[Federal Register Volume 71, Number 113 (Tuesday, June 13, 2006)]
[Notices]
[Pages 34083-34128]
From the Federal Register Online via the Government Printing 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 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\
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\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.
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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\
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\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\
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\97\ U.S. Dept. of Energy, The Future of Electric Power in
America: Economic Supply for Economic Growth, June, 1983 (DOE/PE-
0045).
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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.
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\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.
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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\
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\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.
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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\
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\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\
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\109\ See EPACT 92 House Report. H.R. No. 102-474(I) at 138.
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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.
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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.
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[[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_Interstate ProjectSummary.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.
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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.
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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\
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\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\
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\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.
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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.
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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.
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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.
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\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).
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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\
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\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.
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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%20 Suppliers%20and%20Electricity%20
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. 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\
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\206\ Constellation, PEPCO, Southern and EEI, ICC, IURC, and
NYPSC, ISO-NE.
\207\ National Grid.
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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.
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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\
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\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.
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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\
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\211\ See, e.g., ICC, PPL, and PA OCA.
\212\ See, e.g., PA OCA; NASUCA.
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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.
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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\
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\217\ Illinois profile, Appendix D.
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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\
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\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\
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\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.
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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\
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\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\
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\226\ New York profile, Appendix D; FTC Retail Competition
Report, New York State Profile, Appendix A.
\227\ Illinois profile, Appendix D.
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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\
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\228\ New Jersey profile, Appendix D.
\229\ See, e.g., ME OPA.
\230\ New York profile, Appendix D.
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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\
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\231\ See, e.g., Wal-Mart; WPS Resources; ICC; PPL; RESA.
\232\ See, e.g., Wal-Mart; RESA.
\233\ See, e.g., EEI.
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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.
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\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\
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\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.''
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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.
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\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