New England's $6.53 Billion Winter: The 45% Cost Jump That Should Change How Buyers Plan
Last winter, New England's wholesale electricity market cost $6.53 billion. That is not a typo, and it is not a rounding error. It is the total wholesale cost of electricity for Winter 2026 — December 1, 2025 through February 28, 2026 — as reported by ISO New England's own Internal Market Monitor. It was 45% higher than the winter before, and the highest winter total since 2014.
The same report that carried that number also carried the reason, in plain language: the region's pipelines were "significantly constrained throughout Winter 2026." When the cold arrived, there was not enough gas to go around, and the market did what markets do when supply runs short — it paid whatever it took.
This winter starts from that number. Buyers who plan around it will be fine. Buyers who plan around a normal winter will not.
What Happened
Winter Storm Fern arrived in late January and stayed. A 19-day cold spell ran from January 23 through February 10, and on January 27, in the grip of the storm, Algonquin Citygate — New England's natural gas benchmark — hit $122.58/MMBtu. About 200 miles south, Transco Zone 6 New York reached $142.72/MMBtu.
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. LNG sendout into the region roughly doubled, up about 105%, mostly from the Everett and Saint John terminals. And power plants burned the most oil since at least 2015.
The bill for all of it landed in the wholesale market. ISO New England's market monitor put the total wholesale cost of electricity for the winter at $6.53 billion, up 45% from the winter before. A separate measure — wholesale electricity-market transactions for December through February — totaled about $6 billion, the highest winter total since the markets began in 2003.
And the costs did not stop at energy. ISO New England started a new day-ahead market for ancillary services in March 2025 — payments to generators for holding capacity ready the day before. The ISO expected the new service to cost about $140 million a year. Its market monitor put the first year's cost at $974 million. About 40% of that came in the five days of Winter Storm Fern, January 25 to 29, and 18% on January 27 alone. One storm, one week, nearly $400 million in standby costs.
Eversource's transmission chief put it plainly this summer: wholesale prices this past winter were two-and-a-half times the cost seen in an average winter. "Customers will see that probably six months from now," he said. "And they'll certainly see it in their energy bills next winter."
Why It Matters
The 45% jump was not a one-winter accident. It was the predictable result of a system that has been narrowing for years.
On the demand side, the region is shifting toward a winter-peaking system. 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. Peak demand is expected to climb from about 20,500 MW this winter to roughly 26,400 MW by 2035–36. Every heat pump and electric vehicle added to the region adds load in exactly the season when the gas system is already full.
On the supply side, the fuel diversity that used to cushion a cold snap 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 market monitor's own diagnosis of last winter was blunt: "limited gas pipeline infrastructure, coupled with the absence of local natural gas deposits."
The full-year picture is no better. It was reported that regional wholesale electricity costs rose 48% in 2025 to $15 billion, and named higher natural gas prices — which more than doubled — as "the principal driver." Winter was the worst of it, but it was not the only time.
For households, the numbers are already visible. Massachusetts residential electricity averaged 30.41 cents a kilowatt-hour in 2025, against a national average of 17.23 cents — 76% higher. Through the first eight months of 2026, New England households paid 28.78 cents, 58% above the national average of 18.19 cents. The EIA's Winter Fuels Outlook, released October 6, expects the average U.S. household heating mainly with electricity to spend $1,196 from November through March, up 4% — and in the Northeast, $1,637, where a milder forecast only partly offsets higher prices.
What It Means for Commercial Buyers
For Massachusetts buyers — and anyone else buying power inside ISO New England — last winter's $6.53 billion is a planning number, not a headline. 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, the marginal fuel is oil, and the ancillary-services market is paying a premium for capacity to be on standby. A contract that looks competitive on an annual average can carry real exposure in January and February, when wholesale costs spike and the winter's bill arrives months later in the form of higher supply rates.
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, capacity, and ancillary-services components. The $6.53 billion was not an abstraction — it is already flowing through to buyers in the form of higher winter supply rates. Eversource said so directly: customers will see it in their bills this winter.
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, and the gap widens every year the peak climbs.
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 — a premium that, last winter, ran to $122.58/MMBtu on the gas side and nearly $400 million in five days on the ancillary-services side.
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, and a market monitor that keeps finding the same constraint — 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 power 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, the region keeps retiring the fuel diversity that used to cushion a cold snap, and demand keeps growing in exactly the season the system is tightest. Every winter, the market rediscovers the constraint at the same time, at the same price — and last winter, the price was $6.53 billion.
The projects coming — Enbridge's AGT Enhancement, about 75 MMcf/d targeted for 2029; Project Beacon, about 300 MMcf/d targeted for 2030; the revived Constitution proposal at 650 MMcf/d targeting 2028 — 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.
Last winter cost $6.53 billion. This winter starts from there.
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