A fleet operator wants to install 50 bidirectional EV chargers—not just to charge vehicles, but to send power back to the building and grid during peak hours. The utility reviews both sides of the request: the service connection to draw power, and the interconnection to export it. The verdict: wait three years for a $2 million transformer upgrade! This has been a real challenge for V2G projects, slowing both electrification and the grid services and resiliency these systems could provide. But there’s a better way forward—one that’s already taking shape in leading states and utility territories.
The Grid Connections Dilemma
As vehicle-to-grid (V2G) technology edges closer to mainstream adoption, one of the least understood hurdles is grid connection—which has two sides: service connections for imports (when a customer or DER draws electricity from the grid) and interconnections for exports (when a DER sends power back). These rules of the road determine how distributed energy resources (DERs)—from rooftop solar to battery storage to bidirectional EVs—connect safely and reliably. For V2G in particular, they govern not just whether a car can charge, but whether it can legally and technically discharge energy back to buildings and the grid.
For decades, both imports and exports have been treated rigidly. Utilities typically assume that a project might operate at full capacity during the most constrained hours of the year—whether that’s peak demand, when feeders are stressed by heavy customer loads, or minimum demand, when excess generation risks backfeeding through substations and creating voltage or protection issues. If either scenario could pose a problem, the project is often told to wait—sometimes for years—until costly upgrades are built.
This worst-case planning approach wasn’t simply conservative—it reflected a fundamental reality of traditional grid operations: utilities had virtually no control over how customers used electricity. They had to build infrastructure capable of handling everything that might be needed, whenever it might be needed, because customers could turn on any appliance at any time. While load diversity calculations allowed some statistical refinement, and utilities could offer price signals through rate structures to encourage off-peak usage, these remained just that—signals that customers were free to ignore. Without direct control over loads, planning for the worst-case scenario (often with an additional buffer) was the only way to ensure reliability.
That conservative approach may have made sense in a slower-moving energy system. But today, with electrification surging and clean energy adoption accelerating, the ability to dynamically manage both imports and exports has become essential. Flexible grid connections—systems that allow projects to connect quickly by using smart controls to limit imports or exports only during constrained hours—offer a path forward.
Service Connections: The Rigid Math
When a customer requests a new or expanded electric service—say, to support a bank of EV chargers—the utility evaluates the request using nameplate capacity. If a depot proposes five 150-kW DC fast chargers, the utility assumes a peak demand of 750 kW, all happening at once. Even if the site expects to stagger charging or deploy smart scheduling, planners must design for the worst case.
If the local system can’t deliver that much power, the utility specifies upgrades—new transformers, feeder reinforcements, even substation reconfiguration—and a timeline that can stretch many months or years. This “build to nameplate” approach guarantees reliability, which is paramount: utilities must keep the lights on above all else, even before considerations of cost or efficiency. For the traditional grid—where utilities had no ability to control or communicate with customer loads—this approach made perfect sense and served the system well. It delays projects and overbuilds capacity that may rarely be used, but it ensured that the grid could meet any possible demand scenario.
The State of V2G Interconnection
The regulatory landscape for V2G is evolving rapidly, with several states showing how existing frameworks can accommodate bidirectional charging—and in some cases, establishing new standards entirely.
In July 2025, Maryland became the first state in the country to adopt a comprehensive set of interconnection rules for vehicle-to-everything (V2X). These rules, developed under the state’s DRIVE Act, establish clear interconnection procedures for both DC and AC bidirectional charging systems—giving V2G projects a clear regulatory path to interconnection and the certainty they will be able to operate in Maryland for the first time.
- V2G-DC systems (where the charger houses the inverter) are treated like stationary storage, a familiar category for utilities.
- V2G-AC systems (where the vehicle houses the inverter) now have two approved pathways:
- Option 1: A charger certified to UL 1741 SC paired with a vehicle designed to SAE J3072.
- Option 2: A combined charger–vehicle system certified to UL 1741 SB as a composite DER.
Backup-only systems, where bidirectional charging is used strictly in islanded mode to power a home during an outage, are not subject to lengthy interconnection review; instead, customers simply notify the utility, much as they would with a standby generator. Another pathway is to install chargers in load-only mode initially so the devices can be used to charge EVs and then apply for interconnection later when they are ready to activate bidirectional functionality.
California’s Rule 21 remains the most influential interconnection standard in the U.S. The Rule was adjusted to accommodate V2G-DC by treating the technology as energy storage for purposes of interconnection, though more work is needed to establish clear pathways for AC systems. Elsewhere, states like Massachusetts and New York have approved interconnections for bidirectional chargers under their existing storage frameworks. These examples show that new regulations aren’t always necessary—if regulators interpret current rules flexibly.
The challenge, particularly for V2G-AC, is the “mobile inverter” question: rules designed for stationary equipment simply don’t fit when the grid-interactive inverter is inside a car that can plug in at different sites. As we explored in our previous article on V2G AC vs. DC, this creates fundamental regulatory challenges around how to certify, track, and ensure compliance for equipment that moves between locations.
Underpinning all these regulatory approaches are technical standards that govern safe grid interaction: IEEE 1547 establishes baseline inverter functions such as voltage ride-through and frequency response; UL 1741 provides certification for grid-interactive inverters, controllers, and interconnection equipment to demonstrate compliance with IEEE 1547 requirements; UL 9741 specifically addresses bidirectional EV charging equipment and how UL 1741 applies; and Supplement B to UL 1741 aligns testing with the more advanced smart inverter functionalities described in IEEE 1547-2018, while UL 1741 Supplement C is being developed to address V2G-AC systems with requirements and functionalities placed in both the EV and the EVSE.
The Next Frontier: Flexible Connections
These service connection and interconnection approaches have ensured safety and reliability, but they were designed for a grid where utilities had no control over when or how electricity was used. Now, with technologies that can respond to grid conditions, the opportunity is to make both service connections and interconnection itself adaptive—allowing projects to move forward rather than waiting years for upgrades that address constraints occurring only a few hours annually, while still protecting system reliability.
Flexible service connections allow customers to energize new loads (like EV depots) more quickly by limiting connection size only during grid-constrained hours. This requires a certified Power Control System (PCS) or equivalent energy management system to enforce these limits while still allowing sites to operate effectively. UL 3141, the standard specifically developed for Power Control Systems, provides the certification pathway referenced by utilities and regulators in California and beyond.
On the export side, flexible interconnections allow DERs that export power to buildings or the distribution system to connect without waiting for upgrades. Instead of blocking projects entirely, utilities contractually agree to allow exports most of the time, but curtail or limit them during periods of local constraint. Pilots in New York and Massachusetts show that curtailments are far less frequent than predicted, supporting scalable deployment.1
In both cases, flexibility transforms a rigid “no” into a conditional “yes,” protecting reliability while accelerating electrification.
Why Flexibility Matters
Grid constraints appear not just at peak demand but also at minimum load. Under static rules, even a handful of risky hours per year can block a project entirely. Flexible connections let software controls and certified PCS devices cap imports or exports only when needed, unlocking far more capacity from existing wires.
This is where V2G shines: EV batteries can absorb energy when the grid has headroom and export when it needs support—standing down only during those hours when doing so would create problems.
Utilities are beginning to operationalize these ideas:
- PG&E Flex Connect – as-available service connections for EV hubs, with load caps enforced by PCS.
- Flexible interconnection pilots in NY/MA/CA/CO – using certified PCS, with response requirements like ≤2-second open-loop control under Rule 21.
- DOE synthesis – federal briefings highlight emerging architectures for utility-controlled DER/EV curtailment and show real-world curtailments are rare.
The Path Forward
The foundation for safe V2G interconnection is now in place, thanks to established technical standards and evolving utility practices. The real opportunity ahead is to move beyond static rules and embrace flexibility—pairing proven interconnection pathways with flexible service connections and flexible interconnections, anchored by certified PCS controls. This approach enables projects to connect sooner, utilize existing infrastructure more effectively, and provide grid support most of the time, while scaling electrification without waiting years for costly upgrades.
For policymakers and regulators: Look to Maryland, California, and other leading states as models. Flexible connection rules can be adopted through existing frameworks—new legislation isn’t always necessary.
For utilities: Pilot programs like PG&E Flex Connect show that service connection flexibility works in practice. Flexible interconnection pilot curtailment data consistently shows that constraints are rarer than worst-case planning assumes.
For fleet operators and site developers: Don’t let rigid grid connection rules stop your project. Ask your utility about flexible connection options that use certified PCS systems to manage imports and exports during constrained hours—this can help you energize your site sooner and generate revenue providing grid services to lower the total cost of ownership.
The technology is ready. The standards are maturing. Now it’s time to make the grid connections as flexible as the resources we’re trying to connect.
Note: The author would like to thank Jackie Piero, US Head of Policy & Regulatory at the Mobility House, for her review and helpful comments on an earlier draft. Any remaining errors or omissions are the sole responsibility of the author.
1A flexible interconnection pilot in New York state reduced interconnection costs for one community solar project by $5.95M and its connection time by at least 3 years by avoiding a major substation upgrade, and resulted in limited curtailment estimated to be 1.3%.
