FERC's 2026 Summer Reliability Assessment: What the Grid Is Facing This Season

Each May, the Federal Energy Regulatory Commission releases its Summer Energy Market and Electric Reliability Assessment — a joint review with NERC that surveys the U.S. grid's readiness for peak cooling season. The 2026 edition, published May 21, lands against a backdrop of unprecedented capacity growth but also a lengthening list of regional stress points. The headline is broadly reassuring: all NERC assessment areas are expected to have adequate resources to meet normal summer peak demand. The fine print, as always, is about what happens when normal gives way to extreme.

U.S. generating capacity will be roughly 75 gigawatts larger this summer than it was a year ago — a level of year-on-year growth that has no modern precedent. More than 58 GW of new generation has come online since Summer 2025, led by 16.4 GW of solar, 14.7 GW of battery storage, 6.7 GW of natural gas, and 1.6 GW of wind. Texas alone added about 26 GW; the WECC region added around 13 GW; MISO added roughly 11 GW.

Despite those additions, retirements are slowing rather than stopping — about 8 GW of plant closures are expected this season. The net result is a generation fleet that, on a nameplate basis, is substantially larger than any previous summer.

Despite the national surplus, FERC and NERC flag three subregions as facing elevated risk of supply shortfalls under above-normal or extreme conditions: NPCC–New England, MRO–SaskPower, and WECC–Northwest.

New England's exposure stems from reduced firm import capability and tighter operating reserves once peaker availability is factored in. SaskPower faces higher-than-expected demand against slimmer reserve margins. The Northwest's risk is the most structurally concerning: the region depends heavily on hydroelectric generation, and low snowpack across the Columbia Basin has cut into summer hydro output.

The Colorado River Basin adds a separate layer of western exposure. Low reservoir elevations put roughly 4.5 GW of hydroelectric capacity at risk of reduced output by August, including the 2-GW Hoover Dam, which the Bureau of Reclamation is actively managing to preserve minimum power pool elevations. FERC warns that loss of Colorado River hydro would trigger increased transmission congestion and reduced operational flexibility across the interconnection during peak demand hours.

Henry Hub natural gas prices are projected to average $3.07 per MMBtu this summer, down about 1 percent from summer 2025 — a modest decline that masks significant regional divergence. Northeast gas trading hubs are expected to price notably higher than Henry Hub because a cold 2025–2026 winter drew storage inventories below their five-year average range across New England and the Mid-Atlantic. That storage deficit will keep basis spreads elevated until late-summer injections rebuild cushion.

The West faces the opposite dynamic. A mild winter left western storage facilities above normal, pushing West Coast basis prices lower. The regional spread between constrained Northeast prices and well-supplied western prices is expected to be one of the wider basis differentials of the past several summers.

Aggregate peak demand across all assessment areas has grown by more than 11 GW compared to summer 2025 projections — exceeding the 10 GW year-on-year rise that preceded last summer. Electrification of buildings and transportation accounts for part of that growth, but the larger uncertainty is large-load interconnections, particularly data centers.

Multiple assessment areas have revised their forecasts downward from mid-2025 estimates to account for slower-than-expected completion rates for large load interconnections. But the directional trend is not in doubt: data center demand is rising faster than grid planners can reliably model. FERC Chairman Laura Swett noted that even the possibility of slower data-center buildout is not causing the Commission to ease its focus on large-load grid upgrades — the planning risk is asymmetric.

An additional timing risk has emerged this year. An early arrival of summer heat in March highlighted how maintenance outages planned for the mild spring shoulder season can overlap with unexpectedly high demand. If maintenance windows are not cleared before sustained heat arrives, the effective reserve margin at peak can be materially lower than the nameplate figures suggest.

Wholesale electricity prices are expected to average $46.81 per MWh nationally this summer, down 5 percent from a year ago — a reflection of the capacity overbuild in much of the country. Regional variation is wide: the Northwest is projected to see prices fall by up to 41 percent year-on-year because of the capacity additions, while ERCOT is projected to see prices rise about 11 percent driven by high demand and tighter afternoon reserve margins when solar output ramps down.

The practical read for energy traders and planners: Summer 2026 is the most supply-adequate in recent years under normal weather, but the tail risk from a prolonged heat dome — particularly in the West, where hydro is constrained and transmission is already operating closer to its limits — remains the dominant event risk for the season.

All figures and findings in this article are drawn directly from the official FERC and NERC publications listed below.