ISO-NE published its 2026 to 2035 forecast on May 1. Three numbers worth pulling out of the CELT report:
- Regional electricity use grows about 9% over the next decade.
- The winter 50/50 net peak reaches about 26.5 GW by 2035, close to the summer peak.
- Heating electrification alone adds 5,533 MW to the winter peak by 2035 to 2036.
For 30 years New England has been a summer-peaking grid. The forecast says that's changing.
If you build C&I supply books for a living, this matters. So does how the regulatory framework around it is moving at the same time.
What's also moving in parallel
FERC accepted Phase 1 of ISO-NE's Capacity Auction Reform on March 31. The 3-year-forward auction is being replaced with a prompt auction held about 1 month before the commitment period, with the first prompt auction in 2028. Phase 2, expected at FERC by year-end 2026, splits the annual auction into a winter and summer auction and updates resource accreditation.
Vineyard Wind 1 finished construction in March, and Massachusetts activated its 20-year contracts on April 30, with $1.4B in projected ratepayer savings over the term. SouthCoast Wind's contract filings have been extended to June 30, and the project still sits inside the federal permitting freeze. The New England Clean Energy Connect line is operational and capable of moving up to 20% of Massachusetts's electricity needs.
None of these are coordinated. They're all landing in the same 18-month window.
Three things this does to C&I procurement
1. Capacity cost mechanics. With prompt auctions arriving in 2028 and a likely winter/summer split, the most expensive piece of a C&I bill is also becoming the most volatile. Long-dated capacity sitting inside a 24- or 36-month fixed price is an estimate. The closer the auction is to commitment, the less a multi-year fixed price functions as a true capacity hedge.
2. Shape risk on the heating side. Heat pump load behaves differently from AC load. It peaks earlier in the day, runs longer, and responds steeply to cold snaps. As New England crosses the threshold where heating electrification meaningfully shifts peak hours into the late winter afternoon and evening, a customer with a flat-block hedge or a poorly indexed full-requirements contract picks up shape risk that wasn't priced at signing. That risk shows up in true-ups, basis differentials, and pass-throughs. It rarely shows up in the headline rate the broker quotes.
3. Basis and forward curve. Vineyard Wind 1 changes the supply stack. NECEC moves dispatch in northern Massachusetts. Federal permitting risk on the next round of offshore wind affects what you assume about supply 5 years out. Each of these alone is a basis story. Together they're a forward curve story.
What we're telling brokers this week
Three practical questions for your renewal conversations.
- First, ask about contract vintage. Anything signed before May 2025 was priced against the previous CELT forecast and the old FCA framework. Even mid-term, the renewal conversation shifts.
- Second, look at hourly load shape, not just annual usage. A customer adding heat pumps, EV charging, or a third shift is changing their load shape. A flat-block product that fit last year may underprice the next 24 months.
- Third, treat capacity as a separate decision. With prompt auctions arriving in 2028, the customers who understand their capacity tags and have a plan for managing them will outperform customers who treat capacity as a line item buried in their rate.
What we're doing at Gridwealth
We're stress-testing our C&I supply book against the new CELT numbers. Winter capacity exposure. Shape risk on heat-pump-heavy customer segments. The Phase 1 to Phase 2 transition. We're sharing the results with our broker partners so they can have a substantive renewal conversation, not a rate-only one.
If you broker C&I in Massachusetts or Rhode Island and want to compare notes on how the forecast is changing your re-quote workflow, send me a DM.
