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A surge in behind-the-meter (BTM) solar capacity in the last decade in the region makes the NERC evaluation appear less dire.

The outlook for generation capacity additions over the next six years, according to public information from ISO New England, suggests utility-scale resource additions that are entirely from renewables, which differs substantially from other regional reliability organizations.

A separate long-term study released by the ISO May 1 said that all solar installations, defined as BTM, those bid into the capacity market and those not in capacity markets, are estimated to grow by more than 50% in the next 10 years and exceed 12,700 MW by 2036.

The 2026 summer peak demand forecast for normal conditions in New England comprises a reserve margin of 14%, according to NERC, just above the reference margin of 13%. The reference margin is a targeted capacity buffer that must be maintained to ensure reliability.

The agency, authorized by the U.S. Congress to set grid standards, released its summer assessment in mid-May.

With typical outages, NERC anticipates that New England’s reserve margin during peak hours will fall to 4%. With higher demand, outages and derates in extreme conditions, peak hour reserve margins will dip to negative 0.9%.

The Pacific northwest and SaskPower are the only other areas in North America that have a similar potential for insufficient operating reserves under those conditions this summer.

Under an extreme scenario, the loss of load expectation risk in the region is 0.343 days per period, NERC said, with loss of load hours of 1.178 per period. Expected unserved energy was estimated at 628 MWh per period, with the highest risk occurring in June, with some in July and August.

New England has more than halved its projected net firm imports to 409 MW this year from 2025, the NERC document said. A new, import-only high voltage line from Québec can transport up to 1,200 MW into the region.

The peak internal summer demand forecast is 25,228 MW, little changed from last year. Increases in electrification as well as slight weather normalization changes drive the demand forecast.
ISO New England said separately that very hot and humid weather could drive demand to 26,473 MW. The ISO expects nearly 29,000 MW of generation to be available. All-time peak demand was 28,130 MW on August 2, 2006.

Behind-the-meter solar facilities of more than 8,000 MW have pushed daily regional peaks from grid power to around 5 p.m. to 6 p.m. instead of in the mid-afternoon, the ISO said. This BTM generation is projected to reduce demand by more than 1,700 MW this summer.

“While electrification is pushing demand upward, the expansion of BTM solar is running in parallel, and sometimes in the opposite direction,” energy software forecasting company Amperon said last year. “Some studies even show that overall demand in New England is trending downward, thanks in large part to BTM solar.”

Amperon’s recently-released summer outlook does not list New England as an area of particular reliability concern.

The grid’s public interconnection queue lists more than 1,700 projects, but BTM solar does not need ISO authorization. While the data can be difficult to analyze, it appears that several hundred fairly small solar and battery applications were withdrawn this decade.

The remaining projects expected to sync to the grid in the next six years total just under two dozen. These are renewable energy or distributed generation projects, predominantly in Massachusetts.

Wind power expected online in 2029-2031 is estimated to add 2,000 MW of capacity. Battery storage coming on line from 2027 to 2032 is expected to add about 4,900 MW.
A New Hampshire solar project slated for 2028 has a planned capacity of just over 100MW, while a Maine solar project in 2029 would add 183MW.

State policies are a strong driver of renewables. Most New England states have ambitious goals to reduce carbon dioxide (CO2) emissions.

An economic study by the ISO released last year called New England’s Evolving Grid explored some of the difficulties of co-optimization, or the simultaneous optimization of interdependent systems in a search for efficiency.

Some of the findings suggest eventual conflicts between reduced emissions, low costs and power demand growth.

The study found that photovoltaic solar supports early decarbonization, and land-based wind is consistently economical from 2033 to 2050.

For average weather, the projected resource mix in place in 2033 could serve forecasted demand through 2039, but cannot meet state emissions reductions targets without building new resources.

Zero-carbon generation resources added from 2033 to 2039 would primarily satisfy regional emission reduction policies, not demand growth.

“Emissions reductions before the 2040s are more cost effective than later reductions,” the grid study said. “Emissions reductions beyond 85% of policy goals drive escalating costs.”
New England and some western states are unique because power generators must pay for CO2 allowances.

Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island are among the states in the Regional Greenhouse Gas Initiative.

Auction prices for the cap-and-trade program have gradually risen from $3.07 per short ton of CO2 in 2008 to almost $25 per ton in March. A secondary market also exists.