AB 388 requires the California Public Utilities Commission (CPUC) to evaluate and, if just and reasonable, establish by July 1, 2027 a retail tariff for large “qualified self‑generation projects” with generating capacity greater than 80,000 kilowatts. The tariff would make the investor‑owned utility act as a retail intermediary to purchase electricity from specified solar, wind, or associated storage facilities and resell it to the industrial customer at cost plus incremental administrative charges.
The bill targets new‑load electrolytic hydrogen plants and industrial process‑heat users supplied over private lines, requires participating customers to pay related infrastructure costs and wildfire mitigation where applicable, and explicitly excludes the served load from utilities’ procurement and renewable portfolio accounting calculations. That combination creates a new commercial path for very large off‑site renewables to supply heavy industrial electrification while raising questions about procurement accounting, cost allocation, and federal/state jurisdictional interface.
At a Glance
What It Does
Directs the CPUC to open or use a proceeding to adopt a tariff by July 1, 2027 for self‑generation projects above 80 MW, under which an electrical corporation purchases electricity from specified solar, wind, or dedicated storage and resells it to the customer at cost plus incremental administrative or operational charges. The structure is explicitly intended to allow the generation or storage facilities to be treated as exempt wholesale generators under federal rules.
Who It Affects
Large industrial electricity consumers building new electrolytic hydrogen or industrial process‑heat loads supplied over private lines, developers of utility‑scale solar, wind, and associated storage paired to those loads, and investor‑owned utilities asked to act as retail intermediaries. It also affects CPUC oversight staff and OEIS for wildfire mitigation review.
Why It Matters
The bill creates a regulated commercial pathway for very large off‑site renewable and storage resources to serve industrial electrification without counting that load toward utilities’ procurement or RPS obligations, potentially accelerating hydrogen and decarbonization projects but altering planning, compliance, and market accounting for utilities and regulators.
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What This Bill Actually Does
AB 388 instructs the California Public Utilities Commission to evaluate and, if it finds the proposal "just and reasonable," adopt a tariff for very large qualified self‑generation projects (capacity above 80,000 kW). The CPUC must decide whether utilities will serve as the retail interface: buying generation and storage output and reselling it to an industrial customer supplied over private lines.
The bill is written to let the underlying generation or storage be considered an exempt wholesale generator under federal rules, while keeping the customer on a regulated retail relationship through the utility intermediary.
Under the tariff the utility acts strictly as an administrator of purchase and resale: the statute requires the utility to buy electricity at cost and resell it at cost, then add only the incremental administrative or operational costs of acting as intermediary. Participating customers are responsible for building and paying for the physical connection infrastructure.
The bill also preserves the option for the customer to take supplemental service under a standard offer tariff with separate metering, so projects are not forced exclusively onto the new tariff.The scope of eligible customers is tightly defined: electricity must flow exclusively and directly over private electric lines from solar or wind generation or storage charged only from those resources; the served uses are limited to electrolytic hydrogen production and industrial process heat; the load must be new, not existing load that has departed a utility; and if private lines run through high fire‑threat areas the customer must file wildfire mitigation plans consistent, to the extent feasible, with specified state standards. Costs associated with implementing the tariff are charged only to participating customers.
Finally, any customer load served under this tariff is explicitly excluded from several statutory procurement and accounting requirements, including certain Renewable Portfolio Standard and procurement statutes, which changes how utilities count and meet procurement obligations.
The Five Things You Need to Know
The CPUC must evaluate and potentially adopt the tariff on or before July 1, 2027 for projects with generating capacity exceeding 80,000 kilowatts.
Under the proposed tariff the electrical corporation serves as a retail intermediary that purchases electricity from specified solar, wind, or dedicated storage facilities and resells it solely at cost plus incremental administrative/operational charges.
Eligible projects are limited to new‑load electrolytic hydrogen production or industrial process‑heat facilities served exclusively via private lines from solar/wind generation or storage charged exclusively by those resources.
Participating customers must bear all infrastructure costs for the private connection and pay any costs associated with the tariff—nonparticipating customers are statutorily protected from those costs.
Load supplied under the tariff is excluded from calculations used to determine utilities’ procurement obligations and certain RPS/procurement‑related statutes listed in the bill.
Section-by-Section Breakdown
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CPUC duty to evaluate and adopt tariff by July 1, 2027
This subsection imposes a timetable: by July 1, 2027 the commission must open a new or use an existing proceeding to evaluate and, if it finds the result just and reasonable, establish a tariff for qualified self‑generation projects above the 80,000 kW threshold. Practically, that gives the CPUC a statutory deadline to develop rules, but the language preserves traditional CPUC discretion by conditioning adoption on the tariff being just and reasonable.
Utility as retail intermediary; EWG treatment
The bill requires the tariff to structure the investor‑owned utility as the retail intermediary between the generation/storage asset and the qualified customer. It explicitly directs the CPUC to permit the generation or storage facilities to be considered exempt wholesale generators under 18 C.F.R. § 366.1. That is a deliberate attempt to align state retail treatment with federal wholesale classifications, which will require careful coordination with FERC and market operators to ensure the legal and operational boundaries are clear.
Cost‑based purchase/resale plus incremental charges
This provision constrains pricing mechanics: the utility must administer the purchase and resale of energy from the generation or storage facility solely at cost, and then may add only the incremental administrative or operational costs of serving as the intermediary. The CPUC will need to define what counts as "cost" and what is "incremental"—issues that affect billing design, auditability, and potential cost recovery mechanisms.
Supplemental service allowed; wholesale participation neutral
The bill allows qualified projects to take supplemental service from a standard offer tariff through separate metering rather than being forced onto the new tariff; this preserves commercial flexibility. It also states that the bill neither authorizes nor prohibits the associated generation or storage from participating in wholesale electricity markets, leaving that determination to existing federal and market rules and potentially creating parallel retail and wholesale pathways for the same resource.
Definition of 'qualified self‑generation project'—source, ownership, use, and new‑load test
The bill narrowly defines eligible projects. Supply must be exclusively and directly transmitted over private lines from solar or wind generation or storage that stores energy exclusively from those technologies. The customer must pay for any connection infrastructure, use the electricity only for electrolytic hydrogen production or industrial process heat (with de minimis ancillary use allowed), and the electricity must serve new load—not load that has left utility service. Those constraints target a specific commercial model: large, green power to new industrial electrification.
Wildfire mitigation and electrolytic hydrogen definition
If any private lines covered by the new tariff cross areas the CPUC designates as high fire threat, the customer must file a wildfire mitigation plan consistent with Office of Energy Infrastructure Safety (OEIS) and certain statutory standards to the extent feasible. The bill also supplies a broad working definition of an "electrolytic hydrogen production facility," covering electrolyzers and auxiliary systems—language that clarifies the scale and scope of facilities the tariff intends to serve.
Cost allocation and rules for private lines
The statute bars shifting costs to nonparticipating customers: any cost associated with the section must be paid solely by participating customers. It also says that private lines on property other than the property hosting the single facility are subject to applicable General Orders, unless all property is commonly owned by the same corporation or person, putting nuance around inspection, safety standards, and jurisdiction over private distribution.
Exclusion from procurement and RPS calculations
This subsection lists specific statutory procurement and accounting provisions from which load served under the tariff is excluded (including Section 380, Article 16 beginning at Section 399.11, and Sections 454.51–454.52). That is the clearest statement that the bill intends these projects not to count in utilities’ procurement obligations, which has direct planning and compliance consequences for utilities and their resource portfolios.
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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
- Developers of large solar, wind, and co‑located storage projects — the tariff creates a commercial path to supply very large industrial customers while enabling the generation facility to be treated as an exempt wholesale generator, which can simplify project finance and market participation.
- Operators of new electrolytic hydrogen plants and industrial process‑heat facilities — they gain a regulated retail model to obtain dedicated renewable energy delivered over private lines, with the option for supplemental standard offer service.
- Large industrial corporate owners that can fund private connection infrastructure — they avoid counting the served load toward utility procurement obligations, potentially simplifying corporate renewable accounting and enabling direct long‑term supply arrangements.
Who Bears the Cost
- Participating customers (project owners and industrial offtakers) — the bill requires them to pay all infrastructure and tariff‑related costs, including wildfire mitigation where applicable, and to cover the costs of the purchase/resale mechanism as determined by the CPUC.
- Investor‑owned utilities asked to act as intermediaries — utilities must implement, administer, and audit the tariff and bear operational responsibilities, even if they only recover incremental charges, creating implementation and compliance workload.
- Regulators and safety agencies (CPUC and OEIS) — they must resolve technical definitional questions, supervise wildfire mitigation plans, and coordinate with federal authorities on EWG status and market participation, likely requiring new analytic and oversight resources.
Key Issues
The Core Tension
The central dilemma is balancing the policy goal of enabling large, dedicated renewable supply to power industrial decarbonization against preserving systemwide procurement, reliability, and equitable cost allocation: the bill facilitates direct paths for big users to access renewables but does so by carving those loads out of utility procurement and relying on narrowly written eligibility and cost‑recovery commitments that will be difficult to police and coordinate across state and federal regulators.
The bill sets out a specific commercial architecture but leaves the CPUC with substantial technical discretion. Key implementation questions include how the CPUC will define "cost" and "incremental administrative or operational costs," how it will audit compliance with the exclusive‑supply and new‑load requirements, and what enforcement tools will prevent gamesmanship such as reclassifying existing load as "new." The instruction to allow underlying facilities to be treated as exempt wholesale generators creates a federal–state interface: project owners and the CPUC will need to coordinate with FERC and regional market operators to settle whether and how assets can be simultaneously treated as wholesale, participate in markets, and be connected to a retail intermediary without double counting or jurisdictional conflict.
The procurement and RPS carve‑outs are the most consequential policy hooks. Excluding this load from utilities’ procurement obligations could speed project deployment for targeted industrial customers, but it also reduces the pool of load utilities use to meet statutory targets—potentially shifting the timing and costs of compliance.
Although the bill requires participating customers to pay associated costs, system planning impacts (transmission planning, local reliability, and congestion) can create indirect costs borne by other customers or the grid operator. Finally, the wildfire mitigation and private‑line ownership exceptions create practical enforcement questions: when does a multi‑parcel ownership structure qualify for the ownership exception, and how will the CPUC and OEIS ensure mitigation plans are adequate before energization?
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