NERC Flags Shrinking Reserves as Coal and Gas Outage Rates Climb
Conventional generation availability fell in 2025 as forced outages from coal and gas plants rose sharply, squeezing the grid's buffer heading into peak summer demand.
The North American Electric Reliability Corp. said on Thursday (2026-06-25) that deployable generation reserves shrank in 2025, driven by a combined 58.9 TWh jump in unavailable energy from coal and gas plants — a finding that puts a number on the reliability cost of an aging conventional fleet struggling to keep pace with rising load.3
Coal forced outages accounted for 39.8 TWh of that increase, gas for 19.1 TWh, according to NERC's 2026 State of Reliability report. Together they represent a measurable erosion of the conventional buffer that grid operators depend on when demand spikes or variable renewables underdeliver.3
The report arrives as NYMEX Henry Hub front-month natural gas traded near $3.27 on Thursday (2026-06-25). Low fuel cost supports gas-fired generation economics but does nothing to address the mechanical reliability issues NERC has flagged. Fuel availability and plant availability are separate problems.
Data center exposure to these reliability gaps is already visible in the data. Two separate events in February 2025 required customer-initiated load reduction from data center operators in the Eastern Interconnection: one transmission fault triggered 1.8 GW of CILR, and a second event in the same month resulted in 428 MW. NERC cited both incidents in its 2026 report as evidence that data center load is now a material grid variable.3
The scale of those February 2025 reductions matters. Power purchase agreements increasingly carry interruptibility provisions, but 1.8 GW of reduction at a single event is at the upper range of what grid operators typically see from traditional demand-response programs. The fact that it happened twice in one month in the same interconnection suggests the margin was already thin before summer load arrived.3
On the gas side, the EIA projected in May 2026 that US Lower 48 marketed gas production would average 117.2 billion cubic feet per day in the first quarter of 2026, up 4% from the same period in 2025. The agency expected Permian output to reach 29.2 Bcf/d this year, 6% above 2025 levels. That trajectory points to adequate fuel supply for gas generators. The NERC finding therefore identifies plant-level mechanical performance as the binding constraint — not feedstock.1
The coal picture has a structural dimension. Existing North American coal capacity is aging, its forced outage rate is climbing, and the effective dispatchable fleet is shrinking even before further retirements are counted. Globally, the IEA's Electricity 2026 report published in May 2026 projected coal's share of the generation mix would erode as renewables and nuclear collectively approached 50% of world power by the end of the decade, with global power demand growing at more than 3% annually. But NERC's reliability data makes clear that the transition corridor — the period when conventional plants are needed to backstop intermittency — is becoming harder to manage as aging equipment degrades.2
Grid operators in regions with high coal and gas retirement exposure face a narrowing margin between peak load forecasts and the generation actually available to serve them. NERC's report does not break out which regions saw the sharpest outage rate increases, but the Eastern Interconnection's back-to-back data center CILR events in February 2025 point to at least one area where the buffer has thinned enough to require active demand-side management during a winter event, not just a summer peak.3
The reserve margin question will sharpen through July and August 2026, when cooling load and generation stress hit their annual highs across the Eastern Interconnection. If coal and gas forced outage rates remain at 2025 levels or worsen — as the aging fleet trend suggests they might — grid operators will have less conventional headroom than nameplate capacity implies. Data centers with interruptible contracts should expect more calls on that flexibility before the season ends.3