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

Federal RegisterJun 13, 2006

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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.

SUMMARY:

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

to conduct a study and analysis of competition within the wholesale and retail market for electric energy in the United States and to submit a report to Congress within one year. Section 1815 further requires that the Task Force publish its draft report in the

Federal Register

for public comment 60 days prior to submitting its final report to the Congress. The Federal Energy Regulatory Commission, as an agency with a representative on the Task Force, is publishing this notice providing the draft report and seeking public comment on behalf of the Task Force.

DATES:

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

ADDRESSES:

Comments may be electronically filed by any interested person via the e-Filing link on the Federal Energy Regulatory Commission's Web site at

http://www.ferc.gov

for Docket No. AD05-17-000. Persons filing electronically do not need to make a paper filing. Persons that are not able to file electronically must send an original of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:

Moon Paul, Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. 202-502-6136.

SUPPLEMENTARY INFORMATION:

Section 1815 of the Energy Policy Act of 2005 established an interagency task force to conduct a study and analysis of competition within the wholesale markets and retail markets for electric energy in the United States. The task force has 5 members: (1) An employee of the Department of Justice, appointed by the Attorney General of the United States; (2) an employee of the Federal Energy Regulatory Commission, appointed by the Chairperson of that Commission; (3) an employee of the Federal Trade Commission, appointed by the Chairperson of that Commission; (4) an employee of the Department of Energy, appointed by the Secretary of Energy; and (5) an employee of the Rural Utilities Service, appointed by the Secretary of Agriculture.

The Electric Energy Market Competition Task Force consulted with and solicited comments from the States, representatives of the electric power industry and the public, in accordance with a notice requesting public comment published in the

Federal Register

on October 19, 2005 at 70 FR 60819. A full listing of the persons or entities that have met with the task force or submitted comments in response to the notice will be listed as an attachment to the final report.

The draft report of the Electric Energy Market Competition Task Force is attached to this notice as Appendix A. The appendices to the draft report will not be published in the

Federal Register

, but will be available online, as follows. The draft report is also available at each of the following Web sites of the Task Force members' agencies:

Department of Justice:

http://www.usdoj.gov/atr

Federal Energy Regulatory Commission:

http://www.ferc.gov/legal/staff-reports/epact-competition.pdf

Federal Trade Commission:

http://www.ftc.gov

Department of Energy:

http://www.oe.energy.gov

Department of Agriculture:

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

Members of the public are invited to comment on the draft report and encouraged to file comments as soon as is practicable in order to maximize the time available to the task force to consider these comments. Comments will be received by the Federal Energy Regulatory Commission and available for public review. A final report will be delivered to Congress on or before August 8, 2006 in accordance with the statutory deadline.

How To File Comments

Any interested person may submit a written comment and it will be made part of the public record of the Task Force maintained with the Federal Energy Regulatory Commission. Comments may be filed electronically via the e-Filing link on the Federal Energy Regulatory Commission's Web site at

http://www.ferc.gov

for Docket No. AD05-17-000.

Most standard word processing formats are accepted, and the e-Filing link provides instructions for how to Login and complete an electronic filing. First-time users will have to establish a user name and password. User assistance for electronic filing is available at 202-208-0258 or by e-mail to efiling at ferc.gov. Comments should not be submitted to the e-mail address. Persons filing comments electronically do not need to make a paper filing. Persons that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street NE., Washington, DC 20426.

This filing is accessible on-line at

http://www.ferc.gov

, using the “eLibrary” link and is available for review in the Commission's Public Reference Room in Washington, DC. For assistance with any FERC Online service, please e-mail

FERCOnlineSupport@ferc.gov

, or call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.

Dated: June 5, 2006.

Magalie R. Salas,

Secretary, Federal Energy Regulatory Commission.

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

Report to Congress on Competition in the Wholesale and Retail Markets for ELectric Energy

Draft

June 5, 2006.

By The Electric Energy Market Competition Task Force.

Table of Contents

Executive Summary

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

Chapter 2. Context For The Task Force's Study of Competition in Wholesale and Retail Electric Power Markets

Chapter 3. Competition in Wholesale Electric Power Markets

Chapter 4. Competition in Retail Electric Power Markets

Appendix A: Index of Comments Received

Appendix B: Task Force Meetings With Outside Parties

Appendix C: Annotated Bibliography of Cost Benefit Studies

Appendix D: State Retail Competition Profiles

Appendix E: Analysis of Contract Length and Price Terms

Appendix F: Bibliography of Primary Information on Electric Competition

Appendix G: Credit Ratings of Major American Electric Generation Companies

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

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

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

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

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

Table 1-6. Power Generation Asset Divestitures by Investor-Owned Electric Util. as of April 2000

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

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

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

Figure 1-3. RTO Configurations in 2004

Figure 1-4. Transmission Expenditures of EEI Members

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

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.

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.

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.

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

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

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.

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.

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

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.

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.

American Public Power Association.

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.

National Rural Electric Cooperative Association.

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).

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.

Nonutilities accounted for about 33 percent of generation in 2004. Tables 1-1 through 1-5 summarize this information.

Edison Electic Institute.

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

Ownership

Number of electricity providers

Percent of total

Number of customers

Full service

Delivery only

Total

Percent of total

Publicly-owned utilities

2,011

61.4

19,628,710

6,125

19,634,835

14.4

Investor-owned utilities

220

6.7

90,970,557

2,879,114

93,849,671

68.9

Cooperatives

884

16,564,780

12,170

16,576,950

12.2

Federal Power Agencies

0.3

39,843

39,845

0.03

Power Marketers

152

4.6

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

Full service

Energy only

Delivery

Total

Publicly-owned utilities

$37,734

$5,787

$27

$43,548

Investor-owned utilities

162,691

128

8,746

171,565

Cooperatives

25,448

25,492

Federal Power Agencies

1,211

1,224

Power Marketers

17,163

11,000

28,162

Total

244,247

16,965

8,761

269,992

Source: American Public Power Association, 2006-07 Annual Directory & Statistical Report, from Energy Information Administration Form EIA-861, 2004 data.

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

Electricity Generation 2004

Generation

(thousands of MWhs)

% of Total

Publicly-owned utilities

397,110

10.3

Investor-owned utilities

1,734,733

44.8

Cooperatives

181,899

4.7

Federal Power Agencies

278,130

7.2

Power Marketers

42,599

1.1

Non-utilities

1,235,298

31.9

Total

3,869,769

100.0

Source: American Public Power Association, 2006-07 Annual Directory & Statistical Report, from Energy Information Administration Form EIA-861 and EIA-906/920 for generation. Data are for 2004, adjusted for joint ownership.

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

Ownership

Nameplate capacity

(in MWs)

% of Total

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.

This idea was, in part engendered by the work of Thomas Edison's prote

, 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.

Vernon Smith,

Regulatory Reform in the Electric Power Industry

(1995) (working paper, on file with the Department of Economics, University of Arizona).

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.

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.

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

FERC

, 225 F..3d 667 (D.C. Cir. 2000),

aff'd sub nom. New York

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.

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

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.

Periods of rapid inflation and higher interest rates increased the costs of operating large, baseload generation plants,

and a more elastic-than-expected demand or load led to decreasing profits for large utilities.

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

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

In addition, these technological advances made it more feasible for generation plants hundreds of miles apart to compete with each other

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.

See

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

Id.

at 31,639.

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].

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

Severin Borenstein & James Bushnell,

Electricity Restructuring: Deregulation or Reregulation?

, 23 REGULATION 46, 47 (2000).

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.

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.

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].

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

Congress enacted the Public Utility Regulatory Policy Act of 1978 (PURPA)

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.

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.

Box 1-1 discusses how the implementation of PURPA encouraged nonutilities generation suppliers by guaranteeing a market for the electricity they produced.

PURPA changed prevailing views that vertically integrated public utilities were the only sources of reliable power

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

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

See

EIA 1979-1991 at 22.

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.

. at 24.

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

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.

The response to PURPA was dramatic.

. 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.

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.

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.

These entities were known as merchant generators or

Independent Power Producers (IPPs).

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,

and nonutility generating facilities accounted for one-fifth of all additions to generating capacity in the 1980s.

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

Joskow, Deregulation at 19.

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

EIA 1970-1991 at vii.

. at 27.

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

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.

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.

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.

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.”

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).

. 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.

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.”

. 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.

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.

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.

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

Joskow, Deregulation at 21.

See

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

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)

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).

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.

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.

EPACT 92 also expanded

FERC's authority to order transmitting utilities to provide transmission service for wholesale power transmission to any electric utility, Federal power marketing agency, or any person generating electric energy in wholesale electricity markets.

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.

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.

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

Joskow, Deregulation at 24.

See EIA 1970-1991

at 30; Joskow, Deregulation at 23.

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.

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.

. at ¶ 31,654.

. 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

FERC

, 535 U.S. 1 (2002).

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

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.

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).

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.

The ISO also could achieve coordination, reliability, and efficiency benefits by having regional control of the grid.

Participation in an ISO remained voluntary, however, and it only occurred in some areas of the country. It was not implemented in other areas.

Together, Order Nos. 888 and 889 serve as the primary federal foundation for providing transmission service and information about the availability of transmission service.

EIA 2000 Update at 66.

. at 66, 68, 80.

. at 67.

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.

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.

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.

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.

EIA 2000 Update at ix.

See

discussion

infra

, Box 1-1.

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.

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.

As of 2004 the disparity in retail prices among the states persisted, as illustrated in Figure 1-1, below.

EIA 2000 Update

at 43.

EN13JN06.003

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.

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).

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.

. at 81-82.

Paul L. Joskow,

Markets for Power in the United States: An Interim Assessment

, ENERGY J. 2 (2006) [hereinafter Joskow, Interim Assessment].

EN13JN06.004

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.

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.

Thus, FERC concluded that regional transmission organizations (RTOs) could eliminate transmission rate pancaking,

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.

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

FERC

, 272 F.3d 607 (DC Cir. 2001) [hereinafter Order No. 2000].

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.

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

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.

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.

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.

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.

Id.

at 52.

EN13JN06.005

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.

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.

The 2003 blackout was the eighth major blackout experienced in North America since the 1965 Northeast Blackout.

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.

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.

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),

which amended the core statutes (FPA, PURPA, PUHCA) governing the electric

power industry. Several key provisions of EPACT 2005 are:

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.

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.

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

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.

EN13JN06.006

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.

Until the early 1980s, the electric utilities' share of electric power production increased steadily, reaching 97 percent in 1979.

By 1991, however, the trend had reversed itself, and the electric utilities' share declined to 91 percent.

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).

Id.

at 23.

EIA 1970-1991 at vii.

Id.

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.

EN13JN06.007

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.

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.

Real retail prices have since stayed flat through 2004.

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

Joskow, Difficult Transition at 7.

EN13JN06.008

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.

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.

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.

EIA Electric Power Annual 2004 at 2.

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.

EN13JN06.009

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.

EN13JN06.010

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

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.

The Department of Energy predicts a resurgence of coal-fired generation will continue as far into the future as 2025.

See

EIA Electric Power Annual 2004 at 17, table 2.4,

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

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.

EN13JN06.011

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.

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.

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.

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.

EIA 2000 Update at 91.

Id.

at 105-06.

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

and these power plant divestitures have also reduced the total number of IOUs that own generation capacity.

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.

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.

Id.

at 105.

Id.

at 91.

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

analysts to herald 2004 as the inauguration of a new round of consolidation in the power sector.

One utility-to-utility acquisition was closed

and three were announced.

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.

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

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

Id.

at 31.

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.

Id.

at 30.

Table 1-6.—Power Generation Asset Divestitures by Investor-Owned Electric Utilities, as of April 2000

Status category

Capacity (GW)

Percent of total

Percent of total U.S.

Generation

Capacity

Sold

58.0

Pending Sale (Buyer Announced)

28.2

For Sale (No Buyer Announced)

31.9

Transferred to Unregulated Subsidiary

4.1

Pending Transfer to Unregulated Subsidiary

34.2

Total

156.5

100

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

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.

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

2. Effect on Investment Decisions

The usual market-based signal for efficient investment into a market—prices that align consumer demand with generators' supply under given market conditions—is unavailable under cost-based rate regulation of retail electric power prices. Under cost-based rate regulation, utilities could decide when to add generation, but their recovery of their costs for these investments was dependent on state regulators agreeing that the generation was necessary and prudent. (Most state also imposed siting regulation on construction of major electric power facilities). Thus, it was long term planners and regulators that determined when generation would be built, and it was consumers who bore the cost of investment risks once they had been approved by the state regulators. Utilities were reluctant to take investment risks that might end up being unrecoverable if the regulators deemed their cost unreasonable. By far, the most important of these decisions was for generation investment which constitutes the substantial majority of the capital investment in the electric power industry. While the intent of cost-based rate regulation, was not simply to keep price down, the effect was sometimes to dampen investment in new capacity and innovation.

In making decisions, regulators struggled to strike the balance between reasonable rates and providing utilities with incentives to make necessary and sufficient investments.

See e.g. The Economics and Regulation of Antitrust,

at 6-7.

Regulatory mistakes in setting rates too high or too low may lead to excessive or inadequate additions of new electric power generation and other forms of investment. If rates are set too high, utilities could earn a higher return on new generation investments than would be warranted by the cost of capital. The result could be overinvestment and overbuilding. Utilities also had little incentive to design new generation plants in a cost-effective manner, to the extent regulators were unlikely to identify and disallow excessive costs to be included in customer rates. At the same time, regulatory disallowances of some costs imposed risk on utility decisions to elicit capital and build new generation, and investors sought compensation for this risk when they supplied capital to utilities.

In the academic literature, the risk of utility overinvestment has been explained by the Averch-Johnson Effect. The Averch-Johnson Effect reflects that “a firm that is attempting to maximize profits is give, by the form of regulation itself, incentives to be inefficient. Furthermore, the aspects of monopoly control that regulation is intended to address, such as high prices, are not necessarily mitigated, and could be made worse, by the regulation.” KENNETH E. TRAIN, OPTIMAL REGULATION 19 (1991). The Averch-Johnson Effect also predicts that if a regulator attempts to reduce a firm's profits by reducing its rate of return, the firm will have an incentive to further increase its relative use of capital.

Id.

at 56. Thus, the most obvious regulatory control within cost-base rate regulation creates further distortions. The Averch-Johnson Effect is sometimes thought to explain why a regulated firm is led to “gold plate” its facilities,

i.e.

incur excessive costs so long as those expenses can be capitalized.

Indeed, a 1983 Department of Energy analysis of electric power generation plant construction showed that electric utilities (which were regulated under a cost-based regulatory regime) had little ability to control the construction costs of coal and nuclear generation plants. During the 1970s and early 1980s, the cost range per megawatt to build a nuclear plant varied by nearly 400 percent and by 300 percent for coal plants. The DOE study showed that some companies were not competent to manage such large-scale, capital-intensive projects. In addition, there was a tendency to custom design these plants, as opposed to use of a basic design and then refining it.

U.S. Dept. of Energy,

The Future of Electric Power in America: Economic Supply for Economic Growth,

June, 1983 (DOE/PE-0045).

Box 2-2: Market Prices

Market prices reflect myriad individual decisions about prices at which to sell or buy. Market prices are a mechanism that equalizes the quantity demanded and the quantity supplied. Rising prices signal consumers to purchase less and producers to supply more. Falling prices signal consumers to purchase more and producers to supply less. Prices will stop rising or falling when they reach the new equilibrium price: the price at which the quantity that consumers demand matches the quantity that producers supply.

One alternative to traditional rate-of-return regulation is price cap regulation. Under this approach, the regulator caps the price a firm is allowed to charge.

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.

Under price cap regulation, a firm can theoretically “produce with the cost-minimizing input mix [and] invest in cost-effective innovation.” Train at 318. However, this dynamic only occurs where the price cap is fixed over time and the utility receives the benefit of cost reductions and cost-effective innovations. Further, the benefit of this increased efficiency “accrues entirely to the firm: consumers do not benefit from the production efficiency.”

Id.

Where the price cap is adjusted over time, firms are induced to engage in strategic behavior. Additionally, “if, as * * * expected, the review of price caps is conducted like the price

reviews under cost-base rate regulation, then the distinction blurs between price-cap regulation and cost-base rate regulation.”

at 319.

In part, the struggles of regulators to ensure adequate supplies of power at reasonable rates led policy makers to examine whether competition could provide more timely and efficient incentives for what to consume and build. Advances in technology negated the assumption that generation is a natural monopoly, and thus set the stage for price and competition to provide a market entry signal, although transmission and distribution would continue to be regulated.

B. Competition in Wholesale and Retail Electric Power Markets—The Role of Price

With competition, the price of a commodity such as electric power generally reflects suppliers' costs and consumers' willingness to pay. The price signals the relative value of that commodity compared to other goods and services. How much a supplier will produce at a given price is determined by many things, including (in the long run) how much it must pay for the labor it hires, the land and resources it uses, the capital it employs, the fuel inputs it must purchase to generate the electric power, the transmission it must use to deliver the electric power to end users, and the risks associated with its investment. Consumers' overall willingness to pay for a product also is determined by a large variety of factors, such as the existence and prices of substitutes, income, and individual preferences.

1. Price Affects Customer Consumption

Price changes signal to customers in wholesale and retail markets that they should change their decisions about how much and when to consume electric power. Price increases generally provide a signal to customers to reduce the amount they consume. The dampening effect on price of a reduction in consumption helps consumers safeguard themselves against a supplier that may seek to exercise market power by increasing prices. By contrast, lower prices may encourage some customers to consume more than they would have at higher prices. Price changes thus play an important economic function by encouraging customers and suppliers to respond to changing market conditions. In the electric power industry, consumer's price responsiveness is often referred to as “demand response.”

U.S. Department of Energy,

Benefits of Demand Response in Electricity Markets and Recommendations for Achieving Them: A Report to the United States Congress Pursuant to Section 1252 of the Energy Policy Act of 2005,

February 2006 (DOE EPAct Report). The DOE EPAct Report discusses the benefits of demand response in electric power markets and makes recommendations to achieve these benefits.

The primary objective to incorporate price-based signals into wholesale and retail electric power markets is to provide consumers with price signals that accurately reflect the underlying costs of production. These signals will improve resource efficiency of electric power production due to a closer alignment between the price that customers pay for and the value they place

electricity. In particular, by exposing customers (some or all) to prices based on marginal production costs, resources can be allocated more efficiently.

100

Flat electricity prices based on average costs can lead customers to “over-consume—relative to an optimally efficient system in hours when electricity prices are higher than the average rates, and under-consume in hours when the cost of producing electricity is lower than average rates.”

101

Exposure of customers to efficient price signals also has the benefit of increasing price response during periods of scarcity and high prices, which can help moderate generator market power and improve reliability.

100

There is a substantial literature on setting rates based on marginal costs in the electric sector. See for example, M. Crew and P. Kleindorfer,

Public Utility Economics.

St. Martin's Press: New York, 1979 and B. Mitchell, W. Manning, and J. Paul Acton,

Peak-Load Pricing.

Ballinger: Cambridge, 1978. Other papers suggest that setting rates based on marginal costs will result in a misallocation of resources (

see

Borenstein, S.,

The Long-Run Efficiency of Real-Time Pricing,

ENERGY JOURNAL, Vol. 26, No. 3, 2005). Nevertheless, the literature also indicates that marginal cost pricing may result in a revenue shortfall or excess, and standard rate-making practice is to require an adjustment (presumably to an inelastic component) to reconcile with embedded cost-of-service. Various rate structures to accomplish marginal-cost pricing include two-part tariffs (

see

Viscusi, Vernon, and Harrington,

Economics of Regulation and Antitrust,

MIT Press, 2000) and allocation of shortfalls to rate classes.

101

DOE EPAct Report, p. 7.

When customers have many close substitutes for a particular good, a relatively small price increase will result in a relatively large reduction in how much they consume. For example, if natural gas were a very good substitute for electric power at comparable prices, then even a relatively small increase in the price of electric power could persuade many consumers to switch in part or entirely to natural gas, rather than electricity. To induce those consumers to return to using electricity, electricity prices would not need to fall by very much. However, when there are no close substitutes for electric power, prices may have to rise substantially to reduce consumption in order to restore the balance between the quantity supplied and the quantity demanded.

A substantial body of empirical literature has shown that, even if the retail price of electricity increases relatively quickly and sharply, the short-run consumption of electricity does not decline much. In other words, short-run demand for electricity is very inelastic.

See

Box 2-3. This inability to substitute other products for electricity in the short run means that changes in supply conditions (price of input fuels, etc.) are likely to cause wider price fluctuations than would be the case if customers could easily reduce their demand when prices rise. Furthermore, electric power has few viable and economic substitutes for key end-uses such as refrigeration and lighting and thus the consequences for supply shortfalls can be significant.

102

In the long run, this effect may be somewhat muted as, with time, electricity customers may have more ability to adjust their consumption in response to price changes.

102

Estimates of the total costs in the United States due to August 14, 2003 blackout range between $4 billion and $10 billion. ELCON,

The Economic Impacts of the August 2003 Blackout,

February 2, 2004.

Box 2-3: Demand Elasticity

The desire and ability of consumers to change the amount of a product they will purchase when its price increases is known as the price elasticity of that product. The price elasticity of demand is the ratio of the percent change in the quantity demanded to the percent change in price. That is, if a 10 percent price increase results in a 5 percent decrease in the quantity demanded, the price elasticity of demand equals −0.5 (−5%/10%). If the ratio is close to zero demand is considered “inelastic”, and demand is more “elastic” as the ratio increases, especially if the ratio is greater than −1. Short-run elasticities are typically lower than long-run elasticities.

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

short-run price changes (

i.e.

, have a non-zero short-run price elasticity of demand). Georgia Power's Real Time Pricing (RTP) tariff option has found that industrial customers who receive RTP based on an hour-ahead market are somewhat price-responsive (short-run price elasticities ranging from approximately −0.2 at moderate prices, to −0.28 at prices of $1/kWh or more). Among day-ahead RTP customers, short-run price elasticities range from approximately −0.04 at moderate prices to −0.13 at high prices. Similar elasticities were found in the National Grid RTP pricing program. A critical peak pricing experiment in California in 2004 determined that small residential and commercial customers are price responsive and will make significant reductions in consumption (13 percent on average, and as much as 27 percent when automated controls such as controllable thermostats were installed) during critical peak periods. In addition, the California pilot found that most customers who were placed on the CPP tariffs had a favorable opinion of the rates and would be interested in continuing in the program.

103

Charles River Associates,

Impact Evaluation of the California Statewide Pricing Pilot,

Final Report, March 16, 2005,

available at http://www.energy.ca.gov/demandresponse/documents/group3_final_reports/2005-03-24_SPP_FINAL_REP.PDF.

Customers on a similar CPP program at Gulf Power also have high satisfaction with the program, which incorporates automated response to CPP events.

The ability of a customer to respond to prices requires the following conditions: (1) That time-differentiated price signals are communicated to customers, (2) that customers have the ability to respond to price signals (

e.g.

, by reducing consumption and/or turning on an on-site generator), and (3) that customers have interval meters (

i.e.

, so the utility can determine how much power was used at what time and bill accordingly).

104

Most conventional metering and billing systems are not adequate for charging time-varying rates and most customers are not used to considering price changes in making electricity consumption decisions on a daily or hourly basis.

104

EEI; PEPCO cautions that many customers, particularly residential and commercial customers, are relatively inflexible in responding to price changes due to constraints imposed by their operations and equipment.

2. Supplier Responses Interact With Customer Demand Responses to Drive Production

Generation supply responses are equally important in determining an appropriate equilibrium market price. The extent of supply responses will depend on the cost of increasing or decreasing output. Generally, the longer industry has to adjust to a change in demand, the lower will be the cost of expanding that output. With more time, firms have more opportunity to change their operations or invest in new capacity.

If the cost of increasing production is small, then a relatively small price increase may be enough to encourage existing producers to increase their production levels to provide additional supply in response to increased demand. If the cost of increasing electricity capacity is high, however, existing suppliers will not increase their production without a very strong price signal. In that case, customers would have to pay significantly higher prices to obtain additional supply. Additionally, if suppliers are already producing as much electric power as they can, increased demand can be met only from new capacity, and suppliers must be confident that prices will remain high enough for long enough to justify building a new generating plant.

These supply decisions are complicated because electric power cannot be stored economically, thus there are generally no inventories in electricity markets. Therefore, electricity generation must always exactly match electricity consumption.

105

The lack of inventories means that wholesale demand is completely determined by retail demand. Moreover, any distant generation must “travel” over a transmission system with its own limiting physical characteristics.

106

Transmission capability is required to allow customers access to distant generation sources. The transmission system is complicated by the fact that the dynamics of the AC transmission grid create network effects and can produce positive externalities (depending on the method used in accounting for transmission costs).

107

That is to say, where transmission users are not charged for the congestion impacts of their use patterns, that user's actions can cause costs to other users—costs which the causal party is not obligated to pay. This dynamic can distort the effect of price signals on dispatch efficiencies.

105

APPA.

106

Alcoa.

107

TAPS.

Moreover, aggregate retail demand fluctuates throughout the day, with higher demand during the day than at night. Fluctuating demand means that the transmission operator must have sufficient capacity to equal or exceed customer demand in real-time. Load serving entities (those entities that deliver power to meet demand or “load”) must supply or procure sufficient capacity and energy (either in long-term contracts or short-term “spot” market purchases) to meet these varying loads. The costs of generating electricity are also highly variable, leading to wide disparity between the costs of generating electricity from generation plants that operate around-the-clock versus the cost of those that generate only during peak periods.

In any case, a higher price signals a profit opportunity, attracting resources where they are needed. If customer demand decreases in response to rising prices, prices are likely to fall, all else equal. In that circumstance, falling demand signals suppliers to reduce the amount of electric power that they supply. Suppliers will reduce their generation to meet the new, lower level of consumer demand, and will not be inclined to consider any new capacity increases.

3. Customer and Supplier Behavior Responding to Price Changes in Markets

In sum, the combined impact of consumers' and suppliers' responses to changed market conditions will produce a new market equilibrium price. Current prices must change when they create an imbalance between the quantity demanded and the quantity supplied. For example, when demand spikes, short-run prices might have to swing sharply higher to provide incentives for short-run supply increases. However, consumers do not have very many good substitutes for electric power, and suppliers usually cannot increase output instantly or transport distant available generation to increase the quantity supplied to a market. Even if higher prices give consumers and producers incentives to change their behavior, they may have little ability to do so in the short term. Over much longer time frames, however, both consumers and producers have more options to react to higher prices. The result is that long-run price increases usually will be much smaller than the short-run price increases needed to induce additional generation.

Chapter 3—Competition in Wholesale Electric Power Markets

A. Introduction and Overview

Congress required the Task Force to conduct a study of competition in wholesale electric power markets. Wholesale markets involve sales of electric power among generators, marketers, and load serving entities (e.g., distribution utilities) that

ultimately resell the electric power to end-use customers (e.g., residential, commercial, and industrial customers). Prior to the introduction of competition, vertically integrated utilities with excess electric power sold it to other utilities and to wholesale customers such as municipalities and cooperatives that had little or no generating capacity of their own. The Federal Energy Regulatory Commission (FERC) and its predecessor agency (the Federal Power Commission) regulated the prices, terms and conditions of interstate wholesale sales by investor-owned utilities. The desire of wholesale purchasers for access to competitive sources of electric power was a fundamental impetus to the opening of the generation sector to competition.

108

U.S.

Otter Tail Power Company,

410 U.S. 366 (1973) (the United States sued a vertically integrated utility for refusal to deal with the Town of Elbow Lake, MI, a town that was seeking alternative sources of wholesale power for a planned municipal distribution system).

Effective competition ensures an economically efficient allocation of resources. Congress in the Energy Policy Act of 1992 (EPACT 92) determined that competition in wholesale electric power markets would benefit from two changes to the traditional regulatory landscape: (1) Expansion of FERC's authority to order utilities to transmit, or “wheel,” electric power on behalf of others over their owned transmission lines; and (2) elimination of entry barriers so non-utility entry could occur. The former change permitted wholesale customers to purchase supply from distant generators and the latter change provided customers with competitive alternatives from independent entrants.

109

See

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

As described in Chapter 2, an important component of effective market operation is customer response to prices. The demand for wholesale power, however, is derived entirely from consumption choices at the retail level. The lack of electric power inventories only intensifies the direct link between wholesale and retail electric power markets. Yet state regulators set the prices for retail customers. State regulators generally have treated wholesale rates as an input into retail prices. But states often set retail rates that dilute the direct impact of the price of wholesale power on retail prices.

110

Thus, retail consumption decisions have been guided by prices, terms, and conditions that often do not directly reflect the wholesale price to purchase the electric power or the cost generators incurred to produce it.

110

See infra

Chapter 1.

This price disconnect is heightened by the fact that, if competition is to allocate resources in an economically efficient manner, customers must have access to a sufficient number of competing suppliers either via transmission or from new local generation.

111

But one of the shortcomings of cost-based rate regulation was its inability to provide incentives for investors to make economically efficient decisions concerning when, where, and how to build new generation.

111

See, e.g.

, U.S. Gen. Accounting Office, GAO-03-271, LESSONS LEARNED FROM ELECTRIC INDUSTRY RESTRUCTURING 21 (2002) (“Increasing the amount of competition requires structural changes within the electric industry, such as allowing a greater number of sellers and buyers of electricity to enter the market”).

Thus, the question is whether competition in wholesale markets has resulted in sufficient generation supply and transmission to provide wholesale customers with the kind of choice that is generally associated with competitive markets. In other words, has competition in wholesale electric power markets resulted in an economically efficient allocation of resources? The answer to this question is difficult to derive because each region was at a different regulatory and structural starting point upon Congress' enactment of the Energy Policy Act of 1992. These differences make it difficult to single out the determinants of consumption and investment decisions and thus make it difficult to evaluate the degree to which more competitive markets have influenced such decisions. Even the organized exchange markets have different features and characteristics. For example, some regions already had tight power pools, others were more disparate in their operation of generation and transmission. Some regions had higher population densities and thus more tightly configured transmission networks than did others. Some regions had access to fuel sources that were unavailable or less available in other regions (e.g., natural gas supply in the Southeast, hydro-power in the Northwest). Some regions operate under a transmission open-access regime that has not changed since the early days of open access in 1996, while other regions have independent provision of transmission services and organized day-ahead exchange markets for electric power and ancillary services.

This chapter discusses the impact of competition for generation supply on the ability of wholesale customers to make economic choices among suppliers and for suppliers to make economic investment decisions. The chapter addresses how entry has occurred in several regions with different forms of competition (e.g., the Midwest, Southeast, California, the Northwest, Texas, and the Northeast). This chapter also discusses how long-term purchase and supply contracts, capital requirements, regulatory intervention, and transmission investment affect supplier and customer decisions. The chapter concludes with observations on various regional experiences with wholesale competition. These observations highlight the trade-offs involved with various policy choices used to introduce competition.

B. Background

Congress enacted the EPACT 92 to jump start competition in the electric power industry. One of the stated purposes of the EPACT 92 was “to use the market rather than government regulation wherever possible both to advance energy security goals and to protect consumers.”

112

Policy makers recognized that vertically integrated utilities had market power in both transmission and generation—that is they owned all transmission and nearly all generation plants within certain geographic areas. Congress, therefore, enhanced FERC's authority to order utilities, case-by-case, to transmit power for alternative sources of generation supply.

112

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

Today, vertically integrated utilities that operate their transmission systems generally offer transmission service under the terms of the standard Open Access Transmission Tariff (OATT) adopted by FERC in Order No. 888. The OATT requires a utility to offer the same level of transmission service, under the same terms and conditions and at the same rates that it provides to itself. Vertically integrated utilities (also referred to here as the transmission provider) offer two types of long-term transmission service under the OATT: network integration transmission service (network service) and point-to-point transmission service.

See

Box 3-1 for a description of both types of transmission service. For both services, the price has been predictable and stable over the long term.

113

The demand charge for long-term point-to-point transmission service is known in advance. For network service, the transmission customer pays a load ratio share of the transmission provider's FERC-approved transmission revenue requirement. Thus, even if redispatch to relieve transmission congestion occurs and the costs are charged to

customers, or expansion is necessary and the costs of the expansion are added to the revenue requirement, the distribution of the costs over the whole system has allowed the charges to individual customers to remain relatively stable. Customers who take either kind of service have a right to continue taking service when their contract expires, although point-to-point customers may have to pay a different rate (up to the maximum rate stated in the transmission provider's tariff) for that service if another customer offers a higher rate.

Box 3-1: How Transmission Services Are Provided Under the OATT

OATT contracts can be for point-to-point (PTP) or “network” transmission service. Network integration transmission service allows transmission customers (

e.g.

, load serving entities) to integrate their generation supply and load demand with that of the transmission provider.

A transmission customer taking network service designates “network resources,” which includes all generation owned, purchased or leased by the network customer to serve its designated load, and individual network loads to which the transmission provider will provide transmission service. The transmission provider then provides transmission service as necessary from the customer's network resources to its network load. The customer pays a monthly charge for the basic transmission service, based on a “load ratio share” (

i.e.

, the percentage share of the total load on the system that the customer's load represents) of the transmission-owning and operating utility's “revenue requirement” (

i.e.

, FERC-approved cost-of-service plus a reasonable rate of return).

In addition to this basic charge, some additional charges may be incurred. For example, when a transmission customer takes network service, it agrees to “redispatch” its generators as requested by the transmission provider. Redispatch occurs when a utility, due to congestion, changes the output of its generators (either by producing more or less energy) to maintain the energy balance on the system. If the transmission provider redispatches its system due to congestion to accommodate a network customer's needs, the costs of that redispatch are passed through to all of the transmission provider's network customers, as well as to its own customers, on the same load-ratio share basis as the basic monthly charge.

Also, the transmission provider must plan, construct, operate and maintain its transmission system to ensure that its network customers can continue to receive service over the system. To the extent that upgrades or expansions to the system are needed to maintain service to a network customer, the costs of the upgrades or expansions are included in the transmission-owning utility's revenue requirement, thus impacting the load-ratio share paid by network customers.

Point-to-point transmission service, which is available on a firm or non-firm basis and on a long-term (one year or longer) or short-term basis, provides for the transmission of energy between designated points of receipt and designated points of delivery. Transmission customers that take this kind of service specify a contract path. A customer taking firm point-to-point transmission service pays a monthly demand charge based on the amount of capacity it reserves. Generally, the demand charge may be the higher of either the transmission provider's embedded costs to provide the service, or the incremental costs of any system expansion needed to provide the service. Also, if the transmission system is constrained, the demand charge may reflect the higher of the embedded costs or the transmission provider's “opportunity” costs, with the latter capped at incremental expansion costs.

The comments submitted in response to the Task Force's request raised several concerns as to transmission-dependent customers' access to alternative generator suppliers via OATTs. In particular, some commenters noted that there is a continued possibility of transmission discrimination in their region, and that ability for transmission suppliers to discriminate can deny transmission-dependent customers access to alternative suppliers.

114

The commenters conclude that transmission discrimination can increase delivery risk because purchasers feared that their transmission transactions might be terminated for anticompetitive reasons by their vertically integrated rival, were they to purchase generation from a generator who is not affiliated with the transmission provider. The fact that electricity cannot be stored economically and electricity demand is very inelastic in the short term heightens the ill-effects of this delivery risk.

114

APPA, TAPS.