California’s power industry is divided into five key segments:

• generation;
• distribution;
• transmission;
• storage; and
• supply (retail sales).

Key entities involved in these various segments include:

• investor-owned utilities (IOUs);
• publicly owned utilities (POUs);
• independent power producers (IPPs);
• community choice aggregators (CCAs); and
• direct access (DA) energy service providers (ESPs).

The California power industry is primarily unbundled, meaning that no single entity typically controls the entire process. This is a result of Assembly Bill (AB) 1890 (1996), known as the “Utility Restructuring Act”, which initiated the unbundling of generation from transmission and distribution for IOUs. The legislation introduced competition in the supply segment, transferred grid operation to the California Independent System Operator (CAISO), and led to the eventual rise of CCAs and third-party suppliers.

Generation

Generation is the production of electricity, and is performed by IPPs, IOUs, and POUs.

Distribution

Distribution is performed by IOUs or POUs within exclusive, state-regulated service areas. These entities are required to provide distribution service to all customers in their designated territories.

Transmission

Transmission consists of high-voltage lines owned by a combination of IOUs, POUs and private independent developers.

Nearly all transmission within the CAISO balancing authority area is centrally operated by CAISO, regardless of ownership. However, POUs, like the Los Angeles Department of Water and Power (LADWP) and Sacramento Municipal Utility District (SMUD), maintain separate ownership and operational control of their own networks outside the CAISO balancing area authority.

Storage

Storage is owned and operated by a combination of IOUs, POUs, IPPs, CCAs, private companies or individual customers.

Storage systems may be classified as generation, transmission, or distribution assets, depending on their function within the electricity system. This classification determines how storage assets are regulated, who can own them, and how their costs are recovered from ratepayers.

Supply

Supply (retail electricity sales) is provided by a combination of IOUs, POUs, CCAs and ESPs, depending on local market access and customer eligibility.

Principal laws governing the ownership and structure of California’s power industry include the following.

• The California Public Utilities Code:
1. Sections 216–218 define electric corporations and public utilities;
2. Section 366.2 enables the formation of CCAs; and
3. Sections 454.51–454.53 require utilities to meet planning and clean energy goals.
• Senate Bill (SB) 100 (2018) sets a statewide goal of 100% zero-carbon electricity by 2045.
• AB 2514 and AB 2868 support energy storage procurement and pilot programmes.
• The Federal Power Act (FPA) grants the Federal Energy Regulatory Commission (FERC) authority over interstate transmission and wholesale electricity markets.
• The California Environmental Quality Act (CEQA) applies to most major infrastructure projects, requiring environmental review and public input.

In California, the principal entities in the power industry include IOUs, POUs and CCAs.

IOUs and POUs provide retail electric sales and are responsible for the generation, distribution and transmission systems located within their respective service territories.

The majority of California’s population is served by the state’s three large IOUs:

• Pacific Gas and Electric (PG&E);
• Southern California Edison (SCE); and
• San Diego Gas and Electric (SDG&E).

PG&E’s service territory spans from Santa Barbara to Shasta Counties, SCE’s territory spans from Riverside to Mono Counties, and SDG&E serves San Diego County and southern Orange County.

The largest POUs in California include the Los Angeles Department of Water and Power (LADWP) and Sacramento Municipal Utility District (SMUD); there are currently 37 total POUs operating throughout California.

CCAs are local government entities that buy electricity on behalf of customers within the IOUs’ service territories, while the IOUs remain responsible for power delivery and other customer service functions. There are currently 25 CCAs operating throughout California.

The OBBBA, signed on 4 July 2025, broadened FEOC restrictions across a wider set of clean energy tax credits and formally redefined “prohibited foreign entities” to include both specified foreign entities and foreign-influenced entities. It introduced more stringent eligibility rules by prohibiting taxpayers themselves from being FEOCs and limiting “material assistance” (equipment, components, financing, or control) from such entities in qualifying projects. Many of the expanded restrictions generally became effective on 1 January 2026 while others track the tax years following enactment, replacing prior narrower IRA-only applications and extending to multiple credits (eg, 45X, 45Y, 48E). The law also imposes escalating thresholds on allowable foreign involvement, requiring increasing shares of non-FEOC content in projects over time to maintain eligibility.

Overall, the impact is a materially tighter regime that increases compliance complexity, restricts access to tax incentives, and accelerates supply chain decoupling from foreign adversary-linked entities – while potentially dampening or delaying clean energy investment due to stricter qualification requirements and uncertainty.

There are restrictions regarding the sale of power industry assets or businesses, or for other transactions, including mergers in California. In California, any proposed sale, lease, transfer or merger involving IOU-owned electricity assets – including generation, transmission, storage or distribution infrastructure – is subject to California Public Utilities Commission (CPUC) review and approval.

The two principal laws governing the sale or transfer of these IOU-owned assets are Public Utilities Code Sections 851 and 854.

Section 851 (Transfer of Property)

Under Section 851, IOUs are required to obtain CPUC approval before selling, leasing, assigning or otherwise disposing of any property necessary or useful in the performance of their duties to the public. Transactions valued above USD5 million are subject to review and approval through the CPUC’s formal application process. Certain transactions valued under USD5 million may be reviewed and approved through the CPUC’s advice letter process.

To approve a Section 851 request, the CPUC must make a formal determination that the proposed transaction “is not adverse to the public interest”. The CPUC has broad discretion to make this determination, and may apply a heightened standard, including whether the transaction will serve the public interest or result in a “tangible ratepayer benefit”. Such heightened standards are typically applied to novel, unprecedented transactions, as well as to transactions that could potentially impact rates or the CPUC’s jurisdiction.

Section 854 (Utility Acquisitions)

Section 854(a) prohibits any person or corporation from directly or indirectly merging, acquiring or controlling a California IOU without prior CPUC approval. This is intended to ensure that the CPUC can evaluate whether the change in control would be consistent with and promote the public interest.

Section 854 sets forth several public interest factors to be considered, including potential impacts on the IOUs’ financial condition, quality of service, quality of management, and the CPUC’s capacity to effectively regulate and audit public utility operations.

To approve a Section 854 application, the CPUC must find that the transaction:

• provides short-term and long-term economic benefits to ratepayers;
• equitably allocates 50% of forecasted economic benefits to ratepayers;
• does not adversely affect competition; and
• ensures that the resulting corporation will have an adequate workforce to maintain the safe and reliable operation of the utility assets.

Interstate Transmission Facilities

Section 203 of the FPA mandates that a “public utility” (which includes entities involved in interstate wholesale sales) must obtain FERC approval before selling, leasing or otherwise disposing of facilities used for interstate transmission or wholesale sales, if the value of the assets exceeds USD10 million. FERC approval is also required for mergers or consolidations and the purchase, lease, or acquisition of an existing generation facility.

California does not have a single, centralised agency that oversees every aspect of electricity supply and infrastructure development. Instead, the responsibility is shared among CAISO, the CPUC, the California Energy Commission (CEC) and the California Air Resources Board (CARB). Each agency has distinct roles related to energy supply adequacy, system reliability and grid development.

CAISO

CAISO is a non-profit, federally regulated organisation responsible for managing the flow of electricity across about 80% of California’s high-voltage transmission grid. It functions as the real-time system operator and wholesale market administrator.

Scope of authority

CAISO performs the following within its scope of authority:

• balances supply and demand in real time;
• oversees grid reliability and contingency planning;
• runs day-ahead and real-time electricity markets, including regional market platforms such as the Western Energy Imbalance Market (WEIM) and, as of May 2026, the Extended Day-Ahead Market (EDAM), which expands co-ordinated day-ahead operations with participating utilities in the west;
• leads the Transmission Planning Process (TPP) to identify new grid infrastructure needs; and
• evaluates proposed generation and storage projects for system integration.

CAISO does not own any grid infrastructure – it controls facilities owned by IOUs and independent transmission developers.

CPUC

The CPUC regulates IOUs, CCAs and ESPs, and is the lead agency for long-term resource planning and distribution systems oversight. While the CPUC does not have rate-making responsibility for transmission lines, it does have a significant role in permitting transmission and substation facilities.

Scope of authority

The CPUC performs the following within its scope of authority:

• ensures that IOUs, CCAs and ESPs procure sufficient resources to meet demand and achieve state renewable energy goals through integrated resource planning (IRP) and procurement mandates, including procurement of distributed energy resources;
• sets reliability standards for utilities and mandates compliance with resource adequacy requirements;
• reviews IOU proposals for new generation, storage and distribution investments;
• approves IOU power purchase agreements; and
• approves funding and cost recovery for IOUs’ distribution infrastructure operations and capital projects.

CEC

The CEC is a state administrative agency responsible for statewide planning and forecasting.

Scope of authority

The CEC performs the following within its scope of authority:

• conducts long-term electricity demand forecasts;
• leads energy policy development and building standards; and
• certifies the siting of new thermal power plants of 50 MW and above.

On 7 October 2023, Governor Gavin Newsom signed into law Assembly Bill (AB) 1373, authorising the CPUC to request that the Department of Water Resources (DWR) act as a central procurement entity (CPE). The CPE is responsible for procuring electricity from certain long lead-time resources on behalf of customers of all load serving entities (LSEs) subject to the CPUC’s IRP procedure. In August 2024, the DWR was directed, as the CPE, to procure 10.6 GW of long lead-time emerging technologies.

Regional Organization for Western Energy (ROWE)

In an effort to establish durable, independent oversight of wholesale electricity markets in the west, stakeholders across 11 states are in the process of establishing a new Regional Organization for Western Energy (ROWE). The ROWE would serve as an independent entity with authority over existing and voluntary market services, including the Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). While ROWE would set policy and be the governing body for the WEIM and EDAM, California Independent System Operator (CAISO) would still perform operational functions. ROWE is currently working towards seating an initial board of directors and forming legal and organisational structures.

Over the past year (May 2025 to May 2026), California’s power sector has seen several material changes in law and regulations affecting the State’s carbon market framework, resource adequacy compliance, long-term procurement planning, energy storage oversight, and regional wholesale market co-ordination.

Cap-And-Trade Extension and Programme Redesign

In September 2025, California enacted AB 1207, extending the State’s cap‑and‑trade programme through 2045 and reframing the programme as “Cap‑and‑Invest”, establishing a longer-term statutory platform for the carbon market and related cost‑containment/affordability mechanisms. AB 1207 also directs CARB to update implementing regulations to reflect the legislature’s revised programme design and policy priorities.

Senate Bill 254

In September 2025, California enacted SB 254, an omnibus energy bill that includes measures related to public financing and ownership options for electric transmission infrastructure, wildfire mitigation financing, streamlined clean energy permitting, and limits on certain wildfire mitigation capital expenditures earning a return on equity through the IOU rate base.

Resource Adequacy Slice of Day Construct Implementation

The CPUC has implemented the new resource adequacy (RA) framework known as Slice of Day (SOD), and continues to explore refinements. This framework represents a fundamental shift in how RA compliance is measured for IOUs, CCAs, and ESPs. Rather than relying on a single peak demand hour, the SOD construct requires LSEs to demonstrate that sufficient capacity is available to meet demand in every hour of a 24-hour period, each month.

IRP procurement (2029–2032)

The CPUC adopted a final decision directing CPUC‑jurisdictional LSEs to procure 6,000 MW of new clean net qualifying capacity (NQC) for reliability needs in 2029–2032 (delivered in 2,000‑MW tranches by June 2030, June 2031, and June 2032), in response to forecast demand growth and an identified reliability shortfall.

Assembly Bill 825 (Pathways/ROWE Governance Framework)

In September 2025, California enacted AB 825, which establishes a statutory pathway for CAISO and participating transmission owners to participate in voluntary energy markets governed by an independent regional organisation. AB 825 conditions participation on specified governance and public‑interest safeguards and contemplates that, no earlier than 1 January 2028, CAISO may implement FERC‑accepted tariff changes to operate markets governed by the independent entity, subject to required findings and approvals, including CPUC involvement for electrical corporation participation.

Long‑Term Transmission Planning (CAISO Order 1920 Compliance Filing)

On 9 December 2025, CAISO filed tariff revisions in ER26‑704‑000 to implement Order 1920’s long‑term regional transmission planning framework. In the tariff sheets, CAISO explains that beginning in 2027 it will transition to two complementary planning tracks: a biennial comprehensive transmission plan (issued every two years, with the first issued in 2030) and a Long‑Term Regional Transmission Plan conducted every five years (also first issued in 2030).

Enhanced Standards for Energy Storage Systems

In March 2025, the CPUC adopted General Order (GO) 167-C, which significantly expands and updates the operational and safety standards applicable to electric generating assets. These standards now explicitly apply to battery energy storage systems, and include new mandates for maintenance, operation protocols, emergency response planning, incident reporting, and co-ordination with CAISO on outages.

There have been several new policies and initiatives that would result in material changes for the power industry in California.

Federal Policies

In early 2025, President Donald Trump issued a series of Executive Orders (EOs) targeting aspects of the Inflation Reduction Act (IRA) (2022), particularly certain clean energy tax credits, and directing the Environmental Protection Agency (EPA) to reconsider regulations for power plants, including emissions and wastewater standards issued in 2024. These efforts, in addition to potential tariff changes, introduce considerable uncertainty for renewable energy project development, supply chains and long-term compliance planning for fossil fuel generators nationwide.

One Big Beautiful Bill Act (2025)

The Act represents a federal shift in US energy policy, prioritising expanded domestic fossil fuel production while scaling back federal support for clean energy. It mandates increased oil and gas leasing on federal lands and offshore areas, restores favourable tax treatment for fossil fuel producers, and relaxes certain regulatory constraints, signalling a renewed focus on energy independence and traditional energy sources.

In addition, the Act repeals, restricts, or accelerates the phaseout of many clean energy incentives introduced under the Inflation Reduction Act, including tax credits for wind, solar, electric vehicles, and energy efficiency programmes, while imposing stricter eligibility rules and foreign-entity restrictions on remaining credits.

Overall, the bill reorients federal energy policy away from subsidies for renewable energy and toward support for oil, gas, coal, and certain technologies like carbon capture, with broader implications for energy markets, investment, and decarbonisation efforts in the United States.

US Environmental Protection Agency Emergency Waiver

On 25 March 2026, the US Environmental Protection Agency (EPA) issued a temporary emergency fuel waiver under the Clean Air Act to address anticipated fuel supply disruptions and high gasoline prices. The waiver permits nationwide summer sales of E15 gasoline (15% ethanol), which are normally restricted due to volatility and air-quality rules.

In addition, the EPA temporarily waived certain federal fuel standards, including low‑volatility requirements and federal enforcement of state “boutique” fuel rules, effectively enabling a single national gasoline standard with 9–15% ethanol content.

The agency stated that the action was taken in the public interest to increase fuel supply, stabilise markets, and reduce costs for consumers ahead of the summer driving season, particularly in light of global supply disruptions.

CARB Cap-and-Invest Program Amendments

In 2026, CARB initiated rule-making to implement amendments to the Cap-and-Invest regulation (formerly Cap-and-Trade).

CARB’s proposals include changes to allowance allocation methodologies, industrial assistance mechanisms, and product-based benchmarks, with a focus on addressing emissions leakage risk for emissions‑intensive, trade‑exposed (EITE) industries. The proposed changes are also framed in part as addressing affordability and competitiveness considerations within the carbon market framework.

Implementation of Climate-Related Disclosures

On 26 February 2026, CARB officially adopted the initial regulations for the California Corporate Greenhouse Gas Reporting Program, authorised by SB 253 (2023). This programme requires companies with total annual revenues in excess of USD1 billion that do business in California to submit annual reports disclosing their emissions. Scope 1 and 2 Emissions reporting begins in 2026, with the first report due by 10 August 2026. Scope 3 Emissions reporting requirements have been staggered to begin in 2027.

Governor Gavin Newsom’s EO N-79-20

EO N-79-20 (23 September 2020) mandates that 100% of new passenger vehicles sold in California be zero-emission by 2035, and that 100% of medium- and heavy-duty vehicles be zero-emission by 2045. In response, CARB adopted regulations aimed at increasing the number of zero-emission vehicles in California and tightening vehicle emissions standards. While many expect this aggressive push toward EVs will dramatically increase electricity demand, the exact timing and scale of this growth are highly uncertain due to an ongoing, legal battle with the federal government.

In June 2025, President Trump signed congressional resolutions revoking the federal EPA waivers allowing California to enforce these strict mandates. California and a coalition of states immediately sued to reverse the repeal. The conflict escalated further on 12 March 2026, when the US Department of Justice and Department of Transportation sued California to completely block the State’s zero-emission rules, arguing they illegally infringe on federal authority over fuel economy standards. With both sides locked in federal litigation, the enforcement of California’s 2026 interim goals is entirely up in the air.

California’s power industry presents several unique aspects, shaped largely by the state’s ambitious policies and geographical challenges.

Ambitious Decarbonisation Goals

California has set ambitious renewable energy and decarbonisation goals, including a legal mandate to reach carbon neutrality by 2045, and interim targets of 90% clean electricity by 2035 and 95% by 2040. These goals have contributed to the state’s significant year-on-year deployment of renewable energy resources, particularly utility-scale and distributed solar. In 2024, for the first time ever, California achieved 100% clean energy in the CAISO service area every three out of five days, as the CAISO system reached 100% renewable electricity for a period of the day on 219 different days. This rapid decarbonisation transition has also contributed to the state’s unique and complex challenges related to grid stability, resource adequacy, electric affordability and the integration of intermittent resources.

Wildfire Risks and Resilience Efforts

The escalating threat of catastrophic wildfires caused by utility infrastructure poses persistent challenges surrounding utilities’ legal obligations and operational costs. State policy and regulatory responses to these challenges include the creation of a state-administered Wildfire Fund, mandates for extensive grid hardening (eg, undergrounding, advanced monitoring technology, enhanced vegetation management), and the deployment of public safety power shutoffs (PSPS) during high-risk conditions. AB 1054 established the California Wildfire Fund, making way for socialising the costs of paying for catastrophic wildfire liabilities. Under the doctrine of inverse condemnation, California law uniquely holds IOUs strictly liable for damages from wildfires caused by utility infrastructure, regardless of negligence.

Senate Bill 254 Study Report

The SB 254 Study Report, prepared by the California Earthquake Authority, provides a comprehensive assessment of California’s growing exposure to catastrophic wildfires and other natural disasters, the financial systems used to manage those risks, and policy pathways to improve long‑term resiliency. While the report spans insurance, utilities, land use, and mitigation policy, a central through‑line is the rapidly increasing burden on electric utility ratepayers. The Report cautions that failing to act will come at a significant cost, and will materially worsen affordability, reliability, and clean‑energy outcomes.

SB 254 directed the State to evaluate how California mitigates catastrophe risk, finances recovery, and allocates associated costs across utilities, ratepayers, insurers, survivors, and the public. The Report adopts a deliberately holistic framework, recognising that wildfire risk and recovery outcomes are shaped by the interaction of utility infrastructure, insurance markets, land‑use decisions, and community preparedness. It highlights inverse condemnation, the utility regulatory compact, and AB 1054’s Wildfire Fund as stabilising but ultimately stopgap measures, noting that recent fires – especially the January 2025 Los Angeles wildfires – have exposed structural weaknesses that were not resolved by prior reforms.

The Report concludes that California is confronting a growing and interconnected natural catastrophe risk that cannot be effectively managed through incremental adjustments to existing systems. It underscores that different policy pathways operate on different time horizons and involve tradeoffs, and that no single approach is sufficient on its own. Instead, it calls for co-ordinated action across risk reduction, cost allocation, and catastrophe financing, combined with ongoing monitoring of outcomes, to improve affordability, accelerate recovery, and support California’s energy and climate objectives over time.

CAISO manages the wholesale electricity market for about 80% of the state's load, and operates the Western Energy Imbalance Market (WEIM), which is a voluntary real-time market that extends beyond California’s borders. The remaining roughly 20% of the state’s load is managed by other entities, including POUs and some federal power agencies that operate their own systems.

CAISO Wholesale Market Structure and Price Determination

The wholesale price of electricity in the CAISO market is primarily set by competitive bids from generators and demand-side resources. CAISO employs a security-constrained economic dispatch to determine which resources are used to meet demand.

CAISO Energy Markets and Capacity Mechanism

California has both energy markets and a capacity mechanism.

Energy markets

CAISO operates distinct day-ahead and real-time energy markets.

• The day-ahead market allows market participants to secure prices for energy delivery for the next operating day and hedge against real-time price volatility. Supply offers and demand bids are submitted, and CAISO determines schedules and hourly locational marginal prices (LMPs) for each participating location (node).
• The real-time market manages actual grid operations, adjusting for differences between day-ahead schedules and real-time conditions. The real-time market includes a 15-minute market and a five-minute dispatch to balance supply and demand continuously, while also producing LMPs.

CAISO capacity mechanism

California does not have a centralised capacity auction market like some other jurisdictions. Instead, the CPUC oversees a mandatory RA programme for the LSEs it regulates (IOUs, CCAs, ESPs). Previously, LSEs had to procure sufficient year-ahead and month-ahead capacity resources (system, local and flexible) to meet their forecasted peak demand, plus a reserve margin. These RA resources then had to offer their capacity into the CAISO energy markets. Beginning in 2025, the CPUC’s new SOD RA construct requires LSEs to demonstrate that they have sufficient capacity to meet demand in every hour of a 24-hour period, each month. The RA resources must still offer their capacity into the CAISO energy markets.

CAISO Nodal Pricing

The CAISO market utilises LMPs, which are calculated at thousands of specific locations (nodes) on the transmission system. An LMP at a given node reflects the marginal cost of supplying the next increment of electricity at that location, considering generation offer prices, transmission congestion and energy losses. This results in different prices across the grid, signalling local scarcity or surplus.

Non-CAISO Market Management

Entities within California’s electricity system that operate outside CAISO’s direct market management include the Western Area Power Administration (WAPA) and the Balancing Authority of Northern California (BANC).

WAPA markets and transmits wholesale hydroelectric power from federal water projects, primarily to rural electric co-operatives, municipal utilities and federal and state agencies in 15 western states, including California. BANC is a joint-powers agency that provides services similar to CAISO, but is limited to municipal utilities, irrigation districts and other public entities located in Northern California.

Addressing High-Load Consumers (eg, Data Centres)

High-load consumers like data centres typically procure electricity as customers of load-serving entities (LSEs) under regulated retail tariffs or bespoke service agreements, and their rapidly increasing demand continues to significantly influence LSE load forecasting and resource adequacy (RA) obligations. Since early 2025, California regulators and policymakers have intensified their focus on this segment.  These efforts are being advanced through several CPUC proceedings, including (i) PG&E’s Electric Rule 30 application addressing transmission-level interconnection for large loads; (ii) related proceedings on cost recovery and allocation for large-load interconnections; (iii) the CPUC’s 2026 rule-making on electric rate design for data centres and other transmission-connected customers; and (iv) the Resource Adequacy successor proceeding, which is incorporating large-load growth into reliability planning and procurement frameworks.

Enacted in 2025, SB 57 requires the CPUC to study the potential cost shifts to other customers associated with new data centre load. In parallel, California utilities and regulators have continued to refine interconnection and tariff frameworks: PG&E’s proposed Electric Rule 30 remains under CPUC consideration as of 2026 and is part of a broader effort to standardise and streamline the interconnection process for large new loads, including data centres, while also addressing system upgrade cost responsibility and study timelines.

More broadly, by 2026 the regulatory approach has evolved toward a more integrated framework that links rate design, interconnection policy, and reliability planning for high-load customers, reflecting growing concern about the scale and clustering of new data centre demand and its implications for grid capacity, procurement, and long-term infrastructure investment.

On the Federal side, activity at FERC has impacts for large loads in California. In Docket RM26-4-000 (Interconnection of Large Loads to the Interstate Transmission System), FERC is considering a Department of Energy-directed Advance Notice of Proposed Rule-making (ANOPR) focused on the timely and orderly interconnection of large electrical loads to the interstate transmission system, which it intends to act on by the end of June 2026. FERC noted that it is hard at work having reviewed more than 3,500 pages of comments filed in the docket, conducted meetings with stakeholders, and coordinated with government-wide partners. The Order recognises the unprecedented growth of large loads, including data centres and the urgent need for reforms to ensure timely, orderly, and non-discriminatory interconnection.

California permits imports and exports of electricity with neighbouring jurisdictions within the Western Interconnection, which encompasses 14 western US states, parts of Canada, and northern Baja California, Mexico. Import and export transactions are primarily managed by CAISO. In recent years, electricity imports have proven vital to maintaining California’s grid reliability and meeting its substantial energy demands, especially as the state seeks to integrate more renewable, intermittent power sources.

The operational reliability and co-ordination of the Western Interconnection is overseen by the Western Electricity Coordinating Council (WECC), which is a FERC-designated regional entity. WECC is responsible for developing and enforcing the mandatory reliability standards governing the planning and operation of the bulk power system, including the interties used to facilitate California’s imports and exports.

Major Transmission Interconnections

California trades electricity with the Pacific Northwest (PNW) (Oregon, Washington, British Columbia) via the Pacific DC Intertie and the AC California-Oregon Intertie (COI/Path 66). California trades electricity with the Desert Southwest (Arizona, Nevada) through numerous AC lines. Limited interconnections also exist with Baja California, Mexico.

Reviews and Approvals

Scheduling

Imports and exports are scheduled through CAISO market mechanisms and must adhere to CAISO’s relevant tariff provisions and operating procedures.

FERC jurisdiction

FERC regulates interstate transmission service and wholesale electricity sales, including import and export transactions. As noted above, FERC is expanding its reach as it relates to the interconnection of large loads.

Transmission rights

Entities scheduling imports and exports must possess or acquire necessary transmission service rights on the interconnections. Construction and operation of international transmission lines require permits from the US Department of Energy.

RA

To satisfy California’s RA requirements, imports must meet specific deliverability and availability requirements established by the CPUC and CAISO.

Typical Circumstances and Pricing

California typically imports electricity during peak demand periods – ie, evening ramp period when solar output declines, or summer heatwaves when out-of-state power is cheaper relative to in-state power. Exports typically occur when California has surplus generation, especially during midday when solar output is abundant.

Pricing for imports in the CAISO market is determined by competitive bids at the intertie scheduling points. The clearing price for imports contributes to the LMP, reflecting real-time supply, demand and transmission congestion at the relevant intertie. Exports are priced at the CAISO LMP at the relevant intertie. Exported energy may be delivered pursuant to bilateral arrangements or scheduled through regional markets such as the Western Imbalance Market and the Extended Day-Ahead Market (EDAM), in which prices and transfers are co-optimised across participating balancing authorities.

California’s electricity supply includes in-state generation and out-of-state imports.

The CEC’s most recent comprehensive report shows that, in 2024, California’s total system electric generation (all utility-scale, in-state generation plus net electricity imports) was 278,338 GWh.

The supply mix of that generation was comprised of the following.

• Natural gas: approximately 40%.
• Renewable energy sources (excluding large hydroelectric) – approximately 39%, broken down as follows:
1. solar (utility-scale and rooftop) – approximately 23%;
2. wind – approximately 7%; and
3. geothermal, biomass and small hydroelectric – approximately 9%.
• Large hydroelectric power: about 11%.
• Nuclear power: approximately 9% (note that the majority of this supply was associated with California’s single operating nuclear plant, Diablo Canyon Nuclear Power Plant (see 3.5 Decommissioning a Generation Facility)).
• Coal: 1.12%.
• Oil: 0.02%.

While there are no explicit percentage-based market share concentration limits in California, certain mechanisms are in place to address market concentration and prevent a single entity from exerting undue control over California’s electricity supply.

Principal Laws Governing Market Concentration

FPA

This law is implemented by FERC, an independent federal agency whose mandate is to ensure that wholesale electricity rates are “just and reasonable” and not unduly discriminatory or preferential. This mandate includes preventing the exercise of undue market power.

CAISO’s “Market Power Mitigation Procedures”

These procedures are found under CAISO’s Tariff Section 39, which is approved by and subject to the oversight of FERC under the FPA. The Tariff is intended to address potential market power abuse through certain mitigation measures administered by CAISO’s Department of Market Monitoring (DMM). These measures aim to correct for conduct that could disturb competitive outcomes while minimising interference with market-driven price signals.

Although the oversight of market concentration in California’s wholesale electricity market generally falls under FERC’s jurisdiction, the CPUC also plays a role in mitigating market concentration by regulating the IOUs’ procurement practices and retail rates.

Enforcement and Consequences

FERC’s market-based rate authority

Entities wishing to sell electricity at prices determined by the market (rather than traditional cost-of-service rates) must apply to FERC for “market-based rate authority”. To obtain and maintain this authority, the entity must demonstrate that it (and its affiliates) do not possess or have adequately mitigated horizontal market power (control over generation in a specific market) or vertical market power (control over essential inputs such as transmission).

If FERC finds that an entity abused its market power, or no longer meets the criteria for its market-based rate authority, it can revoke this designation, forcing the entity to sell at cost-based rates. FERC can also order the disgorgement of unjust profits, impose civil penalties or mandate other remedies.

CAISO monitoring

CAISO’s DMM is responsible for continuously monitoring the electricity market to identify conduct that could indicate an abuse of market power, such as bidding strategies that artificially inflate prices or physical withholding of generation capacity. CAISO’s Market Power Mitigation Procedures provide for automated mechanisms that can cap bids from suppliers identified as potentially exercising market power under certain conditions. The DMM can report suspected market power concerns to CAISO and FERC. For example, recent discussions regarding the implementation of CAISO’s EDAM have identified potential incentive and scheduling issues, which are being addressed through ongoing tariff development and market design refinements.

The CAISO DMM’s primary role is to conduct continuous surveillance of the wholesale electricity market and to scrutinise the market for signs of market design flaws, inefficiencies, anti-competitive behaviour or manipulation. The DMM reports its findings to CAISO and FERC, and may trigger certain automated market power-mitigation measures established under Tariff Section 39, but it does not have independent enforcement authority. Rather, under the FPA, FERC has broad authority to investigate and penalise anti-competitive behaviour and market manipulation in wholesale electricity markets. FERC’s powers include:

• conducting formal investigations;
• performing audits;
• ordering specific actions; and
• imposing civil penalties.

FERC actively exercises these powers in practice. For example, in April 2026, it approved a settlement with a market participant relating to alleged manipulation of the CAISO market, resulting in civil penalties and disgorgement of profits. More broadly, FERC’s annual enforcement reports identify fraud, market manipulation, and anti-competitive conduct as core priorities, with numerous investigations and settlements arising from market monitor referrals and other surveillance mechanisms.

The CPUC’s Affiliate Transaction Rules, which apply to the IOUs, also serve to limit anti-competitive behaviour resulting from the IOUs’ monopoly status. These rules are intended to prevent ratepayer subsidies of non-regulated utility enterprises, foster a fair competitive environment, and enhance energy market competition.

Construction of Generation Facilities

In California, CPUC GO 131-E governs the planning and construction of electric generation resources, transmission, power, distribution or distribution lines, and electric substations. There are three overarching review processes for CPUC authorisation of electrical generation resources and infrastructure projects.

The first is obtaining a Certificate of Public Convenience and Necessity (CPCN) from the CPUC, which is required for:

• any new electric generating plant having in aggregate a net capacity available at the busbar in excess of 50 megawatts (MW);
• the modification, alteration or addition to an existing electric generating plant that results in a 50 MW or more net increase in the electric generating capacity available at the busbar of the existing plant; or
• major electric transmission line facilities that are designed for immediate or eventual operation at 200 kV or more.

Before granting a CPCN, the CPUC must find that present or future public convenience and necessity will require its construction. The CPUC considers:

• project need;
• the maximum prudent and reasonable cost of the project;
• community values;
• electric and magnetic field (EMF) issues;
• environmental impacts;
• feasible mitigation measures; and
• project alternatives under CEQA.

The next review process is the Permit to Construct, which is necessary before construction begins. This review is narrow compared to the CPCN process, only considering project need, EMF exposure, environmental impacts, mitigation measures and project alternatives under CEQA.

The third process is for electric distribution lines and other substations. While these projects do not require a CPCN or Permit to Construct, the utility must request input from local authorities on land use matters and obtain any necessary non-discretionary local permits required for construction and operation of these projects.

Lastly, the project must comply with CEQA, which generally requires California public agencies – both state and local – to inform decision-makers and the public about a proposed project’s potential environmental impacts and to minimise any impacts to the extent feasible. California has enacted broader CEQA reforms (AB 130 and SB 131) that introduced new exemptions and streamlining measures across multiple sectors; however, these legislative changes did not specifically target transmission siting and primarily affect CEQA implementation more generally.

Operation of Generation Facilities

The CPUC’s GO 167-B establishes maintenance and operational standards for electric generating facilities to ensure safe and reliable service to customers. The GO includes:

• generator maintenance, generator operator and generator logbook standards;
• a programme for audits, inspections and incident investigations;
• reports of safety incidents, compliance filings and responding to CPUC staff enquiries; and
• enforcement of standards.

See 3.1 Constructing and Operating Generation Facilities.

California has extensive approval processes for siting, construction and operation of generation facilities. Such approvals involve various agencies, such as the CPUC and CEC.

Siting

Determining which agency has jurisdiction depends on the type of generation facility. Thermal power plants of 50 MW or more fall under the exclusive authority of the CEC; the CEC’s Application for Certification (AFC) includes an environmental assessment that is the functional equivalent to an environmental impact report under CEQA. Other facilities, such as wind and solar, require co-ordination with counties and cities.

Land Use

Construction of generation facilities requires a full review under CEQA. After an environmental review, the project may require mitigation measures for significant environmental impacts. The special conditions that may be imposed on a generation facility include protections for biological resources, cultural resources, visual/aesthetic impacts, and air and water quality.

The CEQA process requires the opportunity for public participation, which typically involves public hearings and comment periods, Tribal consultation, and intervenor participation in CEC proceedings.

California enacted major CEQA reforms in June 2025 through Assembly Bill 130 (AB 130) and Senate Bill 131 (SB 131), which significantly expand exemptions and streamlined environmental review, particularly for housing, infrastructure, and public-serving projects.

Interconnection and Transmission

In California, the process requires preliminary agreements with CAISO or a local utility. With these agreements, there may be a need for grid upgrade or congestion conditions.

Other Potential Terms and Conditions

The CEC may also impose certain conditions on construction and operational approvals.

Amendment or Relaxation of a Term or Condition

The process for seeking an amendment or relaxation of terms or conditions of approval depends on the approving entity and type of facility.

For CEC approvals, the proponent of the amendment must submit a petition for amendment and include the following:

• a clear description of the requested change;
• specific condition(s) to be modified;
• reasons/justifications for the change;
• analysis of potential environmental or public impacts; and
• supporting studies or documents.

The CEC will provide a decision, ranking the amendment as significant or insignificant. A significant outcome will require a vote by the full CEC, while an insignificant outcome only requires staff approval of the amendment.

Local governments or agencies will have their own processes, but these typically include filing an application for permit modification that undergoes staff review.

Under California Public Utilities Code Sections 610–626, an IOU may condemn any property necessary for construction and maintenance of its plant, system or facilities.

Section 625 provides that an IOU may not condemn any property for the purpose of competing with another entity, unless the CPUC finds that such an action would serve the public interest, pursuant to a petition or complaint filed by the IOU (personal notice of which has been served on the owners of the property to be condemned) and an adjudication hearing (including an opportunity for the public to participate).

If the CPUC finds that the proposed condemnation would serve the public interest, the IOU may then file an eminent domain action in the California Superior Court. If the IOU prevails, the court will generally require the IOU to pay the property owner the fair market value of the condemned property.

There are approximately 25 decommissioned generation facilities in California. These former facilities produced energy using natural gas, biomass, nuclear, solar thermal, coal and diesel fuel.

Nuclear Power Plant Decommissioning

In general, nuclear facility decommissioning costs are collected through customer rates over the facility’s operating life.

Nuclear Regulatory Commission (NRC) regulations require that, once a nuclear power plant ceases operations, it must be decommissioned. Decommissioning removes a facility or site from service and reduces residual radioactivity to safe levels for use.

To prepare for decommissioning, all nuclear power plant owners are required to establish a trust that is funded by rates collected for the energy produced over the plant’s operational life. This is intended to ensure that financing is available for eventual decommissioning.

The Diablo Canyon Nuclear Power Plant, a PG&E-owned two-unit 2,240 MW nuclear facility (located in San Luis Obispo, California) is a unique example. It was set to be decommissioned when its NRC licence expired in 2024 for Unit 1 and 2025 for Unit 2. However, pursuant to SB 846 (2022), the Commission invalidated its previous retirement order for Diablo Canyon and conditionally approved extended operations at the plant until 31 October 2029 for Unit 1 and 31 October 2030 for Unit 2. SB 846 orders the CPUC to continue authorising PG&E to recover in rates all of the reasonable costs incurred to prepare for the retirement of these units. On 2 April 2026, the NRC approved PG&E’s 20-year licence renewal application for extension of operations. However, any extension beyond 2030 would require additional legislation from the California legislature.

Non-Nuclear Decommissioning

For non-nuclear generation facilities, costs for decommissioning may vary. Before a CPUC-regulated utility collects decommissioning costs from ratepayers, the CPUC must first make a finding that recovery of those costs is just and reasonable. The CPUC may authorise a utility to record decommissioning costs in a Memorandum Account, subject to future review for just and reasonableness.

In California, the ownership, construction and operation of transmission lines and associated facilities are subject to the requirements set forth in the CPUC’s GO 131-E. This GO also governs transmission-level BESS projects. Any qualified entity may propose to construct and operate transmission lines if the CAISO approves the proposal via the CAISO TPP, or if the entity obtains a CPCN from the CPUC.

The CPUC’s Electric Rule 21 encompasses interconnection, operating and metering requirements for generation facilities that connect to an IOU’s distribution system and CPUC-jurisdictional transmission system. Rule 21 does not govern CAISO-controlled transmission interconnections.

FERC issues permits for construction or modification of electric transmission lines, but only for those that are located in National Interest Electric Transmission Corridors (“National Corridors”). FERC will notify stakeholders if a project requires an environmental assessment or an environmental impact statement pursuant to the National Environmental Policy Act (NEPA).

Certificate of Public Necessity and Convenience (CPCN)

In California, an IOU must obtain a CPCN from the CPUC for the construction and operation of any electric power line facilities, substations or switchyards designed for immediate or eventual operation at voltages between 50 kV and 200 kV, or 200 kV or more. GO 131-E provides exemptions for the following:

• replacement of existing transmission lines or supporting structures;
• minor relocation of existing transmission line facilities;
• conversion of existing overhead lines to underground; and
• placing new or additional conductors, insulators or accessories to existing structures.

Permit to Construct

Pursuant to GO 131-E, a Permit to Construct is required for the extension, expansion, upgrade or modification of existing electrical transmission facilities, except where an exemption applies from Section III(B)(2) or if a utility files a CPCN application.

Regulatory Process

Once an entity files a CPCN or Permit to Construct application, the CPUC assigns an administrative law judge, and a two-track parallel proceeding begins. The first track is the environmental review, pursuant to CEQA. The second track is the review of the project’s need and cost, pursuant to the California Public Utilities Code Section 1001 and GO 131-E.

The CEQA phase allows for public participation through public meetings and written comment periods. For the determination-of-need phase, an administrative law judge oversees the process, and parties are permitted to provide input in the proceeding, including through written testimony and evidentiary hearings. At the end of the process, the CPUC approves or denies the application, based on the contents of the final environmental impact report and the record developed during the determination of the need phase of the proceeding.

In California, the common terms and conditions in CPUC approvals to construct and operate transmission lines and associated facilities include:

• routing and siting conditions;
• construction restrictions;
• CEQA compliance and Tribal consultation, when triggered;
• operational restrictions;
• co-ordination with other agencies;
• public and stakeholder engagement; and
• technical and safety standards.

On the federal level, the common terms and conditions include:

• compliance with NEPA, the Clean Water Act, and the Endangered Species Act (ESA);
• right-of-way (ROW) on federal lands;
• FERC backstop authority in designated corridors;
• additional terms imposed under Section 1222 of the Energy Policy Act of 2005;
• Tribal consultation; and
• security, safety and interconnection standards.

To obtain an amendment or relaxation of a term or condition on approval, the proponent must file a Petition for Modification (PFM) application with the CPUC. Once the application is filed, the CPUC staff will review the application and allow for public notice and a public comment period. Subsequently, the assigned administrative law judge will issue a proposed decision with a recommendation for approval or denial. At the end of the application process, the CPUC commissioners vote to adopt, modify or reject the proposed decision.

The federal process requires the proponent to file a formal request or amendment with the lead agency. If approved, the agency may do so as a permit amendment, supplemental record of decision, or modified ROW grant.

Private developers do not have automatic eminent domain rights in California. Instead, developers must partner with a utility that has the eminent domain rights, or must obtain public utility status from the CPUC. California Public Utilities Code Section 610 and California Constitution Article I, Section 19 grant eminent domain authority to public utilities. However, the utilities must first obtain a CPCN from the CPUC in order to initiate condemnation proceedings under California Code of Civil Procedure Sections 1230 et seq.

To obtain the rights to the surface of the land, proponents may enter voluntary agreements or assert eminent domain authority. Voluntary agreements include easements, fee simple purchases, and right-of-entry or temporary construction licences. The eminent domain action must be filed in the California Superior Court, where the landowners may challenge the necessity of the taking and the compensation offered. The final compensation is determined by the court or a jury, based on appraisals.

For projects that cross federal public lands, surface access and use is obtained through ROW grants, which are issued by the Bureau of Land Management or the US Forest Service.

For access to and use of Tribal land, consultation and voluntary agreements are required. Eminent domain cannot be used on Tribal trust lands (without federal approval) or conservation easements.

Both the California and US Constitution require just compensation for landowners when eminent domain is exercised. Such compensation may include:

• fair market value;
• severance damages if the value of the land diminishes due to the transmission line;
• temporary construction damage or licence fees; and
• reimbursement of legal or appraisal fees – these may be negotiated, but are not required.

Transmission service is not an exclusive geographic monopoly in California, although traditional utility companies still own most transmission infrastructure. Unlike local distribution systems (the lower‑voltage lines that deliver electricity directly to homes and businesses), high‑voltage transmission operates under a competitive, open‑access framework.

While major IOUs (such as PG&E and SCE) own a substantial portion of transmission facilities, the system itself is operated and managed by CAISO, an independent, federally regulated entity.

California also does not grant incumbent utilities a “right of first refusal” for new transmission development. As a result, when CAISO identifies the need for major new regional transmission projects, those projects may be opened to competitive solicitation, allowing independent developers to compete with incumbent utilities to build, own, and operate the facilities.

In contrast, POUs generally retain exclusive control over the planning, ownership, and operation of transmission facilities within their service territories.

California’s transmission service charges and terms of service are established and overseen by FERC and CAISO.

FERC’s oversight focuses on rates, terms and conditions of transmission service.

CAISO requires transmission owners to file open-access transmission tariffs. These tariffs govern transmission service terms, eligibility and interconnection, scheduling and congestion management, and charges for using the transmission system.

The FPA requires all public utilities that own, control or operate transmission lines to provide open-access and non-discriminatory access to their system. In California, this federal open-access requirement is principally administered and enforced by CAISO for facilities under its operational control.

Under CAISO’s FERC-approved tariff, all market participants have equal rights to submit energy schedules and access the grid. This framework decouples transmission ownership from grid operations, preventing incumbent utilities from utilising their physical infrastructure to grant competitive advantages to their own generation affiliates. Instead, transmission capacity is allocated and congestion is managed through automated, market-based mechanisms rather than bilateral discrimination.

The construction and operation of electric distribution facilities in California are governed by a combination of the California Public Utilities Code, CPUC GOs, and municipal utility ordinances.

For IOUs, the principal legal frameworks include the following.

• Statutory Authority and Safety Standards: The CPUC exercises broad regulatory authority under the California Public Utilities Code (including Sections 451, 701, and 768) to ensure the safety and reliability of electric systems. This authority is implemented through binding GOs including GO 95 (overhead line design and construction), GO 128 (underground facility standards), GO 131-D (planning and construction of transmission/power/distribution line facilities and substations) and GO 165 (inspection and maintenance requirements for electric distribution systems).
• Wildfire Mitigation and Grid Hardening: Public Utilities Code Sections 8386 et seq. require IOUs to prepare and submit annual Wildfire Mitigation Plans (WMPs) to the Office of Energy Infrastructure Safety (OEIS) for review and approval. These requirements include detailed obligations relating to vegetation management, public safety power shutoffs (PSPS), and system hardening to reduce wildfire risk.
• Distribution-Level Interconnection: The interconnection of distributed energy resources (DERs) – including behind-the-meter solar, energy storage, and microgrids – to IOU distribution systems is governed by CPUC Electric Rule 21. This tariff establishes the technical, engineering, and cost-allocation framework for non-FERC jurisdictional interconnections.
• Storage and Microgrid Mandates: State legislation and CPUC rule-making have played a central role in advancing the deployment and regulation of energy storage and microgrids at the distribution level:

1. Assembly Bill 2514 (Public Utilities Code Sections 2835 et seq.) established energy storage procurement targets for IOUs, catalysing significant deployment of both grid‑connected and distributed battery storage resources.
2. Senate Bill 1339 (Public Utilities Code Section 8370) directed the CPUC to develop regulatory frameworks, tariffs, and interconnection standards to facilitate microgrid commercialisation and deployment, with an emphasis on improving system resilience, particularly during outages and wildfire events.

In parallel, California has significantly expanded safety oversight of battery energy storage systems, particularly following high-profile thermal incidents at large‑scale facilities. This evolving framework includes the following.

• General Order 167‑C: This extends comprehensive operation and maintenance standards to battery energy storage systems, including requirements for auditable maintenance programmes, logbooks, and mandatory incident reporting.
• Senate Bill 38: This requires facility operators to co-ordinate with local emergency response agencies and develop site‑specific emergency response and emergency action plans prior to operation.
• Local Permitting Requirements: While utility-owned infrastructure is generally subject to CPUC permitting authority, independently developed storage facilities and microgrids are typically subject to local land‑use regulation, including zoning approvals, environmental review under CEQA, and permit requirements imposed by the applicable local authority having jurisdiction.

The construction and operation of electric distribution facilities in California typically require approval from local and state agencies, though federal agencies can sometimes be involved. For IOUs, regulatory oversight and approval is provided by the CPUC. For POUs, primary approval authority is typically maintained by local governing boards, though state environmental laws still apply.

The California Public Utilities Code requires the IOUs to apply to the CPUC for a CPCN before constructing new distribution infrastructure. In a formal CPUC proceeding addressing a CPCN application, the public is permitted to participate and provide input as an “intervenor”.

Construction of most new distribution facilities, including distribution lines, substations, large-scale storage and microgrids, also requires review under CEQA to assess and mitigate potential environmental impacts. This process is overseen by the CPUC for IOU projects, and by local agencies for POU or private development projects.

The typical timelines to obtain all necessary approvals vary depending on the nature of the project.

In California, the terms and conditions included in approvals for the construction and operation of electric distribution facilities will depend on the type of project. However, typical terms and conditions generally fall under the following categories:

• environmental – a CEQA review and potential mitigation requirements;
• safety: the CPUC’s GO-95, GO-128 and local codes;
• interconnection and integration – pursuant to CPUC Electric Rule 21;
• operational – may involve curtailment provisions, export limits, required “islanding” equipment for microgrids, and storage charging/discharging constraints;
• reporting and monitoring – the CPUC’s GO 131-E reporting requirements for planned transmission, power line, and substation facilities;
• financial – financial guarantees, insurance requirements, decommissioning plans and cost responsibilities; and
• local permitting.

The ability to obtain an amendment or relaxation of a term or condition of approval depends on the approving entity (see 4.3 Terms and Conditions Imposed on Approvals to Construct and Operate a Transmission Line and Associated Facilities).

In California, a proponent for the construction and operation of electric distribution facilities may exercise eminent domain powers to obtain surface rights for a project. However, these powers are not automatic.

Pursuant to California Public Utilities Code Section 610, IOUs must seek CPUC approval to exercise the power of eminent domain to acquire property necessary to carry out their functions. The IOU must demonstrate that the taking of the property is:

• for a public use;
• necessary; and
• in compliance with relevant CPUC approvals.

Further, the IOUs must comply with California eminent domain law, pursuant to the Code of Civil Procedure Sections 1230.010 et seq, which requires:

• providing adequate notice;
• making a good faith offer of compensation; and
• following court proceedings if the property owners do not agree to sell.

POUs generally have eminent domain authority under their own charters or statutes.

Private developers or joint power authorities must either act under contract with a utility or agency that has eminent domain authority, or must receive special authorisation through legislation, which is rare.

In California, electric distribution entities generally operate as regulated monopolies with exclusive rights within defined service territories. The legal framework differs for IOUs and POUs, but in both cases the delivery of electricity over local distribution infrastructure is typically performed by a single utility provider within a given area.

For IOUs, exclusive service rights are established through a combination of CPUC authorisation and local franchise rights.

A CPCN effectively defines the utility’s authorised service area. An electrical corporation must obtain a CPCN from the CPUC before beginning the construction of a new distribution line, plant or system, or any extension thereof. Although the CPUC regulates the utility’s operations and service obligations, the right to place poles, wires, and other distribution facilities in public streets and rights of way generally depends on local franchise authority.

For POUs, service territory rights generally arise from local governmental authority rather than CPUC certification. While the CPUC does not regulate POU rates, it does have safety jurisdiction over certain POU operations.

Notably, though the distribution of electricity remains a largely monopolistic function, California has introduced competition in other segments of the electricity market, such as generation and retail electricity supply (through mechanisms including community choice aggregation and limited direct access).

In California, the CPUC is responsible for overseeing and establishing the IOUs’ electricity distribution charges and terms of service. POUs establish their charges and terms through their respective governing bodies.

Regulatory Principles and Process

Under California Public Utilities Code Section 451, the CPUC must ensure that all utility charges and rules pertaining to utility service are “just and reasonable”. This includes ensuring adequate, efficient and safe service. Section 453 requires that a public utility’s rates and terms of service must also be non-discriminatory, meaning customers receive service under similar terms and conditions without undue preference or prejudice.

The CPUC establishes distribution system charges under a cost-of-service model. Under this model, the following applies.

• The CPUC determines the utility’s revenue requirement, which is the total amount of money that the utility is authorised to collect from customers to cover its operational costs (eg, maintenance, administration) and provide an opportunity to earn a reasonable rate of return on its capital investments (rate base – the value of infrastructure such as poles, wires, etc).
• This revenue requirement is typically examined and set every few years in a formal proceeding called a General Rate Case (GRC). The GRC involves public hearings, input from stakeholders (including consumer advocates), and review of the utility’s expenses and investment plans.
• Once the revenue requirement is approved (Phase I of a GRC for large IOUs), the costs are allocated among different customer classes (residential, commercial, industrial, agricultural), and specific rates are designed to collect the allocated revenue from each class (Phase II of a GRC). Rates often include fixed charges, volumetric charges (per kWh), and, for some customers, demand charges (per kW).

Distribution terms of service are typically reviewed, established or modified within formal CPUC proceedings; this can occur concurrently with rate-setting in GRCs or separately in specific rule-makings dedicated to particular aspects of service (such as net energy metering or interconnection).

Appeals and Complaints

IOUs and other parties to the proceeding in which a CPUC decision was adopted have a right to appeal the CPUC decision. Parties must first file an “application for rehearing” with the CPUC itself, outlining the alleged legal error. If the rehearing application is denied, or if it is granted but the decision remains unsatisfactory, the applicant may then file a petition for a writ of review with the California Court of Appeal or the California Supreme Court. This judicial review is typically limited to whether the CPUC violated applicable law or acted within its authority, and whether the CPUC’s findings are supported by substantial evidence.

Customers and other parties can also challenge existing rates, service quality, or alleged violations of rules or tariffs through the CPUC’s complaint process. The CPUC provides both an informal complaint process (via its Consumer Affairs Branch, which attempts mediation) and a formal complaint process. The CPUC can order remedies such as bill adjustments or corrective actions, but generally cannot award damages for personal injury or property damage.