In the years following enactment of EPACT, there has been a surge of activity in State legislatures and at utility commissions to examine various issues with respect to the electric utility industry. Critical among them has been a wide range of activities designed to promote industry competition at the retail level and to complement the wholesale wheeling and stranded cost initiatives of the Federal Energy Regulatory Commission (FERC). In 1999, customers in 12 States could actually choose their electricity supplier. In California, Rhode Island, Massachusetts, and New Jersey almost all customers had the right to choose. In Arizona, Delaware, Illinois, Michigan, Montana, New Hampshire, and New York customer choice is still being phased in. In Pennsylvania, where two-thirds of customers could choose in 1999, as of January 1, 2000, all customers can choose their electricity supplier.

Regulatory Activities
Not all State commissions have moved with the same zeal, even though most of them have under consideration the merits and implications of competition, deregulation, and electric utility industry restructuring. States with high electricity rates, such as California and those in the Northeast, have had compelling reasons to promote competition in the hope of making lower rates available to their customers in general.

As an example, the California Public Utility Commission (CPUC) directed an examination of the comprehensive set of regulatory programs to explore alternatives to what was then the current regulatory approach based on conditions and trends identified in its Decision No. 92-09-088 of September 1992.⁽¹⁾ The directive resulted in the submission of a staff report--generally known as the "Yellow Book"--to the CPUC in February 1993.⁽²⁾

The "Yellow Book" study concluded that the State should reform its regulatory program, including a redefinition of the prevailing regulatory compact, and offered strategies to address shortcomings of its regulatory framework. Based on a comprehensive re-examination of the electric utility industry in the State and the regulatory policy under which the industry functioned, the CPUC opened rulemaking and investigative proceedings to consider its proposed restructuring policies in early 1994.⁽³⁾ These initiatives, popularly known as the "Blue Book" proposals, outlined a strategy to replace the traditional cost-of-service regulatory framework with alternatives that focused on utility performance and, where possible, the discipline of the market. Subsequent regulatory and legislative activities in California will be presented in more detail as one of the five case studies that follow later in this chapter.

Other States have not moved with such enthusiasm, however. In December 1998, 23 State public utility commissions sent Congress a letter expressing concerns that issues affecting them may not be given adequate consideration in the debate about restructuring. Kentucky, whose electricity prices are the lowest east of the Rocky Mountains, is one of these States. Recently, Kentucky's Special Task Force on Electricity Restructuring concluded that there are no compelling reasons to restructure their electric power industry.

States such as Idaho and Nebraska have taken the view that the main tenets of EPACT (as pertaining to promoting competition) are difficult for them to implement.

The Idaho Public Utilities Commission (IPUC), for example, has stated that it is not its role to actively attempt to bring about deregulation of the industry. The IPUC expressed the concern that rates in Idaho could go up, and, at the same time, deregulation could result in the diminution of the quality of service enjoyed by the ratepayers in the State.⁽⁴⁾ The Nebraska Public Power District (NPPD) maintains that applying reciprocity requirement provisions of FERC Order 888 violates Nebraska's law and its constitutional rights.⁽⁵⁾ The NPPD has, however, continued to monitor the development of regional transmission organizations and independent transmission companies. NPPD has created a new position--Vice President of Transmission Services--to focus on restructuring outside its boundaries and how external activities might affect NPPD.⁽⁶⁾

In 1996, Idaho, Kentucky, and Nebraska ranked first, second and twelfth, respectively, in lowest average revenue per kilowatthour.⁽⁷⁾ In 1998, they ranked first, third and ninth, respectively. It is not surprising that they are not the States that are leaders in the restructuring movement.

Like California, Kentucky is one of the five States that will be examined in detail later in this chapter. The others are Massachusetts, Pennsylvania, and Texas. Massachusetts and Pennsylvania were chosen because they, like California, were among the earliest States to embrace restructuring although they have had vastly different experiences. Texas was chosen because it is a large State that is in the planning stage for instituting competition.

Legislative Activities
All State utility commissions typically enjoy broad regulatory authority to ensure that electric utilities in their jurisdictions provide fair, just, and reasonable electricity rates to their customers. In addition, State commissions are also empowered to regulate various other aspects of power generation, transmission, and distribution at the State level. However, not all commissions may be endowed with the necessary legal authority to manage an evolving competitive market structure. Accordingly, legislation in some States is designed primarily to grant the utility regulatory agency the authority to address the restructuring issues or to consider alternative rate-making processes (incentive- or performance-based regulation). Elsewhere, State legislators show a serious interest in finding out how the State could respond to new competitive pressures emerging in the electric industry.⁽⁸⁾ Exploratory activities may also be promoted at the behest of the State legislators in an effort to gain additional insights.⁽⁹⁾ In some cases, legislative actions may become necessary to adopt decisions recommended by the commission(s) for implementation.

As of July 1, 2000, 24 States⁽¹⁰⁾ and the District of Columbia had enacted legislation or passed regulatory orders to restructure their electric power industries. Alaska and South Carolina had legislation or regulatory orders pending. Sixteen States⁽¹¹⁾ still had ongoing legislative or regulatory investigations, and there were 8 States⁽¹²⁾ where no restructuring activities had taken place (Figure 23).

This section presents the current status of restructuring in five States: California, Kentucky, Massachusetts, Pennsylvania, and Texas. California, Pennsylvania, and Massachusetts were chosen because they were among the first States to institute restructuring at the retail level and they did so differently. Texas has recently passed restructuring legislation and its utilities and public utility commission are planning for competition which will begin in 2002. Kentucky was chosen to serve as an example of a State that has done little to restructure; in fact, current policy is to maintain the status quo and put off restructuring until there is a compelling reason to do so.

California
In 1996, the average revenue per kilowatthour (which is used as a proxy for price) of electricity sold in California was 9.48 cents,⁽¹³⁾ the tenth highest rate among the 50 States and the District of Columbia. This rate was one factor leading Governor Pete Wilson to sign Assembly Bill 1890 (AB1890) on September 23, 1996. This new law established a 4-year transition period to make the State's electric power industry competitive. To implement it, retail competition, allowing customers to choose their electricity, began on March 31, 1998. Rates were frozen at the levels in effect as of June 10, 1996, and a 10-percent rate reduction was guaranteed for residential and small commercial users.⁽¹⁴⁾ These rates will remain frozen until March 31, 2002. As of December 31, 1999, the State has 209,752 direct access customers. This number represents 2.1 percent of the total number of eligible customers and 13.8 percent of the total load.⁽¹⁵⁾ Industrial customers, who generally use more electricity than residential customers, account for a major share of this load. These customers are currently served by 35 electric service providers registered with the CPUC.⁽¹⁶⁾

AB1890 also contained provisions for the creation of an independent system operator (ISO) and a legally separate power exchange (PX) out of concern about market power issues. To ensure that utilities do not continue their traditional monopolistic advantage by controlling generation, transmission and distribution, the ISO and PX are independent of the utilities.⁽¹⁷⁾ The law allows for stranded cost recovery in California. Utilities may apply the difference between their actual operating costs and the frozen rate toward recovering their stranded costs. A "Competition Transition Charge" based on the sales volume appears on consumers' bills along with another charge that finances the bonds that provided the rate reduction.⁽¹⁸⁾ A subsequent law requires retail suppliers to disclose the sources of generation to customers; report fuel types and consumption to system operators who will make the information available to the California Energy Commission; and report emissions, purchased power, losses, and retail sales.⁽¹⁹⁾

The California ISO received FERC approval in October 1997, and became operational on March 31, 1998. The major responsibility of the ISO is to ensure fair and impartial access to the high-voltage transmission system for all generators, while maintaining reliable operation. The transmission system will continue to be owned by the investor-owned utilities (IOUs). The ISO will ensure that no particular buyer or seller of electricity can block access by others. Generators who ship electricity through the system will pay a fee to cover the system costs and to ensure reliability.⁽²⁰⁾

The PX, regulated by FERC, also became operational on March 31, 1998. It serves as an auction market for the buying and selling  of  electricity.  The three largest IOUs in the State--Pacific Gas & Electric (PG&E), Southern California Edison (Edison), and San Diego Gas & Electric (SDG&E)--must sell their power to the PX. If they wish to, municipalities, independent power producers, irrigation districts, and out-of-state producers may also sell power to the PX.

The PX accepts requests to buy a quantity of electricity at a given price. The PX functions like an auction to match total demand for power with generation of power. It creates a spot market where price information is publicly available. The PX then solicits bids from electricity generators and chooses the lowest bidders until it has enough supply to meet the requests to buy power. The prices change on an hourly basis.⁽²¹⁾

PG&E, Edison, and SDG&E were ordered to buy their power from the PX for 4 years after its inception to resell to customers who buy electricity from the utility distribution companies. They will pay a price determined by the PX based on the market demand for power. This was done to foster fair competition between utilities and other electricity suppliers.

However, in a recent development, California regulators are poised to amend the requirement that the State's IOUs buy all their power through the PX. The Automated Power Exchange of Santa Clara and other rivals have consistently opposed the mandate that the IOUs buy from the PX and they have won support from two commissioners, Josiah Neeper and Richard Bilas. They have introduced a proposal that would allow utilities to buy from any approved exchange.⁽²²⁾

AB1890 established a public benefit program for low income assistance, energy efficiency, research and development programs, and programs to encourage renewables. It was anticipated that approximately $540 million would be collected over 4 years by a non-bypassable wires charge.⁽²³⁾ Approximately 30 local governments have switched to Commonwealth Energy, which is supplying geothermal energy from Lake, Sonoma, and Imperial counties. Santa Monica, in Los Angeles County, is currently the world's largest all-renewable city, but Oakland is considering making purchases that would put it in the global lead.⁽²⁴⁾

PG&E, Edison, and SDG&E have divested a large amount of generating capacity to address concerns about market power. To date PG&E has divested itself of 7.4 gigawatts of capacity at a sale price of $1.5 billion. Edison has sold 10.6 gigawatts for $1.2 billion. SDG&E has completed transactions of 2.1 gigawatts for $475 million.⁽²⁵⁾ California has been cited as "leading the way with merchant plant proposals."The California Energy Commission approved three merchant plant proposals in 1999, has seven applications under review, and anticipates 11 more proposals.⁽²⁶⁾

In June 1999, the CPUC began public hearings on opening distribution to competition. The formal opening of the proceeding in December 1998 resulted in responses from numerous stakeholders. Some have suggested waiting until competition in the generation market has matured before attempting to open distribution to competition.⁽²⁷⁾

The California electricity market was in turmoil during the summer months of 2000. There were periods of rolling blackouts around the San Francisco area. Prices in the San Diego region more than doubled. A scorching summer exacerbated these conditions. Some stakeholders have called to re-regulate the industry, while others have called for market reforms. In the meantime, the California ISO set price caps to contain wholesale prices over the summer. The cap was initially set at $750 per megawatthour and was lowered to $250 per megawatthour in August 2000.

California's high electricity prices have been linked to three causes: a deficiency of generating capacity in California; a market system that does not permit enough forward market trading as a means of managing supply and demand risk; and a system that does not allow sufficient customer response to high prices. The California ISO sees improving consumer response to increasing prices and opening the market to new electricity suppliers as fundamental solutions to the recent instability.⁽²⁸⁾

Government executives and agencies have offered short-term relief to high prices. On August 2, 2000 Governor Gray Davis issued three executive orders aimed at stabilizing prices, increasing supply, and reducing peak demand.⁽²⁹⁾ The Low Income Home Energy Assistance Program and the Small Business Administration released more than $2 million in emergency funds to assist low-income households and small businesses in the San Diego area.⁽³⁰⁾

Responding to San Diego Gas & Electric's petition to reduce wholesale prices, FERC ordered a hearing on August 23, 2000 to investigate if the electricity rates are just and reasonable. Should FERC conclude that the rates were unreasonable, it could order refunds under authority granted by the Federal Power Act for sales that occurred after August 23. Subsequently, on September 21, FERC Chairman James Hoecker asked Congress for greater authority "to retroactively correct extraordinary wealth transfers" since the agency has limited authority to order refunds.⁽³¹⁾

Texas
Much of Texas is unique in that it is not subject to the control of FERC. As stated in Chapter 3, the United States has three separate power grids connected by a few direct current tie lines: the Eastern Interconnect, the Western Interconnect, and the Texas Interconnect. Utilities within each interconnection coordinate operations and planning and buy and sell power among themselves. Because utilities in the Texas Interconnected System are not connected with other utilities outside the State and electric trade does not cross State boundaries for these utilities, FERC does not have regulatory jurisdiction over them. In 1998, Texas was near the middle of the rankings of all States and the District of Columbia with respect to electricity rates. In 1998, the average revenue per kilowatthour was 6.07 cents, which ranked as the 25^th lowest in the country. With prices in the middle of the range of States, it is not surprising that Texas recently passed restructuring legislation.

In 1995, Senate Bill 373, which became the Public Utility Regulatory Act of 1995, was enacted to restructure the wholesale electricity market in Texas consistent with FERC requirements for unbundled transmission service. The law also required the establishment of an ISO. The ISO in the Electric Reliability Council of Texas (ERCOT) differs somewhat from the other ISOs. The ERCOT ISO does not participate in generation dispatch, in power exchanges, in providing ancillary services, or in establishing prices other than determining the cost of any redispatch needed to allow transactions to occur. In 1996, the Public Utility Commission (PUC) of Texas issued rules implementing the legislation that required transmission-owning utilities in the State to provide open access to the transmission system and ancillary services. The rule also required separation of transmission, distribution, and generation costs and rates, and the establishment of the ERCOT ISO.⁽³²⁾

In 1999, Texas was the largest State to pass restructuring legislation. Governor George W. Bush signed Senate Bill 7 to introduce retail competition to Texas.⁽³³⁾ Retail choice will begin in 2002. The restructuring law freezes rates for 3 years or until 40 percent of a utility's customers have switched to an alternate provider, whichever comes first. The law is expected to give a boost to development of renewable energy sources. Utilities can recover an estimated $9 billion in stranded costs through securitization. In response to the law, TXU and Southwestern Public Service have already put some of their power plants up for sale.⁽³⁴⁾ Electric cooperatives and municipally owned utilities are exempt from customer choice unless their governing boards decide to open their markets to competition.

As of January 10, 2000, all Texas IOUs had filed detailed plans  describing  how  they  propose  to unbundle their operations.⁽³⁵⁾ As of March 31, 2000, nine utilities had turned in their transition plan proposals to the PUC.⁽³⁶⁾ Utilities were required to state which aspects of their businesses would be deregulated and which portions would remain regulated. The companies were also required to describe how they would separate their businesses into a retail provider, a generation company, and a transmission and distribution utility. The electric companies were required to report the fees they would charge to retail competitors using the utilities' lines.⁽³⁷⁾ By September 2001, the PUC will begin to certify retail electricity providers. The Texas Pilot Program is scheduled to commence on June 1, 2001, and on January 1, 2002 retail choice is slated to begin with small commercial customer and residential electric rates decreasing by 6 percent. A proposal for a consumer education plan has been approved by State regulators. This marks the first step in implementing a consumer plan mandated by the restructuring law. The intent of the plan is to explain restructuring to customers and inform them of their options. Plans for northeastern Texas have been developed, and the PUC will strive to develop a plan with emphasis on non-English speaking and lower-income customers. The plan will most likely be implemented by early 2001.⁽³⁸⁾

The Texas approach to implementing competition has been cited as a good model for restructuring. The decision to deal with wholesale issues at the outset by leveling the playing field for equal transmission access "promises to create a strong retail market, "according to one energy consultant.⁽³⁹⁾ A spokesperson for another energy company, however, believes that a serious flaw in the restructuring plan is the local control of metering and billing until 2004.⁽⁴⁰⁾

With regard to renewables, a new rule mandates the building of 2 gigawatts of new capacity fueled by renewable sources by 2009. Between now and 2009 the rule requires the following: 400 megawatts by 2003, an additional 450 megawatts by 2005, another 550 megawatts by 2007, and an additional 600 megawatts by 2009. January 1, 2002, will mark the beginning of a Renewable Credits Trading Program in the State, which will continue until 2019. Retailers with insufficient credits will be penalized $50 per megawatthour or 200 percent of the average cost of traded credits of the year.⁽⁴¹⁾

Massachusetts
On November 27, 1997, HB 5117, the Electric Utility Restructuring Act, was signed by Governor Paul Cellucci to restructure the industry in Massachusetts. The law basically affirmed the PUC restructuring order of 1996. The Restructuring Act mainly affects the Commonwealth's eight investor-owned distribution companies, which supply 87 percent of the electricity in Massachusetts.⁽⁴²⁾ Retail access was required by March 1998, and a simultaneous rate cut of 10 percent to be followed 18 months later by an additional 5 percent cut was made law. Municipal utilities have the option to participate.⁽⁴³⁾ Additionally, the divestiture of generation assets was encouraged.⁽⁴⁴⁾ In 1996, Massachusetts had the eighth highest electricity rates in the Nation, which were most certainly a consideration in enacting the legislation the following year. In 1998, the rates in the Commonwealth were the ninth highest in the country. Between 1996 and 1998, the nonutility share of capability increased from 16 percent to 67 percent as utility divestitures took place. So far, however, the number of customers that have switched is not high. A slowly increasing standard offer rate (described below) could lead to increases in customers in the future.⁽⁴⁵⁾

Pennsylvania
In 1996, the average revenue per kilowatthour in Pennsylvania was 7.96 cents;⁽⁵⁵⁾ in 1998, it was 7.86 cents. In both years, Pennsylvania had the eleventh highest average electricity price among the 50 States and the District of Columbia. Like California and Massachusetts, Pennsylvania falls into the camp of relatively high-priced States that have been somewhat aggressive in pursuing restructuring.

In terms of numbers of customers that have switched suppliers, Pennsylvania's restructuring program is the most successful in the Nation. Governor Tom Ridge signed the Electricity Generation Customer Choice and Competition Act into law on December 3, 1996. The law basically separates the generation of electricity from the services of transmitting and distributing it. The law called for a phase-in of retail choice with one-third eligible to choose by January 1998, another third by January 1999, and the remaining third by January 2000. Therefore, all customers in Pennsylvania can now choose the generator of their electricity, but they are still required to purchase the transmission and distribution components of their electricity from the local supplier. All utilities subject to the separation requirements were required to file their restructuring plans with Pennsylvania's Public Utilities Commission (PUC) in 1997. The PUC has established industry groups to provide recommendations on areas of concern that have arisen in the restructuring process. These areas include education, information and billing, universal service, conservation, reliability, direct retail access implementation scheduling, metering competitive safeguards, interaction between suppliers and utilities, and taxes. A multimedia consumer education campaign was launched by the Pennsylvania Electric Choice Program to educate consumers about their ability to shop for a competitive supplier. Included in the campaign were television and radio advertisements as well as a four-page newspaper insert.⁽⁵⁶⁾

With regard to stranded costs, the PUC is authorized to determine the level of stranded costs that each utility is permitted to recover. Cost shifting between customers as a result of stranded cost recovery is prohibited. The costs can be recovered through a non-bypassable competitive transition charge (CTC) that will be reviewed and adjusted annually for each customer who elects to receive service from an alternative generation supplier. The CTC will be collected by utilities over a maximum period of 9 years, unless the PUC approves another time frame. California, by contrast, authorized a collection period of only 4 years.

The Competition Act encourages market participants to coordinate their plans and transactions through an ISO or functional equivalent. Electric utilities are permitted to divest themselves of facilities or to reorganize their corporate structures, but unbundling of services is required. Additionally, public benefits programs are funded by an energy surcharge to provide programs for low-income assistance, energy conservation, and other public purposes at the existing funding level.⁽⁵⁷⁾

As a result of the new law encouraging outsiders to set up business within the Commonwealth (unlike Florida whose Supreme Court recently reaffirmed restrictions on merchant plants), interesting developments have occurred. For example, the largest wind farm in the eastern United States is now in Pennsylvania. GreenMountain.com, which completed the eight-turbine project in April 2000, is betting that customers will pay a slight premium to switch to power that is cleaner than the traditional source of Pennsylvania's electricity--coal.⁽⁵⁸⁾

Today, 52 suppliers are licensed to sell their generation in the Commonwealth. A survey from the Office of Consumer Advocate reports that 408,414 (8 percent) of Pennsylvania's residential electricity customers have switched utility providers. The survey also noted that 95 percent of electricity customers are aware of their options to switch to alternative suppliers under the law. Of those who have switched, approximately 20 percent have opted for a green power choice.⁽⁵⁹⁾ In the PECO service area in southeastern Pennsylvania, 15 percent of residential customers, 30 percent of commercial customers, and 62 percent of industrial customers have switched suppliers.⁽⁶⁰⁾ Twenty-six percent of Duquesne Light's residential customers switched their supplier. Technically, with the recent completion of Duquesne Light's sales of its generating assets to Orion Power Holdings,⁽⁶¹⁾ all customers have a new supplier of electricity. The 26-percent citation represents those customers who actively sought an alternative supplier. Duquesne Light provides service in the Greater Pittsburgh area.

One of the keys to Pennsylvania's successful transition to a competitive retail marketplace may have been its pilot program. The program provided an incentive to participate by guaranteeing a 10- to 13-percent discount off the electric distribution company charge for all classes of customers while establishing a generation credit that allowed customers to obtain electricity supply at 5 to 20 percent below the credit. "As a result, the pilot was oversubscribed and the PUC and the electric distribution companies had an opportunity to work out problems in the transition to competition," according to Sandra Barber of the National Energy Team.⁽⁶²⁾

Kentucky
In December 1999, Kentucky's Special Task Force on Electricity Restructuring released its findings and recommendations. It found that "there is no compelling reason at this time for Kentucky to move quickly to restructure. Despite the prospects of Congressional legislation to mandate restructuring, actions taken by 24 States and the District of Columbia to restructure, and the fact that some of those States are geographically contiguous to Kentucky, there are obvious advantages for Kentucky adopting a wait-and-see approach to electricity restructuring. Representatives from other States that have restructured as well as experts in the field of electricity restructuring indicate that Kentucky is in a unique position because of its existing low electricity rates, which currently are the lowest east of the Rocky Mountains. Most of Kentucky's generation is coal-fired and its generators are close to coal fields which are among the cheapest fuel sources. Also, there has been relatively little construction of generating capacity recently, which has kept the Commonwealth's collective rate base low. A wait-and-see approach allows Kentucky to monitor the progress of restructuring in other States and to develop options that protect Kentucky's existing low rates for electricity."⁽⁶³⁾

In 1998, when the average revenue per kilowatthour in Kentucky was 4.16 cents, only Idaho and Washington had lower electricity rates. Unlike California, Massachusetts, and Pennsylvania, Kentucky has no compelling price pressure to restructure. Therefore, the Commonwealth has no retail competition and no competitive supplier activity. The only recent action of note was a Public Service Commission Order in April 1999 to reduce rates for Kentucky Utilities and Louisville Gas and Electric subsidiaries. The order calls for a $52 million rate reduction under a performance-based rate making approach.⁽⁶⁴⁾

Because Kentucky has had no restructuring activity, no stranded cost provisions are in place.

Issues Under Consideration
The current issues faced by the States are varied based on the wide array of associated circumstances. Some areas of concern, however, are similar across State lines, for example:

• Remedying the loss of tax base for local authorities
• Generating renewable power and provisions for net metering
• Evaluating performance-based ratemaking
• Providing non-discriminatory access to all electric power suppliers
• Setting standards of conduct for suppliers and utility affiliates
• Taking environmental issues into consideration
• Ensuring reliability in supplies and designation of supplier of the last resort during transition
• Establishing consumer protection programs
• Determining the role of public power utilities in promoting competition.⁽⁶⁵⁾

The following chapter examines in more detail the role of recent mergers, acquisitions, and power plant divestitures of IOUs in restructuring the electric power industry.

• Table of Contents
• Chapter 7
• Chapter 9

Endnotes

http://www.magnet.state.ma.us/dpu/restruct/competition/index.htm.

48. Electric Utility Week (New York: McGraw-Hill, January 17, 2000) p. 8.

49. Ibid.

50. Electric Utility Week (New York: McGraw-Hill, January 17, 2000) p. 1.

51. Electric Utility Week (New York: McGraw-Hill, January 17, 2000) p. 9.

52. The  Act  authorizes  the  Massachusetts Industrial Finance Agency to issue "electric rate reduction revenue bonds," to finance the buy-out by electric companies of purchased power contracts with above-market rates.

53. Florida Public Service Commission, "States' Electric Restructuring Activities Update," http://www.psc.state.fl.us/general/ publications/restruc.htm.

54. Ibid.

55. Energy Information Administration, State Electricity Profiles, DOE/EIA-0629 (Washington, DC, March 1999), p. 234.

56. U.S. Department of Energy, Electric Utility Restructuring Weekly Update (February 18, 2000), http://www.eren.doe.gov/ electricity_restructuring/weekly/feb18_00.html.

57. Florida Public Service Commission, "States' Electric Restructuring Activities Update," http://www.psc.state.fl.us/general/ publications/restruc.htm.

58. "GreenMountain.com Makes Pitch for Clean Energy," The Wall Street Journal (May 1, 2000), p. A36.

59. Ibid.

60. The Pennsylvania Electric Choice Program, http://www.electrichoice.com/public/pdf/elecchart.pdf.

61. The Energy Report (Arlington, VA: Financial Times Energy, May 8, 2000), p. 15.

62. Anne Millen Porter, "Why Pennsylvania Might Be the Only Game in Town," Purchasing (July 16, 1998).

63. Kentucky Association of Electric Cooperatives, Inc., http://www.kaec.org/stand/elecrestructuring.htm.

64. Energy Information Administration, "Status of Electricity Industry Restructuring by State," http://www.eia.gov/cneaf/ electricity/chg_str/tab5rev.html.

65. Energy Information Administration, Electric Power Annual 1999, Volume I, DOE/EIA-0348(99)/1 (Washington, DC, August 2000).