​ISO-NE’s battery revenue stack changes materially over the next two decades. Ancillary services lead in the near term, energy arbitrage becomes more valuable as renewable penetration rises, and capacity revenues fall under seasonal accreditation reform. Massachusetts assets stand apart because Clean Peak Certificates can outweigh the entire market revenue stack.

This outlook covers Modo Energy’s Q3 2026 ISO-NE model through 2049. All prices are in real 2025 USD.

Key takeaways

• ISO-NE’s load becomes winter-peaking in 2038. Heat pumps and EVs drive the shift, changing both the timing and value of battery dispatch.
• Massachusetts BESS reaches peak stacked revenue over $300k/MW-year in 2032 before declining under $250k/MW-year by 2049.
• Ancillary services lead BESS revenues through 2038. Energy arbitrage becomes the largest market-revenue stream in 2039.
• Renewable growth strengthens top-bottom (TB4) spreads and energy revenues. State procurement, carbon pricing and the shift toward wind widen top-bottom spreads over time.
• Capacity revenue falls when capacity market reforms arrive in 2028. Seasonal accreditation gives four-hour batteries less credit, particularly in winter, while increasing the relative value of longer-duration storage.
• Clean Peak Certificates transform the Massachusetts stack. A Massachusetts battery can earn $159k/MW-year from Clean Peak alone in 2030, more than the full $141k/MW-year revenue stack available to a comparable Maine asset.

ISO-NE becomes a winter-peaking system

ISO-NE adds the least new load of any Eastern ISO. Net annual load grows 36.8% (117 to 160 TWh) through 2046, versus 811 and 426 TWh added in PJM and MISO. However, its shape changes seasonally the most.

Winter and summer coincident peaks cross over in 2038. Heat pumps drive the shift, adding roughly 9 GW to the modeled winter peak by 2045 as buildings electrify. ISO-NE forecasts just 132 MW of data centers system-wide, a fraction of PJM's or MISO's large-load growth.

See Modo Energy's ISO-NE 2046 load forecast for a breakdown of projections and drivers.

ISO-NE's buildout mix: renewables with firm capacity to meet winter needs in the late 2030s

Through 2029, ISO-NE's committed buildout from the interconnection queue is mainly BESS and offshore wind. There are4.7 GW of expected additions, 98% of it wind, solar, storage, and hydro. Batteries lead with 1.8 GW, 76% of it in Massachusetts and backed by Clean Peak. Offshore wind adds another 1.7 GW. No new thermal capacity has an executed interconnection agreement targeting 2030.

From 2030 onwards, the capacity expansion model (CEM) prioritizes reliable capacity for winter peaks. The CEM builds 10.9 GW of gas cumulatively by 2049. This gas provides new firm and peaking capacity for the winter-peaking system. Solar builds only through 2035 prior to the peak switch.

Overall wind additions total 19.3 GW across 2026-2049: 9.8 GW offshore, 9.4 GW onshore. Besides named and expected offshore wind from the queue, offshore wind only begins to build starting in 2036. Onshore wind builds steadily, concentrated in Maine reflecting state procurements and land availability. Maximum builds in the model are constrained based on ISO-NE economic and transmission studies.

The model builds wind for a few reasons:

1. All six New England states participate in the Regional Greenhouse Gas Initiative (RGGI),
2. Massachusetts generators carry an additional carbon cost,
3. Regional state energy planning and procurement leans heavily toward solar, wind, and BESS resources.

RGGI and Massachusetts' added regulatory costs make gas investment less competitive, which helps wind's economics. BESS and renewables also benefitfrom state offshore wind contracts and RPS carve-outs driving the committed pipeline.

Wind reshapes the generation mix, driving unique pricing patterns

Natural gas is projected to supply 35% of ISO-NE generation in 2027 while wind (onshore and offshore combined) hits 11%. That balance flips by 2039, when combined wind would overtake gas as the system's largest generation source.

Wind output grows nearly tenfold over the forecast, from 12.7 TWh in 2027 to 74.7 TWh by 2049. Gas generation grows too, from 40 to 46 TWh, but its share of the mix falls to 25% as total generation expands around it. More wind on the system deepens the price volatility and creates arbitrage opportunities for BESS.

New England's wind resource is strongest in winter, which complements the peak switch by offsetting the increased load. As the peak shifts to winter, more wind on the system makes up for the shortfall and eventually pushes LMPs down.

ISO-NE gas prices are tied to Algonquin Citygate, a historically volatile pricing hub in the winter. The region's dominant, pipeline-constrained hub is a significant driver of price in winter months, especially during extreme weather (cite benchmark). Because of supply constraints and price swings, ISO-NE often leans on oil during scarcity events. Oil peakers bid in at high prices, due to costly fuel inputs and independent capacity payments, meaning they activate only a few times a year when LMPs are far above normal. This local market characteristic drives price spikes and spreads in the long term, despite wind and solar capacity buildout.

The generation and daily load shapes drive higher TB spreads in the 2030s and 2040s

The load and price shapes below show that winter's evening peak climbs 8 GW from 2027 to 2045. Both seasons pair that evening climb with a deepening midday trough as solar output near noon more than doubles from 1.7 to 4.1 GW in winter, and 2.2 to 5.1 GW in summer. Most of that solar generates in the hours when heat pump and EV load dips between the morning and evening peaks. Although peaks switches from summer to winter in 2038, average daily peak crosses over earlier.

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Around-the-clock prices

ATC prices rise across all zones into the early 2030s as demand grows and capacity tightens, but then pull apart. Maine falls from about $80/MWh in 2032 to $33/MWh by 2049 as new onshore wind pushes down prices across northern New England. Connecticut, Massachusetts, and Rhode Island remain closer to $66/MWh because transmission constraints limit how much of that cheaper northern power can reach southern demand.