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Alabama Electricity Profile

Alabama Energy Profile

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Acronyms for the State of Alabama

PSC-Alabama Public Service Commission

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10/00: The PSC closed the formal inquiry into restructuring in the State of Alabama. They will continue to monitor activity in

other States and at the federal level through less-formal channels. The decision came after the PSC commissioners reviewed

the Staff Electric Industry Restructuring Task Force's Report on the Public Interest and Role of Commission. On the matter

of Public Interest, the report stated that it has not been demonstrated that all consumers in Alabama would continue to

receive adequate, safe, reliable, and efficient energy services at fair and reasonable prices under a restructured retail market

at this time. On the matter of Role of the Commission, the report stated that the "Commission can not mandate or otherwise

allow retail competition or electric industry restructuring without state enabling legislation." It was also stated that the

ultimate role of the Commission both during and after a transition to competition will depend on the form restructuring takes

in Alabama.

02/00: Following the recommendations in Interim Report No.1, the PSC scheduled hearings to address two key issues: whether electric power industry

restructuring for competition is in the best interests of the consumers in Alabama and the regulatory authority of the PSC in a market-based system.

11/99: The Staff Electric Industry Restructuring Task Force Interim Report No. I was received by the PSC in September 1999. Comments from interested parties

were received and reviewed. The PSC issued recommendations for hearings in early 2000 to address two key issues: whether restructuring was in Alabama's public

interest and the regulatory/jurisdictional role of the PSC. The report defined "being in the public interest" as resulting in greater economic efficiency for all

consumers. The task force believes some statutory change and policy guidance from the State Legislature would be necessary to implement a move to an efficient

open market form of controlled retail competition from the then existing cost-based monopoly (in February 2000, the PSC set the inquiry for April 2000).

09/99: Final comments were filed in response to the PSC June 1998 Order soliciting comments on electric utility industry restructuring. As a result, Interim Report

No. 1 was issued by the Task Force in September 1999.

04/99: A study released by the University of Alabama, Auburn University, sponsored by the State's cooperative utilities, estimated that rates in Alabama could rise

6 percent under retail competition. The study recommended a slow approach to restructuring and further study.

06/98: The PSC began a formal investigation into restructuring the electric power industry, as ordered in April 1998 docket, by issuing a Scheduling Order posing a

number of questions dealing with the issues of restructuring for competition. Comments from interested parties were received and analyzed, and a report was

prepared.

04/98: PSC issued an order to establish the instant docket, PSC Docket 26427. A series of workshops were scheduled in 1999 on market power, stranded costs,

service reliability and other issues to aid the PSC in decision making.

12/97: The PSC approved a draft report on restructuring the electric industry, "Report and Policy Development Plan of the Staff Electric Industry Restructuring Task

Force," issued in October 1997. The report recommended that a phased study of restructuring be instituted by the PSC to determine the extent the public interest

would be affected by restructuring and competition.

01/97: Alabama Electricity Consumers Coalition and American Energy Solutions filed in Federal court a suit challenging the statute on stranded costs as

unconstitutional. The suit was dismissed because the law had yet to be invoked..

12/96: The PSC Advisory Staff issued a white paper, "The Electricity Industry and Restructuring." The paper led to the creation of a Staff Electric Industry Task

Force to explore the potential results of deregulating the electricity industry in Alabama.

05/96: Senate Bill 306, "The Electricity Customer Severance Law," was enacted. The law provided utilities with the opportunity to collect from customers who leave

their system the amount of stranded costs associated with the customers' service.
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ISO-Independent System Operator

PUC-Alaska Public Utility Commission

RCA-Regulatory Commission of Alaska

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06/05: The Alaskan 24 Legislature enacted House Bill No. 163 to “promote and support the voluntary creation of a unified

generation and transmission system for the electrically interconnected Railbelt area by authorizing the transfer of ownership of

certain state-owned electric power projects (the Alaska inter-tie, the Healey clean coal project, the Bradley Lake hydroelectric

project) to a joint action agency formed by three or more Railbelt electric utilities.”

Source: Alaska State Legislature Bill Action & Status Inquiry System.

http://w w w .legis.state.ak.us/basis/get_bill_text.asp?hsid=HB0163A&session=24

09/01: The Regulatory Commission of Alaska (RCA) issued an order ending the inquiry into retail electric utility restructuring

and competition in Alaska and closing docket R-9710. According to the RCA's order, "projections of any potential benefits are

too speculative at this time."

Source: Regulatory Commission of Alaska

http://w w w .state.ak.us/rca/orders/

07/99: The legislature disbanded the Public Utility Commission and assigned its responsibilities to the newly named Regulatory Commission of Alaska (RCA). Five

new commissioners were sworn in on July 1, 1999.

06/99: The final version of CH2M Hill's Study of Electric Utility Restructuring in Alaska requested by the PUC was presented on June 30, 1999. Most of the

recommendations targeted the Railbelt (Anchorage and Fairbanks). Included were: consideration of retail pilot programs, encouragement of power trading markets,

creation of a central dispatch point and an ISO, and consolidation of administrative functions and introduction of new technologies such as fuel cells and

microturbines for rural systems.

Source: Regulatory Commission of Alaska

http://w w w .state.ak.us/rca/Electric/CH2Report.pdf

03/99: The Alaska State Legislature Joint Committee issued its report, “Recommendations to the Alaska State Legislature and Alaska Public Utilities Commission

Regarding a Retail Pilot Program.” The report recommended the 21 legislature address restructuring and decide if statutory changes for the PUC are necessary to

implement pilot programs or retail access.

Source: Alaska Legislature

http://w 3.legis.state.ak.us/

01/99: Chugach rejected Matanuska's offer and contended that the savings projected by the merger could easily be achieved through competition; Chugach will

continue to push for statewide competition.

10/98: Matanuska Electric Association, Chugach's largest wholesale customer, offered to buy out Chugach. Chugach's assets were valued at $486 million.

08/98: The Alaska State Legislative Joint Committee, established to develop recommendations for the legislation on electric industry restructuring (due in January

1999) conducted its first hearing. The Alaska Rural Electric Cooperative Association stated that due to the isolation and unique characteristics of Alaska's rural

electric industry, it should be left out of any restructuring plans. Chugach Electric Association, the State's largest electric utility, stated that consumers would

benefit if the State embraced a broad policy of allowing competition.

06/98: PUC rejected Chugach's argument and affirmed the PUC's authority to regulate retail wheeling.

05/98: House Concurrent Resolution No. 34 established a Joint Committee on Electric Utility Restructuring.

Source: Alaska Legislature

http://w 3.legis.state.ak.us/

01/98: Chugach Electric Association, the State's largest utility, urged PUC legislators to allow retail competition in Anchorage and surrounding areas. House Bill

235 primarily failed because Chugach would not support it unless it was amended to allow retail wheeling in Anchorage and surrounding areas.

th

st
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Acronyms for the State of Arizona

ACC-Arizona Corporation Commission

APS-Arizona Public Service Company

CTC-Competition Transition Charges

PG&E-Pacific Gas and Electric Company

SRP-Salt River Project

TEP-Tucson Electric Pow er Company

Home > Electricity > State Restructuring > Arizona Restructuring

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06/07: The Arizona Cooperation Commission held an open meeting and set the APS rate increase to approximately 5.7

percent on summer bills and about 3.5 percent on winter bills. Because APS has a variety of rate plans and customer

options, individuals’ personal rate increases will vary.

Source: Arizona Cooperation Commission

http://w w w .cc.state.az.us/

05/06: The Arizona Corporation Commission approved a temporary interim rate increase designed to partially refund money

Arizona Public Service (APS) has already paid for natural gas in 2005 and what APS projects it will incur in additional charges

for 2006. The increase is necessary to pay down debts that continue growing due to the unprecedented and sustained high

natural gas and purchased power prices. APS does not profit from this increase as the monies collected will be used solely to

pay fuel costs. The temporary increase represents approximately 7.6 percent on the typical residential customer’s bill. The

surcharge will end once APS collects approximately $140 million in fuel and purchased power prices.

Source: Arizona Cooperation Commission

http://w w w .cc.state.az.us/

03/05: In their first quarter 2005 report, the Electric Competition Advisory Group reported no activity for the fourth quarter of

2004 and the first quarter of 2005. The same group reported no activity since the first quarter of 2004. This inactivity strongly

suggests that electricity restructuring in Arizona has been indefinitely put on hold.

10/04: Restructuring in Arizona was essentially placed on hold due to a variety of regulatory orders. However, the state’s initial restructuring rules and legislation

imposed a non-by-passable system benefits charge on direct access customers to fund Commission-approved low-income, demand side management,

environmental, renewable and nuclear power plant decommissioning programs. However, since there were very few direct access customers in Arizona, there was

actually no new funding. According to the Arizona Corporation Commission (ACC), the system benefits charge reflected what was already in base rates for public

benefits for each utility. Some utilities did not levy such a charge. For those utilities that did levy the charge, all customers were required to pay it. The amount of

the charge that funded low-income programs varied by utility. Most of the state’s major utilities have had low-income and energy efficiency programs for a number of

years and these have continued under restructuring.

Source: United States Department of Health and Human Services

http://w w w .liheap.ncat.org/dereg/states/arizona.htm

03/04: The Arizona Court of Appeals ruled that the Arizona Corporation Commission’s decision to require electric utilities to divest their generation assets was

unconstitutional. The Arizona Court of Appeals stated that it is the Commission’s duty to attempt to control retail rates, not to specifically control and manage

electric utilities’ operations. Furthermore, the ACC did not provide an explanation of how requiring electric utilities to divest their generation assets would help to

control rates, thus providing the basis for the Arizona Court of Appeals to rule that this ACC statute was unconstitutional.

Source: Arizona Court of Appeals

http://w w w .cofad1.state.az.us/opinionfiles/CV/CV010068.pdf

04/03: The Arizona Public Service Company (APS) issued a report entitled “Arizona Public Service Company Comments to the Electric Competition Advisory

Group.” The report stated that “For residential and smaller commercial customers, transaction costs of retail choice have been more significant than first believed...

APS does not believe that the Retail Electric Competition Rules should be continued in their present form.”

Source: Arizona Public Service Company

http://w w w .cc.state.az.us/

09/02: The Arizona Corporation Commission (ACC) issued its final order on Track A issues. The order instructed the Arizona Public Service Company (APS) and

the Tucson Electric Power Company (TEP) "to cancel any plans to divest interests in any generating assets." The order also stated that the previous decisions

dealing with the amount of power purchased through a competitive bid process were put on hold. The Commission had designated this issue part of Track B, which

was to deal with the entire "competitive solicitation process." The ACC specifically stated that if APS pursued acquiring Pinnacle West Energy Corporation's

generating assets, then these generating assets cannot "be counted as APS assets in determining the amount, timing and manner of the competitive solicitation

process." In addition, the order established the Electric Competition Advisory Group, and the ACC staff was to “prepare and file reports detailing the activities of the

Advisory Group." This order went into effective immediately.

08/02: Due of the lack of competition in the state, the Arizona Corporation Commission (ACC) nullified a section of the restructuring law that required divestiture of

generation assets. Arizona's restructuring law did not allow former monopoly utilities to own power plants so the utilities were required to "move their power plants

into a separate subsidiary or sell them to another unrelated company." According to an ACC press release, the Commission stated that the Arizona Public Service

Company (APS) and Tucson Electric Power (TEP) "have market power" in their service territories, and "full divestiture would limit the jurisdictional ability of the

Commission to protect Arizonans from market power abuses." Also, APS is required to "file a separate application to transfer generating assets from Pinnacle West

Energy Corporation to APS."

07/02: An ACC Administrative Law Judge issued a recommendation on electric restructuring issues. In the order, the ACC staff concluded that "the wholesale

market was not currently workably competitive; therefore, reliance on that market will not result in just and reasonable rates." The recommended order delayed

divestiture of generation assets until July 1, 2004, and "removes the requirement that 100 percent of power purchased for Standard Offer Service shall be acquired

from the competitive market, with at least 50 percent through a competitive bid process." The recommended order also formed the Electric Competition Advisory

Group, and directed the ACC staff to submit periodic reports on the group's activities. Arizona Public Service Company and Tucson Electric Power Company would
www.eia.gov/cneaf/electricity/page/restructuring/arizona.html 2/2

Group, and directed the ACC staff to submit periodic reports on the group's activities. Arizona Public Service Company and Tucson Electric Power Company would

be required to obtain excess power from "the competitive procurement process as developed in the Track B process." Track B, Competitive Solicitation issues,

were to be dealt with in a subsequent order which the commission would be required to vote on and which would take effect immediately if approved. 100 percent

recovery of $450 million in stranded costs collected by a Competition Transition Charge (CTC) and recovery of the balance of the $638 million in stranded costs

through a "floating" CTC. What does this mean? Twenty percent of the load in TEP's territory was to be open to competition by January 2000, and all by January

2001. Rates were to be reduced by 1 percent and frozen through 2008. TEP's generation assets were to be transferred to an affiliate company by the end of 2002.

01/01: The Salt River Project (SRP) made 20 percent of their 1995 retail peak load available for competition on December 31, 1998 and opened its entire service

territory to competition on June 1, 2000. Arizona Public Service opened 20 percent of their retail load to competition on October 1, 1999, and Tucson Electric Power

opened 20 percent of its retail load to competition on January 1, 2000. Retail access was fully implemented by January 1, 2001.

03/00: The Arizona Restaurant Association began to organize a buying block for its members. A potentially large group of commercial consumers in the Arizona

Public Service territory may switch to an alternative electricity supplier, New West Energy, the marketing arm of the Salt River Project. Members in other service

territories, Tucson Electric and SRP, were allowed to negotiate for an alternative supplier. New West Energy was to provide the Association's members electricity at

a savings and various services including energy efficiency audits to enhance energy savings.

11/99: The ACC approved TEP's restructuring agreement. The agreement was to allow recovery of $450 million in stranded costs collected from ratepayers through

2008; rate reductions of 1 percent and a rate freeze from July 2000 to 2008; and retail access beginning with 20 percent of TEP's retail load 60 days after ACC

approval (January 2000), and all customers by January 2001. TEP's generation assets were to be transferred to an affiliate company by the end of 2002.

09/99: The ACC approved the settlement agreement with APS for restructuring. The APS was required to open 20 percent of its retail territory to competition by

October 1, 1999, and all of it by January 1, 2001. Residential rates were to be reduced 7.5 percent over 4 years, with large users' rates cut 5 percent over 3 years.

APS was to be allowed to recover $350 million in stranded costs over the 5-year transition period. The residential shopping credit is set at 4.5 cents and large users'

at 3 cents. APS was required to transfer its generation assets to an affiliate company.

05/99: The ACC and the Arizona Public Service reached a settlement agreement (still subject to ACC approval and public hearings). The agreement includes 7.5

percent residential and small business rate reductions spread out from 1999 to 2003, and a 5 percent industrial rate reduction over the period 1999 to 2002. The plan

was intended to allow recovery of stranded costs through a competitive transition charge through December 2004. Additionally, the agreement maintains APS's low

income program. TEP's settlement included a more modest rate reduction of 1 percent in July 1999 and in July 2000 with rates frozen at the July 2000 level until

2008.

04/99: The ACC approved a plan with 4 options for stranded cost recovery that was intended to begin retail competition with 20 percent of consumers later that year

and all consumers by January 1, 2001. Utilities were required to file their proposals for stranded cost recovery by June. The solar portfolio standard was eliminated

as too costly. A hearing process was to consider whether to adopt a renewable resource requirement that would include all renewables.

01/99: The Salt River Project opened about 20 percent of their market to retail competition. However, only one alternative supplier (PG&E) was licensed to sell to

only commercial and industrial consumers. SRP's restructuring plan included a 5.4 percent rate reduction for consumers remaining with SRP. SRP was not placed

under jurisdiction of the ACC and thus was not effected by the court ruling that had delayed competition in the investor-owned utilities' territories.

01/99: The ACC delayed retail access when the State Supreme Court decision put a stay on the restructuring settlements submitted by APS and Tucson Electric

with the ACC. The restructuring settlements previously filed by APS and Tucson Electric with the ACC, were withdrawn.

08/98: The ACC approved final rules for restructuring the investor-owned utilities in the State (Arizona Public Service and Tucson Electric Power). Retail competition

was to be phased in over 2 years, beginning January 1, 1999 for large customers. Utilities were required to file restructuring plans by September 1998. These plans

were to include divestiture of all generation assets for utilities to recover 100 percent of stranded costs and rate cuts of 5 percent for residential consumers. The

rules retained the 1996 draft order's solar portfolio standard.

05/98: HB 2663 was enacted and affirmed the ACC's authority to require utilities to open territories to retail competition. The bill extended restructuring to

municipals and other publicly owned utilities, such as the Salt River Project, which opened its territory to retail access on December 31, 1998.

1997: Work group reports were submitted to the ACC and the Joint Legislative Committee on: retail access schedule, taxes, stranded costs, consumer

protections, and the roles of the ACC and legislative committee.
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CTC-Competition Transition Charges

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Last Updated: April 2007

03/03: House Bill 1413 was signed by Arkansas State Governor Mike Huckabee in order to allow the state’s electric power

producers to form consolidated authorities to manage power generating facilities.

Source: Arkansas Legislature

http://w w w .arkleg.state.ar.us/ftproot/bills/2003/public/HB1413.pdf

02/03: House Bill 1114 was signed by Arkansas State Governor Mike Huckabee in order to repeal earlier enacted

deregulation legislation. The Arkansas General Assembly passed Act 204 and determined that it was in the public’s best

interest to continue regulating electric utility rates for the foreseeable future.

Source: Arkansas Public Service Commission

http://w w w .arkansas.gov/psc/electric3.htm

12/01: The Arkansas Public Service Commission (PSC) submitted its report to the General Assembly pursuant to Act 324

of 2001 on the Development of a Competitive Electric Market and Possible Impact on Consumers on December 20, 2001. The report assessed the progress of

restructuring in the Arkansas electric industry. The PSC recommended that the General Assembly either completely suspend the current statute to some future

date or repeal the laws related to retail open access. The recommendations were based on the prevailing absence of an operating regional transmissional

organization and the lack of evidence that customers, especially residential and small commercial customers, would realize a net price benefit from retail open

access. In comments from the PSC staff, it was also stated that in order for competition to exist, improvements to the transmission system were needed to assure

that the major load centers in Arkansas have equal and reasonably unconstrained access to generation supplies.

11/01: The Arkansas Public Service Commission (PSC) issued an order that postponed the October 18, 2001, scheduled hearing regarding delaying the

implementation of retail competition in Arkansas. The hearing was rescheduled for November 1, 2001.

09/01: A study conducted for the PSC by energy consultants, La Capra Associates, concluded that the wholesale markets were not sufficiently developed at the

time to support successful retail competition, nor were the utilities prepared to handle the customer switching functions necessary under retail choice. The PSC was

to hold a scheduled hearing on October 18, 2001, to consider the views of the PSC staff, utilities, and consumer groups on further delaying the implementation of

retail competition in Arkansas. Under current restructuring legislation, the PSC may delay retail access, scheduled for October 2003, until as late as October 2005.

Further delay would necessitate legislative action.

Source: Arkansas Public Service Commission

http://w w w .accessarkansas.org/psc/

08/01: Responding to the requirements of Act 324, which delayed implementation of retail open access until October 2003, but allowed the PSC to further delay

open access until no later than October 2005, the PSC issued a request for utilities to provide an analysis of prices customers may pay for electric generation

service under open access as compared to continued regulation and to provide information needed to evaluate the readiness of both the retail and the wholesale

markets for implementation of retail open access. A public hearing was set for October 18, 2001 to consider these issues.

03/01: Senate Bill 236 was signed into law and included Act 324. Act 324 delayed the start of deregulation from January 2002 to October 2003. The PSC was also

authorized to initiate further delays based on the adequacy of the state's transmission system and generating capacity to support a competitive market.

11/00: The Public Service Commission issued the Report on Electric Restructuring to the Arkansas General Assembly on November 29, 2000. The PSC

recommended the date for deregulation be extended from the original timeframe in the restructuring legislation of January 1, 2002, through June 30, 2003, to October

1, 2003, through October 1, 2005. The PSC was scheduled to present the report and recommendations to the Joint Insurance and Commerce Committees of the

General Assembly on November 30, 2000. The extension was intended to allow more time for the wholesale market to develop and the new federally-regulated

transmission organizations to develop and become operational.

10/00: The PSC opened a docket to study the electric power market. The PSC wanted to ensure that the power supply problems and price spikes that occurred in

California in the summer of 2000 did not occur in Arkansas when restructuring was scheduled to begin in 2002. The State's utilities suggested delaying the start for

competition until October 1, 2003, or October 1, 2005 at the latest. Prevailing legislation required the retail market to open by June 30, 2003 at the latest. The PSC,

utilities, and Attorney General's office all agreed that the original timetable was unlikely to be carried out, but disagreed on when competition would begin in the

State. The PSC was directed to present its recommendation to the legislature in mid-November 2000.

08/00: In an effort to deregulate by 2002, the PSC asked utilities to examine whether or not they had market power. Once a utility provides an analysis to this

inquiry, the PSC was supposed to issue an order determining if, in fact, that utility did have market power. If it is deemed that the utility had market power, it would

be required to submit a mitigation plan, followed by a public hearing and a final PSC order to eliminate that market power.

07/00: The PSC released its report on Mandatory Rate Reductions for Electric Utilities on July 13, 2000. According to the report, the state legislature could not

pass a comprehensive rate reduction without the direct consent of the utilities and after conducting an economic evaluation. The PSC had the power to determine if

a utility's rates' are "unjust and unreasonable." Therefore, residential and small business customers who elect standard service over participation in the retail choice

program would not receive a comprehensive rate reduction during the rate freeze period unless the stated criteria was met.

12/99: The PSC issued Rules for Electric Affiliates and for Energy Provider licensing. These rules issued by the PSC were intended to allow the utilities to use

Competition Transition Charges (CTC) to recover unmitigatable stranded costs. Furthermore, PSC guidelines stated that the sale of generation assets is one way to

quantify stranded costs and/or mitigate stranded costs. Also, the generation portion of the utilities was to be functionally unbundled from the transmission and

distribution functions. Afterwards, the PSC was directed to issue a series of reports to facilitate implementation of retail competition. Reports are due on: tax issues

and the financial impact on local governments; progress reports on competition and its impact on the price(s) of electricity; and standards of conduct for electric
www.eia.gov/cneaf/electricity/page/restructuring/arkansas.html 2/2

and the financial impact on local governments; progress reports on competition and its impact on the price(s) of electricity; and standards of conduct for electric

service providers.

05/99: Rates for consumers of utilities seeking to recover stranded costs were to be frozen for 3 years, and, for those not seeking to recover any stranded costs, 1

year.

04/99: Senate Bill 791, a compromise of the two bills introduced in February, was passed by the General Assembly and signed by the Governor. Act 1556 (Bill 791)

was intended to restructure the electric power industry in the State and allow retail access by January 2002. Stranded costs were to be recovered via a competitive

transition charge and the sale of bonds. Rates were to be frozen for 3 years for utilities seeking stranded cost recovery and one year for those that did not. The PSC

was empowered to force divestiture of generation assets to alleviate market power, and PSC was allowed to decide if stockholders should share stranded costs

recovery with ratepayers. Utilities were required to functionally unbundle generation, transmission, distribution, and customer service and file unbundled rates with

the PSC by January 1, 2000. Municipal utilities were given the option of participating in retail access, and may aggregate retail loads upon filing unbundled

distribution rates with the PSC.

10/98: The final report, Report on Restructuring the Arkansas Electric Utility Industry, was released by the PSC. The report recommended retail competition no

later than January 1, 2002 and asked the legislature to act in 1999 on restructuring giving the PSC authority to implement retail competition and determine stranded

costs and appropriate recovery methods, including securitization.

05/98: The PSC concluded hearings on when and how to open the electric market to retail competition. Entergy and two other utilities agreed competition should

not begin before January 1, 2002, when the neighboring States of Oklahoma and Texas were expected to open their markets.

12/97: The PSC decided to conduct public hearings in 1998 to address restructuring issues. Four dockets were established to investigate the specific issues. A

report with recommendations was due to the General Assembly by October 1998.

12/97: Arkansas PSC agreed to Entergy's restructuring plan. The plan included rate reductions of about $217 million over 2 years; debt reduction of $165 million

over 5 years on the Grand Gulf Nuclear Station; and creation of a special Transition Cost Account to be used to collect funds for stranded costs recovery. In

Entergy's restructuring plan, the Transition Cost Account to be used for funds for stranded costs was to be funded by excess earnings above 11 percent return on

equity during the rate freeze period (at new levels through 2001).

04/97: The General Assembly requested, with Senate Resolution 24, a study on competition in the electric industry. A series of hearings were held through 1998

and a report was to be completed by January 1999.
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California Electricity Profile

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Acronyms for the State of California

CAISO-California Independent System Operator

CEC-California Energy Commission

CPUC-California Public Utilities Commission

CRS-Cost Responsibility Surcharges

DRC-Dedicated Rate Component

DWR-California Department of Water Resources

EOB-California Electricity Oversight Board

FERC-Federal Energy Regulatory Commission

PX-Pow er Exchange

SCE-Southern California Edison

SDG&E-San Diego Gas and Electric

WECC-Western Energy Coordinating Council

Home > Electricity > State Restructuring > California Restructuring

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03/10: Pacific Gas and Electric Company introduced Proposition 16 which aims to make California cities and counties

gain approval of two-thirds of their voters before public power authorities (agencies setup by cities and counties to

purchase electricity for resale to consumers) could be established. Proponents of the proposition state that the

creation of city and county public power authorities could burden taxpayers, while opponents of the proposition feel the

measure would lead to reduced competition in the electricity industry.

Source: The New York Times

http://w w w .nytimes.com

12/08: The California Public Utilities Commission is exploring ways to lift a freeze on the competitive retail electricity

program that would allow residential and large power users, including large stores, cement plants, and universities, to

obtain competitive bids for the best price for electricity. However, the commission stated that one of the biggest

impediments is more than two dozen power-purchase contracts signed by the State in 2001 to help end the California

energy crisis. According to State law, no expansion of retail competition for electricity can occur before the last

contract expires, sometime between 2015 and 2017. However, the commission voted unanimously on November 21,

2008 to set a January 2010 goal for shifting legal responsibility for the contracts from the State to California's three

regulated, investor-owned utilities: Southern California Edison, Sempra Energy's San Diego Gas & Electric Co. and

PG&E Corporation's Pacific Gas & Electric Co.

Source: The Los Angeles Times

http://w w w .latimes.com/

11/06: The California Public Utilities Commission (CPUC) adopted improvements in the electric utilities' demand

response programs and created several new programs. These changes are intended to improve system reliability

during the summers of 2007 and 2008.

Source: California Public Utilities Commission

http://w w w .cpuc.ca.gov/PUBLISHED/NEWS_RELEASE/62260.htm

10/04: The California Public Utilities Commission provided definition and clarification to its resource adequacy

program, with the intent toward ensuring that electricity consumers of California's three largest investor-owned utilities

receive service that is reliable and reasonably priced.

Source: California Public Utilities Commission

http://w w w .cpuc.ca.gov/PUBLISHED/NEWS_RELEASE/40871.htm

10/04: Senate Bill 39xx issues state-wide standards with the intention of preventing price manipulation.

Source: California Public Utilities Commission

http://w w w .cpuc.ca.gov/PUBLISHED/REPORT/31910.htm

09/04: California governor Schwarzenegger signed Senate Bill 1565 which required a state commission to formulate a strategy to improve the reliability of the

state’s electricity transmission system.

Source: California State Senate

http://info.sen.ca.gov/pub/03-04/bill/sen/sb_1551-1600/sb_1565_cfa_20040610_162325_asm_comm.html

06/04: The governor signed Senate Bill 772 which authorized up to $3.0 billion of Energy Recovery Bonds to refinance PG&E's bankruptcy Regulatory Asset. The

Bond principal, interest, and related costs will be recovered via two new surcharges called the Dedicated Rate Component (DRC) and the Energy Recovery Bond

Balancing Account charge. All consumers of electricity in PG&E's service territory will be required to pay these new surcharges, except for those consumers that

are exempt from the new surcharges pursuant to Senate Bill 772 or other Commission decisions.

Source: California Public Utilities Commission

http://w w w .cpuc.ca.gov/Published/Final_decision/41515.htm#P96_2678

01/04: The California Public Utilities Commission assured that California will have the resources to prevent electricity shortages by unanimously adopting a

framework under which the state's three investor-owned utilities will plan for and obtain the energy resources investments and demand-side investments necessary

with the intent to ensure that their customers receive reliable service at low and stable prices.

Source: California Public Utilities Commission

http://w w w .cpuc.ca.gov/PUBLISHED/NEWS_RELEASE/33555.htm

12/02: In accordance with Assembly Bill 57, the California Public Utilities Commission (CPUC) approved procurement plans for Pacific Gas and Electric Company,

Southern California Edison, and San Diego Gas and Electric as well as an operating order and servicing orders. The utilities were allowed to buy power starting

January 1, 2003, thus relinquishing responsibility from the California Department of Water Resources. According to a PUC press release, the operating order

describes how the utilities “will perform the operational, dispatch, and administrative functions for DWR’s Long-Term Power Purchase Contracts.” The commission

also approved servicing orders between the utilities and the DWR, but the orders are only amendments to the current arrangements because neither party has been

able to agree on a final arrangement.

11/02: The CPUC issued a press release stating that direct access customers, those who held contracts prior to September 20, 2001, will be charged “Cost

Responsibility Surcharges (CRS) with an interim overall cap of 2.7 cents/kWh” for the costs incurred by the State and utilities during the energy crisis. The

surcharge applies to direct access customers of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company.

Each surcharge will be based on each customer’s portfolio or their share of the Department of Water Resources and utilities’ procurement costs.
www.eia.gov/cneaf/electricity/page/restructuring/california.html 2/5

Each surcharge will be based on each customer’s portfolio or their share of the Department of Water Resources and utilities’ procurement costs.

11/02: The Public Utilities Commission ruled that revenues from the permanent $0.01 per kilowatt-hour and the $0.03 per kilowatt-hour surcharges may be used “to

return the utilities to reasonable financial health.” The Commission has to determine how the utilities can use the revenues if at all. Decisions on this matter will be

forthcoming.

10/02: In accordance with Assembly Bill 57, the California Public Utilities Commission (CPUC) approved an interim order that allows the Pacific Gas and Electric

Company, Southern California Edison, and San Diego Gas and Electric to buy their own power starting January 1, 2003. The utilities were responsible for submitting

their short-term procurement plans by November 12, 2002 and their long-term plans by April 1, 2003. After the CPUC has approved each utility’s plan, the

Department of Water Resources will no longer be responsible for procuring power for Californians. The CPUC also set January 6, 2003 as the date that interested

parties should file a proposed procedural process and schedule to implement Senate Bill 1078.

09/02: Governor Davis signed several bills this month to strengthen energy infrastructure, protect the State's energy market and provide for cleaner and affordable

energy. Assembly Bill 57 provides that utilities can start buying power no later than January 1, 2003. The California Public Utilities Commission must review each

utility's plan before it can resume these duties. Senate Bill 1078 "established the California Renewables Portfolio Standard for California." Utilities are required to

increase the use of renewable energy by 1 percent per year until 20 percent of retail sales are generated from renewables. Investor-owned utilities and direct access

providers must reach the 20 percent mark by 2017.

07/02: The Federal Energy Regulatory Commission issued two orders on July 17, 2002. The first order was a response to the California ISO's Market Design 2002

Proposal. According to the first FERC press release, FERC extended "the current West-wide requirement that all generators offer all uncommitted power for sale,"

"set a $250/megawatthour (MWh) bid cap for all sales in the Western Energy Coordinating Council (WECC) beginning October 1, 2002," and set the California ISO's

maximum clearing price at $91.87. The second order required the California ISO to elect a new independent two-tiered Governing Board by January 1, 2003.

According to the second FERC press release, the first tier would be made up of "independent, non stakeholders" with "sole decision-making authority," and the

second tier would be "an advisory committee of stakeholders that may make recommendations."

03/02: The CPUC voted to keep September 20, 2001 as the suspension date for direct access. According to the PUC's decision, customers can renew their

contracts or change their electricity providers if they had contracts as of September 20, 2001. The CPUC intent was also to impose an exit fee on these customers

to provide DWR with more funds to cover the cost of purchasing power.

02/02: The CPUC issued two decisions regarding the adoption of a rate agreement between the CPUC and the Department of Water Resources and cost recovery

of the agency's revenue requirements for purchasing power under ABX 1. In the first decision, the PUC adopted a rate agreement that allowed the DWR to issue

bonds to repay over $10 billion in debt, including over $6 billion to California's General Fund. In the second decision, the CPUC agreed to implement a cost recovery

mechanism for DWR's revised revenue requirements for power purchases made on behalf of the state's three largest utilities: Pacific Gas & Electric, Southern

California Edison, and San Diego Gas & Electric. The revenue requirement for the period covering January 17, 2001 through December 31, 2002 is $9 billion, which

is significantly lower than the original requirement. The PUC adopted a 9.295 per kilowatt-hour charge for PG&E customers, 9.744 cents per kWh for SCE

customers, and 7.285 cents per kWh for SDG&E customers. According the CPUC revenue requirement order, "these charges shall apply to each DWR-supplied

kWh included on bills rendered on or after March 15, 2002."

10/01: The CPUC suspended retail choice in California. The CPUC estimated that about 5 percent of the State's peak load of 46,000 MW was then under direct

access contracts, mostly with large industrial customers. Contracts in place will be allowed to continue until their expiration.

10/01: The CPUC and Southern California Edison reached a settlement concerning the lawsuit filed by SCE against the CPUC in November 2000. SCE claimed the

PUC had violated federal law and unconstitutionally took property by its actions in not providing sufficient retail rates for SCE. The settlement was intended to

restore SCE's creditworthiness and enable it to begin purchasing power for its retail customers, limit ratepayers' cost of paying off SCE debt, and enable SCE to

pay its debt over a reasonable, certain period of time.

06/01: The CPUC set a tiered rate structure for the 3-cent per kilowatt-hour increase adopted March 27, 2001. Residential customers of Pacific Gas & Electric and

Southern California Edison were expected to see rate increases of between zero and 80 percent, depending on their usage. Those using below 130 percent of the

baseline amount and exempted or low income consumers were to see no increase. The tiered structure gradually increases the percentage of increase to 80

percent for customers who use over 300 percent of the baseline amount. Commercial rates were to increase between 34 and 45 percent, industrial rates were to

increase an average of 50 percent, and agricultural rates 15 to 20 percent. The new rates were scheduled to begin June 1, 2001.

06/01: The Federal Energy Regulatory Commission [FERC] extended and broadened its price mitigation and market monitoring plan (issued in April 2001). The

price mitigation plan applied to spot market sales 24 hours a day, 7 days a week, in all 11 States in the Western Systems Coordinating Council. The formula to

calculate the market clearing price was changed to reflect the marginal cost of replacing gas used for generation based on gas prices reported in Gas Daily for three

spot market prices in California The formula adjusted operating and maintenance expense upward, and eliminated the emission costs from the calculation (emission

costs will be invoiced to the CAISO and recovered separately). The price mitigation efforts were intended to apply to all spot market transactions. When operating

reserves are above 7 percent, the prices were not to exceed 85 percent of the highest hourly price that was in effect during the most recent Stage 1 reserve

deficiency period called by the ISO.

05/01: SBX1 6, a bill to create the California Consumer Power and Conservation Financing Authority, was signed into law by the Governor. The main objective of the

new authority was to ensure that California had an adequate supply of power at reasonable prices. The new agency was given the authority to construct new power

plants and transmission projects, issue as much as $5 billion in bonds, and direct new energy efficiency programs, renewable energy programs, and efficiency and

environmental improvements to existing power plants.

04/01: The FERC announced a plan for market monitoring and price mitigation designed to bring price relief to the California market and price certainty to buyers

and sellers while promoting energy conservation and encouraging investment in generation and transmission. During periods when operating reserves fell below 7

percent, the market clearing price was to be based on the highest bid of the highest cost gas-fired unit located in California that is needed to serve the CA ISO load

on any day in which a reserve deficiency is called. The gas-fired generators are required to submit their heat and emission rates to the FERC and the CAISO; the

ISO would then calculate the marginal cost for each generator, including operating and maintenance costs. Prices during the period of operating reserve deficiency

were to be limited to the marginal costs of the highest cost (as calculated by the ISO) generator brought online to meet demand.

03/01: The FERC issued an order to 13 power sellers in the California market to either make refunds for power sales above the proxy market clearing price during

stage three emergencies or provide further justification for their prices. FERC also released a staff report on proposed long-term market mitigation measures, a

replacement market monitoring plan expected to be in place by May 2001.

03/01: The CPUC approved substantial rate increases of over 40 percent, effective May 2001, for customers of two of the State's major investor-owned utilities; most

of the increase was marked for reimbursement to the State (DWR) for the power it is purchasing for those customers. Low income customers are exempt from the

increases. The portion of rates that the two utilities retain is still effectively under the rate freeze. The CPUC did not rule out that more rate increases which it may

deem necessary in the future, since the accumulated debt of over $13 billion the two utilities face has not been resolved.

03/01: Governor Davis issued a series of Executive Orders designed to expedite the construction and permitting of generation capacity and boost the output from

existing generation capacity in the State. The orders provided incentives for renewable and distributed generation, bonuses for completing construction and bringing

a plant online by July 2001, and a funding mechanism to help plants install emission control equipment and pay mitigation fees to compensate for increased
www.eia.gov/cneaf/electricity/page/restructuring/california.html 3/5

a plant online by July 2001, and a funding mechanism to help plants install emission control equipment and pay mitigation fees to compensate for increased

operations. The governor anticipated an addition of 5000 MW by the summer of 2001, another 5000 MW by 2002, and a total of 20,000 MW by 2004.

02/01: The Governor issued an executive order for a conservation program. The $800 million program includes incentives to reduce commercial lighting, a public

media campaign, and appliance rebates. Businesses are required to reduce outdoor lighting by half during non-business hours.

02/01: Legislation, ABX1 1, was signed into law by the governor. This legislation allowed the state Department of Water Resources to purchase power under long

term contracts and sell the power to consumers through utilities. The DWR was authorized to sell $10 billion in revenue bonds to fund the power purchases, which

cannot be funded through the state treasury. The bonds were to be paid through electricity rates over the next ten years. Rate increases are authorized after the

2002 election. Additionally, the law provides another $500 million for the DWR to continue its purchasing of power in the short-term. The DWR had already spent

over $400 million under provisions of Assembly Bill 7 to purchase power in order to prevent major blackouts in the State.

01/01: The CPUC released the audits of Southern California Edison and Pacific Gas & Electric which were required in the recent CPUC decision to allow temporary

one cent rate increases for the two utilities.

01/01: The FERC issued, on January 29, a compliance order to the Cal PX seeking to enforce the December 15 order provision that ensured sellers into the PX

market who bid in excess of $150/MWh would only receive their actual bids, rather than the highest bid price. In response, the Cal PX suspended its day-ahead and

day-of market operations, as of January 31, 2001. The Cal PX filed an emergency motion with the court requesting a stay of the December 15th order. Earlier in

January, Cal PX announced it is taking steps to downsize its operations by 15 percent. Southern California Edison and PG&E were suspended from trading on the

PX after they defaulted under the agreed upon tariff and rate schedule.

01/01: The CPUC issued an interim order that provided rate relief for Southern California Edison and PG&E. Retail rates were increased by one cent per kWh for all

rate classes. This meant a 7 to 15 percent increase, whereas the utilities had requested 26 and 30 percent increases. The CPUC will request an independent audit

of the two utilities to determine the need for the rate increases, which are subject to refund provisions if not found to be just and reasonable costs.

01/01: Southern California Edison won a major component of its lawsuit against the CPUC. The court upheld the utility's right to recover just and reasonable costs

for serving its customers as required by law. Southern Cal and PG&E have experienced increasing losses, totaling $12 billion by January 2001, due to the

escalating wholesale prices at the PX and the inability to collect adequate revenues to recover these costs of procuring power because retail rates were frozen at a

much lower rate

01/01: The CPUC suspended penalties for interruptible rate schedule customers who fail to curtail power usage under emergency conditions. Due to the

unexpected extent of curtailment requests in recent months, especially January 2001, there was determined to be a threat to the public health, safety, and welfare

due to the inability of customers who participate in the interruptible programs, particularly the two petroleum pipeline companies, to continue operations, or face

severe monetary penalties for operating during the energy emergency situations. The result created a shortage of and corresponding price increases for gasoline and

diesel in California. The pipelines were be allowed to operate for 7 consecutive days to bring supplies back up to normal levels, and the CPUC expressed its hope

that customers on interruptible schedules would continue to curtail power usage as much as possible in the absence of penalties. The CPUC is planning on

reassessing the interruptible programs in the State and is planning to issue a report addressing these issues.

01/01: ABX1 5, ABX1 6, and SBX1 7, were all passed into law in January. These bills addressed the state's prevailing energy crisis. The ISO has issued a Stage

Three Electrical Emergency for almost every day in January. Stage Three meant that reserves had fallen to below 1.5 percent, and rolling blackouts may be required

to maintain system integrity. AB 5 required, as ordered in the December 15 order by the FERC, the current stakeholder board of the ISO be replaced with

nonstakeholders appointed by the governor. AB 5 also required the ISO to publish a list of the plants that were not operational each day on its Internet site. AB 6

Required generating plants owned by utilities in California prior to June 1997 to remain under CPUC jurisdiction without the possibility of being sold before January

2006. The CPUC was directed to require that the output of utility-owned plants be available for California consumers. SB 7 authorized the Department of Water

Resources to spend $400 million to purchase electricity and sell it to consumers using California’s utilities as intermediaries. Two California utilities (Southern

California Edison and Pacific Gas & Electric) became unable to purchase electricity to meet their consumers' demands due to their inability to obtain financing.

Both utilities' credit ratings were downgraded to "high yield investment" status as their debts for purchased power increased and their ability to pay their power bills

decreased. Escalating wholesale prices at the PX where utilities were required to purchase power under AB 1890 together with the required retail rate caps which

prevented the utilities from recovering the costs of the wholesale purchases resulted in losses totaling around $12 billion for both utilities. Both utilities have stated

that they may file for bankruptcy (which Pacific Gas & Electric did in April 2001) .

12/00: In its December 15 Order Directing Remedies to the California Wholesale Markets, the FERC ended the mandatory PX "buy/sell" requirement, thus allowing

utilities to sell their own power directly to retail customers and enter into long-term bilateral contracts for purchasing power. The PX rate schedule will end on April

30, 2001. It was expected that power provided by the spot market would decrease to about 5 percent of the load. To ensure that the real-time markets are just and

reasonable, the Order provided for appropriate real-time market monitoring and price mitigation for ISO and PX spot markets. In order to encourage less reliance on

the real-time, or spot, market, the FERC imposed a $150 soft cap on wholesale prices. Bids above the $150 cap were not meant to set the market clearing price,

and their costs must be verified. Additionally, the Order required the current stakeholder board at the ISO be replaced with a non-stakeholder board. Meanwhile,

decision making and operating control was been turned over to the management of the ISO, retaining the existing board of directors in an advisory position until the

new board was scheduled to be seated in April.

12/00: Southern California Edison, Pacific Gas & Electric, and San Diego Gas & Electric requested rate increases to recover the increasing costs of purchased

power. In response to the CPUC's refusal to increase rates, both SoCal and PG&E requested the Federal Court "to affirm the utility's right to pass on the increased

costs of wholesale power to its retail customers." The CPUC held hearings in late December, and announced that it would allow rate increases, ending the rate

freeze in effect since March 1998 when competition began. The CPUC said it would take actions necessary to avoid the continuing conditions that may jeopardize

utilities' ability to procure power for their customers.

10/00: San Diego Gas & Electric (SDG&E) received approval from the CPUC to negotiate long-term power contracts. SDG&E was now able to hedge electricity

prices in an effort to protect against volatile price spikes like the ones that occurred the past summer. Southern California Edison (SCE) and Pacific Gas and

Electric (PG&E) were recently granted approval to negotiate long-term contracts.

09/00: Revised legislation, Assembly Bill 265 (formerly Assembly Bill 2290), was signed into law. The law capped electricity rates for San Diego Gas and Electric

(SDG&E) residential, small commercial, and lighting customers at 6.5 cents/kWh through December 31, 2002, retroactive to June 1, 2000. The CPUC retained the

right to extend the rate freeze through December 2003 if they deemed it was in the public interest to do so. The law mandated the CPUC to initiate a voluntary

program for large commercial, agricultural, and industrial customers of SDG&E to also set the energy component of their bills at 6.5 cents/kWh with a true-up after

one year.

09/00: The governor signed Assembly Bill 970, legislation that was intended to accelerate the power plant siting approval process. Assembly Bill 970 reduced the

California Energy Commission (CEC) licensing process from 12 months to 6 months for plants and creates a "green team" to help provide guidance and assistance

with the permitting process. The law was scheduled to go into effect in January 1, 2004.

08/00: At an emergency CPUC meeting called by Governor Davis, the CPUC approved a rate stabilization plan for SDG&E customers on August 21. The CPUC

rejected a price freeze, saying it was unclear who would have to pay the difference in wholesale energy costs. The plan, which is retroactive to June 1, 2000, stated
www.eia.gov/cneaf/electricity/page/restructuring/california.html 4/5

rejected a price freeze, saying it was unclear who would have to pay the difference in wholesale energy costs. The plan, which is retroactive to June 1, 2000, stated

that consumers who use 500 kWh or less per month will pay no more than $68/month for electricity through the end of January 2001. The rates for those customers

was subsequently intended to increase to $75/month through the end of December 2001. Any additional power consumed beyond 500 kWh would be charged at

market-based rates. Caps were also outlined for small commercial customers.

08/00: The CPUC on August 3 ruled in favor of a petition by utilities PG&E and Southern California Edison (SCE) to enter into bilateral agreements with generators

at set prices to shield the utilities and consumers from volatile price spikes. SCE and PG&E were to be allowed to contact third-party suppliers via the Cal PX to

negotiate contracts to buy power at set rates for up to five years. The five-year agreements were to serve as a hedge against price spikes during periods of high

demand and low reserves.

08/00: On August 2, the president of the CPUC and the chairman of California's Electricity Oversight Board (EOB) released a report that addressed blackouts in the

PG&E service territory in early June 2000 and the volatile wholesale market prices that were affecting retail rates to SDG&E consumers. The report sited California's

high demand and limited generating capacity as the main reasons for the blackout. Governor Davis responded to the report by ordering the California Attorney

General to form a task force to investigate California's wholesale market.

07/00: San Diego Gas & Electric and the California PX recently proposed a solution to the CPUC for alleviating the price volatility experienced by SDG&E

customers that summer. The market-based bidding program proposed to the CPUC would allow SDG&E to bid for power within the CalPX for longer periods into the

future using the existing Block Forward Market products. This would enable the company to purchase power at lower prices during periods of high demand, avoiding

the price spikes associated with summer heat and increasing demand such as experienced in Southern California that spring and summer.

01/00: As of January 15, 2000, the CPUC reported 209,752 direct access customers (2.1 percent) out of 10,157,716 possible utility distribution customers. The

direct access customers represented 13.8 percent of the total load. Almost one-third of the demand by large industrial customers was being served by competitive

companies, whereas only about 2.1 percent of residential load was on direct access.

10/99: The CPUC issued its opinion on distributed generation. Addressed were concerns with reliability, safety, and non-discrimination in distributed generation

interconnections with the utilities. Issues also included developing definitions for distributed generation, defining the role of the distribution company, environmental

impacts, and ownership and control issues with distributed generation.

10/99: Senate Bill 418 was passed and states that ratepayers can receive “a fair and reasonable credit” if any surplus profits are made from selling rate reduction

bonds.

09/99: Senate Bill 96 created a five member Electricity Oversight Board to manage the Independent System Operator and Power Exchange. Governing boards will

be appointed by the Electricity Oversight Board to administer the Independent System Operator and Power Exchange.

09/99: Assembly Bill 811 was passed and determined how customers can obtain an energy credit from the Power Exchange.

09/99: PG&E announced plans to sell its hydroelectric assets in California, which includes 68 power plants and 94 dams, after failing to convince the legislature to

allow them to move the plants to an unregulated subsidiary. However, PG&E announced that it may revisit the legislature with the idea of moving the plants to a

subsidiary, since it claimed that this would reduce consumer rates by 10 percent for residential and 20 to 40 percent for large users. At the time, these assets had

a book value of $800 million and recently valued by PG&E at $3.3 billion.

07/99: Senate Bill 1159 was passed and provided consumer protections against slamming or unauthorized transfers of service. Independent third party verification

companies could also provide confirmation of a change in electric service providers.

06/99: The CPUC approved San Diego Gas & Electric's proposal to end its rate freeze on July 1, 1999. The end of the transition period for SDG&E came two and a

half years early, as SDG&E sold their power plants substantially above book value and thus completed recovery of stranded costs.

06/99: The CPUC began public hearings on opening distribution services to competition. The formal opening of the PUC proceeding in December 1998 resulted in

responses from numerous stakeholders including utilities, industrial and agricultural groups, cogenerators, and marketers. The process of opening distribution

services to competition was deemed likely to prove as complex as the opening of generation services had, with some at the time suggesting that waiting until the

transition period for moving generation to competition is completed before attempting to open distribution to competition.

06/99: As of May 31, 1999, the CPUC reports that 135,493 California consumers (about 1.3 percent) had switched electricity providers. The breakdown by

customer class was: 92,904 residential consumers or about 1.1 percent; 26,942 small commercial (2.8 percent); 11,652 large commercial (5.9 percent); 1,002 large

industrial (20.6 percent); 2,977 agricultural (2.5 percent); and 16 unknown. About half of the consumers who switched suppliers opted for "green" power, electricity

generated from environmentally acceptable methods, such as wind, solar, and geothermal.

06/99: The CPUC ended the mandatory 10 percent rate reduction for SDG&E since the transition period for SDG&E ended with recovery of all stranded costs and

the end of the Competition Transition Charge (CTC) for consumers. Rates in SDG&E territory were now unregulated and more likely to become more volatile. The

utility announced expectations that future rates may rise during the summer months.

05/99: Sacramento Municipal Utility District approved a direct access program to replace their pilot program. The program would offer 300 MW of load to competitive

suppliers and was less expensive and simpler for suppliers than was the pilot program.

11/98: PG&E stated that it would sell 13 mostly gas-fired plants to Southern Company for $801 million. PG&E would also sell The Geysers, the nation’s largest

geothermal power complex to FPL Energy for $213 million. PG&E intends to use the money raised by these sales to reduce stranded costs that were being paid by

its consumers.

10/98: Based on the California PUC's data, New Energy Ventures, a retail electricity marketer, calculated it had won about 40 percent of the 13,648-GWh load

being served by nonutility energy service providers.

06/98: Sacramento Municipal Utility District opened a portion of its service territory to competition with a pilot project and announced plans to allow all its

customers retail access over the next few years.

04/98: The CPUC issued the final order officially opening the electric industry market to competition as of March 31, 1998 for all consumers in investor-owned

utilities' service territories. Control of 70 percent of the State's transmission lines was transferred to the California ISO.

04/98: California's restructuring legislation included a 10 percent rate reduction for residential consumers.

03/98: The CPUC issued regulations to protect consumers from fraud and market abuses. To operate in the State, competitive suppliers must provide clear

information on price, service, and generation sources; use a standard bill format; provide proof of technical, operational, and financial capability; and post a $25,000

bond.

12/97: The CPUC delayed the starting date for retail competition to March 31, 1998, due to additional time needed to test software at the ISO and PX.
www.eia.gov/cneaf/electricity/page/restructuring/california.html 5/5

10/97: Senate Bill 90 was enacted to provide administrative guidelines for the renewables program under Assembly Bill 1890. The California Energy Commission

was given authority to administer the funds collected for renewable energy technologies support.

10/97: Senate Bill 1305 was enacted to require retail suppliers of electricity to disclose the sources of generation to customers; report fuel type and consumption to

system operators who would then make the information available to the CEC; and report emissions, purchased power, losses, and retail sales.

09/97: Assembly Bill 360 allowed utilities to issue $7.3 billion in bonds (securitization) to pay off stranded investments.

08/97: Senate Bill 477 was passed to correct a definition in Assembly Bill 1890 which lacked some consumer protections.

09/96: Assembly Bill 1890 was enacted to restructure the California electric utility industry and implement retail direct access. The law required the creation of an

Independent System Operator (ISO) to operate the transmission system and a Power Exchange (PX)--both subject to FERC approval--to operate a wholesale power

market through which the IOU’s must sell to and buy from all power needed to serve their customers; divestiture of power plants (except hydro and nuclear) by the

investor-owned utilities; recovery of stranded costs via a Competition Transition Charge on customer bills until 2002; a 10-percent rate reduction (financed by issuing

bonds that will be repaid by a charge on customers’ bills over a ten year period) and a rate freeze at 1996 levels for small and residential customers for the transition

period of 4 years (through March 2002); continued energy efficiency and renewable energy programs and low-income customer programs funded by public purpose

program charge on customer bills; and numerous protections from any detrimental effects of the restructuring aimed at small consumers and utility employees.

12/95: The CPUC issued its final order calling for the restructuring of the electric power industry and allowing consumers direct access to competitive suppliers of

electric power. Originally, the CPUC plan was to phase in consumer direct access, but later was amended to allow retail access for all consumers simultaneously,

beginning January 1, 1998.

1994: The CPUC issued the "blue book" which initiated a study of electric power industry restructuring in California.
www.eia.gov/cneaf/electricity/page/restructuring/colorado.html 1/1

ELECTRICITY

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PUC-Colorado Public Utility Commission

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06/02: The Colorado Public Utilities Commission initiated a new resource planning framework which required the

commission to approve Colorado utilities’ forecasts and needs assessment proposals.

Source: Colorado Public Utilities Commission

http://w w w .dora.state.co.us/PUC/

11/99: The Colorado Electricity Advisory Panel issued its Final Report. A majority (17 of 29 members) voted against

restructuring the industry as it would not be in the best interest of the State and its consumers. The Legislature required a

2/3 majority vote for a formal recommendation, which was not met. A minority report supporting restructuring was also

issued, as well as a "middle ground" report. The major reasons restructuring was opposed by the Final Report were: 1)

Colorado had low rates; 2) a consultant study modeling the effects of restructuring found that rates were likely to rise; and 3)

rate impacts would have been disproportionately shared among classes of consumers, with low-income, fixed income, rural, residential, and small consumers

seeing the greatest rate increases.

Source: Colorado Public Utilities Commission

http://w w w .dora.state.co.us/PUC/

08/99: The task force continues held public hearings across the state on restructuring the industry. During the five hearings, opponents of restructuring had

outnumbered proponents, on the basis that Colorado currently enjoyed low electric rates and the fear that prices would have risen with competition. A sixth hearing

was scheduled, and the task force would make its report to the General Assembly by November 1999.

07/99: A draft report was released by the Colorado advisory panel. The report showed that most panel members opposed opening the retail electricity market to

competition, believing prices would have risen under restructuring. Proponents of restructuring, including IOU's, environmentalists, and industrial customers, thought

prices would fall, citing a DOE study that supported their view. Public hearings would be held in July and August for public comment on the report. The final report

was not due to the legislature until November 1999.

05/99: A study by Stone & Webster Management Consultants, Inc. and Standard and Poor’s was conducted for the Colorado Electricity Advisory Panel. The study

found that consumers would have paid more for power if the state opened the retail electricity market to competition. The Panel planed to present preliminary

findings on restructuring to the legislature by July 1999.

01/99: The Colorado Public Utility Commission adopted rules which required IOU's to itemize the fuel sources used for generated and purchased electricity. The

idea of unbundling costs was intended to educate consumers on the costs and sources of generation and the separate costs of power generation and delivery.

07/98: The Colorado Electricity Advisory Panel (created by Senate Bill 152) met for the first time in July. The purpose of the panel was to study electric industry

deregulation and report the findings to the legislature by November 1999.

05/98: Senate Bill 152 was enacted. It created a 21-member panel to assess whether retail competition would benefit the state's consumers.

06/96: On June 26, 1996, the Commission opened Docket Number 96Q-313E, in the matter of the Inquiry Into Electric Utility Industry Restructuring of Colorado.
www.eia.gov/cneaf/electricity/page/restructuring/delaware.html 1/2

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DP&L-Delmarva Pow er and Light

PSC-Delaw are Public Service Commission

RFP-Request for Proposal

SOS-Standard Offer Service

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01/07: As of December 2006, only one retail supplier in Delaware was providing services to residential customers, of which,

only one percent had switched services.

Source: LIHEAP Clearing House

http://w w w .liheap.ncat.org/dereg/states/delaw are.htm

11/06: The Delaware Public Service Commission entered Order No. 7078 which adopted the proposed “Rules for

Certification and Regulation of Electric Suppliers” observed in the order. These rules were intended to be used for reregulation of Delaware’s electricity providers.

Source: Delaw are Public Service Commission

http://depsc.delaw are.gov/

5/06: After a pending 59-percent increase in electricity rates, the Delaware General Assembly passed legislation that

enrolled all of DP&L’s residential customers into a plan which spread the higher electricity rates through 2009.

Source: Delaw are Energy Office

http://w w w .delaw are-energy.com/

04/06: A joint resolution was introduced in the Delaware House of Representatives (JR 23) which called for the Delaware Public Service Commission, in

consultation with the Governor’s Energy Advisory Council, to conduct a feasibility study in regards to re-regulating Delaware’s electricity industry.

Source: The State of Delaw are

http://w w w .legis.state.de.us/LIS/LIS143.NSF/vw Legislation/HJR+23?Opendocument

04/06: Joint resolution 3 (JR3) was introduced in the Delaware state senate with the intent to require the state’s Office of Management and Budget and the

Controller General to issue a Request for Proposal (RFP) to “hire an independent consultant to issue a study that recommends a process to re-regulate electric

power in the State. It required the study to examine and discuss the benefits and shortfalls of such re-regulation, and to discuss the costs that re-regulation would

impose upon the State and the electric industry. Finally, the study was scheduled to be presented to the Governor and the General Assembly by December 2006.”

Source: The State of Delaw are.

http://w w w .legis.state.de.us/LIS/LIS143.NSF/vw Legislation/SJR+3?Opendocument

04/06: Gov. Minner signed House Bills 5 & 6 (HB 5 & HB 6). House Bill 5 provided “state government with the flexibility to aggregate its electricity usage and

bargain for the best rates possible to save taxpayer money.” House Bill 6 provided “an optional deferral for Delmarva Power electric customers in connection with

the pending rate increase.”

Source: State of Delaw are

http://w w w .state.de.us/governor/new s/2006/04april/041306_2006_legislative_agenda.shtml

03/06: The Electric Utilities Retail Customer Supply Act of 2006, House Bill 6 (HB 6) was introduced by the House. “The Act provides that all electric distribution

companies subject to the jurisdiction of the Commission would be designated as the standard offer service supplier and returning customer service supplier in their

respective territories. The Act provided further opportunity for distribution companies to enter into long and short-term supply contracts, own and operate generation

facilities, build generation and transmission facilities, make investments in demand-side resources and take any other Commission approved action to diversify their

retail load supply. Additionally, Delmarva Power is required to conduct Integrated Resource Planning for a forward-looking 10 year time frame and to file such plan

with the Commission, the Controller General, the Director of the Office of Management and Budget and the Energy Office every two years starting with December 1,

2006. As part of the initial planning process, Delmarva Power is required to file a proposal to obtain long-term supply contracts. The proposal requires Delmarva

Power to include a Request for Proposal (RFP) for the construction of new generation resources within Delaware.” “With respect to rate increases for Standard Offer

Service to be effective on May 1, 2006, residential and small commercial customers of DP&L, depending on rate classification, shall have the ability to opt out of the

following rate deferral plan:

Date Rate % Increase

5/1/2006 15%

1/1/2007 25%

6/1/2007 19%

1/1/2008 True-up/Balance

a. A customer who did not opt out of the deferral plan would be placed on a non-by-passable tariff, under which the customer would be responsible for all of his/her

incurred deferral amounts including carrying costs of the plan.

b. Customers will have from April 1, 2006 to April 28, 2006 to affirmatively opt out of this plan.”

Source: State of Delaw are

http://w w w .legis.state.de.us/LIS/lis143.nsf/vw Legislation/HB+6/$file/legis.html?open

03/06: Delmarva recommends a 3-step phase in of price increases.

02/06: The governor issued Executive Order No. 82 (EO 82) which directed the Delaware Public Service Commission to “examine the feasibility of (a) deferring, for a

fixed or a phased-in period, pending electricity rate increases; (b) requiring Delmarva to build generation, or enter into long term supply contracts, to meet up to 100

percent of supply options under traditional rate base, rate of return regulation; (c) requiring Delmarva to conduct integrated resource planning to ensure fuel diversity

and least cost supply alternatives; and (d) requiring Delmarva to implement demand side management, conservation and efficiency programs. The examination by

the Public Service Commission shall also include its assessment of the need for legislation to accomplish any of these potential options. The results of this
www.eia.gov/cneaf/electricity/page/restructuring/delaware.html 2/2

analysis shall be submitted to the Office of the Governor no later than March 8, 2006.”

Source: The State of Delaw are

http://w w w .state.de.us/governor/orders/e%20o%20%2082.shtml

10/04: Acting under the Electric Utility Restructuring Act of 1999, House Bill 10 (HB 10), the Public Service Commission began Standard Offer Service (SOS)

providing Conectiv customers who “do not otherwise receive electric supply service from an electric supplier are provided “‘standard offer service’” by the “‘standard

offer service supplier.’”

Source: Delaw are Public Service Commission

http://depsc.delaw are.gov/

08/02: The PEPCO/Conectiv merger was approved pending an extension of the rate freeze through May 2006. The two companies retained their names under the

holding company of Pepco Holdings Inc.

Source: U.S. Security and Exchange Commission

http://w w w .sec.gov/divisions/investment/opur/filing/35-27765.htm

04/02: Delaware’s governor issued Executive Order No. 31 (EO 31), creating the Delaware Energy Task Force. The Task Force was charged with: meeting

the electricity and heating needs of a rapidly growing population, particularly south of the Chesapeake & Delaware Canal; and, ensuring that the transmission and

distribution facilities were adequate to meet future demand.

Source: State of Delaw are.

http://stateplanning.delaw are.gov/

01/00: Delaware Electric Cooperative's restructuring plan was approved on January 27, 2000 with Order No. 5424.

08/99: The PSC issued final rules for restructuring in Delaware. The start date for retail competition was scheduled for October 1, 2000 for residential customers,

October 1, 1999 for large customers, and January 15, 2000 for medium-sized customers. Further details regarding these final rules are as follows:

Conectiv (DP&L)

Phase-in of retail access for consumers in Conectiv's territory was scheduled for large industrial consumers on October 1, 1999; other consumers with over 300 kW

demand by February 2000; and small consumers by August 2000. Conectiv would be the default supplier during the 4-year transition period.

Delaware Electric Cooperative

Consumers in Delaware Electric Cooperative territory were scheduled to have a similar schedule with a 6 month delay. Municipals in Delaware would have the option

to choose whether or not to allow retail access.

Rates Conectiv (DP&L)

Residential consumers were scheduled to receive a 7.5-percent rate reduction and a 4-year rate freeze at the 9/30/99 level from 10/1/99 to 9/30/03. Nonresidential

rates were scheduled to be frozen at the 9/30/99 level from 10/1/99 to 9/30/02.

Delaware Electric Cooperative

Consumers were scheduled to receive no further rate reduction (having received a recent 5- percent cut) but rates would be frozen during the transition period from

4/1/00 to 3/31/05.

04/99: Delaware passed the Electricity Restructuring Act of 1999, House Bill (HB 10). The act was intended to bring competition to Delaware’s electricity

generation. Rate caps were imposed for non-residential consumers of Conectiv from October 1999 through September 2002; caps for residences were imposed

between October 1999 through September 2002. This involved a residential rate cut of 7.5 percent for Conectiv customers and a rate freeze for the coop customers;

funding for public benefits programs; and for Conectiv, no provisions for stranded cost recovery (the cooperative had no public benefit funding and stranded cost

recovery would have been determined by the PSC). These caps were eventually extended to May 2006.

Source: Delaw are Energy Office.

http://w w w .delaw are-energy.com/

http://w w w .legis.state.de.us/LIS/LIS140.NSF/vw Legislation/HB+10?Opendocument

03/99: House Bill 10, "The Electric Utility Restructuring Act of 1999," was enacted on March 31, 1999. The law's provisions included: a phase-in of retail

competition beginning on October 1, 1999 for large customers in Conectiv's service territory and ending on April 1, 2001; a residential rate cut of 7.5 percent for

Conectiv customers and a rate freeze for the coop customers; funding for public benefits programs; and for Conectiv, no provisions for stranded cost recovery (the

cooperative had no public benefit funding and stranded cost recovery would have been determined by the PSC).

01/98: The PSC adopted a final report on electric industry restructuring with recommendations including unbundling of rates and stranded cost recovery using

Competitive Transition Charges. The report called for competition for all Delaware consumers to begin 12 months after restructuring legislation is enacted.
www.eia.gov/cneaf/electricity/page/restructuring/dc.html 1/2

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District of Columbia Electricity Profile

District of Columbia Energy Profile

District of Columbia Web Sites

Acronyms for the State of District of Columbia

PSC-District of Columbia Public Service Commission

RPS-Renew able Portfolio Standards

SOS-Standard Offer Service

Home > Electricity > State Restructuring > District of Columbia Restructuring

District of Columbia Restructuring Active

Last Updated: September 2008

06/08: New Pepco electric generation rates became effective with bills issued on June 1, 2008 for Pepco’s

Standard Offer Service (SOS) customers in the District; that is, customers who have not chosen an alternative

generation supplier. Since generation rates account for nearly 80% of residential customers’ bills, Pepco

anticipates that residential customers will see an average annual increase in bills of 15.5% or about $12.75 per

month. Small commercial customers’ annual bills will increase, on average, by approximately 11.9% (about

$24.35 per month).

Source: District of Columbia Public Service Commission

http://w w w .dcpsc.org/

01/08: On January 30, 2008, the Public Service Commission of the District of Columbia issued Order No. 14712,

which approved an increase in the Potomac Electric Power Company’s (PEPCO’s) distribution service rates in the

District of Columbia by $28.3 million; approximately 59 percent of the Company’s revised request of $47.9 million. The Commission also approved an overall rate of

return for PEPCO of 7.96 percent and a rate base of $978.3 million.

Source: District of Columbia Public Service Commission

http://w w w .dcpsc.org/

07/06: The Public Service Commission issued Order No. 14006 on July 21, 2006. In particular, the Commission established a two-phased approach addressing

improvements to SOS procurement process for the next solicitation and initiating a proceeding to review the SOS process and consider the benefits of a portfolio

management approach.

Source: District of Columbia Public Service Commission

03/06: PEPCO proposed new SOS rates. Based on a March 10th filing, beginning with the June 2006 bills, PEPCO anticipated that residential customers would

see an annual average increase of 12 percent in their bills (about $8 per month). Small commercial customers' bills would increase, on average, by about 10

percent. The Commission approved PEPCO's new SOS rates on March 22, 2006. The new SOS rates became effective June 1, 2006.

Source: District of Columbia Public Service Commission

01/05: The Renewable Energy Portfolio Standard Act was enacted. The Act “established a renewable energy portfolio standard (“RPS”) through which a minimum

percentage of District electric providers’ supply would be derived from renewable energy sources beginning January 1, 2007, with an ultimate goal of 11% by 2022.

Specified examples of renewable energy sources were: solar energy; wind; qualifying biomass; methane; geothermal; ocean; fuel cells; hydroelectric power other

than pumped storage generation; and waste-to-energy.”

Source: District of Columbia Public Service Commission

http://w w w .dcpsc.org/customerchoice/w hatis/electric/elec_restruc.shtm#Link1

03/04: The PSC issued Order No. 13118, which adopted the wholesale Standard Offer Service model to govern the implementation of SOS in the District of

Columbia.

Source: District of Columbia Public Service Commission

http://w w w .dcpsc.org/pdf_files/commorders/orderpdf/ordno_13118.pdf

02/03: The PSC issued Order No. 12655 to initiate a proceeding to establish a procedure for selecting a new Standard Offer Service provider, given that PEPCO’s

obligation to serve as the District’s SOS provider was set to expire by the end of 2004. In this order, the Commission directed all interested parties to review the list

of SOS parameters in the order and to file proposed issues and comments no later than March 2003.

Source: District of Columbia Public Service Commission

http://w w w .dcpsc.org/pdf_files/commorders/orderpdf/ordno_12655.pdf

12/01: According to the Commission's latest status report, 8 electricity suppliers and 3 aggregators (brokers for large groups of customers/communities) had been

certified, but only 2 suppliers, Washington Gas Energy Services and Pepco Energy Services, and 1 aggregator were providing service. As of November 2001, these

companies were supplying 3.1 percent of customers, representing 43.2 percent of MW demand, and 42.7 percent of MWh energy usage. The PSC provided

information on the status of retail competition on its website.

10/01: The PSC issued Order No. 12159 and Order No. 12203, which mandated PEPCO distribute the net proceeds (in excess of the asset's book value) of the

sale of its assets to its customers. Order 12159 allowed the customers to receive $50.1 million, but Order 12203 stated that PEPCO should revise the rate schedule

and add 9.09 percent interest and begin distribution "on October 22, 2001 or the first billing cycle after October 22, 2001." According to the PSC website, residential

customers received $75.39 per household and commercial customers received 0.393 cents per kWh for the annual usage ending March 31, 2001. The total credits

distributed to customers amounted to $51.85 million.

09/01: Order 12186 provided the guidelines and procedures for posting the price-to-compare information on the Commission's website. Consumers could calculate

their savings on the Commission's website.

01/01: The District of Columbia began allowing customers direct access to competitive electricity suppliers on January 1, 2001. The PSC established interim

shopping credits ranging from 3.68 to 5.18 cents/kWh. Pepco, the only utility in DC, recently sold its power plants; the shopping credits would be adjusted based

on the sale of the power plants. The PSC also reviewed marketer licensing applications and consumer protection measures.
www.eia.gov/cneaf/electricity/page/restructuring/dc.html 2/2

12/00: Order 11845 unbundled retail rates into separate categories, generation, transmission, and distribution functions. Unbundling allowed customers to compare

prices among electricity suppliers, and helped the Commission to determine "shopping credits" or "price to compare."

09/00: The District of Columbia Public Service Commission issued Order No. 11796 on September 18, 2000 providing the implementation plan for retail choice.

Effective January 1, 2001, all residential and commercial electricity customers in the District of Columbia would be able to choose an electricity supplier. PEPCO

was scheduled to continue to provide delivery services. Order 11796 also included the licensing requirements for alternative electricity suppliers.

01/00: The DC City Council passed legislation (13-284) to allow retail competition. The PSC was also scheduled to review PEPCO’s restructuring settlement. Under

that settlement, commercial and government consumers would have retail direct access and residential consumers would begin a retail access pilot by January

2001.

12/99: According to the PSC's website, Order No. 11576 authorized a 7-percent reduction in rates for residential customers and a 6.5-percent reduction in rates for

commercial customers, to be implemented in three phases. The first rate reduction occurred on January 1, 2000 and reflected the elimination of the Demand-Side

Management surcharge. This represented a 2-percent rate reduction for residential customers and a 3.5-percent rate reduction for commercial customers. The

second rate reduction occurred on July 1, 2000, and it reflected a 1.5 percent across the board base rate reduction for both residential and commercial customers.

The third rate reduction occurred on February 8, 2001. Residential ratepayers received another 3.5-percent rate reduction and commercial ratepayers received

another 1.5-percent reduction. Order No. 11576 also capped rates after all of the rate reductions were implemented. The caps were effective until January 1, 2007 for

low and moderate-income Residential Aid Discount customers; for all other residential and commercial customers, rates were proposed to be capped until January

1, 2005.

03/99: Potomac Electric Power Co stated that it planned to sell its power plants and purchase power contracts. PEPCO intended to become a "wires" company,

concentrating on power delivery, retailing power, cable TV, and Internet services.

02/99: PEPCO filed a plan with the PSC to allow retail competition in its service territory in the District of Columbia and suburban Maryland. The plan would allow

retail choice in DC by 1/01, included an estimate of stranded costs and a method for recovery, proposed unbundled rates, and a rate freeze through 1/05. PEPCO

planed to sell its DC power plants to recoup stranded costs.

12/98: The PSC requested PEPCO to file a restructuring plan with stranded costs and unbundled rates studies.

08/98: A report was issued by the PSC on electric restructuring issues. The report requested a restructuring plan from PEPCO and recommended retail access be

phased-in over 3 years beginning January 2001.

09/97: The PSC issued a notice of inquiry for issues to investigate on retail competition.
www.eia.gov/cneaf/electricity/page/restructuring/florida.html 1/1

ELECTRICITY

OVERVIEW DATA ANALYSIS & PROJECTIONS GLOSSARY › FAQS ›

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Florida Electricity Profile

Florida Energy Profile

Florida Web Sites

Acronyms for the State of Florida

PSC-Florida Public Service Commission

RTO-Regional Transmission Organization

Home > Electricity > State Restructuring > Florida Restructuring

Florida Restructuring not Active

Last Updated: April 2007

12/01: The Florida Energy 2020 Study Commission released its final report to Governor Bush and the Legislature on

December 11, 2001. The report presented the commission's "strategy for assuring that Florida will have an adequate, reliable

and affordable supply of electricity." The commission recommended removing barriers to entry for merchant plants to

facilitate the development of new generation capacity; providing nondiscriminatory access to the transmission system

through the creation of a regional transmission organization (RTO); and fully implementing wholesale competition in six

years. Also recommended was the establishment of a new study commission in 2004 "to assess the status of wholesale

competition and make recommendations as to whether retail competition should be allowed."

03/01: The Energy 2020 Study Commission released an interim report, "Proposal for Restructuring Florida's Wholesale

Market for Electricity." The report made recommendations to the 2001 legislature that would result in the development of a competitive wholesale electricity market

in Florida. Proposals included removing barriers to entry for merchant generation plants, requiring investor-owned load serving utilities to acquire energy resources

through a competitive acquisition process, and allowing utility affiliate companies to assume ownership of existing generation assets as well as build new ones.

09/00: The Energy 2020 Study Commission held its first meeting to begin studying Florida's future energy requirements over the next twenty years. Six technical

advisory committees were created to identify issues, gather and analyze information, and make recommendations on energy policy. The 17-member Study

Commission was charged with studying retail competition and future electric and gas demand in Florida, and was scheduled to present a final report by December

2001.

07/00: The Energy 2020 Study Commission, a study committee created by Governor Bush's Executive Order 2000-127, was announced May 3 when the legislature

failed to address restructuring the electric power industry. The commission was composed of 17 appointed members that were scheduled to begin meeting in

September. The commission would issue its final report to the Governor by December 2001 on their investigation of current and future electric reliability, energy

conservation, environmental impacts, supply and delivery options, electric industry competition, and the financial consequences of restructuring.

04/00: The Supreme Court of Florida reversed the Florida Public Service Commission (PSC) order that approved Duke Energy's proposal for a merchant plant in

New Smyrna. The Court ruled that the PSC did not have the authority to approve the Duke merchant plant under the Florida Electric Power Plant Siting Act of 1973.

01/00: The staff of the House of Representatives Utilities and Communications Committee conducted a review and issued a report, "An Overview of the Electric

Power Industry," in January 2000. The report provided a history and an overview of the current state of the electric power industry in Florida. Neither the legislature

nor the PSC was actively pursuing restructuring for retail access in Florida.

04/99: The PSC approved a merchant plant to be built in New Smyrna by Duke Energy. The combined cycle gas plant had a photovoltaic unit to offer a "green"

pricing option as part of the plant's marketing. The utilities in the State opposed the plant, but the PSC stated that the plant, and other merchant plants proposed to

be built, could help solve the State's reserve margin problem, lack of photovoltaics, and market share concerns.

02/99: The PSC ruled that investor-owned utilities must disclose the sources of generation and purchased power by fuel type to consumers.

08/98: Responding to competitive pressures that can lower electric bills for large consumers, the PSC approved discount rates (up to 20 percent) for new and

expanding businesses. The Florida Alliance for Lower Electric Rates Today opposed the discounts, and proposed state-wide competition for all consumers.
www.eia.gov/cneaf/electricity/page/restructuring/georgia.html 1/1

ELECTRICITY

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Georgia Electricity Profile

Georgia Energy Profile

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Acronyms for the State of Georgia

PSC-Georgia Public Service Commission

Home > Electricity > State Restructuring > Georgia Restructuring

Georgia Restructuring not Active

Last Updated: April 2007

06/98: Georgia Power submitted a 3-year plan to reduce rates by about $300 million. Georgia Power advocated a slow

approach to restructuring.

06/98: Georgia Power estimated that stranded costs would be between $1 and $3 billion. They felt that beginning to pay

these stranded costs down would be a good idea due to eventual competition.

01/98: The Georgia Public Service Commission (PSC) issued a Staff Report on Electric Industry Restructuring (Docket No.

7313, Document No. 20658), which recommended market-based rates, unbundled services, and stranded cost recovery. Docket 7313-U was established for

stakeholders’ comments. A slow approach to restructuring was recommended.

Source: Georgia Public Service Commission

http://w w w .psc.state.ga.us/

07/97: Public workshops were held to address the issues related to restructuring. The results of the public hearings were incorporated in the Staff Report.
www.eia.gov/cneaf/electricity/page/restructuring/hawaii.html 1/1

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Hawaii Electricity Profile

Hawaii Energy Profile

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Acronyms for the State of Hawaii

PUC-Haw aii Public Utilities Commission

Home > Electricity > State Restructuring > Haw aii Restructuring

Hawaii Restructuring not Active

Last Updated: April 2007

2006: The Hawaiian Public Utilities Commission (PUC) held hearings on competitive bidding for new generation and distributive

generation.

Source: Haw aiian Public Utilities Commission

http://w w w .haw aii.gov/budget/LegReports/puc/2006_AnnualReport.pdf

10/03: The Hawaiian PUC opened up a hearing for competitive bidding for new generation.

Source: Haw aiian Public Utilities Commission

http://w w w .haw aii.gov/budget/LegReports/puc/2006_AnnualReport.pdf

04/99: The PUC had an open docket (Docket No. 96-0493) on electric power industry restructuring, but no recent action on this case has occurred.

1997: The PUC began to develop a draft restructuring plan and a formal investigation into the issues.

12/96: The PUC began investigating competition in the electric power industry. A report was expected to be issued by October 1998.
www.eia.gov/cneaf/electricity/page/restructuring/idaho.html 1/1

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Idaho Electricity Profile

Idaho Energy Profile

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Acronyms for the State of Idaho

PUC-Idaho Public Utilities Commission

Home > Electricity > State Restructuring > Idaho Restructuring

Idaho Restructuring not Active

Last Updated: April 2007

01/99: The Legislative Council Committee on Electric Utilities Restructuring issued its final report. The report recommended a

slow approach to retail competition. Idaho was a low cost state for electricity and concerned about prices rising under a

competitive market. The legislature reestablished the study committee.

12/98: The legislative committee concluded that deregulation would boost electric prices in the State, and recommended

against restructuring.

02/98: PUC approved Washington Water Power Company’s pilot program for approximately 6,000 consumers. The pilot would offer customers a portfolio consisting

of four rate options: Traditional Energy Service, Monthly Market Rate, Annual Market Rate, and Standard Offer Service.

01/98: The PUC issued the Electric Costs Report to the Governor and Legislature. The report contained the findings on the unbundled average costs for utilities in

Idaho compared to national averages.

09/97: The PUC hosted technical workshops to discuss public purpose program costs as part of unbundling.

07/97: The PUC began proceedings on electric restructuring.

05/97: The Governor signed an executive order creating the Governor's Council on Hydroelectric and River Resources that would establish guidelines for electric

industry restructuring in Idaho.

04/97: Idaho Power’s pilot program for 900 customers would begin 7/97 and go through 6/99.

03/97: House Bill 399 was enacted, directing the PUC to establish a committee to obtain information on the costs of supplying electricity to consumers. Utilities

were required to unbundle costs of electric service and report to the PUC.
www.eia.gov/cneaf/electricity/page/restructuring/illinois.html 1/3

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Illinois Electricity Profile

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Acronyms for the State of Illinois

CILCO-Central Illinois Light Company

ComEd-Commonw ealth Edison

ICC-Illinois Commerce Commission

MVI-Market Value Index

PPO-Pow er Purchase Option

RTO-Regional Transmission Organization

Home > Electricity > State Restructuring > Illinois Restructuring

Illinois Restructuring Active

Last Updated: September 2009

07/09: The Illinois Commerce Commission's Office of Retail Market Development (ORMD) determined that as of May 31,

2009 more than half the total electric usage of Commonwealth Edison Company and the Ameren Illinois Utilities’ customers

is provided by alternative retail electric suppliers. In its second report to the ICC, the ORMD found that 75 percent of all nonresidential electrical load in the Commonwealth Edison service area is provided by alternative retail electric suppliers and 97

percent of customers with a demand of over one megawatt are taking service from an alternative supplier.

Source: Illinois Commerce Commission

http://w w w .icc.illinois.gov

12/07: The Illinois Commerce Commission approved, with modifications, ComEd’s and Ameren Illinois’ plans for purchasing

a portion of the electricity required to supply residential and small commercial customers beginning in June 2008. The

Commission’s order complies with a new law creating an Illinois Power Agency to oversee the procurement of electricity

beginning next year for residential and small commercial bundled customers.

Source: Illinois Commerce Commission

http://w w w .icc.illinois.gov/

02/07: “The Illinois House is expected to approve a bill establishing a three-year rate freeze for Illinois utilities as soon as

next week, the St. Louis Post-Dispatch reported. Illinois State Rep. Dan Beiser, D-Alton, said the rate relief proposal on the table from Ameren CEO Scott Cisel

would provide no relief for most of the utility's consumers.

Source: Edison Electric Institute, Energy Daily News, February 2, 2007

12/06: The Illinois Commerce Commission (ICC) approved a plan to phase-in Ameren and Commonwealth Edison (ComEd) rate hikes. The planned program would

allow most Ameren customers the option to reduce their rate hike to a maximum of 14 percent for each of the next three years (2007-2009) and defer the additional

amount to a three-year repayment period beginning in 2010. The program would also allow ComEd’s residential customers to reduce their rate hike to a maximum

of 10 percent for each of the next three years (2007-2009) and defer the additional amount to a three-year repayment period beginning in 2010.

Source: Illinois Commerce Commission

http://w w w .icc.illinois.gov/

06/06: Senate Bill 1705 (SB 1705) was enacted to amend the Public Utilities Act. This bill required each electric utility to file a tariff or tariffs which would allow

residential retail customers in the electric utility's service area to elect real-time pricing beginning January 1, 2007.

Source: Illinois General Assembly

http://w w w .ilga.gov/legislation/BillStatus.asp?GA=94&DocTypeID=SB&DocNum=1705&GAID=8&SessionID=50&LegID=19897

02/06: House Bill 5766 (HB 5766) was put forth to amend the Electric Service Customer Choice and Rate Relief Law of 1997 in the Public Utilities Act. This bill

provided that the "mandatory transition period" extend through the date on which the Illinois Commerce Commission had approved declarations of competitive

service for all classes of service offered in the service areas of all electric utilities that, on December 31, 2005, served at least 100,000 customers (now, the

mandatory transition period extends through January 1, 2007). Furthermore, the bill prohibited the Commission from taking certain actions prior to 2010 with respect

to (i) initiating, authorizing, or ordering any change by way of increase or (ii) in approving an application for a merger, imposing a condition requiring any filing for an

increase, decrease, or change in or other review of an electric utility's rates or enforcing such a condition.

Source: Illinois General Assembly

http://w w w .ilga.gov/legislation/BillStatus.asp?DocNum=5766&GAID=8&DocTypeID=HB&LegId=25345&SessionID=50

01/06: The Illinois Commerce Commission approved plans for Ameren and Com Ed to purchase power through a reverse auction. This reverse auction would take

place when the transition period ends, currently slated for 2007. In this way, once the transition period ends, the Illinois Commerce Commission would no longer

regulate the cost to supply power in the state of Illinois.

Source: Illinois Commerce Commission

http://w w w .icc.illinois.gov/

11/02: The Illinois Commerce Commission issued an interim order to discontinue the current rate for Commonwealth Edison’s large customers with 3 Megawatts of

demand or more and charge competitive rates by June 2006. The current rate would not be available to new or returning customers after June 2003. Commonwealth

Edison stated that competitive rates would help spur competition in the State.

08/02: The Illinois Commerce Commission released the Report of Chairman's Summer 2002 Roundtable Discussion Re: Implementation of the Electric Service

Customer Choice and Rate Relief Law of 1997. The report stated that "there is absolutely no competition (or choice) for retail residential electric customers, and it is

unlikely competition (or choice) will be available for these customers for the next several years." The report also said that commercial and industrial retail customers

also had limited access to alternative retail electric suppliers outside of the Commonwealth Edison service territory, and competition in ComEd's service territory had

been reduced with the approval of a new "market value index" (MVI). The calculation of the MVI, the restructuring legislation, the absence of a Regional

Transmission Organization (RTO), transmission constraints and credit risks were just a few of the reasons cited in the report for the lack of competition.

06/02: Senate Bill 2081 (SB 2081) was enacted to extend the utility-rate freeze and mandatory-transition charges, set forth in the restructuring legislation, for an

additional two years so that the competitive market in Illinois could further develop.

Source: Illinois General Assembly

http://w w w .ilga.gov/default.asp
www.eia.gov/cneaf/electricity/page/restructuring/illinois.html 2/3

http://w w w .ilga.gov/default.asp

05/02: As of May 1, 2002, residential customers were allowed to choose their own electric supplier.

04/02: The ICC released its "Assessment of Retail and Wholesale Market Competition in the Illinois Electric Industry in 2001". According to the report, "14 percent

of the load eligible for delivery services" switched to a retail electric supplier, mainly from the AmerenCIPS, Commonwealth Edison and Illinois Power service areas.

Eighteen suppliers were licensed retail electric suppliers in 2001. In regards to the Power Purchase Option, the number of ComEd and Illinois Power delivery

services customers increased from 2000. The PPO "allows customers to receive a rate discount even when no suppliers are serving the market," but this option

ends in 2006.

10/01: The ICC released its "Report to the General Assembly: Experimental Programs Initiated by Electric Utilities Under Section 16-106 of the Electric Service

Customer Choice and Rate Relief Law of 1997 During 2000". The utilities offered two types of experimental programs, specific customer group programs and

reliability programs.

04/01: The ICC issued its "Assessment of Retail and Wholesale Market Competition in the Illinois Electric Industry." The report concluded that only in the ComEd

service territory was switching rates and supplier activity high in 2000. "Approximately 22 percent of eligible customers in the ComEd service territory had switched

to delivery services," and "62 percent of eligible usage had switched from bundled to delivery services." "At the end of 2000, about eight suppliers were active in the

ComEd service territory; only three or four suppliers had acquired a fairly significant number of customers. In the downstate territories, by contrast, few suppliers are

operating."

01/01: Customers in Commonwealth Edison's territory who chose competitive suppliers for electricity (nonresidential at this time) could have also chosen among

competitive suppliers for metering service.

12/00: The Illinois Commerce Commission (ICC) issued an update on the status of competition in the State. The Illinois electric market first opened in October 1999

to a third of non-residential customers. As of January 1, 2001, all commercial and industrial customers were eligible for retail access to competitive suppliers, and

residential customers would become eligible starting in May 1, 2002. The majority of customers who switched to alternative suppliers were in Commonwealth

Edison's territory. About 12 percent of ComEd's eligible customers representing about half of the company's load switched to alternative suppliers. Illinois Power had

6.9 percent of customers switch and Ameren Central Illinois Public Service Company had 6.8 percent. None were recorded for Illinois Light Co. The ICC stated that

a lack of competition could be due to a need for more suppliers, electricity shortages, inefficient transmission system, a lack of uniform interconnection standards,

and the surrounding states lack of restructuring.

05/00: Commonwealth Edison decided to offer retail access to all industrial consumers on June 1, rather than hold a lottery to select a second third of the

estimated 24,000 manufacturing customers. This would give all ComEd's manufacturing customers retail access 4 months earlier than planned. As planned, all

remaining non-residential customers would gain retail access by December 31, 2000, and all residential consumers by May 1, 2002.

01/00: The ICC issued a report, "Assessment of Competition in the Illinois Electric Industry Three Months Following the Initiation of Restructuring." The report

summarized the status of consumer choice in the State, finding that more consumers had switched suppliers in Commonwealth Edison's territory than any other

Illinois utility, likely because ComEd had comparatively high rates for the State.

01/00: ComEd completed the sale of its fossil-fueled plants to MidWest Generation, a subsidiary of Edison International. The $4.8 billion sale resulted in a $1.5-

billion gain after taxes and sales related obligations. The gain would allow recovery of nuclear-related regulatory assets, as provided under Illinois restructuring

legislation, and provide funding for reliability improvements to ComEd’s transmission and distribution systems. The sale included 6 coal-fired plants representing

5,645 MW of capacity.

11/99: Direct access began in October 1999 for many commercial and industrial consumers. Loads over 4 MW and multi-site (at least 10 sites) customers with

aggregate loads over 9.5 MW were automatically included in the first phase to implement retail access. A lottery was held at each utility to choose consumers to

allow about one-third of the remainder of commercial and industrial load to participate in the first phase. Media sources report that customers in Commonwealth

Edison's service territory were realizing 5 to 15 percent savings from competitive companies.

08/99: Ameren and Cilco both held lotteries to choose the one-third of eligible customers that would receive retail access. All customers over 4 MW are

automatically eligible, and one-third on the load for non-residential customers would be available to competitive suppliers beginning October 1, 1999. Lotteries were

held because more than a third of the customers expressed the desire to be included in this first phase of retail access in Illinois. Those customers not selected in

the lotteries would have retail choice in 2000. Residential customers would have retail choice in May 2002.

07/99: ComEd held three lotteries (one for single-site consumers; one for commercial consumers with at least 10 sites and an aggregated demand of at least 9.5

MW; and one for non-residential consumers with 2 or more sites. Customers with loads 4 MW and more are automatically included) to choose the 1/3 of consumers

who would have retail access by October. Over half of the commercial and industrial consumers in ComEd's territory were registered for retail choice. ComEd

announced the resultant energy freed for competition would be over 30 billion kWh. In Illinois Power's service territory, all commercial and industrial customers who

registered would begin retail access October 1st. Only about 75 percent of those eligible in Illinois' territory registered.

07/99: Senate Bill 24 was enacted to amend the restructuring law. The amendment moved up the transition to customer choice. The first third of commercial and

industrial consumers would have retail access by October 1, 1999, the second third by June 1, 2000, and the final third by October 1, 2000. Residential customers

would receive a 5 percent rate reduction by October 1, 2001, seven months earlier. The rate cap for utilities was increased by 2 percent, cogeneration was

promoted, and ComEd was required to allocate $250 million to a special environmental initiatives and energy efficiency fund.

04/99: The sign up process for eligibility to choose began for each utility. Loads over 4 MW and multi-site (at least 10 sites) customers with aggregate loads over

9.5 MW were automatically included. Interested consumers would sign up and a lottery would be held to determine the 1/3 of nonresidential load (excluding the 4

MW and 9.5 MW aggregated loads) that would have retail choice by October 1999. The remainder of commercial and industrial consumers not chosen in the lottery

were proposed to get retail choice in December 2000, and residential consumers would then have retail access by May 1, 2002.

03/99: ComEd's residential customers saved approximately $170 million as a result of the 15-percent rate reduction on August 1, 1998.

11/98: Central Illinois Light Company (CILCO) requested that the ICC terminate its pilot program for retail choice, "Power Quest." CILCO said that the program

served the purpose of showing that retail choice works in Illinois.

10/98: As required by the restructuring law in Illinois, a 15-percent rate reduction went into effect in August 1998.

08/98: The phase-in of rate cuts took effect. The State's largest utilities, Illinova and Commonwealth Edison, cut rates 15 percent and another 5-percent reduction

was due May 2002. Smaller utilities would phase-in 5-percent reductions by May 2002.

06/98: The ICC issued a ruling that prohibited utility affiliates from exploiting the name, reputation, or logo of the utility in advertising or marketing campaigns. The

rule was intended to protect ratepayers from cross-subsidization of utility affiliates.

05/98: The ICC approved Commonwealth Edison's plan to offer nonresidential customers hourly rates under its "Hourly Energy Pricing" program.
www.eia.gov/cneaf/electricity/page/restructuring/illinois.html 3/3

05/98: The ICC approved Commonwealth Edison's plan to offer nonresidential customers hourly rates under its "Hourly Energy Pricing" program.

12/97: House Bill 362, "The Electric Service Customer Choice and Rate Relief Act of 1997," was enacted. The bill proposed rate cuts for ComEd and Illinois Power

effective August 1998. The law also proposed some commercial and industrial customers choice by October 1999, and all customers, including residential, choice

for their generation supplier by May 2002. Transition charges would be collected through 2006. Most residential customers would receive a 15 percent rate reduction

by August 1998, and another 5 percent reduction in May 2002.

02/96: CILCO and IL Power conducted retail wheeling pilot programs in 1995-1996. IL pilot included only large customers; CILCO pilot included all classes of

customers.
www.eia.gov/cneaf/electricity/page/restructuring/indiana.html 1/1

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11/00: Indianapolis Power & Light extended an experimental pricing program for an additional two-plus years. The pricing option

program initiated in 1998 was to expire on October 18, 2001, but was extended to December 31, 2003.

07/00: The State Utility Forecasting Group, which was charged by the Indiana General Assembly to investigate the electricity supply, predicted that over the next

15 years, competition could lower prices in the short term, raise them in the medium term, and level off in the long term. The State's investor-owned utilities,

American Electric Power and Northern Indiana Public Service Company, were working on proposals to submit to the 2001 General Assembly that would restructure

the industry to allow retail competition.

07/98: Consumers of Indianapolis Power & Light were offered 3 billing options. Consumers could choose a fixed rate, a fixed monthly bill based on last years

average bill, or a "green power" rate under an alternative pricing plan approved in March by the Indiana Utilities Regulatory Commission.

05/97: Senate Bill 427 was enacted and created a legislative study committee that would meet through November on electric restructuring issues. A report was due

in November 1997.
www.eia.gov/cneaf/electricity/page/restructuring/iowa.html 1/1

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IUB-Iow a Utilities Board

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Last Updated: September 2008

05/08: The three-member Iowa Utilities Board today voted unanimously that it is presently not in the public interest for any of the

five cities of Everly, Kalona, Rolfe, Terril, and Wellman to replace Interstate Power and Light Company as the provider of electric

service in their respective communities. The Board raised concerns about utility operation and maintenance costs as well as

future energy costs if certificates for municipal electric service were granted. A lack of evidence demonstrating that energy

efficiency planning and programming would be maintained at least at its current level in those communities was also cited.

Source: Iow a Utilities Board

http://w w w .state.ia.us/iub/

09/07: The Iowa Utilities Board allowed Interstate Power and Light Company (IPL) to sell its electric transmission assets to ITC, which is an independent

transmission company and a subsidiary of ITC Midwest. Board analysis found that any potential impacts on the residential electric rates of customers should be

minimal to the extent that any cost increases will be mitigated by IPL’s commitment to share benefits of the sale with its customers through refunds over an eightyear period.

Source: Iow a Utilities Board

http://w w w .state.ia.us/iub/

04/01: The Iowa Utilities Board (IUB) issued an order closing Docket No. NOI-95- 1, "Inquiry Into Emerging Competition in the Electric Industry" on April 17, 2001.

04/00: Proposed restructuring legislation died in Iowa as the legislative session ended in April without further action on Senate File 2361 or House File 2530.

06/99: The Deregulation and Restructuring of the Electric Utility Industry Study Committee released its final report. The committee was established by the

Legislative Council. The Committee was authorized to conduct five meetings during the 1998 Interim, but made no formal recommendations.

02/99: The IUB announced MidAmerican would offer a 2-year pilot program in Council Bluffs. An education program was beginning and customer sign-up for the

pilot was scheduled to begin 4/99, and delivery of power by 5/99.

11/98: MidAmerican Energy and the IUB chose the community of Council Bluffs to participate in MidAmerican’s pilot program. The program would allow about

15,000 residential and 2,000 small business consumers to have retail choice.

08/98: IUB approved MidAmerican’s pilot, the first major electric choice pilot program in the State which expected to include about 15 large consumers. The

following residential pilot, proposed in 5/98, was yet to be approved.

05/98: MidAmerican filed a proposal with the IUB for a pilot program to allow 15,000 residential and 2,000 small commercial customers (making up approximately 3

percent of the small commercial customers) to choose their power supplier competitively.

05/98: Senate File 2416 was signed by the Governor. It would replace property taxes on electric utilities with excise taxes imposed on generation, transmission

and delivery of electricity. The changes in tax law were to address concerns that under deregulation, non-Iowa suppliers would have a competitive advantage over

Iowa-based companies that were paying property taxes.

09/97: MidAmerican Energy proposed a wheeling pilot for commercial and industrial customers for 60 MW of load in first year and an additional 15 MW each

following year.

09/97: The IUB adopted its "Action Plan to Develop a Competitive Model for the Electric Industry in Iowa." The plan included a statewide pilot program for residential

and commercial customers (about 3 percent of load) over 2 years.

05/96: The IUB adopted principles for restructuring the electric power industry.

02/96: The IUB appointed a 28 member Advisory Group to study restructuring.
www.eia.gov/cneaf/electricity/page/restructuring/kansas.html 1/1

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12/06: The Kansas Corporation Commission approved a Stipulation and Agreement granting the Kansas City Power & Light

Company (KCPL) a $29 million rate increase, which equates to an overall revenue increase of 7.4 percent. The Agreement was

reached through a collaborative process and agreed to by KCPL, Commission Staff, Citizen Utility Ratepayers Board, International Brotherhood of Electrical

Workers, Local Unions No. 412, 1464, and 1613, and Wal-Mart. Also, the Midwest Utility Users Group, representing a group of large volume and industrial

customers, filed a formal statement in support of the Agreement.

Source: Kansas Cooperation Commission

http://w w w .kcc.state.ks.us/

12/05: The Kansas Corporation Commission issued an order granting Westar an overall annual rate increase of approximately $3 million. This order will increase Westar’s northern region rates by approximately 4.7 percent or $24.2 million, and decrease its southern region rates by approximately 4.2 percent or $21.2 million.

Source: Kansas Cooperation Commission

http://w w w .kcc.state.ks.us/

05/05: Westar Energy Inc. (Westar) filed an application with the Kansas Corporation Commission (KCC) requesting a comprehensive review of its electric rates

which included an overall annual revenue increase of approximately $84.1 million. This represented an increase of 9 percent or $47.8 million for its northern region,

and a 6 percent or $36.3 million increase in rates for its southern region customers.

Source: Kansas Cooperation Commission

http://w w w .kcc.state.ks.us/

05/99: Although several bills were introduced in the 1999 legislative session to restructure the industry, no electric restructuring measures were acted on when the

session adjourned May 2.

04/98: The Task Force's restructuring bill was not acted on in the 1998 session.

02/98: The Retail Wheeling Task Force's restructuring bill was introduced in legislature. Also being considered was a bill to establish a joint committee on taxation

of public utilities and a bill to require utilities to disclose generation, transmission, and distribution charges and sales, use, and franchise taxes and any fees relating

to the retail sale of electricity.

01/98: The Retail Wheeling Task Force issued a final report and draft restructuring bill that calls for retail access after July 2001.

09/97: The National Regulatory Research Institute released its "Assessment of Retail Competition in Kansas' Electric Power Industry," a report done at the request

of the Kansas Corporation Commission.

04/96: The Retail Wheeling Task Force was established with passage of House Bill 2600. The bill prohibits the Commission from authorizing retail competition prior

to July 1999, and froze retail rates for 3 years. A final report with a model for legislation was scheduled to be due before January 1998.
www.eia.gov/cneaf/electricity/page/restructuring/kentucky.html 1/1

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03/04: Senate Bill 118 (SB 118) was enacted so that electric utilities within the state of Kentucky could sell wholesale

power to municipal utilities with the consent of the Kentucky Public Utilities Commission.

Source: Kentucky Legislature

http://w w w .lrc.ky.gov/record/04rs/SB118.htm

08/00: The Kentucky Special Task Force on Electricity Restructuring issued its final report on August 10, 2000 to the

Governor and the Legislative Research Commission. The report incorporated the final report approved by the Task Force on

December 13, 1999, and the four interim reports written by Resource Data International (RDI). According to the report, "there (was) no compelling reason at (the)

time for Kentucky to move quickly to restructure."

04/00: Kentucky's 2000 General Assembly reauthorized the Task Force on Electricity Restructuring in Senate Joint Resolution 107 (SJR 107) in April 2000 for the

purposes of monitoring developments in electric power restructuring, maintaining knowledge of the issues, studying within the context of low-income assistance,

and making recommendations to the 2002 General Assembly. The task force was scheduled to report to the Legislative Research Commission and the Governor no

later than November 15, 2001.

01/00: The Task Force on Electricity Restructuring issued its final report on December 13, 1999. The report recommended that no action be taken in 2000 to

restructure the industry. Reasons included Kentucky's low rates, which may see greater variability under restructuring.

06/99: A study produced by Resource Data International for the Special Task Force on Electricity Deregulation concluded that retail prices in Kentucky could rise

under competition. Kentucky had the third lowest retail prices in the Nation. The Task Force on Electric Restructuring continued to meet and discuss issues. The

task force held discussions on reliability of service, consumer protections, unregulated utility businesses, and a review of other States' restructuring activities.

04/99: The Public Service Commission issued an order to reduce rates for Kentucky Utility and Louisville Gas and Electric subsidiaries. Under a performancebased ratemaking approach, rates would be reduced $52 million over 5 years. While not restructuring for competition, the order provided efficiency incentives for

utilities.

04/98: House Joint Resolution 95 (HJR 95) passed legislation and was signed by the Governor to create the Kentucky Task Force on Electric Restructuring. A

report was scheduled to be due November 1999.
www.eia.gov/cneaf/electricity/page/restructuring/louisiana.html 1/1

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04/05: The Louisiana Public Service Commission recommended that all industrial customers with loads greater than five

megawatts be given the choice to select their power provider.

Source: Louisiana Public Service Commission

http://w w w .lpsc.org/default.asp

04/02: The Louisiana Public Service Commission (PSC) issued a restructuring collaborative procedural schedule. The study

groups had to submit their final information to the commission no later than October 31, 2002 because the commission

planned to release its monitoring report on November 30, 2002. The report would address transition cost estimates, the definition of a large industrial customer,

methods to encourage construction of capacity, and affiliate rules.

12/01: The Louisiana Public Service Commission issued two orders in regards to analysis of competitive implications. The first order dealt with cogeneration and

plant construction. The second order declined to implement retail access and the recommendations of the Staff’s report. The PSC would continue to study

restructuring and retail access as well as monitor its neighbors and federal restructuring legislation.

07/01: The staff of the Louisiana PSC issued its final report, Final Response of the Commission Staff to Comments on Proposed Competitive Transition Plan, to the

PSC. The report recommended some changes to the transition plan issued in January including allowing open access to competitive service providers to only large

industrial customers with loads averaging 5 MW or more rather than the original 2 MW load. Even though the PSC ruled two years ago that open access was not in

the State's best interest, a study of the issue continued due to concerns about economic development. The report recommends another study due in 2005 to

determine if competition would benefit all classes of customers. However, the PSC did not take any action on this latest report at their most recent meeting, but

may take it up in its September meeting.

01/01: The PSC issued a draft restructuring plan that would allow large industrial customers retail choice starting in January 2003. Utilities would not be required to

divest their generation assets needed to serve their customer demands.

05/99: The PSC staff presented a report on restructuring recommending a slow approach. The report raised skepticism on the benefits to residential consumers,

citing California's retail market where they said too few electricity suppliers existed to have true competition. The report stated that Louisiana had lower than average

electric rates, and competition could increase prices, not lower them. The report recommended no action toward retail competition be taken at that time, but

"reluctantly" submitted a draft restructuring plan in case the PSC decided to go ahead. In Louisiana, the PSC could have ordered retail competition without

legislative action.

04/99: The PSC issued an order setting up a schedule through August 2000 to study the issues: consumer education; stranded costs; regional planning and

reliability; market power; rate unbundling; functional unbundling; independent system operators; and transition mechanisms.

03/99: The PSC issued an order stating that Commission "defers making a public interest determination until such time that a Louisiana-specific transition to

competition plan has been fully developed. The Staff, outside consultants and counsel are directed to recommend a plan for implementation of retail electric

generation competition for consideration by the Commission on or before January 1, 2001."

02/99: A draft report issued by the PSC advised not to go ahead with deregulation due to concerns that residential consumers could experience higher prices. The

report also said that, however, if deregulation does go forward, it should allow large industrials to shop for power while limiting rates for small consumers. Louisiana

consumers enjoyed rates that were less than the national average.

01/99: Entergy Gulf States and Entergy Louisiana submitted restructuring proposals to the PSC. The PSC Chairman expected the PSC to rule that restructuring

was in the best interest of the State, but expected Louisiana to take a slow approach to retail access.

08/98: The PSC conducted hearings on stranded costs. Participants included Central Louisiana Electric Company, Enron, and Gulf State Utilities.

03/98: The PSC committee and the legislative committee met on March 16, 1998 to discuss the tax implications of deregulation.

12/97: The PSC voted to accept a staff report recommending further study on issues surrounding electricity restructuring. The PSC was scheduled to develop draft

legislation for the 1999 session.

06/97: Resolution 150 created a study committee on electric power restructuring with reports on various issues due in 1998.

05/95: The PSC opened Docket U-21453 on whether electric industry restructuring was in the public interest.
www.eia.gov/cneaf/electricity/page/restructuring/maine.html 1/2

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BHE-Bangor Hydro-Electric Company

CMP-Central Maine Pow er Company

ISO-Independent System Operator

PUC-Maine Public Utilities Commission

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07/08: The Maine Public Utilities Commission accepted bids on new standard offer energy prices for medium and large

commercial and industrial customers of Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE). The

prices are effective September 1, 2008, and extend for six months. The new standard offer prices apply only to customers that

have not made their own electricity supply arrangements. For CMP’s medium business customers, standard offer prices will

increase by 23%, and for CMP’s large business customers, standard offer prices will increase by 32%. For BHE’s medium

business customers prices will increase by 21% and for large business customers, prices will increase by just under 20%.

Source: Maine Public Utilities Commission

http://w w w .maine.gov/mpuc/

01/08: The Maine PUC (PUC) today accepted bids on new standard offer energy prices for residential and small business

customers of Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE). The bids are for 33% of the

load of these customers, and when combined with prices secured in prior years, standard offer prices, effective March 1, 2008,

will be about 9.97 cents per kilowatt hour for CMP customers, and about 10.05 cents cents/kWh for BHE customers.

Source: Maine Public Utilities Commission

http://w w w .maine.gov/mpuc/

01/07: The Maine Public Utilities Commission accepted bids on new standard offer energy rates for residential and small business customers of Central Maine

Power Company (CMP) and Bangor Hydro-Electric Company (BHE). The rates, effective March 1, 2007, for CMP customers, were about 8.8 cents/kWh, and for

BHE customers, about 9.0 cents/kWh. When combined with the CMP and BHE delivery charges, the rates would increase overall by about 1.7% and 2.7% for

BHE and CMP customers, respectively.

Source: Maine Public Utilities Commission

http://w w w .maine.gov/tools/w hatsnew /attach.php?id=28423&an=1

02/06: The New England Independent System Operator (New England ISO) reached a settlement agreement with state regulators, consumer groups, and energy

companies over a multi-billion dollar rate hike proposed for the region. The state of Maine did not sign the agreement and the Public Utilities Commission stated

that it was considering withdrawing from the New England ISO.

Source: Maine Public Utilities Commission

http://w w w .maine.gov/tools/w hatsnew /attach.php?id=12503&an=1

12/04: Auction results showed almost a thirty percent increase in the electric standard offer price for residential and small commercial customers. The Public

Utilities Commission attributed the sharp rise in auction results to the significantly higher costs associated with producing electricity in the New England region.

Source: Maine Public Utilities Commission

http://w w w .maine.gov/tools/w hatsnew /attach.php?id=4792&an=1

12/02: The Maine Public Utilities Commission (PUC) released a report, Standard Offer Study and Recommendation Regarding Service after March 1, 2005, to the

state Legislature. In the report, the PUC recommended standard offer service remain available after March 1, 2005, under certain conditions. For medium and large

nonresidential customers, the report proposed that standard offer service would continue only as a “last resort” service. In the small commercial and residential

sectors, where competitive retail markets for electricity were not as fully developed as the large customer sectors, current standard offer service would continue to

be offered to customers who do not choose an alternative energy supplier. Based on public interest, the PUC also recommended a “green” supply option for

residential and small commercial customers.

03/02: New standard offer rates for customers in the Central Main Power Company, Bangor Hydro Electric Company, and Maine Public Service Company service

territories went into effect on March 1, 2002. According to a PUC press release, medium and large commercial and industrial CMP and Bangor Hydro customers "

(would) see the largest overall price decreases."

03/01: Upon termination of the bid process, the PUC ordered Central Maine Power to provide standard offer service from March 2001 to March 2002 for medium and

large nonresidential customers and set the standard offer rates for these classes of customers. The PUC approved CMP contracts with wholesale suppliers to

supply the power for the standard offer customers, and approved nonresidential standard offer rates ranging from 5.6 cents for off peak non summer to 14.6 cents for

on peak summer.

10/00: The Maine Public Utilities Commission (PUC) approved a 33 percent rate increase for the 107,000 customers who use Bangor Hydro's standard offer. The

rate increase was requested by Bangor Hydro to pay for rising oil and natural gas costs. The average residential customer would pay about 6.1 cents/kWh

compared to the 4.6 cents/kWh they were paying before the increase. The Commission said that it is possible that another increase would be needed if fuel costs

continued to increase, but that increase would most likely be deferred until after winter.

10/00: The PUC issued a request for bids to provide service for Bangor Hydro, Maine Public Service, and Central Maine Power standard offer customers. The

bidding process was revised from last year's, streamlining the process and giving bidders more flexibility in hopes of attracting better offers.

09/00: Statistics from the Maine Public Utilities Commission (PUC) showed that 26 percent of all electricity delivered by the State's three major utilities was being

purchased from alternative suppliers. However, industrial customers are purchasing the bulk of that load. In contrast, 6 percent of residential and small commercial

customers had switched providers, bringing the total number of residential and small commercial customers served by competitive providers to about 1,500
www.eia.gov/cneaf/electricity/page/restructuring/maine.html 2/2

customers had switched providers, bringing the total number of residential and small commercial customers served by competitive providers to about 1,500

customers.

08/00: The PUC approved a transmission/distribution rate scheme for restructuring submitted by Maine Public Service Company and the Maine Office of the Public

Advocate. The order separated MPS's overall T&D revenue requirements into a transmission component (T) under FERC jurisdiction and a distribution component

(D) under PUC jurisdiction.

07/00: The PUC increased standard offer rates for Bangor-Hydro customers to 4.6 cents/kWh.

01/00: In 1999, the PUC finalized the rules necessary to implement electric restructuring by March 1, 2000. Companies were selected to provide standard offer

service at reasonable prices for the majority of electricity consumers in Maine. Principles were established for setting rates, including stranded costs, for distribution

and transmission utilities in the State. The three IOU utilities sold their generation assets.

10/99: The PUC rejected the bids received for standard offer service for Central Maine Power and Bangor Hydro territories, saying they were too high. Using three

service bids that were conditionally approved for Maine Public Service for a new ceiling, and revising some technical rules, a second round of bidding would be

scheduled for November 8. In this way, the standard offer providers were scheduled to be selected by December 1.

05/99: The PUC issued a schedule for suppliers to offer standard service when retail competition was scheduled to begin in March 2000. Standard service price

would be set through a bid process, rather than a predetermined price, as in other states.

01/99: Maine consumers were scheduled to begin seeing itemized bills in January 1999 that separate the costs of power generation from delivery. The restructuring

law requires unbundled billing by January 1, 1999.

12/98: The PUC was scheduled to begin a consumer education program in January 1999 to prepare the public for retail access and unbundled billing.

11/98: Central Maine Power's sale of its non-nuclear generating assets to FPL Group was approved by regulators.

10/98: PP&L Global reached an agreement with Bangor Hydro to purchase 100 percent of it hydro plants and its interest in an oil-fired plant, totaling 89.2 MW for

$89 million. Approval by the Maine PUC and FERC were still to be determined.

05/98: Bangor Hydro announced the schedule for bids on its divestiture of generation assets. Final bids were due 8/7/98. Maine Yankee nuclear plant would also be

offered for sale.

05/98: The PUC approved Central Maine Power's corporate reorganization into a holding company, CMP Group, Inc., and 10 subsidiaries as it prepared for retail

competition. Central Maine Power would remain the core business group offering distribution and transmission services. A new unit, Maine Power, would market

electricity.

05/98: The PUC adopted a requirement that beginning January 1, 1999, utilities must issue bills showing "unbundled" charges for generation and distribution, rules

for consumer education, and standard offer service for all consumers when competition was scheduled to begin on March 1, 2000.

04/98: Central Maine Power's plan to divest its hydro, fossil-fuel, and biomass generation was approved by the PUC.

05/97: Legislation Docket 1804 was enacted. The law would allow retail competition by March 2000 and, for large investor-owned utilities, featured a market share

cap of 33 percent in old service areas, a requirement for divestiture of generation assets by March 2000, and the nation's most aggressive renewables portfolio,

requiring 30 percent of generation to be from renewable energy sources (including hydroelectric).

12/96: The PUC issued a plan requiring utility functional unbundling, divestiture of generation assets by March 2000, and retail competition by 2000.
www.eia.gov/cneaf/electricity/page/restructuring/maryland.html 1/6

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Maryland Electricity Profile

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Acronyms for the State of Maryland

BGE-Baltimore Gas and Electric

CTC-Competitive Transition Charges

MAPSA-Mid-Atlantic Pow er Supply Association

PEPCO-Potomac Electric Pow er Company

PSC-Maryland Public Service Commission

PURPA-Public Utility Regulatory Policies Act

SOS-Standard Offer Service

Home > Electricity > State Restructuring > Maryland Restructuring

Maryland Restructuring Active

Last Updated: January 2010

01/10: Governor Martin O’Malley of Maryland stated that he would not submit legislation to re-regulate energy markets

in the upcoming legislative session. Governor O’Malley stated that he would instead rely on the Public Service

Commission to use existing authority to build new power generation as needed.

Source: Office of Governor Martin O’Malley

http://w w w .governor.maryland.gov/

04/09: The House Economic Matters Committee in the Maryland House of Representatives voted nearly unanimously

to kill Governor Martin O’Malley’s electric re-regulation bill. The governor stated that he plans to resubmit the bill to the

legislature sometime in 2010.

Source: Maryland Energy Administration

http://energy.maryland.gov/

02/09: The Maryland State Finance Committee introduced Senate Bill 795, titled “the Maryland Electricity Reregulation

and Energy Independence Act of 2009.” The bill stated that competitive retail electric markets have not developed as

envisioned by the state’s nearly 10-year old electricity industry restructuring law. Furthermore, Governor Martin

O’Malley issued a media release stating that deregulation had failed in the state of Maryland and that the Governor and

his administration would support reregulating Maryland’s electricity markets.

Source: Maryland Energy Administration

http://energy.maryland.gov/

12/08: The Maryland Public Service Commission issued a report that said the State should not try to buy back power plants that were sold when the State

deregulated its electricity markets. Instead it should consider new laws to protect consumers. The report was ordered by the Maryland State General Assembly in

2007 and recommended that the General Assembly consider placing future power supplies under some form of regulation to stabilize prices and to guarantee that

the State's electricity needs are met. The report also suggests that the Public Service Commission and State legislature work together to partially re-regulate

electricity rates by shifting the jurisdiction of future power plants to the State. Maryland's still-regulated utilities could be required to build new plants or enter

contracts for regulated electricity. The commission said it plans to study those options next year.

Source: The Washington Post Company

http://w w w .w ashingtonpost.com

05/07: Senate Bill 400 was passed by the Maryland General Assembly. The bill requested that the Public Service Commission “reevaluate the general regulatory

structure, agreements, orders, and other prior actions of the Public Service Commission under the 1999 Maryland Customer Choice and Competition Act. The newly

passed bill also requested the “determination of and allowances for stranded costs” and to “conduct hearings” as part of its evaluation of the 1999 Settlement.

Source: Maryland Public Service Commission

http://w w w .psc.state.md.us/

11/06: “On November 8, 2006, the Public Service Commission (“Commission”) issued Order No. 81102, establishing, inter alia, a procurement program for Standard

Offer Service (“SOS”) for Residential and Type I commercial customers. The program applied to the investor-owned electric public service companies for the

provision of SOS which was scheduled to begin on June 1, 2007. In Order No. 81102, the Commission also stated that bid week schedules for SOS procurement

would include a public hearing for the purpose of receiving a briefing from the Commission’s SOS consultant and the Commission’s Technical Staff (“Staff”)

concerning the conduct and results of the SOS solicitation.”

Source: Maryland Public Service Commission

http://w ebapp.psc.state.md.us/Intranet/Casenum/New Index3_VOpenFile.cfm?ServerFilePath=C:\CaseNum\9000-9099\9064\107.pdf

10/06: Constellation Energy and FPL Group terminated plans to merge.

Source: Constellation Energy

http://phx.corporate-ir.net/phoenix.zhtml?c=112182&p=irol-new sArticle&ID=921050&highlight=

09/06: Maryland Court of Appeals overturned legislature’s efforts to depose the Public Service Commission (PSC). However, the court stated that the legislature

was in it rights to remake the PSC and did have authority over appointing members.

Source: Maryland Court of Appeals

http://w w w .courts.state.md.us/opinions/coa/2006/140a05.pdf

07/06: The Maryland General Assembly planned to limit the 72-percent rise in BGE electricity prices by placing a cap on price increases of 15-percent and to defer

the BGE from collecting the difference for 11 months.

Source: Department of Legislative Services, Office of Policy Analysis

“The Road to Electric Restructuring in Maryland, December 2006 (hard copy).

07/06: The rate freeze in the BGE service territory expired. The market price obtained through the Standard Offer Service competitive auction process in the BGE

service territory was expected to increase 72 percent.

Source: State of Maryland Public Service Commission

http://w w w .psc.state.md.us/psc/Info/brochures/BGE_MitigationPlanFactSheet.pdf

07/06: The Maryland General Assembly planned to limit the 72-percent rise in BGE electricity prices by placing a cap on price increases of 15 and to defer the
www.eia.gov/cneaf/electricity/page/restructuring/maryland.html 2/6

BGE from collecting the difference for 11 months. PEPCO and Delmarva customers were offered a similar arrangement with the opportunity to pay back deferred

expenses over 18 months.

Source: Department of Legislative Services, Office of Policy Analysis

“The Road to Electric Restructuring in Maryland, December 2006 (hard copy).

06/06 Senate Bill-1 and House Bill-1 vetoes were overwritten.

06/06: Senate Bill-1 was vetoed by Governor Ehrlich.

Source: Maryland General Assembly

http://mlis.state.md.us/2006s1/billfile/sb0001.htm

06/06: Senate Bill 1 (SB1) and House Bill 1 (HB 1) were introduced in the Maryland General Assembly. SB1 and HB 1 were intended to implement the following

goals: “Limiting the increase in electricity rates in a specified service territory for a specified period; requiring specified electric companies to obtain electricity

supply for extended standard offer service to specified customers in specified manners; authorizing the Public Service Commission (PSC) to take specified actions

concerning competitive auctions and implementation of electricity rates; altering the criteria for appointment to the PSC and the method of appointment of the

People's Counsel; etc.” SB 1 also proposed eliminating the People’s Council.

Source: Maryland General Assembly

http://mlis.state.md.us/2006s1/billfile/SB0001.htm

http://mlis.state.md.us/2006s1/billfile/hb0001.htm

06/06: Maryland Public Service Commission instructed BG&E to implement Order No. 80764.

Source: Maryland Office of the People’s Council

http://w w w .opc.state.md.us/c/202/Request-for-Rehearing-Commission-Order-Case-No.-9052

06/06: Maryland state government held a special session to deal with electricity price crisis. Governor Ehrlich suggested following a rate stabilization plan with

utilities allowing “customers to limit the rate increase exposure to 15% this year, 25% next year, and then market level in January 2008. Opting in to this plan

would allow customers to repay the deferred charges interest-free.”

Source: State of Maryland, Office of the Governor

http://w w w .gov.state.md.us/

05/06: Baltimore city Circuit Court issued an order “vacating, reversing, and remanding Order No. 80764.

Source: Maryland Office of the People’s Council

http://w w w .opc.state.md.us/c/202/Request-for-Rehearing-Commission-Order-Case-No.-9052

05/06: Maryland Office of the People’s Council restated its opinion released in March 2006:

“The current process for procuring power, as approved by the previous Public Service Commission and agreed to by the utilities and the former People’s Counsel,

requires the utilities to buy power using a particular mix of one, two, and three year contracts. This method is not optimal for customer pricing...In our complaint,

we argue that the current method of procuring electricity must be changed to encourage:

1. competitive energy procurement solicitations for contracts covering varying lengths of time;

2. the purchase of existing plants or construction of new generating facilities by our local utilities;

3. long-term contracts for various electricity products, including output from a particular generating plant or generating facilities;

4. new utility risk mitigation strategies, including hedging in the electricity and natural gas markets;

5. diversity of suppliers;

6. diversity in the types of power-generating plants supplying our energy needs;

7. conservation and load management approaches; and

8. creation of a state power authority that could purchase an ownership interest in generating plants with ratepayer or taxpayer funds.”

Source: Maryland Office of the People’s Council

http://w w w .opc.state.md.us/c/190/ELECTRIC-DEREGULATION:--LONG-TERM-SOLUTIONS%20AND%20CHANGE

05/06: Maryland Office of the People’s Council recommended eliminating the interest payment.

Source: Maryland Office of the People’s Council

http://w w w .opc.state.md.us/c/202/Request-for-Rehearing-Commission-Order-Case-No.-9052

04/06: Constellation Energy announced that: “its subsidiary, Baltimore Gas and Electric Company, has filed a comprehensive rate stabilization plan with the

Maryland Public Service Commission (PSC) that would allow BGE's residential electric customers to reduce and defer the pending July 1 rate increase...The rate

stabilization plan is optional; it provides the time for customers to plan for the inevitable impact of a global energy crisis." If approved by the PSC, the plan would

allow BGE customers to select or "opt-in" to a rate stabilization program that would reduce the initial increase and spread out the remainder. Those who opt-in

would see a rate increase of 19.4 percent July 1.”

Source: Constellation Energy

http://phx.corporate-ir.net/phoenix.zhtml?c=112182&p=irol-new sArticle&ID=845637&highlight=

04/06: The Public Service Commission of Maryland released a Rate Stabilization Plan to help Pepco and Delmarva Power and Light Company customers more

gradually adjust to upcoming electric bill increases. The standard offer service prices resulting from this year’s procurement process would go into effect on June 1,

2006 for Pepco and Delmarva residential customers. Based on the competitive bidding process, for Pepco residential customers, a typical bill would increase by

approximately 39%, or $468 annually at that time. For residential customers of Delmarva, a typical electric bill on an annual basis would increase approximately

35% or $464 annually.

Source: Maryland Public Utilities Commission

http://w w w .psc.state.md.us/psc/AboutUs/Press/Pepco_DelmarvaRateStablizationPlan.pdf

04/06: Public Service Commission issued Order No. 80764 which modified Order 80638 “to make it an opt-in plan, to treat interest as a deferred asset, and to

extend the plan to three and four years.”

Source: Maryland Office of the People’s Council

http://w w w .opc.state.md.us/c/202/Request-for-Rehearing-Commission-Order-Case-No.-9052

03/06: On March 6, 2006, the Commission issued Order No. 80638 (the “March 6 Order”), “which adopted a payment plan option for Baltimore Gas and Electric

Company (“BGE”) residential customers. The plan adopted by the March 6 Order is an opt-out plan, includes interest charges at five percent, and is two or three

years in duration.”

Source: Maryland Office of the People’s Council

http://w w w .opc.state.md.us/c/202/Request-for-Rehearing-Commission-Order-Case-No.-9052

03/06: Senate Bill 1102 (SB 1102) was put forward and is a parallel piece of legislation to House Bill 1713 in the Maryland Senate. SB 1102 was vetoed by

Governor Ehrlich.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/SB1102.htm
www.eia.gov/cneaf/electricity/page/restructuring/maryland.html 3/6

03/06: House Bill 1713 (HB 1713) Emergency Bill intended to change PSC review requirements related to electricity or gas acquisitions and mergers involving either

a public service company or a nonpublic service company. Essentially, requires PSC approval of proposed merger between Constellation Energy Group and Floridabased FPL Group. HB 1713 was vetoed by the governor.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/HB1713.htm

03/06: Senate Bill 1102 (SB 1102), prohibited “a specified merger between FPL Group, Inc., and Constellation Energy Group, Inc., from occurring and prohibited

Baltimore Gas and Electric Company (BGE) from increasing specified electricity rates until Constellation Energy returned a specified amount of money in transition

costs to BGE; requiring BGE to use specified transition costs to reduce a specified increase in specified electricity rates; etc.” SB 1102 effectively removed the

current members of the Maryland Public Service Commission. SB 1102 was vetoed by the governor.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/SB1102.htm

03/06: Senate Bill 1050 (SB 1050) intended to “repeal the authority for an electric company to earn a specified return in providing standard offer service to residential

and small commercial customers after the Public Service Commission has made a specified finding that requires the extension of the electric company's obligation

to provide standard offer service.” Standard Offer Service was viewed as a temporary measure which would be used by fewer customers over time. SOS was meant

to be automatically provided to any user who did not designate an electricity supplier or a consumer who opted to choose SOS. SOS was supposed to last only

until July 1, 2003. During an intended four-year transitional phase, utilities were supposed to provide SOS under frozen rates after an initial price reduction of 3 to

7.5 percent. The rate freeze was intended to come to an end on June 30, 2003; however, the rate freeze was extended until June 30, 2004, and then until July 2006

and July 2008 under certain circumstances.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/SB1050.htm

Source: Maryland Office of the People’s Council

http://w w w .opc.state.md.us/assets/documents//SOS%206-16-06%20comments%206-15-06.pdf

03/06: Senate Bill 1099 (SB 1099) intended to prohibit the “specified merger between FPL Group, Inc., and Constellation Energy Group, Inc., from occurring and

prohibiting Baltimore Gas and Electric Company (BGE) from increasing specified electricity rates until Constellation Energy returns a specified amount of money in

transition costs to BGE; requiring BGE to use specified transition costs to reduce a specified increase in specified electricity rates.” Measure was vetoed by

Governor.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/SB1099.htm

03/06: Maryland Office of the People’s Council “petitioned the Maryland Public Service Commission...to undertake an examination of the current procurement

practices of the electricity industry in Maryland, which were the result of deregulation and restructuring of the electric industry by the General Assembly in 1999.

OPC requested the Commission to explore what the optimal structure of the procurement process should be within the structure of retail competition in the market

for suppliers of electricity and safeguarding the consumers from radical and volatile prices swings in the wholesale market.”

Source: Maryland Office of the People’s Counsel

http://w w w .opc.state.md.us/c/178/Electric-deregulation-OPC-Pursues-Comprehensive-Analysis?search_keyw ords=public%20service%20commission

03/06: Senate Bill 1099 (SB 1099) was passed and required Constellation Energy to refund approximately $528 million dollars in stranded recovery costs as a

condition of its proposed merger with FPL group. Governor Ehrlich vetoed this senate bill.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/bills/sb/sb1099t.pdf

03/06: Governor Robert L. Ehrlich Jr. offered $25 million to help defray the costs of higher electricity to Maryland’s poor.

Source: Baltimore Sun.

http://w w w .baltimoresun.com

03/06: Senate Bill 1048 (SB 1048) was put forward and required that: “the Public Service Commission, when a specified rate cap or price freeze expires, to

determine a specified impact on residential customer bills; requiring the Commission, if the expiration of a specified rate cap or price freeze occurred before a

specified date, to determine a specified impact on residential customer bills; requiring the Commission to develop a specified price mitigation plan under specified

circumstances; requiring a price mitigation plan to phase in a specified rate under specified circumstances; etc.”

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/sb1048.htm

03/06: Senate Bill 972 (SB 972) and House Bill 1736 (HB 1736) were intended to reregulate electricity companies. The synopsis of HB 1736 and SB 972 read:

“Returning electric generation to the status of a utility service subject to regulation by the Public Service Commission; requiring a public service company to charge

just and reasonable rates for its utility services; requiring a public service company to file a specified tariff schedule of specified rates and charges with the

Commission; providing that a specified electric company or electricity supplier may apply to the Commission to adjust specified rates and charges; etc.”

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/SB0972.htm

http://mlis.state.md.us/2006rs/billfile/HB1736.htm

02/06: House Bill 1334 (HB 1334) was enacted with the purpose of prohibiting standard offer service rates from increasing more than five percent for residential

customers.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/bills/hb/hb1334f.pdf

http://mlis.state.md.us/2006rs/bills/sb/sb0972f.pdf

02/06: House Bill 1334 (HB 1334) was enacted and prohibits an electric company in any year in which the electric company has an obligation to provide standard

offer service under a Public Service Commission order from increasing the rate for electricity charged to residential customers by more than 5%; allowing an electric

company to recover the portion of the total rate that exceeds 5% through a standard offer service transition charge over a 5-year period; etc.

Source: State of Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/HB1334.htm

02/06: Senate Bill 814 (SB 814) was enacted and “prohibits an electric company in any year in which the electric company has an obligation to provide standard

offer service under a Public Service Commission order from increasing the rate for electricity charged to residential customers by more than 5%; allowing an electric

company to recover the portion of the total rate that exceeds 5% through a standard offer service transition charge over a 5-year period; etc.? Prohibiting an electric

company in any year in which the electric company has an obligation to provide standard offer service under a Public Service Commission order from increasing the

rate for electricity charged to residential customers by more than 5%; allowing an electric company to recover the portion of the total rate that exceeds 5% through

a standard offer service transition charge over a 5-year period; etc.”

Source: State of Maryland General Assembly

http://mlis.state.md.us/

12/05: Constellation and FPL Group announced plans to merge.
www.eia.gov/cneaf/electricity/page/restructuring/maryland.html 4/6

Source: Constellation Energy

http://phx.corporate-ir.net/phoenix.zhtml?c=112182&p=irol-new sArticle&ID=796853&highlight=

02/05: House Bill 1525 (HB 1525) was introduced in the Maryland House of Delegates. During the winter of 2005, the market-based cost of electricity

skyrocketed. In the wholesale electricity auctions, the market-based cost of electricity for an average residential customer was due to increase 72 percent in July

2006 in the BG&E service territory. Increases of 35 percent and 39 percent were expected in services territories covered by Delmarva and PEPCO, respectively. In

response to a pending 72 percent electricity price increase for residential customers of BG&E, HB 1525 required the Public Service Commission (PSC) to extend

the obligation to provide standard offer service (SOS) to residential and small commercial electric customers unless the PSC makes specified findings; altering the

required findings and terms for extending SOS; requiring investor-owned electric companies to obtain electricity supply for extended SOS to residential and small

commercial customers in specified manners; authorizing the Commission to take specified actions; etc.” HB 1525 failed in the Maryland Senate. SOS was

automatically assigned to any customer who did not opt to select an electricity supplier.

Source: Maryland General Assembly

http://mlis.state.md.us/2006rs/billfile/HB1524.htm

10/03: Maryland’s four investor-owned electric utilities, Allegheny Power, Baltimore Gas and Electric Company, Delmarva Power & Light, and Potomac Electric

Power Company, “issued requests for proposals to solicit bids to provide Standard Offer Service (SOS) for a share of its customer load.

Source: State of Maryland Public Service Commission

http://w w w .psc.state.md.us/psc/Reports/Technical_Consultant_Final_Report_5-25-06.pdf

09/03: The Public Service Commission issued Order No. 78710, which approved the technical details that support the standard offer service policy framework set

forth in April 2003.

Source: Maryland Public Utilities Commission

http://w w w .psc.state.md.us/psc/AboutUs/Press/Phase2AgreementApproved_8908.htm

04/03: The Public Service Commission issued Order No. 78400, which required electric utilities to continue to provide electric supply to their customers via a

standard offer service.

Source: Maryland Public Utilities Commission

http://w w w .psc.state.md.us/psc/AboutUs/Press/PSCApprovesStandardOffer.htm

04/02: Senate Bill 285 (SB 285) required electric companies in Maryland to "conduct a study that tracks shifts in generation and emissions as a result of

restructuring the electric industry." The electric companies must submit their studies twice to the PSC and the Department of the Environment on or before

December 31, 2003 and on or before December 31, 2005. If it is determined that restructuring has a negative impact on Maryland's environment, then the PSC will

consider "establishing an air quality surcharge or other mechanism."

Source: Maryland General Assembly

http://mlis.state.md.us/2002rs/billfile/SB0285.htm

01/02: The Office of the People's Counsel of Maryland claimed that the state's electric industry deregulation plan did not produce competition. In the year and a half

since the commencement of deregulation, only 2.6 percent of residential customers of utilities with Electric Choice programs switched suppliers. The Office of the

Peoples Counsel commanded that the General Assembly consider revising the Electric Choice program.

12/01: The Public Service Commission established a plan for four utilities to provide electric services at fixed rates, which was scheduled to expire around 2004. “A

central question was whether retail competition had advanced to such an extent that the Commission could end this obligation or must the Commission require the

four utilities to provide some form of Standard Offer Service (SSO).”

Source: State of Maryland Public Service Commission

http://w w w .psc.state.md.us/psc/Reports/Technical_Consultant_Final_Report_5-25-06.pdf

09/01: BG&E awarded contracts for its wholesale power supplies over the final three years of the transition period. Constellation Energy Source would supply 90

percent and Allegheny Energy Supply Company would supply 10 percent of BG&E's power needs, from July 1, 2003, to June 30, 2006. The contracts were awarded

through a competitive bidding process. BG&E stated that the wholesale contract prices did not exceed the frozen retail rates in effect through the transition period.

09/00: A Baltimore City Circuit Court Judge issued an order and opinion upholding the Maryland Public Service Commission's (PSC) approval of Baltimore Gas &

Electric's (BGE) electric restructuring settlement and generation asset transfers. The decision followed an August 23 hearing in which the Mid-Atlantic Power

Supply Association (MAPSA) and Shell Energy LLC challenged the PSC deregulation settlement and generation asset transfer orders.

08/00: In a hearing on August 4, 2000, the Baltimore City Circuit Court allowed Baltimore Gas and Electric (BG&E) to implement a 6.5-percent rate reduction and

stranded cost recovery plan, lifting a stay imposed in July. BG&E would provide retroactive savings from July 1, when customer choice began in Maryland. BG&E

was scheduled to defend the restructuring agreement in court at an upcoming hearing.

08/00: The Maryland Court of Appeals remanded the case back to the Circuit Court in Baltimore on July 20, reversing the stay issued earlier. The Circuit Court,

however, issued an interim 2 week stay on the restructuring order, scheduling a hearing on August 4. Meanwhile, BG&E's consumers would not begin receiving the

rate reductions or the ability to choose generation supplier that were to go into effect July 1.

07/00: The Maryland Court of Appeals ruled to delay the beginning of retail access in Baltimore Gas & Electric's territory. The Court issued the stay on the

Maryland PSC's November 1999 order that approved BG&E's restructuring settlement at the request of MAPSA, a trade organization representing a group of

competitive generation suppliers. MAPSA had complained that the standard offer rate set in BG&E's territory was too low to attract competitive suppliers. Retail

access and a 6.5-percent rate reduction for residential consumers would have gone into effect July 1 in BG&E's territory. The other utility territories in the State were

not affected by the court ruling.

07/00: Standard offer rates at the four investor-owned utilities in Maryland went into effect July 1, with the opening of retail access across the State. Standard offer

rates for residential consumers at Allegheny Power were 4.34 cents/kWh; Conectiv's were 4.92 cents/kWh; Potomac Electric Power's were 4.99 cents/kWh; and

BG&E's were 4.06 cents/kWh, and scheduled to rise to 4.28 cents/kWh by May 2003.

07/00: Rate reductions went into effect July 1, as approved in the settlement plans for the investor-owned utilities.

07/00: As planned in the restructuring settlement, BGE froze retail rates at a level approximately 6.5 percent below the current rates at the time. The rate freeze

was scheduled to be in effect until June 2006.

01/00: The PSC approved PEPCO's restructuring plan. PEPCO customers were scheduled to begin retail direct access in July 2000. PEPCO also received

approval to sell its generation assets.

01/00: Allegheny Energy Inc.'s settlement plan for restructuring was approved by the PSC in December 1999. Highlights of the plan included: Retail direct access

for almost all Maryland customers by July 1, 2000; a 7-percent residential rate reduction, effective January 1, 2002, through Dec. 31, 2008; a cap on residential

generation rates from Jan. 1, 2002, through January 1, 2008; a cap on nonresidential rates through Jan. 1, 2004; a cap on transmission and distribution rates for all

customers from January 1, 2002, through January 1, 2004; authorization to transfer all generation assets to Allegheny's unregulated affiliate company, Allegheny
www.eia.gov/cneaf/electricity/page/restructuring/maryland.html 5/6

Energy Supply Company, LLC, at book value; the recovery of purchased power costs incurred as the result of contracts with PURPA QF facilities; and

establishment of a fund for the development and use of energy efficient technologies.

12/99: PEPCO began a consumer education program, PEPCO Answers, to provide information to Maryland consumers on electricity competition. Consumers were

told that they may begin "shopping" for power in the spring of 2000, and begin receiving power from competitive companies by July 2000. PEPCO had filed

proposals with the Maryland and DC PSC's to sell its power plants.

11/99: BG&E's restructuring settlement was approved. All consumers were scheduled to have retail choice on July 1, 2000. Residential consumers would receive a

6.5-percent rate reduction.

09/99: PEPCO is seeking approval of its deregulation plan that would include a 3- percent rate reduction over 4 years beginning in July 2000, and another 4-percent

reduction by eliminating a surcharge that had funded energy conservation programs over the last decade.

09/99: Under its proposed restructuring plan, BG&E's shopping credit for residential consumers would be 4.224 cents per kilowatt-hour and rise to 5.02 cents in 6

years, too low according to competitive companies seeking to enter the retail electricity market in Maryland at the time. The Mid-Atlantic Power Supply Association

suggested the credit be set at 5.7 cents. BG&E said that the low credit reflected its low prices.

08/99: Public hearings on BG&E's proposed restructuring settlement began in August. The Mid-Atlantic Power Supply Association (a coalition of energy supply

companies) opposed the settlement on the grounds that the price to compare for BG&E, set at 4.3 cents per kilowatt-hour, was too low to allow competition. Also

suggested was that the stranded cost recovery for BG&E get lowered. The three-day hearings were concluded August 13; closings arguments were due August 30;

and rebuttals due by September 30. The PSC was scheduled to issue a decision in October.

07/99: Baltimore Gas & Electric filed a proposed restructuring plan with the PSC. The plan included a 6.5% rate decrease over six years for residential customers,

$528 million for stranded costs, a six year rate freeze and phase out of transition costs, and customer choice for all residential and business customers by July 1,

2000. Public hearings were set for July and August for comments to the plan.

06/99: The restructuring legislation prompted Maryland utilities to revise their restructuring proposals. BG&E submitted its new plan to the PSC: all customers

would have retail access beginning July 2000; residential rates would be decreased 6.5 percent beginning July 2000; $528 million in transition costs would be

recovered over 6 years from customers; rates would be unbundled and generation assets transferred to an affiliate company; and BG&E would provide the initial

funding of a low-income assistance fund and act as default supplier for customers deciding not to switch suppliers.

04/99: With House Bill 703 (HB 703) and Senate Bill (SB 300), “Maryland Customer Choice and Competition Act,” restructuring legislation was enacted. The

legislation included at least a 3 percent rate reduction for residential consumers, funding for low-income programs, stranded cost recovery to be determined by the

Public Service Commission, disclosure of fuel sources by electric suppliers, recovery of stranded costs through a non bypassable wires charge, and a 3-year phasein for competition beginning in July 2000 and becoming complete by July 2002. As of July 1, 2000, all customers of electric companies (had) the opportunity to

choose electric suppliers. By default, however, a customer remains with the electricity supplied by the distributing electric company under Standard Offer Service.

The PSC (had) extended the opportunity to provide SOS.” “Part of this Act required that all customers receive a rate reduction, followed by a rate freeze. The rate

reduction of 6.5% for BGE customers was based on the last BGE rate case which was in 1993. The Commission’s Technical Staff estimated that in 2005 alone,

this rate reduction saved customers $474 million or an average of $30 per month per customer.”

Source: Maryland General Assembly

http://mlis.state.md.us/1999rs/billfile/HB0703.htm

http://mlis.state.md.us/1999rs/billfile/SB0300.htm

Source: State of Maryland Public Service Commission

http://w w w .psc.state.md.us/psc/

02/99: PEPCO signed an agreement with the Maryland PSC for a plan to bring retail choice to its Maryland consumers as early as next year. The plan required

Maryland legislation and concurrence with the District of Columbia PSC for the sale of PEPCO's power plants.

01/99: House Bill 3 (HB 3) and Senate Bill 65 (SB 65) allowed BG&E to form a holding company. The law was intended to make it easier for BG&E to enter into

new business ventures in a competitive market. Maryland was the only state that prevented public utilities from forming holding companies by enacting HB 3 and SB

65.

Source: Maryland General Assembly

http://mlis.state.md.us/1999rs/billfile/HB0003.htm

http://mlis.state.md.us/1999rs/billfile/sb0065.htm

10/98: Five utilities in Maryland announced that they asked a state court to stop the PSC deregulation effort until several issues were resolved, including the issue

of stranded costs recovery.

04/98: A PSC order established roundtable discussions on restructuring issues: universal service, supplier authorization, demand-side management programs,

customer protection, competitive billing, and consumer education. The discussion groups were to submit reports in May 1999 and July 1999.

Source: Maryland Public Service Commission

http://w w w .psc.state.md.us/psc/electric/roundtable/rtfinal.pdf

12/97: The Legislative Task Force held hearings and issued conclusions and recommendations.

Source: Maryland General Assembly

http://mlis.state.md.us/PDF-Documents/1997rs/bills/sb/sb0851t.PDF

12/97: The PSC issued an Order 8738 establishing a framework for the restructuring of the electric power industry. The plan's schedule: a third of the State's

consumers would have retail access by July 2000; another third by July 2001; and the entire state by July 2002. Round table discussions to address

implementation of specific issues were to commence in April 1998. For the order to be effective, legislation needed to be passed.

Maryland Public Service Commission

http://w ebapp.psc.state.md.us/Intranet/Casenum/New Index3_VOpenFile.cfm?ServerFilePath=C:\CaseNum\9000-9099\9064\107.pdf

12/97: A PSC order stated that utilities would be allowed recovery of stranded costs. Utilities would have to file plans for stranded cost recovery by March 1998.

Competitive transition charges (CTC) and securitization were also being considered.

04/97: Senate Bill 851 (SB 851) created a task force on electric industry restructuring that was scheduled to issue a report by December 1997.

Source: Maryland General Assembly.

http://mlis.state.md.us/1997rs/billfile/SB0851.htm
www.eia.gov/cneaf/electricity/page/restructuring/maryland.html 6/6
www.eia.gov/cneaf/electricity/page/restructuring/massachusetts.html 1/3

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DOER-Massachusetts Division of Energy Resources

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MECO-Massachusetts Electric Company

NEES-New England Electric System

SOS-Standard Offer Service

Home > Electricity > State Restructuring > Massachusetts Restructuring

Massachusetts Restructuring Active

Last Updated: April 2007

01/06: The Massachusetts Department of Telecommunications and Energy (DTE) ruled that

customers who were using alternate electricity suppliers, but switched to the default electricity service,

did not have the option to switch back to using the alternate electricity supplier service for a period of

six months. The DTE mandated this legislation because it was difficult for a utility to plan its energy

needs if an excessive amount of service switching occurred.

Source: Department of Telecommunications and Energy

12/04: The Massachusetts Department of Telecommunications and Energy (DTE) approved a rate

plan set forth by Massachusetts Electric that included a recovery of approximately $60 million in power

supply costs associated with the state’s standard offer service.

Source: Department of Telecommunications and Energy

http://w w w .mass.gov/Eoca/docs/dte/electric/02-79/1217mecrepcom.pdf

09/04: Massachusetts Electric sought an increase of 1.075 cents per kilowatt-hour on the Default

Service portion of residential customers’ electricity bills, effective November 1, 2004. If approved, a

typical residential customer using 500 kWh of electricity per month would see a 9.6 percent increase, or $5.38, in the overall monthly bill.

Source: National Grid Company

http://w w w .nationalgridus.com/masselectric/a3-1_new s2.asp?document=521

05/02: Standard offer service rates (SOS) were set for the NSTAR electric companies at 4.95 cents/kWh for Boston Edison Company, 4.2 cents/kWh for

Cambridge Electric Light and Commonwealth Electric from April 2002 to December 2002. SOS rates were set at 5.626 cents/kWh for Fitchburg Gas and Electric

and 4.841 cents/kWh for Western Massachusetts Electric for all of 2002. SOS rates for Massachusetts Electric were set at 5.626 cents/kWh from January 2002 to

June 2002, but rates would decrease to 4.2 cents/kWh from July 2002 to December 2002. By March 2005, SOS would end and all customers were expected to

take competitive generation service.

03/02: According to the March 2002 monthly edition of DOER's Electric Power Customer Migration Data, 25,053 customers were using competitive suppliers.

Massachusetts had 1,798,141 Standard Offer Service customers and 697,726 default service customers.

08/01: The Department of Telecommunications and Energy approved fuel adjustment rate increases for standard offer rates by 1.23 cents per kWh for most

customers of Massachusetts utilities. Utilities submitted Standard Offer Fuel Adjustment Filings with the DTE requesting increases in standard offer rates to reflect

the rising cost of fuel to generate electricity.

07/01: The DTE, seeking to boost customer participation in the open electricity market, issued an order for utilities to release, with customer approval, default

customers' information to competitive suppliers. Suppliers could request names, addresses, and rate classes of default service customers.

05/01: After viewing the results of Massachusetts Electric Company's solicitation for power, the DTE approved increases in default service rates. Default service

was taken by all new customers and returning customers in MECO territory. Default rates would increase beginning May 1 to keep in line with market costs for

wholesale power. SOS rates would not increase at that time. SOS was taken by customers who remained with MECO since choice of electric service providers

began in 1998.

01/01: The DTE recommended to the legislature that competitive metering and billing not be implemented at the time. Instead, they proposed investigating how to

encourage the offering of advanced metering options by regulated distribution companies.

12/00: In response to the rising costs of wholesale power purchases driven by the increasing prices of natural gas and petroleum, the DTE raised standard offer

rates for the Boston Edison Company to 5.821 cents/kWh from 4.5 cents/kWh. Cambridge Electric Light Company and Commonwealth Electric Company's rates

would raise its rates to 5.121 cents/kWh from 3.8 cents/kWh. Massachusetts Electric Company's new rates would be 5.26 cents/kWh from 3.8 cents/kWh.

Fitchburg Gas and Electric Company's new rates would be 5.121 cents/kWh from 3.8 cents/kWh. Finally, Western Massachusetts Electric Company would raise

its rates to 7.383 cents/kWh from 4.557 cents/kWh. The standard offer rates of these companies were raised in order to compensate them for their losses on

wholesale power purchases due to rising fuel costs. The rates would take effect on January 1, 2001. Regulators also hoped the SOS rate increases would stimulate

the lethargic retail market in the New England States.

11/00: The Department of Telecommunications and Energy raised the default service rates for all Massachusetts utilities due to rising fuel costs, effective

December 1, 2000. Fitchburg Gas and Electric Company rates were increased to 5.206 cents for residential customers, 5.216 cents for commercial customers and

5.059 cents for industrial customers. Boston Edison, Commonwealth Electric, and Cambridge Electric received an increase in their default service rates to 6.28

cents for all customers. Massachusetts Electric Company's default rates were raised to 6.37 cents for residential customers, 6.08 cents for commercial customers,

and 5.36 cents for industrial customers.

09/00: Customer migration statistics showed that real retail competition had yet to take hold in Massachusetts. The Massachusetts Division of Energy Resources

(DOER) reported that 5,176 customers bought power from competitive generators in July 2000 as compared to 2.5 million customers who received power from their

incumbent utility. The low switching rate was expected in the State since competitive generators could not offer better deals than the incumbent utilities until the

standard offer price rises over a seven-year transition period.
www.eia.gov/cneaf/electricity/page/restructuring/massachusetts.html 2/3

standard offer price rises over a seven-year transition period.

07/00: The DTE issued an order that would allow utilities to base their rates for default service on the wholesale bid prices, beginning January 2001. Utilities

complained that the required rate, set below the cost of wholesale power, was causing them to lose money on default customer accounts. Utilities were scheduled

to begin issuing competitive bids seeking 6-month to 1-year contracts for the power needed to serve their default service customers. Default service was defined as

those customers who had left their competitive supplier, or were new to the utility's territory.

07/00: The DTE considered two courses of action, as required by the restructuring legislation passed in 1998. The law required the DTE to consider opening

metering, billing, and information services to competition, and also required the DTE to look into eliminating exclusive service territories for investor-owned utilities.

01/00: Unitil/Fitchburg Gas and Electric Light Company, received approval from the DTE for a rate increase of 2.53 percent, effective January 2000. The DTE stated

that the increase was the result of inflation adjustments allowed by Massachusetts' restructuring legislation. The SOS rate would increase from 3.5 cents to 3.8

cents per kilowatt-hour.

10/99: By the first quarter of 1999, about 1.3 percent of retail sales were supplied by competitive suppliers, representing about 0.13 percent of customers, most of

which were large industrial consumers.

11/98: Boston Edison Company proposed selling its Pilgrim nuclear plant to Entergy Corporation. In the deal, Entergy would pay between $80 and $90 million in

cash. BEC would receive as much as $466 million to cover cleaning up the plant when it ceased operations, scheduled for 2012. Book value for Pilgrim was about

$650 million at that time.

10/98: New England Electric System (NEES) subsidiaries, Massachusetts Electric and Nantucket Electric, reported savings for their consumers of $67.5 million

due to the 10-percent rate reduction mandated by the state's restructuring law and the sale of NEES' generating assets. The sale allowed additional rate reductions

prior to the law's next scheduled rate reduction.

10/98: Eastern Utilities (Montaup) planned to sell the Somerset Station for $55 million to NRG Energy.

10/98: There was an increasing interest in building new capacity, almost all natural gas, in the Northeast. Some gas plants were already begun and experts

predicted between 7,000 and 14,000 MW would be built, replacing older coal and oil plants. The Conservation Law Foundation released a report predicting a drop of

as much as 95 percent in major air pollutants from power plants.

09/98: PG & E Corporation's subsidiary, PG & E Energy Services, secured a multi-year contract with the Massachusetts High Technology Council (with over 200

members) to provide electricity to its members. This was the largest aggregation of customers in the U.S., representing about 1.2 million megawatt-hours annually.

05/98: Commonwealth Energy System and Eastern Utilities Montaup subsidiary would sell their fossil-fueled generating assets in Massachusetts to Southern

Company for $462 million, approximately 6 times the book value at that time. The sale would allow the 10- percent rate cut that began March 1, 1998 to increase to

a 15 percent cut beginning September 1, 1999.

05/98: NEES sale of generating assets representing over 5,100 MW to U.S. Generating, a subsidiary of PG & E Corporation, was completed. 3 fossil-fueled and 15

hydro plants were included in the $1.6 billion sale. It was proposed that customers in NEES subsidiaries, Massachusetts Electric and Nantucket Electric, should

see rate reductions of about 19 percent.

05/98: Boston Edison completed the sale of its entire portfolio of fossil-fueled generating assets to Sithe Energy.

05/98: The Massachusetts Electric Company's pilot saved $1.3 million for about 5,000 small commercial and residential customers. Also, $3.8 million had been

saved by the 14 customers in the Massachusetts High Technology Council pilot.

05/98: Commercial customers would get an unexpected 50 percent cut in sales tax paid on electric bills as a result of deregulation. Businesses would not be taxed

on the now unbundled delivery (distribution and transmission) costs (residential and industrial customers were already exempt from this sales tax).

04/98: Competition and a 10 percent rate reduction began as scheduled March 1998. However, the standard offer rate of 2.8 cents/kWh was low enough that

competitors could not offer better rates, effectively stifling competition until the standard offer rate was scheduled to rise in 1999 and phased out by 2005. Recently,

Enron announced it would not market to the residential sector in California, Massachusetts, or Rhode Island because it was proving to be unprofitable.

04/98: Boston Edison sought buyers for its Pilgrim nuclear plant. The company had already sold its non-nuclear generation to Sithe Energies.

04/98: Eastern Utilities scheduled to sell its generation assets and purchase power contracts.

03/98: DTE issued rules for distribution, default generation services, standard offer generation, aggregation requirements, and ownership of meters.

02/98: The DTE issued implementation rules for the restructured industry. Included were licensing and information disclosures for retail suppliers and provisions for

public interest programs, standard offer service, and utility transition cost recovery filings.

11/97: House Bill 5117 was enacted to restructure the electric power industry. The law required retail access by March 1998, rate cuts of 10 percent by March

1998 and another 5 percent 18 months later, and encourages divestiture of generation assets. The legislation also allowed full recovery of stranded costs over a 10-

year transition period; DTE approved 2 utilities’ plans for stranded cost recovery.

09/97: The Massachusetts Supreme Court upheld the DPU's (now DTE's) jurisdiction in the MIT case, but did not confirm the amount of stranded cost recovery,

initially set at 75 percent. MIT exited the Cambridge Electric system in 1995. The company planned to seek 100 percent recovery.

01/97: The Department of Telecommunications and Energy’s final decision stated that it would officially open the retail electricity market to competition by March 1,

1998.

01/97: Massachusetts Electric began a 1-year pilot program in four communities. Of the pilot participants, 96 percent of the business and 66 percent of the

residential consumers chose supplier based on price, 31 percent of residential consumers choose supplier based on "green power."

10/96: Commonwealth Electric implemented a retail choice pilot program.

07/96: Massachusetts Electric began its pilot program for members of the High Technology Council; another 10,000 consumers were scheduled to be added later.

01/96: Boston Edison began a pilot program.
www.eia.gov/cneaf/electricity/page/restructuring/massachusetts.html 3/3
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AEP-American Electric Pow er

PSC-Michigan Public Service Commission

Home > Electricity > State Restructuring > Michigan Restructuring

Michigan Restructuring Active

Last Updated: September 2008

06/08: The Michigan Public Service Commission authorized Consumers Energy Company to raise electric rates by

$27,468,600. The utility had requested $68,869,000. The average residential Consumers Energy electric customer will see a

rate increase of less than 2 percent per month, effective in July 2008. The Commission also reduced the subsidy paid by

commercial and industrial customers by nearly $20 million.

Source: Michigan Public Service Commission

http://w w w .michigan.gov/mpsc/

02/06: The Michigan Public Service Commission (PSC) issued the Status of Electric Competition in Michigan report that

reviewed electric competition within the state for 2005. The PSC found that overall, electricity load served and the number of

customers participating in Michigan’s competitive electric choice market fell by approximately 40% and 20%, respectively, in the service territories for both

Consumers Energy Company and The Detroit Edison Company. Likewise, the MWh’s of energy sales decreased 26% in The Detroit Edison territory, but increased

by 1% overall in Consumers Energy territory. The decline was attributed to several factors, primarily the steadily increasing power supply costs, and state and

federal regulatory changes, including implementation of stranded cost surcharges and federal seams (“seams” refer to the transmission grid connecting two or more

defined regions) elimination charges. The seams charge particularly affected one supplier causing it to cease doing business in Michigan. These factors likely

impacted the competitive price of electricity supply in 2005.

Source: Michigan Public Service Commission

http://w w w .dleg.state.mi.us/mpsc/electric/restruct/reports/compreport2005.pdf

10/02: The Michigan Public Service Commission approved AEP Ohio Commercial & Industrial Retail Company’s application for an alternative electric supplier

license. At the time, there were 21 other licensed alternative electric suppliers in the State.

08/02: The Michigan PSC issued an order that mandated the CHOICE Advisory Council subcommittee to instigate a statewide customer choice education program.

The order proposed that the council complete the following tasks: "informing commercial electric customers about customer choice, informing commercial and

residential electric customers about the availability of green power, and informing potential alternative electric suppliers of the opportunities to participate in the

customer choice program in Michigan." The order stated that the utilities and the contractors had two months to comply with the order.

02/02: The Michigan Public Service Commission (PSC) issued an order authorizing $27.4 million in grants from Low-Income and Energy Efficiency Fund to various

organizations. According to the PSC press release, the Fund was administered by the PSC and funded from the "securitization savings that exceeded the amount

needed to achieve a 5- percent rate reduction for residential and business customers." The grants were given to the Family Independence Agency, the Michigan

Community Action Agency Association, the Salvation Army, the Heat and Warmth Fund, Newaygo County Community Service, Wayne Metropolitan Community

Action Agency, and Leslie Outreach Inc.

02/02: The Michigan Public Service Commission released its Status of Electric Competition in Michigan Report on February 1, 2002. At the time, retail open

access was fully implemented in the state of Michigan with 3,200 customers and 15 licensed alternative suppliers participating. Michigan had three open access

programs to date, two in Detroit Edison's service territory and one in Consumers Energy' service territory. Detroit Edison's Experimental Retail Access Program

began on December 6, 1999, and will end on June 30, 2004. Alternative suppliers were currently providing 82 megawatts (MW) out of the program's 90 MW limit.

Detroit Edison's industrial and large commercial customers were mostly utilizing the main Electric Choice Program offered to all customers. The program served a

total load of 497 MW as of January 2, 2002. Consumer Energy's Electric Choice Program followed the same trend with mostly industrial and large commercial

customers participating. As of January 28, 2002, alternative suppliers were serving a total load of 238 MW. Overall, the programs grew 30 percent in 2001.

01/02: The Michigan Public Service Commission (PSC) issued an order allowing nine electric cooperatives to use deferral accounting for the implementation and

administrative costs associated with customer choice and unbundling electric rates. Cooperatives were not guaranteed cost recovery under this order, and the order

stated that cooperatives would have to file a separate recovery plan with the PSC.

12/01: The PSC issued nine new orders "to advance Michigan's competitive electric environment" that took effect on January 1, 2002. The first and second orders

prohibit both the Detroit Edison and Consumers Energy from changing their depreciation accrual rates and practices until January 1, 2006. The third order initiated

the drafting of "rules for service quality and reliability standards for electric distribution systems." The fourth order adopted standards for the disclosure of customer

information, fuel mix information, and environmental characteristics of electricity products. The fifth and sixth orders approved Detroit Edison and Consumers

Energy's new retail rates. The seventh order unilaterally determined net stranded costs for utilities. The eighth order approved Wisconsin Electric Power Company

and Edison Sault Electric Company's "revised return-to-service proposal." The ninth order rejected the Detroit Edison Company's application "to unbundle existing

commercial and industrial electric rates."

11/01: Issued orders by the PSC included: an order adopting procedures to protect customers from slamming, switching a customer to another service provider

without their consent, and cramming, billing a customer for unauthorized service, in compliance with the Customer Choice and Electricity Reliability Act of 2000; an

order establishing a procedural framework for implementing and administering the Low-Income and Energy Efficiency Fund; and an order adopting a modified code of

conduct for regulated and unregulated services provided by electric utilities and alternative electric suppliers.

10/01: The PSC issued an order October 11, 2001, to adopt the settlement agreement and authorizing Wisconsin Electric Power Co, Edison Sault Electric Co, Wisconsin Public Service Corp, Upper Peninsula Power Co, Northern States Power Co - Wisconsin, Indiana Michigan Power Co, and Alpena Power Co to

implement Customer Choice and Electricity Reliability Act implementation plans.
www.eia.gov/cneaf/electricity/page/restructuring/michigan.html 2/2

12/00: Detroit Edison completed the fifth and final bidding phase in its Electric Choice Program. As in the previous bidding, the demand for capacity exceeded the

amount available. To date, about 1,125 MW, or 12 percent, of DE's capacity was available to alternative suppliers.

11/00: The PSC issued two orders approving Detroit Edison's and Consumers Energy's financing order applications that allowed them to issue securitization bonds.

Detroit Edison could secure $1.77 billion in costs by issuing bonds, and Consumers Energy could secure $469 million. The refinancing will allow both companies to

cover the cost of implementing the 5-percent reduction in rates, which began in June 2000 after the passage of Public Act 141 and 142.

06/00: The PSC issued a series of orders to implement the restructuring legislation, which was signed into law on June 3, 2000. In the orders the PSC directed:

Consumers Energy and Detroit Edison to file, by September 20, revised tariffs to implement retail access programs; investor-owned utilities, other than Detroit

Edison and Consumers Energy, and cooperatives that had any customer with a peak load of 1 MW or more, to file restructuring plans to implement retail access;

PSC staff to consult with utility owners, merchant plant owners, and other stakeholders to develop standards for the interconnection of merchant plants; utilities to

file reports with the PSC when they learn of any reductions in federal funding for low-income and energy assistance programs; and electric generating facilities to file

reports with the PSC on compliance with all applicable federal Environmental Protection Agency regulations governing mercury emissions. The PSC also issued an

order that establishes the framework for alternative electric suppliers to participate in retail electric markets under the restructuring law.

06/00: The PSC ordered Detroit Edison and Consumers Energy to reduce residential rates by 5-percent. According to Public Act 141 and 142, Michigan's

"Customer Choice and Electricity Reliability Act," the Commission must reduce rates by 5-percent.

06/00: Public Act 141 of 2000 and companion Public Act 142 were signed into law on June 3, 2000. The comprehensive restructuring legislation proposed that all

consumers have retail choice by January 2002. Detroit Edison and Consumers Energy residential consumers would receive an immediate 5-percent rate reduction.

The reduced rates would then be frozen at least until December 31, 2003. Rates for large commercial and industrial consumers would also be capped through 2003,

and small business consumers’ rates would be capped at current levels through 2004. Other provisions of the law include: requiring the PSC to issue orders that

would prevent “slamming” and “cramming”; creating a low-income and energy efficiency fund of approximately $40 million per year for 6 years; creating a consumer

education program; authorizing stranded cost recovery and securitization (refinancing of debt); licensing new suppliers; and requiring a study of the effects of

mercury emissions from the electric power industry in the State. The PSC was given authority to implement restructuring and retail competition.

03/00: The third and fourth bidding phase took place in Michigan on January 20 and March 20, respectively. Together, Consumers Energy and Detroit Edison had a

cumulative total of 1,875 MW electric load under competitive bidding. In all four phases, Consumers Energy offered 150 MW each time, and Detroit Edison offered

225 MW for bid. Demand for capacity exceeded the amount available in all four bidding processes.

01/00: The second phase in Consumers Power's plan to gradually implement retail direct access would allow for 300 MW of load to be served by alternative

suppliers. As in the first round of bids for 150 MW, the second set of bids exceeded the 150 MW of allotted capacity. Three more blocks of 150 MW each were

scheduled to be offered for direct access on December 27, 1999, February 28, 2000, and October 30, 2000. By January 1, 2002, all consumers were scheduled to

have direct access to retail electric power.

01/00: Detroit Edison customers participating in Phase I of the customer choice program began taking power from alternative suppliers in December 1999.

12/99: The first phase of retail access was implemented in September 1999 with full participation in Detroit Edison's territory. The second phase began in

November. Each of five phases were proposed to make 225 MW of capacity available for all classes of consumers, until beginning in January 2002, when all

consumers would have retail direct access to competitive generation provider companies.

08/99: The PSC established September 1, 1999, as the deadline for Detroit Edison and Consumers Energy to notify the PSC of their intent to voluntarily implement

the Electric Choice plan, as ordered by the PSC. Both Detroit Edison and Consumers Energy had announced that they intended to implement retail competition

under a voluntary basis. The Governor issued a statement in which he stated that he "continued to support the implementation of the PSC's Orders to begin the

creation of a competitive market" and that "the next step(was) to codify those Orders into law..."

06/99: The Michigan Supreme Court decided that the PSC did not have the authority to mandate retail wheeling. However, Consumers Energy and Detroit Edison,

which served 90 percent of the consumers in Michigan, were voluntarily restructuring according to the PSC restructuring plan. All of their consumers were scheduled

to have retail access by January 1, 2002.

05/99: Seven large consumers of Detroit Edison were given the ability to buy power from competitive suppliers on June 1, 1999. Choice was scheduled to be

phased in for all DE consumers by January 2002.

03/99: The PSC plan was for 2.5 percent of consumers of Detroit Edison and Consumers Energy to choose electric suppliers beginning September 1999, and

adding an incremental 2.5 percent every six months until January 1, 2002, when all consumers of Detroit Edison and Consumers Energy were scheduled to gain

retail access.

06/98: Detroit Edison and Consumers Energy filed revisions of draft plans that address comments from the PSC staff, customers, suppliers, and other interested

parties. Both plans would phase-in retail competition over the next 4 years beginning with large industrial consumers by November 1998 and full retail access by

January 1, 2002.

04/98: Responding to the PSC order, Consumers Energy and Detroit Edison filed restructuring plans to implement retail competition.

01/98: The PSC completed final action on rehearing orders required to introduce competition into the state’s electric utility market. A phase-in schedule was

adopted allowing 2.5 percent of Consumer’s Energy and Detroit Edison customers retail access as early as March 1998, adding another 2.5 percent on June 1998,

January 1999, January 2000, and January 2001 and all consumers by 2002.
www.eia.gov/cneaf/electricity/page/restructuring/minnesota.html 1/1

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Minnesota Restructuring not Active

Last Updated: September 2008

06/08: A report was issued by the Regulatory Assistance Project to the Minnesota Public Utilities Commission whereby

standards and criteria were proposed so that Section 216B.2412, enacted by the Minnesota Legislature in May 2007, could

be analyzed before implementation.

Source: Minnesota Public Utilities Commission

http://w w w .puc.state.mn.us/docs/rap_decoupling.pdf

05/07: The Minnesota Legislature enacted a new statute, Section 216B.2412, in which it defined an alternative approach to

utility regulation, decoupling, and directed the Public Utilities Commission to “establish criteria and standards” by which decoupling could be adopted for the state’s

rate-regulated utilities. In addition, the legislation authorized the PUC to allow one or more utilities “to participate in a pilot program to assess the merits of a ratedecoupling strategy to promote energy efficiency and conservation,” subject to the criteria and standards that the PUC will have established.

Source: Minnesota Office of the Revisor of Statutes

https://w w w .revisor.leg.state.mn.us/

09/00: A report by the Minnesota Department of Commerce recommended changes in the State's power industry but not full electric competition. The report,

entitled "Keeping the Lights On: Securing Minnesota's Energy Future" stated that the Department would not recommend implementation of full retail electric

competition because of potential shortfalls in available energy. The Department estimates that by 2006 the Midwest could encounter an energy shortfall of 5,000

MW, and in its report proposes a change in the tax structure to promote the building of new power plants. The report also included suggestions for mandated

statewide energy planning, increased energy conservation, and competition on the wholesale level. Fourteen public meetings on the proposal were scheduled

across the state through the end of October 2000.

01/00: The Minnesota Legislative Electric Energy Task Force's January 2000 report confirmed that there is still no underlying consensus among stakeholders as to

whether the state should restructure. However, most stakeholders believed that restructuring in Minnesota is inevitable and that there are many areas of consensus

in terms of the broad issues. The report recommended that the task force's term be extended beyond its current expiration date of June 30, 2000. The task force

also recommended that the staff draft a restructuring plan or outline restructuring options to assist the legislature in its determination of whether and how Minnesota

should restructure.

05/99: The PUC issued an "order initiating development of unbundling program and opening new investigation docket." The purpose of this order was "to investigate

issues of unbundling/retail choice/restructuring in the gas and electric utilities industries." The PUC scheduled the development of a program by January 2001, and

presented it to the Legislature for consideration.

01/99: The Minnesota Legislative Electric Energy Task Force's January 1999 report recommended that a continued study of electric restructuring issues. A 1999

work plan was drafted and a report was scheduled to be completed in January 2000.

04/98: House File 3654 (Chapter 380 of the Laws of Minnesota 1998) established technical advisory work groups within the task force to study "bulk power system

reliability, infrastructure, and regulation issues; distribution reliability, safety, and maintenance issues; energy prices and price protection mechanisms issues; and

universal service issues." The groups were tasked with preparing a report for the full task force to review by November 30, 1998, and the task force was scheduled to

present a report to the Legislature by January 15, 1999.

01/98: The Minnesota Legislative Electric Energy Task Force released its 1998 report to the Legislature, and recommended against acting on electric industry

restructuring in the 1998 session. It also recommended further study of the issues with a report due January 1999.

10/97: The PUC issued a report that reflected the discussions held by the Minnesota PUC Electric Competition Work Group from February 1996 to October 1997.

The report identified restructuring issues and is intended as a starting point for state policy makers and stakeholders to restructure the electric industry.

05/97: The Legislature amended the role of The Minnesota Legislative Electric Energy Task Force to review and analyze issues related to electric power industry

restructuring with the passage of Senate File 1820 (Chapter 191 of the Laws of Minnesota 1997). A report was scheduled to be due in January 1998.
www.eia.gov/cneaf/electricity/page/restructuring/mississippi.html 1/1

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05/00: The Mississippi Public Service Commission (PSC) concluded that a competitive electric power industry would not

be beneficial to the State's consumers at this time. After several years of hearings and investigation into the benefits of

competition, a decision was made to suspend the 1996 docket opened by the PSC to investigate electric power industry

restructuring. Prices for electricity in Mississippi were below the national average at the time, and studies conducted by

the PSC indicated that prices for residential and small consumers could rise in a competitive environment.

09/98: The first legislative hearing on restructuring the electric power industry was held in September 1998. The

Mississippi Senate Committee heard 2 days of testimony on the impact of restructuring the electric power industry. The committee chair said Mississippi stood to

gain from electricity deregulation because of its abundant natural resources.

06/98: The PSC issued a Revised Proposed Plan for retail competition that addressed the comments received from industry, consumers, suppliers, and utilities.

Hearings were scheduled to be held throughout 1999 to address the issues.

05/98: The PSC issued orders to conduct studies on market power and cost of service.

04/98: The PSC received comments and held hearings on its restructuring plan.

01/98: Entergy Mississippi commented to the PSC that the restructuring plan was overly optimistic and recommended January 2002 as the earliest date to begin

retail competition.

11/97: The Public Utilities Staff presented a report to the PSC proposing retail choice to begin by January 2001 and be completed by December 2004, unbundling of

services and rates, and recovery of stranded costs to be determined by the PSC. Implementation of the plan would require legislation to be passed by 1999. The

report also recommended that the Commission have discretion in recovery of stranded costs, on a utility-by-utility basis, through a wires charge. Exit fees and

securitization were deemed anti-competitive and would not be used.

07/97: The PSC issued an order requesting the Public Utilities Staff to develop a plan for restructuring the industry, due by November 1997. The plan, if accepted,

would be a basis to draft legislation for 1999.
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KCPL-Kansas City Pow er and Light

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07/02: House Bill 1402, the "Consumer Clean Energy Act," required retail electric suppliers to set net metering standards by

August 28, 2003. According to the Missouri House of Representatives' summary, the Missouri Public Service Commission

would develop a contract that allowed excess electricity produced by the consumer to be sold to the local utility. The seller

would "receive credit for renewable energy generation and emission avoidance." The PSC would issue the contracts "on a

first-come, first-served basis until statewide capacity equaled the lesser of 10,000 kilowatts or 0.1 percent of the peak

demand for each supplier of electricity during the previous year."

09/01: The Missouri Public Service Commission (PSC) approved the reorganization of Kansas City Power & Light (KCPL).

KCPL would form a holding company, Great Plains Energy, Inc., with three subsidiaries: KCPL which engaged in the generation, transmission, distribution and sale

of electricity to approximately 467,000 customers located in western Missouri and eastern Kansas; Great Plains Power, Inc. which developed competitive

generation for the wholesale market; KLT, an unregulated subsidiary with investments in energy-related businesses. Conditions of the reorganization were designed

to protect KCPL customers. Also, purchase supply agreements between KCPL and Great Plains Power or its affiliates would require PSC approval and would be

cost-based.

05/98: The Retail Electric Competition Task Force issued its Final Report to the PSC with recommendations on issues including public interest programs, stranded

costs, taxes, reliability, and market power.

09/97: As part of the settlement for merger of Union Electric and Central Illinois Public Service, Union Electric would implement a pilot program for 100 MW and

about 5,000 customers. An Utilicorp (Aquila) 2-year pilot was limited to 10 customers with a demand of at least 2.5 MW.

03/97: The PSC established the Retail Electric Competition Task Force to study retail wheeling and related issues and prepare reports for the PSC. Four working

groups were established and were scheduled to submit reports no later than April 1998.

1997: HCR 7 created a panel of legislators to study retail wheeling; a report was scheduled to be due by January 1998.
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PP&L-Pennsylvania Pow er and Light Company

PSC-Montana Public Service Commission

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04/03: House Bill 509 (HB 509) was enacted to include limits on the amount of load served by alternate suppliers such

that no more than 10,000 kW could be served to small customers and no more than 20,000 kW could be served to

medium customers. This bill also defined NorthWestern Energy as the primary default power supplier for the State of

Montana and extended the transition period until 2027.

Source: Montana State Legislature

http://data.opi.mt.gov/bills/2003/billhtml/HB0509.htm

11/02: Voters rejected House Bill (HB 474), thus negating any further restructuring action that would have been put into

place due to mandates set forth in the legislation.

Source: The Foundation for Water and Energy Education

http://w w w .fw ee.org/new s/getStory?story=998

02/02: The Montana Public Service Commission (PSC) issued a final order that will allow the NorthWestern Corporation to complete its acquisition of the Montana

Power Company.

05/01: House Bill 474 was signed into law, significantly altering the existing restructuring legislation, and extending the transition period to July 1, 2007. House Bill

474 allowed customers being served by alternative suppliers to switch to the default supplier providing that the customer did not resell the electricity. The PSC is

directed to adopt a mechanism to ensure the default supplier may fully recover electricity supply costs in rates. The Montana Board of Investment was authorized to

invest in 450 MW of new generation projects and 120 MW in purchases from PURPA qualifying facilities that met certain criteria. Approved projects must have been

contracts for the sale of power to the default suppliers or a Montana industry, and were to be "collateralized by payments from the sale of the electricity produced by

the project...." Additionally, House Bill 474 created a Montana Power Authority, financed by revenue bonds, to purchase, construct and operate electric generating,

transmission, or distribution systems or enter into joint ventures for these purposes. Also, a Consumer Electricity Support Program was created as a State revenue

fund derived from the electrical energy excess revenue tax. The program was formed to promote price stability and fund default customers, Universal Service

programs, low-interest loans for new or upgraded transmission facilities or new generation facilities. The Universal System Benefits Charge was extended from July

1, 2003 to December 31, 2005, and public utilities proposed offering a product composed of electricity from renewable resources.

01/01: The PSC approved an interim $14.5 million increase in delivery rates for Montana Power customers. The increase represented a 4.5-percent increase for

customers who bought their power from Montana Power and a 7.5-percent increase for customers who bought power from competitive suppliers.

11/00: The Montana PSC decided to delay complete retail access for all consumers from July 2002 to July 2004 because the state did not have a competitive

power supply market in place. Most rural electric cooperatives had opted not to restructure or offer retail choice. Also, Montana Power customers had not been

switching to retail choice in large numbers. All NorthWestern Energy customers would be returned to Montana Power service because the Public Service

Commission had imposed a rate hike moratorium on Montana Power customers through July 1, 2002.

01/00: Pennsylvania Power and Light (PP&L) completed its purchase of Montana Power’s power plants: 11 hydroelectric plants and interests in 4 coal-fired plants.

Purchase price was $757 million. The sale represented Montana Power’s exit from the regulated generation business.

07/99: Senate Bill 406, the Electricity Buying Cooperative Act, took effect on May 5, 1999. It allowed residential and small business customers to combine their

buying power to form a cooperative. As a result, a cooperative was formed that would buy up to 330 MW from the market to serve up to 250,000 customers

statewide. The law exempted electricity suppliers from laws that prohibit cooperatives from expanding into cities of more than 3,500 persons.

11/98: The PSC reached an agreement with Pacificorp to proceed with the sale of its service territory in the State to Flathead Electric Cooperative. Pacific Power

(Pacificorp's Montana division) had about 34,500 customers at the time.

11/98: Montana Power was looking to sell 13 power plants, about 2,600 MW of capacity, for $1.6 billion to PP&L Resources. The plants included 11 hydroelectric

plants, 1 wholly owned coal plant, and Montana Power’s controlling interest in Colstrip, a large 4-unit coal plant.

06/98: PSC approved a plan to phase-in competition. Beginning July 1, 1998, Montana Power's largest customers (loads over 1 MW) would be able to choose their

energy supplier. Beginning November 1998, 5 percent of residential and small consumers would select their power supplier under a pilot program.

03/98: Montana Power accelerated its schedule for residential and commercial customers’ pilot program. All customers would have retail access by April 2000, 2

years earlier than the law required at the time.

01/98: Montana Power’s intention to sell its plants set off concerns by deregulation critics that foretell higher rates; a move for a special legislative session to slow

deregulation failed.

12/97: Montana Power announced that it would offer for sale all of its Montana electric generating facilities—13 dams and four coal-fired plants, as well as its

leased interest in another coal-fired plant and its contracts for power purchased from independent producers.

04/97: Senate Bill 390, the Electric Utility Industry Restructuring and Customer Choice Act, was enacted allowing large industrial consumers retail access by July

1998 and all consumers by July 2002. Senate Bill 390 also allowed for recovery of stranded costs through nonbypassable customer transition charges. It also

allowed for securitization for financing certain transition costs and included a 2-year rate freeze beginning July 1998.
www.eia.gov/cneaf/electricity/page/restructuring/montana.html 2/2

allowed for securitization for financing certain transition costs and included a 2-year rate freeze beginning July 1998.
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10/01: The 2001 Annual Report, mandated by Legislative Bill 901, addressed five "condition certain" issues; regional transmission

organizations, wholesale markets, retail rates, regional prices, and state and federal deregulation activities.

04/00: Legislative Bill 901 was enacted by Governor Johanns, and it "adopts the "conditions certain" approach recommended in the Legislative Resolution 455

study, and directed the Power Review Board to monitor the ongoing activities in the electricity industry and submit an annual report to the Governor and Legislature."

12/99: The Final Report of the Phase I Study to the Natural Resources Committee on Nebraska's electric utility industry was issued in December 1997. The report

focused on the existing structure of the industry and how to improve it. The Final Report of the Phase II Study was issued in December 1999. The report addressed

competition issues and policy changes needed to keep public power viable.

06/96: Legislative Resolution 455 was enacted to allow a 3-year study on electric power industry restructuring, with reports scheduled to be due in December 1997

and December 1999.
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PUC-Nevada Public Utilities Commission

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03/03: The Nevada Public Utilities Commission (PUC) ruled that nine large commercial customers, two of which were MGM

Grand and Park Place Entertainment, could purchase electricity from competitors of Nevada Power Company.

Source: Nevada Public Utilities Commission

http://pucw eb1.state.nv.us/PUCN

07/01: Assembly Bill 369 returned electric utilities to regulation, but Assembly Bill 661 allowed eligible large customers,

those using 1MW and above, to choose an alternative supplier for power with permission from the State PUC.

07/01: Assembly Bill 661 was enacted, revising and repealing certain provisions of Nevada's restructuring law. The law allowed eligible large customers, those using

1MW and above, to choose an alternative supplier for power with permission from the State PUC. The law also contained provisions to fund low-income energy

assistance with a universal energy charge and to revise and repeal various provisions concerning the regulation of public utilities and the process of establishing and

changing rates.

07/01: Senate Bill 372 was enacted, requiring the two investor-owned utilities in Nevada to provide 5 percent of their power from renewable resources by 2003, and

15 percent from renewables by 2013. At the time, about 3 percent of electricity in Nevada was generated using renewable energy sources.

05/01: Legislation was enacted to revise and repeal certain provisions of the State's restructuring law governing the regulation of electric utilities. Assembly Bill 369

would return electric utilities to regulation and bar the sale of their power plants before July 1, 2003. Also, utilities would be able to use a deferred accounting

method to protect consumers from wholesale price volatility. Retail rates would remain at April 2001 levels, which included the rate increase of over 17 percent

approved in March 2001, until early next year when adjustments may be made in accordance with the costs of procured power over the past year. Any needed

increases to clear the deferred accounts would be spread out over several years.

03/01: The Governor issued the Nevada Energy Protection Plan, a comprehensive strategy to provide energy reliability, consumer protection, and long-term rate

stability to Nevadans. The plan included an indefinite halt to electric utility deregulation at the time due to high demand, low supply, and unstable prices. The plan

also re-examined utility plant divestiture, sought to accelerate power plant and transmission line construction, and offered to protect consumers from increasing high

energy costs.

01/01: The Governor's energy panel recommended that only large customers be allowed retail choice until supply and wholesale prices become more stable in the

western markets. Residential retail access had been put on hold indefinitely.

10/00: Nevada Governor Kenny Guinn extended the deadline for the start of competition for the second time in 2000. The market, which was most recently

scheduled to open up for large commercial customers on November 1, 2000, would now open on September 1, 2001, for all customer classes in the State. The

Governor cited soaring power prices amid strong demand and short supplies as the reason for delaying competition.

10/00: The PUC approved a $15-million rate increase for Nevada Power Co., which represented a 1.3-percent increase for residential customers. In a July

agreement between regulators and utilities, Nevada Power increased rates by $48 million, or 4.7 percent for the average residential customer. Collectively, the July

increase and two monthly increases since, boosted residential rates by 7.5 percent, or $5.64 per month for the typical residential customer. Nevada Power had

requested the increases in an effort to recover increased costs of fuel and purchased power.

08/00: The PUC set a schedule for opening the retail market in Nevada. The market was scheduled to open November 1, 2000 for the largest commercial

customers, in April 2001 for medium commercial customers, and in June 2001 for small commercial customers. Residential customers were scheduled to be

phased in from September 1 through December 31, 2001.

07/00: An agreement between regulators and the utilities allowed Sierra Pacific and Nevada Power to recover the increased costs of fuel and purchased power.

Nevada Power would be allowed to increase rates by about $48 million or 4.7 percent for the average residential consumer. Even so, the prices for power in southern

Nevada at the time remained below that in neighboring States, such as Arizona and California. The agreement would move the State toward implementing retail

access.

04/00: Sierra Pacific Resources, the parent company of Nevada Power and Sierra Power, filed suit in Federal court claiming the 1999 Nevada restructuring law was

unconstitutional. An issue of disagreement between the PUC and Nevada Power was observed in a rate case, where Nevada Power requested an increase in rates,

prior to the rate freeze mandated in restructuring legislation. The PUC ruled against a rate increase, and instead recommended a slight decrease. (03/01: Sierra

Power dropped the lawsuit.)

03/00: The Governor delayed opening the retail market, originally scheduled for March 1, indefinitely. Issues to be resolved at the time included funding the

Mountain West Independent Scheduling Administrator and decisions on a series of major cases before the PUC regarding unbundling, stranded cost recovery, and

rate freezes.

06/99: Senate Bill 438 was enacted to amend the 1997 restructuring legislation, Assembly Bill 366. The bill delayed the opening of the retail market by March

2000, and gave the Governor, rather than the PUC, the authority to select another date if he deemed it in the best interest of consumers. It also capped residential

rates for the first 3 years. The bill allowed an incumbent utility to use its name and logo for affiliates competing in the unregulated power market.
www.eia.gov/cneaf/electricity/page/restructuring/nevada.html 2/2

04/99: The Senate committee approved a bill that would delay retail access until March 2000 and freeze rates until March 2003.

02/99: The PUC decided to delay deregulation of the electric power industry previously set to begin at the end of 1999 according to legislation passed in July 1997.

They cited a list of "unresolved issues," as the reason for the delay.

12/98: The PUC ordered working groups to investigate issues of retail competition. Reports on meter data exchange and stranded costs were scheduled to be due

in June 1999.

06/98: The PUC issued an order that defined which utility-related services, aside from selling electricity, could be open to competition. Areas of activity expected to

be opened up to competition included metering, billing, and customer service.

03/98: The PUC issued a draft report on the unbundling of services and costs.

11/97: As part of its ongoing investigation, the PUC ordered Nevada Power and Sierra Pacific Power Co to submit filings which demonstrated each distinct

component of electric service (unbundled costs). Hearings were scheduled to be held in December 1997.

08/97: The PUC opened a docket to investigate issues to be considered as a result of restructuring.

07/97: Restructuring legislation, Assembly Bill 366, was enacted. The law directed the PUC of Nevada (formally the PSC) to establish a market in which customers

had access to potentially competitive electric services from alternative suppliers no later than December 31, 1999.
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CVEC-Connecticut Valley Electric Company

NEES-New England Electricity System

PSNH-Public Service Company of New Hampshire

PUC-New Hampshire Public Utilities Commission

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04/03: Senate Bill 170 (SB 170) was enacted and stated that the Public Service of New Hampshire (PSNH) could not

sell certain fossil and hydro generation assets until April 2006.

Source: New Hampshire General Court

http://w w w .gencourt.state.nh.us/legislation/2003/sb0170.html

12/02: The Public Service of New Hampshire (PSNH), the state’s largest electric utility, agreed to buy Connecticut

Valley Electric Company’s (CVEC) franchise and electric system. The Federal Energy Regulatory Commission, the

New Hampshire Public Utilities Commission, and the Securities and Exchange Commission were scheduled to review

the sale for approval.

09/02: The New Hampshire Public Utilities Commission approved Unitil Corporation’s settlement agreement. This

agreement combined Unitil’s two subsidiaries and also provided for retail choice beginning in May 2003.

Source: Unitil Corporation

http://w w w .unitil.com/content/press/2002-09-19.asp

05/02: The New Hampshire Public Utilities Commission (PUC) enacted a four year extension to Granite State Electric customers’ transition service.

Source: New Hampshire Public Utilities Commission

http://w w w .puc.state.nh.us/regulatory/Orders/2002ORDS/23937e.PDF

05/01: The Public Service of New Hampshire (PSNH) implemented retail access on May 1, 2001, for a majority of its customers. The start date for retail access

was delayed for one month because more time was needed to secure the bonds necessary to finance PSNH's deregulation plan. Customer rates were reduced by

10 percent for PSNH customers.

04/01: House Bill 489 (HB 489) was enacted and extended the period of transition service which Public Service Company of New Hampshire (PSNH) was required

to provide 24 months after the initial transition service end day for residential, street lighting, and general delivery service rate G customers. For all other customers,

the transition service would be extended 12 months after the initial transition service end day. Also, the bill postponed the sale of certain PSNH fossil and hydro

generation assets to February 2004.

Source: New Hampshire General Court

http://w w w .gencourt.state.nh.us/legislation/2001/HB0489.html

01/01: The New Hampshire Supreme Court upheld Public Service of New Hampshire's (PSNH) restructuring plan, clearing the way for competition to begin for the

majority of consumers in New Hampshire. The PSNH planned to implement retail choice by April 2001. The plan called for a 10-percent rate reduction; standard offer

rates between 4.4 and 4.6 cents per kWh, increasing gradually over a three year transition period; and divestiture generation assets, including PSNH's interest in

Seabrook nuclear and about 1,200 MW in fossil and hydro plants.

12/00: Granite State Electric Company was granted permission to increase rates by the New Hampshire Public Utilities Commission (PUC) due to the rising costs

for natural gas and petroleum. The rate would rise from 3.8 cents/kWh to 5.6 cents/kWh, an average of 18.4 percent on a customer's bill.

10/00: Lawsuits filed by consumer groups challenged the new PSNH restructuring settlement concerning stranded costs recovery as unconstitutional. Competition

was scheduled to begin on January 1, 2001, with an accompanying rate reduction of about 10.5 percent.

10/00: Public Service of New Hampshire (PSNH) would end its pilot program on November 30, 2000. About 3,000 customers were currently part of the program as

of October 2000.

09/00: The PUC approved a settlement that resolved a three-year long dispute over the restructuring of PSNH. The settlement, which was signed into law in June

2000, called for the utility's residential customers to receive a 5 percent rate reduction on October 1, 2000. The full rate reduction would total 15.5 percent and would

happen when "Competition Day" occurred. The actual start of competition, or Competition Day, was dependent on how soon financing of the rate reduction was

completed, as well as possible legal challenges to the PUC orders by other parties. Residential rates were proposed to be capped for nearly three years, and

businesses' rates for nearly 2 years. PSNH had the ability to begin refinancing $800 million in debt to be paid off over 12 to 14 years. PSNH would divest its

generation assets by July 2001, and operate as a transmission and distribution utility, regulated by the State.

06/00: The New Hampshire Electric Cooperative voted to set their own rates and approve financing without oversight of the PUC. The PUC would continue oversight

of contracts between the cooperative and outside suppliers, IPPs, and municipal utilities as well as continuing oversight of deregulation activities and the service

territory.

06/00: Legislation was passed and signed into law that would resolve the lengthy dispute that delayed retail competition in the PSNH area. Senate Bill 472

authorized the refinancing of $800 million of PSNH debt to be paid off over 12 to 14 years. PSNH would reduce rates by an average 15.5 percent for businesses and

17 percent for residential consumers. Residential rates would be capped for nearly three years, and businesses' rates for nearly 2 years. It was further proposed that

PSNH would divest its generation assets by July 2001, and operate as a transmission and distribution utility, regulated by the State.

08/99: The PSNH filed an agreement with the PUC that could end the litigation that blocked competition in PSNH territory. Under the agreement, it was proposed

that PSNH would be allowed to recover $1.9 billion in stranded costs, and allow the issuance of $725 million in bonds to finance part of these costs (a process
www.eia.gov/cneaf/electricity/page/restructuring/new_hampshire.html 2/2

that PSNH would be allowed to recover $1.9 billion in stranded costs, and allow the issuance of $725 million in bonds to finance part of these costs (a process

known as securitization). The governor supported the agreement, and stated that "If approved by the PUC and legislature, this agreement will reduce electric rates

about 18 percent for families and businesses, open the door for electric competition, and end the costly litigation brought by PSNH that has blocked competition

and lower rates for the past two years."

07/99: House Bill 464, a law that addressed rate reduction financing or securitization, was signed into law on July 16, 1999.

04/99: Restructuring in New Hampshire was at a standstill due to Federal court rulings concerning the PUC's efforts to set stranded costs and rates for PSNH.

12/98: The US Circuit Court of Appeals ruled in favor of a lower court ruling, preventing the New Hampshire PUC from implementing deregulation, advancing PSNH's

lawsuit over the plan to trial. The trial was scheduled for February 1999.

10/98: Granite State proposed that it would begin retail choice in its service territory upon the closing of the sale of NEP's non-nuclear generation assets

09/98: New England Electricity System (NEES) completed the sale of its 18 power plants and 23 power contracts to U.S. Generating. As a result, customers of

Granite State, a NEES subsidiary, would see about a 17 percent rate reduction (including the 10 percent already realized in June). House Bill 1392 stated that

utilities should be allowed to recover net unmitigated stranded costs, and are obligated to take reasonable measures to mitigate their stranded costs.

Nonbypassable charges to consumers was recommended as the recovery mechanism (entry and exit fees were not preferred). The PUC Final Plan discussed

stranded cost recovery through divestiture of generation assets and contracts and securitization of debts.

09/98: Unitil (subsidiaries included: Concord Electric, Exeter & Hampton Electric, and Fitchburg Gas & Electric) filed its restructuring settlement agreement with

the PUC. In the agreement, Unitil would sell its New Hampshire power supply portfolio and be allowed to recover 100 percent of stranded costs over 12 years.

Customer choice was scheduled to be phased-in beginning March 1, 1999.

08/98: The PUC ruled that New Hampshire Electric Cooperative could offer customers choice if FERC approved the "interpretation of its contract" for power

purchases with PSNH.

07/98: The competition pilot program was extended beyond its original ending date in 5/98 until PSNH’s legal disputes were settled and retail competition was

scheduled to begin.

06/98: US District Court issued an order enjoining the PUC from implementing any restructuring plans until the court held a trial for the suit filed by PSNH.

06/98: Senate Bill 341, a law that addressed default and transition services, was signed into law on June 17, 1998.

06/98: House Bill 485, a net metering law, was enacted to allow customers with 25kW or less renewable generation to have the ability to utilize net metering.

06/98: The PUC gave approval to a settlement, the first in the state, with Granite State Electric to bring retail competition to the electricity market.

05/98: The New Hampshire Supreme Court heard arguments in the PSNH rate agreement case. A ruling is expected early in June 1998.

04/98: The Granite State restructuring plan was approved by PUC and the governor. Retail choice was scheduled to begin July 1998 regardless of other utilities in

the State. A 10- percent rate reduction would go into effect and, after divestiture of generation assets, a 17-percent reduction. Stranded cost recovery was set at 2.8

cents/kWh, decreasing by 50 percent once divestiture was completed.

04/98: The case brought by the PSNH was delayed by a Federal judge until November, possibly delaying the scheduled beginning of retail choice until next year.

Legislators discussed a delay to January 31, 1999, or authorizing the PUC to postpone retail choice indefinitely beyond July 1998. Public Service Company of New

Hampshire sued the state to block statewide competition centering on stranded cost recovery using market-based calculation rather than cost based.

02/98: Granite State's restructuring plan was approved; it would offer customer choice to 36,000 customers and rate cuts up to 17 percent beginning July 1998.

01/98: The PUC formally delayed the January 1998 start of retail competition to July 1998 due to the continuing litigation between the PUC and Public Service of

New Hampshire.

03/97: The Public Service Company of New Hampshire filed a complaint with The Federal District Court requesting the court enjoin the PUC restructuring plan, due

to basing stranded cost recovery on market forces rather than utility costs. The court issued a stay on the plan as it applied to PSNH.

03/97: PSNH filed a complaint in Federal District Court requesting a stay against the PUC's stranded cost recovery plan, claiming the PSNH would be forced into

bankruptcy. The stay was issued, halting implementation of the restructuring plan as it applied to PSNH. The stay was extended until a trial was scheduled and

completed.

02/97: Results of the PUC retail choice pilot program were reported and indicated that a 15 to 20 percent savings was achieved.

02/97: The PUC issued a final plan and legal analysis for restructuring the electric power industry in New Hampshire. Among the issues addressed by the plan are

market structure, unbundling electric services, stranded costs, and public policy issues such as universal service, renewable energy, and customer protections.

05/96: House Bill 1392 was enacted, requiring the PUC to implement retail choice for all customers of electric utilities under its jurisdiction by January 1, 1998 or at

the earliest date which the Commission determined to be in the public interest, but not later than July 1, 1998.

05/96: The PUC began a 2-year state-wide pilot program covering approximately 3 percent of the load served by 6 utilities.

06/95: Legislation directed the PUC to establish a statewide pilot program for retail competition for about 17,000 customers (approximately 3 percent of the State’s

consumers).
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BPU-New Jersey Board of Public Utilities

EDECA-Electric Discount and Energy Competition Act

PSEG-Public Service Electric and Gas

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02/08: The New Jersey Board of Public Utilities approved the results of the state's seventh annual electricity

auctions for Basic Generation Service. This year, the value of the fixed price auction was approximately $7.0 billion

over three years. The prices obtained in this year’s fixed price auction are higher than those obtained last year,

primarily because of increased fuel and capacity costs for the upcoming three-year supply period that were factored

into the bidders’ prices. The electricity supplies auctioned this year will replace supplies auctioned in 2005, which

were priced significantly lower. The combination of these two factors will result in an increase in overall electric

bills, ranging from 10.5 % for a typical residential or small business customer in JCP&L’s service area to 17.3 % for

one in Rockland Electric’s service area. The new rates are effective for service rendered on and after June 1, 2008.

Source: New Jersey Board of Public Utilities

http://w w w .bpu.state.nj.us/bpu/

02/06: The outcome of New Jersey’s 5 Electric Auction for basic generation service resulted in prices that were more than fifty percent higher than last year’s

auction at this time. The contracts secured through this auction process would service about one third of the power supply for utilities who participate in the basic

generation service.

Source: New Jersey Board of Public Utilities

http://w w w .state.nj.us/bpu/home/new s.shtml?05-06

09/02: Under the Electric Discount and Energy Competition Act (EDECA), rates were capped during the 4 year transition period that ended August 1, 2003.

According to a New Jersey Board of Public Utilities' (BPU) press release, BPU hired two consulting firms to audit the deferred balance accounts of Conectiv, Jersey

Central Power & Light, Public Service Electric & Gas, and Rockland Electric. "If the market price of electricity exceeds the rate caps, EDECA permits an electric

utility to recover the difference or deferred costs, provided they were incurred in a prudent and reasonable manner." The utilities stated that they had "nearly $1

billion in deferred electric utility balances."

09/02: Senate Bill 869 was enacted on September 9, 2002. SB 869 gives the Board of Public Utilities the discretionary power to allow the utilities to issue

"transition bonds." These bonds would allow Conectiv, Jersey Central Power & Light, Public Service Electric & Gas and Rockland Electric to recover nearly $1

Billion in "deferred balances" as a result of the rate cap. The Board had hired two consulting firms to audit the four utilities.

08/02: On August 30, 2002, the Deferred Balances Task Force released its report and appendices to Governor McGreevey, who established the task force with his

Executive Order on July 31, 2002. The report explained that the four-year rate caps had caused the enormous deferred balances. Under New Jersey's restructuring

legislation, ratepayers were required to repay "reasonably incurred deferred balances." The task force made five recommendations: "sign Senate Bill 869;" "apply

strong consumer protections;" "aggressively mitigate further accumulation of deferred balance;" "mandate bill inserts on educate consumers about deferred

balances;" and "examine boarder changes in EDECA," New Jersey's restructuring legislation, "and its implementation."

09/01: The latest of scheduled rate reductions under New Jersey's law that restructured the electric power industry took effect for customers of PSE&G and GPU

Energy. With the original reduction of 5 percent in August 1999, these reductions bring the total reductions to 9 percent for PSE&G customers and 8 percent for

GPU customers. By 2003, rate reductions totaling 15 percent were scheduled for all New Jersey customers.

01/01: As a result of the restructuring legislation, customers of PSE&G would receive a 2-percent rate reduction. The reduction was the result of PSE&G's sale of

$2.525 billion in securitization bonds. The law required the savings from the bonds to be passed on to PSE&G's customers. Customers received a 5-percent rate

reduction in August 1999 and are scheduled for further reductions of 2 percent in August 2001 and 5 percent in August 2002.

12/00: The New Jersey Supreme Court upheld a decision upholding the New Jersey Board of Public Utilities' (BPU) restructuring and securitization orders for

PSE&G. The decision would allow PSE&G to go forward with its implementing restructuring according to the orders issued by the BPU. Customers would receive

an additional 2 percent rate reduction and securitization bonds would be sold, amounting to $2.5 billion, the proceeds of which would retire outstanding debt and/or

equity.

08/00: Public Service Electric and Gas (PSE&G) transferred about 10,200 MW of its electric generating facilities to PSEG Power, LLC, an unregulated power

generation affiliate. The transfer was executed in compliance with a one-year time frame mandated by the BPU in its restructuring orders for the utility. The assets

were transferred at $2.443 billion.

08/00: As of August 1, the 1-year anniversary of the start of customer choice in New Jersey, the Board of Public Utilities (BPU) reported that 73,133 of the State's

3.1 million residential customers have switched suppliers. About 410,886 commercial and industrial consumers had switched suppliers. At the time, approximately

13.5 percent of the power load in the State was supplied by alternative retail suppliers.

03/00: In New Jersey, 48,000 residential customers and 19,000 businesses representing about 12 percent of the load, had switched electricity suppliers according

the BPU.

03/00: About 2 percent of the retail market in New Jersey had taken advantage of retail choice and switched their electricity suppliers, including over 50,000

residential consumers. All consumers in the State received a 5 percent rate reduction at the onset of retail choice. Some of those who had switched were seeing

reductions of up to 10 percent over last year's rates.

th
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12/99: Due to procedural delays, New Jersey consumers did not start receiving power from their suppliers of choice until November 14, 1999. Legislation was

passed in February 1999, allowing retail choice for all consumers on August 1, 1999.

08/99: Retail rates were reduced 5 percent on August 1, 1999 as required by restructuring legislation. Further rate reductions were scheduled to increase to 10

percent.

07/99: The BPU reached a final settlement agreement with Conectiv. The final plan set a schedule for rate reductions, determined stranded costs recovery and

shopping credits, and scheduled retail access implementation for November 1999.

07/99: Conectiv had received final approval from the BPU for its restructuring plan. The plan would give consumers retail choice by November 14, 1999, as the BPU

had extended the date for delivery of power from alternative suppliers to allow utilities more time to get their computer systems ready for the change. Rates were

scheduled to be cut by 5 percent on August 1, 1999, increase to 7 percent on January 1, 2001, and increase to 10.2 percent on August 1, 2002. Conectiv's

distribution rate would be 2.1384 cents/kWh. The company was allowed $800 million in stranded costs recovery. Shopping credits, the rates which outside suppliers

must compete, were set: residential credits would be 5.65 cents/kWh in 1999, 5.7 in 2000, 5.75 in 2001, 5.8 in 2002, and increase to 5.85 in 2003; commercial

rates would begin at 5.18 cents/kWh and eventually increase to 5.7 cents; industrial rates ranged from 4.95 cents/kWh and went up to 5.65, depending on voltage

and time-of-day usage.

06/99: GPU's restructuring plan for offering customers retail choice as of August 1, 1999, was accepted by the BPU. The settlement included rate reductions in

addition to the 5 percent due August 1 as required by the restructuring legislation. Customers of GPU subsidiary Jersey Central Power & Light would also receive

another 1 percent reduction in 2000, 2 percent in 2001, and 3 percent in 2002. Average shopping credits (actual credits depend on consumer class) were increased

to 5.13 cents/kWh for August 1999, 5.27 cents in 2000, 5.31 cents in 2001, 5.36 cents in 2002, and 5.40 cents in 2003. GPU would be allowed to recover $400

million in stranded costs. Originally they asked for $525 million.

03/99: New Jersey planned to launch its consumer education for electricity restructuring and retail choice program on June 1, 1999.

03/99: Public Service Electric & Gas proposed a deregulation plan to the BPU that would determine how PSE&G would operate in a deregulated environment,

which was scheduled to begin in New Jersey on August 1, 1999.

02/99: Legislation (Assembly Bill 10/Senate Bill 5) to restructure the electric power industry in New Jersey was enacted. The law allowed all consumers to shop for

their electric supplier by August 1999; reduced current rates by 5 percent, and over the next 4 years, by 10 percent; and allowed recovery of utilities' stranded costs

through a wires charge paid by consumers.

10/98: Jersey Central Power & Light began a pilot program in September 1997 for customers in the Monroe Township.

08/98: In a ruling on PSE&G’s restructuring plan, an Administrative Law Judge stated that PSE&G should recover from ratepayers most of its stranded costs and

would have to cut rates by 10-12 percent. Another ALJ issued an initial decision on Atlantic City Electric Co.’s stranded costs and unbundling filings agreeing that

stranded cost estimates were acceptable and should be recovered. Legislative and BPU approval were scheduled in order to implement the utility restructuring

plans.

05/98: The BPU announced a 6-month delay in its plan to offer retail competition. Because of this, phase-in of retail competition would be scheduled for April 1999.

07/97: Assembly Bill 2825, a tax reform bill, was enacted. The law abolished the gross receipts and franchise tax on sales of electricity and replaces it with a

corporate business tax paid by the utilities and a 6 percent sales and use tax paid by the customers on energy use. The new tax system would create tax equity

between utility companies and potential competitors in a deregulated market.

07/97: Utilities submitted filings for stranded cost recovery. A PSE&G plan estimated $3.9 billion in stranded costs and included recovery of $2.5 billion through

securitization; GPU estimated stranded costs at $1.8 billion. An initial decision by the BPU was scheduled to be due by May 1998.

04/97: The BPU issued an order adopting and releasing its final report for the Energy Master Plan. The revised plan accelerated the time line for retail competition

to begin: phase-in should have begun with 10 percent by October 1998, 35 percent by April 1999, 50 percent by October 1999, 75 percent by April 2000, and all by

July 2000.

04/97: The Energy Master Plan allowed for the potential recovery of stranded costs, but did not guarantee it. Securitization was also being considered at the time.

01/97: The BPU issued an order releasing its Energy Master Plan for public comment. The proposal called for a phase-in of retail choice that would give all New

Jersey residents and businesses the option of choosing their electricity supplier by April 2001.
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ELECTRICITY

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Other Links

New Mexico Electricity Profile

New Mexico Energy Profile

New Mexico Web Sites

Acronyms for the State of New Mexico

EPE-El Paso Electric Company

PRC-New Mexico Public Regulations Commission

PSNM-Public Service of New Mexico

PUC-New Mexico Public Utilities Commission

Home > Electricity > State Restructuring > New Mexico Restructuring

New Mexico Restructuring Suspended

Last Updated: September 2008

08/08: The New Mexico Public Regulation Commission (NMPRC) approved this week Southwestern Public Service

Company’s (SPS) request to increase its revenues up to 4.13 percent or about $10.8 million. SPS had originally

requested an increase of about $16 million or 6.34 percent. This increase is part of a proposed comprehensive

redesign of rates intended to simplify SPS’s current rate structure as well as to promote conservation.

Source: New Mexico Public Regulation Commission

http://w w w .nmprc.state.nm.us/

04/08: The New Mexico Public Regulation Commission (NMPRC) approved a 6.4 percent, or an estimated $33 million,

rate adjustment for Public Service Company of New Mexico (PNM). PNM had originally favored a 14.7 percent, or

between $77 million and $82 million, in its request to the NMPRC.

Source: New Mexico Public Regulation Commission

http://w w w .nmprc.state.nm.us/

04/03: Governor Bill Richardson signed Senate Bill 718 (SB 718) which repealed the Electric Utility Industry Restructuring Act of 1999. The legislation was

scheduled to go into effect on July 2003 and could allow utilities to recover transition cost that were incurred during the restructuring process.

Source: New Mexico Legislature

http://legis.state.nm.us/Sessions/03%20Regular/FinalVersions/senate/SB0718.pdf

10/02: Public Service of New Mexico (PSNM) submitted a stipulated agreement to the New Mexico Public Regulation Commission (PRC). The agreement proposed

a means to lower rates by 6.5 percent, repeal Senate Bill 428, the Electric Utility Restructuring Act of 1999, increase electric generation in the state, and allow

PNM to offer green power to its customers. Starting September 1, 2003, rates were scheduled to be cut by 4 percent, and another 2.5 percent by September 1,

2005.

05/01: Legislation, Senate Bill 266, was enacted and delays opening the retail electricity market to competition. Customer choice for residential customers,

originally scheduled for 2002, was delayed until January 2007 and for nonresidential customers until July 2008. Other measures of the law would delay Public

Service of New Mexico's unbundling of its distribution from its generation and marketing businesses and would allow the utility to proceed with plans to build new

generation and form a holding company.

09/00: The New Mexico Public Regulation Commission (PRC) issued its final order on rehearing case no. 3109. The order answers the question, "whether cost

(was) a factor in determining whether to require the inclusion of a renewable resource in standard offer service." The PRC decided to include the cost as a factor, but

capped the increase to standard offer service as a result of encouraging renewables at one tenth of a cent per kWh. Green power was proposed to be offered as an

option.

08/00: New Mexico's Attorney General, the New Mexico Industrial Energy Consumers, and the New Mexico Rural Electric Cooperative Association asked the PRC

to postpone a decision to authorize the state's IOUs to unbundle their operations. The groups were concerned about price spikes and supply problems in California

at the time and felt that delaying the decision would allow them to revisit restructuring issues before the state legislature convened in January 2001.

06/00: El Paso Electric filed its transition plan with the PRC, as required by June 1, 2000, under the New Mexico restructuring law. The filing detailed EPE's

operational plans for the restructured industry when customer choice would be implemented (January 2002 for schools and businesses, and July 2002 for residential

customers). The plan included estimates of transition costs, $18.2 million out of $99 million in stranded costs.

05/00: The PSNM ruled that the schools', small businesses', and residential consumers' retail access date should be delayed one year to January 1, 2002. The

delay provided utilities additional time to prepare their customer information and billing systems to accommodate customer choice. Legislation passed in April 1999

would allow direct access to be phased-in over the next 3 to 4 years.

05/00: The PRC issued code of conduct rules for public utilities and their affiliates offering retail electric services in New Mexico.

04/00: New Mexico IOUs requested the PRC delay the beginning of competition for a year, claiming they were unprepared to implement new billing and computer

systems.

09/99: The Public Service Company of New Mexico reached an agreement with the PRC to reduce its rates by over $34 million, a 6.7-percent decrease. The new

rates were scheduled to remain in effect until competition begins or until January 1, 2003, whichever came first.

04/99: The Electric Utility Restructuring Act of 1999, Senate Bill 428, was enacted on April 8, 1999. The law would open the state's electric power market to

consumer choice beginning in 2001, when residential and small consumers were scheduled to have retail access. All other consumers were scheduled to have retail

access by January 2002. The law split the responsibility for stranded costs between consumers and stockholders, allowing utilities to recover at least 50 percent of

stranded costs through charges to consumers over a five year period.

03/99: The State Supreme Court ruled that the New Mexico Public Utilities Commission exceeded its authority when it ordered the Public Service of New Mexico to

open its power lines to a competitor. The competitor plans to ask the court to address the matter again.

09/98: The Public Service of New Mexico, under order of the New Mexico Public Utilities Commission at the time, would conduct a pilot program with its
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09/98: The Public Service of New Mexico, under order of the New Mexico Public Utilities Commission at the time, would conduct a pilot program with its

Albuquerque customers. About 16 MW of PSNM’s load would open to competition in December 1998. PSMN opposed the order.

02/98: New Mexico PRC submitted legislative language to the legislature and Governor that would give PUC authority to resolve deregulation issues. At the time,

the PUC was pushing for retail competition.

01/98: The PUC issued its restructuring report to the legislature. The report called for full retail competition by January 2001 and for legislative adoption of rules by

July 1999. The report also stated that $60 million/year could be saved.

09/97: Public Service of New Mexico submitted a restructuring plan to the PUC. The plan proposed open access for all consumers by January 2001, unbundling of

services, and recovery of stranded costs using nonbypassable wires charges, exit fees, and securitization.

03/97: The PUC approved Texas-N.M. Power’s “Community Choice” plan to introduce customer choice by 1998 through a pilot program. The program was

scheduled to begin in May 1998.
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ELECTRICITY

OVERVIEW DATA ANALYSIS & PROJECTIONS GLOSSARY › FAQS ›

Other Links

New York Electricity Profile

New York Energy Profile

New York Web Sites

Acronyms for the State of New York

LIPA-Long Island Pow er Authority

NIMO-Niagara Mohaw k Pow er Corporation

NYISO-New York Independent System Operator

O&R-Orange and Rockland Utilities Incorporated

PSC-New York Public Service Commission

RG&E-Rochester Gas and Electric

Home > Electricity > State Restructuring > New York Restructuring

New York Restructuring Active

Last Updated: September 2008

07/08: The New York State Public Service Commission adopted a three-year rate plan for Orange and Rockland

Utilities, Inc.’s (O&R) electric delivery service. Rates for the company’s electric delivery service have not been

increased generally since 1993. The Commission today authorized O&R to increase rates for electric delivery services

in order to generate incremental annual electric revenues of nearly $15.6 million in each of the three rate years ending

June 30, 2009, 2010, and 2011. This amount results in an increase in total company electric revenues of approximately

2.5 percent per year.

Source: New York State Public Service Commission

http://w w w .dps.state.ny.us/

08/04: The New York Public Service Commission (PSC) issued a proceeding related to “Further Steps Toward

Competition in Retail Energy Markets.” In the proceeding, the PSC suggested methods by which utilities could adopt

standards to encourage retail competition.

Source: New York State Public Service Commission

http://w w w 3.dps.state.ny.us/pscw eb/WebFileRoom.nsf/Web/F4746B665D1C642685256EFB00622E91/$File/201a.00m0504.pdf?OpenElement

09/02: A Governor's press release was released and stated that, "Governor Pataki signed net metering legislation that would encourage farmers to sell excess

electricity generated through the use of anaerobic digesters to utilities. Net metering laws already exist for electricity generated by solar panels on homes. The new

legislation would expand those laws to include technically qualified farms as potential "net metering" customers who generate power from methane."

01/02: Retail competition was fully implemented in Long Island and seven years ahead of schedule. According to the Public Authorities Control Board buyout, Long

Island Power Authority was required to phase-in retail competition by 2008. The LIPA purchased Long Island Lighting Company's transmission and distribution

system and electric retail operations in May 1998, and reduced electricity rates by an average of 20 percent. In 1999, 400 MW was open to retail access and

another 400 MW in 2000. The "shopping credit," used for comparing retail marketers' prices, was increased from 3.5 to 4.5 cents/kWh, giving energy supply

companies more incentive to participate in LIChoice. At the time, retail marketers were supplying 220.4 MW to 38,039 residential and commercial customers.

06/01: The New York Public Service Commission approved standards governing the electronic exchange of routine business information and data among electricity

and natural gas service providers in New York. The PSC also issued an order to establish uniform retail access billing and payment processing practices that would

facilitate a single bill option for customers who buy power and/or natural gas from ESCOs. The orders were designed to facilitate retail energy competition in New

York and provide for efficient single-billing options for all New York electricity and natural gas customers.

05/01: The New York Public Service Commission approved Consolidated Edison Company's rate reduction plan. Beginning April 1, delivery rates were scheduled to

be reduced by $208 million for all Con Edison customers. Phase 4 of Con Edison's Retail Electricity Choice program was also approved by the PSC, beginning May

1. Con Edison's competitors could implement small credits as part of their marketing strategy to attract customers. The credit was based on the amount Con

Edison saved by not having to provide electricity to customers who switch to alternative suppliers. Also, ConEd would provide a one-time $65 incentive for each new

customer that switched to a competitive supplier. In order to be eligible at the time, the supplier must have shared the payment with the customer, and the customer

must have been with the supplier for at least three consecutive billing cycles.

03/01: The PSC approved rules for customers in New York State Electric & Gas territory to receive a credit for switching to a competitive electricity supplier. The

old "shopping credit" was set, at 3.71 cents per kilowatt-hour, below market prices. Competitors could not beat that price with market prices consistently being

higher. The new "shopping credit" would be tied to the going market price plus a small amount for administrative costs, making it easier for competitors to deal with

wholesale prices that fluctuate seasonally.

12/00: The New York Public Service Commission staff released a report recommending modifications in the operation of the New York Independent System

Operator. The report recommended a hard cap of $150/MWh and the power to order retroactive refunds. FERC was scheduled to approve the recommendations

before they would become an order.

09/00 U.K. based National Grid Group PLC announced that it would purchase Niagara Mohawk, New York's second largest electric and gas utility, for $3 billion in

stock and cash and the assumption of $5 billion in debt. The deal would require approval from New York regulators, the Securities and Exchange Commission

(SEC), the Federal Energy Regulatory Commission (FERC), and several other regulatory bodies.

08/00: The PSC approved Niagara Mohawk's plans to reduce delivery prices for the third year as part of its 5-year price reduction and restructuring plan of

September 1998. The delivery price reduction, which was scheduled to be implemented on September 1, 2000, would total nearly $19 million. Residential and small

commercial customers were scheduled to see an average delivery price reduction of about 1.5 percent when compared to September 1, 1999 pricing, and the

largest industrial customers were scheduled to see reductions of about 1.9 percent.

08/00: Dynegy announced the intent to purchase two generating facilities totaling 1,700 MW for $903 million. The facilities included a 500-MW plant owned by

Central Hudson Gas & Electric and a 1,200-MW station jointly owned by Central Hudson Gas & Electric, Con Edison, and Niagara Mohawk. Both facilities were

located in Newburgh, NY. The transaction was expected to close during the first quarter of 2001, pending federal and state regulatory approvals.

04/00: The PSC approved a "floating shopping credit" proposed by ConEd. The shopping credit was proposed to reflect prices published by the NYISO in the

differences between actual and market-based costs would be shared 90/10 between the ratepayers and the stockholders.
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differences between actual and market-based costs would be shared 90/10 between the ratepayers and the stockholders.

12/99: A competitive supplier, NYSEG Solutions, offered Niagara Mohawk Power Corporation (NIMO) residential customers a choice in generation supplier.

08/99: Niagara Mohawk received approval to reduce prices for the second consecutive year, beginning September 1, 1999. The price reductions were part of NIMO's

PowerChoice Plan. Average reductions for residential and small commercial consumers were proposed to be about 1 percent in addition to the approximate 0.8

percent affected last year. Another reduction scheduled for September 1, 2000, was scheduled to achieve overall reductions of about 3.2 percent. Industrial

customers would receive larger reductions. Total savings for all customer classes under the three year Power Choice Plan was proposed to be about $600 million.

08/99: Numerous large business customers in LIPA's Choice Program began receiving power in August from an alternative supplier, ConEdison Solutions. ConEd

Solutions was supplying about 20 MW of power to over 100 facilities on Long Island at the time.

04/99: Phase II of ConEd's retail choice program began in April. Nearly 22,000 new customers were enrolled, bringing the total customers in the programs to more

than 68,000 at the time.

02/99: A briefing paper was issued from the New York General Assembly that criticized the piecemeal PSC process of restructuring. It listed five criteria that the

PSC plan had failed on in restructuring the industry.

02/99: The PSC ordered utilities to submit monthly reports in 1999, and quarterly reports thereafter, to monitor competition. The reports would contain the number

of consumers eligible to participate, the number of kWh eligible for retail access, the number of consumers per ESCO in the utility's operating territory, and the

number of kWh provided by each ESCO.

01/99: The governor withdrew a tax break for customers who chose an alternative generation supplier, resulting in a 4 percent increase in rates for customers who

were "choosing."

12/98: ConEd began Phase II of its customer choice program. Enrollment of customers to exercise retail choice was scheduled to begin January 1999.

11/98: Orange & Rockland (O&R) and ConEd proposed to sell 16 power plants (about 1,776 MW of gas, oil, and hydro capacity) in New York to Southern Company

for $480 million.

11/98: NYSEG proposed to sell its fossil fuel-fired generation to AES (6 coal plants for $950 million) and Edison International (Homer City Station for $1.8 billion).

11/98: The PSC ordered utilities, beginning in 4/00, to inform customers of the sources of their electricity and their amount of environmentally "clean" power.

11/98: Long Island Power Authority began retail access for 400 MW of load in January 1999 with a target of August for delivery of power from competitive providers.

The first phase of direct access was split between residential (180 MW), commercial, and government consumers. Phase II was scheduled to open another 800 MW

in May 2000. All customers of LIPA were scheduled to have retail choice by January 2003.

06/98: The PSC set rules for a Systems Benefit Charge to fund R&D related to energy service, storage, generation, the environment, and renewables; pilot

programs for energy management for low-income consumers; and environmental protection.

05/98: Due to over-subscription of ConEd's Phase I for retail competition, the load for residential and small commercial customers was doubled to 1000 MW; a

lottery was scheduled to be conducted for large customers. Customers were also scheduled to begin receiving power from their suppliers of choice among more

than 20 registered ESCO's on June 1.

05/98: Orange and Rockland became the first utility in New York to offer retail choice through its Power Pick program as customers began to receive power from

their suppliers of choice on May 1, 1998.

02/98: Assembly Bill 7942-D was introduced by Senator Tonko to provide an alternative deregulation plan to the PSC, saying the current PSC plan did not go far

enough to protect consumers. The bill called for competition in electric generation no later than March 1, 2000 for all consumers, including municipal systems and

10 percent rate cuts by September 1998.

02/98: The PSC approved Niagara Mohawk’s plan for rate restructuring, a nonbypassable CTC to fund $3.6 billion in debt for settlement with 16 independent power

producers to restructure uneconomic contracts, and divestiture of fossil-fueled and hydroelectric plants. Retail competition was scheduled to begin in 1998 for large

customers and be available to all customers by January 1, 2000.

02/98: The PSC approved a restructuring plan for Central Hudson Gas & Electric. The plan required divestiture of fossil-fueled plants, a rate freeze until June 30,

2001, rate reductions, and transition to full retail competition by July 2001.

01/98: The PSC approved New York State Electric & Gas’s restructuring plan. The plan included a phase-in of retail competition for small industrials beginning

August 1998, full retail competition by August 1999, a rate freeze and rate cuts, and divestiture of its coal plants by August 1999.

01/98: The PSC approved Rochester Gas & Electric's restructuring plan. RG&E proposed beginning the restructuring process in July 1998 with open access for 10

percent of its customers and phase-in full retail access by July 2001. Divestiture of fossil-fueled and hydro plants and rate cuts were also included in the plan.

12/97: The PSC settled Orange and Rockland's proposal for restructuring. O&R was scheduled to phase-in retail competition beginning May 1998, allow full retail

competitive by May 1999, provide rate cuts, and require divestiture of generation assets by May 1999.

09/97: The PSC approved ConEd's restructuring plan. The plan called for rate cuts, retail competition to phase-in beginning June 1998, and full retail access by

December 2001. In addition, ConEd would file by January 1998 unbundled tariffs for all classes of customers, to become effective April 1998. The plan also called for

divestiture of at least 50 percent of ConEd's New York City fossil-fueled generation by the end of 2002.

06/97: The PSC approved a pilot program for more than 17,600 qualified farmers and food processors, beginning in 11/97.

07/96: The PSC approved O&R's pilot program, "Power Pick," that, if enacted, would allow industrial consumers retail access to competitive generation suppliers.

The program was scheduled to begin 5/98.

05/96: The PSC issued its opinion and order regarding competitive opportunities for electric service that restructured New York's electric power industry. The

Competitive Opportunities Case adopted the goal of having a competitive wholesale market by 1997, and a competitive retail market by early 1998. Electric utilities

were required to submit restructuring plans by October 1996. It also stated that utilities should have a reasonable opportunity to recover stranded costs consistent

with the goals of restructuring.
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ELECTRICITY

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North Carolina Electricity Profile

North Carolina Energy Profile

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Acronyms for the State of North Carolina

NCUC-North Carolina Utilities Commission

RTI-Research Triangle Institute

Home > Electricity > State Restructuring > North Carolina Restructuring

North Carolina Restructuring not Active

Last Updated: April 2007

03/02: The North Carolina Utilities Commission (NCUC) issued an interim report regarding the Investigation of Green

and Public Benefit Fund Voluntary Check-Off Programs to the Study Commission on the Future of Electric Service in

North Carolina. According to the report, the NCUC requested "that the Commission continue to work with the

stakeholders to implement a statewide green power program for North Carolina," but "not adopt a voluntary public

benefit fund check-off program at this time." The Commission wanted to concentrate voluntary contributions on green

power because public benefit programs were already successful and well established at the time.

02/01: The North Carolina Utilities Commission issued an order that initiated an investigation "on the creation of

voluntary "green" and "public benefit fund" check off programs." The NCUC was scheduled to issue a report to the Study Commission on the Future of Electric

Service. A hearing would be held on April 3, 2001 to discuss the comments of the Carolina Power & Light Company, Duke Power, Dominion North Carolina Power,

North Carolina Electric Membership Corporation, ElectriCities of North Carolina, Inc.

01/01: The legislation study panel decided more study of restructuring issues was needed before recommending to the legislature to open the state to competition

by 2005, as previously recommended. The studies would focus on consumer protections and ways to encourage power plant construction in the State.

12/00: The Utilities Commission staff issued its comments, recommending a limited deregulation plan to a legislative panel. The legislative panel had been working

for two years and was scheduled to present recommendations on restructuring to the General Assembly by January 2001. In light of California's market dysfunction,

the Utilities Commission recommended that restructuring in North Carolina proceed slowly and with caution. Also, a representative for ElectriCities, which

collectively had $5.5 billion in debt and were concerned about their ability for repayment under restructuring, recommended to the legislative panel that no

restructuring take place until the Commission could demonstrate that there would be a benefit for consumers.

09/00: The Study Commission on the Future of Electric Service in North Carolina wanted to draft a model restructuring bill to submit to state legislators when the

next General Assembly session started in January 2001. At a commission meeting, several panel members suggested that the commission look into this summer's

price spikes in California before proceeding.

07/00: House Bill 1840 provided funding for the Study Commission on the Future of Electric Service in North Carolina until June 30, 2006.

07/00: House Bill 1593 allowed the Study Commission to report periodically to the General Assembly until June 30, 2006.

07/00: Senate Bill 1385 added a 30th member to the Study Commission, the Chief Executive Officer of North Carolina Power Company or the Chief Executive

Officer's designee.

04/00: The Study Commission issued its final report with recommendations to open retail electricity markets to half of consumers by January 2005, and the other

half by January 2006. The study also recommended a rate freeze until January 2005 to allow utilities to pay down stranded costs and implementation of a public

benefit fund for low-income, renewable energy, and energy efficiency programs. The issue of municipals' stranded costs was not addressed. Legislators were

scheduled to review the Study Commission's recommendations in the 2000 short session, and consider enacting restructuring legislation in the longer 2001

session.

03/99: Research Triangle Institute issued a final report to the NCUC as part of its ongoing investigation into electric power industry restructuring. The RTI reports

contained recommendations for a restructured electric industry including: potential distribution reliability problems, forming a regional transmission group,

certification of all electricity suppliers, and consumer safeguards. The final report on stranded costs analyzed four options for ensuring fairness to the consumers

and the utilities, especially the municipals. Municipals in North Carolina had a total bond debt of approximately $5.8 billion at the time, much of it in relatively

expensive nuclear generation.

08/98: At a "Mayor's Day" event, mayors and city officials urged the legislature to pass restructuring legislation to prevent large industrials from relocating and thus

protect the economies of North Carolina cities and the State.

07/98: Research Triangle Institute produced a report for the Study Commission on the Future of Electric Service in North Carolina that summarized the rate

disparity between publicly owned and private utilities in the State. The report recommended the Legislature pass deregulation legislation in 1999.

05/98: House Bill 778 added six members to the Study Commission, three members of the State House of Representatives and three members of the State

Senate.

11/97: The Study Commission commenced its work to investigate restructuring in North Carolina and determine whether legislation was needed. Reports were due

to the General Assembly in 1998 and 1999.

09/97: The NCUC reopened electric restructuring Docket concerning emerging issues in the electric industry.

04/97: Senate Bill 38 established a 23-member Study Commission on the Future of Electric Service in North Carolina. A report was due by 1999 to the legislature.
www.eia.gov/cneaf/electricity/page/restructuring/north_carolina.html 2/2
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01/99: Senate Bill 2389 was enacted and added new language to House Bill 1237. It stated that the committee's study must

determine "whether to grant a public utility a certificate of public convenience and necessity to extend its electric lines and

facilities to serve customers outside the corporate limits of a municipality and....under which a rural electric cooperative may provide electric facilities and service to

new customers and existing customers within municipalities being served totally or primarily by a public utility." The Act was effective from August 1, 1999 to July

31, 2001. No restructuring legislation was introduced in 1999, and the legislature was scheduled to meet again in 2001 (meets every other year).

11/98: The Electric Utilities Committee submitted its report to the legislature. The report stated that restructuring efforts shouldn't proceed until potential tax issues

were considered.

02/98: North Dakota Electric Utilities Committee met and discussed tax implications of restructuring and electric rates of investor-owned and cooperative utilities.

07/97: The first meeting of The Electric Utilities Committee was completed. A final report was due November 1998.

03/97: House Bill 1237 was enacted to create a Legislative Study Committee on Electric Industry Competition. Committee work was scheduled to be completed by

August 1, 2003.
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AEP-American Electric Pow er

CG&E-Cincinnati Gas and Electric Company

CRES-Certified Retail Electric Supplier

DP&L-Dayton Pow er and Light Company

FERC-Federal Energy Regulatory Commission

ISO-Independent System Operator

OCC-Ohio Consumers' Counsel

PUCO-Public Utilities Commission of Ohio

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08/09: Dominion Energy offered the first twenty-five thousand Duke Ohio customers who sign up by September 30, 2009

a fixed electric rate of 6.88 cents per kilowatt hour through December 2010. This fixed rate is approximately 20 percent

less than the incumbent Duke Energy’s current electric rate price of 8.61 cents per kilowatt hour. The lower Dominion

Energy rate would apply only to the electricity consumed portion of a customer’s total electricity bill.

Source: The Enquirer/Cincinnati.Com

http://new s.cincinnati.com/

01/09: The Public Utilities Commission of Ohio voted to allow utility surcharges for FirstEnergy Corporation to expire. The

utility surcharges were originally put in place to allow Ohio electric utilities to recoup some of the costs incurred during

preparation for electricity deregulation that never occurred.

Source: The Public Utilities Commission of Ohio

http://w w w .puco.ohio.gov/

05/08: Following up on 2007's announced "Energy, Jobs, and Progress" plan for Ohio, Governor Ted Strickland signed

into law Senate Bill 221 (SB 221 or "the Act") on May 1, 2008. Under this new law, the regulatory structure for electric

public utility companies is significantly revised and new policies for the development of advanced and renewable energy

are put forward. The new law authorizes The Public Utilities Commission of Ohio (PUCO) to establish rules ensuring

electric price stability. Investor-owned utilities (IOUs) will file an Electric Security Plan (ESP). The electric price

established by a PUCO-approved ESP will consider generation and transmission charges as well as the cost for

care/maintenance and further development of local distribution infrastructure. IOUs will have the option to establish

electric pricing using a PUCO-approved competitive auction process, known as a Market Rate Offer (MRO). If the established MRO price is lower than the utility's

ESP price, the company can proceed under a PUCO–approved transition process to the market rate. The PUCO has authority to test a utility's rate plan to ensure

that prices paid by consumers are fair and equitable, as well as check to see if rates are generating excessive earnings for the utility. The PUCO can order

appropriate rate corrections, refunds, or establish new rate plans to correct pricing issues. Counties, townships and municipalities wanting to establish community

aggregation plans for the purchase of electric power have new options that help reduce utility standby charges. More communities could use aggregation to create

cost-effective electric rates. S.B. 221 requires 25 percent of electricity sold by Ohio's IOUs must come from renewable, clean coal and advanced nuclear sources by

2025. At least half of the minimums must be met by renewables and at least half of all power to meet the standard must come from Ohio-based projects.

Source: Legislative w ebsite

http://w w w .legislature.state.oh.us/analysis.cfm?ID=127_SB_221&ACT=As%20Enrolled&hf=analyses127/08-sb221-127.htm

Source: Ohio Farm Bureau Federation

http://ofbf.org/policy-and-politics/victories/7/

03/06: The Supreme Court of Ohio ruled that FirstEnergy’s auction plan was in violation of the 1999 retail choice legislation because FirstEnergy had not provided

an alternative choice to its customers.

Source: The Supreme Court of Ohio

http://w w w .supremecourtofohio.gov/Communications_Office/summaries/2006/0503/041993.asp

08/05: The Public Utilities Commission of Ohio (PUCO) issued a report showing the progress of The Ohio Retail Electric Choice Program. The report covered the

progress that had been made in the area of retail choice since 2002. Key developments were as follows:

• In the residential market, the megawatthours (MWh) sold by alternative electric suppliers grew from 60 to 73 percent in the Cleveland Electric Illuminating

Company territory, from 36 to 43 percent in the Toledo Edison Company territory, from 22 to 30 percent in the Ohio Edison company territory, and from 2 to 5

percent in the Cincinnati Gas and Electric Company territory.

• In the commercial market, the MWh sold by alternative electric suppliers grew from 50 to 61 percent in the Cleveland Electric Illuminating Company territory, from

38 to 42 percent in the Ohio Edison Company territory, from 32 to 38 percent in the Cincinnati Gas and Electric Company territory, and from 9 to 19 percent in the

Dayton Power and Light Company. These numbers dropped slightly from 51 to 49 percent in the Toledo Edison Company territory and from 6 to 4 percent in the

Columbus Southern Power Company territory.

• In the industrial market, the MWh sold by alternative electric suppliers grew from 28 to 64 percent in the Dayton Power and Light Company territory, from 18 to 20

percent in the Cleveland Electric Illuminating Company territory, from 9 to 18 percent in the Cincinnati Gas and Electric Company territory, and 4 to 5 percent in the

Toledo Edison Company territory. This number dropped slightly from 32 to 29 percent in the Ohio Edison Company territory.

Source: Public Utilities Commission of Ohio

http://w w w .puco.ohio.gov/emplibrary/files/media/publications/electricreport2005.pdf

01/03: The Ohio Consumers’ Counsel (OCC) published its 2002 End-of-Year Update on Ohio’s Electric Market that reviewed the past two years of competition in

Ohio. According to the report, “813,000 residential consumers statewide – or about 20 percent of those who were eligible to participate in electric choice-actually

switched electric suppliers.” Most of those customers participated in community aggregation groups. At the time, Cleveland Electric Illuminating had the highest

percentage of customers who switched to an alternative supplier.

10/02: The Public Utilities Commission received Dayton Power & Light’s proposal to extend its current generation rate freeze from December 31, 2003 to December

31, 2005.

10/02: Dominion Retail Inc., a licensed retail electric supplier by the Public Utilities Commission of Ohio, was offering one-year contracts to residential customers
www.eia.gov/cneaf/electricity/page/restructuring/ohio.html 2/3

10/02: Dominion Retail Inc., a licensed retail electric supplier by the Public Utilities Commission of Ohio, was offering one-year contracts to residential customers

of Cinergy’s Cincinnati Gas and Electric Company’s (CG&E). The contracts were proposed to end in December 2003, but the offer would expire on November 29,

2002. Dominion’s limited time offer was for 4.70 cents per kilowatt-hour, which was approximately 10 percent below CG&E’s current price to compare of 5.22 cents

per kilowatt-hour.

09/02: The Ohio Consumers' Counsel along with the Industrial Energy Users - Ohio and the American Municipal Power - filed a complaint against Dayton Power

and Light for violating the Electric Choice Law. According to an OCC press release, "DP&L had failed to comply with a PUCO order to transfer operational control of

its electric transmission facilities to a Federal Energy Regulatory Commission (FERC) - approved Regional Transmission Organization." These organizations filed a

similar complaint against American Electric Power (AEP) in June 2002.

07/02: The Ohio Consumers' Council (OCC) released its "Summer 2002 Electric Market Update," which stated that "progress towards meaningful electric choice for

the state's residential consumers had begun to stall." In central and southern Ohio, two competitive residential suppliers existed until New Power declared

bankruptcy. The other supplier at the time, an affiliate of FirstEnergy, "has restricted its activity to FirstEnergy's traditional service territory in northern Ohio." Many

Ohio residential customers did not have the opportunity to participate in retail competition, and community aggregation had been the primary option.

06/02: The PUCO issued their first quarter "switching statistics," summaries of electric customer choice switch rates in terms of sales and customers, for 2002. In

terms of customers, 52.58 percent of residential Cleveland Electric Illuminating Company customers switched to a certified retail electric supplier (CRES) while

18.36 percent of commercial and 24.34 percent of industrial customers switched. Toledo Edison Company had 45.84 percent of residential customers, 3.43 percent

of commercial customers, and 20.66 percent of industrial customers switch to a CRES. Ohio Edison Company had 16.43 percent of residential customers, 8.54

percent of commercial customers, and 30.90 percent of industrial customers switch to a CRES. Cincinnati Gas and Electric Company, Columbus Southern Power

Company, and Dayton Power and Light Company had less than 1 percent switch to a CRES. No Monongahela Power Company or Ohio Power Company customers

were participating in the Ohio Electric Choice program at the time.

06/02: According to a press release, Allegheny Energy Supply, a subsidiary of Allegheny Energy, Inc., sold "approximately 45,000 residential and commercial

accounts in FirstEnergy's northern Ohio service territory" to Dominion Retail, Inc., a subsidiary of Dominion. Dominion Retail would replace Allegheny Energy

Supply as the customers' certified retail electric supplier, but customers "would continue to receive one bill from their local utility."

06/02: The Triad Research Group completed its 2002 Research Report for the Public Utilities Commission of Ohio as part of the Ohio Electric Choice campaign.

According to this annual market survey, customers were more supportive and knowledgeable of electric choice because of the increase in advertising. However,

customers were less interested and concerned about the “reliability of electric service.” Of the customers surveyed, “only 5.1% reported switching suppliers, while

one-quarter (25.9%) had decided to not switch.”

04/02: The Public Utilities Commission of Ohio (PUCO) released The Ohio Retail Electric Choice Programs Report of Market Activity for the Year 2001 to the Ohio

General Assembly. The report summarized "the market activity during the first year of Ohio's retail electric choice program." According to the report, the Cleveland

Electric Illuminating Company had 50 percent of its customers switch to alternative suppliers. 15 percent of Ohio Edison's customers switched, and over 4 percent

of Toledo Edison's customers chose another electric supplier. While Cincinnati Gas and Electric, Columbus Southern Power, Dayton Power and Light had less than

1 percent of its customers switch. No Monongahela Power or Ohio Power customers switched during 2001.

01/02: The Ohio Consumers' Counsel released the first report card for Ohio's electric choice program. Overall, the OCC said electric customers were "better off than

they were before electric choice." About 15 percent of eligible customers switched electric suppliers in 2001, mainly former customers of the three FirstEnergy

companies. In northern Ohio, 158 communities aggregated their load and chose an alternative supplier. The counsel recommended that the state work out a plan to

attract more alternative suppliers in less competitive areas of the state; issue competitive bidding rules at the end of the transition period; develop more conservation

and energy efficiency programs and policies; and implement a regional transmission organization. On the federal level, the counsel recommended monitoring

mechanisms to curb market power and guaranteeing adequate wholesale power reserves.

09/01: The PUCO adopted rules for local government aggregation of electricity customers. Under Ohio's restructuring legislation passed in July 1999, local

governments could serve as an aggregator for electricity customers. The new rules focused on three issues: Cooperation of the utilities in providing lists of the

customers in the local government's jurisdiction, forming programs for customers to "opt-out" of the aggregation, and the requirements for providing customers with

written notices of inclusion in the aggregation unless the customer specifically "opted-out."

01/01: Retail direct access to competitive electricity suppliers began on January 1, 2001, in the State. The first month saw about 97,622 customers in First Energy

territories switch suppliers. Standard Offer Rates ranged from 3.6 to 4.9 cents/kWh in the three FirstEnergy subsidiary territories of Toledo Edison, Ohio Edison,

and Cleveland Illuminating.

12/00: Beginning January 1, 2001, Ohio residential, commercial, and industrial consumers were scheduled to have access to retail markets for electricity.

Consumer education programs were available on the Ohio Electric Choice web site, through mass mailing by the PUCO, and by telephone.

10/00: Allegheny Energy's (parent of Monongahela Power) restructuring plan was approved by the Public Utilities Commission of Ohio (PUCO). Competition and a 5

percent residential rate reduction were scheduled to begin January 1, 2001. Rates would be frozen through the development period, which was proposed to be 2003

for large industrial consumers and 2005 for residential consumers.

10/00: American Electric Power's (parent company for Ohio Power and Columbus Southern Power) restructuring plan was approved by the PUCO. Retail

competition was scheduled to begin January 1, 2001, with residential consumers receiving a 5 percent rate reduction. More than $600 million in transition costs

were proposed to be collected through 2007 (for Ohio Power) and 2008 (for Columbus Southern Power). Certain residential customers would have transition charges

waived. Also, rates would be frozen through the development period or 2005, whichever came first. Shopping credits, incentives and switching procedures would also

be provided, and AEP agreed to absorb $40 million of customer education, customer choice implementation, and transition plan filing costs.

10/00: Dayton Power and Light's (DP&L) transition plan to begin retail competition for all customers by January 2001 was approved by the PUC. Under the

agreement, DP&L generation rates would be capped until the end of the recovery period when transition costs were scheduled to be fully recovered, December 31,

2003. Transmission and distribution rates would be capped through the end of 2006. The plan included a 5 percent residential rate reduction to the generation

portion for customers who remain with DP&L, beginning January 1, 2001. Additionally, DP&L would pay up to $1 million for a voluntary enrollment procedure if at

least 20 percent of its customers had not chosen another supplier by September 30, 2003.

09/00: The PUCO approved the Cincinnati Gas & Electric (CG&E) restructuring plan. Retail electric choice was proposed to be offered beginning January 1, 2001.

The price of electricity would be unbundled into its components (generation, transmission, distribution), and a rate cap would be in effect for five years for all

residential customers. Additionally, residential customers who stay with their current supplier would receive a 5 percent rate reduction in the generation portion of

their bill.

07/00: An agreement was reached on AEP's transition plan. Transition costs recovery would be limited through 2007 for Ohio Power consumers and 2008 for

Southern Power consumers. Distribution rates would also be frozen for the recovery period for residential consumers.

07/00: First Energy's (Ohio Edison, Toledo Edison, and The Illuminating Company) restructuring plan was approved by the PUCO. The plan called for recovery of

transition costs through 2006 for Ohio Edison, mid-2007 for Toledo Edison, and 2008 for Illuminating Company. Competition was scheduled to begin January 1,
www.eia.gov/cneaf/electricity/page/restructuring/ohio.html 3/3

2001, and residential consumers would receive a 5 percent rate reduction on the generation portion. Distribution rates were scheduled to be frozen through 2007.

07/00: Allegheny Energy reached a settlement on its transition plan. The plan called for recovery of up to $6.3 million in stranded costs, 5-percent rate reductions

for residential consumers, and a 3-year rate freeze for industrial and commercial consumers.

07/00: Monongahela Power reached a settlement on its restructuring plan. The plan would shorten the development period for competition for large customers to

end December 31, 2003, and for small customers, December 31, 2005. Residential customers would also receive a 5-percent rate reduction, and rates would then

be frozen for the remainder of the development period.

01/00: AEP (Ohio Power and Columbus Southern Power) filed its transition plan with the PUCO. The plan included a requested recovery of $974 million in

regulatory assets.

01/00: Monongahela Power filed its transition plan with the PUCO. Included was a request for $13 million in stranded cost recovery.

01/00: Cincinnati Gas & Electric filed its transition plan with the PUCO. The plan included: 5 percent residential rate reduction in the generation portion of rates,

effective January 2001; rate unbundling into the generation, transmission, distribution, and transition costs components; recovery of $927 million in transition and

stranded costs; corporate separation of regulated and unregulated functions; participation in the MidWest ISO; and a consumer education plan. The PUCO was

scheduled to rule on the plan before Oct. 31, 2000.

01/00: Dayton Power & Light filed its transition plan with the PUCO. The plan included a 5 percent residential rate reduction for generation; a cap on all prices

through December 31, 2004; customer choice by January 1, 2001; recovery of $441 million in transition costs; and a consumer education program. The PUCO was

scheduled to issue comments and recommendations related to the plan within 90 days, and a final order within 275 days.

01/00: First Energy (Ohio Edison, The Illuminating Company, and Toledo Edison) refiled a transition plan with the PUCO to conform to the new rules established to

comply with Ohio’s restructuring law. The plan included: requested recovery of $7 billion for transition and stranded costs; operational and technical support

changes to allow for retail direct access by January 1, 2001; plans to transfer control of transmission assets to the Alliance RTO; unbundled prices; corporate

separation of regulated and unregulated business; and an education program for consumers.

10/99: The PUCO issued an initial set of rules for transition to a competitive retail market. The draft rules included provisions for recovery of stranded costs,

corporate unbundling, consumer education, and employee protections.

10/99: FirstEnergy filed a restructuring plan with the PUCO. The plan included passing $6.9 billion to customers over 8 years, but said bills would not increase over

the transition period. Three separate plans were filed for its subsidiary utilities: Ohio Edison, Illuminating Co., and Toledo Edison.

07/99: The restructuring legislation, Senate Bill 3, was signed into law by the governor on July 6, 1999. The legislation would allow retail customers to choose their

energy suppliers beginning January 1, 2001. The new law required 5 percent residential rate reductions and a rate freeze for 5 years, contains consumer protections,

environmental provisions, and labor protections, and empowers the PUCO to determine the amount and recovery period for stranded costs. Also, the property tax

utilities paid in the past was replaced with an excise tax on consumer bills. Utilities were required to spend $30 million over the next six years on consumer

education programs.

06/99: The restructuring legislation would allow retail customers to choose their energy suppliers beginning January 1, 2001. It also would require a 5 percent

residential rate reduction and a rate freeze for 5 years.

08/98: A lawsuit aimed at blocking conjunctive service regulations was thrown out of court. Because of this, the PUCO would move ahead with plans for a

conjunctive billing service.

06/98: The PUCO approved Monongahela's tariff for conjunctive electric service, the first tariff approved that would allow groups of consumers to aggregate and

negotiate the price for electricity.

12/97: Stranded costs were addressed in the report issued by the co-chairs of the Legislative Joint Committee on Electric Deregulation. The plan allowed for

recovery of stranded costs using nonbypassable wires charges. Utilities would be allowed during the 5-year transition period beginning January 2000 and ending

December 2004 to receive “transition revenues” or stranded costs under certain conditions, but would likely expect less than 100 percent of recovery.

12/96: The PUCO adopted guidelines for Conjunctive Electric Services. The 2-year pilot program would allow ratepayers to band together for collective billing under

rates designed for the group. (The pilot was an experiment in innovative pricing, and did not allow for retail wheeling.)
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01/06: The Oklahoma Corporation Commission (OCC) established new rules governing the purchase of power by electric

utilities. The new rules called for competitive bidding for power by regulated electric utilities in Oklahoma, as well as

reviews by the Commission of power and fuel purchase costs.

Source: Oklahoma Corporation Commission

http://w w w .occ.state.ok.us/Divisions/NEWS/2006/January06/01-12-06Pow er%20Rules.doc

12/01: The Oak Ridge National Laboratory conducted a study on the potential economic impact of electricity industry

restructuring in Oklahoma at the request of the OCC. Phase I of the report was issued in March 2001, and Phase II was presented to the commission in November

2001. Phase I of the report concentrated on an analysis of the near-term effects of potential restructuring in Oklahoma. Phase II analyzed the future of the electricity

market to 2010 incorporating the potential of new generating plants and customer responses to competitive prices.

06/01: The Governor signed Senate Bill 440. The bill establishes a 9-member task force to further study the effects of deregulation. Retail competition would not be

implemented until after the task force issued its final report scheduled for the end of 2002, and the legislature enacted restructuring legislation.

09/00: An electric restructuring symposium, sponsored by the Oklahoma Industrial Energy Consumers, was held to discuss restructuring in other states in

anticipation of developing a similar plan for Oklahoma. An earlier attempt at restructuring failed when the House of Representatives narrowly rejected Senate Bill

220. A similar bill was expected to be introduced during the 2001 legislative session, which began in February 2001.

06/00: Efforts to pass legislation containing implementation guidelines to restructure Oklahoma's electric power industry, set to begin July 1, 2002, by earlier

legislation, ended with the closing of the 2000 legislative session. The Electric Deregulation Task Force was scheduled to remain in operation until January 1, 2003,

and would continue working toward deregulation, presumably addressing new legislation in the 2001 session.

03/00: The Senate passed legislation dealing with the details of how to implement retail competition in the state's electric power industry, as required in Senate Bill

500, passed in June 1998. Retail choice was set to begin by July 2002 in the State. The bill had yet to be approved by the House at that time.

07/99: Oklahoma Gas & Electric Energy Services filed a plan with the OCC for new rate reductions totaling $58.9 million through July 1, 2002, establishing a

performance based incentive plan, and eliminating the fuel adjustment clause. These decreases, in addition to those already scheduled to take effect in 2000, were

intended to help prepare the utility for competition. If the performance goals were not met, the company would pay the price; if they were exceeded, the

stockholders would receive the benefits of the savings. This was the first performance-based ratemaking plan filed in Oklahoma.

10/98: The Joint Electricity Task Force began meeting to discuss deregulating the state's electric utilities. Proposed issues to be studied included customer

choice, reliability, unbundling, and tax impacts. The studies were scheduled to be completed by October 1999.

06/98: Senate Bill 888 was enacted. The bill was proposed to speed up the time line for restructuring the industry. Currently, under Senate Bill 500, studies and

recommendations for restructuring were scheduled to be completed by the OCC by 2000. The new legislation required that all studies be completed by October

1999, and allowed some retail competition to begin as early as 1999.

02/98: The OCC issued final rules for unbundling. The rules would go to the legislature and governor for review.

04/97: The Oklahoma Corporation Commission (OCC) was directed by Senate Bill 500 to undertake a study of all relevant issues relating to restructuring the

electric utility industry and to develop a framework for the restructuring. Four reports: ISO Issues, Technical Issues, Financial Issues, and Consumer Issues were

due February 1998, December 1998, December 1999, and August 2000, respectively.

04/97: Senate Bill 500, the Electric Restructuring Act of 1997, was enacted allowing retail competition by July 2002. The OCC was directed to study the issues and

develop a framework to implement retail competition. Under Senate Bill 500, each entity must propose a recovery plan for stranded costs. Transition charges could

be collected over a 3- to 7-year period and must not cause the total price for electric power to exceed the cost per kWh paid by consumers when the law was

enacted during the transition period.
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ICNU-Industrial Customers of Northw est Utilities

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12/02: A report issued by the Oregon Public Utilities Commission stated that residential customers would not benefit

from retail competition at this time.

Source: Oregon Public Utilities Commission

http://w w w .puc.state.or.us/PUC/new s/2002/2002_036.shtml

11/02: According to an Oregon Public Utility Commission press release, the Commission approved a request by

Industrial Customers of Northwest Utilities (ICNU) to implement a five-year plan for large commercial and industrial

customers of Portland General Electric with an hourly demand of 1 MW or more to choose their own electric supplier.

These customers would be required “to pay a fixed transition charge.” Despite having the opportunity to choose their

own supplier since March 1, 2002, eligible customers had been discouraged by variable transition charges. The

customers who chose this option would “give up receiving the standard cost-of-service rate for at least five years.” However, under the request, if they gave two years

notice they “could switch to any PGE option available to new customers for service after 2007.” Eligible customers had until November 8, 2002 to decide.

06/02: The Oregon PUC issued its monthly status report for June 2002 that tracked what portfolio options residential customers had chosen based on service

territory. Also the report tracked what percentage of nonresidential customers had chosen cost of service, market options or direct access based on load. No

nonresidential customers had chosen direct access as of June 1, 2002. Nonresidential customers were the only customers allowed to choose a certified electricity

service supplier at that time.

03/02: According to Oregon's electric restructuring law, commercial and industrial customers of Portland General Electric and PacifiCorp would be eligible for direct

access (the ability to purchase power from a certified Electricity Service Supplier) on March 1, 2002. In the event that an ESS pulls the plug on non-residential

customers, PGE and PacifiCorp would provide default service. Residential customers were not eligible for direct access, but they would have "a portfolio of energy

options to choose from including electricity from a variety of renewable energy resources." The 12-member portfolio advisory committee recommended the options to

the Public Utility Commission. PGE and PacifiCorp would continue to offer their renewable energy products, "Blue Sky" and "Clean Wind." All Oregon electric

customers had the option to retain "cost-of-service" based rates, but all customers would be assessed "a 3 percent public purpose charge...to fund and encourage

energy conservation and development of renewable energy." According to the PUC approved grant agreement, the Energy Trust of Oregon would administer funds

collected for conservation and renewable energy. The Oregon Housing and Community Services Agency would continue to collect "a low-income bill assistance fee"

from Portland General Electric and PacifiCorp customers.

08/01: Legislation, House Bill 3633, was enacted to revise Oregon's restructuring law. Act 3633 delayed the date for implementing retail access for large customers

from October 2001 to March 2002. Most other provisions of Oregon's plans for restructuring were also delayed 6 months to March 2002, including offering a portfolio

of rate options to residential customers, the collection of public purpose funds, and the requirement for utilities to unbundle the costs of generation, transmission,

distribution, ancillary services, customer services, public purpose programs, and taxes. An exception was made to allow collection of funds for low income

assistance programs, which were scheduled to begin in October 2001.

08/01: House Bill 3502 was enacted. The legislation amended the power of the Public Utility Commission to not only obtain fair and reasonable rates, but also to

balance the interests of the utility investor and the consumer in establishing fair and reasonable rates. Fair and reasonable rates were defined as those that provide

adequate revenue for both operating expenses and capital costs, with a return to the equity holder that was commensurate with the return on investment in other

enterprises of similar risk and sufficient to ensure confidence in the utility's financial integrity.

09/00: The Oregon Public Utilities Commission (PUC) passed the first set of rules governing electricity restructuring in Oregon. Beginning October 1, 2001, large

commercial and industrial customers were scheduled to have the opportunity to choose alternative suppliers. Small commercial and residential customers would

continue to be regulated. Electric utilities are required to file resource plans by November 1, 2000. The plans must identify what aspects of their businesses would

remain regulated to serve residential and small commercial customers.

07/99: The restructuring bill, Senate Bill 1149, was signed by the governor. The bill was somewhat different from the other States that passed restructuring

legislation in that residential consumers would not have retail access, but would be offered a choice of pricing plans by the utilities and regulated by the PUC. The

bill allowed the PUC to suspend restructuring if it jeopardized access to low-cost power from BPA, and it allowed municipals to choose whether or not to participate.

The bill imposed a 3 percent public benefits charge for energy conservation and low-income programs on consumers. Residential consumers were offered a portfolio

of options, including market-based prices, rate-regulated prices, and green prices for energy, while businesses and industrials would have retail access beginning

October 1, 2001. The PUC was given authority to determine stranded costs. Another provision allowed the governor to appoint the chair of the PUC and remove

commissioners for cause, and a net metering law for customer-installed generators less than 25kW (and limited customer generators to one half of one percent of

the utility's single-hour peak). The bill affected consumers of IOU's in the State (Pacificorp and Portland General Electric).

07/98: Pacific Power filed a proposal with the PUC for a “portfolio” pilot program for residential and small commercial consumers and direct access for large

industrial consumers.

07/98: Portland General Electric’s pilot program involving four Oregon cities would end as the two participating energy companies, Enron and Electric Lite, both

discontinued marketing to consumers.

02/98: Portland General Electric's deregulation plan faced opposition from The Oregon Intervener Coalition that included Pacificorp, Washington Water Power, and
www.eia.gov/cneaf/electricity/page/restructuring/oregon.html 2/2

02/98: Portland General Electric's deregulation plan faced opposition from The Oregon Intervener Coalition that included Pacificorp, Washington Water Power, and

consumer groups. Portland's plan called for selling all its generation and allowing all customers to choose competitive generation suppliers. The coalition preferred a

"portfolio model" for customer choice. The portfolio model would have allowed large industrial customers to shop for power suppliers, but small customers would

continue to be served by the incumbent utilities and be offered a menu of plans to choose from. Options would include current, market, or "green" rates.

01/98: Pacificorp filed a pilot program plan for residential and small commercial customers in Klamath County, Oregon. The pilot program would allow customers to

select from a “portfolio” of pricing options for electricity and would go through June 1999. Another proposed pilot program would allow schools and customers with

demands greater than 5 MW in Pacificorp’s service territory to choose alternative generation suppliers for up to 50 percent of their load. Additionally, all of their large

customers in Klamath County would be allowed retail access.

10/97: PUC approved Portland General Electric pilot program which could have allowed 50,000 customers in four cities to choose alternative generation suppliers.

Large industrial customers would begin to choose immediately, and residential customers by December 1997.
www.eia.gov/cneaf/electricity/page/restructuring/pennsylvania.html 1/4

ELECTRICITY

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Acronyms for the State of Pennsylvania

CDS-Competitive Discount Service

CTC-Competitive Transition Charge

DQE-Duquesne Light

POLR-Provider of Last Resort

PP&L-Pennsylvania Pow er and Light Company

PUC-Pennsylvania Public Utility Commission

Home > Electricity > State Restructuring > Pennsylvania Restructuring

Pennsylvania Restructuring Active

Last Updated: September 2010

08/10: A coalition of consumer and business groups wants state regulators to determine whether customers are due a

multi-billion dollar refund based on erroneous assumptions about what would happen to electricity rates when utilities

were deregulated more than a decade ago. Citizen Power and the Pennsylvania Steel & Cement Manufacturers Coalition

say the state-approved fees utilities charged customers were based on the assumption that deregulation would lower

rates. The coalition said that did not happen.

Source: Pittsburgh Post Gazette

http://w w w .post-gazette.com/pg/10236/1082144-28.stm

01/10: Rate caps expired in Pennsylvania Power and Light's (PPL) service area on January 1, 2010. Customers of PPL

are expected to see rates for electricity increase by an estimated 30 percent. Rate caps in Exelon Corporation's and

Allegheny Energy Incorporated's service areas are set to expire at the beginning of 2011.

Source: The Wall Street Journal

http://online.w sj.com/

08/09: The Pennsylvania Public Utilities Commission finalized measures designed to remove barriers to a competitive

retail electric market in the Pennsylvania Power and Light service territory. Some of these measures include access to

customer information databases for electric generation suppliers, data access through standardized transactions, different billing options, customer awareness and

education programs, and commitments to a process for development of a uniform supplier tariff.

Source: Pennsylvania Public Utilities Commission

http://w w w .puc.state.pa.us/

05/09: Senator Lisa M. Boscola filed a formal class-action complaint against the Pennsylvania Public Utilities Commission (PUC) for failing to disclose

Pennsylvania Power and Light’s (PPL) estimated rate increases after the electricity markets were deregulated in Pennsylvania. The PUC issues reports of electric

rate changes in which it provides estimates on electric prices affected by the rate changes. In this case, the PUC stated that it could not provide electricity price

estimates because PPL had already purchased its fuel and price estimates are performed prior to the purchase of any fuel.

Source: State Senator Lisa M. Boscola

http://w w w .senatorboscola.com/

04/09: The Consumer Affairs Committee of the Pennsylvania House of Representatives approved a measure to stagger the impact of rate hikes over three years as

rate caps across the state expire. The measure would limit electric utility rate hikes to a maximum of 20 percent each year for residential customers and small

businesses. Rate caps are set to expire in 2010 for Pennsylvania Power and Light and in 2011 for PECO, Allegheny Energy and First Energy.

Source: The Pennsylvania House of Representatives

http://w w w .house.state.pa.us/

01/09: The Public Utilities Commission of Pennsylvania held a hearing to acquire feedback from the public on Pennsylvania Power and Light’s (PPL) proposed

default service program and energy procurement plan. The plan would be enacted once rate caps expire at the end of 2009, allowing the electric utility to base its

rates on free market competition. Under the proposition, rates in the PPL service area could increase by 36 percent for the average residential consumer beginning

in January 2010.

Source: The Public Utilities Commission of Pennsylvania

http://w w w .puc.state.pa.us/

08/08: The Pennsylvania Public Utilities Commission approved a rate stabilization plan for PPL Electric Utilities Corporation, which is designed to allow customers

to prepay in anticipation of large price increases for supply service that will occur when PPL’s generation rate caps expire on Dec. 31, 2009. In its filing, PPL

projected a 34.5 percent increase for the average residential customer using 1,000 kWh per month. Because of its projected increase, PPL had sought approval to

phase in the estimated 2010 rate increase. As part of the plan, PPL customers can choose to make additional payments and receive corresponding credits on their

electric bills through Dec. 31, 2011. The plan is available to residential, small commercial, small industrial and certain street lighting customers.

Source: Pennsylvania Public Utilities Commission

http://w w w .puc.state.pa.us/

10/06: The Pennsylvania Public Utility Commission (PUC) certified that the process used to determine the provider of last resort (POLR) prices for Pennsylvania

Power Company (Penn Power) customers was transparent and non-discriminatory, and reflected market-based prices. The Commission voted 4-0 that the

competitive bidding process produced electric generation prices for Penn Power that reflected prevailing market prices. The competitive bidding process was

conducted by an independent group on behalf of Penn Power. The market-based prices meant that the average residential heating customer would see about a 20

percent increase in their total bill; the average residential non-heating consumer would see about a 33 percent increase in their total bill. The Commission verified

that the new prices accurately reflected the results of the auction and checked the company’s calculations to ensure the new retail electricity prices accurately

reflected the electricity costs resulting from the auction.

Source: Pennsylvania Public Utilities Commission

http://w w w .puc.state.pa.us/general/press_releases/press_releases.aspx?Show PR=1639

08/04: The Pennsylvania Public Utility Commission approved a plan for Duquesne Light (DQE) residential, small commercial, and industrial customers who chose

to receive their generation service from the company. Under the new plan, these customers were scheduled to receive a set rate through 2007. Furthermore,

generation rates would increase by 11.5 percent in 2005 for small customers, which included residential, small commercial, and industrial accounts. However,

customers were scheduled to pay total rates that were 15 percent lower than the ones in effect in 1996, when DQE’s rates were among the highest in the state and
www.eia.gov/cneaf/electricity/page/restructuring/pennsylvania.html 2/4

customers were scheduled to pay total rates that were 15 percent lower than the ones in effect in 1996, when DQE’s rates were among the highest in the state and

significantly above the national average. Under the new rates, an average residential customer using 500 kilowatthours of electricity per month would see his overall

bill, including generation, transmission and distribution, increase by approximately $3.65, from $50.89 to $54.54.

Source: Pennsylvania Public Utilities Commission

http://w w w .puc.state.pa.us/general/press_releases/press_releases.aspx?Show PR=1214

09/02: The Citizens for Pennsylvania's Future released its Electric Competition: The Story Behind the Headlines, A 50-state Report. The report found that rates for

most restructured states were lower or similar to what they were before restructuring.

08/02: The Pennsylvania Public Utility Commission issued an emergency order to stop New Power "from sending out additional make-up bills that were not

consistent with our rules and regulation." All New Power customers that have already paid these bills were scheduled to be refunded.

07/02: The Pennsylvania Office of Consumer Advocate posted its Electric Shopping Statistics for July 1, 2002. Competitive suppliers served 305,422 customers

representing a load of 2,142 megawatts. This report "included 34,399 residential customers assigned to Green Mountain's Competitive Discount Service (CDS)."

Also, "174,279 CDS customers formerly served by New Power and not reported here, are now served by PECO but continue to receive the discounted CDS price."

In the Consumer Advocate's last report (April 2002), 534,381 customers were being served by competitive suppliers.

06/02: According to a press release, Allegheny Energy Supply, a subsidiary of Allegheny Energy, Inc., sold "approximately 105,000 residential and commercial

accounts in the Duquesne Light service territory in southwestern Pennsylvania" to Dominion Retail, Inc., a subsidiary of Dominion. Dominion Retail was scheduled

to replace Allegheny Energy Supply as the retail electric service provider, but customers "would continue to receive one bill from their local utility."

04/02: PECO Energy was scheduled to take over The New Power Company's 180,000 customers, which it left behind when it exited Pennsylvania’s retail market in

February 2001. Rates would remain discounted until February 1, 2004, and the switch would take approximately 30 days, starting on April 25. According to a PUC

press release, "PECO's restructuring agreement requires PECO to have 50 percent of its residential and commercial customers served by alternative suppliers by

January 2003."

03/02: The Duquesne Light Company became the first Pennsylvania utility to eliminate its competitive transition charge (CTC), reducing customers’ bills by about

16 percent. The CTC enabled the utility to recover costs associated with restructuring. When Duquesne sold its generation plants in April 2000, the profits helped

the utility to eliminate the CTC.

09/01: The Department of Revenue released the second of three required reports that were aimed at recommendations to maintain tax neutrality in Pennsylvania

during the transition period to a competitive electricity industry. The report analyzed the dynamic effects of electricity generation competition on Pennsylvania's

economy and tax revenues. Even though the report generally found restructuring to have currently achieved positive benefits for Pennsylvania's economy, it stated

that "continued realization of lower electricity prices resulting in additional savings for consumers is essential for long-term benefits from electric competition."

08/01: The Pennsylvania Public Utility Commission (PUC) approved a settlement with GPU, Inc. and First Energy Corp (a merger between the two utilities was

pending at the time) that preserved customer rate caps, encouraged customer participation in choosing alternative generation suppliers, increased support for

renewable energy and conservation programs, and enabled GPU to defer its wholesale power losses through 2005. Distribution rate caps were extended for 3 years

to 2005. Total generation rates, including shopping credits and competitive transition charges, continued at the same levels through 2010 as established by GPU's

restructuring settlement. Shopping credits were scheduled to rise with a corresponding decrease in the competitive transition charge, which would enable customers

more opportunity to find alternative suppliers for generation. The settlement also committed $15 million to renewable and sustainable energy development. And

finally, through the establishment of a deferral mechanism that allowed GPU to carry its wholesale power losses in a deferred account through 2010, the settlement

addresses GPU's financial concerns and enabled it to continue meeting its obligations to purchase wholesale power for its customers.

01/01: As required under PECO's restructuring plan, 300,000 residential customers that had not chosen a competitive supplier were randomly chosen and switched

to The New Power Company, which was chosen by PECO to provide "Competitive Discount Service" from March 2001 through January 2004. Customers could have

opted out of the program or chosen another electricity supplier without penalty.

01/01: The PUC deferred the decision on GPU's rate increase request for recovery of wholesale power costs until May, when it was scheduled to be heard with

GPU's merger request (with First Energy). GPU claimed projected losses in 2001 could exceed $145 million due to the rising costs of purchasing wholesale power.

GPU voluntarily divested its generation assets, has not entered into long-term contracts for power, and bought power on the wholesale market at increasing prices

to serve its customer load.

12/00: DQE completed the first phase in its restructuring by selling its generation plants for $1.7 billion, extending its provider of last resort arrangement through

2004 thereby resulting in a 21-percent decrease in rates for its residential customers in 2002, and assuring complete recovery of stranded costs in 15 months.

12/00: GPU asked the PUC to defer the losses from its rising costs of wholesale power purchases, due to rising fuel costs, to provide its default customers with

power. A number of customers returned to GPU this summer following a rise in market prices. GPU was unable to procure through a 1999 auction, a supplier for 20

percent of its "provider of last resort" load. PECO, which initially also could not procure default power through an auction, was able to negotiate privately with New

Power Company to supply part of its default load. NPC was scheduled to offer discounted power to about 299,000 residential PECO customers until 2004.

Customers could have opted out and could have remained with PECO.

08/00: A Pennsylvania Department of Revenue report to Governor Ridge and the General Assembly projected that electric competition would create more than

36,000 new jobs in the state by 2004. The report stated that the success of electric competition would lead to new jobs because related savings gave customers

more money to spend, creating a multiplier effect in the state economy, reducing business costs, and allowing employers more money to invest.

07/00: The PUC approved a change in default service rates. Consumers were "gaming" the system by returning to the incumbent utility for the summer when prices

typically rose, making default service rates more attractive. Under the approved change, utilities could charge market-based rates for default service, and customers

could return to competitive suppliers after 60 to 90 days, rather than 12 months. GPU Energy's consumers could have returned to competitive service whenever they

chose.

01/00: As of January 1, 2000, all consumers in Pennsylvania had retail access to competitive electricity suppliers. The Office of Consumer Advocate reported just

over 507,000 consumers had switched to competitive suppliers at the time.

09/99: Duquesne Light Co., a subsidiary of DQE Inc., proposed selling 7 power plants to Orion Power Holdings bringing the total investment in Northeastern power

plants by Orion to $2.7 billion, and its portfolio of plants to 5,200 MW. Duquesne would use proceeds from the sale toward its allowed $1.9 billion in stranded cost

recovery. DQE expected stranded cost recovery to end by 2001, rather than 2005, and Duquesne customers were scheduled to see a 25-percent reduction in their

bills.

09/99: About 450,000 customers in the state had switched suppliers, a majority of them in the Philadelphia area, PECO's service territory, at this point in time.

PECO had some of the highest prices in the State prior to deregulation.

08/99: Rates for PP&L customers were scheduled to drop by about 1 percent. The approximated rate reduction was the result of PP&L's securitization of a portion

of its competition-related transition costs.
www.eia.gov/cneaf/electricity/page/restructuring/pennsylvania.html 3/4

of its competition-related transition costs.

05/99: The PUC finalized rules for full consumer choice in the retail electricity market. By September 1999, utilities were scheduled to mail information packages to

all consumers that had not chosen a competitive supplier. The packages would contain information about consumer choice, the "price to compare," and a list of

competitive suppliers serving their rate class and location.

01/99: Retail access was made available to two-thirds of the State's customers.

01/99: The 8-percent rate reduction in PECO's restructuring plan took effect for the 1.5 million residential customers in PECO's service territory.

11/98: The PUC and Allegheny reached a compromise agreement. Allegheny would implement a 2.5-percent rate reduction in 1999, and would follow the schedule

consistent with the rest of the State (two-thirds by January 1999 and all consumers by January 2000). $670 million could be recovered in stranded costs over 10

years. The PUC set the "price to compare" at 3.16 cents per kWh.

11/98: GPU sold 23 plants to Sithe Energies for $1.72 billion. GPU planned to focus on transmission, distribution, and diversifying into natural gas, water, and

telecommunications. A large part of the money from the sale of the plants was scheduled to go to paying GPU’s stranded costs.

10/98: It was proposed that as of January 2, 1999, all Pennsylvania Power and Light (PP&L) residential customers would be able to switch to an alternative electric

supplier. Also, the PUC and PP&L reached an agreement on capacity prices; PP&L agreed to sell installed capacity at $19.72/kW-year through 1999.

10/98: GPU announced an agreement with AmerGen Energy (jointly owned by PECO and British Energy) to buy Three Mile Island Unit 1 Generating Facility. If

completed, this would be the first sale of a nuclear power plant in the U.S. Approvals must be sought form various Federal and State agencies, including the Nuclear

Regulatory Commission.

10/98: Duquesne Light Co struck an agreement with FirstEnergy Corp. to swap its interest in the Beaver Valley nuclear plant for three plants owned by FirstEnergy.

09/98: Duquesne Light filed a divestiture plan with the PUC, hoping to open an auction in early 1999 to sell 3,035 MW of coal and nuclear capacity. Approval was

hoped for by December 1998.

09/98: About 1.8 million customers registered to choose their electric generation supplier at this point in time. The customers had received a "How to Shop" guide

and a list of competitive suppliers. Two thirds of the state's consumers were eligible to begin receiving power from their supplier of choice in January 1999. All

residential customers were scheduled to receive an 8- percent rate reduction with competitive suppliers scheduled to provide customers about 14 percent savings.

Also, four "Green-e" products (a product with the Green-e logo was certified to be produced with 50 percent or 100 percent generation from renewables) were being

offered to Pennsylvania customers.

09/98: Penelec customers would receive a 3-percent rate reduction and the "price to compare" was 4.404 cents per kWh. All Penelec customers were scheduled

to be able to participate in the retail choice program on January 1, 1999. Stranded cost recovery was set at $332.16 million over 11 years.

09/98: Met-Ed customers could have received a 2.5-percent rate reduction regardless if they participated in the retail choice program. The "price to compare" or

shopping credit was 4.35 cents per kWh. All Met-Ed customers were scheduled to be able to participate in the retail choice program on January 1, 1999. Stranded

cost recovery was set at $658.14 million over 12 years.

08/98: PP&L's restructuring plan was given final approval by the PUC. In the plan, PP&L was scheduled to provide a 4-percent rate reduction in 1999 for all

customers, and a shopping credit of 3.81 cents per kWh. Customers would be allowed to participate in retail competition in thirds, beginning with two-thirds on

January 2, 1999 and all by January 2000. The amount of recoverable stranded costs allowed at the time was $2.97 billion over 11 years.

08/98: The Electric Choice Program enrolled 1.75 million customers and 70 electric service providers as of August 1, 1998. In September, consumers would receive

information on shopping for an electric service provider and the "shopping phase" was scheduled to begin. Retail access was set to begin on January 1, 1999.

07/98: The PUC approved Wellsboro Electric Company's restructuring plan, allowing a 3.9 cents per kWh shopping credit. Wellsboro did not claim any stranded

cost recovery. Two-thirds of Wellsboro's customers were scheduled to have retail access by January 2, 1999 and all customers by January 2, 2000. Open

enrollment began on July 1, 1998, for the State's retail choice program.

07/98: Pennsylvania consumers began signing up to participate in the first phase-in of competition, two-thirds of consumers. In the first week, over 1.1 million

consumers signed up for the Electric Choice Program.

07/98: All Pike County customers were scheduled to be able to choose their electric supplier on May 1, 1999. A shopping credit or "price to compare" rate was set

at 3.4 cents per kWh. The PUC had not determined the amount of stranded costs Pike County could recover, but it could recover the costs until December 31,

2005.

06/98: The PUC approved restructuring plans for UGI Utilities, allowing a shopping credit of 3.67 cents per kWh until 2000 and 4.3 cents per kWh in 2001. Also, the

Commission approved $32.5 million in stranded cost recovery. All UGI customers were scheduled to be able to choose their electric supplier on January 1, 1999.

06/98: The PUC began its consumer education program. An Electric Supplier Selection Form would be mailed to all consumers in the state to begin enrollment in

the first part of the phase-in of competition, set to begin with two-thirds of consumers in January 1999. Sign-up for retail choice began July 1, 1998. The final third of

consumers were scheduled to begin retail choice in January 2000. Most consumers were expected to realize savings of over 10 percent of what they paid at the

time.

06/98: The PUC approved Penn Power's restructuring plan with a shopping credit of 3.73 cents per kWh and stranded cost recovery of $234 million over 7 years.

Customers were scheduled to be fazed in starting with two-thirds by January 2, 1999 and the final third by January 2, 2000. Open enrollment was scheduled to

begin on July 1, 1998.

05/98: The PUC approved Duquesne Light's restructuring plan. Stranded cost recovery was set at $1.331 billion over 7 years beginning January 1999. Consumers

were expected to save about 12 percent. Retail competition was scheduled to be phased-in beginning January 1999 and be complete by January 2000.

05/98: The PUC gave final approval to PECO's restructuring plan in a compromise agreement. Under the plan, PECO customers were scheduled to receive an 8

percent rate reduction next year, 6 percent in 2000, with 20 percent savings expected for those willing to shop for power. PECO would be allowed to recover $5.26

billion in stranded costs over a period of 12 years. Two-thirds of customers were scheduled to be phased in to retail competition by January 1999 and all customers

by January 2000.

03/98: Pilot programs were fully subscribed with more than 72,000 participants, making it the largest pilot program nationally.

02/98: Pilot programs completed lotteries to select final pilot participants. The first portion of the State's customers were actively participating in retail access pilot

programs since November 1997.
www.eia.gov/cneaf/electricity/page/restructuring/pennsylvania.html 4/4

12/97: House Bill 1509 allowed stranded cost recovery through a competitive transition charge; however, the detailed decisions and amount of recoverable costs

were left to the PUC. The legislation expected utilities to use reasonable mitigation measures, and securitization was allowed but not required.

08/97: As required by House Bill 1509, PUC approved statewide pilot programs for 5 percent of each utility's load, beginning 11/97.

12/96: House Bill 1509, the Electricity Generation Customer Choice and Competition Act, was enacted. The law proposed a schedule whereby consumers could

begin choosing among competitive generation suppliers, beginning with one third of the State's consumers, by January 1999, two thirds by January 2000, and all

consumers by January 2001. Utilities were required to submit restructuring plans by September 1997.
www.eia.gov/cneaf/electricity/page/restructuring/rhode_island.html 1/2

ELECTRICITY

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Acronyms for the State of Rhode Island

LRS-Last Resort Service

PUC-Rhode Island PUblic Utilities Commission

SOS-Standard Offer Service

Home > Electricity > State Restructuring > Rhode Island Restructuring

Rhode Island Restructuring Active

Last Updated: April 2007

06/06: Donald L. Carcieri signed into law Senate Bill 2903 (SB 2903) which created an Office of Energy Resources as a

successor to the state energy office. The new office was created to implement programs that promote the use of energy

resources, develop energy programs in order to achieve and demonstrate the benefits of energy efficiency, and advise the

governor and the general assembly on energy resource matters.

Source: State of Rhode Island General Assembly

http://w w w .rilin.state.ri.us/Billtext/BillText06/SenateText06/S2903.pdf

03/06: The Rhode Island Senate passed Senate Bill 2906 (SB 2906). The bill would require the proposed Rhode Island

Office of Energy Resources to offer assistance to low and middle-income households so that they may become more

energy efficient through weatherization and energy conservation projects.

Source: State of Rhode Island General Assembly

http://w w w .rilin.state.ri.us/Billtext/BillText06/SenateText06/S2906.pdf

03/06: The Rhode Island State Senate passed Senate Bill 2905 (SB 2905). The bill extended standard offer service through 2020 and integrates energy efficiency

into procurement decisions.

Source: State of Rhode Island General Assembly

http://w w w .rilin.state.ri.us/Billtext/BillText06/SenateText06/S2905.pdf

07/02: The PUC proposed keeping Standard Offer Services rates at 4.662 cents/KWh, but Last Resort Services rates were proposed to rise from 6.365 cents/KWh

to 7.481 cents/KWh in July and 7.496 cents/KWh in August.

06/02: House Bill 7786 was enacted. It changed the composition of the Public Utilities Commission, its membership, meetings, and hearings. The bill changed the

number of commissioners to five instead of three, and three of the commissioners must be independent from any business regulated by the commission. The bill

also amended the State's restructuring law, House Bill 8124. Utilities must offer Standard Offer Service (SOS) to customers not participating in retail competition

until 2009, and Last Resort Service (LRS) to customer who left the competitive market. All SOS and LRS rates would be approved by the PSC. Starting January 1,

2003 and for the next 10 years, utilities would collect $0.000002 per kilowatthour "to fund demand side management programs and $0.0000003 per kilowatthour "to

fund renewable energy programs." Municipal aggregation was also permitted.

05/01: The Rhode Island State Senate passed Senate Bill 881, an act that would enable nonresidential customers enrolled in last resort service the option to return

to standard offer service. These customers were required to sign an agreement for 2 years prohibiting self-generation during non-emergency conditions and

remarketing of purchased electricity.

04/01: The PUC approved an increase from 5.095 cents/kWh to 6.302 cents/kWh for standard offer rates for Narragansett Electric, beginning April 1, 2001.

02/01: The PUC released its annual report on electric restructuring to the State Legislature. According to the report, the number of customers leaving the

competitive market and becoming Last Resort Service (LRS) customer "increased dramatically in 2000." In June 2000, LRS rates "moved gradually to the full market

price" for nonresidential customers, but LRS rates were still the same as Standard Offer Services rates for residential customers.

10/00: The PUC approved a 10.6-percent increase request by Narragansett Electric. Standard offer rates were increased from 4.5 cents/kWh to 5.4 cents/kWh. A

typical residential customer's bill was scheduled to be increased by about $4.50 per month. As part of its contract to purchase electricity for its customers,

Narragansett paid a fuel surcharge when oil and natural gas prices increased.

09/00: The PUC approved an immediate rate increase of 4 percent for Narragansett Electric's 460,000 customers. Narragansett Electric filed an additional plan that

would increase rates another 10 percent on October 1, 2000, if approved by the PUC. The requests were made in response to rising fuel prices. As part of its

contract to purchase electricity for its customers, Narragansett would have to pay a fuel surcharge when oil and gas prices reach high levels.

07/00: The increased cost of fuel and wholesale power prompted the PUC to increase the standard offer rates from 3.8 cents/kWh to 4.1 cents/kWh. Default service

rates were also increased to 4.5 cents/kWh. After June, default (or last resort) service rates were scheduled to be market-based.

09/99: As of June 1999, roughly about 2,000 customers out of the State's 456,000 chose alternative generation suppliers.

01/99: The standard offer rate increased from 3.2 cents per kilowatthour to 3.5 cents. The standard offer rate was scheduled to increase again to 3.8 cents in

January 2000.

09/98: The completed sale of New England Electric System’s generation assets would result in increasing rate reductions, already 7 percent under the

restructuring act, to a proposed 19 percent for Narragansett customers.

08/98: Narragansett proposed to cut rates 12.4 percent as a result of selling its power plants for $1.6 billion to US Generating Company.

05/98: The PUC approved a rate increase for Narragansett Electric Company for its standard offer rate from the current 3.2 cents/kWh to 7.1 cents/kWh by 2009.

Similar increases were approved for Blackstone Valley and Newport Electric.
www.eia.gov/cneaf/electricity/page/restructuring/rhode_island.html 2/2

01/98: Retail access was implemented with 25 registered generation suppliers, but the standard offer interim rates (3.2 cents/kWh) offered by the State's investor

owned utilities were low enough that no real competition has occurred.

12/97: The Rhode Island Public Utilities Commission (PUC) issued an order accepting interim rates and approving retail choice for all Rhode Island consumers on

January 1, 1998.

08/96: The Rhode Island Utility Restructuring Act of 1996, House Bill 8124, allowed retail choice to be phased-in starting July 1997. In July 1997, Rhode Island

became the first state to begin phase-in of statewide retail wheeling (for industrial customers). Residential consumers were scheduled to have retail access by July

1998.
www.eia.gov/cneaf/electricity/page/restructuring/south_carolina.html 1/1

ELECTRICITY

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Acronyms for the State of South Carolina

PMPA-Piedmont Municipal Pow er Agency

PSC-South Carolina Public Service Commission

Home > Electricity > State Restructuring > South Carolina Restructuring

South Carolina Restructuring not Active

Last Updated: April 2007

03/00: Restructuring legislation, Senate Bill 1168, was introduced and referred to the Committee on Judiciary. The bill

would allow retail direct access within three years in South Carolina. Debate and discussions continue in both the

House and Senate, but few expect passage of a bill this session.

05/99: Three restructuring bills and one joint resolution calling for a study of restructuring the electric power industry

have not been passed in the legislature. The legislature continues to debate and review the bill proposed by

Representative Cato at this time.

03/99: Restructuring legislation was introduced. The bill calls for competition to be phased-in over 6 years and would allow regulators to determine how much

utilities could recover in stranded costs.

12/98: A task force was appointed to study deregulation in South Carolina.

11/98: A restructuring bill was prefiled that would create a deregulation task force.

10/98: The PSC released a report on deregulation that stated the cost of deregulating the 3 large investor-owned utilities in the state would be about $1.4 billion.

Stranded costs for South Carolina Electric and Gas were estimated to be $882 million; for Carolina Power & Light, $410 million; and for Duke Energy, $81 million.

The Piedmont Municipal Power Agency, not regulated by the PUC, estimated its stranded costs (mostly associated with its part ownership in Catawba nuclear

station) at $2.8 billion. The PMPA wanted recovery of its stranded costs to be spread across the State.

09/98: The PSC estimated stranded costs for Duke Energy at $81 million; for Carolina Power & Light at $410 million; for South Carolina Electric and Gas at $882

million; and for Lockhart Power Co, $0.

06/98: The Public Service Commission of South Carolina (PSC) decided to conduct stranded cost proceedings for the 4 investor-owned utilities in the State,

expecting completion by the end of the year.

04/98: The PSC requested utilities to calculate their stranded costs under a retail access scenario.

02/98: The PSC issued the Proposed Electric Restructuring Implementation Process as requested by the House Speaker. The plan calls for a five-year transition

period following passage of legislation to deregulate the electric power industry. Also, utilities would submit recovery plans for approval by the PSC.

05/97: The House Speaker requested a PSC study and recommendations for restructuring electric industry by January 1998.

1997: Legislation (Bills 346 and 3414) to restructure the electric industry and allow retail wheeling were introduced in the House and Senate. The bills would allow

retail competition to be phased in beginning January 1998 and going through January 1999. Neither were acted on in the 2-year legislative session that ended in

June 1998.
www.eia.gov/cneaf/electricity/page/restructuring/south_dakota.html 1/1

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06/99: Black Hills Power and Light agreed to freeze its rates for 5 years, until January 1, 2005. This continued a 5-year freeze

begun in 1995. South Dakota’s electric rates were among the lowest in the Nation, and some studies have indicated retail

competition in such low-cost rural areas could cause rates to rise.

02/99: A study by the University of South Dakota Business Research Bureau commissioned by the rural cooperatives stated that under restructuring, cooperatives

would see rates increase.

01/98: The Legislative Research Council hosted an informational forum on developments in utility competition. This was the first time the State Legislature

addressed restructuring of the electric industry. Current law allows retail wheeling for new, large customers.
www.eia.gov/cneaf/electricity/page/restructuring/tennessee.html 1/1

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TVA-Tennessee Valley Authority

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02/00: The Comptroller of the Treasury issued a report titled "The Potential Impacts of Electric Industry Restructuring in

Tennessee". The report stated that Tennessee should be ready to join the national trend towards electric industry

restructuring. The study suggested that the Joint Study Commission continue studying restructuring issues. If Tennessee

decided to allow retail competition, then the state should "move slowly in allowing competition, possibly following the

examples of Virginia and Pennsylvania in first pursuing pilot projects." Also, "full retail competition was probably the

preferable approach," allowing residential consumers to participate.

02/99: Recommendations for restructuring including any proposed legislation in Tennessee must have been made by February 28, 2001, when the General

Assembly Study Commission was scheduled to end.

01/99: The Tennessee Regulatory Authority released a report on deregulation of the industry. The report identifies 10 issues: rates and prices; stranded costs;

reliability; market power; universal service; environmental concerns; taxes; local rate setting; consumer education; and regulatory and legal issues.

06/98: The General Assembly Study Commission continued their study of restructuring the electric industry into 1999.

05/98: The Department of Energy advisory committee on TVA issued a final report calling for more regulation controls on TVA if national electric deregulation began.

It recommended TVA remain mainly in the "wholesale electric business."

04/98: TVA's distribution company customers with 10-year contracts can vary the amount of purchased power and TVA would be allowed to recover any stranded

costs associated with the lost load. The distribution companies could buy power from competitive wholesale suppliers, and TVA could sell outside its traditional

service territory.

02/98: TVA offered its 159 municipal and cooperative wholesale customers new power-purchase contracts. To date, 86 were interested and 18 signed on. Under the

new contracts, distributors could give TVA five years (instead of the current 10) notice of intent to end power-purchase agreements.

06/97: The General Assembly created a special joint legislative committee to study electricity deregulation. A report was scheduled for October 1998.
www.eia.gov/cneaf/electricity/page/restructuring/texas.html 1/4

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AEP-American Electric Pow er

CPL-Central Pow er and Light Company

CTC-Customer Transition Charge

EES-Enron Energy Services

ERCOT-Energy Reliability Council of Texas

HL&P-Houston Light and Pow er Company

ISO-Independent System Operator

POLR-Provider of Last Resort

PUC-Public Utilities Commission of Texas

REP-Retail Electric Provider

RTO-Regional Transmission Organization

SPP-Southw est Pow er Pool

SPS-Southw estern Public Service Company

TNMP-Texas-New Mexico Pow er Company

TXU-TXU Energy Corporation

WTU-West Texas Utilities

Home > Electricity > State Restructuring > Texas Restructuring

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08/10: The Board of Directors for the Electric Reliability Council of Texas, grid operator and manager of the electric market

for most of the State, voted unanimously to proceed with two key components of the nodal wholesale market. The board

certified that readiness criteria had been met for both the outage scheduler and congestion revenue rights system in order

to proceed with nodal cutover activities for the December 1, 2010 nodal market launching. This market structure was a part

of Project 26376, whereby the Public Utility Commission of Texas (PUCT) ordered ERCOT to develop a nodal wholesale

market design. The transition to the nodal market requires significant changes to processes and systems. In today's zonal

market, the grid is divided into congestion management zones (CMZs), which are defined by commercially significant

constraints (CSCs). Moving to a nodal design will satisfy the PUCT order to directly assign local congestion. The nodal

market grid will consist of more than 4,000 nodes, replacing today's CMZs.

Source: Electric Reliability Council of Texas

http://w w w .ercot.com/new s/press_releases/2010

05/09: The Texas House of Representatives unanimously approved Senate Bill 547 and House Bill 870. The two bills

delay deregulation of electric utilities in Northeast Texas indefinitely.

Source: Texas Legislature Online

http://w w w .legis.state.tx.us/

04/09: Senate Bill 547 and House Bill 870 were introduced into the Texas Legislature to halt electricity deregulation in

Southwestern Electric Power Company’s service area in Eastern Texas in 2011. Under these two bills, a pilot program

would first need to prove that electricity deregulation would lower rates before the entire service area could be deregulated.

Source: Texas Legislature Online

http://w w w .legis.state.tx.us/

06/08: The Public Utility Commission (PUC) urged customers of Sure Electric, LLC, also known as Riverway Power

Company, to shop for a new provider as the Electric Reliability Council of Texas (ERCOT) began the process to switch

Riverway customers to a Provider of Last Resort (POLR). ERCOT began the switching process for approximately 6,200

customers on Tuesday, June 10.

Source: Public Utility Commission of Texas

http://w w w .puc.state.tx.us/

02/04: The Texas Public Utilities Commission (PUC) set forth a rule establishing new monitoring, enforcement and market

behavior standards for the wholesale electric market. The new rule 1) clarifies the standards and criteria the PUC will use

when reviewing market participants’ activities; 2) requires market participants to maintain records showing compliance; 3)

identifies the role of the Electric Reliability Council of Texas (ERCOT) in enforcing operating standards; 4) and establishes

a PUC process for an expedited informal review of market participant activities.

Source: Texas Public Utilities Commission

http://w w w .puc.state.tx.us/nrelease/2004/021804.cfm

05/03: The Texas Public Utilities Commission has delayed retail choice in Northern Texas, which comes under the jurisdiction of the Southwest Power Pool (SPP)

Regional Transmission Organization, until 2011.

Source: Texas Public Utilities Commission

http://w w w .puc.state.tx.us/rules/subrules/electric/ch25complete.pdf

12/02: Central Power and Light, a subsidiary of American Electric Power, filed its divestiture plan with the Public Utility Commission of Texas. The utility proposes

to sell its generating assets to determine the level of stranded costs that may be recovered, as provided for under Texas’ restructuring law, SB 7. According to an

AEP press release, “the assets to be sold have a nameplate generation capacity of 4,241 megawatts and a net book value just under $1.9 billion.” The proposed

plan “does not include power plants owned by other AEP subsidiaries in Texas – West Texas Utilities (WTU) or Southwestern Electric Power Company – as AEP is

not seeking stranded cost recovery for those generating assets.”

10/02: The Texas Public Utilities Commission issued a settlement agreement for NewPower’s exit from the Texas retail electric market. According to a PUC news

release, NewPower’s final bills must follow PUC rules. “Customers with past due bills of more than $50 may request a deferred payment plan,” but they “will not be

charged any late fees or penalties.” The NewPower call center will remain “open until December 30, 2002 or the 61st day after NewPower issues its final bill,

whichever date is later.” All complaints received by October 16, 2002 must be resolved, and “all other complaints sent by the PUC to NewPower must be resolved

within 21 days.”

08/02: The PUC approved a new rule that prohibits retail electric providers (REP) from transferring non-paying customers to the Provider of Last Resort (POLR). As

of September 24, 2002, residential and small commercial customers who have switched to an REP will not be transferred to the POLR because they did not pay

their electric bill. According to a PUC press release, "they will be switched to the affiliated REP and be charged the Price-to-Beat rate, which is lower than the

current POLR rates." Also, current affiliated REP customers will not be switched to a POLR for non-payment. POLR customers must choose a REP before

December 31, 2002 or they "will be served by the POLR's competitive affiliate at an unregulated rate."

08/02: The Texas Public Utilities Commission approved a rate increase due to rising fuel costs. According to a PUC press release, Texas' restructuring legislation,
www.eia.gov/cneaf/electricity/page/restructuring/texas.html 2/4

Senate Bill 7, provides that the PUC can raise rates "twice a year if natural gas prices increase at least four percent over a 10-day period." The PUC is considering

this issue and may change it in the near future, but the Commission stated that customers are still paying "approximately 10 percent" less than last year.

Customers should see the fuel cost increase on their October bills.

08/02: As part of the upcoming "Report to the 78th Legislature on the Scope of Competition in Electric Markets," the PUC released its July 2002 Report Card on

Retail Competition. According to the report card, 349,612 switch requests have been completed as of July 22, 2002. There was a 31 percent increase in switching

activity since the May 2002 Report Card. The final report will be given to the Legislature in January 2003.

07/02: As part of the upcoming "Report to the 78th Legislature on the Scope of Competition in Electric Markets," the PUC released its June 2002 Report Card on

Retail Competition. According to the report card, 262,593 switch requests have been completed and 39,634 switch requests are either in review or scheduled. There

has been a 9 percent increase in switching activity since the May 2002 Report Card on Retail Competition. The final report will be given to the Legislature in January

2003.

06/02: New Power Company customers will be switched to either TXU Energy (TXU) or Reliant Energy Retail Services based on the customer's location. The PUC

struck an agreement with the two companies to prevent the customers from being switched to provider of last resort (POLR) service. According to a PUC press

release, TXU will take on New Power customers in the Houston metropolitan area, and Reliant will take on New Power customers in the Dallas-Fort Worth area and

areas in north and west Texas. Reliant and TXU will offer rates "significantly below POLR rates" and below each other's proposed "price to beat" rates, which will be

reviewed by the PUC this month. Since the agreements provide for monthly service contracts, customers can switch to another service provider at any time "without

a fee or penalty."

03/02: According to a press release, the Public Utility Commission of Texas (PUC) "issued an interim order approving a procedure to allow for the transfer of

customer contracts from an Enron subsidiary, Enron Energy Services, Inc. (EES), to Constellation Power Source, Inc. The order also prohibits EES from marketing

to or serving customers in Texas pending the sale. This action will allow EES customers to keep the existing contract terms with a qualified provider who buys the

contracts from EES or to opt out of their contracts with EES and choose another retail electric provider (REP)."

03/02: The Federal Energy Regulatory Commission delayed deregulation in Southeast Texas from September 15, 2002 until 2003 because no consensus has been

reached on the formation of a regional transmission organization.

12/01: The PUC set the "Price to Beat" for the six utility-affiliated retail electric providers in the State. Customers who do not choose to switch to an alternative

retail electric provider will continue to receive full service from their utility-affiliated provider. Rates for residential customers will be cut by at least 6 percent on

January 1, 2002, when all customers will be able to choose to buy their energy from a competing provider. See the Texas Electric Choice web page

(http://www.powertochoose.org) for customer information about choosing a retail electric provider.

11/01: Exercising its option to delay retail access in regions where fair competitive service cannot be implemented, the PUC accepted a settlement to delay

implementation of retail access in Southeast Texas. Affected are customers of Entergy within the Southeast Regional Reliability Council. The PUC cited a lack of

an RTO in the region and the absence of marketing by retail electric service providers as the primary reasons for the decision.

11/01: Exercising its option to delay retail access in regions where fair competitive service cannot be implemented, the PUC accepted a settlement to delay

implementation of retail access in Southeast Texas. Affected are customers of Entergy within the Southeast Regional Reliability Council. The PUC cited a lack of

an RTO in the region and the absence of marketing by retail electric service providers as the primary reasons for the decision.

10/01: The PUC delayed retail choice in the area covered by the Southwest Power Pool in Texas (Panhandle area). The delay will affect customers of Southwest

Electric Power Company and a few customers of West Texas Utilities. Reasons cited include the lack of an RTO in that region, no retail electric suppliers, and

wholesale electricity markets in the area are not yet competitive.

09/01: Utilities in Texas began the process of auctioning part of their generating capacity. According to SB 7, at least 60 days before competition begins, each

generation company affiliated with a former monopoly utility must sell entitlements to at least 15 percent of its installed generation capacity. The action is designed

to increase the pool of available power for new retail suppliers entering the market, prevent market power, and promote competition in electricity markets.

08/01: The official opening of the pilot program in Texas has been delayed twice, from the original data of June 1 to July 6, and now to at least July 31. The

schedule for full implementation of retail open access is still set to begin January 2002.

07/01: The Texas Supreme Court upheld the March PUC settlement with Central Power and Light (a subsidiary of American Electric Power) to securitize

approximately $764 million in regulatory assets. Securitization, or refinancing of debt, is the mechanism to recover stranded costs as provided by the Texas

restructuring law, SB 7, passed in June 1999.

07/01: Three companies were chosen by a competitive bidding process to be the POLR for Texas customers whose retail electricity providers (REP) cancel service.

POLR service is designed as a safety net to provide continuity of service when a customer's REP does not continue service. POLR service is relatively high-priced

and should only be used as a temporary service until a customer can choose another REP.

05/01: The Texas retail pilot program has 12,723 residential participants in the TXU service territory, but can admit as many as 113,295 customers. However, more

commercial and industrial customers signed up than are allowed under the 5 percent rule, and a lottery was conducted to determine participants.

03/01: A high level of interest in participating in the retail choice pilot program by nonresidential customers is requiring most of the investor-owned utilities to

conduct lotteries to choose the allowed 5 percent of their customers who will be allowed to choose their electricity supplier. Beginning in June, 5 percent of each

customer class in each of the investor-owned utilities will be allowed to choose their supplier of electricity. The residential participants are being selected on a firstcome, first-serve basis.

03/01: The PUC is overseeing the pilot program set to begin retail competition by June 1, 2001. The pilot program will be open to customers in the State's IOU

service territories. Enrollment began in February 2001, and if over 5 percent of customers choose to enroll, a lottery will be held to choose participants.

03/01: The PUC began its consumer education program to promote competition for electricity suppliers. Inserts are being enclosed in bills, and an information

website (http://www.powertochoose.org) and telephone line are now operating.

12/00: The PUC issued a Request for Proposals (RFPs) to select electric service providers to be providers of last resort (POLR). The POLR will serve customers in

areas open to competition on January 1, 2002, where the Retail Electric Provider (REP) of choice fails to continue service. According to the PUC's restructuring

rules, POLRs must offer a firm, nondiscountable, seasonally differentiated rate to any of three consumer classes: residential, small nonresidential, and large

nonresidential. The POLR service is not supposed to be competitive, innovative or anything other than basic standard service.

10/00: The PUC adopted rules for the provider of last resort for when competition begins in early 2002. The rules will allow for continuity of service if a service

provider goes out of business or drops a consumer. The provider of last resort will be required to provide to consumers no longer served by their provider of choice

with service at a fixed price. A competitive bidding process will designate the last resort providers for each consumer class. Bidding is expected to be completed by

June 1, 2001.
www.eia.gov/cneaf/electricity/page/restructuring/texas.html 3/4

07/00: Pilot programs involving 5 percent of each utility’s load are scheduled to begin June 1, 2001. Proposed rules have been issued by the PUC. Retail electric

providers must register with the PUC, and affiliate companies may not operate in the incumbent utility’s territory. Customer class participation will be determined by

the share of load each class represents in a utility territory, and apportioned accordingly. Full implementation of retail access is scheduled to begin January 1, 2002,

in Texas.

04/00: Utilities filed restructuring plans with the PUC. The plans incorporate how the utilities will implement retail choice by 2002, a mandated rate reduction of 6

percent after January 1, 2002, and how the utilities will separate their business into generation, retail provider, and delivery divisions.

04/00: Southwestern Public Service Company (SPS) announced a rate reduction of 7 percent for most of its consumers, beginning in 2001. Also, they are planning

to sell about 2/3 of their generating capacity in order to meet the mandated requirement of owning no more than 20 percent of capacity in their territory in order to

participate in retail competition.

12/99: Texas-New Mexico Power Company’s (TNMP) pilot programs in Gatesville and Olney City began November 1, when customers began receiving power from

Bryan Texas Utilities. Prices are between 7 and 10.5 percent lower than other TNMP customers. The pilot programs are required by the Texas restructuring

legislation. All utilities must conduct pilots by June 2001. TNMP is ahead of schedule with the implementation of these two programs.

10/99: Central Power & Light (CPL) filed an application with the PUC to securitize or refinance their regulatory assets, as allowed in the recently passed

restructuring legislation. If granted, CPL would securitize about $1.27 billion of its retail generation-related regulatory assets and about $47 million in other qualified

costs.

10/99: Southwestern Public Service Company filed its plan for evaluation of market dominance with the PUC, as required by the legislation passed in June. To

alleviate market dominance, SPS plans to transfer ownership or control of 595MW of generating capacity. Some entitlements to power will be auctioned, and some

generation assets divested (by 2002).

09/99: Gatesville, TX, will begin one of the largest pilot programs in the Nation. The city banded together all its customers and sought bids from competitive

suppliers. Bryan Texas Utilities will supply all Gatesville’s consumers with power, and Texas- New Mexico will continue to provide the distribution services. Individual

customers may opt out of the program. The program is scheduled to begin 11/1/99, and expected to provide 8- to 10-percent savings.

06/99: Restructuring legislation, Senate Bill 7, was enacted to restructure the Texas electric industry allowing retail competition. The bill requires retail competition

to begin by January 2002. Rates will be frozen for 3 years, and then a 6 percent reduction will be required for residential and small commercial consumers. This will

remain the "price to beat" for five years or until utilities lose 40 percent of their consumers to competition. The bill will also require a reduction of NOx and SO2

emissions from "grandfathered" power plants over a 2-year period. All net, verifiable, nonmitigated stranded costs may be recovered. Securitization will be allowed as

a recovery mechanism. Utilities must unbundle into 3 separate categories, using separate companies or affiliate companies, the generation, the distribution and

transmission, and the retail electric provider. Utilities will be limited to owning and controlling not more than 15 percent of installed generation capacity in their region

(ERCOT). Municipals and cooperatives are not affected by the law, unless they choose (after January 2002) to open their territories to competition. The law also

requires an increase in renewable generation and 50 percent of new capacity to be natural gas-fired.

12/98: As part of Texas-New Mexico's transition to competition, the PUC approved a price reduction for their customers retroactive to January 1998, resulting in a

credit on bills for customers. The price reduction is part of TNMP's plan to reduce residential rates by 9 percent and commercial rates by 3 percent over a 5-year

transition period.

11/98: The House committee released a report on the tax impacts of deregulation indicating a major overhaul of the state's tax system would be necessary if

restructuring legislation were to pass in 1999.

10/98: Texas-New Mexico Power Co. named 2 communities, Gatesville and Olney City, in which to initiate its pilot program, “Community Choice,” for retail access

to generation suppliers of choice.

07/98: The PUC approved TNMP's proposal for retail competition. The plan includes provisions for a pilot program and a five-year transition to competition. This

voluntary plan has a provision that it would be modified to conform to any restructuring legislation passed.

05/98: The PUC’s revisions to their plan for deregulation would allow securitization of stranded assets, estimated to be $4.5 billion if retail competition happens in

2001. Deferring full competition one more year would lessen stranded costs to $3.3 billion, and delaying competition until 2003 would set stranded costs at

approximately $2.3 billion.

05/98: An administrative law judge recommended the PUC reject Texas-New Mexico's restructuring plan. The plan would provide residential customers an

immediate 3-percent rate reduction and another 3 percent in January 2000 and January 2001, totaling 9 percent over 3 years. Also, the plan provided for full recovery

of stranded costs through a customer transition charge (CTC). A final decision by the PUC is expected by July.

04/98: The PUC is finalizing its plan and recommendations for restructuring and expects to forward it to the legislature within days.

03/98: The PUC approved Texas Utilities restructuring plan.

03/98: HL&P's restructuring plan was approved The HL&P plan provides a 4- percent rate cut this year and another 2 percent next year.

12/97: The Senate Interim Committee on Electric Industry Restructuring met, and will continue meeting with stakeholders; next meeting set for February 1998. The

committee expects to issue a report prior to when the 1999 legislative session reconvenes in January.

12/97: Houston Light and Power, Texas Utilities Electric Co., and Texas-New Mexico Power Co. announced agreements with the PUC on proposed competition

plans, although final approval by the PUC is still needed. All three contain rate reduction measures. Texas-New Mexico's plan offers a guaranteed date, 2003, for full

retail choice beginning with a phase-in of customers as early as January 1998, and a plan for stranded cost recovery.

10/97: Houston Light and Power presented its transition proposal for restructuring. Included is a 4-percent rate decrease over 2 years for residential customers.

08/97: A Senate committee was formed to review electric industry restructuring.

01/97: The PUC issued three reports as directed by the legislature. Volume I is on the scope of competition in the electric industry in Texas; Volume II is an

investigation into retail competition; and Volume III focuses on recovery of stranded costs and competition.

08/96: The PUC authorized the ERCOT ISO, to be operational by July 1997.

1995: Senate Bill 373 enacted to restructure the Texas' wholesale electric industry, consistent with FERC requirements. The law requires utilities to provide

unbundled transmission service on a non-discriminatory basis and establish an ISO.
www.eia.gov/cneaf/electricity/page/restructuring/texas.html 4/4
www.eia.gov/cneaf/electricity/page/restructuring/utah.html 1/1

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03/01: House Bill 244 changed the name of the Electrical Deregulation and Customer Choice Task Force to the Energy

Policy Task Force, which studies the State's energy needs.

03/00: Senate Bill 250 extended the Electrical Deregulation and Customer Choice Task Force until November 30, 2002.

03/99: Senate Bill 15 continued the Electrical Deregulation and Customer Choice Task Force through November 30, 2000,

and repealed the rate freeze from the prior session.

11/98: A draft report on restructuring was issued by the Utah Legislature's Electrical Deregulation and Customer Choice Task Force. The report is generally

favorable toward competition; however, it advises a "go slow" approach.

10/98: The Public Service Commission (PSC) of Utah issued a report to the Electrical Deregulation and Customer Choice Task Force on stranded costs. The Task

Force favors allowing the market to determine the value of stranded costs.

09/98: The PSC completed a report on market power for the Electrical Deregulation and Customer Choice Task Force. Market power is considered a "serious

problem."

08/98: The PSC completed a report on consumer protections for the Electrical Deregulation and Customer Choice Task Force.

06/98: The PSC's "Unbundling Electricity Related Services" report to the Electric Deregulation and Customer Choice Task Force detailed technical options for

separating the costs for generation, transmission, and distribution.

04/98: The Utah Legislature's Electrical Deregulation and Customer Choice Task Force is favoring a slower approach, and will not begin working on draft legislation

until the fall of 1998.

03/98: According to the Utah Division of Public Utilities' Electric Utility Restructuring timeline, HJR 7 recommended that the task force continue its work in 1998

and decide whether or not to introduce restructuring legislation in 1999. The bill also stated that the rate freeze should be allowed to expire and "a full rate hearing

for Utah Power & Light be allowed to proceed before the Utah Public Service Commission."

11/97: The task force voted to recommend no restructuring legislation for 1998 session. The task force will prepare draft legislation for a restructuring plan by April

1998 for introduction in the 1999 General Session.

03/97: House Bill 313 created a task force to study the various issues of electric industry restructuring. Draft report is due November 1997, and the final report is

due November 1998.
www.eia.gov/cneaf/electricity/page/restructuring/vermont.html 1/1

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Home > Electricity > State Restructuring > Vermont Restructuring

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Last Updated: April 2007

07/02: Senate Bill 138 (Act No. 145), a bill regarding net metering, took effect July 1, 2002. The act allows farms to produce

up to 150 kilowatts of electricity using renewable energy sources. The farm will receive renewable energy credits as long as it

produces "less energy than the annual load of the meters associated with the farm." As long as the farm has a certificate of

public good, an electric company "may contract to purchase all or a portion of the output from a farm system."

02/02: The Vermont Public Service Board (PSB) stated that it is no longer exploring the opportunities to open up its electric

market to competition, saying that there is too much uncertainty in the outcomes in restructuring the market.

Source: Vermont Public Service Board

http://w w w .state.vt.us/psb/

03/99: Central Vermont Public Service and Green Mountain Power filed a joint restructuring plan with the PSB of Vermont. The plan would consolidate the two

companies into one distribution company and would have both companies sell their generating assets and focus on distribution and retail sales.

12/98: The governor's Working Group on Vermont's Electricity Future issued a report that unveiled a restructuring plan. The report suggests that the industry in

Vermont should be restructured within the next year to 18 months, and the three major utilities in the State merge and that the contracts costs with Hydro Quebec

be paid down with State-backed loans.

08/98: The Governor created a task force to study restructuring activities regionally and nationally; the effects of Hydro-Quebec contracts on ratepayers; the State's

competitive position with a deregulated environment; and the effect of recent regulatory activities on Vermont utilities. A report is due by December 1998.

04/98: Several restructuring bills were considered in 1998 session. The session ended on April 17 with no action taken on any of the bills.

10/97: House Electric Utility Regulatory Reform Committee voted to not propose any retail wheeling legislation in 1998, but will draft its version of a restructuring bill

for 1999.

08/97: Prompted by the Senate bill, the House formed a special committee to study restructuring issues.

04/97: The Senate passed a bill based on the plan issued by the PSB that would have allowed retail choice by 1998; however, the bill stalled in the House.

12/96: Vermont Public Service Board (PSB) issued a report and order on electric power industry restructuring that called for retail competition by 1998, functional

unbundling, and allowed recovery of stranded costs. Implementation of the plan requires legislation.

10/95: The PSB opened docket 5854, a formal investigation into restructuring the electric power industry. An informal investigation yielded a set of principles for

implementing competition.
www.eia.gov/cneaf/electricity/page/restructuring/virginia.html 1/4

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Acronyms for the State of Virginia

AEP-American Electric Pow er

DVP-Dominion Virginia Pow er

FERC-Federal Energy Regulatory Commission

NOVEC-Northern Virginia Electric Cooperative

SCC-Virginia State Corporation Commission

VEPCO-Virginia Electric and Pow er Company

Home > Electricity > State Restructuring > Virginia Restructuring

Virginia Restructuring Suspended

Last Updated: April 2007

04/07: Governor signs SB 1416 which “advances the scheduled expiration of the capped rate period from December 31,

2010, to December 31, 2008, establishes a new mechanism for regulating the rates of investor-owned electric utilities,

and limits the ability of most consumers to purchase electric generation service from competing suppliers. The

ratemaking procedure requires the State Corporation Commission (SCC) to conduct a rate case for investor-owned

utilities in 2009; thereafter, the SCC will review each utility's rates, terms, and conditions using two 12-month test periods

ending December 31, 2010, though the SCC is given discretion to stagger the years in which it conducts such reviews.

In these biennial reviews the SCC will determine fair rates of return on common equity for the utility's generation and

distribution services, using any methodology it finds consistent with the public interest...Under the program, a

participating utility that meets specified percentage goals for sales of eligible renewable energy is eligible for a

Performance Incentive that increases the fair combined rate of return on common equity for the utility...With regard to the

ability of customers to purchase generation services from competing providers, the measure provides that after the

capped rate period ends, only customers whose annual demand exceeds five megawatts will be permitted to shop.”

Source: Virginia General Assembly

http://leg1.state.va.us/cgi-bin/legp504.exe?071+sum+SB1416

02/07: Legislation backed by the state's dominant power company to pull the plug on the state's experiment with electric utility deregulation was unanimously

endorsed by a Senate committee Monday evening. Meanwhile, the House of Delegates gave preliminary approval to a similar but competing version of the "reregulation" bill that contains some provisions the utility, Dominion Resources, dislikes.

Source: Associated Press authors Larry O’Dell and Bob Lew is via Dailypress.com

http://w w w .dailypress.com

01/07: Virginia State Sen. Thomas K. Norment introduced legislation that would replace the state's deregulated electric power market with regulated profits at 7

percent over utilities’ long-term bond costs.

05/06: Governor Tim Kaine signed Senate Bill 262 (SB 262) which initiates the development of a state energy plan and also amends earlier legislation so that

Dominion Virginia Power’s fuel rate must be adjusted annually until the rate cap expires in 2011.

Source: Virginia General Assembly

http://leg1.state.va.us/cgi-bin/legp504.exe?061+sum+SB262

09/05: The Virginia State Corporation Commission issued its 2005 status report and stated that little electrical retail competition has developed since restructuring

legislation was enacted. The commission states that rules are in place to promote retail choice. However, electricity suppliers still find that there is little economic

incentive to enter the retail market.

Source: Virginia State Corporation Commission

http://w w w .scc.virginia.gov/division/restruct/history.htm

04/04: Governor Mark Warner signed Senate Bill 651 (SB 651) which extends the retail electricity rates cap through 2010. The bill also allows Dominion Virginia

Power to hold its fuel rate at its present level until July 1, 2007, after which it can only be adjusted once more for the 31⁄2-year period ending Dec. 31, 2010.

Furthermore, the bill ends wires charges on July 1, 2007, expands local government options to form buying groups to save money on electricity for their citizens,

and sets up procedures to make it easier for many large commercial and industrial consumers to switch electricity suppliers.

Source: Dominion

http://w w w .dom.com/new s/elec2004/pr0415.jsp

08/03: The Virginia State Corporation Commission issued its 2003 status report and recommended suspending restructuring in the state. One of the commission’s

concerns is that Dominion Virginia Power is earning more than it would under a cost of service program.

Source: Virginia State Corporation Commission

http://w w w .scc.virginia.gov/division/restruct/history.htm

12/02: The Virginia State Corporation Commission released an Addendum to the 2002 Status Report on Competition called the Review of FERC’s Proposed

Standard Market Design and Potential Risks to Electric Service in Virginia. The report advocates for rebundling of retail rates and service because competition is

currently lacking. In addition, the study suggests that if Virginia reverted back to a regulated market, then the State would not be subject to the FERC’s standard

market design as long as the State’s jurisdiction was upheld.

12/02: The State Corporation Commission issued an order establishing an investigation into default service for electricity customers. According to an SCC press

release, “the staff will develop recommendations for establishing one or more default service programs that will be available by January 1, 2004.”

11/02: The Legislative Transition Task Force issued an order to examine utilities’ stranded cost recovery mechanisms, and convene the Stranded Costs Task

Force. The task Force released a stranded costs summary, which includes information on how Virginia utilities currently collect stranded costs from customers.

Customers fund stranded cost recovery through “a nonbypassable wires charge” until mid- 2007. The task force is considering two new proposals that would

eliminate the wire charges for industrial and commercial customers and halt minimum stay periods. The current rate cap would be lifted so retail customers could

pay market-based rates.
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11/02: The Virginia State Corporation Commission (SCC) released its 2003 average “price to compare” for Dominion Virginia Power, American Electric PowerVirginia, Allegheny Power and Conectiv. Customers can use the “price to compare” as guide to evaluating offers made by competitive service providers. On January

1, 2003, the final phase of Dominion Virginia Power’s restructuring will take effect, opening retail access to the utility’s residential customers in the Tidewater region. With implementation of this next phase, all customers of Dominion Virginia Power, AEP Virginia, Allegheny Power and Conectiv will have access to competitive

energy providers.

11/02: The Virginia State Corporation Commission (SCC) issued a report to the Legislature titled “The Feasibility, Effectiveness, and Value of Collecting Data

Pertaining to Virginia’s Energy Infrastructure.” Senate Bill 684 required the SCC to submit a “workgroup study” to the Legislature on this matter. According a SCC

press release, the “workgroup study” found that utilities, generators and customers “generally agree that collecting information does not appear to be a problem,” but

“the value and effectiveness of collecting the information is more difficult to ascertain,” especially after deregulation.

11/02: Dominion Virginia Power commissioned Chmura Economic & Analytics to conduct a report on how much a residential customer would save during the

capped rate period of 1998-2007. The utility’s rates are capped until July 1, 2007. A Dominion Virginia Power press release stated “the average annual savings per

residential customer range from $45 to $50 during the capped rate period.”

11/02: The Virginia State Corporation Commission increased the fuel rate from 1.31 cents per kilowatthour to 1.463 cents per kilowatthour for AEP-Virginia effective

January 1, 2003. The Virginia Electric Utility Restructuring Act allows the SCC to increase rates for fuel costs even during the rate cap period.

09/02: The Virginia State Corporation Commission released its 2002 Status Report to Governor Warner and the General Assembly. The report states, “At the time

of this report, only 2,500 residential consumers and 24 small commercial consumers are using an alternative supplier. The residential consumers that have switched

are customers of a competitive provider offering “green” power at a premium to the incumbent utility’s price-to-compare.” Another 750,000 Virginians will have access

to retail choice on September 1, 2002. The report concluded no competitive suppliers are offering a rate below the “price-to-compare,” and wholesale market power

is still evident.

08/02: The Legislative Transition Task Force of the Virginia Electric Utility Restructuring Act released its 2002 Report. The Task Force considered many proposals

to amend the 1999 Virginia Electric Utility Restructuring Act. The AES New Energy and Old Mill Power Company proposal suggested phasing out wire charges,

which they consider an obstacle to competition. The Task Force stated that the issue of wire charges would be addressed next year when they examine whether or

not the recovery of stranded costs has occurred.

06/02: According to a SCC press release, the commission approved Northern Virginia Electric Cooperative's (NOVEC) retail choice plan; set to begin after July 1,

2002. NOVEC will be responsible for delivering power to Clarke, Fairfax, Fauquier, Loudoun, Prince William, and Stafford counties, and the city of Manassas Park.

In Virginia, electric cooperatives have until January 1, 2004, to implement retail choice. NOVEC must file "price to compare" information with the SCC before the

plan can take effect. Since cooperatives rely on the wholesale market, "price to compare" rates can differ from month to month.

04/02: Dominion Retail is switching its 19,000 Virginia customers back to Dominion Virginia Power because it "has been unable to locate wholesale power at a

competitive price." The company cites wire charges as its main obstacle because customers are required to pay this charge before leaving Dominion Virginia

Power. Under Virginia's deregulation law, wire charges must be collected until 2007.

01/02: The State Corporation Commission (SCC) issued the average price to compare rates for each customer class. "The price to compare is the regulated price

of generation and transmission of electricity, less any applicable competitive transition charge." Competitive service providers use these rates to determine what it

must offer in order to attract customers. Eligible customers must contact their current supplier for the actual rates. According to the SCC's 2002 average "price to

compare" chart, overall AEP Virginia has the lowest average rates. However, Dominion Virginia Power has the lowest average rate in the large commercial class. All

AEP-Virginia, Allegheny Power, and Conectiv customers became eligible to choose an electric supplier on January 1, 2002. Dominion Virginia Power allowed only

its Northern Virginia residential customers and one-third of its non-residential customers to participate in electric choice on January 1, 2002, but it will phase in

electric choice by January 1, 2003 for the rest of its customers.

12/01: The SCC issued orders for each investor-owned and cooperative utility to functionally unbundle generation from delivery within each company. Virginia

Electric and Power Company and American Electric Power had requested legal separation of generation assets from the rest of the company, but the SCC denied

the requested plans, imposing only functional separation at this time. The orders direct each utility to maintain separate divisions along functional lines for the

generation, transmission and distribution functions. Customer choice for most customers in the State will begin January 2002 and by January 2004 all customers

will be able to choose their supplier for the generation portion of electric service. The incumbent utilities will continue to provide delivery service for all customers and

default service for the customers who do not choose an alternative provider. The SCC will set rates for the generation portion of service provided by incumbent

utilities, which will be capped during a transition period through 2007. Customers will be able to use this "price to compare" rate when deciding to remain with their

incumbent utility or choose a competing supplier for generation. The Virginia Energy Choice web site provides information about the new competitive energy supply

market in Virginia.

11/01: The phase-in of retail access in Virginia was issued by the SCC earlier this year. As of January 1, 2002, all customers of AEP-Virginia, Allegheny Power

(Potomac Edison), and Conectiv (Delmarva Power), as well as residential customers of Dominion Virginia Power (DVP) in Northern Virginia and 1/3 of DVP's nonresidential load throughout its service territory, will receive retail access to competitive electricity suppliers. On September 1, 2002, DVP's residential customers in

Central Virginia and another 1/3 of its non-residential load will have retail access. On January 1, 2003, DVP's customers in Eastern/Tidewater Virginia and the

remaining 1/3 of non-residential customers will receive retail access. On January 1, 2004, Kentucky Utilities (Old Dominion Power Company) and the 13 electric

cooperatives' customers will receive retail access.

10/01: The SCC issued an order regarding customer minimum stay periods (the time a customer must remain with the incumbent utility upon returning from

competitive supplier service). When returning to a capped rate or default service after receiving service from a competitive service provider, customers with an annual

peak demand of 500 kW or greater will be required to remain with the default supplier a minimum of 12 months. However, if the competitive service supplier leaves

Virginia, the minimum stay period will not apply to the affected customers. The complete set of rules governing retail access to competitive energy services

including minimum stay periods is located on the SCC's website.

09/01: The SCC staff presented to the 2001 Legislative Transition Task Force the required annual report on the status of development of a competitive retail

electricity market within Virginia. According to the report, the pilot programs currently underway in Dominion Virginia Power, American Electric Power, and

Rappahanock Electric Cooperative are not as successful as anticipated. Although some customers in Dominion Virginia Power’s area have switched to competitive

suppliers, none switched in AEP or Rappahanock’s areas, and no competitive suppliers are currently making offers for service in any area. The report also examines

other retail electricity markets in surrounding regions and found most to be under stress and undergoing decreasing participation. The report includes

recommendations by interested parties to facilitate competition in retail electricity markets. One suggestion, the elimination of price caps and wires charges, was

rejected by the SCC since these mechanisms are intended to protect both consumers and incumbent utilities.

06/01: The SCC adopted rules to advance a competitive energy supply market and protect customers that shop for alternative electric suppliers when the retail

market opens in January 2002. The SCC ruled that utilities will be required to provide lists of all eligible customers to competitive service providers. Customers will

have the opportunity to have the information withheld, known as the "opt-out" provision. Utilities will also be required to unbundle charges on customer bills into the

following components: distribution service, competitive transition charge, electricity supply service, state and local consumption tax, and local utility tax. Bills will

also include a customer's monthly energy consumption for the previous 12 months, a "price to compare" for shopping comparison to energy service providers prices,
www.eia.gov/cneaf/electricity/page/restructuring/virginia.html 3/4

descriptions of charges, and notices of any rate changes. Rules also provide numerous consumer protections and rights to information. The Virginia Energy Choice

web site provides information about the progress toward developing a competitive energy supply market in Virginia.

03/01: Senate Bill 1420, a bill concerning the designation of a default supplier and a mechanism for establishing default service rates, was enacted. The bill

designates the SCC as the deciding agent for supplier of last resort in a competitive retail market for electricity. Potential suppliers could bid to provide the service,

and the SCC can set the rates for default service, based on market rates. Other points contained in the bill: transfer or sale of generating assets would be subject to

SCC approval; competitive metering and billing, scheduled for 2002 and 2003, could be delayed; and suppliers would be allowed to recover the costs of

implementing competitive metering and billing through tariffs.

12/00: Pilot programs in Virginia have fallen short of full participation, but regulators feel there are enough participants to provide information and experience needed

for expanding the projects and eventual beginning of retail competition statewide in January 2002. About 18,000 out of 33,000 eligible participants have switched to

competitive suppliers in the Richmond area pilot program. The Northern Virginia area will begin its pilot program on January 1, 2001.

08/00: The State Corporation Commission (SCC) has approved Rappahannock Electric Cooperative's plans for a pilot program. The program will allow 900

customers to choose an alternative power supplier beginning January 1, 2001.

07/00: AEP will begin its pilot program by offering about 8,000 customers retail choice by October 1, 2000. Another 8,000 AEP customers will be added on March

1, 2000. The SCC will establish a "price to compare" by considering the prices at 5 nearby trading hubs and calculating an average of the prices at the two hubs

with the highest prices.

07/00: Phase I of Virginia Power's pilot program, Project Current Choice, has begun enrolling volunteers in the City of Richmond and Hanover, Henrico, and

Chesterfield counties, and the Town of Ashland. Plan A of the pilot includes over 35,000 small consumers, residential and churchs / synogogues in the above areas.

Larger commercial and industrial consumers statewide are included in Plan B, which will allow over 250 million kilowatt-hours of power to be supplied by alternative

suppliers. Pilot participants should begin receiving power from alternative suppliers by September 1, 2000. Phase II will enroll small and residential consumers in

several Northern Virginia locations. Phase II participants are scheduled to begin volunteering in October 2000 and receive power from alternative providers by January

2001. Phase-in of the entire State is scheduled to begin by January 2002.

02/00: The SCC issued rules for the pilot programs, requesting comments by February 24, 2000. Rappahanock Electric Cooperative filed a plan for a pilot program

with the SCC. And, AEP may expand its planned pilot program to include as many as 8,000 customers initially. Pilot programs are expected to begin in AEP and

VA Power territories by spring 2000.

12/99: Virginia Electric and Power Company’s (VEPCO) website includes a new page on its forthcoming pilot program for a competitive electricity market. The

program, Project Current Choice, will be one of the largest in the Nation, allowing about 700,000 consumers, or 400 MW of load, retail direct access. The pilot

program is expected to begin by mid- 2000.

09/99: Virginia Power reached a compromise with the SCC that will expand VEPCO's pilot project by about 3 times the original plan. The pilot program will include

customers from both Northern Virginia and Richmond.

09/99: AEP filed an outline for its pilot program with the SCC. AEP proposes to allow about 17,500 participants in a pilot program beginning in March 2001.

06/99: Legislation passed in June 1999 proposes to allow recovery of stranded costs through utility rates that will be capped through mid-2007, and a special wires

charge on customers who choose to leave their utility for a competitor.

06/99: The SCC is working on formulating rules for pilot programs in the State. A task force is discussing rules that will ensure that utilities do not take advantage

as distribution companies to assist an affiliated competitive power supplier, or use their transmission and distribution business to subsidize an affiliate competitive

energy supplier.

06/99: Two cooperatives, Mecklenburg and Rappahanock Electric Cooperatives, are proposing to develop retail access pilot programs. Cooperatives are not

required, as investor-owned utilities are by the restructuring legislation, to develop pilot programs.

03/99: The Virginia Electric Utility Restructuring Act, Senate Bill 1269, passed the General Assembly and was signed into law by the Governor. Highlights of the bill

include: creation of a regional transmission entity by January 1, 2001; deregulation of generation by January 1, 2002; phase-in of consumer choice between January

1, 2002 and January 1, 2004; rates capped through July 2007 for those who remain with the incumbent utility; recovery of stranded costs through capped rates for

customers staying with the incumbent utility and through a wires charge for those who switch to competitive suppliers; and consumer protections such as universal

service, education programs, fuel and emission disclosure requirements, and allowing aggregation for small consumers.

11/98: Virginia Power and American Electric Power have proposed pilot programs to the SCC. VP's Plan I program will involve about 17,000 residential and 1,700

small commercial customers in the Greater Richmond area; Plan II will be for large industrial customers. AEP's plan will involve about 2 percent (3,200) of its

Virginia customers.

08/98: The SCC approved more than $700 million in refunds and rate reductions. A total of $150 million in refunds will be provided by November 2, 1998. In return for

the refund/rate cuts, Virginia Power will use $220 million in revenue to reduce debt on generation assets.

06/98: In an agreement between regulators, government, and business and Virginia Power, VEPCO will refund $920 million, the biggest rate adjustment in Virginia

history, in rate cuts and refunds over the next 5 years. The rate reduction refund agreement is subject to approval by the SCC. A public hearing is scheduled for July

21, 1998 on the proposed settlement.

04/98: Restructuring legislation, House Bill 1172, was signed into law. The law establishes a schedule for retail competition beginning January 2002 and completion

by January 2004. Also, the law requires establishment of an independent system operator and allows recovery of net stranded costs. The General Assembly will

deal with details of restructuring issues such as stranded costs and public benefits programs in the 1999 session.

03/98: The SCC ordered investor-owned utilities to begin work on change to introduce retail competition to the State including the creation of an independent

system operator, power exchange, and plans for pilot programs. Utilities are to report on their previous activities and future plans by April 15, 1998.

11/97: The SCC issued a study on electric industry restructuring and a model for competition. The draft model recommends a five-year transition to full retail

access. Phase I, from 1998 to 2001, would involve unbundled rates and bills, a study of stranded costs, formation of an independent system operator and PX, and

pilot programs to study retail wheeling. Phase II, from 2000 to 2002, would involve decision-making for a competitive industry and utility plans for restructuring. Full

competition would then be phased-in through 2005.

11/96: The SCC issued an order calling for more study on competition in the industry. The SCC asked that the state move slowly toward retail competition.
www.eia.gov/cneaf/electricity/page/restructuring/virginia.html 4/4
www.eia.gov/cneaf/electricity/page/restructuring/washington.html 1/1

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WUTC-Washington Utilities and Transportation Commission

WWPC-Washington Water Pow er Company

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12/07: The Washington Utilities and Transportation Commission approved an agreement that reduces by 40

percent a proposed utility rate increase for Avista’s electric customers in Washington. Under the settlement

agreement, the average residential electric customer using 1000 kilowatt-hours a month will pay an additional

$6.39 a month for a total of $70.76. Avista sought the rate hike to pay for rising costs in the wholesale price of

natural gas used to generate some of the electricity it supplies to customers. The company also had made

significant investments in its transmission system and upgraded some hydroelectric projects.

Source: Washington Utilities and Transportation Commission

http://w w w .w utc.w a.gov/

10/01: Puget Sound's Time of Use Rate Plan, which was to expire in October 2001, has been extended through May 31, 2002. The program, originally for about

300,000 residential customers, also is being expanded to include about 20,000 nonresidential customers. Under the plan, customers' rates vary with on-peak and

off-peak hours. The program has resulted in a shift of about 5 percent of load from peak to off-peak hours, creating savings for both the utility and the customers.

05/01: The Washington Utilities and Transportation Commission (WUTC) announced a settlement between Puget Sound Energy and the utility's large industrial

customers. The utility's six largest industrial customers will be allowed to buy power from any source, including other utilities, power marketers and each other.

12/00: Two publicly owned utilities have had to raise their rates due to high wholesale prices in the western states. Snohomish Public Utility increased rates by 35

percent, effective in January 2001. Tacoma Power is considering a surcharge on bills of 86 percent, an unprecedented increase of between $70 and $100 monthly in

the cost of electricity for Tacoma's residential consumers.

06/98: The pilot program that will allow Washington Water Power Company's customers to choose the type of electric power they want to buy will begin 7/1/98.

05/98: Several bills were passed by the legislature: a net metering bill to allow net metering for on customer site generation from solar, wind, and small (under 25

kW) hydro; and an unbundling bill to require generation, distribution, transmission, control area services, and programs to benefit the public (i.e., low-income,

conservation) to be shown as separate charges for the purpose of preparing a report to the State Legislature. The bill did not require utilities to offer unbundled

services to consumers.

05/98: The WUTC completed Phase I of its investigation into electric restructuring concluding the pace nationwide is faster than expected.

04/98: House Bill 2831 passed the State Legislature and the Governor is expected to sign it. The bill requires utilities to study and submit reports on unbundling

their costs and the quality of service and reliability. Reports must be submitted by September 1998, and the WUTC will provide a consolidated report to the

legislature by December 1998.

02/98: Washington Water Power Company (WWPC) is selling blocks of wood and wind powered electricity in its pilot program.

12/97: Washington Water Power filed a new pilot program with the WUTC, "More Options for Power Service II," to replace their previous one. The pilot will allow

about 7,800 customers in WA and ID to choose among five energy service alternatives without changing energy service providers. The portfolio of options includes

traditional energy service, 2 variable market rate options, a "standard rate offer" based on BPA's preference rate, and a renewable resource rate. The pilot is

scheduled to begin in 1998 and go through 5/2000.

08/97: WUTC approved 2-year Pilot program submitted by Puget Sound Energy for 10,000 customers. The pilot will begin 11/1/97 and go through 12/99.

12/96: Regional study entitled Comprehensive Review of the Pacific Northwest Energy System is completed and accepted by four Northwest governors.

12/95: The WUTC issued its final guidelines after a year-long inquiry into retail wheeling and restructuring issues, favoring a gradual approach.
www.eia.gov/cneaf/electricity/page/restructuring/west_virginia.html 1/1

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10/00: In light of the low cost of electricity in West Virginia and the price spikes experienced this past summer in other

States that have restructured retail markets, lawmakers seem to need to be convinced that restructuring will benefit

West Virginia consumers. Before the provisions of the restructuring law can take effect, a resolution must be passed by

the legislature in 2001. Most concerns center on protecting small (residential) consumers from price increases.

09/00: The West Virginia Public Service Commission (PSC) has begun hearing testimony from electric utilities

regarding their plans for unbundling electric rates. Monongahela Power Company and The Potomac Edison Company,

both owned by parent company Allegheny Power, were the first to participate in the hearings. Hearings for the remaining West Virginia utilities are scheduled

throughout the months of October and November.

03/00: The Legislature approved the Electricity Restructuring Plan submitted by the PSC. The plan will allow retail choice by January 2001, unbundles and caps

rates until 2004, and provides commercial and industrial rate reductions through 2005. The legislation requires passage of a resolution in the 2001 session before

the provisions of the law can go into effect.

01/00: The West Virginia Pubic Service Commission (PSC) issued an order recommending a plan for restructuring on January 28, 2000. The PSC submitted this

plan, the culmination of three years of study, to the legislature for approval. The plan will implement consumer choice by January 2001, provides a rate freeze

through 2004, and will stabilize rates through 2014. In the plan, divestiture is not required, but utilities must transfer generation to a fully separate subsidiary by

2005.

09/99: The Consumer Advocate Division of the PSC argues that consumers in West Virginia have already paid the stranded costs associated with power plant

construction. They are also pushing for a rate cap in the deregulation plan to be developed for submittal to the legislature early next year. All parties are planning to

begin negotiation of the plan by November 1999.

01/99: The PSC scheduled 2 hearings in August of 1999 that will address electric restructuring issues such as stranded costs and consumer protections.

11/98: The PSC staff issued a status report on its study of deregulation in West Virginia stating that utilities, industrials, consumer advocates, and marketers have

failed to reach a final consensus on a restructuring plan in West Virginia.

10/98: The PSC pushed back the October 1998 deadline for its final report on restructuring to November 16, 1998.

09/98: The PSC suspended an October 1998 hearing on deregulation, delaying any plan to submit recommendations to the 1999 legislature. No hurry is seen to

enact deregulation since West Virginia rates are low.

06/98: A report was filed with the Consumer Advocate Division of the PSC stating that the public interest would not be served by the current proposals to deregulate

the State’s electric power industry. West Virginia enjoys some of the lowest rates in the Nation, and it is feared that rates for residential consumers would rise in a

competitive electricity market.

05/98: In compliance with HB 4277, a new restructuring docket was established. Proponents of deregulation are requested to file plans meeting criteria in HB 4277.

A series of restructuring workshops will be held this summer and fall. Proposed plans have been submitted by 11 parties including AEP.

03/98: House Bill 4277 was passed to give the PSC authorization to develop a restructuring plan for presentation to the legislature in January 1999. The plan will

require legislative approval. The principles which a restructuring plan should be based on are included in the legislation.

01/98: A bill was introduced to the legislature to authorize the PSC to design and implement an electricity deregulation plan.

05/97: The PSC formed a task force to study restructuring, and a report is due October 1997.
www.eia.gov/cneaf/electricity/page/restructuring/wisconsin.html 1/1

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12/00: Wisconsin Public Service Resources (WPS) filed a restructuring plan with the Wisconsin Pubic Service

Commission (PSC) that would transfer WPS generating assets to a nonregulated subsidiary (genco) and transform Wisconsin Public Service Corporation into a regulated electric distribution company (disco). A power purchase agreement

between the disco and genco would be executed, and ratepayers would retain the same rates as they have today. WPS

sees this plan that would remove power plants and their construction from rate bases as a step toward a competitive

market in Wisconsin, something they see as inevitable due to surrounding states restructuring status.

10/99: A proposal called "Reliability 2000," includes a budget plan to restructure the utility industry. It estimates a cost of

$14 per year per consumer for energy conservation projects and low-income assistance programs; would create a nonprofit

company to own and operate the transmission system; and would lift a rule that limits a utility's investments to 25 percent

of its assets.

09/99: Wisconsin Electric Power Company requested that the PSC establish criteria for performance-based ratemaking. WEPC also submitted a request for a 3.1-

percent rate increase.

04/98: Legislation to improve reliability and prevent power shortages by establishing a competitive merchant plant generating industry and creating a regional

independent system operator was signed into law on April 28, 1998. The law will allow merchant plants up to 100 MW to be built without PSC approval, and utilities

are required to join an ISO and create 50 MW of power from renewable sources by 2000.

04/98: IES Inc., Interstate Power Co., and WPL Holdings, Inc. merged and began operation as a new company named Alliant.

01/98: A bill authored by the Governor was introduced in the 1998 session that considers the reliability issues as proposed in the PSC final decision of October 30,

1997.

11/97: The PSC issued its final decision on electric industry restructuring. The plan does not recommend retail access before 2000, but focuses on improving the

utility infrastructure. Recommendations included improving transmission facilities; removing barriers to open transmission access; developing an ISO; promoting

construction of merchant plants; and promoting the development of renewable energy resources.

08/97: The PSC submitted its draft 7-step work plan to restructure the electric industry to the legislature. The plan focuses on reliability and infrastructure

improvements, and does not recommend retail access at least until 2000. A final decision is set for October 30, 1997.
www.eia.gov/cneaf/electricity/page/restructuring/wyoming.html 1/1

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06/98: The Wyoming Public Service Commission (PSC) had scheduled a hearing on deregulation in June 1998 to establish

voluntary guidelines for utilities, but the hearing was canceled in response to legislator's concerns.

09/97: A joint committee of the Wyoming Legislature began a series of hearings on electric industry restructuring.

09/97: The PSC released the Study of the Potential Economic Impacts of Electric Restructuring on the State of Wyoming,

a report commissioned by the PSC and completed by Black & Veatch and Planning Information Corporation on September

15, 1997. The paper stated that further study was needed; legislation would be needed; stranded costs should be recoverable; and pilot programs should be

developed.

Source: Wyoming Public Service Commission

http://psc.state.w y.us/htdocs/electric/econimpact/w yoming.pdf