AB 740 requires the California Energy Commission to develop a virtual power plant (VPP) deployment plan as part of the next update to the Integrated Energy Policy Report after January 1, 2027, subject to available funding. The plan must be developed with the California Public Utilities Commission, the Independent System Operator (CAISO), and the disadvantaged community advisory group, and through public workshops and stakeholder sessions.
The statute directs the plan to do detailed technical and economic work: identify policies, timelines, and resources to meet statewide load-shift goals; analyze how VPPs can qualify for and serve as load-modifying resources for resource adequacy; assess customer energy data barriers; estimate costs relative to alternative capacity; and recommend incentive structures that maximize grid and ratepayer benefits without increasing costs to nonparticipating ratepayers.
At a Glance
What It Does
The bill directs the California Energy Commission to adopt a virtual power plant deployment plan in the next IEP update after Jan. 1, 2027 (if funded). It requires targeted analyses on resource adequacy eligibility, load-modifying capability, customer energy data access, cost comparisons, and incentive alignment.
Who It Affects
The requirement touches the CEC, the California Public Utilities Commission, CAISO, load‑serving entities (including investor‑owned utilities and community choice aggregators), local publicly owned utilities, DER aggregators/operators, device manufacturers, and participating and nonparticipating customers — including disadvantaged communities.
Why It Matters
By tying VPP deployment to resource adequacy and load‑shift goals, the plan could change how DERs are valued and compensated in capacity markets and procurement plans. The bill forces a single statewide assessment of technical, data, and cost barriers and demands recommendations that preserve cost protections for nonparticipating ratepayers.
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What This Bill Actually Does
AB 740 sets a single, mandated planning task: the California Energy Commission must produce a VPP deployment plan as part of its next Integrated Energy Policy Report update after January 1, 2027 — but only if funding is available. The law defines “smart” devices and “virtual power plant” broadly to include behind‑the‑meter batteries, EVs and chargers, smart thermostats, water heaters, smart plugs, building controls, and flexible commercial loads.
That definitional sweep intentionally puts most behind‑the‑meter DERs within scope of the analysis.
The bill prescribes an inclusive process: the CEC must consult with the CPUC, CAISO, and the disadvantaged community advisory group under Public Utilities Code Section 400, hold at least two public workshops, and convene stakeholder sessions with industry, workforce, ratepayer and consumer organizations, load‑serving entities, and local publicly owned utilities. Those steps are designed to surface operational constraints, market rules conflicts, and equity concerns before the CEC issues recommendations.Substantively, the plan must do three technical economic analyses.
First, it must identify barriers and opportunities for VPP resources to qualify for resource adequacy (RA), assess which VPP resources are already eligible under PU Code Section 380, estimate VPP costs against alternative RA sources, and spell out data needs for agencies and CAISO to value those resources. Second, it must analyze VPPs as load‑modifying resources that can reduce an LSE’s RA obligation: recommend fixes to barriers, estimate relative costs, and identify the most cost‑effective VPP types for that role.
Third, the plan must assess customer energy data access barriers that limit VPP operation and value, and propose ways to fix them — a practical recognition that telemetry, metering, and privacy rules are gating issues.Finally, the CEC must evaluate how VPPs can be operated to achieve particular objectives — for example, maximizing savings for participating customers, reducing costs for nonparticipants, lowering greenhouse gas emissions, or relieving local congestion — and propose incentive structures that align those objectives. Critically, any recommendations must not result in increased costs for nonparticipating ratepayers, placing a clear constraint on how incentives and cost allocation can be designed.
Taken together, these requirements map the technical, market, and equity work the state expects before large‑scale VPP deployment is treated as a core grid resource.
The Five Things You Need to Know
The bill requires the California Energy Commission to adopt a VPP deployment plan in the next Integrated Energy Policy Report update after January 1, 2027, subject to available funding.
The CEC must consult with the California Public Utilities Commission, the California Independent System Operator, and the disadvantaged community advisory group established under Public Utilities Code Section 400.
The plan must identify barriers and opportunities for VPPs to qualify for resource adequacy, include an assessment of current eligibility under Public Utilities Code Section 380, and recommend fixes.
The CEC must analyze VPPs as load‑modifying resources that can reduce a load‑serving entity’s resource adequacy obligations, estimate relative costs versus other load‑modifying resources, and identify which VPP resources are most cost‑effective.
The plan must recommend incentive structures that maximize both grid benefits and cost savings while explicitly ensuring no increased costs for nonparticipating ratepayers as a result of VPP deployment.
Section-by-Section Breakdown
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Definitions: “smart” devices and virtual power plant scope
These subsections set the scope by defining “smart” devices (internet‑connected, remotely controllable with explicit customer consent, and customer‑controllable smart features) and “virtual power plant” as an actively coordinated aggregation of behind‑the‑meter DERs. For implementers, these definitions matter because they determine which devices, customers, and aggregators fall within the analysis — and because the customer‑consent language creates an explicit privacy/control baseline that the CEC must respect when recommending data or telemetry requirements.
Timing and funding condition for the plan
The CEC must adopt the VPP deployment plan as part of the next biennial IEP update after Jan. 1, 2027, but only if funding is available. Practically, this makes the mandate conditional: the statutory deadline ties the work to the IEP cycle while leaving budgetary discretion (and potential delays) in the hands of the Legislature or the CEC’s budget process.
Required consultations, workshops, and stakeholder sessions
The CEC must consult with CPUC, CAISO, and the disadvantaged community advisory group and run at least two public workshops plus multiple stakeholder sessions covering industry, workforce, ratepayer and consumer organizations, LSEs, and local public utilities. This structure forces the CEC to surface operational interdependencies (market rules, telemetry, procurement timelines) and equity concerns before issuing technical recommendations — and it creates a record that regulators can reference if they later propose rule changes at CPUC or CAISO.
Resource, policy, timeline needs and resource adequacy analysis
The CEC must identify the resources, policies, and timelines necessary for VPPs to meet statewide load‑shift goals and carry out a deep dive on RA qualification: identify barriers/opportunities, assess which VPPs currently qualify under PU Code Section 380, recommend fixes, estimate VPP costs relative to alternative RA capacity, and specify the data agencies and CAISO need to value VPPs for RA. This subsection compels the CEC to move from conceptual support for VPPs to concrete valuation and procurement inputs that procurement planners and market designers can use.
Load‑modifying resource assessment and customer data access
The bill requires analysis of VPPs as load‑modifying resources that can reduce an LSE’s RA obligations — including cost estimates, identification of the most cost‑effective resource types, and data‑need assessments — and a standalone assessment of customer energy data access barriers. These provisions recognize two practical bottlenecks: (1) the measurement and verification standards needed to let LSEs count DERs toward RA, and (2) the legal, technical, and privacy constraints that limit data flows between customers, aggregators, utilities, and CAISO.
Operational optimization, incentive alignment, and cost protection
The CEC must evaluate how different operational configurations of VPPs support objectives such as maximizing cost savings to participating and nonparticipating ratepayers, cutting greenhouse gas emissions, and easing local congestion. It must recommend incentive structures to align those objectives and explicitly ensure its recommendations do not increase costs for any nonparticipating ratepayers. That last constraint is a binding policy goal that will shape any proposed cost allocation, tariff design, or incentive scheme the CEC advances.
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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
- DER aggregators and VPP operators — the bill commissions a statewide valuation and deployment plan that can clarify market entry rules, RA pathways, and data requirements, reducing regulatory uncertainty for aggregation business models.
- Participating customers (residential and commercial) — if the plan leads to clear compensation and optimization rules, participants can access payment streams for flexibility and potentially lower energy bills through managed load shifting and local grid services.
- Load‑serving entities (LSEs) — with credible measurement, verification, and RA qualification recommendations, LSEs could use VPPs to shave peak obligations and lower capacity procurement costs, if cost‑effective VPPs are identified.
- Disadvantaged communities — the required consultation with the disadvantaged community advisory group creates a channel to surface equity objectives and localized benefits (like congestion relief or local backup) during plan development.
- State planners and CAISO — the mandated assessment of data needs and valuation methods gives planning bodies the analytical inputs needed to integrate VPPs into system planning and market design.
Who Bears the Cost
- California Energy Commission — the CEC must assemble technical analyses, convene stakeholders, and produce cost estimates and recommendations, creating a resource and staffing burden (noted explicitly as subject to available funding).
- Device manufacturers and aggregators — they may need to invest in telemetry, interoperability, cybersecurity, and customer‑consent mechanisms to meet the data and performance expectations identified in the plan.
- Local publicly owned utilities and LSEs — implementing M&V, changing procurement practices, or adapting tariffs to incorporate VPPs will impose operational and administrative costs.
- Small DER providers and installers — new performance or telemetry requirements could raise compliance costs, potentially favoring larger firms with capital to retrofit equipment or build interoperable systems.
- Regulators (CPUC/CAISO) — the plan will likely generate follow‑on rulemaking requests and workload for CPUC and CAISO to change market rules, telemetry standards, or RA counting methods.
Key Issues
The Core Tension
The central dilemma is balancing the technical and market certainty necessary to treat VPPs as reliable, monetizable resources (which requires stringent measurement, telemetry, and data access) against the policy constraints to protect consumers and nonparticipating ratepayers (which restricts how costs and data access can be organized). Tight performance standards and open data flows help markets value VPPs, but they raise compliance and privacy costs that may hinder broad, equitable deployment.
AB 740 forces an evaluation of VPPs across technical, market, and equity dimensions, but it stops short of mandating any specific market rule changes. That leaves open an implementation path where the CEC produces a detailed menu of recommendations and the CPUC and CAISO — each with their own legal authorities and market constraints — decide which to adopt.
Translating CEC recommendations into binding RA rules will require resolving measurement and telemetry standards, defining performance guarantees and penalties, and allocating costs across ratepayers and participants.
The bill’s explicit prohibition on recommending actions that increase costs for nonparticipating ratepayers creates a practical constraint that could limit how incentives are structured. Incentives that reward participating customers or aggregators often require cross‑subsidies, tariff redesign, or new charges; the no‑cost‑increase rule will force the CEC to prioritize net‑neutral or subsidy‑sourced approaches (for example, grant funding or rate‑neutral tariff designs), which may be politically or technically harder to implement.
Finally, the heavy emphasis on data access highlights a second tension: unlocking VPP value requires richer customer data and near‑real‑time telemetry, but expanding data flows raises privacy, cybersecurity, and consent management costs that the bill does not fully resolve.
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