New England's Winter Gas Squeeze Is Back on the Calendar
Last winter gave New England a reminder it did not need. In late January, during Winter Storm Fern, the region's natural gas benchmark — Algonquin Citygate — hit $122.58/MMBtu. About 200 miles south, Transco Zone 6 New York reached $142.72/MMBtu. For comparison, Henry Hub, the national benchmark, peaked at roughly $30.57 during the same event — and for most of the year, the gas a few hundred miles south in Appalachia trades for a few dollars.
Winter is coming again. The pipelines have not changed. The demand has not gone down. And the region's own grid operator expects the squeeze to get worse, not better.
What Happened
Winter Storm Fern arrived in late January 2026 and settled in. A 19-day cold spell ran from January 23 through February 10, and on the coldest days, heating customers took priority on the pipelines — as they should, and as they are contracted to do. That left power generators bidding for what was left. Oil-fired generation in New England briefly surpassed gas-fired generation, and ISO New England's wholesale electricity-market transactions for December through February totaled about $6 billion — the highest winter total since the markets began in 2003.
This was not a one-off. Algonquin Citygate reached $71.42/MMBtu on February 3, 2023, and topped $33/MMBtu on January 21, 2025. Each winter's blowout has been bigger than the last, with only January 2024 — a comparatively mild stretch — breaking the pattern. Then came Fern.
The irony is that New England is not short of gas. The Marcellus and Utica shales hold plenty, and from April through July this year Algonquin traded about 43 cents below Henry Hub. What the region lacks is firm, deliverable gas on the handful of days that matter most. Five pipelines serve New England, and local distribution companies hold more than 80% of the contracted capacity on four of them, because they contract for peak-day heating needs. Power generators hold only about 200 MMcf/d of firm capacity while burning roughly 1.3 Bcf/d on average. On the coldest days, the LDCs use every molecule they have paid for, and generators are left bidding up for scraps — or burning oil.
Why It Matters
Both sides of the balance are moving the wrong way. On the demand side, ISO New England's 2026 CELT forecast has net electric energy use rising about 9% between 2026 and 2035, led by electrified heating and transportation. The region is shifting toward a winter-peaking system, with peak demand climbing from about 20,500 MW this winter to roughly 26,400 MW by 2035–36. Electrified heating cuts both ways for gas: it adds power load while taking heating load off the LDCs — but the net effect is a winter peak that keeps growing.
On the supply side, power supply keeps leaving. New England has spent two decades retiring big coal- and oil-fired units — Salem Harbor in 2014, Brayton Point in 2017, Bridgeport Harbor Unit 3 in 2021,
Merrimack Station in 2025 — plus Vermont Yankee and Pilgrim on the nuclear side. Gas-fired generation filled most of the gap, rising from roughly a quarter of New England generation in 2000 to more than half today. The queue is not replacing it in kind: ISO-NE's January 2026 queue held nearly 14 GW of nameplate capacity, 46% batteries, 44% wind and 10% solar, with essentially no thermal. Short-duration batteries can shave a peak, but they cannot replace sustained fuel supply over a prolonged cold spell.
The industry's answer has been incremental: smaller projects on existing rights-of-way. Enbridge's AGT Enhancement adds about 75 MMcf/d of Algonquin capacity, targeted for 2029; Project Beacon would add about 300 MMcf/d eastbound from Ramapo, targeted for 2030.
Williams' Northeast Supply Enhancement is under construction with a 2027 target, aimed mainly at New York City and Long Island. The revived Constitution proposal, at 650 MMcf/d, is targeting 2028 but still needs commercial support. Combined, the New England-aimed projects add roughly 375 MMcf/d — real help, but measured against a system where a single cold snap can move prices by tens of dollars, it is not a fix.
What It Means for Commercial Buyers
For Massachusetts buyers — and anyone else buying power inside ISO New England — the lesson of last winter is a planning one. Winter energy costs in New England are not a smooth average; they are concentrated in a handful of days when the pipeline system is full, and the marginal fuel is oil. A contract that looks competitive on an annual average can carry real exposure in January and February, when wholesale costs spike and basis blows out.
Three things are worth doing before this winter's cold arrives:
Know your winter exposure. Understand how much of your supply cost is fixed versus indexed, and how your supplier handles the January–February basis and capacity components. The $6 billion winter total was not an abstraction — it showed up in wholesale costs that flow through to buyers.
Watch the peak, not just the average. ISO-NE expects the region to become winter-peaking, with the peak rising to roughly 26,400 MW by 2035–36. As electrified heating grows, winter demand — and winter price risk — grows with it. A buying strategy built for a summer-peaking system is already out of date.
Plan the timing. With storage and pipeline capacity both constrained, the weeks before a cold snap are when the market prices in the risk. Buyers who lock in structure early, rather than buying into a January rally, avoid paying the scarcity premium that Fern delivered.
This is an ISO New England story, not a PJM one. Massachusetts sits in ISO-NE, and the dynamics here — constrained pipelines, heating priority, a winter-peaking shift — are specific to this region. The capacity-market debates playing out in PJM do not change the arithmetic on Algonquin.
PEM Perspective
New England's winter gas problem is not a mystery, and it is not new. It is the predictable result of a system where heating demand holds the firm pipeline capacity, power generation rides on interruptible space, and the region keeps retiring the fuel diversity that used to cushion a cold snap. Every winter, the market rediscovers the constraint at the same time, at the same price.
The projects coming — AGT Enhancement, Beacon, NESE — will help at the margin. But none of them changes the fundamental shape of the problem before this winter or the next. For commercial buyers, the practical answer is the same one it has been for years: understand where your winter exposure sits, structure around it before the cold arrives, and do not mistake a mild November for a solved problem.
Winter is coming. The calendar says so. So does last January.
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