​Evening price ramps, especially during a heatwave from April 14 to 17, drove the bulk of April's top-bottom spread differences in ISO-NE. April 17 real-time prices spiked above $100/MWh from 5 PM through 8 PM, peaking at $131/MWh at 7 PM. Over the entire month, real-time prices at ISO-NE’s Internal hub swung between -$73/MWh and $138/MWh.

Natural gas set the margin across all four heatwave evenings as constraints limited transmission between zones.

At ISO-NE’s reference hub, April delivered a day-ahead average of $46.3/MWh and a real-time averages of $45.7/MWh. Both markets increased by more than 10% compared to April 2025. The average gap of $0.6/MWh between the two markets understates intraday volatility: on event days, real-time settled as much as $28/MWh above day-ahead.

Four-hour top-bottom spreads at the Internal Hub averaged $178/MW-day in real-time and $134/MW-day in the day-ahead, up 26% and 22% year over year respectively.

Key takeaways

• The Internal Hub's four-hour real-time top-bottom spread averaged $178/MW-day, up 26% year over year. Day-ahead spreads averaged $134/MW-day, a 22% increase.
• Nuclear averaged 1.7 GW in April, down 33% from 2.5 GW in 2025. Natural gas filled the gap, adding roughly 800 MW to average output year over year.
• Evening ramps from April 14 to 17 sustained real-time prices above $100/MWh across three consecutive days, with April 17 peaking at $131/MWh at 7 PM.
• Ten-Minute Spinning Reserve (TMSR) cleared $13/MWh day-ahead while regulation averaged $5/MWh. Both are small relative to the $178/MW-day TB4 real-time spread.

Evening ramps from April 14 to 17 defined the month's spread value

Daily day-ahead averages ranged from $30/MWh to $66/MWh across April, but four evenings from April 14 to 17 produced substantially higher prices. April 14 peaked at $108/MWh at 8 PM. April 16 crossed $107/MWh from 5 PM to 6 PM. April 17 had the longest period of elevated prices, holding above $100/MWh for four consecutive hours and peaking at $131/MWh at 7 PM.

April 17 was also the month's second-largest day-ahead forecasting discrepancy. April 1 saw real-time settle $28/MWh above day-ahead and April 17 followed with RT prices exceeding DA by $17/MWh.

April 22 posted the month's single-hour ceiling at $138/MWh at 8 PM. Demand climbed from 13.0 GW to 13.9 GW as solar faded to near zero.

The spike can be attributed to binding reserve constraints and loads above day-ahead forecasts. New England's pipeline constraints limit intraday gas supply, reducing reserve capacity when demand spikes later than anticipated.

Day-ahead markets cannot accurately price intraday gas constraints in advance, and therefore that premium accrues entirely to operators with real-time dispatch.

Only two hours cleared negative for the month, both on April 3. Good Friday cut commercial load about 1.2 GW while solar at 556 MW and wind at 613 MW pushed net load to roughly 8 GW. In response, real-time prices dipped to -$73/MWh.

Top-bottom spreads widened across every ISO-NE zone

Top-bottom spreads in day-ahead and real-time markets rose in every zone compared to 2025.

At the Internal Hub, the DA TB4 spread averaged $134/MW-day, up 22%, while the RT TB4 averaged $178/MW-day, up 26%.

Northeastern Massachusetts and Vermont both posted 26% increases in real-time TB4 spreads. Maine recorded the highest RT TB4 spreads at $196/MW-day but the smallest YoY gain at 15%.

The Maine-New Hampshire Interface bound on multiple days across April, depressing Maine's day-ahead price relative to the rest of New England. That constraint is structural, recurring monthly and therefore depressing prices in Maine that drive the regions largest TB4 spreads.

Nuclear's spring outage pushed gas to 57% of April generation mix

Nuclear generation averaged 1.7 GW (17% of the mix), down from 2.5 GW (25%) in 2025. That 0.8 GW shortfall is consistent with spring refueling for New England's nuclear reactors.

Natural gas generation fills that gap and supplied 57% of the total generation stack (5.6 GW), up from 53% a year ago.

Reserve products stayed secondary to arbitrage in April

Ten-Minute Spinning Reserve (TMSR) averaged $13/MWh day-ahead, peaking at $22/MWh on April 22. Ten-Minute Non-Spinning Reserve (TMNSR) averaged $8/MWh and Thirty-Minute Operating Reserve (TMOR) $7/MWh day-ahead.

Regulation capacity averaged $5/MWh while real-time reserve prices cleared near zero for most of the month. At those levels, energy arbitrage at $178/MW-day remains the primary revenue driver for storage operators.

Outlook

This month reinforced a structural pattern: spreads widen on event days, and event days in shoulder seasons are driven by abnormal temperature conditions during planned outages.

Maine's average of $44/MWh remains the cheapest DA zone, held down by the Maine-New Hampshire Interface constraint that bound repeatedly this month. Additionally, Maine’s wide TB4 spreads represent the zone’s premium for dispatchable BESS.

Battery revenues in ISO-NE will continue to be defined by similar conditions the heatwave as temperatures rise through the rest of spring 2026.