Winter weather, just like in February, set the price in ISO-NE, not generation outages. A late-winter cold front pushed overnight temperatures below minus 5 degrees Fahrenheit across northern New England during the first week of March. Residential heating demand surged onto the same constrained gas pipeline network that feeds power generation. Day-ahead (DA) prices spiked to $110/MWh on March 2 while the Internal Hub DA average landed at $46.96/MWh, flat year over year. Real-time (RT) prices averaged $47.60/MWh, up 4.4 percent.

Top-bottom spreads rose across every zone, with Maine's four-hour RT spread reaching $292/MW-day, up 36.8 percent year over year. Wind climbed 38 percent while natural gas fell to 48 percent of the mix. February's benchmark told the same story at higher intensity.

Key takeaways

• The Internal Hub four-hour RT top-bottom spread reached $278/MW-day (up 31 percent year over year). The $133/MW-day DA-to-RT gap would be actionable by operators with real-time dispatch capability.
• Natural gas fell to 48 percent of the generation mix as wind rose 38 percent year over year to 754 MW, steepening the morning and evening ramps that BESS operators target.
• The first week averaged $69/MWh DA (1.7 times the March 8-onward average), with a single-day peak of $110/MWh on March 2 and an RT high of $225/MWh on March 6.
• Wind's capture rate fell to 97 percent from 101 percent in March 2025, consistent with growing output shifting into lower-priced hours.
• Reserve prices spiked during the cold snap (ten-minute spinning reserve hit $39.62/MWh on March 2, regulation capacity hit $55.79/MWh on March 3) but remained a small fraction of revenue.

The first week averaged $69/MWh DA before prices settled below $50

The cold front that arrived on March 1 tightened gas supply on the Algonquin pipeline system for roughly five days. March 2 recorded the highest DA daily average at $110/MWh; the RT market followed a day later, with March 3 averaging $118/MWh. The one-day lag between DA and RT peaks is typical of weather-driven events. By the second week, prices dropped below $50/MWh for most remaining days.

The first-week DA average of $69/MWh ran 1.7 times higher than the $41/MWh average from March 8 onward. A four-hour battery earning the first-week spread would book most of its March return in those five days.

Zonal prices followed the system pattern but with an important divergence. Southeastern Massachusetts (SEMASS) posted the highest DA average at $47.59/MWh, while Maine was the cheapest zone at $44.17/MWh DA. Maine is on the constrained side of north-south transmission bottlenecks and has the highest wind penetration in the region. The constraint depresses Maine's DA price because the DA market schedules imports away from the zone.

Real-time prices across ISO-NE

The hourly RT price profile peaked at $71/MWh at 7 AM (hour 7) and fell to $26/MWh at 1 PM (hour 13) as solar displaced gas. RT prices ranged from negative $119/MWh in Vermont (hour 14 on March 25) to $225/MWh (hour 5 on March 6). In total, 35 hourly intervals recorded negative RT prices, concentrated between 10 AM and 4 PM during late March.

At negative prices, the charge cycle itself is a revenue source. 35 negative-price intervals in late March extended BESS earning windows beyond the morning and evening ramps.

How did these spreads differ across ISO-NE?

At the Internal Hub, the four-hour DA top-bottom spread averaged $146/MW-day, up 12.7 percent year over year. The four-hour RT spread reached $278/MW-day, up 30.9 percent. The $133/MW-day DA-to-RT gap accrues to operators with real-time dispatch capabilities to act on pipeline constraints arbitrage.

Maine saw both the largest absolute RT spread at $292/MW-day and the largest year-over-year gain at 36.8 percent. Vermont ranked second at 33 percent, reaching $277/MW-day. On the DA side, Maine posted $149/MW-day, up 13.1 percent. Connecticut had the lowest four-hour DA spread at $139/MW-day but still grew 13.4 percent year over year.

The consistent year-over-year gains across all zones confirm that the early-month cold snap lifted spreads system-wide. The zonal ranking is persistent: Maine and Vermont lead month after month because their position behind transmission bottlenecks amplifies RT volatility. That pattern is structural and will not change absent major transmission buildout.

How did ISO-NE’s generation mix vary during March?

Natural gas supplied 5,367 MW on average, or 47.8 percent of total generation, down 6.1 percent year over year. Nuclear held flat at 3,356 MW (29.9 percent), providing the stable baseload floor that keeps overnight prices from collapsing even as wind rises.

Wind was the standout in ISO-NE. Average output rose 38 percent to 754 MW, reaching 6.7 percent of the mix. Wind's capture rate (the ratio of the generation-weighted average price to the time-weighted average price) fell to 97 percent from 101 percent in March 2025. As New England's onshore wind fleet grows, more output lands in overnight and midday hours when load is lower and prices softer. Solar contributed 182 MW (1.6 percent). Hydro provided 972 MW at 8.7 percent.

Oil generation was negligible at 15 MW (0.1 percent), a contrast to February when cold snaps pushed oil-fired units into the merit order. The growing wind share and falling gas contribution steepen the morning and evening ramp profiles, widening the arbitrage windows that BESS operators target.

Reserve revenues remained marginal compared to energy arbitrage in ISO-NE

ISO-NE co-optimizes energy and reserves. Prices spiked during the early-March cold snap but averaged modest levels.

All reserve products rose 50 to 70 percent year over year, driven by the early-March cold snap: ten-minute spinning reserve averaged $14/MWh versus $9/MWh in March 2025, and regulation capacity rose 63 percent. Forward energy reserve was the exception, falling 61 percent.

A BESS operator stacking regulation on top of energy would add single-digit percentage points to monthly returns. At current prices, that is not enough to support a single merchant case.

Outlook

March confirmed that BESS value in ISO-NE remains event-driven: five days of cold weather delivered the bulk of spread value, and February told the same story at higher amplitude.

The structural conditions are durable. New England's pipeline constraints, north-south transmission bottlenecks, and growing wind fleet are all persistent features. As wind output rises and its capture rate falls, lower midday prices and a growing number of negative-price hours widen the charge window. On the discharge side, evening ramp scarcity and weather-driven gas basis spikes sustain high spreads. For operators, Maine offers the region's cheapest DA charging at $44.17/MWh and its widest RT spread at $292/MW-day, a combination no other zone matches.