AB 2383 directs the California Public Utilities Commission (CPUC) to create a distinct retail classification and rate schedule for “large energy use facilities” and to require electrical corporations to enter contracts with those facilities covering transmission, generation, or distribution as applicable. The measure aims to align cost responsibility, protect other customers from cost shifts, and give utilities and large customers clearer commercial terms.
The bill matters because it changes who pays for interconnection and grid costs, locks in long-term payment commitments for very large users, and requires the CPUC to evaluate rates against wildfire, climate, and clean‑energy obligations. That combination could alter procurement choices, capital planning, and siting decisions for big industrial, data center, and other high-load facilities.
At a Glance
What It Does
The bill requires the CPUC to establish a separate classification and rate schedule for “large energy use facilities” and to mandate contracts between those facilities and electrical corporations that specify duration, minimum payments, and reporting of onsite generation plans.
Who It Affects
Facilities with very large peak demand (industrial campuses, large data centers, manufacturing complexes) that take service under a retail transmission tariff, plus the electrical corporations that serve them, investor‑owned utilities' ratepayers, CCAs, and regulators responsible for procurement and reliability.
Why It Matters
It shifts decision-making and cost-allocation toward explicit contractual arrangements and customer-level responsibility for interconnection upgrades, while requiring rates and contracts to account for wildfire liability, climate mandates, and the state’s clean-energy targets—potentially changing investment incentives.
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What This Bill Actually Does
The bill defines a “large energy use facility” as a single site (or contiguous sites under common control) with a peak load of 20 megawatts or more that is interconnected under a retail transmission tariff. It narrows “costs of serving” to routine transmission, distribution, energy, capacity, or ancillary services while expressly excluding upgrades to the transmission or distribution system from that definition.
That definitional split matters because it separates the recurring cost-to-serve calculation from discrete interconnection upgrade costs.
CPUC must open or use an existing proceeding to create, by January 1, 2028, a separate class and rate schedule for these facilities that is distinct from other commercial and industrial rates. The bill requires the commission’s adopted rate schedule to allocate costs equal or proportional to actual costs of serving the class, avoid shifting costs onto other customers, and meet criteria the statute lists (including contributing equitably to wildfire mitigation, climate mandates, and grid resiliency).
The statute directs the CPUC to consider how onsite generation at the facility affects system reliability and cost allocation to nonparticipating customers.For facilities taking service on or after January 1, 2027, the CPUC must require the serving electrical corporation to enter a contract covering transmission, generation, or distribution service as applicable. Transmission or distribution interconnection contracts must be for a minimum of 15 years; contracts generally must specify duration, require a commission-determined minimum payment or percentage based on projected usage, and include reporting obligations so the utility sees planned onsite generation investments before service begins.
The bill preserves a facility’s right to use direct access, a community choice aggregator, voluntary renewable tariffs, or a special contract approved by the CPUC, but requires any contract to be consistent with the statute’s requirements.Finally, the bill instructs the CPUC, to the extent permitted by the Federal Energy Regulatory Commission (FERC), to require large energy use facilities to cover electrical infrastructure upgrades needed for interconnection, including their proportionate share of shared network upgrades. That provision explicitly invites coordination — and potential friction — with federal rules governing who pays for transmission upgrades.
The Five Things You Need to Know
A “large energy use facility” is any contiguous site under common control with a peak load of 20 megawatts or more that takes service under a retail transmission tariff.
CPUC must establish the separate classification and rate schedule on or before January 1, 2028; contracts required under the bill apply to facilities receiving service on or after January 1, 2027.
Transmission or distribution interconnection contracts must be for a minimum of 15 years; contracts must also include a commission‑determined minimum payment or percentage based on projected usage.
The statute excludes transmission and distribution upgrades from the statutory definition of “costs of serving,” but separately requires facilities, to the extent permitted by FERC, to pay for necessary interconnection and shared network upgrades.
Contracts must require facilities to report expected investments in onsite generation to the electrical corporation prior to the initial point of service, and the CPUC must ensure rates include equitable contributions for wildfire mitigation, climate mandates, and grid resiliency.
Section-by-Section Breakdown
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Definitions and scope
This section codifies the core definitions: “costs of serving,” “facility,” “large energy use facility” (20 MW+ under a retail transmission tariff), and “retail electricity consumer.” Notably, it excludes transmission and distribution upgrades from the statutory “costs of serving” definition, creating a separate bucket for capital upgrades that the bill later assigns to facilities to the extent federal law allows.
CPUC classification and rate-schedule requirements
CPUC must create a distinct classification and rate schedule for large energy use facilities by Jan 1, 2028, and the statute prescribes several rate-validation tests: allocation proportional to costs, protections against cost-shifting, and criteria that force the commission to weigh wildfire liability, climate mandates, resiliency, and the state’s clean-energy targets. Practically, the provision forces the CPUC to develop a cost‑allocation model for a single large‑user class and to justify rate designs in light of state policy goals and nonparticipant protections.
Temporary non‑applicability until CPUC approval
This short, time-bound section says utilities and facilities don't have to adopt the new classification until the CPUC approves the utility’s rate schedule for that class; it expressly sunsets on Jan 1, 2028. The effect is to pause mandatory use of the new classification until rate designs and tariffs receive regulatory sign-off, preventing a unilateral reclassification before procedural work is complete.
Mandatory contracts, payment floors, reporting, and exceptions
The CPUC must require electrical corporations to enter contracts with large energy use facilities for the services provided; transmission/distribution interconnection contracts must run at least 15 years. Contracts must be consistent with Section 945.1 criteria, include a commission-set minimum payment tied to projected usage, obligate facilities to disclose planned onsite generation before service starts, and permit—but bind—alternative procurement routes (direct access, CCA, voluntary tariffs, or CPUC‑approved special contracts) so long as they meet the statute’s requirements.
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Explore Energy in Codify Search →Who Benefits and Who Bears the Cost
Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- Large energy use facilities seeking predictability — The contract requirements and distinct rate class create clearer commercial terms and a path to negotiate long-duration commitments and cost responsibilities, reducing regulatory uncertainty around price exposure and allocation of upgrade costs.
- Electrical corporations (investor‑owned utilities) — Mandated contracts and minimum payments reduce sales and revenue uncertainty, improve demand forecasting, and provide a contractual means to recover some fixed costs tied to serving large customers, easing planning for generation and transmission needs.
- Nonparticipating ratepayers — The statute directs the CPUC to prevent cost‑shifting and to make large facilities contribute equitably to wildfire mitigation, climate mandates, and resiliency, which could protect smaller customers from subsidizing disproportionate system impacts.
- Workforce and local economic development — By instructing the CPUC to encourage facilities that bring high‑wage, high‑skilled jobs, the bill creates a policy signal that could make California more attractive to certain large industrial investments.
Who Bears the Cost
- Large energy use facilities — The bill requires minimum payments, potentially long contract terms, reporting obligations, and, to the extent permitted by FERC, payment for interconnection and shared network upgrades, shifting upfront capital risk toward the customer.
- Electrical corporations — Utilities will incur administrative, contract‑management, and procurement costs (and potential stranded investments) implementing new rate schedules and long‑term contracts, and may bear costs that cannot be passed through immediately under existing regulatory mechanisms.
- Other rate classes and nonparticipating customers — If the CPUC's cost allocation is imperfect, residual risks remain that some costs (like reliability or procurement premiums) indirectly affect other customers through overall utility revenue requirements.
- Community Choice Aggregators and direct access providers — While not banned, their customers who are large facilities may be constrained by contract terms, reporting requirements, and statutory consistency obligations that change procurement flexibility.
Key Issues
The Core Tension
The central dilemma is balancing explicit cost responsibility and contractual certainty for very large customers against preserving equitable and reliable service for smaller customers: shifting more interconnection and reliability costs onto big users reduces cross-subsidies but may deter beneficial investment or push costs into wholesale/regulated constructs controlled by FERC, creating jurisdictional and fairness tradeoffs with no simple solution.
The bill threads several technically difficult tradeoffs. First, separating “costs of serving” from interconnection up‑front upgrades creates bookkeeping clarity but invites disputes about which upgrades are truly interconnection‑related versus general system needs.
Utilities, large customers, and potentially FERC will contest where shared network upgrades fall, and disputes could delay project timelines or shift costs unpredictably.
Second, the statute requires the CPUC to prevent cost‑shifting while also asking for equitable contributions to wildfire mitigation, climate mandates, and resiliency—objectives that pull in different directions. Designing a rate that both reflects marginal or embedded costs and collects equitable contributions for state programs is computationally and politically complex.
The minimum‑payment model tied to projected usage helps utilities recover fixed costs but risks overcharging if usage forecasts fall short or onsite generation reduces grid demand unexpectedly.
Finally, federal jurisdiction over transmission and shared network upgrade cost allocation complicates implementation. The bill conditions facility payment obligations on FERC permissibility; that caveat means outcomes may depend on lengthy, fact‑specific federal proceedings or tariff interpretations.
Enforcement, confidentiality of commercial data reported under contracts, and how onsite generation (which the bill requires to be reported) will be credited in cost‑allocation models are open operational questions the CPUC must resolve.
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