California electric utility regulations are split across five bodies. The California Public Utilities Commission (CPUC) sets rates, approves integrated resource plans, oversees safety, and regulates the three large investor-owned utilities (Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric) plus smaller IOUs. The California Energy Commission (CEC) writes state energy policy, publishes the Integrated Energy Policy Report, and administers appliance and building efficiency standards. The California Independent System Operator (CAISO) runs the wholesale electricity market and the transmission grid for roughly 80 percent of the state. The California Air Resources Board (CARB) administers the cap-and-trade program that electric utilities participate in. The North American Electric Reliability Corporation (NERC) sets bulk power reliability standards including the Critical Infrastructure Protection rules. The statutory framework runs through the Public Utilities Code, Senate Bill 100 (100 percent zero-carbon electricity by 2045), Senate Bill 350 (renewable portfolio and efficiency doubling), Assembly Bill 32 (cap-and-trade authority), Assembly Bill 1054 (wildfire fund and safety), and CPUC Rule 21 (distributed energy resource interconnection).
California is the most heavily regulated electric market in the country. The CPUC has authority over rates, integrated resource plans, safety, and procurement for the large IOUs. The CEC drives state energy policy. CAISO runs the grid and wholesale market. CARB administers cap-and-trade. Layer on community choice aggregation, the NEM 3.0 transition, default time-of-use residential rates, and wildfire mitigation plans, and California compliance runs across five agencies at the same time.
This guide walks through the five regulators, the statutes driving compliance, and what a billing platform must do. Utilities running a California electric operation should look at SMART360 electric utility management software, which is purpose-built for utilities serving 3,000 to 100,000 connections.
Five bodies shape what a California electric utility can charge, how it must plan, and what it has to report. Most operational decisions land at the CPUC.
Is your utility under CPUC jurisdiction?
If you are an investor-owned electric utility serving retail customers in California, the answer is yes for rates, integrated resource planning, safety, and most operational rules. PG&E, SCE, and SDG&E are the three large IOUs; PacifiCorp California and Liberty Utilities Bear Valley are smaller IOUs also under CPUC. Community choice aggregators such as Marin Clean Energy, Silicon Valley Clean Energy, Peninsula Clean Energy, Clean Power Alliance, Central Coast Community Energy, and Sonoma Clean Power are CPUC-registered but retain local governance over rates. Publicly owned utilities like the Los Angeles Department of Water and Power, Sacramento Municipal Utility District, Silicon Valley Power, Roseville Electric, Anaheim Public Utilities, and the city utilities in Palo Alto, Alameda, and Lodi are exempt from CPUC rate jurisdiction. They set rates through their own boards and councils, and their integrated resource plans go to the CEC rather than the CPUC.
California electric compliance is anchored in a handful of statutes and CPUC rules. Compliance officers, rate analysts, and integrated resource planning teams should be able to locate each one without searching.
The full Public Utilities Code is published through the California Legislative Information site. CPUC decisions and dockets are searchable through the CPUC Docket Card system.
California is the largest community choice aggregation market in the country. About two dozen CCAs serve roughly 11 million customer accounts, procuring electricity for their communities while the incumbent IOU continues to deliver over the wires and handle billing under an exit fee structure.
The CCA layer changes the billing architecture. The CCA sets the generation rate; the IOU sets the delivery rate and the Power Charge Indifference Adjustment; the customer bill combines both. Billing platforms that handle CCA generation charges as a first-class rate class produce clean CCA bills. Platforms that treat CCA as a bolt-on force the utility to reconcile across systems every cycle.
The CPUC does not run the transmission grid or the wholesale market. Reliability of the high-voltage transmission network, wholesale market participation, and cybersecurity for bulk power are federal matters governed by CAISO tariffs and NERC standards.
CAISO operates the balancing authority area that covers roughly 80 percent of California plus parts of Nevada. Utilities inside the CAISO footprint participate in the day-ahead and real-time markets, the Reliability Coordinator functions, and the resource adequacy market. CAISO tariffs are approved by FERC and govern how generators, load-serving entities, and transmission owners interact.
NERC Reliability Standards apply to California transmission operators and generation owners connected to the Bulk Electric System. The CIP standards cover cybersecurity for the BES with annual self-certification and audits. Distribution-only utilities below the BES threshold are not directly subject to NERC CIP, but most California compliance officers track CIP because CPUC and cyber insurance expectations are converging on the framework.
For utilities operating across the federal-state boundary, a regulatory compliance software platform for utilities centralizes evidence, automates report generation, and keeps the audit trail intact across CPUC, CEC, CAISO, CARB, and NERC requirements.
California completed its first AMI rollout more than a decade ago and is now the only state where the three largest IOUs have moved residential customers to a default time-of-use rate. That single change reshaped how billing works.
The default TOU rate applies interval consumption data to peak, mid-peak, and off-peak windows on every residential bill. Interval meter data has to land in the MDM layer, be validated, and flow into the rating engine on the cycle it happens. A rate change (season transition, holiday schedule, adjusted peak hours) has to propagate to every account without a manual reset.
The NEM 3.0 transition (Net Billing Tariff, adopted in 2022) added another layer. NEM 3.0 replaces retail-rate credit for exported solar generation with an avoided-cost export compensation schedule that varies by hour of the day. NEM 3.0 customers need a bill that shows imports, exports, and hourly export compensation applied to export volume. Older NEM 1.0 and NEM 2.0 customers stay on retail-rate credit under grandfathering rules. Billing platforms must handle three NEM regimes at the same time.
Is your rate engine ready for TOU default and NEM 3.0?
For billing and customer information teams, TOU default and NEM 3.0 are the most demanding rate-design changes California IOUs have shipped in a generation. Interval AMI data drives every rate calculation. Export compensation calculations have to reflect the CPUC-approved hourly avoided-cost schedule for the year the customer interconnected. Community choice aggregation charges layer on top, along with wildfire cost-recovery riders and the Power Charge Indifference Adjustment. See our guide on how AMI smart meters connect to billing for the technical architecture that makes this work.
A California general rate case for one of the large IOUs typically runs 12 to 18 months from filing to final decision. Here is the path.
The reporting burden under general rate cases plus the parallel Cost of Capital proceeding, the Wildfire Mitigation Plan review, the Integrated Resource Plan cycle, and the NEM 3.0 hourly export data raises operational complexity. Utilities that built their billing and customer information systems around annual cost-of-service reporting often find California reporting harder than the rate case itself.
Default TOU rate design, NEM 3.0 export compensation, CCA generation charges, wildfire cost-recovery riders, and CPUC consumer protection rules raise the bar on what a billing and customer information platform must do. The criteria that matter most for California utilities:
For a side-by-side look at the vendors serving electric utilities, see our comparison of the best electric utility billing software for 2026.
SMART360 by Bynry is built on this architecture. It connects billing, customer information, meter data management, and work orders so TOU default, NEM 3.0 export calculations, and CCA generation charges flow from the same data utilities already use. Island Water Authority deployed SMART360 in 10 weeks and achieved a 47 percent operational cost reduction, a 92 percent reduction in billing errors, and a 22 percent improvement in customer satisfaction. Every utility that has gone live is still on it.
TOU default, NEM 3.0, wildfire mitigation, and CCA growth are easier to manage with peer benchmarks. California IOUs, CCAs, and publicly owned utilities typically send teams to CMUA (California Municipal Utilities Association) events, Cal-CCA meetings, the Western Energy Institute Operations Conference, and the national EEI Annual Convention. The most useful sessions cover rate design, wildfire compliance, and AMI-to-billing integration lessons. For the 2026 schedule, see our list of electric utility conferences for 2026.
The California Public Utilities Commission (CPUC) regulates investor-owned electric utilities for rates, integrated resource planning, safety, procurement, and consumer protection. The California Energy Commission (CEC) writes state energy policy, publishes the Integrated Energy Policy Report, and reviews publicly owned utility integrated resource plans. The California Independent System Operator (CAISO) runs the wholesale electricity market and transmission grid for roughly 80 percent of the state. The California Air Resources Board (CARB) administers cap-and-trade. NERC sets Bulk Electric System reliability standards including CIP cybersecurity. Publicly owned utilities like LADWP and SMUD are exempt from CPUC rate jurisdiction.
The CPUC regulates rates, integrated resource plans, and safety for investor-owned utilities. The CEC writes state energy policy, publishes the Integrated Energy Policy Report every two years, administers appliance and building efficiency standards, certifies renewable generation for the state renewable portfolio standard, and reviews the integrated resource plans of publicly owned utilities. Investor-owned utilities file their IRPs with the CPUC. Publicly owned utilities file their IRPs with the CEC. Both agencies contribute to statewide planning under SB 100 and SB 350.
Senate Bill 100, adopted in 2018, sets a 100 percent zero-carbon electricity mandate for California by 2045, with a 60 percent renewable portfolio standard by 2030 as an interim target. The CPUC integrates SB 100 into IOU procurement and resource planning through IRP cycles. The CEC integrates SB 100 into publicly owned utility IRP review. SB 100 drives generation retirement, renewable procurement, offshore wind, long-duration storage, and transmission planning for the next two decades.
NEM 3.0, adopted by the CPUC in December 2022 and effective April 2023 for new residential interconnections at PG&E, SCE, and SDG&E, replaced the retail-rate export credit under NEM 2.0 with an avoided-cost export compensation schedule that varies by hour of the day. New rooftop solar customers on NEM 3.0 receive export compensation set by the CPUC-approved avoided-cost calculator, not retail rates. Existing NEM 1.0 and NEM 2.0 customers stay on retail-rate credit under grandfathering rules. Billing platforms must handle all three regimes concurrently.
No, not for rates and service quality. POUs like LADWP, SMUD, Silicon Valley Power, Roseville Electric, and Anaheim Public Utilities set rates through their own boards and are exempt from CPUC rate jurisdiction. They are still subject to CEC IRP review under SB 350, CARB cap-and-trade obligations, NERC reliability standards for bulk-power facilities, and CAISO tariffs if they participate in the market. SB 100's 100 percent zero-carbon mandate applies to POUs and IOUs alike.
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