​New England's gas bottleneck converted an early-February cold snap into a reliability event. Oil-fired generation surged 939% year over year to 15% of the mix as gas-fired plants could not secure fuel.

Day-ahead prices at the Internal Hub, ISO-NE's system-wide reference pricing point, topped $200/MWh for eight of the first nine days. Real-time TB4 (top-bottom) spreads at the Internal Hub averaged $404/MW-day, concentrated in that opening stretch, which could have increased BESS revenues.

Prices collapsed below $70/MWh once temperatures normalized, leaving the day-ahead hub average at $126.09/MWh, down 3.3% year over year.

Key takeaways

• Oil-fired generation surged to 15.0% of the mix from 1.7% a year earlier, a clear signal of New England's gas infrastructure bottleneck.
• Day-ahead hub prices averaged $126.09/MWh for the month, masking a 2.6x gap between the first half ($182/MWh) and second half ($70/MWh).
• Day-ahead four-hour TB spreads at the Internal Hub averaged $257/MW-day, up 6.1% YoY.
• Combined with regulation and capacity payments, total four-hour BESS revenue potential at the Internal Hub reached $54/kW-month ($1,800/MW-day average).\
• The highest real-time four-hour spread appeared in Maine ($434/MW-day) despite the zone having the lowest day-ahead prices.

How wide was ISO-NE's price split in February?

Eight of the first nine days saw day-ahead prices above $200/MWh at the Internal Hub, with real-time prices reaching $400.46/MWh on February 2. Day-ahead averaged $70.10/MWh from February 15 onward — the first-half average ran 2.6 times the second half, a wider split than MISO during the same period (see the MISO February 2026 monthly benchmark).

Across zones, monthly averages reveal a north-to-south gradient shaped by congestion:

Maine's discount reflects north-to-south congestion that caps exports to southern load centers.

Why did oil generation surge, and did it help BESS?

New England's gas network cannot serve both heating and power generation during extreme cold. Residential heating consumed pipeline capacity in early February, leaving gas-fired generators unable to secure fuel. Oil-fired plants stepped in.

• Natural gas: 45.8%, +5.5% year over year
• Nuclear: 24.5%, steady
• Oil: 15.0% (2,064 MW average), up from 1.7% a year earlier, concentrated in the first two weeks
• Wind: 662 MW average (4.8%), +18.6% year over year, though still too small a share to offset the gas constraint during peak hours

Total ISO-NE generation rose 19.6% year over year to 9,225 GWh. Oil-fired units set the marginal price during peak hours, decoupling wholesale prices from gas fundamentals and widening the peak-to-off-peak gap that drives BESS arbitrage.

To what extent did prices decouple from gas?

Henry Hub averaged $3.60/MMBtu. In most ISOs, the observed $3.90/MMBtu range would translate to $30-40/MWh of power price movement. In ISO-NE, Algonquin Citygate, the main gas delivery point for New England power plants, decoupled from Henry Hub and the actual swing was far larger.

On February 9, the implied heat rate, calculated as the day-ahead hub price divided by the Algonquin Citygate spot gas price, reached 66.4 MMBtu/MWh — more than nine times an efficient combined-cycle plant — confirming oil, not gas, was setting the marginal price. By late February, heat rates settled to 13-20 MMBtu/MWh as gas fell below $3.15/MMBtu and power prices followed.

Limited pipeline capacity from Appalachia causing Algonquin Citygate to decouple from the national benchmark, is the root cause of both the price spikes and the oil generation surge.

What drove demand higher and is there BESS potential?

Gross system demand averaged 15,147 MW (+4.6% year over year), driven by cold weather rather than structural growth. Net load averaged 14,363 MW (+4.1%). The narrow gap at the solar peak (roughly 1,000 MW) confirms ISO-NE's BESS opportunity comes from weather-driven price spikes, not the solar-driven duck curve seen in ERCOT or CAISO.

Prices followed a double-peak pattern — morning heating and evening ramps flanking a shallow midday dip compared with southern ISOs.

How large were BESS spreads?

Day-ahead TB spreads at the hub grew modestly year over year:

The prior February's elevated pricing compressed these gains. Real-time spreads were flat year over year (-0.5% one-hour, -1.6% four-hour). On February 9, four-hour real-time spreads reached $960/MW-day. Nine days accounted for most of the month's BESS revenue potential.

Rhode Island posted the highest day-ahead four-hour spread at $263/MW-day (+9.0%), reflecting tighter local supply-demand conditions that favor BESS in southern New England load pockets. The widest day-ahead-to-real-time gap appeared in Maine: the lowest day-ahead spread ($238/MW-day) but the highest real-time spread ($434/MW-day, +5.5% year over year). Physical congestion on north-south corridors creates real-time scarcity that day-ahead scheduling does not anticipate. BESS operators with real-time dispatch capability would capture this gap.

How did ancillary services price?

Energy arbitrage dominated BESS revenue in February. A four-hour discharge on February 9 could capture $960/MW-day from TB spreads alone, 29 times the average TMSR rate.

Even at its February 2 peak, TMSR would capture less than 8% of the best spread day's arbitrage. Reserves are marginal against TB spreads in ISO-NE's winter.

Outlook

Revenue is event-driven: a handful of winter days can define the annual return. Real-time participation is essential: four-hour spreads exceeded day-ahead by 57% at the hub and 82% in Maine.

North-to-south transmission constraints bind unpredictably during real-time dispatch, creating scarcity that the day-ahead market does not fully anticipate. Congested zones, particularly Maine, offered meaningfully higher real-time returns than day-ahead pricing suggested.