i

United States of America 

Electric Energy Market Competition Task Force 

and the 

Federal Energy Regulatory Commission 

Notice Requesting Comments on Draft Report to Congress on Competition in the Wholesale and Retail 

Markets for Electric Energy

Docket No. AD05-17-000 

________________________________________________________________________ 

AGENCY: Federal Energy Regulatory Commission 

ACTION: Notice 

SUMMARY: Section 1815 of the Energy Policy Act of 2005 requires the Electric 

Energy Market Competition Task Force to conduct a study and analysis of competition 

within the wholesale and retail market for electric energy in the United States and to 

submit a report to Congress within one year. Section 1815 further requires that the Task 

Force publish its draft report in the Federal Register for public comment 60 days prior to 

submitting its final report to the Congress. The Federal Energy Regulatory Commission, 

as an agency with a representative on the Task Force, is publishing this notice providing 

the draft report and seeking public comment on behalf of the Task Force. 

DATES: Comments are due on or before 5:00 p.m. Eastern Time June 26, 2006. 
ii

ADDRESSES: Comments may be electronically filed by any interested person via the eFiling link on the Federal Energy Regulatory Commission’s Website at 

http://www.ferc.gov for Docket No. AD05-17-000. Persons filing electronically do not 

need to make a paper filing. Persons that are not able to file electronically must send an 

original of their comments to: Federal Energy Regulatory Commission, Office of the 

Secretary, 888 First Street NE., Washington, DC 20426. 

FOR FURTHER INFORMATION CONTACT: 

Moon Paul 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

202-502-6136 

SUPPLEMENTARY INFORMATION: 

Section 1815 of the Energy Policy Act of 2005 established an interagency task force to 

conduct a study and analysis of competition within the wholesale markets and retail 

markets for electric energy in the United States. The task force has 5 members: (1) an 

employee of the Department of Justice, appointed by the Attorney General of the United 

States; (2) an employee of the Federal Energy Regulatory Commission, appointed by the 
iii

Chairperson of that Commission; (3) an employee of the Federal Trade Commission, 

appointed by the Chairperson of that Commission; (4) an employee of the Department of 

Energy, appointed by the Secretary of Energy; and (5) an employee of the Rural 

Utilities Service, appointed by the Secretary of Agriculture. 

The Electric Energy Market Competition Task Force consulted with and solicited 

comments from the States, representatives of the electric power industry and the public, 

in accordance with a notice requesting public comment published in the Federal Register 

on October 19, 2005 at 70 FR 60819. A full listing of the persons or entities that have 

met with the task force or submitted comments in response to the notice will be listed as 

an attachment to the final report. 

The draft report of the Electric Energy Market Competition Task Force is attached to this 

notice as Appendix A. The appendices to the draft report will not be published in the 

Federal Register, but will be available online, as follows. The draft report is also 

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

Department of Justice: www.usdoj.gov/atr 

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

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

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

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

Members of the public are invited to comment on the draft report and encouraged to file 

comments as soon as is practicable in order to maximize the time available to the task 

force to consider these comments. Comments will be received by the Federal Energy 

Regulatory Commission and available for public review. A final report will be delivered 

to Congress on or before August 8, 2006 in accordance with the statutory deadline. 

How To File Comments: 

Any interested person may submit a written comment and it will be 

made part of the public record of the Task Force maintained with the Federal Energy 

Regulatory Commission. Comments may be filed electronically via the e-Filing link on 

the Federal Energy Regulatory Commission's Web site at http://www.ferc.gov for Docket 

No. AD05-17-000. 

Most standard word processing formats are accepted, and the e-Filing link provides 

instructions for how to Login and complete an electronic filing. First-time users will have 

to establish a user name and password. User assistance for electronic filing is available at 

202-208-0258 or by e-mail to efiling at ferc.gov. Comments should not be submitted to 

the e-mail address. Persons filing comments electronically do not need to make a paper 

filing. Persons that are not able to file comments electronically must send an original of 
v

their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 

First Street NE, Washington, DC 20426. 

This filing is accessible on-line at http://www.ferc.gov, using the “eLibrary” link and is 

available for review in the Commission's Public Reference Room in Washington, DC. 

For assistance with any FERC Online service, please e-mail 

FERCOnlineSupport@ferc.gov, or call (866) 208-3676 (toll free). For TTY, call (202) 

502-8659.

Dated:_______________________ _______________________________ 

Magalie R. Salas 

Secretary 

Federal Energy Regulatory Commission 

Appendix A – Draft report of the Electric Energy Market Competition Task Force 
i

REPORT TO CONGRESS ON COMPETITION IN THE WHOLESALE 

AND RETAIL MARKETS FOR ELECTRIC ENERGY 

DRAFT 

June 5, 2006 

By The Electric Energy Market Competition Task Force 
ii

TABLE OF CONTENTS 

Table of Contents...................................................................................................................... ii 

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

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

Developments.......................................................................................................... 7 

Chapter 2. Context For The Task Force’s Study of Competition in Wholesale and Retail 

Electric Power Markets ........................................................................................... 35 

Chapter 3. Competition in Wholesale Electric Power Markets ............................................... 44 

Chapter 4. Competition in Retail Electric Power Markets ....................................................... 71 

Appendix A: Index of Comments Received ........................................................................... 95 

Appendix B: Task Force Meetings With Outside Parties ....................................................... 99 

Appendix C: Annotated Bibliography of Cost Benefit Studies ..............................................100 

Appendix D: State Retail Competition Profiles .....................................................................118 

Appendix E: Analysis of Contract Length and Price Terms....................................................158 

Appendix F: Bibliography of Primary Information on Electric Competition .........................163 

Appendix G: Credit Ratings of Major American Electric Generation Companies...............165 

Table 1-1. U.S. Retail Electric Providers 2004 ........................................................................ 11 

Table 1-2. U.S. Retail Electric Sales 2004 ............................................................................... 11 

Table 1-3. U.S. Retail Electric Providers 2004, Revenues from Sales to Ultimate Consumers 12 

Table 1-4. U.S. Electricity Generation 2004 ............................................................................ 12 

Table 1-5. U.S. U.S. Electric Generation Capacity 2004 ........................................................ 13 

Table 1-6. Power Generation Asset Divestitures by Investor-Owned Electric Util. as of 

April 2000 ............................................................................................................... 34 

Table 4-1 Distribution Utility Ownership of Generation Assets in the State in Which It 

 Operates....................................................................................... 79

Figure 1-1. U.S. Electric Power Industry, Average Retail Price by State 2004 ...................... 22 

Figure 1-2. Status of State Electric Industry Restructuring Activity, 2003 ............................. 23 

Figure 1-3. RTO Configurations in 2004 ................................................................................. 25 

Figure 1-4. Transmission Expenditures of EEI Members ....................................................... 28 

Figure 1-5. U.S. Electric Generating Capacity Additions: Non-Utility Growth Overtakes 

Utility 2000-2004 .................................................................................................. 29 

Figure 1-6. National Average Retail Prices of Electricity for Residential Customers ............ 30 

Figure 1-7. Gas Has Recently Been Dominant Fuel ................................................................ 31 

Figure 1-8. Net Generation Shares by Energy Source ............................................................. 32 

Figure 1-9. Electric Power Industry Fuel Costs, Jan. 2005-December 2005 ........................... 33 

Figure 3-1. U.S. Electric Generating Capacity Additions (19602005) .................................... 50 

Figure 3-2. Estimate of Annul NY Capacity Values – All Auctions ....................................... 54 
iii

Figure 4-1. U.S. Electric Power Industry, Average Retail Price of Electricity 

 by State, 1995............................................................................... 73 

Figure 4-2. U.S. Map Depicting States with Retail Competition, 2003 .................................. 77 

Figure 4-3. Average Revenues per kWh for Retail Customers 1990-2005 Profiled States vs. 

National Avg. ........................................................................................................ 82 

Appendix D Tables 1-34....................................................................................................120-155 

 
1

EXECUTIVE SUMMARY 

Congressional Request

Section 1815 of the Energy Policy Act of 2005 (the Act) requires the Electric Energy Market 

Competition Task Force (Task Force) to conduct a study of competition in wholesale and retail 

markets for electric energy in the United States.1 Section 1815(b)(2)(B) of the Act requires the 

Task Force to publish a draft final report for public comment 60 days prior to submitting the 

final version to Congress. This Federal Register notice fulfills this statutory obligation. The 

Task Force seeks comment on the preliminary observations contained in this draft report. 

Task Force Activities

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

 Section 1815(c) of the Energy Policy Act of 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 to comply with this 

statutory obligation. The Task Force received over 80 comments that expressed a variety 

of opinions and analyses. The list of parties who submitted comments is attached as 

Appendix A. 

 The Task Force met and discussed competition-related issues with a variety of 

representatives of the electric power industry in October/November 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 researched and analyzed the relevant features of seven states that have 

implemented retail competition. The states include: Illinois, Maryland, Massachusetts, 

New Jersey, New York, Pennsylvania, and Texas. These seven states represent the 

various approaches that states have used to introduce retail competition where retail 

competition programs are active. Appendix D contains these individual state profiles. 

 1

 The Task Force consists of 5 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; (5) one employee of the Rural Utilities Service (RUS), appointed by the Secretary of Agriculture. 
2

 The Task Force reviewed the information gleaned from comments, interviews, and 

further research. They then produced draft documentation of the resulting observations 

and findings. These drafts were circulated among task force members for comments and 

revised. No outside contractors were hired to conduct this work. 

Federal and several state policymakers generally introduced competition in the electric power 

industry to overcome the perceived shortcomings of traditional cost-based regulation. In 

competitive markets, prices are expected to guide consumption and investment decisions to bring 

about an efficient allocation of resources. 

Observations on Competition in Wholesale Electric Power Markets

For almost 30 years, Congress has taken steps to encourage competition in wholesale electric 

power markets. The Public Utility Regulatory Policies Act of 1978, the Energy Policy Act of 

1992, and the Energy Policy Act of 2005 all sought to promote competition by lowering entry 

barriers, increasing transmission access, or both. Federal electricity policies seek to strengthen 

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

In responding to its statutory charge, the Task Force has sought to answer 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 is generally associated with competitive markets? 

To answer this question, the Task Force examined whether competition has elicited consumption 

and investment decisions that were expected to occur with wholesale market competition. 

The Task Force found this question challenging to address. Regional wholesale electric power 

markets have developed differently since the beginning of widespread wholesale competition. 

Each region was at a different regulatory and structural starting point upon Congress’ enactment 

of the Energy Policy Act of 1992. Some regions already had tight power pools, others were 

more disparate in their operation of generation and transmission. Some regions had higher 

population densities and thus more tightly configured transmission networks than did others. 

Some regions had access to fuel sources that were unavailable or less available in other regions 

(e.g., natural gas supply in the Southeast, hydro-power in the Northwest). Some regions operate 

under a transmission open-access regime that has not changed since the early days of open 

access in 1996, while other regions have independent provision of transmission services and 

organized day-ahead exchange markets for electric power and ancillary services. These 

differences make it difficult to single out the determinants of consumption and investment 

decisions and thus make it difficult to evaluate the degree to which more competitive markets 

have influenced such decisions. Even the organized exchange markets have different features 

and characteristics. 

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

of wholesale competition has yielded some useful observations, as presented below. The Task 

Force seeks comment on these observations. 
3

Observations on Competitive Market Structures:

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

bilateral sales directly negotiated between suppliers, rather than on a centralized trading and 

market clearing mechanisms. This approach predominates in the Northwest and Southeast. This 

bilateral format allows for somewhat independent operation of transmission control areas and, in 

the view of some market participants, better accommodates traditional bilateral contracts. 

However, the fact that prices and terms can be unique to each transaction and are not always 

publicly available can lead to less than efficient (not least cost) generation dispatch scenarios. 

Also, it can be difficult to efficiently coordinate transmission when using this trading 

mechanism. The lack of centralized information about trades leaves the transmission owner 

with system security risks that necessitate constrained transmission capacity. In some of these 

markets, wholesale customers have difficulty gaining unqualified access to the transmission they 

would need to access competitively priced generation – thus limiting their ability to shop for 

least cost supply options. 

2. Another approach to wholesale competition relies on entities which are independent of 

market participants to operate centralized regional transmission facilities and trading markets 

(Regional Transmission Organizations or Independent System Operators). Various forms of this 

approach have come to predominate in the Northeast, 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 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 transparency 

of prices in these 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 

However, concerns have been raised about the inability to obtain long-term transmission access 

at predictable prices in these markets and the impact that this lack of long-term transmission can 

have on incentives to construct new generation. Some customers have raised concerns about 

high commodity price levels in these markets. 

Observations on Generation Supply in Markets for Electricity

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

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

occur 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. Customers exposed to a price spike often assume that the 

spike is evidence of market abuse. 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 
4

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. 

 

2. “Capacity payments” also can help elicit new supply. Wholesale customers make these 

payments to suppliers to assure the availability of generation when needed. However, where 

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

determine the appropriate level of capacity payments to spur entry without over-taxing 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 the closure of that generation. 

3. Building appropriate transmission facilities may encourage entry of new generation or 

more efficient use of existing generation. But, 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 with transmission construction is that 

it is often difficult to assess the beneficiaries of transmission upgrades and, thus, it is difficult to 

identify who should pay for the upgrades. This challenge may cause uncertainty both for new 

generators and for transmission owners. There can also be difficulties associated with uncertain 

revenue recovery due to unpredictable regulatory allowances for rate recovery. 

4. Another option for ensuring adequate generation supply is through traditional regulatory 

mechanisms - regulatory control over electricity generators/suppliers. In this situation, 

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. However, 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. Furthermore, under traditional regulation, 

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

Observations on Competition in Retail Electric Power Markets

The Task Force examined the implementation of retail competition in seven states in detail: 

Illinois, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, and Texas. The 

implementation of retail competition raises the question whether retail prices are higher or lower 

than they otherwise would be absent the introduction of this competition. 

In most profiled states, retail competition began in the late 1990s. States implemented retail rate 

caps and distribution utility obligations to serve, which are now just ending, that make it difficult 

to judge the success or failure of retail competition. Few alternative suppliers currently serve 

residential customers, although industrial customers have additional choices. To the extent that 

multiple suppliers serve retail customers, prices have not decreased as expected, and the range of 

new options and services is limited. Since retail competition began, most distribution utilities in 
5

the profiled states have either sold most of their generation assets or transferred them to 

unregulated affiliates. 

One of the main impediments to retail competition has been the lack of entry by alternative 

suppliers and marketers to serve retail customers. Most states required the distribution utility to 

offer customers electricity at a regulated price as a backstop or default if the customer did not 

choose an alternative electricity supplier or the chosen supplier went out of business -- this is 

called “provider of last resort (POLR) service.” Many of these states capped the POLR service 

price for “transitional” multi-year periods that are now just ending. These caps have had the 

unintended effect of discouraging entry by competitive suppliers. Thus, it has been difficult for 

the Task Force to determine whether retail prices in the profiled states are higher or lower than 

they otherwise would be absent the introduction of retail competition. 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 commercial and industrial customers. 

When the rate caps expire, states must decide whether to continue POLR for all customer classes 

and how to price POLR service for each class. Several states have rate caps that will expire in 

2006 and 2007. The Task Force seeks comment on the observations about how POLR prices 

affect competition in retail electric power markets. 

1. If regulators intend for the POLR service to be a proxy for efficient price signals, it must 

closely approximate a competitive price. The competitive price 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.2

 

2. 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 rate shock 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. Although this approach reduces rate shock for customers, it is likely to distort 

retail electricity markets both in the short-term (when costs are deferred) and in the long-term 

(when the deferred costs are recovered). 

3. Some states have different POLR service designs for different customer classes. POLR 

prices for large commercial and industrial customers have reflected wholesale spot market prices 

more than have POLR prices for residential customers. This approach generally has led the large 

customers to switch suppliers more than the small customers have. Also, more suppliers have 

made efforts to solicit these large customers. Retail pricing that closely tracks wholesale prices 

provides efficient price signals to consumers. It creates incentives for customers to cut 

consumption during peak demand periods which, in turn, can reduce the risk that suppliers will 

exercise market power and can improve system reliability. 

 

2

 Theoretically, competitive prices provide efficient incentives for all resource allocation (supply and consumption) 

decisions, and thus encourage efficient allocation of resources, including use of existing capacity, new investment 

by incumbent suppliers, entry by new suppliers, consumption, new investments by consumers. 
6

4. Some states have used 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. 

5. One reason why retail competition for small customers may be slow to develop is that it 

is difficult to for the consumer 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 effort to find 

this information is justified by the potential cost savings that can be realized. As and when there 

are more alternative suppliers, it may result in greater potential savings. But the need for clear 

and readily available information relating to competitive offers will remain. 
7

CHAPTER 1 

INDUSTRY STRUCTURE, LEGAL AND REGULATORY 

BACKGROUND, INDUSTRY TRENDS AND DEVELOPMENTS 

For the majority of the twentieth century, the electric power industry was dominated by regulated 

monopoly utilities. Beginning in the late 1960s, however, a number of factors contributed to a 

change in structure of the industry. In the 1970s, vertically-integrated utility companies 

(investor-owned, municipal, or cooperative) controlled over 95 percent of the electric generation. 

Typically, a single local utility sold and delivered electricity to retail customers under an 

exclusive franchise. Now, the electric power industry includes both utility and nonutility 

entities, including many new companies that produce and market electric energy in the wholesale 

and retail markets. This section will briefly describe the structural changes in the wholesale and 

retail electric power industry from the late 1960s until today. It provides a historical overview of 

the important legislative and regulatory changes that have occurred in the past several decades, 

as well as the trends seen over this time period that have led to increased competition in the 

electric power industry. 

A. Industry Structure and Regulation 

Participants in the electric power sector in the United States include investor-owned, cooperative 

utilities; Federal, State, and municipal utilities, public utility districts, and irrigation districts; 

cogenerators; nonutility independent power producers, affiliated power producers, and power 

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

In 2004, there were 3276 regulated retail electric providers supplying electricity to over 136 

million customers. Retail electricity sales totaled almost $270 billion in 2004. Retail customers 

purchased more than 3.5 billion megawatt hours of electricity. Active retail electric providers 

include electric 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 United States Department of Energy (DOE), Energy 

Information Administration (EIA). 

1. Investor-Owned Utilities

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

ranging in size from small local operations serving a 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 

facilities/resources required to meet the needs of the retail customers in their assigned service 

areas. Over the past decade, under State retail competition plans many IOUs have undergone 

significant restructuring and reorganization. As a result, many IOUs in these states no longer 

own generation, but must procure the electricity they need for their retail customers from the 

wholesale markets. 
8

IOUs continue to be a major presence in electric power industry. 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 own about 39.6 percent 

of total electric generating capacity and generated 44.8 percent of total generation in 2004 to 

meet their retail and wholesale sales. 

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

operations, services, and rates. States generally regulate bundled retail electric rates of IOUs 

under traditional cost of service rate methods. In states that have restructured their IOUs and 

IOU regulation, distribution services continue to be provided under monopoly cost-of-service 

rates, but retail customer are free to shop for their electricity supplier. IOUs operate retail 

electric systems in every state but Nebraska. 

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

wholesale electricity transactions (sales for resale) and unbundled transmission activities of IOUs 

(except in Alaska, Hawaii, and the ERCOT region of Texas). 

2. Public Power Systems

The more than 2,000 public power systems include local, municipal, State, and regional public 

power systems, ranging in size from tiny municipal distribution companies to large systems like 

the Power Authority of the State of New York. Publicly owned systems operate in every State 

but Hawaii. About 1,840 of these public power systems are cities and municipal governments 

that own and control the day to day operation of their electric utilities.3 Public power systems 

served over 19.6 million retail customers in 2004, or about 14.4 percent of all customers. 

Together, public power systems generated 10.3 percent of the Nation’s power in 2004, but 

accounted for 16.7 percent of total electricity sales, reflecting the fact that many public systems 

are distribution-only utilities and must purchase their power supplies from others. Public power 

systems own about 9.6 percent of total generating capacity. Public power systems are 

overwhelmingly transmission-and wholesale-market-dependent entities. 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 

came from power generated by a utility to serve its own native load. 

Regulation of public power systems varies among States. In some States, 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 selfregulated. Municipal systems are usually governed by the 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. 

 

3

 American Public Power Association. 
9

On the whole, state retail deregulation/restructuring initiatives left untouched retail services in 

public power 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, about 884 

electric distribution cooperatives provided retail electric service to almost 16.6 million 

customers. In addition to these 884 distribution cooperatives, about 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 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 for the benefit of their customers. Electric 

cooperatives operate in 47 States. Most electric cooperatives were originally organized and 

financed under the Federal rural electrification program and generally operate in primarily rural 

areas. Electric cooperatives provide electric service in all or parts of 83 percent of the counties 

in the United States.4

In 2004, electric cooperatives sold more than 345 million megawatt hours of electricity, served 

12.2 percent of retail customers and accounted for 9.7 percent of electricity sold at retail. 

Nationwide electric cooperatives generated about 4.7 percent of total electric generation. 

Electric cooperatives own approximately 4.2 percent of generating capacity 

While some cooperative systems generate their own power and make sales of power in excess of 

their own members needs, most electric cooperatives are net buyers of power. Cooperatives 

nationwide generate only about half of the power needed to meet the needs of retail customers. 

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

2004. Although cooperatives own and operate transmission facilities, almost all cooperatives are 

dependent on transmission service by others to deliver power to their wholesale and/or retail 

customers. 

Regulatory jurisdiction over cooperatives varies among the States, with some States exercising 

considerable authority over rates and operations, while other States exempt cooperatives from 

State regulation. In addition to State regulation, cooperatives with outstanding loans under the 

Rural Electrification Act of 1936 also are subject to financial and operating requirements of the 

U.S. Department of Agriculture, which must approve borrower long-term wholesale power 

contracts, operating agreements, and transfer 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. EPACT 05 

provided FERC additional discretionary jurisdiction over the transmission services provided by 

larger electric cooperatives. 

 

4

 National Rural Electric Cooperative Association. 
10

4. Federal Power Systems

Federally owned or chartered power systems include the Federal power marketing 

administrations, 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. PMAs may also 

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

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

sale of their generation output 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, they do engage in some end-use sales of generation. 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 or sell electric power, but that do not operate retail 

distribution franchises. They include wholesale non-utility affiliates of regulated utilities, 

merchant generators, and PURPA qualifying facilities (industrial and commercial combined heat 

and power producers). Power marketers that buy and sell power at wholesale or retail, but that 

do not own generation, transmission, or distribution facilities are also included in this category. 

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

interstate commerce are subject to FERC regulation under the FPA. Power marketers that sell at 

wholesale are also subject to FERC oversight. Power marketers that sell only at retail are subject 

to State jurisdiction and oversight in the States in which they operate. 

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 or 39.6 percent of all electric generation capacity. In 1993 

they owned only about 8 percent of generation. It is estimated that about half of nonutility 

generation capacity is owned by non-utility affiliates or subsidiaries of holding companies that 

also own a regulated electric utility.5

 Nonutilities accounted for about 33 percent of generation 

in 2004. Tables 1-1 through 1-5 summarize this information. 

 

5

 Edison Electric Institute. 
11

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

Ownership 

Number 

of 

Electricity 

Providers 

Percent 

of Total Number of Customers 

 

Full Service 

Delivery 

only Total 

Percent 

of 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 

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

Information Administration Form EIA-861, 2004 data. 

Notes: Delivery-only customers represent the number of customers in a utility’s service territory that purchase 

energy from an alternative 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. 

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

Sales to ultimate consumers in thousands of MWhs 

 Full Service Energy only Total Percent 

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

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

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. 

Notes: Energy-only revenue represents revenue from a utility’s sales of energy outside of its own service territory. 

Total revenue shows the amount of revenue each sector receives from both bundled (full service) and unbundled 
12

(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. Investor-owned utilities in the ERCOT region of Texas no longer report sales or revenue 

to ultimate consumers on EIA 861. 

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

Consumers 

 Sales in $ 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 

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

Information Administration Form EIA-861, 2004 data. 

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

Electricity Generation 2004 Generation 

 (thousands of MWhs) % of Total 

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 

Non-utilities 1,235,298 31.9 

Total 3,869,769 100.0 

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

Information Administration Form EIA-861 and EIA-906/920 for generation. Data are for 2004, adjusted for joint 

ownership. 
13

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

Ownership Nameplate Capacity % 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 

Non-utilities 409,689 39.7 

Total 1,031,692 100.0 

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

Information Administration Form EIA-860 for capacity, including adjustments for joint ownership. Data are for 

2004. 

B. Growth of the Electric Power Industry 

1. Electric Power Characterized as a Natural Monopoly

The early electric power industry has been characterized as a natural monopoly.6 This idea was, 

in part engendered by the work of Thomas Edison’s protégé, Samuel Insull who acquired 

monopoly ownership over all central station electricity production in Chicago. Insull went on to 

publicly characterize electricity production as a “natural monopoly” and promote the idea of the 

public granting monopoly franchises to integrated generation/transmission utilities whose profits 

would be monitored and regulated.7 

Over the years, experts have debated whether or not Samuel Insull was right. But he made a 

compelling argument, and the industry structure developed as if electricity was a natural 

monopoly. States granted monopoly franchises to vertically-integrated utilities. These 

franchises controlled the generation, transmission, and distribution of electricity. Public utility 

commissions were established to regulate the retail prices the electric utilities could charge. 

Electric rates were set to cover the companies' reasonable costs plus a fair return on their 

shareholders' investment. Retail customers were charged a price based on the average system 

cost of production (including the investors’ fair return on investment). In some circumstances, 

the public chose to establish publicly owned municipal utilities and cooperatives. 

Most utilities began by building their own generation plants and transmission systems, primarily 

due to the cost and technological limitations on the distance over which electricity could be 

 

6

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

Department of Economics, University of Arizona). 

7

 See Richard F. Hirsch, Power Loss: The Origins of Deregulation and Restructuring in the American Electric Utility 

System, MIT PRESS (1999); SHARON BEDER, POWER PLAY: THE FIGHT TO CONTROL THE WORLD’S 

ELECTRICITY, W.W. Norton (2003). 
14

transmitted.8 In the beginning, the federal role in the electric power industry was limited. Under 

the Federal Power Act of 1935 (FPA), the Federal Government regulated the price of IOUs’ 

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

and terms of use of the interstate transmission system, which was used in these interstate sales of 

wholesale power. When this act was passed, interstate sales of electricity were limited. Over 

time utilities became more interconnected via high-voltage transmission networks that were 

constructed primarily for purposes of reliability but facilitated more robust interstate trade. 

However, this trade was slow to develop. Entry into these markets by nonutility generators was 

limited. 

Until the late 1960s, this system appeared to work reasonably well. Utilities were able to meet 

increasing demand for electricity at decreasing prices, due to advances in generation technology 

that increased economies of scale and decreased costs.9

 

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

Expansion of Nonutility Generation and Wholesale Power Markets

Several changes during the 1970s created a shift to a more competitive marketplace for 

wholesale power. Mainly, the large vertically integrated utility model became less profitable. 

Additional economies of scale were no longer being achieved; large generating units needed 

greater maintenance and experienced longer downtimes. Thus a bigger generation facility was 

no longer considered the most cost-efficient format.10 Periods of rapid inflation and higher 

interest rates increased the costs of operating large, baseload generation plants,11 and a more 

elastic-than-expected demand or load led to decreasing profits for large utilities.12 Significant 

improvements in technology allowed smaller generation units to be constructed at lower costs.13 

As a result, lower cost generation sources could reach systems where customers were captive to 

high cost generators.14 In addition, these technological advances made it more feasible for 

generation plants hundreds of miles apart to compete with each other15 and for nonutility 

generators to enter the market; physically isolated systems became a thing of the past. Criticism 

of the cost-based regime also increased during this period with suggestions for alternate 

approaches to regulation and changes in industry structure. Critics of cost-based regulation 

argued that the industry structure provided limited opportunities for more efficient suppliers to 

expand and placed insufficient pressure on less efficient suppliers to improve their 

performance.16 

8

 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]. 

9

 See U.S. Dep’t of Energy, Energy Info. Admin., 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]. 

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

11 Id. at 31,639. 
15

Other events also influenced these changes. First, a major power blackout in the Northeastern 

U.S. in 1965 raised concerns about the reliability of weakly coordinated transmission 

arrangements among utilities.17 Second, from October of 1973 to March of 1974, the Arab oilproducing nations imposed a ban on oil exports to the United States. The Arab oil embargo 

resulted in significantly higher oil prices through the 1970s, adding to inflation.18 

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

the energy crises of the 1970s. A major goal of PURPA was to promote energy conservation and 

alternative energy technologies and to reduce oil and gas consumption through use of technology 

improvements and regulatory reforms. PURPA further created an opportunity for nonutilities to 

emerge as important electric power producers. 20 PURPA required electric utilities to 

interconnect with and purchase power from certain cogeneration facilities and small power 

producers meeting the criteria for a qualifying facility (QF). PURPA provided that the QF be 

paid at the utility’s incremental cost of production, which FERC, in a departure from cost-based 

regulation, defined as the utility’s avoided cost of power.21 Box 1-1 discusses how the 

implementation of PURPA encouraged nonutilities generation suppliers by guaranteeing a 

market for the electricity they produced.22 PURPA changed prevailing views that vertically 

integrated public utilities were the only sources of reliable power23 and showed that nonutilities 

 12 Consumers reacted to electricity price increases, and growth in demand fell sharply below projections. See U.S. 

Congress, Office of Technology Assessment, Electric Power Wheeling and Dealing: Technological Considerations 

for Increasing Competition 39, OTA-E-409 (Washington, DC: U.S. Government Printing Office, May 1989) 

[hereinafter U.S. Congress, Office of Technology Assessment]. 

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

14 Id.

15 Severin Borenstein & James Bushnell, Electricity Restructuring: Deregulation or Reregulation?, 23 REGULATION

46, 47 (2000). 

16 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.aeibrookings.org/admin/authorpdfs/page.php?id=271 [hereinafter Joskow, Difficult Transition]. 

17 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. U.S. Dept. of 

Energy, Energy Info. Admin., The Changing Structure of the Electric Power Industry 2000: An Update, at 109 

(October 2000), available at http://www.eia.doe.gov/cneaf/electricity/chg_stru_update/update2000.pdf [hereinafter 

EIA 2000 Update]. 

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

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

20 See EIA 1979-1991 at 22. 

21 PURPA specifically set forth criteria on who and what could qualify as QFs (mainly technological and size 

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 same fuel source, and small power producers, which use waste, 

renewable energy, or geothermal energy as a primary energy source. These nonutility generators are “qualified” 

under PURPA, in that they meet certain ownership, operating, and efficiency criteria. See EIA 1970-1991 at 5. 

22 Id. at 24. 

23 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,642. 
16

could build and operate generation facilities effectively and without disrupting the reliability of 

transmission systems.24 

PURPA was largely responsible for creating an independent competitive generation sector.25 

The response to PURPA was dramatic. 

Before passage of PURPA, nonutility generation was primarily confined to commercial and 

industrial facilities where the owners generated heat and power for their own 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 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. 

Annual QF filings at FERC rose from 29 applications covering 704 megawatts in 1980 to 979 in 

1986 totaling over 18,000 megawatts. From 1980 to 1990 FERC received a total of 4610 QF 

applications for a total of 86,612 megawatts of generating capacity.26 

Following PURPA, there were economic and technological changes in the transmission and 

generation sectors that further contributed to an influx of new entrants in wholesale generation 

markets who could sell electric power profitably with smaller scale technology than many 

utilities.27 In addition to QFs, other non-utility power producers that could not meet QF criteria 

also began to build new capacity to compete in bulk power markets to meet the needs of load 

serving entities.28 These entities were known as merchant generators or Independent Power 

Producers (IPPs).29 By 1991, nonutilities (QFs and IPPs) owned about six percent of the electric 

24 Joskow, Deregulation at 19. 

25 Id. at 17. 

26 CONG. RESEARCH SERV., COMM. ON ENERGY AND COMMERCE, 102D CONG., ELECTRICITY A 

NEW REGULATORY ORDER? 92 (Comm. Print 1991). 

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

28 Joskow, Deregulation at 19. 

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

Box 1-1: State Implementation of PURPA 

PURPA required states to define the utility’s own avoided cost of production. This cost was used to set the 

price for purchasing a QF’s output. Several states, including California, New York, Massachusetts, Maine, and 

New Jersey, enacted regulations that required utilities in these states to sign long-term contracts with QFs at 

prices that ended up being much higher than the utilities’ actual marginal savings of not producing the power 

itself (avoided costs). The result of these regulations was that many utilities entered into long-term purchase 

contracts that ultimately proved uneconomic, and thus distorted the development of competitive wholesale 

markets. The costs of such contracts were subsequently reflected in retail rates as cost pass-throughs. The 

experience added to the dissatisfaction with retail utility service and regulation. See Joskow, Deregulation at 

18. 
17

power generating capacity and produced about nine percent of the total electricity generated in 

the United States,30 and nonutility generating facilities accounted for one-fifth of all additions to 

generating capacity in the 1980s.31 

FERC allowed many new utility and non-utility generators to sell electric power supply at 

wholesale market, rather than regulated rates.32

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

concerning the pricing of electricity in wholesale transactions: 1) competitive bidding for new 

power requirements; 2) treatment of independent power producers; and 3) determination of 

avoided costs under PURPA.33 These proposals would have moved towards greater use of a 

“non-traditional” market-based pricing approach in ratemaking as opposed to the agency’s 

“traditional” cost-based approach. These FERC NOPRs proved controversial, and efforts to 

establish formal rules or policies adopting them were abandoned as commission membership 

changed. However, with the support of several Commission members and key FERC staff, the 

overall policy goals were still pursued on a case-by-case basis. 

FERC laid the foundation for greater reliance on market-based mechanisms for Federal oversight 

of wholesale electricity prices on a case-by-case basis. Between 1983 and 1991, FERC 

considered more than 31 cases concerning approval of non-traditional rates involving 

independent power producers, power brokers/marketers, utility-affiliated power producers, and 

traditional franchised utilities. FERC approved all but four of these applications.34 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.”35 

 

30 EIA 1970-1991 at vii. 

31 Id. at 27. 

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

33 See Regulations Governing Bidding Programs, Notice of Proposed Rulemaking, 53 Fed. Reg. 9,324 (March 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 

(March 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 (March 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. 

34 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). 

35 Id. at 100. 
18

In its process of determining whether the seller could exercise market power over the buyer, the 

FERC considered whether the seller or its affiliates owned or controlled transmission that might 

prevent the buyer from accessing other sources of power. A seller with transmission control 

might be able to force the buyer to purchase from the seller, thus limiting competition and 

significantly influencing the price the buyer would have to pay. The FPA does not allow rates to 

reflect an exercise of such market power.36

The potential for control of transmission to create market power, and the challenge that such 

control created in moving to greater reliance on market-based rates, was recognized. “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.”37

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

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

cheaper electric power could not easily gain access to the transmission grid to reach potential 

customers.38 Under the FPA as then written, FERC authority to order transmission access was 

limited. FERC would subsequently find that "intervening" transmitting utilities would deny or 

limit transmission service to competing suppliers of generation service in order to protect 

demand for wholesale power supplied by their own generation facilities.39 Second, unlike QFs 

that enjoyed a statutory exemption under PURPA, IPPs were subject to the Public Utility 

Holding Company Act of 1935 (PUHCA), which discouraged non-utilities from entering the 

generation business.40 

 

36Id.

37 Id. at 102. 38 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,642-43. 

39 Joskow, Deregulation at 21. See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,644. 40 Joskow, Deregulation at 23. Under PUHCA, those public utility holding companies that did 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 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 provided for limited exemptions, it was long criticized as discouraging new investment in the 

electric utility industry by non-utility entities. Mergers and acquisitions of utilities subject to PUHCA 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. 
19

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

Congress enacted the Energy Policy Act of 1992 (EPACT 92) 41 and amended the FPA and 

PUHCA to address two major limitations on the development of a competitive generation sector. 

First, EPACT 92 created a new category of power producers, called exempt wholesale generators 

(EWGs).42 A EWG was an entity that directly, or indirectly through one or more affiliates, 

owned or operated facilities dedicated exclusively to producing electric power for sale in 

wholesale markets.43 EWGs were exempted from PUHCA regulations, thus eliminating a major 

barrier for utility-affiliated and nonaffiliated power producers that wanted to compete to build 

new non-rate-based power plants.44 EPACT 92 also expanded FERC’s authority to order 

transmitting utilities to provide transmission service for wholesale power transmission to any 

electric utility, Federal power marketing agency, or any person generating electric energy in 

wholesale electricity markets.45 The amendment provided for orders to be issued on a case by 

case basis following a hearing if certain protective conditions were met. Though FERC 

implemented this new authority, it ultimately concluded that procedural limitations limited its 

reach and a broader remedy was needed to effectively eliminate pervasive undue discrimination 

in the provision of transmission service. 

Thus, in April 1996, FERC adopted Order No. 888 in exercise of its statutory obligation under 

the FPA to remedy undue transmission discrimination 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, the FERC found that undue 

discrimination and anticompetitive practices existed in the provision of electric transmission 

service by public utilities in interstate commerce, and determined that non-discriminatory open 

access transmission service was 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 non-price terms and conditions 

and to “functionally unbundle” wholesale power services from transmission services.46 To 

functionally unbundle, a public utility was required to: (1) take wholesale transmission services 

under the same tariff of general applicability as it offered its customers; (2) state 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.47

 

41 Pub. L. No. 102-486, 106 Stat. 2776 (1992), codified at, among other places, 15 U.S.C. § 79z-5a and 16 U.S.C. §§ 

796(22-25), 824j-l. 

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

43 Joskow, Deregulation at 24. 

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

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

46 Id. at ¶ 31,654. 

47 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 
20

Concurrent with the issuance of Order No. 888, FERC issued Order No. 88948 that imposed 

standards of conduct governing communications between the 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 Sametime Information System, to provide 

information regarding available transmission capacity, prices, and other information that will 

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

service. 49 

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

Independent Systems Operator (ISOs). Participating utilities would voluntarily transfer 

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

transmission grid.50 The ISO also could achieve coordination, reliability, and efficiency benefits 

by having regional control of the grid. 51 Participation in an ISO remained voluntary, however, 

and it only occurred in some areas of the country. It was not implemented in other areas.52 

Together, Order Nos. 888 and 889 serve as the primary federal foundation for providing 

transmission service and information about the availability of transmission service.53 

4. Restructuring Initiatives in Retail Markets: State-Authorized Retail Electricity 

Competition

Beginning in the early 1990s, several states with high electricity prices began to explore opening 

retail electric service to competition. With retail competition, customers could choose their 

electric supplier, but the delivery of electricity would still be done by the local distribution 

utility. 

Substantial rate disparity existed among and between utilities in different states. For example, 

customers in New York paid more than two and one-half times the rates paid by customers in 

Kentucky in 1998. Rates in California were well over twice the rates in Washington.54 Some of 

 

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). 

48 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). 

49 Joskow, Deregulation at 29. 

50 EIA 2000 Update at 66. 

51 Id. at 66, 68, 80. 

52 Id. at 67. 

53 Joskow, Deregulation at 27-28. 

54 EIA 2000 Update at ix. 
21

this disparity in price from state to state can be attributed to different natural resource 

endowments across regions -- most important the hydroelectric opportunities in the Northwest 

and some states such as Kentucky and Wyoming with abundant coal reserves -- and the resulting 

diverse costs of fuel used for generation by utilities. Another reason for the price disparity may 

be that some states required utilities to enter into PURPA contracts that subsequently resulted in 

prices higher than the cost to acquire power in the wholesale market.55 Utilities’ QF contract 

costs were included as part of the bundled service provided to retail customers; ultimately the 

cost of these high-cost PURPA contracts was reflected in the regulated retail prices.56 

Additionally, utilities in some states invested heavily in large, new nuclear power plants, and 

coal plants, which turned out to be more expensive than anticipated, adding to the retail rate 

shock. 

Not only were there large disparities in utility rates among states, but many industrial customers 

contended that they subsidized lower rates for residential customers. For example, a survey by 

the Electricity Consumers Resource Council in 1986 contended that industrial electricity 

consumers paid more than $2.5 billion annually in subsidies to other electricity customers (e.g., 

commercial and residential customers). By allowing industrial customers to choose a new 

supplier, it was presumed that these subsidies could be avoided and industrial customer 

electricity prices would decrease.57

This rate disparity provided an impetus for states to initiate their restructuring efforts; thus it is 

not surprising that many of the states that led the restructuring movement were those with higher 

prices.58 As of 2004 the disparity in retail prices among the states persisted, as illustrated in 

Figure 1-1, below. 

 

55 See discussion infra, Box 1-1. 

56 Joskow, Deregulation at 19. 

57 Electricity Consumers Resource Council, Profiles in Electricity Issues: Cost-of-Service Survey (Mar. 1986). 58 EIA 2000 Update at 43. 
22

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 

Not all state commissions adopted retail competition plans, although most of them considered the 

merits and implications of competition, deregulation, and industry restructuring. States such as 

California and those in New England and the mid-Atlantic region, with high electricity rates, 

were among the most aggressive in adopting retail competition in the hope of making lower rates 

available to their retail customers. 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. There were only eight states where no restructuring activities had 

taken place.59 Since 2000, however, no additional states have announced plans to implement 

retail competition programs, and several states that had introduced such programs have delayed, 

scaled back, or cancelled their programs entirely (see Figure 1-2 below).60 The California energy 

crisis is widely-perceived to have halted interest by states in restructuring retail markets. These 

issues are further discussed in Chapter IV, Retail Competition. 

Figure 1-2: Status of State Electric Industry Restructuring Activity, 2003 

 59 Id. at 81-82. 

60 Paul L. Joskow, Markets for Power in the United States: An Interim Assessment, ENERGY J. 2 (2006) 

[hereinafter Joskow, Interim Assessment]. 
23

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 

5. Development of Regional Transmission Organizations and Regional Wholesale Markets 

Even after issuance of Order Nos. 888 and 889, FERC continued to receive complaints about 

transmission owners discriminating against independent generating companies. Transmission 

customers remained concerned that electric utilities’ implementation of functional unbundling 

did not produce complete separation between operating the transmission system and marketing 

and selling electric power in wholesale markets. Also, there were concerns that Order No. 888 

changes made some discriminatory behavior in transmission access more subtle and difficult to 

identify and document. 

The electric industry continued to transform since FERC issued Order Nos. 888 and 889, in 

response to competitive pressures and state retail restructuring initiatives. Utilities today 

purchase more wholesale power to meet their load than in the past and are expanding reliance on 

availability of other utility transmission facilities for delivery of power. Retail competition 

increased significantly in the years following adoption of Order No. 888. These state initiatives 

brought about the divestiture of generation plants by traditional electric utilities. In addition, this 

period saw a number of mergers among traditional electric utilities and among electric utilities 

and gas pipeline companies, large increases in the number of power marketers and independent 

generation facility developers entering the marketplace, and the establishment of ISOs as 

managers of large parts of the transmission system. Trade in wholesale power markets has 

increased significantly and the Nation's transmission grid is being used more heavily and in new 

ways. 
24

In response to continuing complaints of discrimination and lack of transmission availability and 

in the wake of an expanding competitive power industry, in December 1999, FERC issued Order 

No. 2000.61 This order recognized that Order No. 888 set the foundation upon which to attain 

competitive electric markets, but did not eliminate the potential to engage in undue 

discrimination and preference in the provision of transmission service.62 Thus, FERC concluded 

that regional transmission organizations (RTOs) could eliminate transmission rate pancaking,63

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

services that can occur when the operation of the transmission system remains in the control of a 

vertically integrated utility. Accordingly, FERC encouraged the voluntary formation of RTOs.

 

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. 

FERC has approved RTOs or ISOs in several regions of the country including the Northeast 

(PJM, New York ISO, ISO-New England), California, the Midwest (MISO) and the South (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.64

In 2004 and 2005, the PJM grid expanded substantially to include several additional service 

territories in the Midwest. In 2004, the territories serviced by Commonwealth Edison (ComEd), 

American Electric Power (AEP), and Virginia Electric and Power (VEPCO) joined PJM. The 

expansion continued in 2005 with the addition of Duquesne Light. The area now in PJM covers 

about 18 percent of total electricity consumption in the United States.65

In most cases, RTOs have assumed responsibility to calculate the amount of available transfer 

capability (ATC) for wholesale trades across the footprint of the RTO. RTOs also are 

responsible for regional planning, at least for facilities necessary for reliability above a certain 

voltage. 

As of 2004, all of the RTOs in operation coordinate dispatch of the generators in their systems 

and provide transmission services under a single RTO open access tariff. In addition, RTOs 

 

61 Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 16 (1999), order on 

reh’g, Order No. 2000-A, FERC Stats. & Regs. ¶ 30,092, 65 Fed. Reg. 12,088 (2000), aff'd, Public Utility District 

No. 1 v. FERC, 272 F.3d 607 (D.C. Cir. 2001) [hereinafter Order No. 2000]. 62 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. 

63 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. 

64 Fed. Energy Regulatory Comm’n, Office of Mkt. 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 2005], available at http://www.ferc.gov/legal/staff-reports.asp. 

65 Id. at 53. 
25

operate regional organized energy markets, including a short-term market which prices energy, 

congestion, and losses. RTOs in the East all offer day-ahead and real-time markets, while 

California and Texas offer real-time market alone. Further, all RTOs in current operation use or 

plan to use some form of locational pricing and have independent market monitors.66 

Figure 1-3: RTO Configurations in 2004 

Source: FERC State of the Market Report for 2004, Figure 2, Page 53 

 

6. 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, leaving more than 50 million people 

without power.67 The August 2003 blackout was the largest blackout in the history of the 

United States, leaving some parts of the nation without power for up to four days and 

costing between $4 billion and $10 billion.68 The 2003 blackout was the eighth major 

blackout experienced 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 Blackout Report identified factors that were common to some of the 

eight major outage occurrences from the 1965 Northeast Blackout through the 2003 

Blackout, as shown below: 

 

66 Id. at 52. 

67 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. 68 Id.
26

(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.[69]

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

In 2005, Congress passed the Energy Policy Act of 2005 (EPACT 2005),70 which amended the 

core statutes (FPA, PURPA, PUHCA) governing the electric power industry. Several key 

provisions of EPACT 2005 are: 

 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. 

 Authorizes the Secretary of Energy to conduct a study of electricity congestion 

within one year of the enactment of the Energy Policy Act, and every three years 

thereafter . Authorizes the Secretary of Energy to designate “National Interest 

Electric Transmission Corridors” based on these congestion studies. EPACT 05 

also authorizes FERC in limited circumstances to approve the siting of 

transmission facilities in these corridors, in states which lack such authority or do 

not exercise it in a timely manner. Proponents of this new federal authority have 

argued that it will facilitate the construction of new transmission lines and, thus, 

help alleviate transmission congestion that can impair competition in electric 

markets. 

 Requires FERC to establish incentive-based rate treatments for public utilities’ 

transmission infrastructure in order to promote capital investment in facilities for 

the transmission of electricity, attract new investment with an attractive return on 

equity, encourage improvement in transmission technology, and allow for the 

recovery of prudently incurred costs related to reliability and improved 

transmission infrastructure. Proponents of this authority contend it will encourage 

the expansion of transmission capacity and, thus, help foster greater competition in 

electric markets. 

 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 is negating the need for PURPA’s “forced sale” requirements. 

 

69 Id. at 107. 

70 Pub. L. No. 109-58, 119 Stat. 594 (2005). 
27

 Repeals PUHCA 1935 and replaces it with new PUHCA 2005, which provides 

FERC and state access to books and records of holding companies and their 

members and provides that certain holding companies or states may obtain FERCauthorized 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 of these provisions is to reduce 

legal obstacles to investment in the electric utility industry and, thus, help 

facilitate the construction of adequate energy infrastructure. 

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

Given the previous reviewed of electric industry legal and regulatory background, this section 

discusses several more recent electric industry policy developments and characteristics. 

1. Technological Improvements in Generation and Transmission

Electric power industry restructuring has been largely sustained by technological improvements 

in gas turbines. No longer is it necessary to build a large generating plant to exploit economies 

of scale. Combined-cycle gas turbines reach maximum efficiency at 400 megawatts (MW), 

while aero-derivative gas turbines can be efficient at sizes as low as 10 MW. These new gasfired combined cycle plants can be more energy efficient and less costly than the older coal-fired 

power plants.71 Technological advances in transmission equipment have made transmission of 

electric power over long distances more economical. As a result, generating plants hundreds of 

miles apart can compete with each other and customers can be more selective in choosing an 

electricity supplier.72

Despite these increases in technology, the Edison Electric Institute reports that investment in 

transmission declined from 1975 through 1997. See Figure 1-4. Since 1998, transmission 

investment has increased annually, but remains below 1975 levels. Over that same period, 

electricity demand has more than doubled, resulting in a significant decrease in transmission 

capacity relative to demand. Box 1-2 discusses some suggested explanations for this trend of 

declining transmission investment. 

 

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

72 Id.
28

Figure 1.4: Transmission Expenditures of EEI Members, 1975-2003 

1975 1979 1983 1987 1991 1995 1999 2003

0

1,000

2,000

3,000

4,000

5,000

Million 2003 Dollars

Source: Edison Electric Institute

2. Increase in Nonutility Generation Suppliers

The market participation of utilities and other suppliers in the generation of electricity has 

changed over the past few decades. The change began with the passage of PURPA, when 

nonutilities were promoted as energy-efficient, environmentally-friendly, alternative sources of 

electric power. The change continued through the issuance of Order No. 888, which opened up 

the transmission grid to suppliers other than utilities.73 Until the early 1980s, the electric 

utilities’ share of electric power production increased steadily, reaching 97 percent in 1979.74 By 

1991, however, the trend had reversed itself, and the electric utilities’ share declined to 91 

percent.75 By 2004, regulated electric utilities' share of total generation continued to decline 

 

73 Id. at 23. 74 EIA 1970-1991 at vii. 

75 Id.

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 of the reasons suggested for the decline in transmission investment between 1975 and 1997 

(see Figure 1-4) are: 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. 

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

transmission lines. Siting can bring long delays and negative publicity. NIMBY-based local opposition is 

usually strong. Also, many state processes require a showing of benefits to the state to site a transmission line. 

This can create barriers for transmission facilities that primarily benefit interstate commerce. 
29

(63.1 percent in 2004 versus 63.4 percent in 2003) as IPPs’ share increased (28.2 percent versus 

27.4 percent in 2003).76 

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

generation suppliers, as shown in Figure 1-5 below. While most of the existing capacity, and 

until the late 1980s, most of the additions to capacity, have been built by electric utilities, their 

share of capacity additions declined in the 1990s. Between 1996 and 2004, roughly 74 percent 

of electricity capacity additions have been made by independent power producers. 

Figure 1-5: U.S. Electric Generating Capacity Additions: Non-Utility Growth Overtakes 

Utility in 2000-2004 

 

0

10

20

30

40

50

60

70

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Capacity (GW)

NON-UTILITY

UTILITY

Source: FERC Analysis of Platts PowerDat data 

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 (after adjusting for 

inflation) in real terms.77 On a national level, 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.78 Real retail prices have since stayed flat through 2004. 

 

76 U.S. Dept. of Energy, Energy Information Administration, Electric Power Annual 2004, at 2 (November 2005), 

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

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

78 Joskow, Difficult Transition at 7. 
30

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

1- In chained (2000) dollars, calculated by using gross domestic product implicit price deflators. 

 Source: Energy Information Administration Annual Energy Review 2004 

4. Changing Patterns of Fuel Use for Generation – Reaction to Increased Oil Prices and 

Clean-Air Environmental Regulations

For utilities, coal was the fuel most commonly used for many years, providing 46 percent of 

utilities’ generation in 1970 and more than 50 percent since 1980. When world oil prices 

escalated in the 1970s, oil-fired and gasoline-fired generation’s share of electricity supply began 

decreasing. 

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

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

sites for hydroelectric projects. Nuclear power grew to be the second largest fuel source in 1991 

but was not expected to continue to increase.79 

For nonutilities, natural gas has been the major fuel. Indeed, new capacity added in recent years 

shows the prevalence of natural gas to fuel new plants. 80 As shown in Figure 1-7, recent plant 

additions illustrate this change in fuel sources. This increased use of natural gas also is due, in 

part, to the Clean Air Act Amendments of 1990 (CAA) and state clean air requirements. 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 generating plants. The CAA fundamentally changed the generation business 

because it would no longer be costless to emit air pollutants. As a result of these requirements, 

 

79 EIA 1970-1991 at 20. 

80 EIA Electric Power Annual 2004 at 2. 
31

many generation owners and new generation plant developers turned to cleaner-burning natural 

gas as the fuel source for new generation plants. California has been very dependent on gas-fired 

generation because of its specific air quality standards.81

Figure 1-7: Gas Has Recently Been Dominant Fuel 

 

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 

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. 

 

81 Fed. Energy Regulatory Comm’n, 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 
32

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

January-December 2005 

49.9%

18.6%

6.4%

19.3%

3.0% 2.8%

Coal

Natural Gas

Hydroelectric

Nuclear

Petroleum

Other Energy Sources

 Source EIA, Electric Power Monthly with data for December 2005. 

The trend toward gas-fueled capacity additions may be changing, however. In the coming years, 

more coal-fired generation capacity may be built. Two major reasons may explain coal’s 

resurgence: (1) the relative price of natural gas compared to coal has increased substantially in 

recent years and (2) the cost of environmental equipment for coal plants, such as scrubbers, has 

decreased. To the extent that 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 significantly higher, both these assumptions have proved questionable 

with time. The Department of Energy’s Energy Information Administration (EIA) estimated 

only 573 megawatts of new coal generation would be added nationally in 2005, which compares 

with an estimate of 15,216 megawatts of gas-fired additions for the same year. For the year 

2009, however, predicted trends shift - the EIA projects that 8,122 MW of new coal generation 

will be added that year, whereas only 5,451 MW of gas-fired generation additions are predicted 

for that year.82 The Department of Energy predicts a resurgence of coal-fired generation will 

continue as far into the future as 2025.83

5. Price Changes in Fuel Sources

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

of petroleum prices. Natural gas prices experienced a 51.5 percent increase between 2002 and 

2003, a 10.5 percent increase between 2003 and 2004, and a 37.6 percent increase between 2004 

and 2005. Strong demand for natural gas, as well as natural gas production disruptions in the 

Gulf of Mexico, contributed to these price increases. As shown in Figure 1-9, for December 

2005 the overall price of fossil fuels was influenced by the increases in price of natural gas. In 

December 2005, the average price for fossil fuels was $3.71 per MMBtu, 10.1 percent higher 

than for November 2005, and 44.4 percent higher than in December 2004. As natural gas prices 

 

82 See EIA Electric Power Annual 2004 at 17, table 2.4, available at

http://www.eia.doe.gov/cneaf/electricity/epa/epat2p4.html. 

83 See U.S. Dept. of Energy, Nat’l Energy Tech. Lab, Tracking New Coal-Fired Power Plants, at 3-4, available at

http://www.netl.doe.gov/coal/refshelf/ncp.pdf (predicting 85 GW of new coal capacity created by 2025). 
33

increase relative to coal prices, the change may make development of clean-burning coal plants 

more economical than they were when natural gas fuel prices were lower. 

Figure 1-9: Electric Power Industry Fuel Costs, 

January 2005 through December 2005 

Source: Source EIA, Electric Power Monthly with data for January 2006. 

 

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

Many IOUs have fundamentally reassessed their corporate strategies to function more as 

competitive, market-driven businesses in response to an increasingly competitive business 

environment.84 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 subsidiary within the company.85 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.86 

 

84 See U.S. Congress, Office of Technology Assessment at 47. 85 EIA 2000 Update at 91. 

86 Id. at 105-06. 
34

Since 1997, IOUs have divested power generation assets at unprecedented levels,87 and these 

power plant divestitures have also reduced the total number of IOUs that own generation 

capacity.88 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.89 As described in Table 1-6 below, between 1998 and 2001, over 300 plants, 

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

There was no significant electric power company merger activity from 2001 to 2004, but this 

changed in 2004, when utilities and financial institutions exhibited growing interest in mergers 

and acquisitions, prompting many analysts to herald 2004 as the inauguration of a new round of 

consolidation in the power sector.90 One utility-to-utility acquisition was closed91 and three were 

announced.92 Most electric acquisitions in 2004 took place with 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 2004.93

Table 1-6: Power Generation Asset Divestitures by Investor-Owned Electric Utilities, as of 

April 2000 

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 2000 Update, Table 19 

 

87 Id. at 105. 88 Id. at 91. 

89 Id. at 106. 

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

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

92 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. 

93 Id. at 30. 
35

CHAPTER 2 

CONTEXT FOR THE TASK FORCE’S STUDY OF COMPETITION IN 

WHOLESALE AND RETAIL ELECTRIC POWER MARKETS

This chapter provides the context to the Task Force’s study of competition in wholesale and 

retail electric power markets. For approximately 70 years, state and federal policymakers 

regulated the generation, transmission, and distribution of electric power as natural monopolies – 

it was considered inefficient to have multiple sources of generation, transmission, and 

distribution facilities serving the same customers. The traditional “regulatory compact” required 

an electric power utility to serve all retail customers in a defined area in exchange for the 

opportunity to earn a reasonable return on its investment. This approach is often called “costbased” or “cost-plus” regulation. 

Technological and regulatory changes as discussed in Chapter 1 negated the natural monopoly 

assumption for the most capital intensive segment of the industry – the generation of electric 

power. Federal and several state policymakers introduced competition to provide for an 

economically efficient allocation of resources within the industry’s generation sector and to 

overcome the perceived shortcomings of traditional cost-based regulation. This chapter 

describes these shortcomings. It also discusses the role of price in guiding consumption and 

investment decisions in competitive markets. 

This chapter highlights three issues that policymakers confronted as they considered introducing 

competition into wholesale and retail electric power markets. First, customers under historical 

cost-based regulation generally paid average prices calculated over an extended period of months 

or years that did not vary with their consumption or with variation in the cost of generating 

electric power. Thus, wholesale and retail customers did not receive economically accurate price 

signals to guide their consumption decisions. Similarly, suppliers did not receive economically 

accurate price signals to guide their short term sales of existing generation and long term 

generation . Second, regulators had historically encouraged local utilities to build or contract for 

sufficient generation to serve customers within their territories and they erected entry barriers to 

block entry by independent generators. These actions resulted in utilities owning nearly all 

generation assets within their own service territories. Under cost-based regulation, the regulator 

would set the price for electric power, thus addressing possible market power abuses that 

otherwise could occur with the monopoly utility structure. Third, certain physical realities 

associated with electricity generation constrain regulatory and market options in this industry. 

The inability to economically store electric power means that electricity must generally be 

consumed as soon as it is generated – supply must always exactly equal demand in real time. 

The delivery of electric power depends, however, upon availability and pricing of the regulated 

transmission grid. Thus, the physical realities of the transmission grid must be considered as 

competition develops in wholesale electric power markets. 

The Task Force received many comments identifying or endorsing various studies on aspects of 

the costs and benefits of competition in wholesale and retail electric power markets, particularly 

the formation of Regional Transmission Organizations (RTOs) or similar entities. 
36

Appendix C contains an annotated bibliography of these studies. Many of these studies, 

however, provide only limited insights into the effect of restructuring in wholesale and retail 

electric power markets. See Box 2-1 that describes a recent Department of Energy review of 

such studies. This Report addresses competition in various wholesale and retail markets 

regardless of whether they contain an RTO or similar entity. 

A. Overview of Cost-Based Rate Regulation – Effect on Customer Prices and 

Investment Decisions 

State policymakers imposed rate regulation on retail sales of electric power because allowing 

prices to be set by the monopolist was expected to lead to uneconomic results, namely higher 

prices with lower output. Regulators used cost-based regulation to meet state legal requirements 

to ensure sufficient output at reasonable prices for consumers. 

1. Effect on Customer Prices

Retail prices for most customers, although different for each customer class, often were average 

prices calculated over an extended period of months or years that did not vary with their 

consumption or with the costs of generating electric power. These rates were stable and often 

Box 2-1 

“A Review of Recent RTO Benefit-Cost Studies: Toward More Comprehensive 

Assessments of FERC Electricity Restructuring Policies” 

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

This paper provides a review of the state of the art in RTO Cost/Benefit studies and suggests 

methodological improvements for future studies. The study draws the following 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 of these 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 absence of 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 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 not be to simply improve current methods, 

but to establish a more robust empirical basis for ongoing assessment of the electric industry’s 

evolution. These efforts should be devoted to studying 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. 
37

only varied by season (e.g., summer rates may be higher than winter rates). Although time-based 

rates and certain regulated products such as interruptible or curtailable services have been used 

within the electric power industry for decades, they have not been applied to the vast majority of 

retail customers. In addition, many argued that retail rate structures contain cross-subsidies 

among customer classes.94

2. Effect on Investment Decisions

The usual market-based signal for efficient investment into a market – prices that align consumer 

demand with generators’ supply under given market conditions – is unavailable under cost-based 

rate regulation of retail electric power prices. Under cost-based rate regulation, utilities could 

decide when to add generation, but their recovery of their costs for these investments was 

dependent on state regulators agreeing that the generation was necessary and prudent. (Most 

state also imposed siting regulation on construction of major electric power facilities). Thus, it 

was long term planners and regulators that determined when generation would be built, and it 

was consumers who bore the cost of investment risks once they had been approved by the state 

regulators. Utilities were reluctant to take investment risks that might end up being 

unrecoverable if the regulators deemed their cost unreasonable. By far, the most important of 

these decisions was for generation investment which constitutes the substantial majority of the 

capital investment in the electric power industry. While the intent of cost-based rate regulation, 

was not simply to keep price down, the effect was sometimes to dampen investment in new 

capacity and innovation.95 In making decisions, regulators struggled to strike the balance 

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

investments. 

Regulatory mistakes in setting rates too high or too low may lead to excessive or inadequate 

additions of new electric power generation and other forms of investment. If rates are set too 

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

by the cost of capital. The result could be overinvestment and overbuilding. Utilities also had 

little incentive to design new generation plants in a cost-effective manner, to the extent 

regulators were unlikely to identify and disallow excessive costs to be included in customer 

rates. 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.96

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

1986). 

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

96 In the academic literature, the risk of utility overinvestment has been explained by the Averch-Johnson 

Effect. The Averch-Johnson Effect reflects that “a firm that is attempting to maximize profits is give, 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). 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. 
38

Indeed, a 1983 Department of Energy analysis of electric power generation plant construction 

showed that electric utilities (which were regulated under a cost-based regulatory regime) had 

little ability to control the construction costs of coal and nuclear generation plants. During the 

1970s and early 1980s, the cost range per megawatt to build a nuclear plant varied by nearly 

400 percent and by 300 percent for coal plants. The DOE study showed that some companies 

were not competent to manage such large-scale, capital-intensive projects. In addition, there was 

a tendency to custom design these plants, as opposed to use of a basic design and then refining 

it.97 

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

approach, the regulator caps the price a firm is allowed to charge.98 This alternative may remedy 

some of the incentive problems of cost-base regulation. Another alternative is Integrated 

Resource Planning, which provided that choices about the building of new generation would be 

controlled by the regulator. Even with this oversight mechanism, regulators had few reference 

points to determine prudence in the choices that the builder made about design, efficiency, and 

materials. 

In part, the struggles of regulators to ensure adequate supplies of power at reasonable rates led 

policy makers to examine whether competition could provide more timely and efficient 

incentives for what to consume and build. Advances in technology negated the assumption that 

generation is a natural monopoly, and thus set the stage for price and competition to provide a 

market entry signal, although transmission and distribution would continue to be regulated. 

B. Competition in Wholesale and Retail Electric Power Markets – The Role of Price 

With competition, the price of a commodity such as electric power generally reflects suppliers’ 

 97 U.S. Dept. of Energy, The Future of Electric Power in America: Economic Supply for Economic 

Growth, June, 1983 (DOE/PE-0045). 

98 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. 

Box 2-2 

Market Prices 

Market prices reflect myriad individual decisions about prices at which to sell or buy. Market prices are 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. 
39

costs and consumers’ willingness to pay. The price signals the relative value of that commodity 

compared to other goods and services. 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. 

1. Price Affects Customer Consumption

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 generally 

provide a signal to customers to reduce the amount they consume. The dampening effect on 

price of a reduction in consumption helps consumers safeguard themselves against a supplier that 

may seek to exercise market power by increasing prices. By contrast, lower prices may 

encourage some customers to consume more than they would have at higher prices. Price 

changes thus play an important economic function by encouraging customers and suppliers to 

respond to changing market conditions. In the electric power industry, consumer’s price 

responsiveness is often referred to as “demand response.”99 

The primary objective to incorporate price-based signals into wholesale and retail electric power 

markets is to provide consumers with price signals that accurately reflect the underlying costs of 

production. These signals will improve resource efficiency of electric power production due to a 

closer alignment between the price that customers pay for and the value they place on electricity. 

In particular, by exposing customers (some or all) to prices based on marginal production costs, 

resources can be allocated more efficiently.100 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.”101 Exposure of customers to efficient price 

 99 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 (DOE EPAct Report). The DOE EPAct Report discusses the benefits of demand response in 

electric power markets and makes recommendations to achieve these benefits. 

100 There is a substantial literature on setting rates based on marginal costs in the electric sector. See for 

example, M. Crew and P. Kleindorfer, Public Utility Economics. St. Martin’s Press: New York, 1979 and B. 

Mitchell, W. Manning, and J. Paul Acton, Peak-Load Pricing. Ballinger: Cambridge, 1978. Other papers suggest 

that setting rates based on marginal costs will result in a misallocation of resources (see Borenstein, S., The LongRun Efficiency of Real-Time Pricing, ENERGY JOURNAL, Vol. 26, No. 3, 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 (see Viscusi, Vernon, and 

Harrington, Economics of Regulation and Antitrust, MIT Press, 2000) and allocation of shortfalls to rate classes. 

101 DOE EPAct Report, p. 7 
40

signals also has the benefit of increasing price response during periods of scarcity and high 

prices, which can help moderate generator market power and improve reliability. 

When customers have many close substitutes for a particular good, a relatively small price 

increase will result in a relatively large reduction in how much they consume. For example, if 

natural gas were a very good substitute for electric power at comparable prices, then even a 

relatively small increase in the price of electric power could persuade many consumers to switch 

in part or entirely to natural gas, rather than electricity. To induce those consumers to return to 

using electricity, electricity prices would not need to fall by very much. However, when there 

are no close substitutes for electric power, prices may have to rise substantially to reduce 

consumption in order to restore the balance between the quantity supplied and the quantity 

demanded. 

A substantial body of empirical literature has shown that, even if the retail price of electricity 

increases relatively quickly and sharply, the short-run consumption of electricity does not decline 

much. In other words, short-run demand for electricity is very inelastic. See Box 2-3. 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 their demand when prices rise. Furthermore, electric 

power has few viable and economic substitutes for key end-uses such as refrigeration and 

lighting and thus the consequences for supply shortfalls can be significant.102 In the long run, 

this effect may be somewhat muted as, with time, electricity customers may have more ability to 

adjust their consumption in response to price changes 

 102 Estimates of the total costs in the United States due to August 14, 2003 blackout range between $4 

billion and $10 billion. ELCON, The Economic Impacts of the August 2003 Blackout, February 2, 2004. 

Box 2-3 

Demand Elasticity 

The desire and ability of consumers to change the amount of a product they will purchase when its price 

increases is known as the price elasticity of 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%/10%). 

If the ratio is close to zero demand is considered "inelastic", and demand is more "elastic" as the ratio increases, 

especially if the ratio is greater than -1. Short-run elasticities are typically lower than long-run elasticities. 
41

Experience in New York, Georgia, California, and other states and pricing experiments have 

demonstrated that customers have adjusted their consumption, and are 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 has found that industrial customers who receive RTP based on 

an hour-ahead market are somewhat price-responsive (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. Similar elasticities were found in the National Grid RTP pricing program. 

A critical peak pricing experiment in California in 2004 determined that small residential and 

commercial customers are price responsive and will make significant reductions in 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 who were placed on the CPP tariffs had a favorable opinion of the rates and 

would be interested in continuing in the program.103

The ability of a customer to respond to prices requires the following conditions: (1) that timedifferentiated 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 what time and bill accordingly).104 Most conventional metering and billing systems 

are not adequate for charging time-varying rates and most customers are not used to considering 

price changes in making electricity consumption decisions on a daily or hourly basis. 

2. Supplier Responses Interact with Customer Demand Responses to Drive Production

Generation supply responses are equally important in determining an appropriate equilibrium 

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 will be the 

cost of expanding that output. With more time, firms have more opportunity to change their 

operations or invest in new capacity. 

If the cost of increasing production is small, then a relatively small price increase may be enough 

to encourage existing producers to increase their production levels to provide additional supply 

in response to increased demand.. If the cost of increasing electricity capacity is high, however, 

existing suppliers will not increase their production without a very strong price signal. In that 

case, customers would have to pay significantly higher prices to obtain additional supply. 

Additionally, if suppliers are already producing as much electric power as they can, increased 

demand can be met only from new capacity, and suppliers must be confident that prices will 

remain high enough for long enough to justify building a new generating plant. 

 103 Charles River Associates, Impact Evaluation of the California Statewide Pricing Pilot, Final Report, 

March 16, 2005, available at http://www.energy.ca.gov/demandresponse/documents/group3_final_reports/2005-03-

24_SPP_FINAL_REP.PDF . Customers on a similar CPP program at Gulf Power also have high satisfaction with 

the program, which incorporates automated response to CPP events. 

104 EEI; 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. 
42

These supply decisions are complicated because electric power cannot be stored economically, 

thus there are generally no inventories in electricity markets. Therefore, electricity generation 

must always exactly match electricity consumption.105 The lack of inventories means that 

wholesale demand is completely determined by retail demand. Moreover, any distant generation 

must “travel” over a transmission system with its own limiting physical characteristics. 106 

Transmission capability is required to allow customers access to distant generation sources. The 

transmission system is complicated by the fact that the dynamics of the AC transmission grid 

create network effects and can produce positive externalities (depending on the method used in 

accounting for transmission costs).107 That is to say, where transmission users are not charged 

for the congestion impacts of their use patterns, that user’s actions can cause costs to other users 

– costs which the causal party is not obligated to pay. This dynamic can distort the effect of 

price signals on dispatch efficiencies. 

Moreover, aggregate retail demand fluctuates throughout the day, with higher demand during the 

day than at night. Fluctuating demand means that the transmission operator must have sufficient 

capacity to equal or exceed customer demand in real-time. Load serving entities (those entities 

that deliver power to meet demand or “load”) must supply or procure sufficient capacity and 

energy (either in long-term contracts or short-term “spot” market purchases) to meet these 

varying loads. The costs of generating electricity are also highly variable, leading to wide 

disparity between the costs of generating electricity from generation plants that operate aroundthe-clock versus the cost of those that generate only during peak periods. 

In any case, a higher price signals a profit opportunity, attracting resources where they are 

needed. If customer demand decreases in response to rising prices, prices are likely to fall, all 

else equal. In that circumstance, falling demand signals suppliers to reduce the amount of 

electric power that they supply. Suppliers will reduce their generation to meet the new, lower 

level of consumer demand, and will not be inclined to consider any new capacity increases. 

 

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

 105 APPA 

106 Alcoa 

107 TAPS 
43

In sum, the combined impact of consumers’ and suppliers’ responses to changed market 

conditions will 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 very 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 

consumers and producers incentives to change their behavior, they may have little ability to do 

so in the short term. Over much longer time frames, however, both consumers and producers 

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. 
44

CHAPTER 3 

COMPETITION IN WHOLESALE ELECTRIC POWER MARKETS 

A. Introduction and Overview

Congress required the Task Force to conduct a study of competition in wholesale electric power 

markets. Wholesale markets involve sales of electric power among generators, marketers, and 

load serving entities (e.g., distribution utilities) that ultimately resell the electric power to enduse customers (e.g., residential, commercial, and industrial customers). Prior to the introduction 

of competition, vertically integrated utilities with excess electric power sold it to other utilities 

and to wholesale customers such as municipalities and cooperatives that had little or no 

generating capacity of their own. The Federal Energy Regulatory Commission (FERC) and its 

predecessor agency (the Federal Power Commission) regulated the prices, terms and conditions 

of interstate wholesale sales by investor-owned utilities. The desire of wholesale purchasers for 

access to competitive sources of electric power was a fundamental impetus to the opening of the 

generation sector to competition.108

Effective competition ensures an economically efficient allocation of resources. Congress in the 

Energy Policy Act of 1992 (EPACT 92) determined that competition in wholesale electric power 

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 owned transmission lines; and (2) elimination of entry barriers so non-utility entry 

could occur. The former change permitted wholesale customers to purchase supply from distant 

generators and the latter change provided customers with competitive alternatives from 

independent entrants.109 

As described in Chapter 2, an important component of effective market operation is customer 

response to prices. The demand for wholesale power, however, is derived entirely from 

consumption choices at the retail level. The lack of electric power inventories only intensifies 

the direct link between wholesale and retail electric power markets. Yet state regulators set the 

prices for retail customers. State regulators generally have treated wholesale rates as an input 

into retail prices. But states often set retail rates that dilute the direct impact of the price of 

wholesale power on retail prices.110 Thus, retail consumption decisions have been guided by 

prices, terms, and conditions that often do not directly reflect the wholesale price to purchase the 

electric power or the cost generators incurred to produce it. 

This price disconnect is heightened by the fact that, if competition is to allocate resources in an 

economically efficient manner, customers must have access to a sufficient number of competing 

 108 US v. Otter Tail Power Company, 410 U.S. 366 (1973) (the United States sued a vertically integrated 

utility for refusal 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). 

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

110 See infra Chapter 1. 
45

suppliers either via transmission or from new local generation.111 But one of the shortcomings of 

cost-based rate regulation was its inability to provide incentives for investors to make 

economically efficient decisions concerning when, where, and how to build new generation. 

Thus, the question 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. In other words, has competition in wholesale 

electric power markets resulted in an economically efficient allocation of resources? The answer 

to this question is difficult to derive because each region was at a different regulatory and 

structural starting point upon Congress’ enactment of the Energy Policy Act of 1992. These 

differences make it difficult to single out the determinants of consumption and investment 

decisions and thus make it difficult to evaluate the degree to which more competitive markets 

have influenced such decisions. Even the organized exchange markets have different features 

and characteristics. For example, some regions already had tight power pools, others were more 

disparate in their operation of generation and transmission. Some regions had higher population 

densities and thus more tightly configured transmission networks than did others. Some regions 

had access to fuel sources that were unavailable or less available in other regions (e.g., natural 

gas supply in the Southeast, hydro-power in the Northwest). Some regions operate under a 

transmission open-access regime that has not changed since the early days of open access in 

1996, while other regions have independent provision of transmission services and organized 

day-ahead exchange markets for electric power and ancillary services. 

This chapter discusses the impact of competition for generation supply on the ability of 

wholesale customers to make economic choices among suppliers and for suppliers to make 

economic investment decisions. The chapter addresses how entry has occurred in several regions 

with different forms of competition (e.g., the Midwest, Southeast, California, the Northwest, 

Texas, and the Northeast). This chapter also discusses 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. These observations highlight the trade-offs involved 

with various policy choices used to introduce competition. 

B. Background 

Congress enacted the EPACT 92 to jump start competition in the electric power industry. One of 

the stated purposes of the EPACT 92 was “to use the market rather than government regulation 

wherever possible both to advance energy security goals and to protect consumers.”112 Policy 

makers recognized that vertically integrated utilities had market power in both transmission and 

generation – that is they owned all transmission and nearly all generation plants within certain 

geographic areas. Congress, therefore, enhanced FERC’s authority to order utilities, case-by-

 111 See, e.g.,U.S. Gen. Accounting Office, GAO-03-271, LESSONS LEARNED FROM ELECTRIC

INDUSTRY RESTRUCTURING 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”). 

112 H.R. No. 102-474(I) at 133. 
46

case, to transmit power for alternative sources of generation supply. 

Today, vertically integrated utilities that operate their transmission systems generally offer 

transmission service under the terms of the standard Open Access Transmission Tariff (OATT) 

adopted by FERC in Order No. 888. The OATT requires a utility to offer the same level of 

transmission service, under the same terms and conditions and at the same rates that it provides 

to itself. Vertically integrated utilities (also referred to here as the transmission provider) offer 

two types of long-term transmission service under the OATT: network integration transmission 

service (network service) and point-to-point transmission service. See Box 3-1 for a description 

of both types of transmission service. For both services, the price has been predictable and stable 

over the long term.113 

 113 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 costs of the expansion are added to the revenue 

requirement, the distribution of the costs over the whole system has allowed the charges to individual customers to 

remain relatively stable. Customers who take either kind of 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 

stated in the transmission provider’s tariff) for that service if another customer offers a higher rate. 
47

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 includes 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 the basic transmission 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, some additional charges may be incurred. 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. 

Also, 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 to the system are needed to maintain service to a network customer, the costs of the upgrades or 

expansions 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 the transmission of energy 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 either the transmission 

provider’s embedded costs to provide the service, or the incremental costs of any system expansion needed to 

provide the service. Also, 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. 
48

The comments submitted in response to the Task Force’s request raised several concerns as to 

transmission-dependent customers’ access to alternative generator suppliers via OATTs. In 

particular, some commenters noted that there is a continued possibility of transmission 

discrimination in their region, and that ability for transmission suppliers to discriminate can deny 

transmission-dependent customers access to alternative suppliers.114 The commenters conclude 

that transmission discrimination can increase delivery risk because purchasers feared that their 

transmission transactions might be terminated for anticompetitive reasons by their vertically 

integrated rival, were they to purchase generation from a generator who is not affiliated with the 

transmission provider. The fact that electricity cannot be stored economically and electricity 

demand is very inelastic in the short term heightens the ill-effects of this delivery risk. 

One response to this risk is to turn over operation of the transmission grid in a region to an 

independent operator, like the ones that now operate in New England, New York, the MidAtlantic, Texas, and California (“organized markets”). With the market design in these regions, 

there is no risk that a wholesale customer will not be able to deliver power to its retail customers 

(although they remain exposed to price risk).115 See Box 3-2 for a discussion of how 

transmission is provided in organized wholesale markets. 

 114 APPA, TAPS. See also Midwest Stand Alone Transmission Companies. 

115 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. 
49

In regions with RTOs, wholesale electricity can be bought and sold through the use of 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 and have terms and conditions unique to a single transaction. 

Standard products are available through brokers and over-the-counter (OTC) exchanges such as 

the NYMEX and Intercontinental Exchange (ICE).116 Standard products have a standard set of 

specifications so that the main variant is price. Finally, there are organized exchange markets 

operated by the RTOs. In addition to offering transmission services, these organized exchange 

markets offer various products including electric power and ancillary services. Electric power 

markets typically involve sales of electric power in both hour-ahead and day-ahead markets. 

 116 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, we discuss 

contracts for physical delivery rather than financial contracts, unless otherwise noted. 

Box 3-2 

How Transmission is Priced in an ISO or RTO: 

 ISOs and RTOs (hereinafter RTOs) provide transmission service over 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 the 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 

and time are the same. 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. 

All existing organized markets have a uniform price auction or exchange to determine the price of electric power. 

Because of this variation in exchange prices at different locations, a transmission customer is unable to determine 

beforehand the price for electric power at any location because congestion on the grid changes constantly. 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 electric power 

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 less 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 05, FERC has begun a rulemaking to ensure the 

availability of long-term FTRs. 
50

Ancillary services include various categories of generation reserves such as spinning and nonspinning reserves in addition to Automatic Generation Control (AGC) for frequency control. 

The question remains, however, 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? The next section reviews generation entry in different regions. 

C. Generation Investment Has Varied by Region since Competition Increased in 

Wholesale Electric Power Markets 

Since the adoption of open access transmission and the growth of competition, the amount of 

new generation investment has varied significantly by region. Figure 3-1 shows the overall 

pattern of new investment, broken down by region. A substantial amount of new investment has 

occurred in the Southeast, Midwest, and Texas. Other regions have not experienced as much 

investment. Wholesale customers obtain transmission services under different pricing formats in 

each region. Moreover, the regions that operate exchange markets for electric power and 

ancillary services use different forms of locational pricing, price mitigation, and capacity 

markets. 

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 the 

challenge to create markets with sufficient supply choices to support competition and to allocate 

resources efficiently. 
51

 

1. Midwest

Wholesale Market Organization: In 2004, the Midwest RTO began providing transmission 

services to wholesale customers in its footprint. On April 1, 2005, the MISO commenced its 

organized electric power market operations. Prior to this time, wholesale customers obtained 

transmission under each utility’s OATT and there were no centralized electric power exchange 

markets. 

New Generation Investment: The Midwest experienced a wholesale price spike during the 

summer of 1998.117 An increase in demand due to unusually hot weather combined with 

unexpected generation outages created a rapid spike in wholesale prices. A significant amount 

of new generation was built in response to the price spike as shown in Table 3-1. For example, 

from January 2002 through June 2003, the Midwest added 14,471 MW in capacity.118

Most of the new generation was gas-fired, even though the region as a whole relies primarily on 

coal-fired generation.119 More-recent entry has in fact been coal fired, in part because of rising 

natural gas prices.120 The results of this entry and the subsequent drop in wholesale power prices 

have included: (1) merchant generators in the region declaring bankruptcy and (2) verticallyintegrated utilities returning certain generation assets from unregulated wholesale affiliates to 

rate-base. 

2. Southeast

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. 

New Generation Investment: The Southeast’s proximity to natural gas sources in the Gulf of 

Mexico and pipelines to transport that natural gas have made natural gas 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 2005,121 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 new generation in the Southeast was non-utility merchant generation. 

A number of merchant companies that built plants in the 1990s have sought bankruptcy 

protection. Often, the plants of the bankrupt companies have been purchased by local vertically-

 117 Fed. Energy Regulatory Comm’n, Staff Report to the Fed. Energy Regulatory Comm’n on the Causes of 

Wholesale Electric Pricing Abnormalities in the Midwest During June 1998 (1998). 

118 FERC State of the Markets Report 2004 at 109. 

119 FERC State of the Markets Report 2004 at 50. 

120 FERC State of the Markets Report 2005 at 77 121 Southern Companies. 
52

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.122 Even apart 

from bankruptcies, some independent power producers have withdrawn from the region. 

3. California

Wholesale Market Organization: The California ISO began operation in 1998 to provide 

transmission services. Concurrently, a separate Power Exchange (PX) operated electric power 

exchanges. Subsequent to the 2000-01 energy crisis, the California dissolved the PX. 

New Generation Investment: Even prior to the California energy crisis, California was 

dependent on imported electric power from neighboring states. Much of the generation capacity 

for 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. Since 2000-01, demand has increased in California, but construction of local 

generation has not kept pace. Over 6,000 MW of new generation capacity has entered California 

in 2002-03, but very little of it was built in congested, urban areas like San Francisco, Los 

Angeles and San Diego.123 The commenters acknowledged that significant new generation has 

been announced or built in California in the past few years, but most of the projects have been in 

Northern California.124 In the past five years, transmission investment has improved links 

between Southern and Northern California and accessible generation investment in the 

Southwest more generally has increased. 

4. The Northeast

a. New England

Wholesale Market Operation: The New England ISO (ISO-NE) provides transmission services 

as well as operating a centralized electric power market. Under the electric power pricing 

mechanism adopted by the New England ISO, the expensive units used to maintain resource 

adequacy in some local areas are often not eligible to set the market clearing price because of the 

ISO’s use of must-run reliability contracts. Rather, the cost of these high-priced units is spread 

across the region to all users. 

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

populated areas of the region, such as Maine, but much of the demand for power is in southern 

New England. From January 2002 through June 2003, ISO-NE added 4159 MW in capacity.125 

 122 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. 

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

124 California ISO. 

125 FERC State of the Markets Report 2004 at 109. 
53

Capacity additions in 2004 were less 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. 

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 

transmission congestion prevents use of distant generation units to meet local demand. These 

pockets have not seen entry of generation to meet that demand. 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 or increased transmission investment to 

reduce congestion. 

Moreover, the need for more supply in these load pockets is not reflected in high locational 

prices that would signal investment.126 ISO-NE has recognized this issue and in 2003, it 

implemented a temporary measure known as Peaking Unit Safe Harbor (PUSH). PUSH enabled 

greater cost recovery for high-cost, low-use units in designated congestion areas, although PUSH 

units still may not be able to recover completely all their fixed costs.127 ISO-NE also seeks to 

establish a locational capacity product that will project the demand three years in advance and 

hold annual auctions to purchase power resources for the region’s needs. This proposal is part of 

a settlement pending before FERC. ISO-NE originally proposed a different market model called 

Locational Installed Capacity (LICAP). That model was opposed by a variety of stakeholders.128

b. New York

Wholesale Market Operation: The New York ISO (NYISO) provides transmission services as 

well as operating a centralized electric power market. On the one hand, NYISO uses price 

mitigation to guard against wholesale price spikes but, on the other, it allows high cost 

generators to be included in marginal location prices. 

New Generation Investment: New York has traditionally built generation in less populated areas 

and moved it to more populated areas. For example, the New York Power Authority was 

responsible for getting 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.129 

Three generating plants with a total summer capacity of 1,258 MW came on line in 2004. Three 

plants totaling 170 MW retired in 2004.130 

 

126 FERC State of the Markets Report 2005 at 83. 

127 FERC State of the Markets Report 2004 at 36. 

128 Press Release, ISO New England, ISO New England Announces Broad Stakeholder Agreement on New 

Capacity Market Design (Mar. 6, 2006), available at http://www.isone.com/nwsiss/pr/2006/march_6_settlement_filing.pdf. 

129 FERC State of the Markets Report 2004 at 109. 

130 FERC State of the Markets Report 2005 at 97. 
54

Transmission constraints are therefore a concern, and currently, transmission constraints in and 

around New York City limit competition in the city and lead to more use of expensive local 

generation, thereby raising prices. NYISO uses price mitigation that seeks to avoid mitigating 

high prices that are the result of genuine scarcity, though 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 capacity construction, NYISO also sets a more generous 

“reference price” for new generators in their first three years of operation.131 (Bids above the 

reference prices may trigger price mitigation.) Unlike New England, New York is seeing new 

generation investment in a congested area. Approximately 1,000 MW of new capacity is 

planned to enter into 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 clearer market price signals in New York, both in energy markets and capacity markets. 

The effect of load pockets on prices are 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. 

Figure 3-2: Estimate of Annual NY Capacity Values - All Auctions 

0.00

20.00

40.00

60.00

80.00

100.00

120.00

2002 2003 2004 2005 2006 YTD

Est. $/kW-yr

LI

NYC

ROS

c. PJM

Wholesale Market Operation: The PJM Interconnection provides transmission services as well 

as operating a centralized electric power market. PJM has both energy and capacity markets. 

PJM’s energy market has locational prices. FERC recently approved the concept of PJM’s 

 

131 FERC State of the Markets Report 2004 at 39. 
55

proposal to shift to locational prices in its capacity markets.132 The locational capacity market 

has not yet been implemented. 

New Generation Investment: PJM capacity includes a broad mix of fuel types. Recent PJM 

expansion has added significant low-cost coal resources to PJM’s overall generation mix. From 

January 2002 through June 2003, PJM added 7458 MW in capacity.133 Capacity additions in 

2004 were lower than in the two previous years. 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.134

Like other areas, PJM depends on transmission to move power from the areas of low-cost 

generation to the areas of high demand. In PJM, 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 a set of transmission lines known as the Eastern Interface, which at 

times limits the deliverability of generation from the west. This means that higher-cost 

generation must be run in the eastern region to meet local demand. Within the eastern region, 

there are also areas of still-more-limited transmission. As a result of these kinds of transmission 

limitations, generation in some areas that is not economical to run is being given reliability mustrun (RMR) contracts to prevent it from retiring and possibly reducing local reliability.135 

Recently, three utilities in PJM have proposed major transmission expansions to increase 

capacity for moving power from into eastern parts of PJM.136

5. Texas 

Wholesale Market Operation: The Electric Reliability Council of Texas (ERCOT) manages the 

scheduling of power on an electric grid consisting of about 77,000 megawatts of generation 

capacity and 38,000 miles of transmission lines. ERCOT also manages financial settlement for 

market participants in Texas's deregulated wholesale bulk power and retail electric market. 

ERCOT is regulated by the Public Utility Commission of Texas. ERCOT is generally not 

subject to FERC jurisdiction because it does not integrated with other electric systems, i.e., there 

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

133 FERC State of the Markets Report 2004 at 109. 

134 FERC State of the Markets Report 2005 at 112. 

135 Id. at 188. 

136 American Electric Power 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 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 Penninsula and into New Jersey. 
56

is not 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. 

In ERCOT, for each year, ERCOT determines a set of transmission constraints within its system 

which it deems Commercially Significant Constraints (CSCs). These constraints create 

Congestion Zones for which zonal "shift factors" are determined. Once approved by the ERCOT 

Board, the CSCs and Congestion Zones are used by the ERCOT dispatch process for the next 

year. In 2005, ERCOT has six CSCs and five Congestion Zones. When the CSCs bind, ERCOT 

economically dispatches generation units bid against load within each zone. To keep the system 

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

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.137 

At least one study argues that when there is local congestion, local market power is mitigated in 

ERCOT by ad hoc procedures that are aimed at keeping prices relatively low while maintaining 

transmission flows within limits. As a result, prices may be too low when there is local scarcity. 

In particular, prices may not be high enough to attract efficient new investment to provide longterm solutions to local market power problems. It is difficult for new entrants to contest such 

local markets, so that the local monopoly positions are essentially entrenched.138 

New Generation Investment: In the late 1990s, developers added more than 16,000 megawatts 

of new capacity to the Texas market.139 Certain aspects of the Texas market may make it 

attractive to new investment. Texas consumers directly pay (via their electricity bills) for 

updates to the transmission system required by the addition of 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.140 

6. The Northwest 

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. Several trading hubs with significant levels 

of liquidity also are sources of 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., 

 137 ERCOT Response to the DOE Question Regarding the Energy Policy Act 2005, available at

http://www.oe.energy.gov/document/ercot2.pdf. 138 Ross Baldick and Hui Niu, Lessons Learned: The Texas Experience, available at

http://www.ece.utexas.edu/~baldick/papers/lessons.pdf. 

139 U.S. Gen. Accounting Office, GAO-02-427, Restructured Electricity Markets, Three States' Experiences 

in Adding Generating Capacity 9 (2002). 

140 Id. at 19. 
57

interdependent nodes) hydroelectric generation and difficulties in understanding the potential 

cost shifts that might result in restructuring contract-based transmission rights. 

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.141 The remaining generation derives primarily from coal and natural gas 

resources, (with smaller contributions from wind, nuclear and other resources). The 

hydroelectric share of generation has decreased steadily since the 1960s. 

The Northwest’s hydroelectric base allows the region to meet almost any capacity demands 

required of 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 because in three years out of four, hydro generation can 

displace much of the existing thermal generation in the Northwest. There has, however, been 

generation addition in the past years to meet load growth and to attempt to capitalize on highprices during the Western energy crisis of 2001-02. 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 3800 MWs of new generation has been added 

to the Northwest Power Pool since 1995 – 75% of that was commissioned in 2001 or later. 

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

The Task Force examined comments on how competition policy choices have affected the 

investment decisions of both buyers and sellers in wholesale markets. A number of issues 

emerged including the difficulty of raising capital to build facilities that have revenue streams 

that are affected by changing fuel prices, demand fluctuations and regulatory intervention and a 

perceived lack of long term contracting options. Some comments to the Task Force assert that 

significant problems still exist in these markets, particularly steep price increases in some 

locations without the moderating effect of long-term contracting and new construction.142 In 

some markets, the problem is that prices are so low as to discourage entry by new suppliers, 

despite growing need.143 Experience over the last 10 years shows three different regional 

competition models emerging. Each has its own set of benefits and drawbacks. 

 141 For a complete discussion of generation characteristics of the Northwest, see NW. POWER & CONN. 

COUNCIL, THE FIFTH NORTHWEST POWER AND CONSERVATION PLAN,, Ch. 2 (2005), available at

http://www.nwcouncil.org/energy/powerplan/plan/Default.htm 

142 ELCON; NRECA; APPA. 

143 E.g., PJM; EPSA. 
58

1. Long-Term Purchase Contracts – Wholesale Buyer Issues

Many wholesale buyers suggested that they had sought to enter into long-term contracts but 

found few or no offers.144 The Task Force attempted to determine whether the facts supported 

these allegations by examining 2004-05 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 not conclusive because of data limitations described in Appendix E, the 

analysis showed that contracts of less than one-year dominated each of the three regional markets 

examined and that in two of the markets, longer contract terms are associated with lower contract 

prices on a per MWh basis. 

Three reasons may exist to explain the perceived lack of ability to enter long-term purchase 

power contracts.145 First, some comments argued that organized exchange markets based on 

uniform price auctions (e.g., PJM and NYISO) have made it difficult to arrange contracts with 

base-load and mid-merit generators at prices near their production costs.146 These generators 

would rather sell in the exchange markets and obtain the market-clearing price, which may be 

higher than their production costs at various times. 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. Box 3-2 describes how prices are set in organized exchange markets. 

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.147 Stated another way, 

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 traditional 

regulation, by contrast, all of an owner’s generation units generally are allowed the same return, 

which may be less than marginal units, and more than infra-marginal units, in competitive 

markets. 

In addition, the very competitiveness of these markets cannot be assumed. For example, over ten 

years ago, FERC requested comments on a wholesale “PoolCo” proposal, which was the 

predecessor entity to today’s organized electricity market with open transmission access.148 At 

the time, the 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 

 144 ELCON. 

145 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. 

146 APPA, NRECA. 

147 See, e.g., Public Advocate’s Office of Maine, National Association of State Utility Consumer 

Advocates. 

148 Inquiry Concerning Alternative Power Pooling Institutions Under the Federal Power Act, Docket No. 

RM94-20-000. 
59

would be sufficient to reasonably assure that the benefits of eliminating traditional rate 

regulation exceed the costs.”149 

The fact that the market-clearing price in organized exchange markets may be established by a 

subset of generators depending upon demand and transmission congestion heightens the 

competitiveness concern in the organized markets. At one end, generators with high costs do not 

have much impact on the market prices when there is low demand and low transmission 

congestion, and conversely, generators with low costs do not have much impact on the marketclearing prices when there is high demand and high transmission congestion. There is a widerange of market-clearing prices between these two end points based on the diversity of generator 

costs available in each region.150 Indeed, some commenters specifically cited to recent studies of 

the electric industry that argue that a larger number of suppliers are needed to sustain 

competitive pricing in electricity markets than are needed for effective competition in other 

commodities.151

Second, the perceived lack of long-term purchase contracts may be due to a lack of trading 

opportunities to hedge these 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 risk due 

to such price differences. Currently, liquid electricity forward or futures markets often do not 

extend beyond two to three years.152 In some markets, one-year contracts are the longest 

products generally available; in markets where retail load is being served by contracts of fixed 

durations, such as the three-year obligations in New Jersey and Maryland, contracts for the 

duration of that period are slowly growing in number. But the relative lack of liquidity may 

discourage parties from signing long-term contracts, because they lack the ability to "hedge" 

these longer-term obligations. 

Third, the availability of long-term purchase contracts depends on the availability and certainty 

of long-term delivery options. Particularly in organized markets, transmission customers have 

argued that the inability to secure firm transmission rights for multiple years at a known price 

introduces an unacceptable degree of uncertainty into resource planning, investment and 

 149 Comments of the U.S. Department of Justice, Inquiry Concerning Alternative Power Pooling Institutions 

Under the Federal Power Act, Docket No. RM94-20-00 filed March 2, 1995 at p. 6. See also Reply Comments of 

the U.S. Department of Justice, Inquiry Concerning Alternative Power Pooling Institutions Under the Federal Power 

Act, Docket No. RM94-20-00 filed April 3, 1995. 

150 See Comment of the Federal Trade Commission. Docket No. RM-04-7-000 (Jul. 16, 2004) at 7-8, 

available at http://www.ftc.gov/os/comments/ferc/v040021.pdf. 

151 APPA, Carnegie Mellon. 

152 Nodir Adilov, Forward Markets, Market Power, and Capacity Investment (Cornell Univ. Dep’t of Econ. 

Job Mkt. Papers, 2005), available at http://www.arts.cornell.edu/econ/na47/JMP.pdf. 
60

contracting.153 They report that this financial uncertainty has hurt their ability to obtain 

financing for new generation projects, especially new base-load generation. 

Congress addressed this issue of insufficient long-term contracting in the context of RTOs and 

ISOs in EPACT05. In particular, section 1233 of EPACT05 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 load-serving 

entities to satisfy the service obligations of the load-serving 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.

154

To implement this provision in RTOs and ISOs, FERC proposed new rules regarding FTRs in 

February 2006. The rules would require RTOs and ISOs to offer long-term firm transmission 

rights. FERC did not specify a particular type of long-term firm transmission right, but instead 

proposed to establish guidelines for the design and administration of these rights. The proposed 

guidelines cover basic design and availability issues, including the length of terms the rights 

should have and the allocation of those rights to transmission customers. FERC has received 

comments on its proposal but has not yet adopted final rules. 

2. Long-Term Supply Contracts – Generation Investment Issues

Commenters cited the certainty of long-term contracts as a critical requirement for obtaining 

financing for new generators.155 These contracts, however, are vulnerable to certain regulatory 

risks. First, contracts are subject to regulation by FERC, and a party to a contract can ask FERC 

to change contract prices and terms, even if the specific contract has been approved 

previously.156 For example, in 2001-2002 several wholesale purchasers of electric power 

requested that FERC modify certain contracts entered into during the California energy crisis. 

The customers alleged that problems in the California electricity exchange markets had caused 

their contracts to be unreasonable. The sellers argued that if FERC overrides valid contracts, 

market participants will not be able to rely on contracts when transacting for power and 

 153 APPA, TAPS. 

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

155 Constellation, Mirant. 

156 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 Federal Power Act and the Natural Gas Act. Standard of 

Review for Modifications to Filed Agreements, 113 FERC ¶ 61,317 (2005) (Proposed Rule). Specifically, FERC 

proposed that, in the absence of specified contractual language, a party 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. 
61

managing price risk. FERC declined to change the contracts.157 FERC cited its obligation to 

respect contracts except when other action is necessary to protect the public interest.158

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.159 These efforts, when successful, leave 

counterparties facing circumstances that they did not anticipate when they entered into their 

contracts. This risk may give state regulators an incentive to favor construction of generation by 

their regulated utilities over wholesale purchases from merchant generators. These disputes have 

spawned conflicting rulings in the courts. In particular, these cases have centered on separate, 

but intertwined, issues: first, 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; and second, what standard applies to such efforts (that is, what 

showing must a party make to rid itself of a contract). As FERC and the courts have only 

recently begun to consider these questions, the law remains unsettled, as do parties’ 

expectations.160

A third type of regulatory uncertainty concerns the regulated retail service offerings in states 

with retail competition.161 The uncertainty of how much supply a distribution utility will need to 

satisfy its customers due to customer switching that can occur in retail markets can prevent or 

discourage those utilities from signing long-term contracts.162 The extent of this disincentive is 

unclear if competitive options are available for distribution utilities to purchase needed supply or 

sell excess supply. 

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

Building new generation in wholesale markets also is based on the ability of a company to 

acquire capital, either from internal sources or external capital markets. If a company can 

acquire the necessary capital it can build. There is no federal regulation of entry, and most states 

 157 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). 

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

159 See Howard L. Siegel, The Bankruptcy Court vs. FERC- The Jurisdictional Battle, 144 PUB. UTIL. 

FORTNIGHTLY 34 (2006). 

160 At least one rating agency treats a utility’s self-built generation as an asset while treating long-term 

purchase contracts as imputed debt, thus making it less attractive for utilities to choose the contract option. 

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

162 Mirant, Constellation. 
62

that have permitted retail competition have eliminated any “need-based” showing to build a 

generation plant. 

Private capital has generally funded the electric power transmission network in the United States. 

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. The ratepayers 

often bore the risk. Money from the 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.163 Regulatory disallowances of 

imprudent expenditures are viewed by investors as regulatory risk. This risk can be mitigated 

somewhat by Integrated Resource Planning, to the extent it limits or avoids after-the-fact 

regulatory reviews of investment decisions.164

In competitive markets, projects obtain funding 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.165 Therefore, potential entrants to generation markets have to be able to convince 

the capital markets that new generation is a viable profitable undertaking. In the late 1990s 

investors appeared to prefer market investments over 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.166

In recent years, however, investors have generally favored traditional utilities over merchant 

generators when it comes to providing capital for large investments.167 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 non-utilities after Enron’s financial 

collapse.168 As shown in the Table in Appendix G, for example, virtually all of the companies 

rated A- or higher are traditional utilities, not merchant generators. 

Investor preference for traditional utilities also may be affected by increasing volatility in electric 

power markets. As wholesale markets have opened to competition, investors recognized that 

income streams from the newly-built plants would not be as predictable as they had been in the 

 163 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. 

164 Southern, Duke. 

165 COMMODITY FUTURES TRADING COMM’N, THE ECONOMIC PURPOSE OF FUTURES MARKETS, available at

http://www.cftc.gov/opa/brochures/opaeconpurp.htm. 

166 APPA. 

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

168 U.S. GEN. ACCOUNTING OFFICE, GAO-02-427, RESTRUCTURED ELECTRICITY MARKETS, THREE STATES'

EXPERIENCES IN ADDING GENERATING CAPACITY 13 (2002). 
63

past.169 Under cost-based regulation, vertically integrated utilities’ monopoly franchise service 

territories significantly limited the risk that they would not recover 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.170

Financing was more readily accessed for projects like combined cycle gas and particularly gas 

turbines that can be built relatively quickly and were viewed at the time to have a cost advantage 

compared with existing generation already in operation, including less efficient gas-fueled 

generators.171 In 1996, the Energy Information Administration projected that 80% of electric 

generators between 1995 and 2015 would be combined cycle or combustion turbines.172 Baseload units, such as coal plants, with construction and payout periods that would put capital at risk 

for a much longer period of time, were harder to finance.173

The increasing amount of new generation fueled by natural gas, however, has caused electricity 

prices to vary more frequently with natural gas prices, a commodity subject to wide swings in 

price.174 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. 

 169 Connecticut DPUC. 

170 U.S. GEN. ACCOUNTING OFFICE, GAO-02-427, RESTRUCTURED ELECTRICITY MARKETS, THREE STATES'

EXPERIENCES IN ADDING GENERATING CAPACITY 13 (2002). 

171 ENERGY INFO. ADMIN., DOE/EIA-0562(96), THE CHANGING STRUCTURE OF THE ELECTRIC POWER 

INDUSTRY: AN UPDATE 38 (1996). 

172 Id.

173 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. 174 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 (February 13, 2006) at 7. 

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. 
64

4. Regulatory Intervention May Affect Investment Returns

Generation investors must expect to recover not only their variable costs but also an adequate 

return on their investment to maintain long-term financial viability. One way for suppliers to 

recover their investment is to charge high prices during periods of high demand. However, 

regulators may limit recovery of high prices during these periods, and thus may deter suppliers 

from making needed investments in new capacity that would be economical absent these price 

caps. 

This dynamic leads to a chicken-and-egg conundrum: if there were efficient investment, there 

might not be a need for wholesale price or bid caps. 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 the confidence of 

investors that they can rely on market forces (rather than regulation) to set prices. That 

diminished confidence in their ability to earn sufficient investment returns thus deters entry of 

new generation supply. 

Price mitigation through the use of price or bid caps has become an integral component of most 

organized markets. The use of mitigation has led generators to seek a supplemental revenue 

stream (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 the 

predicted outcomes. California did not have capacity credits and did not experience much new 

generation, but two of the regions (the 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. 

As noted above, much of the new generation in the Southeast was non-utility merchant 

generation, and 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. Unfortunately, there is no conclusive result from any of these approaches – no one model 

appears to be the perfect solution to the problem of how to spur efficient investment with 

acceptable levels of price volatility. 

Net revenue analyses for the 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.175 Based on 2004 data, net revenues in New England, 

 175 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. MARKET MONITORING UNIT, PJM

INTERCONNECTION, LLC, 2005 STATE OF THE MARKET REPORT, at 118 (2006) [hereinafter PJM STATE OF THE 

MARKET REPORT 2005], available at http://www.pjm.com/markets/market-monitor/som.html. 
65

PJM and California would have allowed a new combined-cycle plant to recover no more than 

70% 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 sub-optimal solution. Such compensation, like the reliability must run 

(“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.”176 To the extent that market rules allocate the cost 

of keeping these plants running to 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 new entry of efficient plants may be a partial solution to retirement of inefficient old 

plants. 

5. Investment in Transmission: A Necessary Adjunct to Generation Entry

Transmission access can be vital to the competitive options available to 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 and, 

traditionally, these utilities have an incentive to limit the use by others of the grid, to the extent 

such use conflicts with sales by their own generation. In short, the availability of transmission is 

often the keystone in determining whether a generating facility is likely to be profitable and, 

thus, to elicit investment in the first instance. 

Since FERC issued Order No. 888 in 1996, questions have arisen concerning the efficacy of 

various terms and conditions governing the availability of transmission. For example, 

transmission customers have raised concerns regarding the calculation of Available Transfer 

Capacity (ATC). Another area of concern is the lack of coordinated transmission planning 

between transmission providers and their customers. Finally, customers have raised concerns 

about aspects of transmission pricing. Based on these concerns, FERC in May 2006 proposed 

modifications to public utility tariffs to prevent undue discrimination in the provision of 

transmission services. FERC is soliciting public comments on its proposed modifications. 

As discussed above, generation that is built where fuel supplies are readily available, but not 

necessarily near demand, and construction costs are low, rely 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 had demand 

 

176 Intial Order on Reliability Pricing Model, 115 FERC ¶ 61,079, *3 (2006)
66

growth 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 proposition. 

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 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 be needed to run during fewer hours. 

E. Observations on Wholesale Market Competition 

One of the most contentious issues currently facing federal regulators 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 upon the OATT to make generation options available to wholesale 

customers. No central exchange market for electric power operates in regions taking this option 

(the Northwest and Southeast) Instead, wholesale customers shop for alternatives through 

bilateral contracts with suppliers and 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 that wholesale customers seek and a rough price signal to determine 

whether to build new generation or buy generation in wholesale markets. 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 necessitate constrained transmission capacity.. The lack of price transparency can also add 

to the difficulty of pricing long-term contracts in these markets. 

This model is extremely dependent on the availability of transmission capacity that is sufficient 

to allow buyers and sellers to connect. Thus, it also is dependent upon the accurate calculation 

and reporting of transmission capacity available to market participants. 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, but 

it must be seen to be available on a nondiscriminatory basis. As the 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 and be denied the competitive 

options supplied by more distant generation. Similarly, new suppliers may have no means of 

competing with incumbent generators located close to traditional load. 
67

2. Policy Options in 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). Such an exchange market could have 

prices set by a number of mechanisms. All existing 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. 

The academic research on whether pay-as-bid auctions can actually result in lower prices 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. More recent research suggests 

that pay-as-bid can sometimes result in lower costs for customers. 177 But, the pay-as-bid 

approach may reduce dispatch efficiency, to the extent generator bids deviate from their marginal 

costs.178 

A uniform price auction may allow some generators (e.g., coal- or nuclear-fueled units) to earn a 

return above those typically allowed under cost-based regulation, but it also may limit the return 

of other generators (e.g., natural gas-fueled units) to a return 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 may thus produce prices that are very high compared with the 

costs of 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. Three policy options have been suggested to address the tension 

between market-clearing prices with uniform auction and entry. 

a. Unmitigated Exchange Market Pricing

One possible, but controversial, way to spur entry is to let wholesale market prices rise. As 

discussed in Chapter 2, the market will likely 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. Where transmission capacity limits the availability of 

electric power from some generators within a regional market, the cost of supplying customers 

 177 Par Holmberg, Comparing Supply Function Equilibria of Pay-as-Bid and Uniform Price Auctions

(Uppsala University, Sweden Working Paper 2005:17, 2005); G. Federico & D. Rahman, Bidding in an Electricity 

Pay-As-Bid Auction (Nuffield College Discussion Paper No 2001-W5, 2001); Joskow, Difficult Transition at 6-7. 

178 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). 
68

within the region may vary. 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.179

Second, higher prices will likely signal to customers that they should change their decisions 

about how much and when to consume. Price increases signal to customers to reduce the amount 

they consume. Indeed, during the Midwest wholesale price spikes in the summer of 1998, 

demand fell during the period in which prices rose and customers purchased little supply during 

those periods.180 For an efficient reduction in consumption to occur, however, 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 

market-clearing prices, not all the caps in place may be necessary to prevent exercise of market 

power or set at appropriate levels. Higher caps may strike a balance between the desire of policy 

makers to smooth out the peaks of the highest price spikes and the need to demonstrate 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 insure that investors will recover the cost of new investment. Thus prices can rise 

significantly and yet not elicit entry by additional supply that could moderate price in later 

periods. 

Capacity payments are one way to ensure that investors recover their fixed costs. Capacity 

payments can provide a regular payment stream that, when added to electric power market 

income, can make a project more economically viable than it might be otherwise. 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. 

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

180 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. 
69

To the extent that capacity rules change, this creates 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 also 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 disproportionately reward traditional utilities and their affiliates 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 – but in general, it is difficult to tell whether capacity 

payments alone would spur economically efficient entry. 

One issue that has arisen 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 transmissionconstrained, high-demand areas. The combination of high electric power prices and high capacity 

prices in these areas may combine to create an adequate incentive to build generation in load 

pockets.181 

c. Encouraging Additional Transmission Investment

Building the right transmission facilities may encourage entry of new generation or more 

efficient use of existing generation. But transmission expansion to serve increased or new load 

raises the difficulty of tying the economic and reliability benefits of transmission to particular 

consumers. In other words, because transmission investments can benefit multiple market 

participants, it is difficult to assess who should pay for the upgrade. This challenge may cause 

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

generators and for transmission providers. 

If transmission entry can connect low-cost resources to high-demand areas, it is closely linked to 

the issues of generation entry. Transmission entry, however, can in theory remove the kinds of 

transmission congestion that results in higher prices in load pockets. Transmission entry may be 

a double-edged sword: if it is expected to occur, it would reduce the incentive of companies to 

consider generation entry, by eliminating the high prices they hope to capture. 

Both generation and transmission builders face the issue of dealing with an existing transmission 

owner or an RTO/ISO to obtain permission to build. Moreover, there are substantial difficulties 

to site new transmission lines. It is difficult to assess whether these risks are higher for 

transmission builders than for generation builders. 

d. Governmental Control of Generation Planning and Entry

 181 Siting in these areas can be difficult or impossible as a result of land prices, environmental restrictions, 

aesthetic considerations, and other factors. 
70

The final alternative is a regulatory rather than a 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 

market-based solutions, but that entry may not occur where, when or in a way that most benefits 

customers. Regulatory oversight of investment also means regulators can bar entry for reasons 

other than efficiency. The stable rate of return on invested capital offered under rate-regulation 

can encourage investment. On the other hand, rate-regulation can lead to overinvestment, 

excessive spending and unnecessarily high costs. Regulation also lacks the accountability that 

competition provides. Mistakes as to where and how investments should be made may be borne 

by ratepayers. In competitive markets, the penalties for such mistakes would fall on 

management and shareholders. The specter of future accountability for investment decisions can 

lead to better decision-making at the outset.182

It is possible that regulatory oversight of planning would result in greater fuel diversity, and thus 

less exposure to risks associated with changes in fuel prices or availability. It could also lessen 

potential boom-bust cycles where investors overreact to market signals and too many parties 

invest in one region. That reaction creates overcapacity, which in turn leads to lower prices. 

One large drawback to regulation, however, is the regulator’s lack of knowledge about the 

correct price to set. It is difficult to set the correct price unless frequent experimentation with 

price changes is possible, and yet consumers generally do not favor significant price variation. 

 182 Regulatory solutions, more so than market-based outcomes, may outlive the circumstances that made 

them seem reasonable. 
71

CHAPTER 4 

COMPETITION IN RETAIL ELECTRIC POWER MARKETS 

A. Introduction and Overview 

Congress required the Task Force to conduct a study of competition in retail electricity markets. 

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 their 

customers to choose their electricity supplier. 

 

Although it has been almost a decade since states started to implement retail competition, 

residential customers in most of these states still have very little choice among suppliers. Few 

residential customers have switched to alternative suppliers or marketers in these states. 

Commercial and industrial customers, however, have more choices and options than residential 

customers, but in several states these customers have become increasingly dissatisfied with 

increasing prices. Residential, commercial, and industrial customers in states with retail 

competition often have limited ability to adjust their consumption in response to price changes. 

One of the main impediments to market-based competition has been the lack of entry by 

alternative suppliers and marketers to serve retail customers. Unlike markets in other industries, 

most states required the distribution utility to offer customers electricity at a regulated price as a 

backstop or default if the customer did not choose an alternative electricity supplier or the chosen 

supplier went out of business. States argued that a regulated service was necessary 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. These initial discounts sought to approximate the 

anticipated benefits of competition for residential customers. Since then, wholesale prices have 

increased. More than any other policy choice surrounding the introduction of retail competition, 

this policy of requiring distribution utilities to offer service at low prices unintentionally impeded 

entry by alternative suppliers to serve retail customers – new entrants cannot compete against a 

below-market regulated price. 

States with below-market, regulated prices now face a chicken-or-egg problem and “rate shock.” 

With rate caps set to expire for the regulated service that most residential customers use, states 

are loath to subject their customers to substantially higher market prices that the distribution 

utilities indicate they must charge. These higher prices are even more painful to customers 

because they have few tools to adjust their consumption as wholesale prices vary over time. 

However, if states require the distribution utility to offer regulated service at below-market rates, 

retail entry, and thus competition, will not occur. Moreover, below-market rates put the solvency 

of the distribution utility at risk. 

This conundrum is further complicated by the fact that most distribution utilities that offer the 

regulated service no longer own generation assets. The utilities in many states sold their 

generation assets or transferred them to unregulated affiliates at the beginning of retail 
72

competition. Thus, distribution utilities that offer the regulated service must purchase supply in 

wholesale markets. Attempts to reassemble the vertically integrated distribution company face 

the reality that prices for many generation assets may be higher now than when they were 

divested at the beginning of retail competition. If the utility re-purchases these assets at these 

higher prices, it is likely to have “sold low and bought high.” In both cases, the competitiveness 

of wholesale prices has a direct impact on the retail prices consumers pay. 

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. See Appendix D for each state profile. These seven states represent 

the various approaches that states have used to introduce retail competition.183 The Chapter also 

discusses why it is difficult at this time to determine whether retail prices are higher or lower 

than they otherwise would be absent the move to retail competition. 

The chapter provides several observations based on the experiences of states that have 

implemented retail competition with an emphasis on how states can minimize market distortions 

once the rate caps expire. States with expiring rates caps face several choices on whether and 

how to rely on competition, rather than regulation, to set the retail price for electric power. 

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

Competition 

For most of the 20th century, local distribution utilities typically offered electric service at rates 

designed for different customer classes (e.g., residential, commercial, and industrial). State 

regulatory bodies set these rates based on the utility’s costs of generating, transmitting, and 

distributing the electricity to customers. 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 plant used to 

serve customers. Public power and cooperative systems operate under a cost of service nonprofit structure and rates typically include a margin adequate to cover unanticipated costs and 

support new investment. 

 183 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 seven profiled states include a range of conditions that are 

similar to the other states with retail competition. Virginia is similar to Pennsylvania in that their transitions to retail 

competition are over approximately a 10-year period. Maine and Rhode Island are similar to New York and Texas 

in that prices for POLR service have been regularly adjusted to reflect changes in wholesale prices. Delaware, the 

District of Columbia, Illinois, Michigan, New Hampshire, Ohio and Rhode Island share the situation in Maryland 

with the transition period of fixed prices for residential and small C&I POLR service coming to an end in the near 

future. Massachusetts’ rate cap period ended recently. Many of the states about to end the transition period, share 

the development of 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 the shopping is limited to a short window of time each year. 
73

With minor variations, monopoly distribution utilities deliver electricity to retail customers.184 

Industrial customers sometimes had more options as to service offerings and rate structures (e.g., 

time-of-use rates, etc.) than residential and small business customers.185

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 those in the same state. Some of the disparity was due to 

different natural resource endowments across regions -- most important the hydroelectric 

opportunities in the Northwest and states such as Kentucky and Wyoming with abundant coal 

reserves. Also, 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. 

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 (December 1996), Figure 11. 

With retail competition, customers could choose their electric supplier or marketer, but the 

delivery of electricity would still be done by the local distribution utility.186 The idea was that 

 184 In 30 states retail electric customers continue to receive service almost exclusively under a traditional 

regulated monopoly utility service franchise. These states include 44% of all U.S. retail customers which represents 

49% of electricity demand. 

185 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. 
74

customers could obtain electric service at lower prices if they could choose among suppliers. For 

example, they could buy from suppliers located outside their local market, from new entrants 

into generation, or from marketers, any of which might have lower prices than the local 

distribution utility. Moreover, the ability to choose among alternative suppliers would reduce 

any market power that local suppliers might otherwise have, so that purchases could be made 

from the local suppliers at lower prices than would otherwise be the case. Also, customers might 

be able to buy electricity on innovative price or other terms offered by new suppliers. 

In 1996, California enacted a comprehensive electric restructuring plan to allow customers to 

choose their electricity supplier. To accommodate retail choice, California extensively 

restructured the electric power industry. The legislation: 

(1) established an independent system operator to operate the transmission grid 

throughout much of the state so that all suppliers could access the transmission grid to 

serve their retail customers; 

(2) established a separate wholesale trading market for electricity supply so that utilities 

and alternative suppliers could purchase supply to serve their retail customers; 

(3) mandated a 10 percent immediate rate reduction for residential and small commercial 

customers for those customers that did not choose an alternative supplier; 

(4) authorized utilities to collect stranded costs related to those 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.187

Other states also enacted comprehensive legislation. In May 1996, New Hampshire enacted 

retail competition legislation – Rhode Island (August 1996), Pennsylvania (December 1996), 

Montana (April 1997), Oklahoma (May 1997), and Maine (May 1997) – all followed suit. By 

January 2001, some 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. 

(See chart and timeline with retail choice legislation dates) Several states, primarily those with 

low-cost electricity such as Alabama, North Carolina, and Colorado, concluded that the retail 

competition would not benefit their customers. In Colorado, for example, limitations on 

transmission access and a high concentration among generator suppliers led the state to be 

concerned that these suppliers would 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. These goals 

included: 

• Lower electricity prices than under traditional regulation through access to lower cost 

 186 The FERC and the state will continue to regulate the price for transmission and distribution services 

and, in most states, the local distribution utility will continue to deliver the electricity, regardless of which 

generation supplier the customer chooses. 

187 Ca. AB 1890, available at http://www.leginfo.ca.gov/pub/95-96/bill/asm/ab_1851-

1900/ab_1890_bill_960924_chaptered.pdf. 
75

power in competitive wholesale markets where generators competed 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; 

• Improvements in the environment through displacement of dirtier, more expensive 

generating plants with cleaner, cheaper, natural gas and renewable generation. 

At the same time, legislatures and regulators affirmed support for the availability of electricity to 

all customers at reasonable rates with continuation of safe and reliable service and consumer 

protections under regulatory oversight under the restructured model. Boxes 4-1 and 4-2 describe 

the Pennsylvania and New Jersey Legislatures’ finding and expected results of retail 

competition. 

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.HTMhttp://www.legis.state.pa.us/WU01/LI/

BI/BT/1995/0/HB1509P4282.HTMhttp://www.legis.state.pa.us/WU01/LI/BI/BT/1995/0/HB1509P4282.HTM 
76

C. Meltdown and Retrenchment 

Starting in the late spring 2000 and lasting into the spring of 2001, California experienced high 

natural gas prices, a strained transmission system, and generation shortages. Wholesale prices 

increased substantially during this time frame. State law capped residential provider of last 

resort (POLR) rates at levels that were soon below the market price paid by utilities for 

wholesale electric power. One of California’s large investor owned utilities declared bankruptcy 

because it could not increase its retail rates to cover the high wholesale power prices. The state 

stepped in to acquire electricity supply on behalf of two of the three IOUs operating in 

California.188 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. The suspension continues today. Box 4-3 

describes the State’s role in purchasing electricity and the all-time high prices it paid, and 

continues to pay, for such electricity. 

 188 See, e.g., California Attorney General’s Energy White Paper, A Law Enforcement Perspective on the 

California Energy Crisis, Recommendations for Improving Enforcement and Protecting Consumers in Deregulated 

Energy Markets (Apr. 2004), available at http://ag.ca.gov/publications/energywhitepaper.pdf; 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, 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.

Box 4-2 

Findings of the New Jersey Legislature

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

(1) Lower the current high cost of energy, and improve 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; 

(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; . . . 

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

(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; 

(6) Ensure that rates for non-competitive public utility services do not subsidize the provision of competitive 

services by public utilities; . . . 
77

The experience in California and its ripple effects in the western region prompted several states 

to defer or abandon their efforts to implement retail competition. Since 2000, no additional 

states have adopted retail competition. Indeed, some states including Arkansas and New 

Mexico, which had previously adopted retail competition plans, repealed them. 

Other large states such as Texas, New York, Pennsylvania, New Jersey, and Illinois moved 

ahead with retail competition as planned. These states have ended, or are about to end, their 

POLR service rate caps and will soon rely on competitive wholesale and retail markets for 

electricity. 

As shown in Figure 4-2, at present, 16 states and the District of Columbia have restructured at 

least some of the 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, District of Columbia, Illinois, Maine, Maryland, 

Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, 

Pennsylvania, Rhode Island, Texas, and Virginia. 

Figure 4-2: United States Map Depicting States with Retail Competition, 2003 

Box 4-3 

The State of California’s Electricity Purchases at All-Time High Prices. 

In 2001, the 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 for 10 

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 all-time high. Future prices hovered in the range of $350-$550 per MWh during the 

time the State 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 sunk below $100. Thus, as of May 2006, the 

state is obligated to pay well over market prices for at least 5 more years. See Southern California Edison. 
78

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 these expected benefits in mind, the Task Force examined seven states in depth to report 

the status of retail competition. These states represent the different approaches taken to 

introduce retail competition. The states include Illinois, Maryland, Massachusetts, New Jersey, 

New York, Pennsylvania, and Texas and they. These states are referred to as “profiled states.” 

In most profiled states, competition has not developed as expected. Few alternative suppliers 

currently serve residential customers. To the extent that there are multiple suppliers serving 

customers, prices have not decreased as expected, and the range of new options and services is 

limited. Much of the lack of expected benefits can be attributed to the fact that some states still 

have capped residential POLR rates. Commercial and industrial customers generally have more 

choices than residential customers because most do not have the option to take POLR service at 

discounted, regulated rates, have substantially larger demand (load), and have lower 

marketing/customer service costs. 

This section first reviews the status of retail competition in the profiled states with an emphasis 

on entry of new suppliers, migration of customers to alternative suppliers, and the difficulties in 

drawing conclusions about retail competition’s effect on prices. The section then discusses how 

regulated POLR service has distorted entry decisions of alternative suppliers. The section also 

discusses the lessons learned from the use of POLR that may assist states as they decide how to 

structure future POLR service. 

1. Status of Retail Competition

a. States Have Allowed Distant Suppliers to Access Local Customers and 
79

Have Encouraged Distribution Utilities to Divest Generation

The profiles revealed that each state took some measures to encourage entry of new suppliers to 

compete with the supply offered by the incumbent utility. Each of the profiled states adopted 

policies to allow suppliers other than the local incumbent distribution utility access to local retail 

customers by requiring the utilities in the state to join an independent system operator (ISO) or 

regional transmission organization (RTO). As discussed in Chapter 3, larger wholesale 

electricity geographic markets 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 the choices available 

to retail customers and makes it more difficult for local generators to exercise market power. 

Some states such as Massachusetts, New Jersey, and New York ordered or encouraged utilities to 

divest generation assets to independent power producers (IPP) either to eliminate possible 

transmission discrimination or to secure accurate stranded cost valuations.189 These divestitures 

have generally not required that a utility sell its generation assets to more than one company to 

eliminate the potential for the exercise of generation market power, but often generating facilities 

have been purchased by more than one IPP.190 In other states, such as Illinois and Pennsylvania, 

several utilities voluntarily divested their generation assets by selling them or moving them into 

unregulated affiliates.191 

The result of these divestitures has been that regulated distribution utilities in profiled states 

operate fewer generation assets than in the past. Distribution utilities that are required to serve 

customers must access the wholesale supply market to obtain generation supply to serve their 

customers. Table 4-2 shows the amount of a state’s generation that was under operation by the 

state’s regulated distribution utilities (i.e., in the “rate base”) prior to retail competition and after 

the start of retail competition. 

Table 4-1 

Distribution Utility Ownership of Generation Assets in the State in Which It Operates 

 

State Prior to Restructuring 2002 

Illinois 97.0% 9.1% 

Maryland 95.4% 0.1% 

Massachusetts 86.6% 9.0% 

New Jersey 81.2% 6.8% 

 189 See Massachusetts, New Jersey, and New York profiles, Appendix D. See also FTC Staff Report 

Competition and Consumer Protection Perspectives on Electric Power Regulation Reform: Focus on Retail 

Competition (Sept. 2001) at 43 [hereinafter FTC Retail Competition Report]. 

190 The price of generation assets have been volatile since these divestitures occurred. The asset prices are 

often based 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. 

191 See Illinois and Pennsylvania profiles, Appendix D. See also FTC Retail Competition Report, 

Appendix A (State profiles of Illinois and Pennsylvania). 
80

New York 84.3% 32.4% 

Pennsylvania 92.3% 12.3% 

Texas 88.3% 41.2% 

Source: U.S. Department of Energy, Energy Information Administration, State Profiles, Table 4 in each state 

profile, available at http://www.eia.doe.gov/cneaf/electricity/st_profiles/e_profiles_sum.html. The pre-retail 

competition statistics are from 1997 and the post-retail competition statistics are from 2002 

Other states, such as Texas, limited the market share that any one generation supplier can hold in 

a region, thus providing more of an opportunity for other suppliers to enter.192 Still others such 

as New York have helped organize introductory discounts from alternative suppliers, thus 

providing customers an incentive to switch to these new suppliers.193

b. Alternative Suppliers Serving Retail Customers and Migration Statistics

In the profiled states, substantial numbers of generation suppliers serve large industrial and large 

commercial customers. For example, in Massachusetts, over 20 direct suppliers provide service 

to commercial and industrial customers, along with over 50 licensed electricity brokers or 

marketers.194 In Massachusetts, however, there are substantially fewer active suppliers serving 

residential customers – only four in Massachusetts.195 In New Jersey, commercial and industrial 

customers can choose among nearly 20 suppliers, but residential customers have a choice of one 

or two competitive suppliers.196

For residential customers, Texas and New York are the two states in which more than just a 

handful of suppliers serve residential customers. In Texas, residential customers have 

approximately 15 suppliers from which to choose.197 In New York, between six and nine 

suppliers offer services to residential customers in each service territory.198 Very few, if any, 

suppliers provide service to residential customers in the other profiled states or in other retail 

 192 Texas profile, Appendix D. 

193 New York profile, Appendix D. 

194 Massachusetts Department of Telecommunications and Energy, List of Competitive 

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

195 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%20Electr

icity%20Brokers. 

196 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 

commercial and industrial (C&I) and 1 residential suppliers. Eighteen suppliers serving C&I customers and one 

serving residential customers in the PSE&G service territory. 

197 Texas Public Utilities Commission, Texas Electric Choice Compare Offers from Your Local Electric 

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

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

available at http://www3.dps.state.ny.us/e/esco6.nsf/ 
81

competition states. One notable exception has been the municipal aggregation program in Ohio 

described in Box 4-4. 

In those territories with more generation suppliers, the migration or number of residential 

customers switching from the POLR service to an alternative competitive supplier is the greatest. 

For example, in Massachusetts, as of December 2005, 8.5 percent of the residential customers 

had migrated to a competitive supplier. Approximately 41 percent of large commercial and 

industrial customers had switched to alternative suppliers, representing 57.5% of the load.199 In 

states with a large number of suppliers serving residential customers, higher percentages of 

residential customers had switched to a new supplier with approximately 26% choosing a new 

supplier in Texas.200 Of course, once alternative suppliers serve customers, the local distribution 

utility no longer provides generation supply, but continues to deliver the generation supply over 

its transmission and distribution system. 

c. Retail Price Patterns by Type of Customer

Figures 4-3 shows average revenues per kilowatt hour for all customer types in the profiled states 

against the national average for the period 1990-2005. The U.S. national average was generally 

flat at 8 cents per kWh during this period. New York, Massachusetts, and New Jersey have 

generally been higher than the national average and Texas, Pennsylvania, Maryland, and Illinois 

have been lower. In 2004 and 2005 retail prices in all states have begun to increase. 

 199 Massachusetts profile, Appendix D. 

200 Texas profile, Appendix D. 

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 

customers making a choice 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. In Ohio, the 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 is made up of 100 member communities and serves 

approximately 500,000 residents. Aggregation accounts for most of the residential switching in Ohio. The Ohio 

program allows individual customers to opt out of the aggregation. In most other states, aggregation programs 

use an approach under which customers must specifically opt in to participate. Participation rates generally are 

much higher under opt out than under opt in programs. 
82

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

Profiled States vs. 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. 

i. Residential and Commercial Customers

It is difficult to draw conclusions about how competition has affected retail prices for residential 

customers in those states in which residential customers continue to take capped POLR service 

(e.g., Maryland, Illinois, and portions of New York, Pennsylvania, and Texas). Price 

comparisons of regulated prices shed little light on the price patterns as a result of retail 

competition. 

For those states in which the residential rate caps have expired, POLR prices have increased 

recently. In New Jersey, residential rate caps on POLR service expired in the summer of 2003. 

Since then, 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 the 

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 they 

increased in 2005 and 2006 with rates increasing approximately 13% between 2005 and 2006.201 

 201 New Jersey profile, Appendix D. See also Kenneth Rose, 2003 Performance of Electric Power Markets, 

Review Conducted for the Virginia State Corporation Commission (Aug. 29, 2003) at II-19. 
83

In Massachusetts, capped POLR rates expired in February 2005. Since then customers who had 

not chosen an alternative supplier were still able to obtain POLR service. Massachusetts based 

the generation portion of the POLR service on the price of supply procured in wholesale markets 

through fixed-priced, short-term (three or six months) 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 2006.202

ii. Large Industrial Customers

Similar to the situation described above for residential customers, large industrial customers that 

continue to use a fixed price POLR service shed little light on price patterns. A number of states, 

however, have revised their POLR policies for large customers such that the 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.203 In these states, substantial numbers of 

customers, as described above, have switched to alternative suppliers. 

Large industrial customers have cited how their rates have increased since the beginning of retail 

competition.204 Indeed, some commenters suggested that the Task Force compare prices for 

customers of the same utility that operates in a state that did not implement retail competition to 

examine the effect of retail competition on rates.205

The difficulty with this type of comparison is that many factors simultaneously influence prices 

that may not be related to retail competition. For example, one state may have reduced the crosssubsidies of residential by industrial customers, and another may not have, so that a price 

comparison would be misleading. Access to different generators (with low or high prices) may 

be affected by transmission congestion such that comparing two states as if they were in the 

same physical location would be misleading. Finally, some states may be deferring recovery of 

costs to a future time period whereas other states are not. Thus, a simple price comparison may 

not reveal whether retail competition has benefited customers, without consideration of these and 

other factors. At this point it is difficult for the Task Force to provide a definitive explanation of 

price differences between states. 

d. Results of Efforts to Bring Accurate Price Signals into Retail Electric Power Markets

The impact of retail competition to bring efficient price signals to retail customers has been 

mixed. Residential POLR service rate caps have not increased customer exposure to time-based 

 202 Massachusetts profile, Appendix D. 

203 Although POLR price is based on the hourly wholesale price of electricity, customers in New York and 

New Jersey who purchase this service are unaware of the price until they are billed. 

204 See, e.g., ELCON; Portland Cement; Alliance of State Leaders; Alcoa. 

205 Portland Cement; Lehigh Cement. 
84

rates. The exception has been real-time pricing as the POLR service for the largest customers in 

New Jersey, Maryland, and New York. 

Commenters argue that POLR rate structure can have a major effect on customer price 

responsiveness, especially among larger customers. A broad spectrum of utilities, state 

regulators, and ISOs argue that variable rates permit customers to react to price changes because 

these rates allow customers to clearly see how much money they can save.206 Indeed, the 

experience of the largest customers in National Grid USA’s New York area, suggests that after 

the introduction of retail competition, customers using real-time pricing demonstrate price 

sensitivity.207 

In states with traditional cost-based regulation, utilities have used various incentives for 

customers to reduce consumption during periods in which there is high demand and transmission 

congestion (e.g., hot summer days). The existence of retail competition has, in some instances, 

discouraged the use of these traditional types of programs, particularly when POLR is no longer 

the responsibility of distribution utilities.208 Without the need to maintain a portfolio of resources 

to meet POLR, distribution utilities 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 the direct interest by 

distribution utilities in these types of product offerings. 

e. Retail Competition and Rural America

Many rural areas are served by small non-profit electric cooperative and public power utilities. 

Historically rural areas were among the last to be electrified and the most costly to serve. 

Customers are scattered and residential and small loads predominate. Electric distribution 

cooperative service areas have been opened to competition under some state plans. No states 

have required municipal and/or public power utilities to implement retail competition. 

Eight states with retail competition required electric cooperatives to implement retail competition 

in their service territories. These states are Arizona, Delaware, Maine, Maryland, Michigan, 

New Hampshire, Pennsylvania and Virginia. With the exception of Pennsylvania, state public 

utility commissions regulated retail rates of electric cooperatives and approved the retail 

competition plans for each cooperative. Pennsylvania’s restructuring legislation left the design 

and implementation of retail competition to the individual distribution cooperatives and their 

boards. 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. In Arizona 

and Michigan some aspects of cooperative retail competition plans are still in administrative or 

judicial proceedings. Michigan currently has allowed electric cooperatives to offer retail 

 206 Constellation, PEPCO, Southern and EEI, ICC, IURC, and NYPSC, ISO-NE. 

207 National Grid 

208 For example, when PEPCO divested its generation assets it stopped actively supporting its airconditioner DLC program. 
85

competition to a portion of their very large industrial and commercial customers. Action on 

extending competition to other customers in Michigan has been deferred. 

Six more states allow electric cooperatives to opt in to retail competition on a vote of their 

boards or membership. These are Illinois, Montana, New Jersey, Ohio, and Texas. None of 

these states regulate the rates or services of electric distribution cooperatives, so design and 

implementation of cooperative retail competition plans is left to the individual cooperative. 

Licensing of competitive providers is handled by the state, but providers must enter into 

agreements with the cooperative in order to begin enrolling retail customers. A handful of 

individual cooperatives in Montana and Texas elected to provide retail competition options for 

their members. 

Tracking the progress of retail competition in rural areas is difficult because most states do not 

post switching data or maintain up to date information on active suppliers in cooperative service 

territories. Nevertheless, it was possible to determine that there were few alternative competitive 

providers, if any, for residential customers of rural systems open to retail competition. There 

were no competitive providers enrolling customers in coop systems in Maine, New Hampshire, 

Pennsylvania, Arizona, Maryland, and Virginia in May 2006. In Delaware, and Montana, 

competitive providers had been licensed to serve coop customers, but it is unclear that any are 

currently enrolling customers. Licensed provider and switching information for Texas 

cooperatives is not yet available. 

B. POLR Service Price Significantly Affects Entry of New Suppliers 

Each of the profiled states has required local distribution utilities to offer a POLR service for 

customers who do not select an alternative generation service 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. The most significant portion of the POLR service price is the generation 

portion of the POLR service. Many states denote this as the “price to beat” or the “shopping 

credit.” It also represents the amount that the customer avoids paying the distribution utility 

when the customer chooses an alternative generation service provider. The customer instead 

pays the alternative electricity supplier’s charges for generation services. 

The comments reported that the price of POLR service is the most significant factor affecting 

whether new suppliers will enter the market and compete to serve customers.209 The POLR price 

 209 The comments also identified other factors that depress or delay entry into retail competition markets 

besides the policies surrounding POLR discussed above. It is difficult for the Task Force to evaluate which 

additional factors are the most important because of the lack of entry in most states. 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 OCA at 3. The Maine Public Advocate echoed these and identified the “miscalculation by some suppliers as to 

the risks and rewards for retail electricity competition” ME PA at 3. The Industrial Customers identified that retail 

markets are not fully competitive because of the insufficient generation divestitures that left suppliers with market 

power. ELCON at 2. Other factors identified by Industrial Customers include inability of alternative suppliers to 

gain access to necessary transmission services to serve their customers. ELCON at 6. Others customers suggested 

the lack of uniform rules throughout every service territory hinder ease of entry for suppliers. Wal-Mart at 13. 
86

is the price that new suppliers, including unregulated affiliates of the distribution utility, must 

compete against if they are to attract customers.210 

1. Contrasting Visions of POLR Service

The comments revealed two long-term visions of POLR service. In the first vision, POLR is a 

long-term option for customers. In the second vision, POLR is a temporary service for 

customers between suppliers. The first vision entails POLR service that closely approximates 

traditional utility service, but in a market place with other sources of supply available to 

customers. POLR service under the first vision often features prices that are fixed over extended 

periods of time. In this vision, government-regulated POLR service competes head-to-head with 

private, for-profit retail suppliers.211 An analogous example may be the United States Postal 

Service as a provider of parcel postage service in competition with for-profit, package delivery 

services such as United Parcel Service, DHL, and Federal Express. Alternative suppliers may 

grow in this vision as they find additional approaches to attract customers, but POLR service will 

likely retain a substantial portion of sales, particularly sales to residential customers. This type 

of POLR service serves as a yardstick against which alternative suppliers compete. Most states 

have used this version of POLR.212 

In the second vision, POLR service is a barebones, temporary service consisting of retail access 

to wholesale supply, primarily for customers who are between suppliers. In this vision, 

alternative suppliers serve the bulk of retail customers. The alternative suppliers compete 

primarily against each other with a variety of price and service offers designed to attract different 

types of customers. This type of POLR service acts as a stopgap source of supply that ensures 

that electric service is not interrupted for customers 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 under 

this vision.213 A comparable supply arrangement for this version of POLR service is the high 

risk pool for automobile insurance operated in any of several states.214 Texas and Massachusetts 

provide current examples of this vision, as is Georgia in its design for retail natural gas sales.215

 

Other commenters argued that alternative suppliers need access to customer usage data from utilities to be able to 

market to prospective customers. Constellation at 43. Still others argued for no minimum stay requirements at 

POLR and constrained shopping windows, which can dampen entry. RESA at 30-31, Strategic at 10, Wal-Mart at 

13. 

210 There is one potential exception. Suppliers that offer a substantially different product, “green” power 

from wind turbines, for example, may be able to charge a higher price and still attract customers. 

211 See, e.g., ICC, PPL, and PA OCA. 

212 See, e.g., PA OCA; NASUCA. 

213 See, e.g., RESA, Wal-Mart, NEMA, and Suez. 

214 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 that 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 
87

Some of profiled states incorporated aspects of both visions of POLR service for different types 

of customers. For example, New Jersey adopted the first approach for POLR service to 

residential customers and the second approach for POLR service to large commercial and 

industrial customers.216 Large C&I customers are generally expected to be well-informed buyers 

with wide energy procurement experience. As such, some states determined that large C&I 

customers are more likely to be able to quickly obtain the benefits of retail competition without 

additional help from state regulators provided in the form of fixed price POLR prices. 

2. Key POLR Service Design Decisions

The profiled states took different approaches to design their POLR service offerings. Key design 

decisions involved the pricing of the POLR, how to acquire POLR supply, and the duration of 

the POLR obligation. 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 pre-retail competition regulated price for 

electric power less a discount. The 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 applied to customers viewed as less likely to be 

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. Those customers in 

areas with relatively low prices before customer choice did not receive discounts below previous 

regulated rates at the beginning of retail competition. In contrast, customers in the 

Commonwealth Edison territory, the area with the highest cost-based rates, received 20% 

discounts to bring retail POLR prices there into line with regional average bundled service prices 

prior to the restructuring legislation.217

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 fuel costs to generate electricity. Some states have separated fuel costs 

 

for individuals with prior health conditions who are seeking health insurance coverage. See Communicating for 

Agriculture and the Self-Employed, Comprehensive Health Insurance of High-Risk Individuals, 19th Ed. (2005) 

215 Texas will end its “price to beat” system in 2007 (Texas profile). Massachusetts ended its rate-capped 

POLR service in February 2005 (Massachusetts profile). 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 as 

alternative supplier is randomly assigned to 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. 

216 New Jersey profile, Appendix D. 

217 Illinois profile, Appendix D. 
88

from other cost components, because fuel costs have been more volatile than other input prices--

they are the largest variable cost component, and can be calculated for each type of generation 

unit, based on public information. These factors also suggest that a generation firm does not 

have much control over its fuel costs once the generation investment has been made. 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, the Texas regulators have been 

able to prevent 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.218 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.219

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 consumer. The distribution 

utility therefore “credits” the customer’s bill so that the customer pays the alternative supplier for 

the electricity supplied.220 This avoided charge is known as the shopping credit and is equal to 

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, has 

estimated avoided costs on this basis with no additional estimated avoided costs.221 This view 

results in a lower shopping credit and total POLR price. An alternative perspective is that the 

distribution utility also avoids other costs on top of avoided procurement costs, including 

marketing and administrative costs.222 This view results in a higher shopping credit and total 

POLR price. In Pennsylvania, the POLR shopping credit included several other elements such as 

avoided marketing and administrative costs.223 Some observers attributed the early high volume 

 218 Texas profile, Appendix D. 

219 See discussion of the California energy crisis in which one of the state’s utilities declared bankruptcy 

because, in part, capped POLR rates were substantially below wholesale prices. 

220 The distribution utility continues to charge the customer a delivery charge to cover the transmission and 

distribution expense (the “wires” charge). 

221 Thomas L. Welch, Chairman, Maine Public Utilities Commission, UtiliPoint PowerHitters interview 

(January 24, 2003), available at http://mainegovimages.informe.org/mpuc/staying_informed/about_mpuc/commissioners/ph-welch.pdf. 

222 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.ohiostate.edu/dspace/bitstream/2068/610/1/00-10.pdf, for a discussions of adders and their relationship to wholesale 

prices and headroom for entrants in Pennsylvania and other states. 

223 Id. 
89

of switching to alternative suppliers in Pennsylvania to the additional avoidable costs that were 

included in the Pennsylvania shopping credit calculations.224 

d. The multi-year period for POLR service. 

Every state that implemented retail competition has determined the length for which POLR 

should continue to be available to customers at a discount from prior regulated prices. The 

length of this period has generally corresponded to the distribution utility’s collection of 

“stranded” generation costs. In a competitive retail environment, utilities no longer were assured 

that they could recover the costs of all of their state-approved generation investments. Most 

states faced claims of utility stranded costs associated with generation facilities that were 

unlikely to earn enough revenues to recover fixed costs once customers can seek out alternative, 

lower-priced retail suppliers. States allowed utilities with stranded costs to recover those costs 

through charges on distribution services that cannot be bypassed.225 

Each state that authorized the collection of stranded costs faced decisions on how 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 facing state 

regulators. First, some states required that some or all generation be sold to obtain a marketbased determination of the level of stranded costs. For example, Maine and New York took this 

approach.226 In other states, such as Illinois, utilities voluntarily divested generation assets. As 

noted above, the result of these divestitures is that generation is no longer primarily in the hands 

of regulated distribution utilities.227 

 224 Over time, the size of 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 the appendix. 

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

226 New York profile, Appendix D; FTC Retail Competition Report, New York State Profile, Appendix A. 

227 Illinois profile, Appendix D. 
90

e. Procurement for POLR service: 

Given that most utilities no longer own generation to satisfy all of their POLR obligations, 

utilities have taken different approaches to acquire the necessary generation supply. For 

example, the utilities in New Jersey that offer residential POLR service acquire the generation 

supply through the use of three overlapping 3-year contracts, each for approximately one third of 

the projected load.228 This “laddering” of supply contracts reduces the volatility of retail 

electricity prices for customers, but it does not assure that the prices paid by POLR service 

consumers are at the short-term competitive level.229 Other states have 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 divested generation assets (“vesting 

contracts”) based on pre-divestiture average generation prices.230

E. Observations on How POLR Service Policies Affect Competition 

One of the most contentious issues currently facing state regulators is whether and how to price 

POLR service once the rate caps expire. This situation is especially vexing for those states that 

had stranded cost recovery periods during which fixed POLR prices became substantially lower 

than current wholesale prices. The rate caps expire in 2006 for states such as Maryland, 

Delaware, Illinois, Ohio, and Rhode Island, and customers that did not choose an alternative 

supplier are faced with the prospect of substantially increased electricity prices relative to those 

in effect when retail competition began six or seven years. The various state POLR policies 

show the range of options available to these states. 

1. POLR Service Price to Approximate the Market Price

For the POLR service price to provide economically efficient incentives for consumption and 

supply decisions, it must closely approximate or be linked to a competitive market price based on 

supply and demand at a given point in time. If the POLR service price does not closely match 

the competitive price, it is likely to distort consumption and investment decisions away from 

theoretically optimal allocation of electricity resources. Theoretically, competitive market prices 

align consumers’ willingness to pay for a service with a suppliers cost of supply (where, in the 

long run, cost includes a fair market return on investment). This alignment is thought to lead to 

an economically efficient allocation of resources, wherein no alternate distribution of resources 

could lead to greater benefits to society as a whole. 

Experience within the profiled states shows that approximating the competitive price is not an 

easy task. 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 competitive price can quickly 

and dramatically move. Over the past several years, the initial fixed discounts for POLR service 

have resulted in POLR service prices that are below market prices or occasionally above market 

 228 New Jersey profile, Appendix D. 

229 See, e.g., ME OPA. 

230 New York profile, Appendix D. 
91

prices, but never at the market price for long.231 When the POLR prices are below competitive 

levels, even efficient alternative suppliers cannot profit by entering or continuing to serve retail 

customers.232 Firms with the POLR obligation can become financially distressed, as they did in 

California during its energy crisis.233 

Some of the change in the market price is likely to be due to changes in fuel prices. A POLR 

service design that adjusts the retail electricity price for changes in the prices of fuels used by 

marginal generators makes a better proxy for the market price than one that is fixed. When the 

POLR price is adjusted to incorporate underlying fuel price changes, but it is adjusted 

infrequently, the POLR price can repeatedly change from being above the competitive market 

price to below the competitive market price.234 In this way, a fixed price creates incentives for 

customers to move back and forth from POLR service to alternative suppliers. This repeated 

switching can create additional costs for both POLR service providers and alternative suppliers 

and it can reduce the certainty that both POLR service and competitive suppliers may need in 

order to make long-term supply arrangements. If there are other identifiable cost components 

that fluctuate widely, including them in POLR service price adjustments will also 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 wholesale supply prices. In these circumstances, customers are likely to 

experience a shock when POLR service prices are adjusted to match prevailing wholesale prices. 

This situation 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 customers pay is usually deferred and collected later from the POLR provider’s customers. 

Although this approach reduces rate shock for customers, it is likely to distort retail electricity 

markets. First, a phase-in continues to provide inaccurate price signals for customers and 

undermines incentives to reduce consumption or to conserve electric power use. Second, it 

prevents entry of alternative suppliers by keeping the POLR rate below market for additional 

years. Third, it results in higher prices in future years as the deferred revenues are recovered. 

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 because the POLR provider will have lost 

customers who were counted on to pay the higher prices. Moreover, if the state prevents the 

stranded cost problem by imposing large exit fees on POLR service customers, competition may 

 231 See, e.g., Wal-Mart; WPS Resources; ICC; PPL; RESA. 

232 See, e.g., Wal-Mart; RESA. 

233 See, e.g., EEI. 

234 See, e.g., RESA. 
92

not develop even after POLR service prices rise to market levels because POLR service 

customers will be locked in to the POLR provider. Finally, continued POLR service price caps 

in an environment of increasing wholesale prices increase can endanger the financial viability of 

the distribution utility. 

3. Different POLR Services Designed for Different Classes of Customer

Some states have different POLR service designs for different customer classes. POLR service 

prices offered to large C&I customers generally have entailed 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 better understanding of price risk, the means to reduce it, 

and the costs to reduce it than do other customer classes. In addition, suppliers often can 

customize service offerings to the unique needs of these large customers.235 Large C&I 

customers, with their larger loads, 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.236

In states in which this division between POLR service for large C&I customers and POLR 

service for residential and small C&I customers has been implemented, there has been more 

switching to competitive providers among large C&I customers.237 Many alternative suppliers 

have reportedly developed customized time of use contracts for large C&I customers.238

Moreover, the profiled states show that there are a substantial number of suppliers actively 

serving large C&I customers. Box 4-5 describes the unique sign-up period that Oregon has 

developed for its non-residential customers. 

 235 See, e.g., Wal-Mart and 10-11; Morgan. 

236 In case 03-E-0641, the New York 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.” 

237 New Jersey profile, Appendix D; RESA. 

238 See, e.g., Consolidated Edison; Alliance for Retail Energy Markets; Constellation; PPL; RESA; NY 

PSC; Direct Energy; Reliant; PA OCA; Wal-Mart; Morgan. 
93

Exposure of all customers to time-based prices is not necessary to introduce price-responsiveness 

into the retail market.239 As a first step, customers who are the most price-sensitive and elastic 

could be exposed to time-based rates. Niagara Mohawk in upstate New York has taken this 

approach for its largest customers, as have Maryland and New Jersey for their largest customers. 

California is considering setting real-time pricing as the default rate for medium-sized and larger 

commercial and industrial customers. Another means to introduce price-responsiveness is to 

provide customers voluntary time-based rate programs, along with assistance in equipment 

purchase or financing. The actions of the New York PSC to require voluntary TOU for 

residential customers, and the Illinois legislature to require that residential customers be offered 

real-time pricing as a voluntary tariff are examples of such a policy. Of course, the point is that 

competition will provide customers with the mix of products and services that match their needs 

and preferences – not a determination of the popularity of real-time pricing. 

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 has proposed to use a similar auction when its rate caps 

expire. Auctions may allow retail customers to obtain the benefit of competition in wholesale 

markets as suppliers compete to supply the necessary load. However, as discussed in Chapter 3, 

if there is a load pocket, use of an auction is unlikely to help this process and thus the benefits of 

competition may not be as great. 

5. Consumer Awareness of Customer Choice and Engendering Interest in Alternative 

 Suppliers

Observers of restructuring in other industries have found that the growth of customer choice can 

be a slow process. A commonly cited example is that it took 15 years before AT&T lost half of 

long-distance service customers to alternative suppliers.240 One reason why retail competition 

 239 Steven Braithwait and Ahmad Faruqui, The Choice Not to Buy: Energy Savings and Policy 

Alternatives for Demand Response, PUBLIC UTILITIES FORTNIGHTLY, March 15, 2001 

240 James Zolnierek, Katie Rangos, and James Eisner, Federal Communication Commission, Common 

Carrier Bureau, Industry Analysis Division, Long Distance Market Shares, Second Quarter 1998 (September 1998), 

pp. 19-20, available at http://www.fcc.gov/Bureaus/Common_Carrier/Reports/FCC-State_Link/IAD/mksh2q98.pdf, 

and Thomas L. Welch, Chairman, Maine Public Utilities Commission, UtiliPoint PowerHitters interview (January 

Box 4-5 

Oregon’s Annual Window for Switching for Nonresidential Customers 

Nonresidential customers of the two large investor-owned distribution utilities in Oregon can switch to an 

alternative supplier, but the switching process is unique. Nonresidential customers must make their selections 

during a limited annual window. The window must be at least 5 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 5 years, with an annual renewal after than. As of 2005, alternative 

suppliers were anticipated to serve about 10% of load in one distribution area and about 2.1% in the other. The 

former utility offered choice beginning in 2003. The latter utility began customer choice in 2005. Detailed 

descriptions are available at http://www.oregon.gov/PUC/electric_restruc/indices/ORDArpt12-04.pdf. 
94

could be slow to develop is that the expected gains from learning more about market choices are 

too small be make it worthwhile to learn.241 Residential customers with small loads might be in 

this position in states with retail customer choice.242 

The pricing of POLR service and aid in computing the “shopping credit” may be elements that 

can encourage more rapid development of retail competition by making the rewards for active 

search sufficient to motivate search behavior by residential consumers. Some states that have 

low “shopping credits” have had little retail entry. Some of retail competition states have had 

substantial consumer education programs, including websites with orientation materials and 

price comparisons.243 These efforts minimize the cost of learning more about the market and 

about market alternatives and can, therefore, make market search beneficial to customers. 

New York has engaged in a different approach to encourage the development of retail 

competition. It is helping to organize temporary discounts from alternative suppliers and 

ordering distribution utilities to make these discounts known to consumers who contact the 

distribution utility.244 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 once the temporary discounts no 

longer apply.245

 

24, 2003) available at http://mainegov-images.informe.org/mpuc/staying_informed/about_mpuc/commissioners/phwelch.pdf. 

241 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. 

242 Joskow, Interim Assessment. 

243 See, e.g., ELCON; Progress Energy; Constellation; PEPCO; PA OCA. 

244 In Case 05-M-0858, the New York Public Service Commission adopted the “PowerSwitch” alternative 

supplier referral program, first developed by Orange and Rockland, as the model for all state utilities. 

245 New York State Consumer Protection Board, Comment to the New York State Public Service 

Commission, Case 05-M-0334, Orange and Rockland Utilities, Inc., Retail Access Plan (May 2, 2005) at 5. The 

Board indicates that retail customers who have participated in “PowerSwitch” are returning to POLR service at a 

rate of less than 0.1% per month. The Board applauds PowerSwitch because it is completely voluntary and provides 

assured initial savings to consumers. 
95

APPENDIX A 

LIST OF COMMENTERS WHO RESPONDED TO TASK FORCE NOTICE 

REQUESTING COMMENTS FOR 1815 REPORT*

* Published in the Federal Register as FERC Docket Number AD05-17-000, Issued October 18, 

2005 – actual comments may be found at FERC.gov

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 (California State Commission) 

Cape Light Compact 

Carnegie Mellon Electricity Industry Center (Carnegie Mellon) 

CenterPoint Energy Houston Electric, LLC (CenterPoint) 

Los Angeles Department of Water and Power (LADWP) 

Commercial End Users: 7-Eleven, Inc, Big Lots Stores, Inc., Crescent Real Estate Equities, 

Federated Department Stores, Hines, JC Penney, Wal-Mart Stores, Inc. 

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

Connecticut Department of Public Utility Control (Connecticut State Commission) 

Consolidated Edison Company of New York, Inc. and Orange and Rockland Utilities, Inc. 

(together, New York Companies) 
96

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), 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 State Commission) 

Illinois Commerce Commission (Illinois State Commission) 

Independent Power Producers of New York, Inc. (IPP NY) 

Indiana Utility Regulatory Commission (Indiana State Commission) 

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 
97

Large Public Power Council (LPPC) 

Lehigh Cement Company (Lehigh) 

Maine Office of Public Advocate (Maine Public Advocate) 

Midwest Independent Transmission System Operator Inc. (MISO) 

Midwest Stand-Alone Transmission Companies 

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. (New York ISO) 

New York State Department of Public Service (New York State Commission) 

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

Corporation (Rochester G&E) (together, New York and 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) 

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) 
98

Pepco Holdings, Inc. (Pepco) 

PJM Interconnection, LLC (PJM) 

PNM Resources, Inc. (PNM) 

PPL Companies (PPL) 

Progress Energy, Inc. (Progress) and South Carolina Public Service Authority (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) 

Virginia State Corporation Commission 

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

WPS Resources Corporation (WPS) 

Xcel Energy Services, Inc. (Xcel) 
99

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 
100

APPENDIX C 

AN ANNOTATED BIBLIOGRAPHY OF QUANTITATIVE COST BENEFIT 

ASSESSMENTS OF ELECTRIC INDUSTRY RESTRUCTURING PROPOSALS 

Commenters on the 1815 study highlighted a wide variety of cost-benefit studies that seek to 

evaluate the electric power industry. Indeed , 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 1815 Task Force reviewed roughly 30 cost-benefit analyses246 in an attempt to better 

understand what they reveal. Based on this review, together with a review of the recent 

Department of Energy Report (A Review of Recent RTO Benefit-Cost Studies: Toward More 

Comprehensive Assessments of FERC Electricity Restructuring Policies” By J. Eto, B. 

Lesieutre, and D. Hale, December 2005), the Task Force has drawn the following conclusions: 

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 juxtapose 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 et. Al., p. 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. 

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, 

 

246 This review focuses on original studies – responses and critiques to these studies are listed under the “Alternate 

Views” table category. 
101

market behaviors, generation costs, etc. (See Appendix C: “Study of Costs, Benefits and 

Alternatives to Grid West”, vs. “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 

looses, 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 a 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. 

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 
102

Midwest: $ 8 billion 

South: $24 billion 

West: -$7 billion 

Alternate Views • American Public Power Association 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 

the National Rural Electric Cooperative Association, November 

18, 2005 

• The Electricity Journal, “A Response to Two Recent Studies that 

Purport to Calculate Electric Utility Restructuring Benefits 

Captured by Consumers,” H. Spinner, 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 

Department of Energy , and the GSA), industry experts, representatives 

from utilities, and customers 

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

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 
103

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% 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 • “RTO Dollars and Sense: Financial Data Raises Doubts About 

Whether Deregulation Benefits Outweigh Costs,” M. Lutzenhiser, 

Public Utilities Fortnightly, December, 2004. 

• “Commentary on FERC Staff Report on Day-1 RTO Cost” 

Alliance of State leaders Protecting Electricity Consumers, 

November, 2004: 

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). 
104

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% 

in 2005, increasing to 2% by 2020, relative to the non-SMD case. 

3. The net benefit to all consumers of implementing SMD is estimated to 

be $1 billion/year 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. In the NWPP Region, wholesale prices are predicted to drop by 3-4% 

and retail rates are expected to increase by 1%. The discrepancy is 

attributed to two factors- the assumption that BPA would be selling 

into less lucrative markets, decreasing surplus income and increasing 

rates and the NW’s loss of transmission revenues from exports. 

Alternate Views Commentary on DOE’s Study of Standard Market Design, Alliance of 

State Leaders Protecting Electricity Consumers, June, 2003, 

http://www.pulp.tc/Alliance_Commentary_on_DOE_Study.pdf 

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 
105

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% improvement in transmission transfer capability and 

measures production cost impacts. 

• Capacity sharing benefits simulated. 

• Decreased reserve requirements (from 15% to 13%) 

• 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% 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, 3/13/03 

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 
106

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 
107

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’s “Putting Competitive Power Markets to the 

Test”: An Alternative View of the Evidence 

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 Interconnection, LLC 

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 
108

generation service costs (GSC) are the unbundled generation portion of the 

pre-deregulation 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 National Rural Electric Cooperative Association 

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’s ) study entitled “Estimating the Benefits of Restructuring 

Electricity Markets: An Application to the PJM Region” (hereafter 

referred to as the “Study”), dated September 22, 2003. 

Period Studied 1997-2002 

Conclusion The 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” at 

http://www.caem.org/website/pdf/PJM.pdf

Estimating the Benefits of Restructuring Electricity Markets: An Application to the PJM 

Region 

Region PJM 

Report Date October, 2003 

Sponsor Center for the Advancement of Energy Markets (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 
109

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 New York ISO 

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 

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 
110

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 

in all states studied other than Maine increased an average of .8% per 

year prior to competition and they increased by 2% per year after 

competition. 

Web Reference http://wpweb2.tepper.cmu.edu/ceic/papers/ceic-05-01.asp 

Economic Assessment of American Electric Power's Participation in PJM 

Region PJM combined with American Electric power 

Report Date December, 2003 

Sponsor American Electric Power (AEP) 

Author/Contractor Cambridge Energy Research Associates 

Model/Method ? 

Scope of Inquiry Quantifies the costs and benefits of AEP’s integration into PJM markets. 
111

Period Studied ? 

Conclusion $245M 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 

STUDIES OF BENEFITS IN THE NORTHWEST

BPA Grid West Benefit Assessment for Decision Point 2 

Region Northwest US 

Report Date August 4, 2005 

Sponsor Bonneville Power Administration 

Author/Cont

ractor 

Internal BPA 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 
112

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 

$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. 

Web Reference http://www.gridwest.org/Doc/RR_PreliminaryReport_July192005.pdf 

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 
113

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 

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% of this benefit can be attributed to the elimination of 

rate pancaking, 60% to reserves sharing. 

Web Reference http://www.rtowest.com/Doc/BenCost_031102_RTOWestBCFinalRevised

.pdf 

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 
114

• RTO Annual Costs of $63-$76 million 

• Misc. qualitative benefits 

Web Reference http://www.rtowest.com/Doc/Benefit_Cost_Study_FinalDraft_Oct2320

00.PDF 

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.icfconsulting.com/Markets/Energy/doc_files/gridflorida-rtoreport.pdf 
115

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 

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 
116

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. 

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 +$1,421 to +$854 for SeTrans; -$286 to +$84 for Grid South; 

-$25 to +248 for Grid Florida: ($Million 2003 dollars, PV over 10 years) 

Note: Total Benefits are Net of Estimated Costs of Operating RTO 

Web Reference http://www.crai.com/pubs/pub_2901.pdf 

STUDIES OF BENEFITS IN TEXAS

Electric Reliability Council Of Texas, 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. 
117

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 
118

APPENDIX D 

STATE RETAIL COMPETITION PROFILES 

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,247 commercial customers with businesses at ten or more sites 

with an aggregate coincident peak demand of 9.5 megawatts or greater, and non-residential 

customers accounting for one-third of the remaining electricity use of their customer class. All 

other non-residential customers were allowed to choose a supplier as of December 31, 2000, and 

all residential customers as of May 1, 2002.248 The mandatory transition period ends January 1, 

2007.249 

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.250 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 only be declared competitive 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.251

 

 247Average 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. 

248220 Ill. Comp. Stat. § 5/16-104 (West 2001). 

249SB2081 enacted in June 2002 extended the transition period from January 1, 2005, to January 1, 2007. 

250 Order in Docket No. 02-0479. 

251Id. at § 5/16-113. 
119

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).252

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.253 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 2004, the number of active suppliers in each distribution utility’s 

territory ranged from zero for MidAmerican to eight for ComEd.254 Over the 2000 to 2004 

period, the number of suppliers increased in the AmerenCIPS service territory from 3 to 5. 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. 

Retail Pricing Trends: As Table 1 shows, retail prices for the residential sector rose about 7% 

between 1988 to 1997. Commercial and industrial prices rose by lesser amounts during that 

decade. Prices for all classes of customers declined after that through 2004 with the largest 

declines taking place in the residential sector due to mandatory rate reductions. 

 252Id. at § 5/16-110. 

253Id. at § 5/16-115. 

254 ICC, Competition in Illinois Retail Electric Markets in 2004 (April 2005), Table 2. 
120

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 Provider of Last Resort (POLR) Service for Residential Customers: In accord 

with the restructuring legislation, there have been mandatory residential POLR service rate 

reductions instituted in 1998, which depend 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 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 2.255 

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 October 1, 1998. 

Residential customers were able to elect real-time pricing beginning October 1, 2000.256 Real 

time pricing is pricing which varies hour by hour for non-residential customers, and on a periodic 

basis during the day for residential customers.257 The largest residential real-time pricing effort 

is a pilot program involving 1,500 customers in the Commonwealth Edison territory operated by 

 255S.B. 24, amending H.B. 362, enacted June 30, 1999. Comment of the ICC to the Task Force, Question 

IV.B.2. 

256Id. at § 5/16-107. 

257Id. at § 5/16-102. 
121

the Community Energy Cooperative.258 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.259 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.260

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.261

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 utilities 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 very little outside of these three. 

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 0.0% 0.0% 0.0% 0.0% 

 258 Robert Lieberman, ICC Commissioner, “Ruminations on Demand Response --- a View from Chicago” 

(October 28, 2005), available at http://www.raabassociates.org/Articles/Lieberman_10.28.05.ppt#299. 

259Id. at § 5/16-103. 

260Id. at § 5/16-108. 

261See 220 Ill. Comp. Stat. § 5/16/-103(d). 
122

139 (0.0%) (0.0%) (0.0%) (0.0%) 

Source: Illinois Commerce Commission 

Table 4 shows the patterns of switching statement 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%) 

Source: Illinois Commerce Commission 

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% 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% to create the proxy for the state-wide value. 

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 

Source: Used with permission, 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. 

Note: Trust Funds are administered by the Illinois Department of Commerce and 

Economic Opportunity (DCEO). 

* In Dec97, 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 ok’d by legis. May 99 (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. Commonwealth Edison 
123

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:

262 Prior to the restructuring legislation (1997), utilities operated 97% of 

the generation capability in Illinois. By 2002, that figure dropped to 9.1%. 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 by 135 million megawatt-hours to 188 million megawatt-hours, a nearly 40% 

increase. During the 1993 to 1997 period, output in the state had shrunk by more than 5%. 

Use of Customer Information: No customer specific information can be given to a supplier 

without customer authorization.263

Standardized Labeling:

264 “The 1997 Illinois restructuring law includes provisions for disclosing 

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% in 2007 and rising by one percent 

each year until it reaches 8% in 2013.265 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 

 262 Department of Energy, Energy Information Administration, Illinois State Profile, Table 4, available at

http://www.eia.doe.gov/cneaf/electricity/st_profiles/illinois.pdf. 

263Id. at § 5/16-122. 

264 Department of Energy, Energy Information Administration, “Disclosure Policies” available at

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 

265 ICC Resolution, “Response to Governor’s Sustainable Energy Plan for the State of Illinois,” 05-0437 

(July 19, 2005). 
124

(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.266

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 ends for most 

consumers in the Maryland as of July 2006. 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.267 A supplier must also 

give proof of financial integrity,268 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.269 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. 

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

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%.270

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 Provider of Last Resort (or Regulated) Service: Individual distribution utility 

plans vary, but a cap for all distribution utilities was put into effect through 2004 and then 

 266 Md. Code Ann., Pub. Util. Comp., ∋7-509 (2000). 

267 Id. at ∋7-507.b. 

268 Id. at ∋7-507.c. 

269 PSC Supplier Authorization Procedures (Mar. 17, 2000). 

270 Andrew Green, “Utility, Legislators Not Close on Rates,” Baltimore Sun (April 4, 2006). 
125

extended for two to four years. During the initial four years, distribution utilities were required 

to decrease prices 3-7.5%.271 During this period, if the distribution utility’s Provider of Last 

Resort (POLR) price increased, transition charges decreased by a corresponding amount, so that 

standard offer customers did not have an overall price increase.272

Provider of Last Resort 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 are 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.273 

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 

from the creation of customer choice.274 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 to customers. 

Switching Activity: Table 7 show 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. 

 271 Md. Code Ann., Pub. Util. Comp., ∋7-505.d (2000). 

272 PSC, Maryland Electric Choice FAQ. <www.psc.state.md.us/psc/electric/FAQ/overall.htm> 

273 Md. Code Ann., Pub. Util. Comp., ∋7-513 (2000). 

274 Id. at ∋7-501.p. 
126

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%) 

Source: Maryland PSC 

Note: Prior to 2004, Non-residential data were combined into a single category. 

Public Benefits Programs: Funds for a Universal Service Program will be collected from all 

customers, and may not be assessed on a per kilowatt-hour basis.275

Table 9: Maryland Public Benefits Programs 

 Research & 

Develop. 

Energy 

Efficiency 

Low 

Income 

Renewable 

Energy Total 

Million $ Up to 1.0 34.0 34.0+ 

Mills/kWh 0.51 0.51+

% revenue 0.82 0.82+

Admin. Utility State 

MD’s 

restructuring law 

was signed in 

April 1999 

including a $34 

M/yr. tax funded 

Universal Service 

Fund. Additional 

funds from 

individual utility 

settlements. 

Source: Used with permission, 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, 2000.276 Distribution utilities must 

provide a code of conduct to prevent their regulated service customers from subsidizing services 

of unregulated businesses.277 A distribution utility can transfer any of its generation facilities or 

assets to an affiliate, if it desires.278 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. 

 275 Md. Code Ann., Pub. Util. Comp., ∋7-512.1 (2000). 

276 Id. at ∋7-505.b(10). 

277 Id. at ∋7-505.b(13). 

278 Id. at ∋7-508. 
127

Generation Capability: Prior to the restructuring legislation, utilities operated 95.4% of 

generating capability in Maryland. By 2002, that figure dropped to 0.1%. 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.279 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.280

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.281 

• Timing: Labels must be provided to customers every six months.282

Renewable Energy Portfolio Standard: Maryland enacted a renewable energy portfolio standard 

in 2004. The standard gradually increases to 7.5% in 2019. A separate standard of 2.5% 

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 

 279 Md. Code Ann., Pub. Util. Comp., ∋7-505.b (2000). 

280 PSC Order 76110 (Apr. 25, 2000). 

281 PSC Order 76241. See section below on advertising restrictions for supplier requirements to disclose 

pricing information to customers. 

282 Md. Code Ann., Pub. Util. Comp., ∋7-505.b (2000). 
128

then received a “default” service. Unlike most states that provided Provider of Last Resort 

(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 Provider of Last Resort (POLR) service. 

 

Alternative Suppliers Licensed to Provide Service: All alternative suppliers must be licensed to 

provide service to customers in Massachusetts.283 Licensing regulations require a supplier to 

show technical and financial capability.284 Massachusetts maintains a roster of registered 

competitive electricity suppliers including brokers and direct competitive suppliers. The roster 

in February 2006 included 30 direct suppliers and twice as many brokers.285 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 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 

2001 2002 2003 2004 

Residential 8.5 9.1 9.7 10.4 10.6 11.0 11.1 11.3 11.3 11.6 10.6 10.1 10.8 12.5 10.9 11.7 11.75 

Commercial 7.7 8.1 8.6 9.2 9.3 9.7 9.8 9.9 9.9 10.3 9.4 8.9 9.0 11.6 10.0 10.5 11.0 

Industrial 6.8 7.3 7.9 8.5 8.6 8.7 8.5 8.4 8.4 8.8 8.2 7.7 8.1 9.4 8.3 9.1 8.5 

All Sectors 7.8 8.3 8.8 9.5 9.7 10.0 10.0 10.1 10.1 10.5 9.6 9.1 9.5 11.6 10.1 10.6 10.8 

Source: Energy Information Administration

Price Changes for Standard Offer Service: Massachusetts set a minimum 10% 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%, in order to adjust for inflation. These 

rate reductions applied to all distribution utilities.286 Distribution utilities were authorized to use 

securitization to meet the second rate reduction effective September 1, 1999.287 

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.288

 283Mass. Gen. Law ch. 164, §1F(1) (2001). 

284Mass. Regs. Code tit. 220, §11.05(2) (2001). 

285 DTE, Mass. Competitive Electricity Suppliers (2/14/2006). 286Mass. Gen. Law ch. 164, §1B(b) (2001). 

287Id. at §1G(c)(2). 

288Id. at §1B(b). 
129

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.289

 

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 

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.290 This charge was 

capped by the DTE, and the DTE determined, on a case-by-case basis, the time period for 

recovery.291

Switching Restrictions and Minimum Stay Requirements: Customers can switch to or from 

POLR (default/basic) service.292

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 any other area of the state. 

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%) 

 289Id. at §1B(d). 

290Id. at §1G(a). 

291Id. at §1G(e). 

292 David L. O’Connor, Commissioner, Mass. Division of Energy Resources, “Retail Competition: 

Managing a Difficult Transition,” (April 6, 2001), p. 6, available at http://www.nga.org/Files/ppt/ElecOconnor.ppt. 
130

Cambridge 

154,540 

0.2% 

(0.3%) 

6.7% 

(13.5%) 

8.4% 

(12.4%) 

33.6% 

(52.6%) 

Commonwealth 

403,108 

54.2% 

(51.8%) 

55.0% 

(57.5%) 

44.3% 

(46.2%) 

65.6% 

(70.5%) 

Fitchburg 

47,256 

0.0% 

(0.0%) 

3.8% 

(2.9%) 

4.8% 

15.5% 

72.7% 

(86.6%) 

Mass. Electric 

1,995,096 

2.1% 

(2.4%) 

7.4% 

(12.2%) 

31.1% 

(29.3%) 

58.1% 

(66.2%) 

Nantucket 

12,547 

0.2% 

(1.3%) 

4.4% 

(6.6%) 

23.6% 

(29.3%) 

50.0% 

(53.2%) 

Western Mass. 0.5% 

(0.7%) 

6.6% 

(11.9%) 

32.4% 

(36.8%) 

60.2% 

(76.3%) 

Source: Mass. Department of Telecommunications and Energy 

Table 13 shows the state aggregate levels of 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% to 30.4% 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 

In Nov97, comprehensive legislation was 

signed bringing retail 

access to all customers 

in 1996, included a % revenue 2.81% EE 0.58% 3.38% 
131

non-bypassable wires Admin. Utility Utility MTPC 

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. 

Source: Used with permission, American Council for an EnergyEfficient Economy, “Summary Table of Public Benefit Programs and 

Electric Utility Restructuring” (December 2005) available at 

http://www.aceee.org/briefs/mktabl.htm. 

Note: MTPC is part of the Massachusetts Technology Collaborative.

Separation of Generation and Transmission: The Massachusetts restructuring law required 

distribution utilities to divest their generation facilities (either by sale or by transfer to an 

affiliated company), if they sought to recover stranded costs.293 If a distribution utility opted to 

transfer its generation assets to an affiliate, the two companies had to be strictly separated,294 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).295 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:

296 Prior to the restructuring legislation, utilities operated 86.6% of 

generating capability in Massachusetts. By 2002, that figure dropped to 9.0% with 91% 

belonging to independent power producers. Between 1997 and 2002, generation capability 

increased from 11,328 megawatts to 12,159 megawatts. Most of the new capacity uses natural 

gas.297

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.298

Standardized Labeling:

299 “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, 

 293Mass. Gen. Law ch. 164, §1A(b)(2) (2001). 

294Id. at §1A(c). 

295Id. at §1A(b)(1). 

296 Department of Energy, Energy Information Administration, Massachusetts State Profile, Table 4, 

available at http://www.eia.doe.gov/cneaf/electricity/st_profiles/massachusetts.pdf. 

297EIA, State Electricity Profiles 2002, Massachusetts Electric Power Industry Generating Capability by 

Primary Energy Sources, 1993, 1997, and 2002. 

298Id. at §11.04(12). 

299 Department of Energy, Energy Information Administration, “Disclosure Policies” available at

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 
132

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 Independent System Operator (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.” 

Renewable Energy Portfolio Standard: Massachusetts enacted a minimum renewable energy 

portfolio standard on April 26, 2002. The standard started at 1% in 2003 and increases to 4% in 

2009 in one half percent increments. After 2009, the standard is scheduled to increase in 1% 

increments at least through 2014.300

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.301 

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 does not receive basic generation 

service from the distribution utility.302

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 

 300 225 CMR 14.00. 

301 New Jersey BUP, Order 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. 

302N.J. Stat. Ann. §48:3-51.3 (2001). 
133

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.303 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. 

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% rate reduction with an additional reduction of at least 5% over the first three years 

of the transition period for POLR service. This entailed a reduction of at least 10% 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 2003.304 

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...”305 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. 

 303BPU, Interim Licensing and Registration Standards §4.e. 

304 Jeanne M Fox, N.J. B.P.U Chair, “New Jersey’s BGS Auction: A Model for the Nation,” Public Utilities 

Fortnightly (Sept. 2005), pp. 16-19. 

305 N.J. Board of Public Utilities Press Release, February 15, 2002. 
134

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: NJ 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.306 Through BGS, all 

customer classes are eligible for generation service overseen by the BPU.307 Non-residential 

customers who return to BGS are generally required to remain with that service for one year.308 

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).309 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% 0.0% 0.7% 64.0% 

 306N.J. Stat. Ann. §48:3-57.9.a (2001). 

307Id. at §48:3-51.3. 

308NJ Ratepayer Comments at 7. 

309Id. at §48:3-61.13.i. 
135

 (15.3%) (84.0%) 

Rockland 0.0% 

(4.4%) 

0.0% 0.3% 55.0% 

(70.3%) 

Source: New Jersey BPU and Restructuring Today (January 27, 2006), p. 3. 

Note: New Jersey does not report separate residential and small C&I load of alternative suppliers. 

The number of residential customers served by alternative suppliers is and has remained very 

low with the peak of less than 6% in the Conectiv (Atlantic) distribution area in December 

2000.310 As of December 2005, less than 1,000 residential customers had alternative suppliers 

in the entire state.311 As with the residential sector, the number of small C&I customers served by 

alternative suppliers peaked in December 2000 with 8.6% of customers and 16.3% of load for 

this class of customer served by alternative suppliers.312 As of December 2005, less than 1% 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%) 

Source: Restructuring Today various issues. 

Note: Archives of N.J. BPU switching statistics are not available. [SHOULD WE CONTACT?] 

 

Public Benefits Programs: Table 19 identifies the elements and New Jersey’s public benefit 

programs. 

Table 19: New Jersey Public Benefits Programs 

 310 FTC Staff, Competition and Consumer Protection Perspectives on Electric Power Regulatory Reform: 

Focus on Retail Competition (2001), pp. A78 to A80. 

311 N.J. B.P.U, “New Jersey Electric Statistics,” (December 2005). 

312 FTC Staff, Competition and Consumer Protection Perspectives on Electric Power Regulatory Reform: 

Focus on Retail Competition (2001), pp. A78 to A80. 
136

 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: Used with permission, American Council for an EnergyEfficient 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, 

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.313 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.314 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 1999.315

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:

316 Prior to the restructuring legislation, utilities operated 81.2% of the 

generation capability in New Jersey. By 2002, that figure dropped to 6.8% after divestitures, 

transfers, and entry of new generators. Between 1997 and 2002, generation capability in the 

state increased from 16,855 megawatts to 18,384 megawatts, an increase of 9.1%. Nearly all of 

 313Id. at §48:3-59.11.a. 

314NJ Ratepayer Comments at 9. 

315Rockland Utilities Divestiture Approval (June 24, 1999). 

316 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. 
137

the increase was in dual fueled generators built by IPPs. During the 1993 to 1997 period, 

generating capability had increased by less than 3%. 

 

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.317 

Standardized Labeling:

318 “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 

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% for 2005 

and rises to 6.5% 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 Public Service Commission (PSC) 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 New York PSC ordered distribution utilities to submit plans to speed the 

development of retail competition.319 Subsequently, the PSC adopted the program developed by 

Orange and Rockland (O&R) as the model for all utilities to follow.320 The O&R program 

requires the utility to invite any customers who contact the utility to try an alternative supplier 

 317Id. at §48:3-85.36.b. 

318 Department of Energy, Energy Information Administration, “Disclosure Policies” available at

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 

319 NY PSC, Case 00-M-0504, “Statement of Policy on Further Steps toward Competition in Retail Energy 

Markets” (August 25, 2004). 

320 The Central and Hudson retail competition enhancement plan, including this approach, was approved by 

the PSC on June 1, 2005 (Case 05-M-0332). The PSC has rejected substitute approaches proposed by other 

distribution utilities. 
138

for a two-month period. Alternative suppliers participating in the program offer a one-time 7% 

discount for the trial period. Customers can either pick an alternative supplier or have one 

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.321 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 that 

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 

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.322

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 designated 

POLR service provider in the distribution territory. POLR service for large C&I customers is 

offered on an hourly price basis that tracks wholesale spot market prices. 

Alternative Suppliers Licensed 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. 

 321 NY PSC, Case 03-E-0641, “Order Instituting Further Proceedings and Requiring the Filing of Draft 

Tariffs” (September 23, 2005). 

322NYPSC Case 00-E-0165 – In the Matter of Competitive Metering and Case 94-E-0952 – In the Matter 

of Competitive Opportunities Regarding Electric Service (Feb. 26, 2001). 
139

 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% per year rate reductions until mid-2001. 

• Con Edison industrial customers received a 25% immediate rate decrease, which 

remained fixed for five years. All other customers received a 10% rate decrease, phased 

in over five years. 

• Orange and Rockland residential customers received a 4% decrease in rates during 1995 

and 1996, while industrial and commercial customers received rate reductions of 4-14%. 

On December 1, 1997 and on December 1, 1998, residential rates were reduced an 

additional 1%. Large industrial customer rates were reduced by approximately 8.5% on 

December 1, 1997. 

• Rochester Gas and Electric residential and small commercial customers received a 7.5% 

rate decrease. Other commercial and most industrial customers received an 8% decrease. 

Large industrial customers received an 11.2% 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% 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% in the third year of the plan, and a total decrease of 5% by 

the fifth year of the plan. Industrial and commercial customers who are not eligible for 

the 5% 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%. Residential and commercial customers were to have a 3.2% decrease 

phased in over three years. Industrial customers were to have decreases of approximately 

13%. 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. 
140

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.323

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 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.324

Switching Restrictions and Minimum Stay Requirements: The NY PSC is in the midst of 

implementing policies to encourage consumers to try alternative suppliers.325 These policies do 

not authorize suppliers to levy charges against departing customers. 

Switching Activity: The switching statistics for December 2005 in each distribution territory 

appear in the Table 21. 

Table 21: New York Retail Customers and Load Supplied 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: New York PSC 

The aggregate switching statistics for the utility distribution territories in the states 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 

 323NYPSC Opinion 96-12, Opinion and Order Regarding Competitive Opportunities for Electric Service 

(May 20, 1996). 

324Id. 

325 New York State Department of Public Service, Staff Report on the State of Competitive Energy Markets: 

Progress to Date and Future Opportunities (March 2, 2006), Electric and Natural Gas Retail Markets sections I to 

III. 
141

% 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: New York PSC, Electric Retail Access Migration Reports 

Public Benefits Programs: New York’s public benefit programs are charted in the Table 23 

below. 

Table 23: New York Public Benefits Programs 

 Research & 

Development 

Energy 

Efficiency 

Low 

Income 

Renewable 

Energy 

Total 

Million $ 26.0 87.0 22.0 150.0 

Mills/kWh 0.26 0.83 0.21 1.42 

% revenue 0.20% 0.69% 0.17% 1.18%

Admin. NYSERDA NYSERDA NYSERDA 

In May95, the PSC 

issued Order 96-12 

requiring all IOUs 

to file restructuring 

plans. A July98 

Order set $78 

million/year for an 

SBC, administered 

by NYSERDA. In 

Jan01 the PSC 

raised the SBC to 

$150 million/yr 

and extended it for 

5 years. (Table 

shows allocation 

minus 10% held 

open.) R&D incl. 

$14 million/yr for 

RE. Table does 

not include $100 

million/yr EE by 

Power Authorities 

Source: Used with permission, 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. 

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 

(In the Matter of System Benefits Charges III, Case 05-M-0090, available at 

http://www.state.nj.us/bpu/wwwroot/energy/EX99090676_20040624.pdf. 

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.326 Each distribution utility company’s restructuring 

agreement established different requirements for separation of generation and transmission.327

State RTO Involvement: New York distribution utilities belong to the New York ISO, formed in 

 326NYPSC Opinion 96-12, Opinion and Order Regarding Competitive Opportunities for Electric Service 

(May 20, 1996). 

327PSC Publication: PSC Rate and Restructuring Plan Fact Sheets. 

<www.dps.state.ny.us/energyarch.htm#facts> 
142

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).328

Generation Capability:

329 Prior to the restructuring regulations, utilities in New York operated 

84.3% of the generation capability in the state. By 2002, that figure dropped to 32.4%. The 

difference reflected mandatory divestitures of generation to independent generation firms and 

entry or expansion of independent power producers. Between 1997 and 2002, generation 

capability in the state increased from 35,576 megawatts to 36,041 megawatts. In the previous 

5-year period, generation capability had decreased. Dual fueled generation increased as a 

proportion of generation from 34.1% to 39.5%. 

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.330

Standardized Labeling:

331 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 Energy Information Administration 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% (mostly hydro) to 25% by 2013. 

 328NYISO Frequently Asked Questions. www.nyiso.com/public/services/customer_relations/faqs/index.jsp

329 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. 

330New York Public Service Commission, Case 98-M-1343, Uniform Retail Access Business Practices, 

Appendix A, “Customer Information” (April 14, 1999). <www.dps.state.ny.us/doc5743_appendix_a.pdf> For 

information on the acceptance of uniform retail access business practices in New York see

www.dps.state.ny.us/ubr.htm

331 Department of Energy, Energy Information Administration, “Disclosure Policies” available at

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 
143

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.332 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 

alternative supplier may provide these services.333 Pennsylvania’s efforts to allow licensed 

generation suppliers to provide metering and billing services to retail customers were suspended 

on August 12, 2002.334

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.335 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. 

 332Pennsylvania PUC Publication: Pennsylvania Electric Choice, Q&A. 

www.electrichoice.com/public/qa.html

333Pennsylvania PUC Publication: Pennsylvania Electric Choice, How to Shop Guide. 

www.electrichoice.com/public/guide.html

334Letter from the Pennsylvania PUC 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 (February 5, 2004). 

33566 Pa. Cons. Stat. §2809.A (2001). 
144

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, 2006.336 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.337

Overall rate reductions, Table 25 for the first year ranged from 2.5% to 8% for the major utilities 

operating in Pennsylvania:338

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. The 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% of its customers have electric choice.339 In June 2000, the PUC issued a 33666 Pa. Cons. Stat. §2804.4 (2001). 

337Comments of the Pennsylvania Utility Commission, Federal Trade Commission Retail Electricity Study 

(April 9, 2001). 

338Ahmed Kaloko, Ph.D., Chief Economist, Pennsylvania Public Utility Commission, “Power 99–

California & Pennsylvania Retail Market Development.” 

33966 Pa. Cons. Stat. §2807.E (2001). 
145

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.340 The largest CDS effort took place 

in the PECO territory. PECO awarded a contract for 20% 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.341 Due to concerns that POLR prices 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.342

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.343 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 

 340Id. 

341Id. 

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

343 66 Pa. Cons. Stat. §2808.A, B (2001). 
146

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.344

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%) 

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%) 

Source: Pennsylvania Office of the Consumer Advocate 

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 

 344 Pennsylvania PUC, 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. 
147

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. 
148

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%

Admin. SEF Utility SEF 

In Dec95, a 

restructuring 

laws was 

signed with 

retail access to 

be phased-in 

over 2 yrs 

starting in 

Jan99. The 

restructuring 

law resulted in 

PUC-approved 

restructuring 

settlement 

agreements for 

each electric 

company. Each 

settlement 

agreement 

created a 

system benefits 

fund for LI 

programs and a 

Sustainable 

Energy Fund 

(except for 

Duquesne). 

Source: Used with permission, 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. 

Note: Administrators are Sustainable Energy Funds in each area of the state. 

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.345 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.346 In March 

2001, Allegheny Power and PJM filed with FERC a request to expand PJM by forming PJM-

 34566 Pa. Cons. Stat. §2804.5 (2001). 

346Pennsylvania Public Utility Commission, Bureau of Conservation, Economics, and Energy Planning, 

“Electric Power Outlook for Pennsylvania: 1999-2004" (July 2000). 
149

West.347

Generation Capability:

348 Prior to the restructuring legislation, utilities in Pennsylvania operated 

92.3% of generation capability in the state. By 2002, that figure dropped to 12.3%, 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 megawatts to 39,783 megawatts. Most of increase 

consisted of dual fueled generation. 

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.349 Customer information 

cannot be given preferentially by a distribution utility to its affiliate.350 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.351

Standardized Labeling:

352 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. 

 347PJM Interconnection Press Release, “Allegheny Power and PJM File with FERC to Create PJM West” 

(Mar. 15, 2001). www.pjm.com/contributions/news-releases/2001/20010315-ap-pjm-file-with-ferc.pdf

348 Department of Energy, Energy Information Administration, Pennsylvania State Profile, Table 4, 

available at http://www.eia.doe.gov/cneaf/electricity/st_profiles/pennsylvania.pdf. 

349Id. at §54.8. 

350Id. at §54.122.2. 

351Comments of the Pennsylvania Utility Commission, Federal Trade Commission Retail Electricity Study 

(April 9, 2001). 

352 Department of Energy, Energy Information Administration, “Disclosure Policies” available at

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 
150

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% 

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% and 

10% 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, 2002.353 Competition is not open as yet in areas outside of ERCOT 

because the PUC is not convinced that retail competition is feasible without a regional 

transmission organization in these areas.354 

Services Open to Competition: Generation and billing (retail sales). Competitive metering for 

commercial and industrial customers began January 1, 2004. Metering for residential customers 

was regulated until September 1, 2004, or until 40% of customers have switched to a competitive 

supplier, whichever is later.355

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. 

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.356 

There are numerous suppliers marketing to all classes of customers in Texas that are open for 

retail customer choice. In addition to the POLR 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”357 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. 

 353Tex. Util. Code Ann. §39.102 (2001). 

 

354 Public Utility Commission of Texas, “Scope of Competition in Electric Markets in Texas (January 

2005), pp. 36-38, available at http://www.puc.state.tx.us/electric/reports/scope/2005/2005scope_elec.pdf. 

355Id. at §39.107. 

356Tex. Util. Code Ann. §39.352-355 (2001). 

357 Available at http://www.puc.state.tx.us/electric/reports/RptCard/rptcrd/aug05rptcrd.pdf. 
151

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 Service: Distribution utility rates were frozen from September 1, 1999, 

levels until January 1, 2002.358 On January 1, 2002, rates for residential and small commercial 

customers were reduced approximately 6% from January 1, 1999, levels and then frozen until 

January 1, 2007, or until 40% of residential or small commercial customers have chosen a 

competitive supplier. The January 1, 2002, reduced rate is called the “price to beat.”359 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.” 

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 price for different levels of consumption. Table 31 shows the POLR 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% 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 14.48 8% 10% 14.77 11% 6% 

 358Id. at §39.052. 

359Id. at §39.202 
152

Power 

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 have 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.360

POLR Service Provider: Until December 31, 2001, POLR service was provided by the 

distribution utility. When competition for all customers began in 2002, POLR 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 service were fixed at 

the “price to beat” plus fuel adjustments. The PUC designates a REP to be the provider of last 

resort for customers whose supplier goes out of business or terminates service to a customer. 

The POLR service provider offers this service at a fixed, non-discountable rate approved by the 

PUC that includes periodic fuel cost adjustments.361 Distribution utilities are to offer POLR 

 360 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. 

361Id. at §39.106. 
153

service at the “price to beat” unless alternative suppliers attain a market share of 40% for a 

particular class of residential and small commercial customers, whichever comes first. In 2004, 

all but one of the distribution utilities within ERCOT (the separate transmission interconnection 

system in Texas), were granted permission to price POLR service for small C&I customers at 

prices other than the price to beat because the 40% market share threshold had been met.362

POLR service customers have been divided into three classes: residential, small non-residential, 

and large non-residential. The POLR service provider supplies customers in any or all of these 

three classes who either request POLR service or are assigned to POLR service because they are 

not receiving service from an REP, for any reason. The rates for POLR service are established 

through a competitive bid process. A bidder for 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 provider in the distribution utility’s own service territory during the period when the 

price to beat is in effect.363 Analysis by the PUC concluded that POLR 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. 

CenterPoint Energy Services Area 2002 2003 2004 2005

Estimated Regulated Price 11.1 12.0 12.7 13.9

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 12.9

 362 Public Utility Commission of Texas, “Scope of Competition in Electric Markets in Texas (January 

2005), p. 24, available at http://www.puc.state.tx.us/electric/reports/scope/2005/2005scope_elec.pdf. 

363PUC Sub. Rules §25.43. 
154

TXU Electric Delivery Service Area 2002 2003 2004 2005

Estimated Regulated Price 9.4 10.5 10.7 12.1

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

Source: PUC legislative report # 32198, “Electricity Pricing in Competitive Retail Markets in 

Texas” (February 3, 2006).364

Recovery of Stranded Costs/Transition Costs: Distribution utilities can recover all of their net 

non-mitigated stranded costs through a transition charge. The PUC determines the amount of 

stranded costs eligible for 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. 365 

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%) 

Source: Texas Public Utility Commission 

 364 The report is available at

http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/32198_7_504891.PDF. 

365PUC Publication, Texas Electric Choice, Electricity Information-FAQ’s. 

<www.powertochoose.org/residential/electricinfo/faq.html> 
155

Note: Texas does not provide separate distribution area statistics for large C&I customers. 

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%) 

Sources: Texas Public Utility Commission 

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 expect the 2005 figure which is from September. 

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 .65 

mills/kWh. 

Source: Used with permission, American Council for an EnergyEfficient 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 (a “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.366 After the beginning of retail competition, a distribution utility 

 366Id. at §39.051. 
156

may not sell electricity or participate in the market for electricity except to procure electricity to 

serve its own needs.367 Wholesale electric power generation companies that are affiliated with a 

distribution utility are required to auction off 15% of their installed generation capacity,368 and 

no wholesale generator can own more than 20% of the installed capacity that can be sold in a 

region.369 REP affiliates of transmission and distribution utilities cannot offer competitive rates 

to residential and small commercial customers in the territory of the distribution utility, except as 

the POLR (standard offer) service provider, until 40% of the residential and small business load 

in the territory is buying electricity from competitive suppliers.370 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%) is in the ERCOT 

interconnection.371 ERCOT began operations as an independent system operator in 1996. It is 

regulated by the Texas PUC rather than by the Federal Energy Regulatory Commission.372 

Transmission operations of distribution utilities outside of ERCOT are regulated by FERC. 

Generation Capability:

373 Prior to the restructuring legislation, utilities operated 88.3% of 

generation capability in Texas. By 2002, that figure dropped to 41.2%, as divestitures, transfers 

to affiliates, and entry and expansion of independent generators took place. Between 1997 and 

2002, generation capability in the state increased from73,454 megawatts to 94,488 megawatts. 

This is an increase of 28.6%. Much of the growth in generation was fueled by natural gas. The 

share of generation capability fueled by natural gas increased from 21.4% to 38.5%. Natural gas 

fueled generation more than doubled during the period. 

Use of Customer Information: Distribution utilities are required to include customer name, 

address, and usage information on a list of eligible customers given to competitive suppliers. 

Distribution utilities will provide their customers with information on how to remove their name 

from this list.374

 367Id. at §39.105. 

368Id. at §39.153 

369Id. at §39.154. 

370PUC Publication, Electric Competition-Fostering Competition, available at

www.choiceenergyservices.com/residential/pdf/Competition.pdf> 

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

372ERCOT, “The Market Guide: A Guide to How the Electric Reliability Council of Texas (ERCOT) 

Facilitates the Competitive Power Market,” (Feb. 22, 2001) 

. 

373 Department of Energy, Energy Information Administration, Texas State Profile, Table 4, available at

http://www.eia.doe.gov/cneaf/electricity/st_profiles/texas.pdf. 

374PUC Publication, Consumer Protections in a Competitive Electric Market, available at

http://www.powertochoose.org/publications/consumer_brochure.pdf. 
157

Standardized Labeling:

375 “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 in March of each year 

and posted on the Commission's web site. 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 with renewable fuels if it can be shown that the 

natural gas was produced in Texas.”376

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. 

The original electric restructuring bill included many environmental protections, including that 

50% 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% reductions in nitrous 

oxide emissions and 25% reduction in sulphur 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.377 The PUC has adopted a renewable 

energy credit trading program to encourage cost-effective new renewable generation facilities. 

 375 Department of Energy, Energy Information Administration, “Disclosure Policies” available at

http://www.eere.energy.gov/greenpower/markets/disclosure.shtml?print. 

376 The consumer brochure on electricity offer labeling is available at

http://www.powertochoose.org/publications/efl_brochure.pdf. 

377PUC Publication, Electric Restructuring to Improve Air Quality, available at

www.puc.state.tx.us/nrelease/2000/082400.cfm. 
158

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, MISO 

and SERC as representative markets for the following reasons. NYISO provides a consistent data 
159

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
160

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 that have had a duration longer than a year 

since contracts were executed. 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% in NYISO, 77% 

in MISO, 60% in SERC); 

 relatively few contracts were older than 10 years (0% in NYISO, 2% in MISO, 16% 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. 
161

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 three 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
162

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. 
163

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 1815 Task Force members have not attempted to generate another primer on restructuring as 

part of its competition study. Instead, we refer 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. 

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. 

http://www.ncouncil.org/pdfs/restruc.pdf

Matthew Brown and Richard P. Sedano, “Electricity Transmission, A Primer”, National Council 

on Electricity Policy, June, 2004. http://www.ncouncil.org/pdfs/primer.pdf 

Energy Information Administration, “The Changing Structure of the Electric Power Industry 

2000: An update”, US Department of Energy, October, 2000 

http://www.eia.doe.gov/cneaf/electricity/chg_stru_update/

William W. Hogan, “Competitive Electricity Market Design: A Wholesale Primer” working 

paper, December, 1998 http://stoft.com/metaPage/lib/Hogan-1998-Primer.pdf

William W. Hogan, “Market Design and Electricity Restructuring”, presentation, Association of 

Power Exchanges (APEx), 2005 Annual Conference, Orlando FL, Presentation, November 1, 

2005. http://ksghome.harvard.edu/~whogan/hogan_apex_110105.pdf 
164

Paul L. Joskow, “Markets for Power in the United States: An Interim Assessment” Energy 

Journal, Forthcoming, 2006. 

http://stoft.com/metaPage/lib/Joskow-2006-power-market-assessment.pdf

Paul L. Joskow (1997), "Restructuring, Competition, and Regulatory Reform in the U.S. 

Electricity Sector", Journal of Economic Perspectives 11(3), 119-138. 

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. Hirsch Power Loss: The Origins of Deregulation and Restructuring in the American 

Electric Utility System (Hardcover) by Richard F. Hirsh, The MIT Press, December 3, 1999. 

Sally Hunt, Making Competition Work in Electricity, Wiley Publishing, March 22nd, 2002. 

Steven Stoft , Power System Economics: Designing Markets for Electricity, IEEE Press, WileyInterscience, 2002. 
165

APPENDIX G 

CREDIT RATINGS OF MAJOR AMERICAN 

ELECTRIC GENERATION COMPANIES* 

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 

PG&E Corp AAA 11.7 0.92 34.07 13.02 

Pinnacle West Capital Corp BBB- 2.99 0.18 12.07 4.05 

PPL 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 
166

Name Credit Rating 

Sales 

($bil) 

Profits 

($bil) 

Assets 

($bil) 

Market Value 

($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 Energy 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 

*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) 

*credit rating is the "Long Term Issuer Default Rating" from Fitch Ratings 

(www.fitchratings.com)