The deregulation of energy in California was a short-lived 1996 experiment that opened the state’s electricity generation market to competition, collapsed into the 2000–2001 energy crisis, and was effectively reversed by emergency state intervention. The regulatory system Californians live under today was built in reaction to that failure, and it still shapes retail bills, procurement rules, and who can sell power to whom.
What the 1996 Deregulation Law Did
California formalized its push toward competitive electricity markets with Assembly Bill 1890, signed on September 23, 1996. Before restructuring, a single utility handled everything for each customer: generation, transmission, distribution, metering, and billing. AB 1890 broke that model apart by making electricity generation competitive while keeping the poles-and-wires infrastructure under regulation.1U.S. Energy Information Administration. California Electric Energy Crisis – Provisions of AB 1890
A common misconception is that AB 1890 forced the state’s investor-owned utilities to sell their power plants. The law didn’t mandate divestiture. It authorized the California Public Utilities Commission to allow plant sales if doing so would mitigate market power concerns. In practice, the CPUC encouraged the large utilities to sell, and they did, unloading much of their generation capacity to unregulated companies in a bid to recover stranded costs and enter the new competitive era on favorable terms.2California Public Utilities Commission. Attachment B – Regulatory Background
Two new institutions were set up to run the restructured system. The Independent System Operator took operational control of the high-voltage transmission grid so no utility could favor its own generators when granting access to power lines. The Power Exchange operated like a commodities market where generators competed through daily auctions, with prices changing hourly and all information made public.1U.S. Energy Information Administration. California Electric Energy Crisis – Provisions of AB 1890
During a four-year transition, the large utilities were required to bid their remaining generation into the Power Exchange and buy back whatever they needed from that same spot market. This was meant to prevent self-dealing, but it also left utilities dangerously exposed to wholesale price swings with no ability to lock in long-term supply contracts.
To make the deal palatable for consumers, AB 1890 froze retail electricity rates at June 10, 1996 levels and layered on an additional 10 percent discount for residential and small commercial customers. The frozen rates were set higher than the utilities’ actual costs at the time, giving them a window to recover transition costs through a Competition Transition Charge on customer bills. In exchange, utilities accepted the risk that not all transition costs would be recovered by the March 31, 2002 deadline.3California Public Utilities Commission. D0401026 Final Decision on End of Rate Control Period
Why the Market Collapsed in 2000 and 2001
The structure built by AB 1890 contained a fatal flaw: retail prices were frozen while wholesale prices were not. When wholesale costs were low, utilities pocketed the difference and paid down transition costs. When wholesale prices exploded, utilities had no way to pass those costs through to customers and began hemorrhaging money.
The explosion came fast. The average wholesale clearing price on the Power Exchange was $29.71 per megawatt-hour in December 1999. By December 2000, it had climbed to $376.99, more than eleven times higher.4U.S. Energy Information Administration. Subsequent Events – Californias Energy Crisis Several factors converged. A drought reduced hydroelectric output. Natural gas prices spiked. Demand grew faster than new generation came online. And energy traders manipulated the market.
The crisis was not just bad market design meeting bad luck. Energy companies, most infamously Enron, exploited the system’s vulnerabilities for profit. Traders overstated how much power they needed so they could collect premium payments for releasing the excess. Others routed power on unnecessary paths to trigger congestion fees. Still others bought power at California’s capped price and resold it out of state for a markup. The Federal Energy Regulatory Commission later revoked Enron’s authority to sell power at market-based rates in June 2003 and pursued settlements against dozens of companies, with El Paso Corporation agreeing to pay $1.7 billion in November 2003.5Federal Energy Regulatory Commission. Chronology at a Glance
The Power Exchange ceased operations at the end of January 2001 and filed for bankruptcy in March, destroying the day-ahead market that had handled roughly 80 percent of electricity sales in the state. Rolling blackouts hit hundreds of thousands of customers. Pacific Gas and Electric Company filed for Chapter 11 bankruptcy on April 6, 2001, reporting $9 billion in wholesale power costs that frozen retail rates made unrecoverable.6PG&E Corporation. Pacific Gas And Electric Company Files For Chapter 11 Reorganization Southern California Edison came close to the same fate before negotiating a financial rescue.
How California Ended the Deregulation Experiment
With utilities on the brink and the Power Exchange defunct, the state intervened directly. Emergency legislation known as AB 1X authorized the California Department of Water Resources to step in as a power buyer, purchasing electricity and selling it to the retail customers of PG&E, Southern California Edison, and San Diego Gas & Electric. DWR’s contract authority ran through December 31, 2002, though it continued administering existing contracts after that date.7California Public Utilities Commission. Wood Revised Alternate Decision Implementing Cost Recovery
That move effectively ended retail electricity competition in California. DWR locked in long-term power contracts that replaced the volatile spot market, and the CPUC resumed its traditional role of overseeing utility procurement and setting retail rates. PG&E emerged from bankruptcy in April 2004.8PG&E Corporation. Pacific Gas And Electric Company Emerges From Chapter 11 The political fallout was severe. The crisis helped fuel a recall election on October 7, 2003 that removed Governor Gray Davis, the first successful gubernatorial recall in California history since 1911.
Who Regulates California Electricity Now
The system that replaced deregulation is split between two regulators, and the boundary between them determines how costs reach your bill.
Under Section 201 of the Federal Power Act, FERC has authority over wholesale electricity sales and the interstate transmission of electric energy. The high-voltage transmission network that moves power across regions and state lines falls under FERC’s rate-setting authority. FERC also oversees reliability standards for the bulk power system and regulates wholesale power markets.9California Public Utilities Commission. Protecting California Electricity Customers – CPUC Transmission Advocacy at FERC
The CPUC, by contrast, sets retail electricity rates and regulates local distribution, meaning the part of the system that delivers power from substations to homes and businesses. Transmission costs approved by FERC flow into the retail rates California customers pay, which is why state statute charges the CPUC with representing retail electric customers in federal proceedings.9California Public Utilities Commission. Protecting California Electricity Customers – CPUC Transmission Advocacy at FERC
Community Choice Aggregation
California didn’t entirely close the door on alternatives to utility-controlled procurement. Assembly Bill 117, signed on September 24, 2002, created the Community Choice Aggregation framework, which has become the most significant surviving competitive element in the state’s electricity market.10California Legislative Information. California Assembly Bill 117 – Electrical Restructuring Aggregation
Under the CCA model, a city, county, or group of local governments can purchase electricity generation on behalf of all residents and businesses within their boundaries. The local government becomes the default power supplier for generation, though individual customers can opt out and stay with the traditional utility. The investor-owned utility keeps its monopoly over transmission, distribution, metering, and billing. It just no longer controls where the electrons come from for CCA customers.11California Legislative Information. California Assembly Bill 117 – Electrical Restructuring Aggregation
Roughly 25 CCA programs now operate across the state, and many emphasize procuring higher percentages of renewable energy than the utilities they replaced. Two mechanisms exist to manage the friction CCAs create.
The Power Charge Indifference Adjustment
When customers leave an investor-owned utility for a CCA, the utility still holds long-term generation contracts it signed when those customers were part of its load. The Power Charge Indifference Adjustment exists so remaining customers don’t shoulder those stranded costs. The PCIA equals the cost of the utility’s legacy generation portfolio minus that portfolio’s current market value. When legacy contracts cost more than market rates, departing CCA customers pay the difference as a surcharge on their bills.12California Public Utilities Commission. Power Charge Indifference Adjustment
The PCIA is one of the most contentious elements of California’s current framework. CCAs argue it inflates their customers’ costs and undermines the savings that make community choice attractive. Utilities counter that without it, their remaining customers would subsidize departed load. The methodology has been revised multiple times, most recently in 2025.
Provider of Last Resort
Senate Bill 520, enacted in 2019, designated the investor-owned utility as the Provider of Last Resort, the backstop that must absorb returning customers if a CCA shuts down or decertifies. The CPUC initiated a rulemaking in March 2021 to develop rules ensuring cost recovery, continuity of service, and reliability if that scenario materializes.13California Public Utilities Commission. Provider of Last Resort The POLR designation means the large utilities can never fully exit the generation business even as CCAs chip away at their customer base.
Direct Access Is Capped and Closed to Residential Customers
Direct Access, authorized as part of the 1996 restructuring, allows individual commercial and industrial customers to buy electricity from competitive Electric Service Providers while the utility continues to handle transmission and distribution. It was suspended during the energy crisis and remained frozen for years. Senate Bill 237, enacted in 2018, expanded the statewide enrollment cap to roughly 28,800 gigawatt-hours, with new enrollment allocated by lottery.14California Public Utilities Commission. Direct Access
The CPUC concluded in 2021 that it could not find further expansion consistent with greenhouse gas goals, grid reliability, and avoidance of cost-shifting, and recommended against it. Direct Access remains limited to nonresidential customers. Residential consumers’ realistic alternatives today are bundled utility service or a CCA.
Clean Energy Mandates Apply to Every Supplier
California’s post-crisis framework has evolved well beyond keeping the lights on. The state has layered increasingly aggressive clean energy requirements onto every load-serving entity, meaning utilities, CCAs, and Electric Service Providers alike.
The Clean Energy and Pollution Reduction Act of 2015, known as SB 350, established a target of 50 percent renewable procurement by December 31, 2030, with interim milestones: 25 percent by the end of 2016, 33 percent by 2020, 40 percent by 2024, and 45 percent by 2027. The law also set a goal of doubling statewide energy efficiency savings by 2030 and required the electricity sector to meet greenhouse gas reductions of 40 percent below 1990 levels by 2030.
Senate Bill 100, enacted in 2018, went further by requiring that 100 percent of California’s retail electricity sales come from renewable and zero-carbon resources by 2045.15California Energy Commission. SB 100 Joint Agency Report The target applies to every entity that sells electricity to California consumers, so a customer’s generation mix must reach zero carbon within two decades regardless of whether their power comes from PG&E, a CCA, or a direct access provider.
Resource Adequacy
Clean energy mandates don’t help if the grid can’t keep the lights on during a heat wave. California’s Resource Adequacy program requires every entity serving retail customers to lock in enough generation capacity to meet demand under stressed conditions.
The CPUC requires all load-serving entities to demonstrate procurement across three categories: system-wide needs, local reliability needs in specific areas, and flexible capacity that can ramp quickly to follow demand swings. Each entity must procure its share of projected peak demand plus a 17 percent planning reserve margin.16California Public Utilities Commission. Resource Adequacy Homepage
Entities that fall short face financial penalties. There is no waiver for an inability to find capacity. Deficiencies not cured within five business days trigger penalties, and a tiered point system adopted in 2022 escalates the consequences for repeat shortfalls.17California Public Utilities Commission. Resource Adequacy Penalties and Citations The 2000–2001 crisis showed what happens when no one is responsible for ensuring adequate supply. The current system places that responsibility on every entity that sells a kilowatt-hour.
Wildfire Liability and the Fund That Keeps Utilities Solvent
California’s investor-owned utilities face a financial risk that has nothing to do with deregulation but everything to do with the regulatory environment that followed it. Under the state’s interpretation of inverse condemnation, a utility can be held strictly liable for wildfire damages caused by its equipment even if the utility met all safety requirements and properly maintained its infrastructure. Negligence is irrelevant.18California Public Utilities Commission – Public Advocates Office. Ratepayer Impacts of Strict Liability and Inverse Condemnation
That exposure nearly destroyed PG&E a second time. The company filed for bankruptcy again in 2019 after catastrophic wildfires, and the state responded with AB 1054 the same year, creating a Wildfire Fund capitalized with an initial cash infusion of up to $10.5 billion. Large utilities contribute through initial payments and annual contributions of $300 million multiplied by each utility’s share of the statewide allocation. To access the fund, a utility must hold a safety certification requiring an approved wildfire mitigation plan, a board-level safety committee, and executive compensation structures tied to safety performance.19California Legislative Information. California AB 1054 – 2019-2020 Regular Session
The state later enacted SB 254, creating a wildfire fund continuation account providing an additional $18 billion for future wildfire claims. Funding comes from a mix of extended customer surcharges, annual utility contributions running through 2045, and contingent utility payments if the fund administrator requests them. A report due in April 2026 will recommend new approaches for allocating wildfire costs across stakeholders going forward.
Every ratepayer in the state has a financial stake in keeping these utilities solvent. Credit rating agencies have made the point bluntly: without a fund of roughly $20 billion, a utility like PG&E struggles to maintain investment-grade credit, and full depletion of the fund could cap its rating at junk status.
Where the Market Stands
California’s energy market in 2026 looks nothing like what AB 1890’s authors envisioned. Full retail competition is gone. The state operates a hybrid system where the CPUC regulates retail rates and oversees utility procurement, FERC governs wholesale markets and transmission, community choice aggregators handle an expanding share of generation procurement, and every load-serving entity must meet strict capacity and clean energy requirements. The 1996 experiment with deregulation lasted barely four years in practice. The regulatory infrastructure built in response to its failure has now lasted more than two decades and shows no signs of yielding to another round of market liberalization.