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://www.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://www.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://www.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://www.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://www.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://www.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.

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 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 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.

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.