A distribution-connected battery of 20 megawatts (MW) or less in PJM can skip the transmission interconnection queue. It can interconnect through the utility, take a Wholesale Market Participation Agreement (WMPA), and capture the full wholesale revenue stack: energy, regulation, reserves, and capacity. That route takes months as opposed to nearly two years for a queued project.

A battery could also interconnect without a WMPA, but they would forego substantial revenue opportunity. A front-of-meter distributed battery could have earned $352 to $449 per kilowatt-year (kW-year) from wholesale markets in July 2025-2026. Over the same period, behind the meter BESS could have earned $55 to $231/kW-year. But regulation makes up 47 to 66% of that wholesale revenue, and PJM's regulation market is only 750 MW. As battery supply grows, that revenue erodes.

Key takeaways

• ​A distribution-connected battery below 69 kilovolts (kV) and 20 MW can interconnect through the utility and could apply for a WMPA. This allows BESS to reach PJM's wholesale markets without a transmission-queue position.
• Distributed BESS could receive interconnection approval in months while a transmission-queue project took nearly two years in PJM's first reformed cycle.
• Wholesale participation earns $352 to $449/kW-year, beating the $55 to $231/kW-year behind-the-meter alternative in every zone modeled.
• Only two PJM states will pay distributed batteries directly by the end of 2026: Illinois, through the CRGA rebate, which is currently in effect and New Jersey through the Garden State Energy Storage Program (GSESP).

Standalone distributed BESS capacity in PJM totals 198 MW across 28 front-of-meter projects

PJM's operating fleet of distributed BESS, which are connected front-of-meter, totals 198 MW in capacity across 28 sites.

​The fleet is short-duration, reflecting prior strategies focused on capturing PJM's regulation revenues instead of energy arbitrage. Projects are no larger than 20 MW, consistent with the Small Generating Facility threshold. Above 20 MW, a battery must connect via PJM's interconnection queue instead of a utility's process.

Two agreements replace the PJM interconnection queue process

​PJM sorts interconnections by nameplate capacity and voltage. A resource that interconnects below 69 kV and under 20 MW connects at distribution, not through PJM's transmission queue. Two separate agreements follow, including an interconnection agreement with a utility and a WMPA with PJM.

First, the battery signs a distribution interconnection agreement with the utility, under the interconnection rules of the state it sits in. That agreement covers the physical connection with varying requirements and timelines per utility.

Then PJM, not the utility, issues the WMPA. It carries no interconnection terms, and only lets the battery participate in wholesale energy markets, ancillary services, and capacity markets as an Electric Storage Resource. The floor to participate is 100 kilowatts (kW) with no upper bound.

The utility cannot refuse the connection outright. State interconnection rules require it to process the request without discrimination, similar to the rules governing rooftop solar system interconnection. But the utility sets the hosting-capacity limit, any export cap, and the cost of any distribution upgrades. The utilities assess these requirements case by case and additional upgrades or information can slow down project timelines.

​If there are minimal revisions, the premium for distributed BESS is time to market. A distribution battery can receive an interconnection approval in months while avoiding costly transmission network-upgrade charges. Queued transmission projects in PJM's first reformed cycle waited nearly two years for approval and paid $206 per kW, on average, for upgrades.

Wholesale participation earns up to $418/kW-year in Dominion, but new BESS risk saturating the market

​Modo Energy's virtual BESS (vBESS) benchmark can model a theoretical four-hour battery located at a particular PJM zone. For the year between July 2025 and July 2026, a Dominion-zone battery could have earned $362/kW-year from energy and ancillary services. Capacity added $87/kW-year, for a total of $449/kW-year.

That capacity blends the 2025/26 and 2026/27 delivery years, at a four-hour Effective Load Carrying Capability (ELCC) rating of 55% then 50%.

​Regulation is the largest single stream across the 3 zones, from 47% of total revenue in Dominion to 66% in ComEd. PJM's October 2025 redesign lifted prices for the regulation market.

However, the requirements were relatively stable across both sides of the October 2025 reform, holding near 750 MW. Operating BESS already totals 596 MW across PJM and Transition Cycle 1 currently holds 1.9 GW on track for commercial operation. As new supply saturates the market, the regulation price falls, reducing revenue for eligible BESS.

Behind-the-meter pays less for standalone BESS, and only where the tariff exposes a charge to shave

​A battery can forgo the PJM wholesale market and connect via a utility tariff or Power Purchase Agreement. A standalone BESS cannot participate in net metering, which is limited to generation such as solar. Instead, it offsets the host's bill by curtailing load during expensive periods of peak demand. Billed items include the monthly demand charge, the capacity charge (set by Peak Load Contribution, PLC), and, in some zones, a transmission charge.

The PLC is the host's demand during PJM's five coincident-peak hours (5CP), the five hours of highest system-wide demand each year. The utility bills each customer for capacity in proportion to its PLC, which is set on a rolling 12 month period. Therefore, reducing PLC cuts next year's capacity charge. A battery lowers its host's PLC by discharging through those peak hours and reducing total load. Each kilowatt of PLC it shaves avoids a full year of capacity cost. Blending the 2025/26 and 2026/27 delivery years proportionally for the July 2025-26 comparison, that is $100/kW-year.

The BTM value proposition in PJM is reliant on avoided charges

​The behind-the-meter value is a sum of the avoided charges. The demand charge is the monthly $/kW rate on peak demand. The capacity tag is the PLC saving above, $100/kW-year per kilowatt shaved. In PSE&G a transmission tag adds $162/kW-year, a demand-based charge set by the customer's load during the transmission peak. ComEd bills transmission per kilowatt-hour, so a battery cannot shave it.

A battery captures only part of each charge. Lawrence Berkeley National Laboratory finds a two-to-four-hour battery shaves a demand charge between 45 to 65% of its size, depending on load shape. Net of charging, the estimated value by zone is:

• PSE&G: $167 to $231/kW-year, closest to wholesale. It exposes both a capacity tag and a demand-based transmission tag, both shavable with battery dispatch.
• ComEd: $125 to $175/kW-year. A capacity tag and a high distribution demand charge, but transmission is billed per kilowatt-hour, so a battery cannot shave it.
• Dominion: $55 to $79/kW-year. The vertically integrated utility does not have a dedicated capacity tag to shave. Dominion instead bills on prior peaks, a 12-month rolling peak and a 75% summer floor, which a battery cannot sustainably lower.

Illinois and New Jersey are the states to watch for direct incentives

​Two PJM states pay distributed batteries directly via rebates, with CRGA starting July 2026 and GSESP in late 2026.

Illinois's Clean and Reliable Grid Affordability Act (CRGA) rebate is worth $67/kW-year, the only PJM-state incentive that pays a distributed developer directly today. New Jersey is next: the Garden State Energy Storage Program, approved in 2025, is set to open a Phase 2 for distributed storage in 2026. This carveout is expected to apply to both front-of-meter and behind-the-meter systems.

For a distributed developer, a direct payment is the difference between a marginal project and a fundable one, which is why Illinois and New Jersey are the states to watch.