This article is the second installment in our V2G Value Series. The first focused on benefits beyond the grid—household resilience (e.g., V2H backup) and lowering the total cost of EV ownership. Here, we map grid-facing value into three categories: behind‑the‑meter optimization, avoided cost-based programs, and market participation.

Three-Part Framework for V2G Value

As interest in vehicle-to-grid (V2G) and bidirectional charging continues to grow, one of the persistent challenges is explaining exactly where the value comes from. Stakeholders often talk past one another because “value” can mean very different things depending on perspective. For regulators and utilities, it may be about avoided costs or market efficiencies. For customers, it’s often about managing their energy bills.

To clarify the discussion, it’s useful to organize V2G grid value into three categories: behind-the-meter optimization, programs based on administratively set avoided costs, and market participation (see table below). Each plays a role in shaping the future of V2G, though they vary widely in consumer accessibility and alignment with system needs. For regulators, such a framework is critical to ensure that value streams can be stacked without the risk of double compensation — a necessary step to accelerate approval and scaling of V2G programs.

Value Category	Description	Use Cases
Behind-the-Meter (V2B Optimization)	Customer-side savings based on utility tariffs; tied to legacy cost structures rather than real-time grid needs. Focused on vehicle to building (V2B/V2H); no value for exports.	Demand charge management, TOU arbitrage, solar self-consumption.
Avoided Cost (Administratively Set Grid Values)	Values set by regulators/utilities based on forecasts of future energy market prices and infrastructure investments.	Cost-effectiveness screening for efficiency and DR programs; compensation for BTM exports.
Market Value (Wholesale & Local Markets)	Direct participation in organized markets (ISO/RTO and local flexibility); limited mostly to managed charging (V1G) today.	Curtailment during high-priced energy hours or other bulk system constraints, frequency regulation pilots, and some EU countries’ local flexibility markets.

1. Behind-the-Meter (V2B/V2H Optimization)

This is the most immediate and intuitive source of value. With V2B technology, EVs can act as flexible energy assets at a customer site, charging and discharging in ways that reduce energy costs. Common strategies include:

• Demand charge management – reducing peak demand to lower charges for commercial customers.
• Time-of-use (TOU) arbitrage – charging when rates are low, discharging when they’re high.
• Solar self-consumption – storing excess solar generation in an EV battery and displacing grid purchases later.

Importantly, this category is limited to the customer side of the meter. Under today’s tariffs, energy stored in an EV cannot typically be exported back to the grid for compensation. That makes V2B strictly a bill-management strategy, not a grid service.

It’s also critical to recognize that behind-the-meter optimization does not reflect real-time system values. Tariffs are built on legacy cost structures—averages of long-term costs—not actual grid conditions hour by hour. For example, when off-peak TOU rates begin, many EVs start charging simultaneously, creating a demand spike that saves customers money but can stress local distribution networks. In short, behind-the-meter value is customer-centric: useful for bill savings, but not always aligned with system needs.

Some utilities are experimenting with more market-informed dynamic rates to better align customer behavior with system needs, though these remain limited pilots rather than standard offerings. In California, the CPUC is developing the CALFUSE (California Flexible Unified Signal for Energy) model, which bases retail rates on day-ahead wholesale market prices to encourage more responsive load flexibility.¹ A handful of utilities elsewhere are also testing day-ahead hourly pricing programs that expose customers to varying rates each day, informed by wholesale forecasts.² These approaches represent a step closer to real-time alignment, but adoption challenges loom. Even traditional time-of-use (TOU) rates—available for years in many states—have seen relatively low enrollment. Customer appetite for more complex dynamic rates remains uncertain. And even where these pilots exist, they are still retail products shaped by market data—not direct participation in organized markets.

2. Avoided Cost (Administratively Determined)

The second category represents value streams that are administratively determined rather than market-based. Regulators set avoided cost values through formal proceedings, typically estimating what it would cost utilities to supply energy, capacity, or grid upgrades in the absence of customer-side resources. Utilities then capture these values by implementing cost-effective programs that compensate customers for actions that help avoid those costs.

This framework traces to PURPA (1978), which required utilities to purchase from qualifying facilities at their avoided cost—the marginal cost of the next‑best resource. Regulators later adapted that same construct to demand-side resources: the benefits of an efficiency portfolio are the avoided utility-system costs (energy and capacity, transmission and distribution, line losses, and sometimes emissions), discounted over measure lives, compared against program costs. Under the Total Resource Cost (TRC) test—the most common cost-effectiveness screen—participant costs are also included.

More recently, California adopted the Net Billing Tariff (NBT) for rooftop solar, which credits exported energy not at retail rates but at avoided cost values that vary by time and location._³ This method provides a signal more precise than legacy retail rates, but still based on forecasts and administrative judgment rather than real-time grid conditions. The level of avoided cost compensation directly shapes customer participation—higher values attract adoption and deliver more grid-edge flexibility, while lower values may limit program effectiveness.

For V2G, avoided cost shows up most clearly in utility demand response and battery incentive programs. In Massachusetts and Rhode Island, utilities such as National Grid and Eversource run Connected Solutions programs that pay customers for peak reductions during the summer months. These programs are explicitly judged against avoided cost: if the total cost of the program—including customer incentives and administration—exceeds the estimated avoided costs, regulators would deem it not cost-effective and the program would be revised or ended.

Although avoided costs are set administratively, many programs now weave in market dynamics. In ISO-NE, demand response events are triggered by system peaks, tying customer actions directly to wholesale market conditions. In PJM, demand response clears in the capacity market, helping utilities meet resource adequacy obligations while lowering clearing prices. In California, the Avoided Cost Calculator embeds historical wholesale energy prices to produce time- and location-specific values. Together, these hybrid approaches blur the boundary between administratively set avoided costs and true market participation.

3. Market Value (Wholesale and Local Market Participation)

The third category involves direct participation in organized markets—wholesale markets run by Independent System Operators and Regional Transmission Operators (ISOs/RTOs) and local flexibility markets. In principle, aggregated EVs could directly compete in these markets, providing services such as frequency regulation, capacity, and local reliability alongside traditional resources.

In the U.S., demand response resources have participated in wholesale markets for more than a decade. Large commercial and industrial loads, and later aggregated resources, have provided capacity and ancillary services in markets such as PJM and ISO New England (NE). EVs, however, are only just beginning to enter this space. At present, most EV “market” activity is limited to managed charging (curtailment)—reducing load during high-price or high-stress system periods. This aligns with wholesale energy market conditions but falls short of full bidirectional participation.

FERC Order 2222 is important here because it expands wholesale market access for aggregations of smaller DERs, including EVs, beyond the large-scale demand response resources that already participate. Implementation, however, is uneven across regions. California ISO and ISO-NE have aggregation pathways already underway, New York ISO is developing its model but has set a longer compliance horizon, and PJM has received approval to delay full implementation until 2028. This means that the opportunities for EV aggregations to participate in wholesale markets will vary significantly depending on geography for the foreseeable future.

True V2G exports into wholesale markets remain confined to pilots and demonstrations—for example, the University of Delaware project that provided frequency regulation in PJM, and more recent school bus V2G demonstrations.⁴ These prove technical feasibility but underscore the regulatory, interconnection, and performance barriers that prevent widespread participation.

At the distribution level, the U.S. has historically lacked formal flexibility markets, relying instead on non-wires alternatives (NWA) solicitations to defer or avoid grid upgrades, as seen in California’s Distribution Investment Deferral Framework and New York’s DSIP-based procurements. These solicitations are structured, project-specific procurements rather than open markets, which limits participation. That picture is now beginning to shift: utilities such as National Grid in New York and Eversource (United Illuminating) in Connecticut are piloting local flexibility marketplaces through partnerships with Piclo, offering DER owners and aggregators new opportunities to compete to provide grid services. These early efforts signal a gradual U.S. move toward distribution-level flexibility markets, bringing practice closer to the European model.

By contrast, Europe is further ahead. In the UK, distribution system operators (DSOs) procure flexibility through recurring tenders, often run via the Piclo platform.⁶ In the Netherlands, the GOPACS (Grid Operators Platform for Congestion Solutions) platform coordinates congestion management by linking DSO (distribution system operator) and TSO (transmission system operator) needs through market trades.⁷ These efforts create continuous opportunities for EVs and aggregators to deliver value both at the bulk system and local levels.

Unlike behind-the-meter and avoided cost approaches, market participation offers transparent, dynamic price signals that directly align EV charging and discharging with system needs. Unlocking this value in the U.S. will require reducing barriers to EV aggregation under existing wholesale rules, completing uneven Order 2222 implementation, and piloting true local flexibility markets modeled on European experience.

Building Consensus on V2G Value

Reaching consensus on how to value bidirectional charging requires recognizing both the promise and the limits of existing approaches. Behind-the-meter optimization demonstrates clear customer savings but does not fully reflect real-time grid needs. Avoided-cost programs capture system benefits but rely on administrative values that may under- or overstate the true worth of flexibility. Market participation most directly aligns EV charging and discharging with grid conditions, yet access today remains narrow and highly constrained.

For policymakers and utilities, the task is to reconcile these pathways into a coherent framework—one that rewards customers fairly while capturing system benefits without overlap or double counting. With thoughtful program and market design, consensus on value can accelerate V2G’s evolution from limited pilots into a meaningful contributor to a cleaner, more resilient grid.

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1. See California Public Utilities Commission, Advanced Strategies for Demand Flexibility Management and Customer DER Compensation available at https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/demand-response/demand-response-workshops/advanced-der—demand-flexibility-management/ed-white-paper—advanced-strategies-for-demand-flexibility-management.pdf.
2. See ComEd, ComEd’s Hourly Pricing can help you save money while contributing to a cleaner tomorrow, available at https://hourlypricing.comed.com/ and Utility Dive, New York approves ‘innovative’ Con Edison pricing pilot with dual recruitment strategies, available at https://www.utilitydive.com/news/new-york-approves-innovative-conedison-pricing-pilot-with-dual-recruitmen/544503/.
3. See Canary Media, The avoided-cost calculator: The controversial metric at the center of California’s solar net-metering fight, available at https://www.canarymedia.com/articles/policy-regulation/the-avoided-cost-calculator-the-controversial-metric-at-the-center-of-californias-solar-net-metering-fight.
4. See University of Delaware, A Test of Vehicle-to-Grid (V2G) for Energy Storage and Frequency Regulation in the PJM System, available at https://www1.udel.edu/V2G/resources/test-v2g-in-pjm-jan09.pdf.
5. See National Grid, Piclo and National Grid launch new marketplace for flexibility services in New York state, available at https://www.nationalgridus.com/News/2022/12/Piclo-and-National-Grid-launch-new-marketplace-for-flexibility-services-in-New-York-state/ and Piclo, Eversource and United Illuminating launch New England’s first grid flexibility marketplace for winter 2024-25 with Piclo, available at https://www.piclo.energy/press-releases/eversource-and-united-illuminating-launch-new-englands-first-grid-flexibility-marketplace-for-winter-2024-25-with-piclo.
6. See Piclo, The independent marketplace for energy flexibility, available at https://www.piclo.energy/.
7. See GOPACS, Congestion Management, flexibility creates space, available at https://www.gopacs.eu/en/.

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