NERC's 2026 Summer Reliability Assessment, released May 19, found that more than 58 gigawatts of new generation has come online across North America since last summer, led by 16.4 GW of solar and 14.7 GW of battery storage, with 6.7 GW of natural gas and 1.6 GW of wind rounding out the total. That build-out is real, and it moved the needle: the number of regions NERC classifies as facing elevated risk of summer shortfalls dropped from six last year to three this year, and the Texas grid operator, flagged as a concern in 2025, is now rated adequate for normal conditions. On its face, the report reads as good news for any facilities or energy team that spent last summer watching grid alerts.
The assessment does not incorporate an important parallel development. The improvement in this year's numbers is overwhelmingly the result of record additions of solar, battery storage, and natural gas capacity, exactly what NERC credits it to. But since May 2025, the Department of Energy (DOE) has also issued numerous emergency orders and extensions under Section 202(c) of the Federal Power Act, a provision historically reserved for hurricanes and other short-notice emergencies, directing utilities to keep several coal plants operating beyond their planned retirement dates. Those orders have collectively stalled the retirement of roughly 4 gigawatts of coal capacity that utilities and grid operators had already scheduled to shut down, in some cases after the relevant grid operator had reviewed the retirement and found no reliability problem with it. None of that capacity is counted among NERC's anticipated new resources. It sits alongside the assessment as an additional layer of temporary reliability cushion that was never intended to be permanent.
Why Three Regions Still Made the Watch List
New England, the Pacific Northwest, and the Canadian province of Saskatchewan are the three areas NERC flagged as carrying elevated risk of shortfalls under above-normal or extreme summer conditions. New England's exposure comes from declining firm import commitments from neighboring systems, which pushes the region toward greater reliance on non-firm power precisely when demand is highest. The Pacific Northwest's risk is a hydropower story: below-normal snowpack and drought conditions are cutting into a resource the region has historically treated as a reliability anchor. NERC's director of reliability assessment and system analysis, John Moura, told reporters on a call about the assessment that the improved conditions should not be read as reliability risk declining broadly, even as specific regions posted real gains.
The Orders Behind the Numbers
The Section 202(c) orders follow a pattern. Michigan's J.H. Campbell plant, a 1,331-megawatt coal facility that Consumers Energy had planned to retire 15 years ahead of its original schedule, is now on its fourth consecutive 90-day extension under an order first issued in May 2025, even though MISO had approved the original retirement in March 2022 and found no reliability problem with it at the time. Washington's Centralia Unit 2 and a pair of Indiana coal units at Northern Indiana Public Service Company followed similar paths in late 2025. The U.S. Energy Information Administration (EIA) reports that utilities planned to retire 12.3 gigawatts of coal capacity in 2025 but actually retired only 4.6 gigawatts, the smallest annual total since 2008, largely because DOE orders kept several large plants online past their scheduled closures. Each order runs for 90 days before requiring renewal, a cadence that does not match how facilities and energy teams underwrite multi-year capital plans or negotiate long-term power contracts.
The Trend the Summer Snapshot Skips
NERC's separate Long-Term Reliability Assessment, released January 29, points to a steeper problem than any single summer. It projects summer peak demand will grow by 224 gigawatts over the next decade, 69% higher than the 132 GW growth the same assessment projected just one year earlier, with winter peak demand growth climbing even faster at 245 GW. Both figures represent the highest compound annual growth rates NERC has recorded since it began tracking the data in 1995. Thirteen of the 23 regions NERC assesses face elevated or high resource adequacy risk within the next five years, including MISO, PJM, ERCOT, and the WECC Northwest and Basin regions. MISO alone expects summer peak demand to reach 127 GW this year and climb to nearly 144 GW by 2035, with data centers accounting for 18 GW of that growth, even as the region's accredited thermal capacity has already fallen by 8.8 GW.
What This Means for Capital and Contract Planning
For a facilities or energy team evaluating a multi-year expansion, the distinction between "adequate resources" and "resources that include plants running on temporary federal orders" is not academic. A 90-day extension is not the same commitment as a utility's own integrated resource plan, and companies that have built site-selection or expansion timelines around this summer's improved numbers are, in effect, borrowing reliability from a source that could be withdrawn on short notice. Distributed energy resources are increasingly filling part of that gap, and the same load growth pressure is already showing up in how manufacturers and data center developers compete directly for substation capacity in constrained regions. Companies that treated last year's grid availability risk as a temporary planning variable rather than a structural one are the ones most likely to be caught short when a 202(c) order lapses instead of renews. The assessment suggests the grid has gained time to address longer-term resource adequacy challenges, but some of that flexibility depends on emergency measures that were never intended to be permanent.
