California lawmakers have advanced two virtual power plant bills through a critical legislative committee, reviving a policy push that Governor Gavin Newsom rejected last year amid rising electricity costs and grid reliability concerns. The bills – AB 2451 and SB 1374 – would require utilities to integrate distributed energy resources like rooftop solar, batteries, and smart thermostats into grid planning and market operations at scale. If enacted, they could unlock gigawatts of flexible capacity from customer-sited assets, directly affecting how the state meets peak demand without new gas plants or transmission build-out.
Legislative Mechanics and the Veto Precedent
The two bills cleared the Assembly Utilities and Energy Committee and Senate Energy, Utilities and Communications Committee respectively in early July, meeting the “policy committee” deadline that kills most legislation each session. AB 2451, authored by Assemblymember Laura Friedman, directs the California Public Utilities Commission (CPUC) to establish targets for virtual power plant procurement by investor-owned utilities, with interim milestones starting in 2026. SB 1374, from Senator Josh Becker, complements this by requiring the CPUC to create a compensation framework that values the locational and temporal benefits of distributed resources – essentially paying VPPs for where and when they deliver power, not just how much.
Last October, Newsom vetoed three VPP bills (AB 1373, SB 1174, and AB 2054) in a single message, arguing they would “increase costs for ratepayers” and “duplicate existing CPUC proceedings.” His veto message emphasized that the CPUC’s Distribution Resources Plan (DRP) and Integrated Resource Plan (IRP) processes were already evaluating VPP integration. That reasoning drew sharp criticism from clean energy advocates and some legislators who noted the CPUC’s proceedings had produced no binding procurement targets after years of workshops. The current bills differ by writing specific deadlines and valuation requirements into statute, removing CPUC discretion to delay.
Newsom’s office has not signaled a position on the 2024 versions. His administration’s current energy focus – codified in the “Strategic Reliability Reserve” and the 2023 budget’s $2.2 billion for demand-side resources – suggests openness to VPPs as a reliability tool, but the governor remains sensitive to rate impacts. Residential electricity rates in PG&E, SCE, and SDG&E territories have risen 30-50% since 2020, driven by wildfire mitigation costs, undergrounding mandates, and generation procurement. Any bill perceived as adding to that trajectory faces scrutiny.
Grid Economics: VPPs Versus Peakers and Transmission
That points to a core tension: VPPs are among the lowest-cost capacity resources available, but their deployment requires upfront investment in enrollment, software, and customer incentives that utilities recover through rates. The California Energy Commission estimates the state needs 7-10 GW of new clean capacity by 2030 to meet reliability standards while retiring gas plants. A 2023 Brattle Group study for the CPUC found VPPs could provide 7.5 GW of peak reduction by 2035 at a levelized cost of $50-150/kW-year – compared to $150-300/kW-year for new combustion turbines and $400-600/kW-year for standalone battery storage when full interconnection and land costs are included.
If this trend holds, mandating VPP procurement targets could save ratepayers billions versus the default resource adequacy procurement path. But the savings are not automatic. They depend on participation rates, which in turn depend on compensation design. Current programs like PG&E’s Emergency Load Reduction Program (ELRP) and SCE’s Capacity Bidding Program pay roughly $1-2/kWh for event-based reductions – lucrative for participants but thinly subscribed. A 2024 Lawrence Berkeley National Lab analysis found only 3-5% of eligible residential customers enroll in such programs without automated enrollment or bill protection guarantees. The Becker bill’s locational valuation mandate aims to fix this by paying more for resources in constrained grid areas, potentially doubling effective compensation for batteries in West LA or the Central Valley.
By comparison, Texas ERCOT’s demand response participation hovers around 10% of peak load after a decade of market reforms, while Australia’s South Australia grid routinely sees 15-20% of peak demand met by orchestrated distributed resources. California’s fragmented regulatory structure – three large IOUs, dozens of community choice aggregators, and a CPUC that separates distribution planning from resource adequacy – has slowed similar adoption.
Who This Affects
- Utility planners: Must model VPPs as firm capacity in IRP filings starting 2026, requiring new distribution-system visibility tools and coordination with aggregators – a shift from treating DERs as load modifiers to dispatchable resources.
- Storage and solar developers: Gain a statutory pathway to stack VPP revenue (capacity payments, energy arbitrage, ancillary services) behind a single customer contract, improving project financeability for residential and C&I battery attachments.
- Aggregators and VPP software providers: Face a defined procurement pipeline with utility counterparties, reducing customer acquisition cost uncertainty – but must meet telemetry and performance standards the CPUC will codify.
- Ratepayer advocates: Gain legislative leverage to demand cost-effectiveness proof for every VPP megawatt procured, with the CPUC required to report annual $/kW-year metrics by utility.
What to Watch Next
- Appropriations Committee votes (August): Both bills carry fiscal notes – AB 2451 estimates $15-25 million annual CPUC administrative costs; SB 1374’s valuation study mandate adds $3-5 million. If placed on the “suspense file” for costs exceeding $150,000, they need a separate floor vote to advance.
- CPUC Rulemaking 22-07-005 (DER valuation) final decision (Q4 2024): The commission’s parallel proceeding on “avoided cost calculator” updates will set the baseline compensation methodology; legislation could override or accelerate it.
- Governor’s signing deadline (September 30): Newsom has 30 days post-passage to sign, veto, or allow bills to become law without signature. His 2023 veto message language will be the template for any 2024 objection.
- Utility 2025 General Rate Case filings (late 2024): PG&E, SCE, and SDG&E will embed VPP program costs and proposed cost-recovery mechanisms – the first real test of whether ratepayer advocates accept the cost-benefit case.
Bottom line: California has moved from studying virtual power plants to writing procurement mandates into law – the question is no longer whether VPPs will be part of the resource stack, but whether the compensation framework will unlock enough customer participation to make the mandates meaningful rather than symbolic.
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Note: facts and figures attributed above to Energy News Network reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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