New England Is Overhauling Its Capacity Market. The Redesign Favors Batteries.

ISO New England filed the first phase of its Capacity Auction Reforms with FERC on December 31, 2025, requesting approval by March 31 of this year. If accepted, the region’s next capacity procurement will not resemble any of its eighteen predecessors. The forward auction, a fixture of New England’s electricity markets since 2008, would be replaced by a prompt auction held roughly one month before the delivery period. The capacity commitment period itself would split from annual into seasonal (summer and winter, procured separately). And the Minimum Offer Price Rule, which has governed new resource offers for over a decade, would not apply.

The first auction under this framework is planned for 2028, covering the capacity commitment period beginning June 1 of that year. Meanwhile, FCA 19 is being conducted this month under the current structure for the 2028/2029 commitment period. It is the first auction without the MOPR and the first under new Resource Capacity Accreditation rules, with DER aggregations eligible for the first time under FERC Order 2222.

The old model. Since its inception, ISO-NE’s Forward Capacity Market has procured resources more than three years before they were needed. The design made sense when the grid was dominated by large thermal generators with long construction timelines. The market generates an estimated $1.3 billion annually. FCA 18, held in February 2024, saw new solar, storage, and demand-reduction resources clear alongside incumbent generators, signaling a shift in the composition of New England’s resource mix.

The problem with three years. A three-year-ahead auction forces resource developers to commit capacity obligations based on projections that may not hold. ISO-NE’s own filing acknowledges the resulting “phantom entry” problem: resources that clear the auction but never reach commercial operation, distorting price signals and complicating reliability planning. A prompt auction, conducted with current information about which resources actually exist and which loads actually materialize, would eliminate that gap.

The shift would also compress timelines for generators seeking to retire, while retaining safeguards against market manipulation and transmission security risks. Generators that want to exit could do so faster. Generators that stay would need to demonstrate they can actually perform.

Why seasonal matters. New England has a winter problem that no other U.S. grid region shares at the same scale. Natural gas pipelines serving the region become constrained when residential heating demand surges, leaving gas-dependent generators unable to secure fuel on the spot market. The current annual capacity framework treats a megawatt in July the same as a megawatt in January. The seasonal redesign would not.

Under the proposed accreditation approach, a gas plant without firm fuel contracts or on-site storage would receive lower capacity compensation than an otherwise identical plant that has secured its fuel supply. Battery storage systems, which do not depend on pipeline access, would face no such seasonal penalty. A four-hour lithium iron phosphate system performs identically whether the temperature is 95 degrees or 5 degrees, provided it is charged.

The MOPR disappears. The Minimum Offer Price Rule was originally designed to prevent state-subsidized resources from suppressing capacity prices. In practice, it created a floor price that made it harder for renewable and storage resources receiving state incentives to clear the auction. With FCA 19, the elimination takes effect. Resources backed by state clean energy mandates, including battery storage projects supported by programs like the Massachusetts Clean Peak Standard or Connecticut’s energy storage deployment targets, can now offer into the capacity market at their actual cost.

The queue. Battery storage has grown from a marginal presence to a significant share of ISO-NE’s interconnection queue. According to ISO-NE’s published data, battery projects now constitute a substantial portion of proposed new capacity. If even a fraction of queued projects reach operation before the first prompt auction in 2028, the battery share of cleared capacity would increase materially.

DER aggregations. Separately from the capacity auction reforms, ISO-NE continues implementing FERC Order 2222, which requires the grid operator to allow distributed energy resource aggregations to participate in wholesale markets. ISO-NE has made multiple compliance filings, and FERC has partially accepted the proposals while directing revisions in areas including behind-the-meter metering requirements and small utility opt-in provisions.

When the auction reform and Order 2222 implementation timelines align, a portfolio of commercial battery systems spread across multiple buildings in, say, the Boston metro area could bid aggregated capacity into the same market where a large gas plant competes. The regulatory calendar, not the technology, is the remaining constraint.

Phase 2. ISO-NE is already developing the second phase of the Capacity Auction Reforms, which will establish the mechanics of separate winter and summer auctions and finalize updated resource accreditation standards. The accreditation methodology is expected to recalibrate how much capacity credit a resource receives based on its actual contribution to reliability rather than its nameplate rating.

For battery storage, accreditation based on actual performance is favorable terrain. Storage systems have no fuel risk, minimal correlated outage exposure, and measurable energy limits that the framework is designed to assess.

What this means for the region. The structural redesign underway does not change the total dollars flowing through the market so much as it redirects them. Resources that perform reliably across seasons, that do not depend on constrained fuel infrastructure, and that can be built and operational within the compressed timeline of a prompt auction all gain relative advantage under the proposed rules.

Whether the accreditation framework, the MOPR elimination, and the prompt auction timeline deliver on their theoretical promise depends on FERC’s response to the December filing and the execution of Phase 2. The reforms remain proposals until FERC acts. If approved, New England’s capacity market would be structured around the resource mix the region is actually building.

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