AB 1372 revises California’s net energy metering framework and introduces two new metering modalities — co‑energy metering and wind energy co‑metering — while updating administrative and billing rules for customer‑owned renewable generation. The bill also clarifies eligibility criteria and the valuation/ownership of exported energy and renewable attributes.
For professionals managing distributed energy resources, interconnection, or tariffs, the bill retools how exported generation is measured, billed, and counted toward utilities’ renewable goals — changing commercial decisions about system sizing, meter installations, and whether to pursue export compensation or credits.
At a Glance
What It Does
Requires electric utilities to offer a standardized net energy metering program with annualized (12‑month) netting, creates parallel options called co‑energy metering and wind co‑metering, and directs ratemaking authorities to set a per‑kilowatt‑hour net surplus compensation valuation. It preserves parity with the customer’s otherwise applicable retail rate and forbids standalone standby or demand charges tied to a facility’s generation.
Who It Affects
Applies to electrical corporations, local publicly owned utilities, electrical cooperatives, and a wide range of customer‑generators (residential, small commercial, commercial, industrial, agricultural) and certain institutional operators. It also creates specific carve‑outs for large institutional sites that pursue on‑site generation and for local utilities that elect co‑energy metering.
Why It Matters
Shifts the economics of exported distributed generation by formalizing annual netting, defining how exported kilowatt‑hours are valued, and assigning renewable attributes once a compensation rule is adopted. Compliance, interconnection planning, and project financing will be affected because the bill ties metering configuration and interconnection upgrades to customer costs and tariff design.
More articles like this one.
A weekly email with all the latest developments on this topic.
What This Bill Actually Does
AB 1372 repackages California’s net energy metering program into a still‑familiar but operationally tighter system. It requires utilities to provide a standard net energy metering contract or tariff on a first‑come, first‑served basis up to a 5 percent program cap (calculated against aggregate peak demand) and sets the accounting period for netting at 12 months.
That means an eligible customer‑generator’s imports and exports are reconciled annually: customers who consume more than they produce owe for net consumption; customers who produce more than they consume become “net surplus” generators and may elect compensation or carry forward credits depending on the utility’s offering.
The bill adds two new metering variants. Co‑energy metering is an option local publicly owned utilities may choose that requires time‑of‑use metering and applies a generation‑to‑generation, time‑sensitive credit formula.
Wind energy co‑metering is a specific track for wind projects sized between 50 kilowatts and one megawatt and follows tailored accounting rules. The statute also expands what counts as “renewable electrical generation” to include regenerative braking from electrified trains when the electricity powering that train comes from qualifying renewable sources — creating a pathway for rail operators to participate as customer‑generators.Eligibility rules are detailed and nonstandard in places.
Typical residential and small commercial systems are capped at one megawatt. The Department of Corrections can qualify for larger on‑site systems (up to eight megawatts) subject to limits on wind exports and to interconnection studies and upgrade costs borne by the customer if upgrades are necessary.
United States Armed Forces bases are eligible under a separate, capacity‑tied carve‑out but are explicitly not entitled to export compensation for exported generation. Where interconnection triggers transmission or distribution upgrades, the bill permits utilities an established study period and allows the customer‑generator to pay upgrade costs and wait for completion.On billing and valuation, the ratemaking authority must set a net surplus electricity compensation rate designed to give net surplus generators just and reasonable compensation “while leaving other ratepayers unaffected.” Once that valuation is adopted, renewable energy credits for exported net surplus electricity transfer to the purchasing utility and the exported energy counts toward the utility’s RPS procurement targets.
The statute also preserves that eligible customer‑generators pay public goods charges and obligates net‑metered customers to reimburse the Department of Water Resources for certain bond‑related and unavoidable contract costs as nonbypassable charges. Finally, the bill mandates safety and performance standards, assigns responsibility for meter upgrades, and requires utilities to provide reporting and timely processing of interconnection and net‑metering applications.
The Five Things You Need to Know
An electrical utility must process a completed net energy metering or interconnection application within 30 working days or notify the applicant and ratemaking authority with a reason and an expected completion date.
Wind energy co‑metering applies only to wind projects greater than 50 kilowatts but not exceeding one megawatt and is governed by Section 2827.8 procedures in the statute.
Eligible customer‑generators with multiple meters may aggregate contiguous or adjacent parcel loads, including parcels separated by a street, but doing so permanently forfeits eligibility for net surplus electricity compensation.
When the ratemaking authority adopts a net surplus compensation rate, renewable energy credits associated with exported net surplus electricity become the property of the purchasing electric utility and the purchases count toward that utility’s Renewable Portfolio Standard targets.
If interconnection of certain larger systems requires transmission or distribution upgrades arising solely from the interconnection, the customer‑generator must pay for those upgrades and wait for completion; the statute allows utilities a prudent study period before completing interconnection.
Section-by-Section Breakdown
Every bill we cover gets an analysis of its key sections.
New metering terms and expanded renewable definition
This section defines co‑energy metering, wind energy co‑metering, net surplus electricity, and net surplus customer‑generator, among other terms. Critically, it broadens the statutory definition of renewable electrical generation to include regenerative braking from electric trains where the powering electricity is itself from qualifying renewable sources. The definitions set the legal frame for everything that follows: whether a site can participate, which metering modality it must use, and how exports are classified for compensation and RPS accounting.
Standard net metering contract, single‑meter accounting, and a 5% program ceiling
Utilities must offer a standard net energy metering contract or tariff until the aggregate peaked capacity used by eligible customer‑generators reaches five percent of the utility’s aggregate customer peak demand. Net metering is accomplished with a single two‑way meter capable of recording flow in both directions; customers may accept additional metering for research or billing accuracy, but if their existing meter lacks two‑way capability they pay to upgrade it. The provision also preserves first‑come, first‑served eligibility and requires utilities to make forms and contracts available online.
30‑working‑day processing windows and study periods for larger interconnections
The bill requires utilities to process net‑metering and interconnection applications within 30 working days for similarly situated customers, or explain delays to the customer and ratemaking authority. For interconnections above one megawatt (or higher caps applicable to institutional carve‑outs), the utility is entitled to a prudent study period as set by the commission’s executive director; if the study shows upgrades are necessary, the customer pays those upgrade costs and waits for completion before interconnection.
Identical retail rate structures and 12‑month annualized netting
Net‑metered customers keep the same rate structure and retail components they would have absent onsite generation (with an exception for time‑variant pricing elements). The statute requires annual reconciliation: imports and exports are netted over a 12‑month period; net consumers pay for net kilowatt‑hour consumption, and net surplus generators may elect either payment under a net surplus compensation rate or carry forward credits. Importantly, the bill forbids new standby, demand, customer, or interconnection charges that would make net‑metered customers pay more than similarly situated non‑participants.
Meter aggregation across adjacent parcels and allocation rules
Customers with multiple meters on contiguous or adjacent parcels (including those divided by streets) can elect to aggregate load across those meters for netting purposes, subject to a one‑megawatt total facility limit. If they aggregate, the bill requires proportional allocation of generation among meters based on each meter’s share of load and makes the election irrevocable for compensation purposes — aggregated customers cannot later receive net surplus electricity compensation and the utility retains any kilowatt‑hours in excess of aggregated load.
Ratemaking for net surplus compensation and treatment of renewable attributes
The ratemaking authority must establish a net surplus compensation valuation designed to be just and reasonable and avoid cost‑shifting to other ratepayers; that valuation can include the energy value and, where justified, the value of renewable attributes. Once the ratemaking authority adopts a compensation rate, renewable energy credits for exported net surplus electricity belong to the purchasing utility and those purchases count toward the utility’s RPS procurement. The bill also makes certain charges nonbypassable (including Department of Water Resources bond‑related costs) and ensures any shortfalls remain within the affected customer class.
This bill is one of many.
Codify tracks hundreds of bills on Energy across all five countries.
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
- Distributed generation owners and developers — The bill clarifies billing rules, creates explicit export valuation via net surplus compensation, and allows certain site types (including rail regenerative projects) to participate, improving bankability and playbooks for project sizing.
- Local publicly owned utilities that elect co‑energy metering — They gain a defined, time‑of‑use based mechanism to credit behind‑the‑meter generation in a way that better aligns generation and load timing.
- Utilities’ RPS compliance programs — Purchased net surplus electricity, once compensated, counts toward a utility’s RPS targets, giving utilities an additional compliance avenue.
Who Bears the Cost
- Customer‑generators requiring interconnection upgrades — If an interconnection study shows upgrades are needed solely because of the project, the customer pays for them and must wait for completion.
- Electric utilities and their ratepayers in the short term — Utilities must implement new reporting, meter installs, and tariff filings; where compensation rates are set above avoided cost, customers in the same class could bear indirect costs unless the ratemaking process prevents cost‑shifting.
- Small local governments or institutions deploying large systems — Entities like the Department of Corrections can build larger systems but face special constraints (export limits and the responsibility to fund and wait for upgrades), complicating project timelines and budgets.
Key Issues
The Core Tension
The bill is trying to balance encouraging distributed renewable investment (including unconventional sources like train regenerative braking) with protecting nonparticipating ratepayers and preserving utility system reliability; the central dilemma is that higher compensation or broad aggregation encourages more behind‑the‑meter deployment but increases the risk of cost‑shifting, grid upgrade needs, and misaligned timing — and the statute leaves the critical valuation work to contested ratemaking decisions.
AB 1372 stitches together multiple policy goals — broad participation, time‑sensitive valuation, and utility operational certainty — but that combination produces several practical tensions. First, annualized netting smooths short‑term volatility but weakens the price signals for generation at times of system peak; co‑energy metering tries to restore time alignment but applies only where a local utility elects it and imposes time‑of‑use metering costs on customers.
Second, requiring the customer to pay for distribution or transmission upgrades internalizes cost causation but can deter larger behind‑the‑meter projects or shift projects toward grid‑connected development that increases utility procurement rather than customer self‑supply.
Implementation questions remain. The statute empowers ratemaking authorities to set a ‘‘just and reasonable’’ net surplus compensation valuation and to ensure no cost shifting, but it gives little methodologic guidance on how to value the time, locational, and capacity attributes of exports.
That leaves the valuation to contested ratemaking proceedings where outcomes will materially affect project returns. Similarly, treating RECs as utility property after a compensation rule is adopted simplifies RPS accounting but may reduce the monetizable asset pool for project owners and third‑party financiers.
Finally, the carve‑outs for institutional players (Department of Corrections, Armed Forces) create uneven incentives: larger capacity allowances can lower per‑kWh costs for those institutions, but export limits and the denial of compensation to some military facilities complicate procurement and financing choices.
Try it yourself.
Ask a question in plain English, or pick a topic below. Results in seconds.