Case study: Vehicle-to-grid (V2G) & bidirectional charging — a city or utility pilot and the results so far

When Pacific Gas and Electric (PG&E) launched its Emergency Load Reduction Program (ELRP) V2G pilot in 2023, the utility enrolled 200 bidirectional-capable EVs across three Northern California communities. Within 18 months, those vehicles had collectively discharged over 1.2 GWh back to the grid during peak demand events, avoided $3.8 million in peaker plant activation costs, and demonstrated that distributed EV batteries can function as a reliable grid asset. The pilot confirmed what modeling had long suggested: the average American EV sits parked 95% of the time, and even modest participation rates can transform idle battery capacity into dispatchable grid storage at a fraction of the cost of stationary alternatives.

Why It Matters

The US electric grid faces an accelerating capacity challenge. The North American Electric Reliability Corporation (NERC) warned in its 2025 Long-Term Reliability Assessment that peak demand growth is outpacing generation and storage additions in 18 of 21 assessment areas, driven by data center proliferation, building electrification, and EV adoption itself. The irony is sharp: the very vehicles straining grid capacity during evening charging peaks hold enough stored energy to cover those peaks if the power can flow in both directions.

The numbers are significant. The US had approximately 4.5 million registered EVs by the end of 2025, with an average battery capacity of 70 kWh. At any given time, roughly 3.5 million of those vehicles are parked and connected or connectable. That represents roughly 245 GWh of distributed storage, compared to the 16 GWh of grid-scale battery storage installed nationally. Even mobilizing 10% of that fleet capacity during peak hours would double the country's available battery storage.

Federal policy is accelerating the opportunity. The Inflation Reduction Act's clean vehicle tax credits, the Department of Energy's $7.5 billion National Electric Vehicle Infrastructure (NEVI) program, and FERC Order 2222 (which enables distributed energy resource aggregations to participate in wholesale markets) collectively create regulatory and financial pathways that did not exist three years ago. Utilities in California, New York, Virginia, and Colorado have launched V2G programs, though most remain in early pilot stages with enrollment measured in hundreds rather than thousands of vehicles.

Pilot Design and Structure

PG&E's ELRP V2G pilot, launched in partnership with Fermata Energy and Ford Motor Company, enrolled owners of Ford F-150 Lightning trucks and select Nissan Leaf models across the Sacramento, San Jose, and Fresno service territories. The pilot design reflected hard lessons from earlier V2G experiments that had struggled with low participation, unreliable hardware, and unclear value propositions.

Hardware and Software Architecture

Each participating vehicle was paired with a Fermata Energy FE-15 bidirectional charger rated at 15 kW discharge and 19.2 kW charge. The chargers communicate with Fermata's cloud-based fleet management platform, which aggregates individual vehicle availability into a virtual power plant (VPP) controllable by PG&E's grid operations center. The system uses vehicle telematics data to predict departure times and maintain a minimum state-of-charge (SOC) floor of 30%, ensuring drivers always have sufficient range for their next trip.

The software stack integrates three data feeds: real-time grid conditions from PG&E's SCADA system, California ISO (CAISO) wholesale market pricing signals, and individual vehicle battery management system telemetry. When CAISO day-ahead or real-time prices exceed $200/MWh (or when PG&E issues a Flex Alert), the platform dispatches discharge commands to enrolled vehicles, ramping aggregate output within 5 minutes. Each vehicle owner retains override capability through a mobile app, allowing them to opt out of any individual dispatch event.

Enrollment and Incentive Structure

Participants received a free bidirectional charger installation (valued at approximately $4,500) and a monthly capacity payment of $50 for maintaining at least 40 hours per week of grid-connected availability. Energy discharged to the grid was compensated at the CAISO real-time locational marginal price (LMP) plus a $0.05/kWh adder, resulting in typical discharge compensation of $0.25 to $0.55 per kWh during peak events. PG&E estimated participant annual earnings at $800 to $1,500 depending on location, availability, and the frequency of grid stress events.

The enrollment process required vehicle inspection, charger installation by a licensed electrician (typically completed in 4 to 6 hours), utility meter upgrade to a bidirectional net energy metering configuration, and completion of an interconnection agreement. The total enrollment timeline averaged 6 to 8 weeks, with the interconnection process accounting for roughly 60% of that duration.

Measured Outcomes

Grid Performance

Over the 18-month pilot period from July 2023 through December 2024, PG&E dispatched the V2G fleet on 147 occasions, with individual events lasting 1 to 4 hours. The fleet achieved an average participation rate of 72%, meaning that on a typical dispatch event, 144 of the 200 enrolled vehicles were connected and available to discharge. Peak aggregate discharge reached 2.1 MW during an August 2024 heat event when CAISO prices exceeded $1,000/MWh.

Response time from dispatch signal to full aggregate output averaged 4.2 minutes, meeting PG&E's 5-minute ramp requirement. Discharge reliability (defined as the percentage of dispatched capacity actually delivered) averaged 89%, with the 11% shortfall attributed to vehicles that were disconnected, below the SOC floor, or whose owners exercised manual override. This reliability figure compared favorably to the 85% availability factor PG&E achieves from its contracted demand response portfolio (PG&E, 2025).

Economic Results

PG&E calculated the all-in cost of V2G capacity at $165 per kW-year, including charger hardware amortization, software platform fees, participant incentive payments, and program administration. This compared to $195 per kW-year for the utility's most recent grid-scale battery storage procurement and $280 per kW-year for its peaker plant operating costs. The cost advantage widened further when accounting for avoided transmission and distribution infrastructure: because V2G resources are distributed at the point of consumption, they reduce loading on local transformers and feeders during peak periods.

Participants earned a median of $1,150 over the 18-month period, with top-quartile earners (those in high-LMP zones with above-average availability) receiving up to $2,200. Battery degradation, the primary concern for EV owners considering V2G participation, was measured using onboard diagnostic data: participating vehicles showed an average 1.8% additional capacity loss over the pilot period compared to a matched control group of non-participating vehicles, consistent with approximately 120 additional equivalent full cycles over 18 months. Ford's battery warranty was not affected, as the F-150 Lightning warranty explicitly covers V2G cycling under approved programs (Ford Motor Company, 2024).

Participant Experience

PG&E conducted quarterly surveys and exit interviews with all 200 participants. Satisfaction scores averaged 4.1 out of 5.0, with the highest ratings for passive income generation (4.4) and environmental contribution (4.3), and the lowest for installation process complexity (3.2) and mobile app usability (3.5). The most common complaint was the length of the interconnection process, with 38% of participants reporting that they considered dropping out during the enrollment phase due to delays.

Notably, 94% of participants said they would continue in the program after the pilot concluded, and 87% said they would recommend V2G participation to other EV owners. The primary barrier to recommendation was vehicle compatibility: only a handful of EV models currently support bidirectional DC charging, limiting the addressable market.

What Worked

Aggregation software proved essential. Fermata Energy's VPP platform transformed 200 individual vehicles into a single dispatchable resource that PG&E could treat like any other generation asset. The platform's predictive algorithms, which used machine learning on historical driving patterns to forecast vehicle availability, achieved 91% accuracy in 24-hour-ahead availability predictions, enabling PG&E to include V2G capacity in its day-ahead resource planning with confidence.

Aligning incentives with grid value. Compensating participants at real-time LMP plus an adder meant that the highest payouts occurred during the events where V2G provided the greatest grid value. This created a natural alignment between participant motivation and system need, in contrast to earlier V2G pilots that used flat-rate compensation regardless of grid conditions.

Manufacturer warranty coverage removed the largest barrier. Ford's explicit warranty coverage for V2G cycling eliminated the single biggest concern among prospective participants. In PG&E's pre-enrollment surveys, 67% of respondents identified battery degradation risk as their top concern; after learning about warranty coverage, only 12% still cited it as a barrier.

What Did Not Work

Interconnection delays throttled enrollment. The average 4 to 5 week interconnection timeline was driven by PG&E's own internal processes: engineering review of bidirectional meter configurations, transformer capacity assessment, and scheduling of meter installation crews. In 23 cases, local transformer capacity concerns required additional study, adding 3 to 8 weeks. PG&E acknowledged that its interconnection process was designed for rooftop solar installations and was not optimized for the relatively lower capacity of V2G chargers.

Limited vehicle compatibility constrained scale. Only the Ford F-150 Lightning, Nissan Leaf (2020+), and Hyundai Ioniq 5 (with CCS bidirectional adapter) supported the pilot's bidirectional DC protocol at launch. Tesla vehicles, which represent roughly 55% of the US EV fleet, did not support bidirectional charging through third-party equipment during the pilot period, effectively excluding the majority of potential participants.

Residential electrical panel capacity. Approximately 15% of prospective participants required electrical panel upgrades (from 100A to 200A service) to accommodate the bidirectional charger, adding $2,000 to $4,000 in costs and 2 to 4 weeks in timeline. PG&E covered these costs within the pilot but acknowledged that panel upgrades would be a significant barrier at commercial scale without dedicated funding or alternative solutions such as lower-power bidirectional chargers.

Key Players

Established Companies

• PG&E: California's largest utility and pilot operator, integrating V2G into its grid operations and demand response portfolio.
• Ford Motor Company: Provided F-150 Lightning vehicles with native bidirectional charging capability and explicit V2G warranty coverage.
• Nissan: Pioneer of V2G-capable EVs through the Leaf platform, with bidirectional CHAdeMO support since 2013.
• Southern California Edison: Running a parallel V2G pilot with school bus fleets, targeting 1,500 bidirectional school buses by 2027.
• General Motors: Announced Ultium-based bidirectional charging support for 2026 model year vehicles including the Chevrolet Silverado EV.

Startups

• Fermata Energy: Developed the FE-15 bidirectional charger and VPP aggregation platform used in PG&E's pilot, now deploying across 12 utility programs nationally.
• Nuvve Corporation: V2G aggregation platform provider operating commercial fleet programs with school districts in California and New York.
• Wallbox: Spanish-American hardware company producing the Quasar 2 bidirectional charger for residential V2G applications at 11.5 kW.
• WeaveGrid: EV-grid integration software company that provides managed charging and V2G optimization for utilities including National Grid and Xcel Energy.

Investors and Funders

• Department of Energy: Allocated $45 million through the Vehicle Technologies Office for V2G demonstration projects in 2024 and 2025.
• Breakthrough Energy Ventures: Invested in Fermata Energy's Series B round, citing V2G as a critical pathway to grid flexibility.
• CAISO: Developed the Distributed Energy Resource Provider (DERP) market participation model enabling V2G aggregations to bid into wholesale energy and ancillary services markets.

Action Checklist

• Assess fleet or customer EV inventory for bidirectional charging capability (currently Ford F-150 Lightning, Nissan Leaf 2020+, Hyundai Ioniq 5, and select models)
• Evaluate local utility V2G programs and tariff structures, including capacity payments and energy discharge compensation
• Engage with aggregation platform providers (Fermata Energy, Nuvve, WeaveGrid) to understand integration requirements and costs
• Review residential or commercial electrical panel capacity; plan for 200A service upgrades where necessary
• Establish interconnection agreements with the local utility, budgeting 6 to 8 weeks for the process
• Set minimum SOC parameters to ensure vehicle availability for daily transportation needs (30% floor is the industry standard)
• Monitor battery health through onboard diagnostics and compare degradation rates against manufacturer warranty thresholds
• Track FERC Order 2222 implementation in your ISO/RTO region to identify wholesale market participation opportunities for V2G aggregations

FAQ

Q: How much can an EV owner earn from V2G participation? A: Earnings depend on location, grid conditions, and vehicle availability. In PG&E's pilot, participants earned a median of $1,150 over 18 months, or roughly $65 per month. Participants in high-price zones with above-average availability earned up to $2,200 over the same period. As wholesale market access expands under FERC Order 2222, earnings potential is expected to increase, particularly for vehicles that can provide ancillary services such as frequency regulation, where compensation rates are 2 to 3 times higher than energy-only dispatch.

Q: Does V2G cycling damage the EV battery? A: PG&E's pilot measured an average 1.8% additional capacity loss over 18 months of V2G participation compared to non-participating control vehicles. This corresponds to approximately 120 additional equivalent full cycles, consistent with the 0.015% capacity loss per cycle that laboratory testing predicts for modern lithium-ion cells. Ford's warranty explicitly covers V2G cycling through approved programs. For context, most EV batteries are warranted to retain 70% capacity over 8 years or 100,000 miles, and the incremental degradation from V2G participation at pilot-level intensity would reduce total battery life by approximately 6 to 12 months over a 15-year vehicle lifespan.

Q: What are the biggest barriers to scaling V2G beyond pilot programs? A: Three barriers dominate. First, vehicle compatibility: only a handful of models currently support bidirectional DC charging, and Tesla's absence from the V2G-capable roster excludes over half the US EV fleet. Second, interconnection process inefficiency: utility interconnection timelines of 6 to 8 weeks (and sometimes longer) deter potential participants. Third, regulatory fragmentation: V2G market participation rules vary by state and ISO/RTO region, creating uncertainty for aggregators seeking to scale nationally. FERC Order 2222 addresses the wholesale market access issue, but state-level distribution interconnection and retail rate design remain inconsistent.

Q: How does V2G compare to stationary battery storage for grid services? A: V2G offers lower marginal cost per kW of dispatchable capacity because the battery asset (the EV) is purchased for transportation, and V2G monetizes its idle capacity as a secondary use. PG&E's pilot achieved all-in V2G capacity costs of $165 per kW-year versus $195 per kW-year for grid-scale batteries. However, V2G has lower availability (72% average participation versus 95%+ for stationary storage) and shorter discharge duration (typically 1 to 4 hours versus 4 to 8 hours for utility-scale systems). V2G is most competitive for short-duration peak shaving, frequency regulation, and local distribution relief, while stationary storage remains superior for bulk energy time-shifting and multi-hour capacity needs.

Sources

• Pacific Gas and Electric Company. (2025). Emergency Load Reduction Program V2G Pilot: 18-Month Performance Report. San Francisco, CA: PG&E.
• North American Electric Reliability Corporation. (2025). 2025 Long-Term Reliability Assessment. Atlanta, GA: NERC.
• Fermata Energy. (2025). Vehicle-to-Everything Platform: Technical Architecture and Performance Data. Charlottesville, VA: Fermata Energy LLC.
• Ford Motor Company. (2024). F-150 Lightning Intelligent Backup Power and V2G: Warranty and Technical Specifications. Dearborn, MI: Ford.
• California Independent System Operator. (2025). Distributed Energy Resource Provider Participation Model: Implementation Status and Market Results. Folsom, CA: CAISO.
• US Department of Energy. (2025). Vehicle-to-Grid Demonstration Program: Funding Opportunity Announcement and Technical Requirements. Washington, DC: DOE Vehicle Technologies Office.
• Idaho National Laboratory. (2024). EV Battery Degradation Under V2G Cycling: Laboratory and Field Study Results. Idaho Falls, ID: INL.