation to affiliates as well 

as expansion and entry of independent power 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 PA. CONS. STAT. § 2804.5 (2001). 

434 Pennsylvania Public Utility Commission, Bureau of Conservation, Economics, and Energy Planning, Electric Power Outlook for 

Pennsylvania:1999-2004 (July 2000). 

435 Press Release, PJM Interconnection, LLC, Allegheny Power and PJM File with FERC to Create PJM West (Mar. 15, 2001), available at

www.pjm.com/contributions/news-releases/2001/20010315-ap-pjm-file-with-ferc.pdf. 

436 U.S. Department of Energy, Energy Information Administration, Pennsylvania State Profile, Table 4, available at

http://www.eia.doe.gov/cneaf/electricity/st_profiles/pennsylvania.pdf. 

167 
Use of Customer Information: A customer can restrict the disclosure of his telephone number 

and his historical billing data. A distribution utility or supplier who intends to supply a thirdparty with this information must provide a customer with the means of restricting the release of 

this information, either through a signed form, orally, or electronically.437 Customer information 

cannot be given preferentially by a distribution 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 competitive suppliers as a result of the customer’s 

enrollment into the electric choice program. The customer had the option 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 forms to customers to give them the opportunity to 

restrict the release of load data, or of all information (name, address, rate class, and account 

number). Telephone numbers would not be released to suppliers under any circumstances.439

Standardized Labeling:

440 The Pennsylvania Public Utility Commission (PUC) issued final rules 

in April 1998 requiring retail electricity suppliers to "respond to reasonable requests made by 

consumers for information concerning generation energy sources." Suppliers must respond to 

such requests "by informing consumers that this information is included in the annual licensing 

report and that this report exists at the Commission." 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 information in an annual report to the Commission. 

Suppliers that market electricity as "having special characteristics" such as being 

environmentally friendly, must have information 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 methane) and other (waste coal, distributed 

generation, demand-side management, large-scale hydro, municipal waste, wood processing 

waste, and integrated combined coal gasification). Separate standards are set for the two groups– 

-8 percent and 10 percent respectively. 

Texas: Overview of Retail Competition Plan and Market Response 

Administrator and Start Date: The Texas restructuring bill was signed June 18, 1999. The 

Public Utility Commission of Texas (PUC) administers the transition to retail competition, which 

began with a pilot program on June 1, 2001. Retail competition for all customer classes within 

ERCOT began January 1, 2002.441 Competition is not open as yet 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/disclosure.shtml?print. 

441 TEX. UTIL. CODE ANN. § 39.102 (2001). 

168 
because 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 sales). 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 “price to beat” default service). 

Alternative Suppliers Licensed to Provide Service: In order to be licensed to provide service in 

Texas, competitive suppliers must meet financial creditworthiness and technical standards.443 

There are numerous suppliers marketing to all classes of customers in Texas that are open for 

retail customer choice. In addition to the Texas POLR default service offer, there are several 

alternative suppliers actively serving retail residential 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 alternative “green” offers for residential customers 

in the major distribution territories 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 increased 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 rates 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/reports/scope/2005/2005scope_elec.pdf. 

443 TEX. UTIL. CODE ANN. § 39.352-55 (2001). 

444 Available at http://www.puc.state.tx.us/electric/reports/RptCard/rptcrd/aug05rptcrd.pdf. 

169 
September 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 costs. Because Texas primarily relies on natural gas 

fueled generation, the increases in natural gas prices have resulted in substantial increases in the 

“price to beat.” POLR (default) service is available from the distribution utility’s competitive 

retail affiliate until January 1, 2007. Prior to January 1, 2005, affiliates of distribution utilities 

could offer services other than POLR (default) service only if at least 40 percent of residential or 

small commercial customers chose a competitive supplier not affiliated with the local 

distribution utility. Since January 1, 2005, affiliates of distribution utilities have been allowed to 

offer any service they wish in addition to POLR (default) service. 

The Texas PUC provides information on the price to beat and on alternative supplier’s prices in 

each distribution territory. The information includes a comparison of each alternative supplier’s 

price to the POLR (default) price for different levels of consumption. Table 31 shows the POLR 

(default) price and the range of offers from alternative suppliers 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 lowest offer of alternative suppliers. The figure below, from the 

PUC report to the 79th 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/reports/scope/2005/2005scope_elec.pdf. 

170 
POLR (Default) Service Provider: Until December 31, 2001, POLR (default) service was 

provided by the distribution utility. 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 electric providers” (REPs). Prices for POLR 

(default) service were fixed at the “price to beat” plus fuel adjustments until January 1, 2007. 

Affiliated retail electric providers were allowed to offer only POLR (default) service (at the 

“price to beat”) unless alternative suppliers attained a market share of 40 percent of residential 

or small commercial customers. In 2004, all but one of the affiliated retail electric providers 

within ERCOT (the separate transmission interconnection system in Texas) were granted 

permission to offer additional products.448 Starting in 2005, all affiliated 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 prior 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. 

171 
CenterPoint 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 Competitive Retail Markets in Texas (March 3, 2006), available at

http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/32198_7_504891.PDF 

POLR Service Provider for other than Default Service: POLR service customers have been 

divided into three classes: residential, small non-residential, and large non-residential. POLR 

service providers supply customers in any or all of the three classes 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 are obtained, are then allocated 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 service supplier in its own 

service territory during the period while the price to beat is in effect.449

The Texas PUC is currently reviewing its POLR service rules.450

Recovery of Stranded Costs/Transition Costs: Distribution utilities can recover all of their net 

non-mitigated stranded costs through a transition charge. The PUC determines the amount of 

 

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. 

172 
stranded costs eligible for recovery, which includes 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 the 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 the 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 distribution 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 load, as shown in Table 33. 

Table 33. Texas Retail Aggregate Customer 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, September 2004, and June 2005. The Residential and Small C&I figures 

are all from January except the 2005 figure which is from September.

Source: Texas Public Utility Commission

 

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

http://www.powertochoose.org/yourrights/q_changing.asp. 

173 
Public Benefits Programs: The Texas public benefit programs 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, utilities were required to 

separate their business activities into three units: a wholesale electric power generation 

company, a retail electricity company (REP), and a transmission and distribution company. This 

separation could take place either through the sale of assets to a third party, or by the creation of 

separate non-affiliated companies or separate affiliated companies owned by a common holding 

company.453 After the beginning of retail competition, a distribution utility may not sell 

electricity or participate in the market for electricity except to procure electricity to serve its own 

needs.454 Wholesale electric power generation companies that are affiliated with a distribution 

utility are required to auction off 15 percent 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 commercial customers in the territory of the 

distribution utility, except as the POLR (default) service provider, until 40 percent of the 

residential or small business load in the territory is buying electricity from competitive 

 

452 Although the System Benefit Funds are being collected, the Legislature did not appropriate any fund for a low-income discount or for 

customer education in the 2005 session. Some REPs are continuing to offer low-income discounts and other benefits to these customers on a 

voluntary basis. Funding will be reconsidered in the 2007 legislative session; Reliant comments. 

453 Tex. Util. Code Ann. at § 39.051. 

454 Id. at § 39.105. 

455 Id. at § 39.153. 

456 Id. at § 39.154. 

174 
suppliers.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 (approximately 85 percent) is in the ERCOT 

interconnection.458 ERCOT began operations as an independent 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 legislation, utilities operated 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 state increased from 73,454 MWs to 94,488 MWs, 

an increase of 28.6 percent . Much of the growth in generation was fueled by natural gas. The 

share of generation capability fueled by natural gas increased from 21.4 percent 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 include 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 Public 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 environmental impacts to their retail and small 

residential customers, in accordance with the state's restructuring law. The label must also be 

included in promotional material soliciting new customers. Fuel mix data must be compared to 

the state average, with energy generated from renewable resources to be listed under a single 

category. Emissions of carbon dioxide, sulfur dioxide, 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, the Commission is developing 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 project 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 mix 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 with the Eastern or Western Interconnects. 

459 Electric Reliability Council of Texas, The Market Guide: A Guide to How the Electric Reliability Council of Texas (ERCOT) Facilitates the 

Competitive Power Market (Feb. 22, 2001). 

460 U.S. Department of Energy, Energy Information 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/publications/consumer_brochure.pdf. 

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

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 

175 
with renewable fuels if it can be shown that the natural gas was produced in Texas.”463

Renewable Energy Portfolio Standard: Texas adopted a renewable energy portfolio standard on 

February 24, 2004. The standard establishes yearly 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 process that will allow the PUC to 

prioritize transmission development to facilitate delivery of energy from renewable sources.464

The original electric restructuring bill included many environmental protections, 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 renewable resources. The bill requires 50 percent 

reductions in nitrous oxide emissions and 25 percent 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 upgrade older generation facilities to 

meet emissions standards may recover the costs from retrofitting as stranded costs.465 The PUC 

has adopted a renewable energy credit trading program to encourage cost-effective new 

renewable generation facilities. 

 

463 The consumer brochure on electricity offer labeling is available at http://www.powertochoose.org/publications/efl_brochure.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. 

176 
APPENDIX E 

ANALYSIS OF CONTRACT LENGTH AND PRICE TERMS 

COMPARISON OF NYISO, MISO AND SERC MARKETS USING 2005 EQR DATA 

This analysis compares the short-term versus long-term sales volumes and prices in three regions 

using reported sales information from Electric 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 repurchased at a later date, effectively undoing the prior sale. 

Depending on changes in market prices in the interim, the repurchase may produce profits or 

limit losses for the seller. 

EQR limitations are best explained with the help of the diagram below, which 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. Sales by non-jurisdictional entities may appear in 

some EIA reports. Financial transactions done on NYMEX are reportable to CFTC, but other 

financial transactions do not need to be reported. Sales reportable to EQR could have been 

transacted bilaterally, on RTO/ISO’s, through ICE or through voice brokers, and credit cleared 

through ICE-LCH or NYMEX-ClearPort. Other transaction venues may develop. There is no 

complete aggregated market picture. Analysts can only try to make inferences 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 analysis is informative. The Task Force selected NYISO, 

177 
MISO and SERC as representative markets for the following reasons. NYISO provides a 

consistent data set for sales in its established, single-state organized market. MISO provides a 

consistent data set for sales in its new, multi-state organized part of the market (sales in Q1/05 

occurred before the organized market started). SERC is an example of a purely bilateral 

wholesale market with relatively few participants (which increases the likelihood of consistent 

dataset). 

The three graphs below show transaction volumes 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

Source: FERC Electric Quarterly Reports

178 
SERC

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 defined as transactions under contracts of one year or less or sales 

into organized markets, such transactions include bilateral sales as well as sales to NYISO and 

MISO. Long-term transactions occur under contracts lasting more than a year. For example, a 

contract initiated four years ago and still delivering power would be grouped under the 3 to 5 

year vintage. A contract initiated 11 years ago 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 years (0 percent in NYISO, 2 percent in 

MISO, 16 percent in SERC); 

 quarterly variation in quantities 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 longer term needs between parties 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 financial transactions would naturally lead to a high 

percentage of short term transactions using EQR numbers in organized markets such as NYISO 

and MISO. The trend towards capacity or reliability 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. 

179 
The 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 competitive 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

180 
This 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 changes 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. 

181 
APPENDIX 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 intending to explain the basic engineering, economic 

and regulatory theories that support restructuring ideas. The intended audience of these studies 

has been various – from state regulators and legislators, 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 reader 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 references – but their theoretical 

arguments remain applicable to current debates. 

NOTE: Inclusion of articles does not indicate the 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/APPAWhitePaperRestructuringatCrossroads1204.pdf 

Matthew Brown and Richard P. Sedano, A Comprehensive View U.S. Electric 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, Energy 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 Exchanges 2005 Annual Conference in Orlando FL), 

available at http://ksghome.harvard.edu/~whogan/hogan_apex_110105.pdf 

182 
Paul L. Joskow, Markets for Power in the United States: An Interim Assessment, ENERGY J. 

(forthcoming 2006), available at http://stoft.com/metaPage/lib/Joskow-2006-power-marketassessment.pdf 

Paul L. Joskow, Restructuring, Competition, and Regulatory Reform in the U.S. Electricity 

Sector, J. ECON. PERSPECTIVES 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.cmu.edu/ceic/publications.htm 

Books

RICHARD F. HIRSH, POWER LOSS: THE ORIGINS OF DEREGULATION AND RESTRUCTURING IN THE 

AMERICAN ELECTRIC UTILITY SYSTEM (MIT Press 1999). 

SALLY HUNT, MAKING COMPETITION WORK IN ELECTRICITY (Wiley Publishing 2002). 

STEVEN STOFT, POWER SYSTEM ECONOMICS: DESIGNING MARKETS FOR ELECTRICITY (IEEE 

Press, Wiley-Interscience 2002). 

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APPENDIX G 

CREDIT RATINGS* OF MAJOR AMERICAN 

ELECTRIC GENERATION COMPANIES** AS OF JULY 24, 2006 

Name Credit Rating 

Sales 

($bil) 

Profits 

($bil) 

Assets 

($bil) 

Market Value 

($bil) 

AES Corp. B+ 10.64 0.56 29.65 11.33 

Allegheny Energy Inc BB+ 3.04 0.07 8.56 5.82 

Alliant Energy Corp. no rating 3.28 -0.01 7.78 3.87 

Ameren Corp. A- 6.78 0.63 18.16 10.33 

American Electric Power Co., Inc. BBB 11.9 0.81 36.17 14.36 

Atmos Energy Corp. BBB 5.89 0.15 6.62 2.13 

CALPINE Corp. D 9.23 -0.24 27.09 0.13 

CenterPoint Energy, Inc. BBB- 9.72 0.22 17.12 4.02 

Cinergy Corp. BBB 5.41 0.49 17.2 8.75 

CMS Energy Corp. B+ 6.41 -0.08 16.02 3.1 

Consolidated Edison A 11.69 0.73 24.85 11.26 

Constellation Energy BBB+ 17.13 0.63 21.47 10.48 

Dominion Resources Inc BBB+ 18.04 1.04 52.58 25.59 

DTE Energy Co. BBB 9.02 0.54 23.36 7.7 

Duke Energy Corp. BBB 16.75 1.83 54.59 26.3 

Edison International BB 11.2 1.24 35.51 14.45 

Energy East Corp. BBB 5.3 0.26 11.45 3.7 

Entergy-Koch BBB- 10.11 0.92 29.97 15.04 

Exelon Corp. BBB+ 15.36 0.97 42.39 38.06 

FirstEnergy Corp. BBB- 11.99 0.89 31.84 16.85 

FPL Group, Inc. A 11.85 0.89 33 16.56 

KeySpan Corp. A- 7.66 0.4 13.81 7.11 

Kinder Morgan, Inc. BBB 1.59 0.55 17.38 11.34 

MDU Resources Group, Inc. A- 3.46 0.28 4.42 4.23 

Mirant Group B+ 3.7 NA 12.88 7.38 

NiSource Inc. BBB 7.89 0.31 17.96 5.6 

Northeast Utilities BBB 7.4 -0.25 12.57 3 

NRG Energy Inc B 2.36 0.11 7.8 3.76 

NStar A- 3.24 0.2 7.65 3.14 

OGE Energy A 6.98 0.17 5.72 2.6 

Pepco Holdings, Inc. BBB 7.73 0.32 14.22 4.5 

Pacific Gas & Electric BBB 11.7 0.92 34.07 13.02 

Pinnacle West Capital Corp. BBB- 2.99 0.18 12.07 4.05 

PPL Corp. BBB 6.22 0.69 18.04 12.09 

Progress Energy Inc BBB- 10.11 0.7 27.07 11.14 

Public Service Enterprise Group, Inc. BBB 12.43 0.68 29.82 17.43 

184 
Name 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