PG&E expands bidirectional EV grid programme

Pacific Gas and Electric Company has expanded its Vehicle-to-Everything programme, adding bidirectional charging partners and new vehicle combinations capable of providing home backup power and, where programme conditions permit, exporting electricity to the California grid.

Bidirectional Energy and PowerFlex have joined the programme as approved partners, widening an ecosystem that already includes vehicle manufacturers, charger suppliers, and software providers. PG&E has also added eligible models from Kia, Volvo, Polestar, Nissan, and General Motors alongside existing options involving Ford, GM, and Tesla vehicles.

New combinations include the 2018–2025 Nissan Leaf, 2025 Volvo EX90, and 2025 Polestar 3 with the dcbel Ara charger. Kia EV9 models from 2024 onwards and EV6 models from 2025 onwards can use the Wallbox Quasar 2, while the Chevrolet Bolt, Cadillac Celestiq, and Cadillac Escalade IQL have joined the General Motors options.

The expanded list does not mean every vehicle can provide every V2X function with any charger. PG&E states that capabilities vary by vehicle-and-charger combination, reflecting one of the central technical problems facing bidirectional charging: compatibility has to extend across the vehicle, charger, building electrical installation, communications system, and utility interconnection.

Compatibility reaches beyond the charging connector

Vehicle-to-Everything is a broad term covering several operating modes. Vehicle-to-home can use the traction battery to supply a property during an outage or selected high-price periods, while vehicle-to-grid adds controlled export through the utility connection. Conventional managed charging performs a different function again by altering when the vehicle draws power without discharging its battery back into the electrical system.

Each mode creates different protection and control requirements. A vehicle supplying a home during an outage must not energise utility conductors that are expected to be isolated, while grid export requires an approved interconnection arrangement, suitable protection, and controls that keep voltage, frequency, and power flow within permitted limits.

PG&E’s programme requires participating systems to use eligible equipment and, for grid-connected operation, meet the utility’s interconnection requirements. Customers are therefore installing a small distributed-energy system rather than simply replacing a one-way charger with hardware capable of reversing current.

The cost reflects that difference. PG&E is offering residential customers a $2,500 upfront incentive, rising to $3,000 for customers in disadvantaged communities, plus a $1,500 early-adopter payment for the first 250 enrolments. Some newly approved combinations can qualify for up to $13,000 of additional California Energy Commission-backed support, subject to separate eligibility requirements.

That funding can cover part of the premium associated with bidirectional equipment, controls, electrical alterations, and interconnection work. The commercial case otherwise depends on how frequently backup capability is valued, the difference between charging and discharge prices, available grid-service payments, and the amount of battery capacity the vehicle owner is prepared to make available.

Home resilience is the most direct proposition because the benefit belongs to the customer at the point of an outage. Grid support is more demanding: an individual EV exporting a few kilowatts makes little difference to a large power system unless many vehicles can be aggregated, controlled, and relied upon to respond together.

Aggregation determines grid value

The software layer therefore matters as much as the charger. Bidirectional Energy specialises in connecting vehicles, bidirectional equipment, and utility programmes, while PowerFlex manages a large US charging estate. Their addition gives PG&E more routes to coordinate systems from different manufacturers rather than building the pilot around one vertically integrated hardware combination.

That approach mirrors a wider move towards EVs as controllable grid-edge assets. Finnish distribution-network trials involving 150 EV drivers have already examined whether aggregated residential charging can be started and stopped together to support local network operation, although bidirectional export introduces an additional level of electrical and customer complexity.

Availability is one of the harder variables. EV batteries may spend much of their lives parked, but that does not mean they are always plugged in, sufficiently charged, or available to discharge. Drivers still expect the vehicle to meet its primary purpose, and participation has to preserve whatever minimum state of charge the owner requires for the next journey.

A useful V2X platform therefore has to forecast and aggregate a resource whose availability changes continually. Utilities need to know how many kilowatts can be delivered, for how long, and with what confidence before vehicle batteries can be treated alongside stationary storage or conventional demand response.

PG&E has already extended bidirectional work beyond passenger cars through electric school-bus projects in Fremont, Oakland, and San Francisco. Fleet vehicles offer potentially useful characteristics because their routes and depot schedules can be more predictable than residential driving patterns, while centralised charging allows larger blocks of capacity to be managed at one site.

Residential V2X offers a larger potential population but a less predictable one. Connection times, battery sizes, customer preferences, driving patterns, and charger ratings vary widely, meaning the aggregate response has to be built from thousands of relatively small resources.

Transport electrification consequently creates two competing effects for distribution systems. Uncontrolled charging can add new evening or localised peaks, while managed charging can move demand into quieter periods; bidirectional systems add the possibility of returning electricity when the network or wider power system is under greater pressure.

That flexibility can reduce some reinforcement requirements at particular times and locations, but it does not remove physical network limits. Feeders, transformers, protection systems, and substations still have finite ratings, while vehicle availability can never be guaranteed in the same way as a dedicated grid asset whose only purpose is electricity storage.

PG&E’s current programme remains a route for testing those boundaries rather than evidence that residential EVs have already become a large dispatchable power station. Enrolment remains open until 30 June 2027, giving the utility additional time to build the installed base and gather operating data across a broader selection of hardware.

The useful measure will be less glamorous than the number of compatible vehicle models: how many bidirectional systems are actually commissioned, how reliably they respond when required, and how much controllable capacity remains available after drivers have reserved the energy they need to get home again.