NERC's 2026 Reliability Assessment: Key Warnings
The North American Electric Reliability Corporation's most recent long-term reliability assessment paints a concerning picture for the U.S. electrical grid in 2026 and beyond. NERC, the entity responsible for overseeing the reliability of the bulk power system across North America, has identified elevated risk across multiple regions due to the convergence of accelerating demand growth, generation retirements, and the increasing penetration of intermittent renewable resources without sufficient dispatchable backup capacity.
The assessment warns that several major grid regions — including the Midcontinent Independent System Operator territory, the Western Interconnection, the Electric Reliability Council of Texas, and the PJM Interconnection — face heightened risk of capacity shortfalls during extreme weather events. These warnings are not theoretical: the 2021 Texas winter storm, the 2022 winter storms in the Southeast, and the 2023 heat waves across the Southwest all demonstrated that grid reliability failures have real and costly consequences for commercial building operations.
For commercial property owners and operators, NERC's warnings translate into tangible operational risks. Grid reliability failures can cause building system outages, trigger demand response program activations, create utility billing anomalies, and in worst-case scenarios, result in extended power interruptions that disrupt tenant operations, damage equipment, and create liability exposure. Understanding the drivers of grid reliability risk is essential for developing mitigation strategies that protect building operations and financial performance.
Demand Growth: Data Centers, EVs, and Electrification
After two decades of relatively flat electricity demand growth in the United States, the grid is now facing a surge in new load that is straining generation and transmission capacity planning. Three primary demand drivers are converging to create what grid operators describe as an unprecedented planning challenge: the explosive growth of data center construction, the accelerating adoption of electric vehicles, and the policy-driven electrification of building heating systems.
Data center demand alone accounts for the most dramatic near-term load growth. The expansion of artificial intelligence workloads, cloud computing, and digital infrastructure has triggered a wave of data center development across the country. A single hyperscale data center campus can consume 100 to 300 megawatts of electricity — equivalent to the power consumption of a small city. The pipeline of announced data center projects in regions like Northern Virginia, Central Ohio, and the Dallas-Fort Worth metroplex represents tens of gigawatts of new demand that utilities must plan to serve within the next three to five years.
Electric vehicle adoption is adding another layer of demand growth. As EV penetration increases, the aggregate charging load adds significant new demand to the grid, particularly during evening hours when residential charging peaks coincide with building cooling loads in summer months. Workplace charging installations at commercial properties add daytime load that can affect building-level demand charges and create localized distribution system constraints.
Building electrification policies in major cities — requiring heat pump installations in new construction and major renovations — are shifting heating loads from the gas system to the electric grid. While heat pumps are significantly more efficient than electric resistance heating, the aggregate impact of converting millions of buildings from gas to electric heating creates substantial new winter peak demand that the grid was not historically designed to serve.
Generation Retirements and the Capacity Gap
On the supply side, the grid is facing an accelerating wave of generation retirements that is not being offset by sufficient new dispatchable capacity. Coal-fired power plants, which historically provided reliable baseload generation, are retiring at an unprecedented rate due to age, environmental regulations, and unfavorable economics relative to natural gas and renewable alternatives. Between 2020 and 2030, an estimated 80 to 100 gigawatts of coal-fired capacity is projected to retire across the United States.
While renewable energy installations have grown dramatically — with solar and wind now representing the majority of new generation capacity additions — these resources are intermittent and cannot be dispatched on demand. A gigawatt of solar capacity provides approximately 20 to 25 percent of the energy output of a gigawatt of dispatchable coal or gas capacity, meaning that significantly more nameplate capacity must be installed to replace the energy and reliability services provided by retiring baseload plants.
Natural gas generation has served as the primary bridge between coal retirements and the renewable future, but new gas plant construction faces its own challenges. Permitting timelines have extended significantly, environmental opposition has increased, and the long- term economic viability of gas plants is uncertain given state-level clean energy mandates that may limit their operating lifetimes. Battery storage, while growing rapidly, is not yet deployed at the scale needed to provide multi-hour duration support during extended periods of low renewable output or extreme weather events.
The result is a capacity gap — a growing margin between available dispatchable generation and peak demand that manifests as reliability risk. NERC's assessment highlights regions where this gap is most acute, but the underlying drivers of demand growth and supply retirements are national in scope.
Aging Infrastructure and Extreme Weather
Beyond the generation-demand balance, the physical infrastructure of the grid itself is under increasing stress. The average age of transmission lines in the United States exceeds 40 years, and many critical components were designed for load levels and weather conditions that no longer reflect current reality. Transformers, which are among the most critical and difficult-to-replace components of the grid, have lead times of 18 to 36 months for new orders, and the global supply chain for large power transformers remains constrained.
Extreme weather events are occurring with greater frequency and intensity, putting stress on grid infrastructure that was designed for historical climate conditions. Wildfires in the Western states have forced utilities to implement public safety power shutoffs that can leave commercial buildings without electricity for days at a time. Hurricane seasons have become more active, with major storms causing grid damage that takes weeks to fully repair. Winter storms in regions that historically experienced mild conditions have revealed vulnerabilities in gas supply systems and power generation equipment that was not designed for sustained extreme cold.
Distribution-level infrastructure is equally vulnerable. Local substations and feeder circuits that serve commercial buildings are increasingly being asked to accommodate two-way power flows from distributed solar, rapid demand fluctuations from EV charging, and peak loads that exceed their design capacity. These distribution- level constraints can create localized reliability problems even when the bulk power system has adequate generation and transmission capacity.
Financial Impact on Commercial Buildings
Grid reliability risks translate into specific financial impacts for commercial building owners and operators. The most direct costs come from power interruptions: equipment damage, spoiled inventory, lost tenant productivity, emergency generator fuel, and potential lease clause activations that provide tenants with rent abatement during extended outages. For a large office building, a multi-day power interruption can result in losses measured in hundreds of thousands of dollars.
Less visible but equally significant are the costs associated with grid stress events that stop short of full outages. Voltage fluctuations and power quality issues can damage sensitive electronic equipment, cause HVAC system malfunctions, and trigger building automation system faults that require expensive service calls. Demand response program activations, while voluntary, often carry financial penalties for non-participation and can disrupt building operations by requiring load curtailment during critical business hours.
Utility rate impacts from grid reliability investments are also substantial. As utilities invest in grid hardening, transmission upgrades, and capacity additions to address reliability concerns, these costs flow through to ratepayers as rate increases. The American Society of Civil Engineers estimates that the United States needs approximately $2.6 trillion in grid infrastructure investment over the next decade, and a significant portion of this investment will be recovered through commercial electricity rates.
Insurance costs are another financial channel. As grid reliability events become more frequent, insurance underwriters are adjusting their risk models for commercial properties, potentially increasing premiums for buildings in high-risk grid areas or requiring additional backup power capabilities as a condition of coverage.
Mitigation Strategies for Building Owners
Commercial building owners can take several concrete steps to mitigate the financial and operational risks associated with declining grid reliability. The foundation of any mitigation strategy is comprehensive utility data visibility — the ability to monitor consumption patterns, identify anomalies, and understand how grid events affect building operations in real time or near real time.
On-site generation and storage represent the most direct physical mitigation. Backup generators, while commonplace in critical facilities, are increasingly being considered for standard commercial buildings as reliability risks increase. Battery energy storage systems provide a more flexible alternative, offering backup power during outages, demand charge reduction during normal operations, and the ability to participate in utility demand response programs that generate revenue during grid stress events.
Building automation and load flexibility are important operational mitigations. Buildings with sophisticated BAS systems can automatically curtail non-critical loads during grid emergencies, reducing the risk of equipment damage from voltage sags and helping the grid maintain stability. Pre-cooling and pre-heating strategies that shift thermal loads away from peak periods can reduce both demand charges and the building's exposure to grid stress events.
For portfolio owners, understanding the grid reliability profile of each property is essential for risk management. Properties in regions identified by NERC as high-risk deserve particular attention, and the cost-benefit analysis for backup power, storage, and building automation investments should be calibrated to the specific reliability risk at each location. Centralized utility data management that provides portfolio-wide visibility into consumption patterns, demand profiles, and billing anomalies is the information infrastructure needed to make informed decisions about grid reliability mitigation across a diverse portfolio of commercial properties.