[Federal Register Volume 71, Number 113 (Tuesday, June 13, 2006)]
[Notices]
[Pages 34083-34128]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-5247]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. AD05-17-000]


Electric Energy Market Competition Task Force; Notice Requesting 
Comments on Draft Report to Congress on Competition in the Wholesale 
and Retail Markets for Electric Energy

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice.

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SUMMARY: Section 1815 of the Energy Policy Act of 2005 requires the 
Electric Energy Market Competition Task Force

[[Page 34084]]

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 p.m. Eastern Time June 26, 2006.

ADDRESSES: Comments may be electronically filed by any interested 
person 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. 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 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 Web sites of the Task Force members' agencies:

Department of Justice: http://www.usdoj.gov/atr
Federal Energy Regulatory Commission: http://www.ferc.gov/legal/staff-reports/epact-competition.pdf
Federal Trade Commission: http://www.ftc.gov
Department of Energy: http://www.oe.energy.gov
Department of Agriculture: http://www.usda.gov/rus/electric/competition/index.htm

    Members of the public are invited 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 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 ferc.gov">FERCOnlineSupport@ferc.gov, or call (866) 
208-3676 (toll free). For TTY, call (202) 502-8659.

    Dated: June 5, 2006.
Magalie R. Salas,
Secretary, Federal Energy Regulatory Commission.

Appendix A--Draft Report of the Electric Energy Market Competition Task 
Force

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.

Table of Contents

Executive Summary
Chapter 1. Industry Structure, Legal and Regulatory Background, 
Industry Trends and Developments
Chapter 2. Context For The Task Force's Study of Competition in 
Wholesale and Retail Electric Power Markets
Chapter 3. Competition in Wholesale Electric Power Markets
Chapter 4. Competition in Retail Electric Power Markets
Appendix A: Index of Comments Received
Appendix B: Task Force Meetings With Outside Parties
Appendix C: Annotated Bibliography of Cost Benefit Studies
Appendix D: State Retail Competition Profiles
Appendix E: Analysis of Contract Length and Price Terms
Appendix F: Bibliography of Primary Information on Electric 
Competition
Appendix G: Credit Ratings of Major American Electric Generation 
Companies
Table 1-1. U.S. Retail Electric Providers 2004
Table 1-2. U.S. Retail Electric Sales 2004
Table 1-3. U.S. Retail Electric Providers 2004, Revenues from Sales 
to Ultimate Consumers
Table 1-4. U.S. Electricity Generation 2004
Table 1-5. U.S. U.S. Electric Generation Capacity 2004
Table 1-6. Power Generation Asset Divestitures by Investor-Owned 
Electric Util. as of April 2000
Table 4-1 Distribution Utility Ownership of Generation Assets in the 
State in Which It Operates
Figure 1-1. U.S. Electric Power Industry, Average Retail Price by 
State 2004
Figure 1-2. Status of State Electric Industry Restructuring 
Activity, 2003
Figure 1-3. RTO Configurations in 2004
Figure 1-4. Transmission Expenditures of EEI Members
Figure 1-5. U.S. Electric Generating Capacity Additions: Non-Utility 
Growth Overtakes

[[Page 34085]]

 Utility 2000-2004
Figure 1-6. National Average Retail Prices of Electricity for 
Residential Customers
Figure 1-7. Gas Has Recently Been Dominant Fuel
Figure 1-8. Net Generation Shares by Energy Source
Figure 1-9. Electric Power Industry Fuel Costs, Jan. 2005-December 
2005
Figure 3-1. U.S. Electric Generating Capacity Additions (19602005)
Figure 3-2. Estimate of Annul NY Capacity Values--All Auctions
Figure 4-1. U.S. Electric Power Industry, Average Retail Price of 
Electricity by State, 1995
Figure 4-2. U.S. Map Depicting States with Retail Competition, 2003
Figure 4-3. Average Revenues per kWh for Retail Customers 1990-2005 
Profiled States vs. National Avg.
Appendix D Tables 1-34

Executive Summary

Congressional Request

    Section 1815 of the Energy Policy Act of 2005 (the Act) requires 
the 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.
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    \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.
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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.
     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.

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

[[Page 34086]]

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 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 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

[[Page 34087]]

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\
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    \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.
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    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.
    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 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.

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.
    IOUs continue to be a major presence in the 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 customers 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

[[Page 34088]]

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.
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    \3\ American Public Power Association.
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    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 
self-regulated. 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.
    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\
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    \4\ National Rural Electric Cooperative Association.
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    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. 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).

[[Page 34089]]

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 Electic Institute.

                                                     Table 1-1.--U.S. Retail Electric Providers 2004
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Number of                                   Number of customers
                       Ownership                           electricity      Percent of   ------------------------------------------------   Percent of
                                                            providers         total        Full service    Delivery only       Total           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       2,879,114      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          41,521             1.2
Power Marketers.................................         207,696         203,202         410,898            11.6
                                                 ---------------------------------------------------------------
    Total.......................................       3,267,089         273,269       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 (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
                                                 ------------------------------------------------      Total
                                                   Full service     Energy only      Delivery
----------------------------------------------------------------------------------------------------------------
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.


[[Page 34090]]


              Table 1-4.--U.S. Electricity Generation 2004
------------------------------------------------------------------------
                                            Generation
       Electricity Generation 2004         (thousands of    % of Total
                                               MWhs)
------------------------------------------------------------------------
Publicly-owned utilities................         397,110            10.3
Investor-owned utilities................       1,734,733            44.8
Cooperatives............................         181,899             4.7
Federal Power Agencies..................         278,130             7.2
Power Marketers.........................          42,599             1.1
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.


           Table 1-5.--U.S. Electric Generation Capacity 2004
------------------------------------------------------------------------
                                             Nameplate
                Ownership                  capacity  (in    % of Total
                                               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 protege, 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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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 
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.
---------------------------------------------------------------------------

    \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 FR 21,540, FERC Stats. & Regs. ] 31,036, 31,639 
(1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 
31,048 (1997); order on reh'g, Order No. 888-B, 81 FERC ] 61,248 
(1997), order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), 
aff'd in relevant part sub nom. Transmission Access Policy Study 
Group v. FERC, 225 F..3d 667 (D.C. Cir. 2000), aff'd sub nom. New 
York v. FERC, 535 U.S. 1 (2002)[hereinafter Order No. 888].
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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].
---------------------------------------------------------------------------

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

[[Page 34091]]

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 other \15\ 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\
---------------------------------------------------------------------------

    \10\ See Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,640-
41.
    \11\ Id. at 31,639.
    \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].
    \13\ Order 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.aei-brookings.org/admin/authorpdfs/page.php?id=271 
[hereinafter Joskow, Difficult Transition].
---------------------------------------------------------------------------

    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 
oil-producing 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 power \23\ and 
showed that nonutilities could build and operate generation facilities 
effectively and without disrupting the reliability of transmission 
systems.\24\

    \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.
    \24\ Joskow, Deregulation at 19.
---------------------------------------------------------------------------

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.

    PURPA was largely responsible for creating an independent 
competitive generation sector.\25\ The response to PURPA was dramatic.
---------------------------------------------------------------------------

    \25\ Id. at 17.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \26\ CONG. RESEARCH SERV., COMM. ON ENERGY AND COMMERCE, 102D 
CONG., ELECTRICITY A NEW REGULATORY ORDER? 92 (Comm. Print 1991).
---------------------------------------------------------------------------

    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

[[Page 34092]]

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

    \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.
    \30\ EIA 1970-1991 at vii.
    \31\ Id. at 27.
---------------------------------------------------------------------------

    FERC allowed many new utility and non-utility generators to sell 
electric power supply at wholesale market, rather than regulated 
rates.\32\
---------------------------------------------------------------------------

    \32\ See Order No. No. 888, FERC Stats. & Regs. ] 31,036 at 
31,643.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \33\ See Regulations Governing Bidding Programs, Notice of 
Proposed Rulemaking, 53 FR 9,324 (March 22, 1988), FERC Stats. & 
Regs. ] 32,455 (1988) (modified by 53 FR 16,882 (May 12, 1988)). 
This proposal would have adopted competitive bidding into the 
process of acquiring and 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 FR 9,327 (March 22, 1988), FERC Stats. & 
Regs. ] 32,456 (1988) (modified by 53 FR 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 FR 9,331 (March 22 1988), FERC 
Stats. & Regs. ] 32,457 (1988) (modified by 53 FR 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \36\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \37\ Id. at 102.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 34093]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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 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).
---------------------------------------------------------------------------

    Concurrent with the issuance of Order No. 888, FERC issued Order 
No. 889 \48\ 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\
---------------------------------------------------------------------------

    \48\ Open Access Same-Time Information System (Formerly Real-
Time Information Networks) and Standards of Conduct, Order No. 889, 
61 FR 21,737 (May 10, 1996), FERC Stats. & Regs. ] 31,035 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \50\ EIA 2000 Update at 66.
    \51\ Id. at 66, 68, 80.
    \52\ Id. at 67.
    \53\ Joskow, Deregulation at 27-28.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \54\ EIA 2000 Update at ix.
    \55\ See discussion infra, Box 1-1.
    \56\ Joskow, Deregulation at 19.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \57\ Electricity Consumers Resource Council, Profiles in 
Electricity Issues: Cost-of-Service Survey (Mar. 1986).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \58\ EIA 2000 Update at 43.

---------------------------------------------------------------------------

[[Page 34094]]

[GRAPHIC] [TIFF OMITTED] TN13JN06.003

    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.
---------------------------------------------------------------------------

    \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].

---------------------------------------------------------------------------

[[Page 34095]]

[GRAPHIC] [TIFF OMITTED] TN13JN06.004

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.
    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.
---------------------------------------------------------------------------

    \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 FR 12,088 (2000), aff'd, 
Public Utility District No. 1 v. FERC, 272 F.3d 607 (DC Cir. 2001) 
[hereinafter Order No. 2000].
    \62\ In Order No. 2000, FERC found that ``opportunities for 
undue discrimination 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.
---------------------------------------------------------------------------

    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

[[Page 34096]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \65\ Id. at 53.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \66\ Id. at 52.
    [GRAPHIC] [TIFF OMITTED] TN13JN06.005
    
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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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:
    (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\
---------------------------------------------------------------------------

    \69\ Id. at 107.
---------------------------------------------------------------------------

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

[[Page 34097]]

power industry. Several key provisions of EPACT 2005 are:
---------------------------------------------------------------------------

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

     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.
     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 FERC-authorized cost allocations for non-power 
goods or services provided by an associate company to public utility 
members in the holding company. PUHCA 2005 also contains a mandatory 
exemption from the Federal books and records access provisions for 
entities that are holding companies solely with respect to EWGs, QFs or 
foreign utility companies. The goal 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 gas-fired 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\
---------------------------------------------------------------------------

    \71\ EIA 2000 Update at ix. The size of the cost improvements 
depends on the underlying fuel prices.
    \72\ Id.
---------------------------------------------------------------------------

    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.

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.

[[Page 34098]]

[GRAPHIC] [TIFF OMITTED] TN13JN06.006

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 (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\
---------------------------------------------------------------------------

    \73\ Id. at 23.
    \74\ EIA 1970-1991 at vii.
    \75\ Id.
    \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].
---------------------------------------------------------------------------

    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.

[[Page 34099]]

[GRAPHIC] [TIFF OMITTED] TN13JN06.007

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.
---------------------------------------------------------------------------

    \77\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,640.
    \78\ Joskow, Difficult Transition at 7.

---------------------------------------------------------------------------

[[Page 34100]]

[GRAPHIC] [TIFF OMITTED] TN13JN06.008

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\
---------------------------------------------------------------------------

    \79\ EIA 1970-1991 at 20.
---------------------------------------------------------------------------

    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, 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\
---------------------------------------------------------------------------

    \80\ EIA Electric Power Annual 2004 at 2.
    \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.

---------------------------------------------------------------------------

[[Page 34101]]

[GRAPHIC] [TIFF OMITTED] TN13JN06.009

    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.
[GRAPHIC] [TIFF OMITTED] TN13JN06.010

    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

[[Page 34102]]

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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 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.
[GRAPHIC] [TIFF OMITTED] TN13JN06.011

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.
---------------------------------------------------------------------------

    \84\ See U.S. Congress, Office of Technology Assessment at 47.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \85\ EIA 2000 Update at 91.
    \86\ Id. at 105-06.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \87\ Id. at 105.
    \88\ Id. at 91.
    \89\ Id. at 106.
---------------------------------------------------------------------------

    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

[[Page 34103]]

analysts to herald 2004 as the inauguration of a new round of 
consolidation in the power sector.\90\ One utility-to-utility 
acquisition was closed \91\ 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\
---------------------------------------------------------------------------

    \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.

     Table 1-6.--Power Generation Asset Divestitures by Investor-Owned Electric Utilities, as of April 2000
----------------------------------------------------------------------------------------------------------------
                                                                                                    Percent of
                                                                                    Percent of      total U.S.
                         Status category                           Capacity (GW)       total        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.

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 ``cost-based'' 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.
    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.

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

[[Page 34104]]

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.

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 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\
---------------------------------------------------------------------------

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

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.
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \97\ U.S. Dept. of Energy, The Future of Electric Power in 
America: Economic Supply for Economic Growth, June, 1983 (DOE/PE-
0045).
---------------------------------------------------------------------------

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.

    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\

[[Page 34105]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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' 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \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 Long-Run 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.
---------------------------------------------------------------------------

    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.

    Experience in New York, Georgia, California, and other states and 
pricing experiments have demonstrated that customers have adjusted 
their consumption, and are responsive to

[[Page 34106]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    The ability of a customer to respond to prices requires the 
following conditions: (1) That time-differentiated price signals are 
communicated to customers, (2) that customers have the ability to 
respond to price signals (e.g., by reducing consumption and/or turning 
on an on-site generator), and (3) that customers have interval meters 
(i.e., so the utility can determine how much power was used at 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
    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.
---------------------------------------------------------------------------

    \105\ APPA.
    \106\ Alcoa.
    \107\ TAPS.
---------------------------------------------------------------------------

    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 around-the-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
    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.

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

[[Page 34107]]

ultimately resell the electric power to end-use 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\
---------------------------------------------------------------------------

    \108\ U.S. 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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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.
---------------------------------------------------------------------------

    \110\ See infra Chapter 1.
---------------------------------------------------------------------------

    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 
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.
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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-case, to transmit power for alternative 
sources of generation supply.
---------------------------------------------------------------------------

    \112\ H.R. No. 102-474(I) at 133.
---------------------------------------------------------------------------

    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.

---------------------------------------------------------------------------

[[Page 34108]]

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.

    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.
---------------------------------------------------------------------------

    \114\ APPA, TAPS. See also Midwest Stand Alone Transmission 
Companies.
---------------------------------------------------------------------------

    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 Mid-Atlantic, 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.

    \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.

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.

    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

[[Page 34109]]

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.
    Ancillary services include various categories of generation 
reserves such as spinning and non-spinning reserves in addition to 
Automatic Generation Control (AGC) for frequency control. 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
[GRAPHIC] [TIFF OMITTED] TN13JN06.012

    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.
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

[[Page 34110]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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) vertically-integrated utilities 
returning certain generation assets from unregulated wholesale 
affiliates to rate-base.
---------------------------------------------------------------------------

    \119\ FERC State of the Markets Report 2004 at 50.
    \120\ FERC State of the Markets Report 2005 at 77.
---------------------------------------------------------------------------

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-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.
---------------------------------------------------------------------------

    \121\ Southern Companies.
    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \123\ FERC State of the Markets Report 2005 at 69; FERC State of 
the Markets Report 2004 at 41-43.
    \124\ California ISO.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \125\ FERC State of the Markets Report 2004 at 109.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.iso-ne.com/nwsiss/pr/2006/march_6_settlement_filing.pdf.
---------------------------------------------------------------------------

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

[[Page 34111]]

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\
---------------------------------------------------------------------------

    \129\ FERC State of the Markets Report 2004 at 109.
    \130\ FERC State of the Markets Report 2005 at 97.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \131\ FERC State of the Markets Report 2004 at 39.
---------------------------------------------------------------------------

    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.
[GRAPHIC] [TIFF OMITTED] TN13JN06.013

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 
proposal to shift to locational prices in its capacity markets.\132\ 
The locational capacity market has not yet been implemented.
---------------------------------------------------------------------------

    \132\ Intial Order on Reliability Pricing Model, 115 FERC ] 
61,079, *3 (2006).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \133\ FERC State of the Markets Report 2004 at 109.
    \134\ FERC State of the Markets Report 2005 at 112.
---------------------------------------------------------------------------

    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 must-run 
(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\
---------------------------------------------------------------------------

    \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.

---------------------------------------------------------------------------

[[Page 34112]]

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 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\
---------------------------------------------------------------------------

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

    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 long-term 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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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., 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 high-prices 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.
---------------------------------------------------------------------------

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

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

[[Page 34113]]

markets, longer contract terms are associated with lower contract 
prices on a per MWh basis.
---------------------------------------------------------------------------

    \144\ ELCON.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 would be sufficient to 
reasonably assure that the benefits of eliminating traditional rate 
regulation exceed the costs.'' \149\
---------------------------------------------------------------------------

    \148\ Inquiry Concerning Alternative Power Pooling Institutions 
Under the Federal Power Act, Docket No. RM94-20-000.
    \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.
---------------------------------------------------------------------------

    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 market-clearing prices when 
there is high demand and high transmission congestion. There is a wide-
range 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 contracting.\153\ They report 
that this financial uncertainty has hurt their ability to obtain 
financing for new generation projects, especially new base-load 
generation.
---------------------------------------------------------------------------

    \153\ APPA, TAPS.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \154\ Pub. L. 109-58, Sec.  1233, 119 Stat. 594, 958 (2005) 
(emphasis added).

    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

[[Page 34114]]

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 
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\
---------------------------------------------------------------------------

    \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.
    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \161\ See infra Chapter 4 for a discussion of regulated service 
offerings in states with retail competition.
    \162\ Mirant, Constellation.
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \165\ Commodity Futures Trading Comm'n, The Economic Purpose of 
Futures Markets, available at http://www.cftc.gov/opa/brochures/opaeconpurp.htm.
    \166\ APPA.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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 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

[[Page 34115]]

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\ Base-load 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\
---------------------------------------------------------------------------

    \169\ Connecticut DPUC.
    \170\ U.S. Gen. Accounting Office, GAO-02-427, Restructurd 
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.

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.

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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, PJM and California 
would have allowed a new combined-cycle plant to recover no more than 
70% of its fixed costs.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    Regulation also may interfere with efficient exit of generation 
plants due to the use of reliability-must-run requirements. In some 
load pockets in organized markets, plant owners are paid above-market 
prices to run plants that are no longer economical at the market-
clearing price. 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.
---------------------------------------------------------------------------

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

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

[[Page 34116]]

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 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.
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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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

[[Page 34117]]

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 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\
---------------------------------------------------------------------------

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

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
    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 transmission-
constrained, 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\
---------------------------------------------------------------------------

    \181\ Siting in these areas can be difficult or impossible as a 
result of land prices, environmental restrictions, aesthetic 
considerations, and other factors.
---------------------------------------------------------------------------

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

[[Page 34118]]

these risks are higher for transmission builders than for generation 
builders.
d. Governmental Control of Generation Planning and Entry
    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\
---------------------------------------------------------------------------

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

    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.

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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    The chapter provides several observations based on the experiences 
of states that have implemented retail

[[Page 34119]]

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 non-
profit structure and rates typically include a margin adequate to cover 
unanticipated costs and support new investment.
    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
[GRAPHIC] [TIFF OMITTED] TN13JN06.014

    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 
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.
---------------------------------------------------------------------------

    \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.

---------------------------------------------------------------------------

[[Page 34120]]

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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

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; * * *
    (3) Ensure universal access to affordable and reliable electric 
power and natural gas service;
    (4) Maintain traditional regulatory authority over non-
competitive energy delivery or other energy services, subject to 
alternative forms of traditional regulation authorized by the 
Legislature;
    (5) Ensure that rates for non-competitive public utility 
services do not subsidize the provision of competitive services by 
public utilities; * * *

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.

---------------------------------------------------------------------------

[[Page 34121]]

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.

    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.
[GRAPHIC] [TIFF OMITTED] TN13JN06.015

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.

[[Page 34122]]

1. Status of Retail Competition
a. States Have Allowed Distant Suppliers to Access Local Customers and 
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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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
------------------------------------------------------------------------
                                                 Prior to
                    State                     restructuring      2002
                                                 (percent)    (percent)
------------------------------------------------------------------------
Illinois....................................         97.0%          9.1%
Maryland....................................          95.4           0.1
Massachusetts...............................          86.6           9.0
New Jersey..................................          81.2           6.8
New York....................................          84.3          32.4
Pennsylvania................................          92.3          12.3
Texas.......................................          88.3         41.2
------------------------------------------------------------------------
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\
---------------------------------------------------------------------------

    \192\ Texas profile, Appendix D.
    \193\ New York profile, Appendix D.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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%20Electricity%20Brokers Brokers.
    \196\ New Jersey Board of Public Utilities, List of Licensed 
Suppliers of Electric, available at http://www.bpu.state.nj.us/home/supplierlist.shtml 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 1 serving 
residential customers in the PSE&G service territory.
---------------------------------------------------------------------------

    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 
competition states. One notable exception has been the municipal 
aggregation program in Ohio described in Box 4-4.
---------------------------------------------------------------------------

    \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/.
---------------------------------------------------------------------------

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.

    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

[[Page 34123]]

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.
---------------------------------------------------------------------------

    \199\ Massachusetts profile, Appendix D.
    \200\ Texas profile, Appendix D.
---------------------------------------------------------------------------

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.
[GRAPHIC] [TIFF OMITTED] TN13JN06.016

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.
---------------------------------------------------------------------------

    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

[[Page 34124]]

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\
---------------------------------------------------------------------------

    \202\ Massachusetts profile, Appendix D.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \204\ See, e.g., ELCON; Portland Cement; Alliance of State 
Leaders; Alcoa.
    \205\ Portland Cement; Lehigh Cement.
---------------------------------------------------------------------------

    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 cross-
subsidies 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 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\
---------------------------------------------------------------------------

    \206\ Constellation, PEPCO, Southern and EEI, ICC, IURC, and 
NYPSC, ISO-NE.
    \207\ National Grid.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \208\ For example, when PEPCO divested its generation assets it 
stopped actively supporting its air-conditioner DLC program.
---------------------------------------------------------------------------

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 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

[[Page 34125]]

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 is the price 
that new suppliers, including unregulated affiliates of the 
distribution utility, must compete against if they are to attract 
customers.\210\
---------------------------------------------------------------------------

    \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. 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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \211\ See, e.g., ICC, PPL, and PA OCA.
    \212\ See, e.g., PA OCA; NASUCA.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \216\ New Jersey profile, Appendix D.
---------------------------------------------------------------------------

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

[[Page 34126]]

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\
---------------------------------------------------------------------------

    \217\ Illinois profile, Appendix D.
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 of switching to alternative suppliers in Pennsylvania 
to the additional avoidable costs that were included in the 
Pennsylvania shopping credit calculations.\224\
---------------------------------------------------------------------------

    \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://mainegov-images.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.ohio-state.edu/dspace/bitstream/2068/610/1/00-10.pdf, for a discussion of adders and their relationship to 
wholesale prices and headroom for entrants in Pennsylvania and other 
states.
    \223\ Id.
    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \225\ FTC Retail Competition Report, State Profiles, Appendix A.
---------------------------------------------------------------------------

    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 market-based 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\
---------------------------------------------------------------------------

    \226\ New York profile, Appendix D; FTC Retail Competition 
Report, New York State Profile, Appendix A.
    \227\ Illinois profile, Appendix D.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \228\ New Jersey profile, Appendix D.
    \229\ See, e.g., ME OPA.
    \230\ New York profile, Appendix D.
---------------------------------------------------------------------------

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

[[Page 34127]]

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 ago. 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 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\
---------------------------------------------------------------------------

    \231\ See, e.g., Wal-Mart; WPS Resources; ICC; PPL; RESA.
    \232\ See, e.g., Wal-Mart; RESA.
    \233\ See, e.g., EEI.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \234\ See, e.g., RESA.
---------------------------------------------------------------------------

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 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 price increases 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\
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

    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

[[Page 34128]]

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.
---------------------------------------------------------------------------

    \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.

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 that. 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.

    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.
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    \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.
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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 could be slow to develop is that the expected gains from 
learning more about market choices are too small to make it worthwhile 
to learn.\241\ Residential customers with small loads might be in this 
position in states with retail customer choice.\242\
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    \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 24, 2003) available at 
http://mainegov-images.informe.org/mpuc/staying_informed/about_mpuc/commissioners/ph-welch.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.
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    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 retail 
competition states have had substantial consumer education programs, 
including Web sites 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.
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    \243\ See, e.g., ELCON; Progress Energy; Constellation; PEPCO; 
PA OCA.
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    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\

    \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.
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[FR Doc. 06-5247 Filed 6-9-06; 8:45 am]
BILLING CODE 6717-01-C