ISO-NE Capacity Market Reform: FERC Approves Shift from 3-Year-Forward to Prompt Auction — What It Means for New England Rates
On March 30, 2026, FERC approved ISO New England's most significant capacity market redesign in its history: the transition from a 3-year-forward Forward Capacity Market (FCM) to a prompt Annual Capacity Auction (ACA) held approximately one month before the Capacity Commitment Period. The reform — Phase 1 of ISO-NE's Capacity Auction Reform (CAR) project — takes effect immediately, with the first prompt auction targeting the 2028/2029 capacity year (beginning June 1, 2028). The most consequential rule: only resources in full commercial operation may participate, eliminating the "phantom entry" problem that has plagued New England's capacity market for years — where non-existent resources secured capacity obligations, then failed to materialize. For the six-state region's commercial electricity buyers, this reform creates both opportunity (better price accuracy, elimination of phantom supply) and risk (upward capacity cost pressure, supplier hesitancy to quote fixed prices beyond 2028).
Executive Impact
- →Fixed-Price Contract Cliff at June 2028: Multiple competitive electricity suppliers in New England have ceased offering fixed-price contracts that extend past June 1, 2028 — the start date of the first prompt capacity auction. The regulatory uncertainty around how the new auction will clear means suppliers cannot reliably hedge capacity costs. If your contract expires in mid-2028 or later, expect limited fixed-price options and wider bid-ask spreads.
- →Phantom Entry Eliminated: Under the old FCM, projects that won capacity obligations three years in advance sometimes failed to build — creating reliability risk and market distortion. The prompt model requires demonstrated commercial operation. For ratepayers, this means the capacity you're paying for will actually exist, reducing the hidden "insurance cost" of backstop procurement that ISO-NE has relied on when preferred resources defaulted.
- →Winter Reliability Premium Coming: Phase 2 of the CAR project — expected to be filed with FERC by end of 2026 — introduces seasonal (summer/winter) auctions. New England's winter reliability crisis (gas pipeline constraints, $6B wholesale cost Winter 2025/2026) will be explicitly priced in the winter auction. Resources that have invested in dual-fuel capability or LNG storage will command premium winter capacity payments. This premium will flow through to commercial rates as a separate seasonal capacity charge.
Why ISO-NE Abandoned the Forward Capacity Market
The Forward Capacity Market — introduced in 2006 — was designed around a simple premise: by auctioning capacity three years in advance, ISO-NE could send price signals that would attract new generation investment before it was needed. For nearly two decades, this worked reasonably well. But three structural failures converged to make the FCM unsustainable:
- Phantom Entry: Projects won capacity supply obligations in the forward auction, then failed to reach commercial operation by the delivery date. ISO-NE was forced to run expensive "reconfiguration auctions" to backfill these holes, creating market uncertainty and additional costs that ratepayers absorbed.
- Forecast Uncertainty: A three-year-forward auction requires ISO-NE to predict peak load, resource retirements, and market conditions 36+ months in advance. In a world of rapid load change (data centers, electrification, behind-the-meter solar), this forecasting exercise became increasingly unreliable.
- Retirement Timing Mismatch: Under the FCM, generators had to provide approximately four years' notice before retiring. This created a perverse incentive for aging plants to delay retirement decisions, distorting supply curves and preventing newer, cleaner resources from entering the market.
What Changes Under the Prompt Auction
The new Annual Capacity Auction (ACA) model changes the fundamental economics of New England's capacity market:
- Operational Requirement: Only resources that are commercially operating and have demonstrated their ability to deliver capacity to the region may participate. This eliminates the "paper megawatt" problem entirely.
- Shortened Retirement Notice: From approximately four years to one year. Generators can now make retirement decisions based on current market conditions — not projected conditions half a decade out.
- Reduced Reconfiguration: With auctions held just one month before delivery, the entire reconfiguration auction mechanism becomes unnecessary. This eliminates a significant source of administrative cost and market complexity.
- MOPR Removal: The Minimum Offer Price Rule, which restricted how state-subsidized resources could bid into the market, has been eliminated. This allows renewable resources with state backing to compete on equal footing.
State-by-State Commercial Impact
Massachusetts
MA accounts for approximately 50% of ISO-NE's load. Eversource and National Grid commercial customers will bear the largest absolute share of any capacity cost changes. The state's aggressive clean energy mandates (50% clean by 2030, 100% by 2050) align with the MOPR removal — clearing the path for offshore wind and battery storage to compete in the capacity auction without reference price floors. However, if these resources receive lower accreditation under the new MRI-based methodology, MA customers could pay more for capacity despite having more clean energy on the grid.
Connecticut
CT commercial rates — already among the highest in the lower 48 at 18-20¢/kWh — face additional upward pressure from capacity reform. Eversource's distribution rate case compounds the wholesale market changes. The CT PURA has been vocal about cost containment; expect regulatory scrutiny on how prompt auction costs are passed through to commercial tariffs.
New Hampshire
The DASI ancillary services cost overrun ($921M — which we covered extensively) has already eroded rate confidence in NH. Governor transparency reform demands apply directly to the capacity market transition: NH stakeholders will demand clear accounting of how the shift from FCM to prompt affects the capacity portion of commercial bills.
Maine, Rhode Island, Vermont
These smaller states face proportionally smaller absolute costs but have fewer competitive retail options. VT's unique structure (Burlington Electric Department is not a full ISO-NE market participant) partially insulates commercial ratepayers. ME and RI commercial customers should lock current-term contracts before June 2028 uncertainty introduces risk premiums.
Action Items for New England Commercial Buyers
- Extend Current Contracts Through June 2028: If your commercial electricity contract expires in 2027, negotiate an extension through at least May 2028 to avoid the uncertainty window around the first prompt auction. Fixed-price options expiring beyond June 2028 are already limited.
- Request Capacity Cost Breakdowns: Ask your supplier to show the capacity component of your rate separately. Understanding your baseline capacity cost (~$3-4/MWh at current FCM clearing prices) enables you to model the potential impact of higher prompt auction clearing.
- Evaluate Demand Response: The prompt auction increases the value of demand response in ISO-NE. If your facility can curtail 100+ kW during system peaks, enrollment in a demand response program could generate $10,000-$25,000/year in capacity credit revenue — effectively offsetting the higher capacity charges you'll pay on your supply contract.
- Track Phase 2 (Seasonal Auctions): The winter capacity premium — expected with Phase 2 in late 2026 — will be the most significant cost impact. If your business operates 24/7 through winter, consider behind-the-meter backup generation (propane or dual-fuel) to reduce your winter capacity tag.