The North American electric grid faces intensifying reliability risks over the next decade as demand growth driven by data centers and artificial intelligence threatens to outpace resource additions, according to the 2025 Long-Term Reliability Assessment (LTRA) released Jan. 29 by the North American Electric Reliability Corporation (NERC).
The assessment, which covers 2026 to 2035 and models known system changes, projects that summer peak demand could climb by 224 GW over the next 10 years—a 69% increase over last year’s projection. Winter demand could surge even more, by 245 GW, NERC reported. Data centers for artificial intelligence and the digital economy account for most of the projected increase, the report suggests, though it also considers large industrial loads, transportation electrification, cryptomining, heat pumps, and demographic changes as “primary drivers.”
NERC identified 13 of 23 assessment areas facing resource adequacy challenges, with regions including MISO, PJM, Texas RE-ERCOT, SERC-East, and multiple areas in the Northeast and Western Interconnections classified as elevated or high risk. The assessment represents a snapshot based on mid-2025 data showing current system plans struggling to keep pace with rapidly accelerating electricity needs.
“This assessment is not a prediction of failure but an early warning on the trajectory of risk,” said John Moura, NERC’s director of Reliability Assessment and Performance Analysis. “The path forward is still manageable but only if planned resources come online and on time.”
The heightened risk stems from multiple converging factors. Planned generator retirements total 105 GW of peak seasonal capacity over the next decade—though this figure has declined 10 GW from last year’s projections as utilities delay deactivations in response to growing demand. Meanwhile, interconnection queues continue swelling with uncertainty surrounding the timing and magnitude of new resource additions.
“The challenge is not a lack of effort,” Moura said during a media briefing. “It’s really the pace and scale of the system transformation occurring at the same time as demand growth accelerates.”
Resource Mix Transformation Accelerates
NERC officials noted the grid’s resource composition is shifting dramatically toward weather-dependent technologies. From 2024 to 2025, fossil-fueled generator capacity fell 21 GW while battery, wind, and solar resources increased 23 GW in peak-hour capacity.
Battery storage projects have surged in interconnection queues to match solar photovoltaic projections, with the two technologies together representing two-thirds of Tier 1 and Tier 2 resources planned over the next decade, according to the assessment. Natural-gas-fired generator additions represent 15% of projected capacity additions at 53 GW, followed by wind and hybrid resources at 8% each.
Mark Olson, NERC’s manager of Reliability Assessments, emphasized the changing winter risk profile during the briefing. “There’s a lot of solar and batteries in the resource mix,” Olson said. “Those provide good capability for meeting summer peak demand, but the capability of resources in the winter is very different.”
The assessment shows a growing mismatch between seasonal demand patterns and resource characteristics. Solar output approaches zero during winter peak hours—typically 6 a.m. to 6 p.m.—while batteries face charging limitations during extended cold periods. The seasonal vulnerability increases supply shortfall risks during extreme winter weather, particularly as natural-gas-fired generation becomes more critical but faces fuel delivery constraints.
MISO faces particularly acute challenges, with resource additions failing to keep pace with escalating demand forecasts and announced retirements. The region begins meeting elevated-risk criteria in 2027 and transitions to high-risk status by winter 2028, though the recently approved Expedited Resource Addition Study process is expected to bring additional resources beginning in 2028 that were not included in the assessment model.
At PJM, summer peak demand is expected to grow 56 GW to reach 210 GW by 2035, while winter demand could climb 62 GW to 198 GW by winter 2034–35. The region’s anticipated resource margin falls below its Installed Reserve Requirement starting in 2029, though recently approved generation projects under the Reliability Resource Initiative were not sufficiently advanced for inclusion in the risk analysis.
Texas RE-ERCOT showed improved probabilistic unserved energy metrics for 2026–2027 compared to last year’s assessment, but continued rapid load growth outpaces projected resource additions in later years. Texas lawmakers have granted ERCOT operators curtailment authority over new large loads to prevent grid emergencies and established funding programs to expedite resource additions.
SERC-East faces supply shortfalls during below-normal winter temperatures, with current resource addition projections unable to match escalating demand forecasts and planned generator retirements.
Grid operators and regulators have accelerated efforts to address mounting adequacy concerns. Expedited resource programs approved by the Federal Energy Regulatory Commission in late summer 2025 for MISO, PJM, and Southwest Power Pool prioritize resources addressing identified reliability risks, though most additions from these programs were not included in the 2025 assessment.
“The programs are stimulating resource development,” Olson said. “There’s clearly a need for these programs to meet the shortfalls that we’re projecting.”
Market mechanisms including capacity accreditation are more precisely highlighting loss-of-load risks from generation mixes with increasing variable resources, making market procurements more effective. Generator retirement projections have moderated as utilities extend service lives for existing units, with integrated resource plans adjusted to address growing demand.
Natural Gas Infrastructure Concerns Grow
The grid’s increasing reliance on natural-gas-fired generation—with 13 of 23 assessment areas adding gas capacity over the next decade—raises fuel assurance challenges. The assessment notes significant uncertainty around generators securing firm fuel supply and transportation arrangements, particularly during extreme cold weather when residential heating demand surges.
Moura contrasted U.S. arrangements with Canadian practices during the briefing. “If you look at an area like Canada, 97% of electric generation has firm rights to gas,” Moura said. “It’s unheard of to have so much interruptible gas, especially when it underpins some of our national strategies around electricity dominance and AI dominance.”
Florida’s natural gas fleet demonstrates a successful model with pipelines built specifically for electric generators with firm service and dual-fuel capability requirements, Moura noted, suggesting these practices should be replicated in other regions.
Transmission projections reflect increased development, with 41,000 miles of projects above 100 kV under construction or in planning stages for the next decade—substantially higher than last year’s 28,275-mile projection. Several Planning Coordinators including Hydro-Québec, ERCOT, SPP, MISO, PJM, BC Hydro, and Ontario’s Independent Electricity System Operator have approved or are contemplating expansive extra-high voltage overlays.
However, transmission development faces significant headwinds. Of nearly 900 projects under construction or in planning, at least 390 have been delayed from originally expected in-service dates due to permitting issues, supply chain constraints, and planning challenges.
Interregional transmission projects supporting energy transfers between neighboring systems represent just 4% of total projects—down from 6% in last year’s assessment—despite their importance during extreme weather events.
Load Forecast Uncertainty Adds Complexity
Data center and large-load projections introduce volatility into demand forecasts as project timelines vary with construction, permitting, grid development, and developer decisions. ERCOT and PJM have both prepared revised load forecasts since the assessment’s mid-2025 data collection period, showing some near-term projects slowing while later-year interconnection requests continue increasing.
“We’re taking quite a bit of a haircut and looking at what’s reasonably expected to come in,” Moura said, emphasizing NERC’s conservative approach. “That uncertainty and what we know about the magnitude of load growth is increasingly uncertain and its impact on planning is going to have significant risk.”
NERC’s recommendations call for integrated resource planners, market operators, and regulators to expedite new resources and carefully manage generator deactivations through enhanced mechanisms and early retirement identification. The assessment urges regulators and policymakers to streamline siting and permitting processes, noting these issues rank among the most common causes for delayed transmission projects.
The reliability organization recommends continued collaboration between electric and natural gas industries on interconnected system planning and operations, with stakeholders urged to implement solutions with urgency. Regional transmission organizations, independent system operators, and FERC should continue ensuring essential reliability services are maintained as the resource mix transforms.
“We must accelerate the right resources, not just the megawatts,” Moura said. “We have to look at the energy components to the resources that we’re building. We must treat large loads as part of system planning, not just demand forecasts.”
The assessment emphasizes that while the risk trajectory is rising, the window to shape outcomes remains open. “The question is no longer whether the change is coming,” Moura concluded. “It’s whether the infrastructure and coordination can keep pace.”
—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).
Editor’s Note: This story is actively being updated and subject to change. We encourage you to revisit this article or check our website for the latest updates.
