The North American grid handles regional emergencies by moving power from areas with surplus to areas under stress. That mutual aid architecture has held through dozens of crises since the 2003 Northeast blackout. It works because most emergency events are geographically isolated. What it was not designed to handle is simultaneous high-stress conditions across multiple interconnected regions. That scenario is no longer theoretical.

The North American Electric Reliability Corporation (NERC) released its 2026 Long-Term Reliability Assessment (LTRA) in January, placing 13 of 23 North American assessment areas at elevated or high resource adequacy risk over the next five years. NERC's director of Reliability Assessment and Performance Analysis described the demand growth projections as some of the highest the organization has tracked since it began collecting data in 1995. For executives building operational and financial plans against infrastructure assumptions, the document deserves a careful read beyond the headline risk numbers.

NERC's 2026 LTRA Identifies Six High-Risk Regions Spanning Three Grid Interconnections

The regions NERC classified as high risk include the Midcontinent Independent System Operator (MISO), PJM Interconnection (PJM), the Electric Reliability Council of Texas (ERCOT), the Western Electricity Coordinating Council's (WECC's) Northwest subregion, the WECC Basin subregion, and the SERC-Central region covering parts of the South and Midwest. These regions are not isolated from each other. MISO and PJM share a significant seam. ERCOT operates as a largely separate interconnection but draws on neighboring systems during emergencies through limited DC ties. The WECC regions share transmission corridors and coordination protocols across the western interconnection.

NERC projects summer peak demand across North America to rise by approximately 224 gigawatts (GW) by 2035. That figure is 69% higher than NERC's own projection from the previous year's assessment, driven primarily by data center and AI infrastructure load growth. MISO alone is projecting its peak summer internal demand at 127 GW in 2026, growing to 143.7 GW by 2035, while accredited thermal capacity in that region has declined by 8.8 GW since the prior assessment.

How Cascade Failures Actually Develop Across Interconnected Systems

The August 2003 Northeast blackout started with a software bug at a single Ohio utility and a transmission line contact in the same area. Within minutes, 55 million people across eight U.S. states and the Canadian province of Ontario lost power. The cascade was not caused by catastrophic equipment failure across the whole region. It was caused by a series of individually manageable events that compounded faster than operators could respond, in a system that was already running at high utilization.

The February 2021 Texas event followed a different path but the same logic. The Electric Reliability Council of Texas lost over 30 GW of generation capacity during Winter Storm Uri. Neighboring systems in the Southwest Power Pool (SPP) and MISO provided what assistance they could, but both were managing their own demand spikes from the same cold event. The available mutual aid was not enough to prevent the shortfall that left millions of Texans without power for days. The lesson is not that mutual aid is unreliable. It is that mutual aid has a ceiling, and that ceiling becomes visible when the triggering event affects multiple regions simultaneously.

Summer 2026 Risk Conditions Across MISO, PJM, and ERCOT Simultaneously

All three of those regions are in NERC's elevated or high risk category heading into summer 2026. MISO's accredited thermal capacity has declined at the same time demand forecasts have risen. PJM's new interconnection cycle opened in April 2026 with a one-to-two year review timeline, meaning new capacity approved today will not be online for this summer. ERCOT is projecting a summer peak of 94,650 MW for 2026, up from prior years, with the majority of recent capacity additions concentrated in solar, which ramps down precisely as evening heat events push demand to its daily peak.

None of this means a multi-region failure event is likely this summer. NERC explicitly frames its assessments as risk identification documents, not failure forecasts. What it does mean is that the conditions supporting a simultaneous multi-region stress event are present in a way they have not been in recent memory. The planning question is not whether your region will have a problem. It is what your operational continuity plan assumes about neighboring regions when your own region has a problem.

Business Continuity Plans Built Around Single-Region Assumptions Have a Structural Gap

Most corporate business continuity and operational resilience frameworks model grid outage scenarios based on historical events in a specific service territory. They assume that a regional utility disruption will eventually be resolved through mutual aid, with restoration timelines measured in hours rather than days. That assumption is reliable when the event is geographically contained. It becomes unreliable when the utility handling the restoration is simultaneously fielding mutual aid requests from multiple neighboring systems.

Organizations with operations in more than one NERC high-risk region should map each facility against its regional grid operator and model what an isolated-region restoration scenario looks like. The question for the executive team is not whether backup power is available at the facility level. It is what happens to operational sequencing, supply commitments, and customer SLAs if restoration in one region takes five times longer because the neighboring grid cannot provide assistance. That is a different conversation than the one most continuity plans are currently built around.

The Window for Proactive Planning Closes When the First Alert Arrives

MISO, ERCOT, and PJM all operate demand response programs with enrollment windows and advance notice requirements. Grid operators issue emergency alerts in real time, and organizations that receive those alerts without pre-established load prioritization protocols and supplier communication plans are making decisions under pressure rather than against a plan. The practical implication of NERC's 2026 data is not panic. It is a prompt to verify, before the first heat event of the season, that the continuity assumptions built into your operational plan reflect a grid environment that is materially different from the one those plans were written around.