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1Fix the driver behind crashes, sound loss and screen glitches2Clear out junk files and repair common Windows errors3Scan for outdated or missing drivers - takes under a minuteCalifornia could make better use of electricity by shifting some demand to hours when power is plentiful and away from hours when the grid is strained. An August 2026 report from GridLab, Kevala and E3 argues that flexible electricity use—from EV charging to building controls—could help curb grid costs, but only if programs pay for verified value and account for costs borne by customers who do not participate. It does not promise lower bills for any particular household.
What flexible load means
Flexible load is electricity use that can change in response to prices or dispatch instructions. A device may charge, discharge or shift when it uses power. Examples include EVs, distributed batteries, smart appliances and heating and cooling systems, as well as commercial or industrial processes that can shift use or be interrupted in a managed way.
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The opportunity is temporal and sometimes geographic: use more electricity when clean energy is plentiful, and reduce demand during scarce, high-cost hours. Where dispatch can reliably address a specific grid need, flexibility may also help make existing infrastructure work harder or defer some generation, transmission or distribution investment.
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What the report proposes
The authors’ three guiding principles are to compensate flexibility below verified avoided costs, pay for measured performance rather than enrollment alone, and use standardized, interoperable program designs. They argue that baselines must be accurate and difficult to game, participants should be accountable for delivered performance, and programs should be coordinated rather than overlap unnecessarily.
These are recommendations by the report’s authors, not statewide rules. The report, Unlocking California’s Flexible Load: A Durable Blueprint for Affordability and Reliability, was written by Eric Cutter of E3, Pete Skala of Kevala and Ric O’Connell of GridLab. UC Davis’s Energy and Efficiency Institute convened stakeholder roundtables that informed the work. The report says the California Public Utilities Commission (CPUC) did not participate in the project and does not endorse its conclusions.
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Three pathways for using flexible load
The report groups its proposals by how flexibility would be encouraged and what grid value a program would target.
| Pathway | How it works | What the report says to verify or target |
|---|---|---|
Rate-driven load shifting |
Time-of-use or dynamic rates give customers a price signal to shift electricity use, potentially creating persistent changes without an aggregator. | Rates can encourage shifting without program baselines, but the authors say rates alone are unlikely to capture all potential benefits. |
Avoided-system-cost programs |
Programs pay for services that reduce broader system costs, including retail pay-for-performance, firm capacity and tailored wholesale-market access. | Retail programs would use individual-level regression baselines. Firm-capacity offers would need predictable shifts and accountability. Streamlined wholesale access is aimed at large commercial loads and sophisticated aggregations. |
Avoided-distribution-cost programs |
Dispatch is directed to locations where local grid constraints may otherwise require infrastructure upgrades. | Value is location-specific: enrollment and dispatch must address the constrained distribution area and the timing of its need. |
What the reported figures do—and do not—show
The estimates below describe modeled potential or projections, not observed statewide program results. They are not household savings guarantees.
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| Estimate | Source and qualification |
|---|---|
| 7,671 MW of statewide virtual power plant technical potential by 2035, alongside $550 million in annual avoided generation, transmission and distribution costs. | The Brattle Group, 2024; GridLab commissioned the study. The report says broad assumptions make the statewide figures directional potential, not a forecast of achievable program delivery. |
| $6.7 billion to $9.9 billion in avoided distribution upgrade costs associated with 3.5 GW of additional system peak or net-peak flexibility toward a 7 GW goal for 2030. | Kevala, 2025 study updated for the 2026 report. The authors describe this as a broad estimate: value is concentrated in particular locations, and implementation costs are excluded. |
| 2.8 GW lower summer peak demand and $1.8 billion lower cumulative distribution costs through 2040, about 7% of a $25.5 billion base-case distribution investment projection. | PG&E, 2026. This was the utility’s most aggressive flexible-load scenario. The report says the value depends on targeted enrollment and dispatch on constrained circuits. |
| 10% of projected light-duty EVs enrolled in vehicle-to-grid (V2G) could supply 30% of the cumulative utility-scale storage procurement target for 2036. | GridLab, Kevala and E3, 2026. The scenario depends on assumptions about the vehicle fleet, charging power, battery size and capacity accreditation; it is not capacity already installed. GridLab’s release describes the scenario as approximately 9 GW of 12-hour storage and more than one-third of the target. |
The 2026 report also cites a California Energy Commission projection of 8.4 million light-duty EVs in California by 2035 from its 2025 Integrated Energy Policy Report. That is a separate projection from the vehicle-fleet assumption used in the report’s 2036 V2G scenario; the two should not be combined as if they were the same forecast.
Why location, adoption and implementation matter
A statewide technical-potential estimate can obscure where flexibility is useful. A load shift has value only when it occurs at the relevant time and, for local distribution needs, in the relevant place. The amount of potential customers actually adopt also constrains what a program can deliver.
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Recruitment, administration and technical-enablement costs matter too. Because some statewide estimates do not include those costs, they cannot by themselves establish the net benefit of a program. A full cost-benefit assessment needs to account for those expenses as well as the value of the service actually delivered.
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The authors say new flexibility compensation should account for the existing cost shift associated with California’s Net Energy Metering (NEM) and Net Billing Tariff (NBT) arrangements. They argue that a new program should pay only for incremental value not already induced by retail rates, measure performance robustly, and avoid increasing costs for other ratepayers.
Best Value
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- INSTALLS IN CIRCUIT PANEL of most homes with clamp-on sensors. Supports Single phase, Single-split phase, and 2-wire systems. 3-wire systems; 3-phase, 4-wire Wye systems with earthed (TN or TT) neutral (no-Delta) are supported with an additional 200A sensor (sold separately).
- 24/7 ENERGY MANAGEMENT AND MONITORING: Automate, manage and control your home's real power anywhere, anytime to prevent costly repairs, conserve energy, and save costs. Monitor solar / net metering. PROTECTED BY A 1-YEAR WARRANTY.
- LOWER YOUR ELECTRIC BILL: Configure settings in the Emporia Energy App to automate energy management for time of use, peak demand, excess solar, and rewards programs. You can even see live reporting and invaluable savings opportunities instantly. Gauge real-time spending and get actionable notifications and automated energy management to help you reduce costs.
- REAL-TIME ENERGY DATA: REQUIRES 2.4 GHz WIFI WITH AN INTERNET CONNECTION to monitor energy use with iPhone / Android / Web app. Vue sensors collect energy data and are accurate from ±2%. The Vue is UL and CE Listed for your safety. 1 second data is only available in the app (when actively open) and retained 3 hours. Minute and hour data are retained in the cloud. 1 minute data is retained 7 days, 1 hour data is retained indefinitely. Export cloud data whenever you want in the app.
As context, the report cites a CPUC estimate published in 2025 that non-participating customers’ bills had increased by $7 billion per year by the end of 2024 because of California NEM policies. This is the report’s cited estimate of the NEM cost shift, not a new independent measurement by the 2026 report.
The report does not settle whether NEM or NBT customers should be eligible for new programs. It presents exclusion, eligibility when participants deliver verified net benefits, and conditional eligibility after tariff reform as possible policy approaches—not as a settled consensus.
What an EV owner or household can conclude
The report’s case is about potential grid value and program design, not a promise of personal savings or earnings. An EV, battery, smart appliance or HVAC system is not automatically providing a grid service just because it is connected. Its contribution depends on whether it can respond to a program or price signal, whether the relevant service is needed, and whether performance is measured and compensated.
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In particular, the V2G estimate is a conditional fleet-scale scenario, not a claim that an ordinary EV and charger can send electricity back to the grid. It does not establish what an individual owner could earn or save.
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