ISO-NE's Coldest Winter in 20 Years: LMP and Contract Lessons for Grows

What happened winter 2025/26

ISO New England called winter 2025/26 the region's coldest in 20 years, with average temperatures 3.4°F below normal [iso-ne-winter-recap]. Total winter energy demand was the highest in 11 years [iso-ne-winter-recap].

From January 23 through February 10, an arctic outbreak kept temperatures about 11°F below normal for 19 straight days [iso-ne-winter-recap]. New England consumed roughly 7,669 GWh during that period alone [iso-ne-winter-recap]. Wholesale energy market transactions for December, January, and February totaled about $6 billion, the highest winter energy market cost since markets began in 2003 [iso-ne-winter-recap].

The grid stayed reliable. That does not mean bills were calm.

Why prices spiked: gas, oil, and imports

About half of New England's electricity normally comes from natural-gas-fired generators [iso-ne-winter-recap]. Pipeline capacity is contracted first for home and business heating. During the cold snap, gas demand for heat left less fuel for power plants at reasonable prices.

Generators switched to oil where economical [iso-ne-winter-recap]. Winter Storm Fern on January 25 disrupted fuel oil logistics across the Northeast, creating competition for distillate [iso-ne-winter-recap]. Imports averaged about 2,400 MW per hour over the 19-day event, but neighboring regions were also cold, limiting help [iso-ne-winter-recap].

Behind-the-meter solar underperformed: snow cover cut output to about 41% of potential during the cold snap [iso-ne-winter-recap]. That pushed more load onto the grid exactly when supply was strained.

Peak demand and cultivator load

Winter peak demand hit 20,182 MW on January 25, 2026, in the hour ending 2 p.m. [iso-ne-winter-recap]. Indoor cannabis facilities contribute winter peak from HID or LED heat load plus HVAC and dehumidification fighting cold, dry outdoor air.

Your facility may not move the ISO peak, but your supplier pricing follows Mass Hub or zone LMP if you are on index or hourly default. A cultivator on Eversource or National Grid basic service that procures quarterly or semi-annually may lag real-time spikes. A large C&I account on hourly pricing feels them immediately.

Cold-dry air and dehumidification during the January price spike

ISO-NE's cold snap kept outdoor temperatures about 11°F below normal for 19 straight days [iso-ne-winter-recap]. Cannabis facilities in Massachusetts run dehumidification and reheat year-round, but winter brings a specific double hit: cold outside air increases latent load when you ventilate, and reheat strips moisture at high kWh intensity. That load often runs during daytime hours when ISO-NE LMP spiked on gas scarcity, not during off-peak nights.

Assume a 12,000 sq ft flower facility with 450 kW dehumidification and HVAC draw during daytime operation. During the January 23 through February 10 event, the facility consumed an extra 2.5 hours of peak dehumidifier staging per day compared to a normal January week (illustrative ops input). At 180 kW average for those hours over 19 days:

Extra kWh ≈ 180 kW × 2.5 hr × 19 days ≈ 8,550 kWh

If index supply averaged 18 ¢/kWh during the tightest weeks versus 9 ¢/kWh in a normal week (illustrative stress inputs, not ISO-published averages [iso-ne-winter-recap]), incremental supply cost ≈ 8,550 × ($0.18 − $0.09) ≈ $770 for dehumid alone. Scale to full canopy and 24-hour HVAC and six-figure quarter swings match the earlier table.

Operators sometimes lock winter energy but leave dehumid profiles unchanged. Lowering winter ventilation setpoints or pre-heating stored thermal mass before forecast cold snaps reduces both kWh and exposure to high-LMP hours. Track NOAA forecasts the same way you track harvest dates.

Section 202(c) and what it signals

The U.S. Department of Energy issued an order under Section 202(c) of the Federal Power Act from January 25 through February 14, 2026, allowing generators with permit limits to run when needed for reliability [iso-ne-doe-202c]. Fifty-seven resources, about 39% of winter generating capacity, received specified resource treatment [iso-ne-doe-202c].

For operators, the takeaway is operational: the ISO came close enough to limits that federal intervention was necessary. Winter supply risk is not theoretical in New England. Contracting strategy should assume multi-week cold events, not single-day peaks.

Contracting lessons for cannabis operators

Separate energy from capacity in your head. This winter story is primarily energy market cost (LMP), not the forward capacity market (FCM). Your bill can spike on index energy even when capacity rates were set in prior FCM auctions.

Lock winter energy before November. Forward procurement for basic service and many supplier contracts happens months ahead [mass-basic-service-2026]. If you float index through winter, you accept gas pipeline risk.

Understand block-and-index. A block-and-index contract fixes a portion of volume and floats the rest. Cultivators with flat load may need a higher block percentage in winter than office tenants.

Delivery demand is still yours. Demand charges on Eversource G-2 or National Grid G-3 do not disappear when LMP falls. Winter peaks from heating and lighting still set kW charges.

Do not rely on solar offset in January. Snow-covered BTM PV increased grid demand during the cold snap [iso-ne-winter-recap]. Budget grid kWh for winter flower rooms even if summer net metering looks favorable.

Worked bill impact (illustrative)

Assume a Massachusetts cultivation facility with 1.5 million kWh winter quarter use (Jan-Mar) and a supply arrangement indexed to ISO-NE LMP.

Scenario	Avg supply adder	Winter supply cost
Normal winter (assume 8 ¢/kWh supply)	8 ¢/kWh	$120,000
Cold event quarter (assume 14 ¢/kWh blended)	14 ¢/kWh	$210,000
Difference		$90,000

These rates are illustrative inputs, not ISO-published averages. The $6 billion winter energy market total across all New England load shows the order of magnitude [iso-ne-winter-recap]. Your share depends on hour-by-hour usage during spikes.

Compare to summer planning

New England summers bring different stress (heat, air conditioning, capacity maintenance outages). Winter 2025/26 proved gas-linked energy volatility remains the dominant cost surprise for Massachusetts grows on floating supply.

Many operators optimize LED retrofits for summer kWh but underbudget winter supply on index. After this winter, ask your supplier for a historical stress test: what would January 2026 LMP have done to your account at current load?

Practical checklist before next winter

Pull interval data for January 25 through February 10, 2026, and mark your kWh during the highest-priced hours.

Request a fixed winter block quote starting November 1.

Confirm whether basic service reset dates align with your license budget cycle.

Review oil and gas backup generator fuel contracts if you rely on onsite generation for curtailment.

Revisit demand response only if winter curtailment avoids crop-critical loads.

ISO-NE kept the lights on through a historic cold period [iso-ne-winter-recap]. The cost landed in wholesale energy markets. Your contracting job is deciding how much of that volatility you pay upfront versus at the meter.

Eversource and National Grid basic service timing versus index exposure

Massachusetts basic service rates reset on schedules set by the Department of Public Utilities, not on daily LMP [mass-basic-service-2026]. A cultivator on fixed basic service felt winter 2025/26 costs on a lagged reset, while a large C&I account on hourly index pricing felt January spikes immediately [iso-ne-winter-recap] [mass-basic-service-2026].

That split matters for budgeting. If your facility switched from basic service to a third-party index contract in October 2025, you may have traded predictable lag for real-time exposure exactly when gas pipeline constraints lifted LMP [iso-ne-winter-recap]. Conversely, operators who stayed on basic service through winter and shopped in spring should read the next procurement reset for embedded winter costs [mass-basic-service-2026].

Block-and-index structures let you fix a percentage of winter kWh while floating the remainder [mass-basic-service-2026]. Cultivators with flat flower-room load often need a higher block percentage in Q1 than office tenants because dehumidification and reheat run through cold snaps [iso-ne-winter-recap]. A 70% block on 1.5 million kWh winter quarter use leaves 450,000 kWh exposed. If exposed hours averaged 20 ¢/kWh during the arctic event versus 9 ¢/kWh normal (illustrative stress inputs), incremental cost ≈ 450,000 × ($0.20 − $0.11) ≈ $40,500 on the unblocked slice alone.

Section 202(c) orders from January 25 through February 14, 2026 show how close the ISO came to operational limits [iso-ne-doe-202c]. Contracting for winter 2026/27 should assume multi-week cold, not a single peak day. Lock blocks before November when suppliers still offer winter strips; waiting until after the first cold snap often means buying risk already priced in [iso-ne-winter-recap].

Imports, oil, and gas: why January LMP stayed high for weeks

ISO New England reported about half of electricity normally comes from natural-gas-fired generators, with pipeline capacity contracted first for heating [iso-ne-winter-recap]. During the January 23 through February 10 arctic period, generators burned oil where economical and imports averaged about 2,400 MW per hour, but neighboring regions were cold too [iso-ne-winter-recap]. Behind-the-meter solar underperformed at about 41% of potential with snow cover [iso-ne-winter-recap].

Cannabis facilities cannot fix pipeline economics. They can fix contract exposure. Pull January 2026 interval data and tag kWh during the top ten priced hours. If more than 15% of monthly kWh landed in those hours because dehumidification ran flat out, your index contract is structurally wrong for winter [iso-ne-winter-recap]. Request a supplier stress test: replay January 2026 LMP against current load shape and compare to a November-fixed block quote [mass-basic-service-2026].