[Federal Register: June 13, 2006 (Volume 71, Number 113)]
[Notices]
[Page 34083-34128]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr13jn06-50]
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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/atrFederal Energy Regulatory Commission: http://www.ferc.gov/legal/staff-
reports/epact-competition.pdf
Federal Trade Commission: http://www.ftc.govDepartment 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).
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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.
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\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.
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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.
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\98\ Under price cap regulation, a firm can theoretically
``produce with the cost-minimizing input mix [and] invest in cost-