When the New York Independent System Operator (NYISO) forecast its slimmest reliability margin in recent history ahead of summer 2026, the immediate story was a local one: a single transmission line, the Champlain Hudson Power Express, went offline during a July heat wave, removing 1,250 megawatts (MW) of imported hydropower right as demand peaked. NYISO leaned on reserve peaker plants to cover the gap, and the lights stayed on. But the tight margin that made that near-miss possible is not unique to New York. It is a pattern now showing up across nearly every regional grid in the country. The North American Electric Reliability Corporation (NERC), which assesses reliability for the entire U.S. and Canadian bulk power system, found in its 2026 Long-Term Reliability Assessment that 13 of 23 regional assessment areas face elevated or high risk of resource shortfalls within the next five years. Summer peak demand is now projected to climb 224 gigawatts (GW), or 24%, over the next decade, a forecast that itself jumped 69% from just a year earlier. Understanding why reserve margins are narrowing nationwide, not only in New York, requires looking at both sides of the ledger: how fast demand is growing, and how slowly new firm supply is arriving to match it.
NERC’s 2026 assessment describes the fastest demand growth the organization has tracked since it began compiling data in 1995. Winter peak demand is expected to rise by roughly 245 GW over the same ten-year window, edging out even the summer figure. The increases are not evenly distributed across sectors. In PJM Interconnection, the largest U.S. grid operator by footprint, an executive attributed the bulk of a recent demand forecast jump, about 5,250 MW, almost entirely to data centers. The International Energy Agency’s Electricity 2026 report points to a similar pattern globally and domestically: global electricity demand is set to grow at an average annual rate of 3.6% through 2030, roughly 50% faster than the prior decade’s average, and data centers account for around half of the total increase in U.S. electricity demand through 2030. Several forces are converging at once:
No single driver explains the shift on its own. It is the combination arriving within the same five-year window that is straining planning assumptions built for a slower-growth era.
On the supply side, the picture is mixed rather than a straightforward story of decline. U.S. coal-fired retirements actually slowed sharply in 2025: the power sector retired just 2.6 GW of coal capacity, the least since 2010 and a fraction of the 13.7 GW retired in 2022, according to the U.S. Energy Information Administration (EIA). Of the 8.5 GW of coal capacity originally planned for retirement in 2025, 4.8 GW was pushed to future years, 1.1 GW was cancelled outright, and roughly 3.24 GW was kept online under U.S. Department of Energy emergency orders issued under Section 202(c) of the Federal Power Act. Plants once scheduled to close are, in many cases, still running. Even so, NERC’s assessment still counts more than 105 GW of confirmed and announced retirements over the coming decade, a reminder that today’s delays push the resource-adequacy question further out rather than resolving it. New firm generation is not moving fast enough to offset that eventual loss: natural gas projects in the development queue total roughly 53 GW of new winter-rated capacity, while battery storage, wind, and solar additions in 2024 and 2025 combined added about 23 GW against 21 GW of retired fossil capacity over the same period, a narrow net gain relative to the demand growth on the other side of the ledger.
Wholesale capacity markets are pricing this tightening in real time. PJM’s most recent base residual auction cleared at $333.44 per megawatt-day for the 2027-28 delivery year, up slightly from $329.17 the year before, but only because a temporary price cap held it down; without that cap, analysts at Jefferies estimated the price would have reached nearly $530 per megawatt-day, about 60% higher. The auction procured 145,777 MW against a 20% installed reserve margin target, a shortfall of roughly 6,625 MW, or 5.2 percentage points below target, and total auction costs reached $16.4 billion, up from $16.1 billion the prior year. Regionally, NERC flags MISO, PJM, ERCOT, and the WECC-Basin and WECC-Northwest sub-regions as facing elevated-to-high resource adequacy risk at specific points before 2030, with exact timing varying by each region’s load growth and retirement schedule. Transmission expansion, which could relieve some of this pressure by moving power between regions, is itself constrained: NERC counts roughly 41,000 miles of transmission projects under construction or in planning, spread across nearly 900 identified projects, of which almost 400 are already running behind schedule. Building new lines and new generation are both multi-year undertakings, which is part of why grid planners describe the next five years as the period of greatest exposure.
Taken together, the data describes a grid under structural strain rather than a series of isolated regional incidents. Demand is growing faster than at any point since NERC began tracking it three decades ago, driven substantially by data centers and electrification. Supply is not standing still: generator retirements are being delayed, new gas capacity is in development, and renewables and storage continue to be added at scale. But net additions are not yet outpacing peak demand growth across most regions, and the transmission projects that could help balance supply and demand between regions face delays of their own. None of this points to a single cause or a single fix; it reflects a grid built for a slower-growth era now absorbing a much faster one. Grid operators, utilities, and regulators across the country are responding with a mix of tools, including capacity market redesigns, extended plant lifespans, accelerated interconnection processes, and demand-response programs, aimed at closing the gap before it produces the kind of near-miss NYISO described in its own service territory this past summer. For any organization that depends on a stable, affordable power supply, the reserve-margin trend is now a national one worth watching closely, not a regional curiosity.
