This bill directs the State Energy Resources Conservation and Development Commission (CEC) to create transparent methodologies for when and how load‑serving entities (LSEs) can reflect aggregated behind‑the‑meter (BTM) demand reductions in their electricity demand forecasts. It also authorizes the commission to partner with utilities and aggregators to test technological and programmatic approaches so that operators can rely on those reductions for planning.
Why it matters: counting aggregated BTM reductions differently changes how the grid plans for capacity and reliability and shifts investment signals for both supply‑side resources and flexible demand products. For compliance officers, procurement teams, and aggregators, the bill creates a pathway to convert behind‑the‑meter flexibility into something that can be used in formal reliability planning — but it also raises practical questions about verification, coordination across agencies, and market treatment.
At a Glance
What It Does
The bill requires the CEC to define and publish standardized ‘‘load modification protocols’’ that allow LSEs to lower or modify the demand forecasts they submit under state law when aggregated BTM technologies and programmatic measures operate and are deemed to reliably reduce demand by the CEC, the Public Utilities Commission (CPUC), and the Independent System Operator (CAISO). The commission may use legislative appropriations to pilot and test technological and programmatic approaches in partnership with LSEs and distributed energy resource aggregators.
Who It Affects
Directly affected parties include load‑serving entities (investor‑owned utilities, publicly owned utilities, and other entities that serve load under PUC §380), behind‑the‑meter DER aggregators and demand‑response providers, and system operators (CAISO and regulators at the CPUC). Indirectly affected players include manufacturers of smart thermostats, batteries and controls, energy service companies, and procurement and resource‑planning teams.
Why It Matters
If regulators accept verified aggregated demand reductions in formal forecasts, that can reduce reliance on fossil, on‑call generation in planning and change how capacity needs are procured. The measure shifts focus from measuring only program enrollment to verifying real‑world, automated performance — which could speed commercialization of flexible demand products but also requires robust measurement and interagency coordination.
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What This Bill Actually Does
The bill charges the California Energy Commission with creating clear, public methodologies — called load modification protocols — that explain when and how an LSE can reflect the effect of aggregated behind‑the‑meter actions in its statutory demand forecast. Those protocols must be developed in consultation with the entities that operate and aggregate the resources, ensuring the rules are practical for both utilities and third‑party aggregators to implement.
The aim is to move from loosely counted demand‑side programs toward a standardized, verifiable way to convert aggregated demand reductions into forecasted, reliable capacity contributions.
To be useful for planning, the protocols will need to define eligibility, performance metrics, and verification methods for a wide range of technologies and program types — for example, automated thermostatic control, battery dispatch behind the meter, or aggregated EV charging curtailment programs. The bill explicitly ties the protocols’ credibility to an interagency view: the CEC, CPUC, and CAISO must consider these aggregated actions reliable before an LSE can adjust its forecast on that basis.
That three‑way credibility requirement signals that the protocols are meant to feed into both reliability planning and market operations, not simply serve as a reporting convenience.Recognizing reliability requires more than rules on paper, the bill lets the CEC use legislative appropriations to run pilots or demonstration projects with willing LSEs and aggregators. Those pilots are intended to generate operational data and build confidence that aggregated BTM resources will perform as expected when called upon.
Importantly, the bill focuses on forecasting and transparency: it does not itself create new payment schemes, change existing rate structures, or alter CAISO market rules — but those downstream questions will become urgent once protocols are in place.Finally, the statute anchors terminology to existing law by referring LSEs to the definition in Public Utilities Code §380. That keeps the scope tied to entities already recognized in state regulation but leaves open the detailed definitions of eligible technologies, program types, measurement intervals, and the specific M&V standards the commission must adopt or reference.
The Five Things You Need to Know
The commission must develop and publicize 'load modification protocols' that let LSEs adjust forecasts submitted under Section 25301 when aggregated BTM measures operate and are deemed reliable.
The bill requires consultation with load‑serving entities and distributed energy resource aggregators when defining the methodologies.
The reliability judgment that allows a forecast adjustment depends on agreement among the CEC, the CPUC, and the Independent System Operator (CAISO).
The CEC is authorized to use funding appropriated by the Legislature to test technological and programmatic approaches with LSEs and aggregators to improve confidence in performance.
The statute adopts the term 'load‑serving entity' by reference to Public Utilities Code §380, tying the rule to existing regulatory actors and obligations.
Section-by-Section Breakdown
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Legislative findings and intent
This prefatory section explains why the Legislature wants demand flexibility counted more reliably: to align renewable supply with flexible demand, reduce reliance on fossil generators for reliability, and accelerate commercialization of automated demand‑side tools. The findings frame the bill as an enabling step — emphasizing transparency and the need for high confidence in flexible demand performance before it can replace supply‑side resources in planning.
Define and publish load modification protocols
This is the operative mandate. The CEC must, in consultation with LSEs and aggregators, produce public methodologies detailing when and how aggregated BTM actions can be used to reduce or modify the statutory demand forecast. The clause ties acceptance of those adjustments to a determination of reliability by the CEC, CPUC, and CAISO, which effectively makes the protocols a cross‑agency gate for counting demand‑side contributions in formal planning processes.
Pilot testing authority using legislative appropriations
The commission may use available appropriated funds to run tests of different technical and programmatic approaches with interested LSEs and aggregators. Practically, this authorizes pilots that generate the operational data the CEC and other agencies will need to judge whether a given class of aggregated BTM resources can be relied upon in planning, and it signals that the Legislature expects empirical validation before widespread adoption.
Reference for 'load‑serving entity' definition
Rather than redefining terms, the bill imports the 'load‑serving entity' meaning from Public Utilities Code §380. That keeps the provision scoped to entities already governed by California utility law and avoids ambiguity about which organizations can adjust forecasts under the protocols.
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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
- Load‑serving entities (investor‑owned utilities, publicly owned utilities and other entities under PUC §380): they gain an explicit, regulator‑defined pathway to reflect aggregated demand flexibility in formal forecasts, which can reduce procurement obligations and lower capacity costs if validated.
- Distributed energy resource aggregators and demand‑response providers: the protocols create a clearer commercial pathway to have aggregated behind‑the‑meter performance recognized in planning, improving the marketability and potential contract value of flexible demand products.
- Grid operators and reliability planners (CAISO and the CEC): better, standardized inputs for planning reduce uncertainty about how much flexibility is actually available during stress events and can improve alignment between operational needs and resource commitment.
- Ratepayers and climate planners: if protocols reliably unlock demand flexibility, the state may reduce the need for fossil peaker plants and expensive out‑of‑state capacity, lowering costs and emissions over time.
Who Bears the Cost
- California Energy Commission (CEC): staff time and technical capacity to design protocols, run pilots, analyze data, and maintain public methodologies — tasks that require funding and coordination across agencies.
- Load‑serving entities and aggregators: administrative and technical costs to collect data, implement verification and telemetry, participate in pilots, and adapt procurement and operations to account for forecast adjustments.
- Distributed resource owners and vendors: potential upfront investment to meet new performance and reporting requirements (telemetry, control interfaces, response guarantees) so their resources qualify under the protocols.
- System regulators (CPUC and CAISO): transaction costs to coordinate on reliability determinations and potentially to change market rules or settlement processes if protocols affect resource valuation.
Key Issues
The Core Tension
The central dilemma is this: California needs to trust aggregated behind‑the‑meter flexibility enough to replace some supply‑side capacity, but trusting it too quickly risks overestimating available resources and jeopardizing reliability. The bill pushes for standardized, public protocols and pilots to resolve that tension, but setting those standards involves trade‑offs between conservatism that can slow market participation and permissiveness that can introduce reliability or market‑integrity risk.
The bill asks for standardized protocols but leaves many consequential details to later rulemaking and interagency coordination. It does not specify performance thresholds, minimum sample sizes for pilots, detailed measurement and verification (M&V) standards, or how to treat partial performance or non‑performance during peak events.
Those gaps mean implementation could become contentious: M&V standards determine whether a resource is conservative enough to protect reliability or permissive enough to let lower‑cost products qualify.
Another implementation challenge is double‑counting and interaction with existing programs. Aggregated BTM actions are already enrolled across demand‑response programs, capacity procurements, and retail rate designs; the protocols must avoid crediting the same kilowatt‑reduction to multiple products or markets.
The bill also does not address liability or backstop obligations if an aggregated resource fails to deliver when its forecasted contribution was relied upon — a legal and commercial question likely to require new contract language or market rules. Finally, the authorization to use legislative appropriations for pilots is useful but not guaranteed funding; the pace of adoption will depend on whether the Legislature funds demonstration work and whether CAISO and CPUC accept the resulting methodology into market and reliability processes.
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