NERC’s Summer Grid Outlook Shows Progress, But Elevated Risks Persist as Load Growth Outpaces Flexibility

All regions across the North American bulk power system (BPS) are generally positioned to meet peak demand under normal summer conditions, though elevated risks of electricity supply shortfalls could persist under extreme heat, surging demand, and resource variability, the North American Electric Reliability Corp. (NERC) warns.

In its May 14–released 2025 Summer Reliability Assessment (SRA), NERC once again presented a reliability picture ridden with complexity, highlighting how accelerating load growth, shrinking dispatchable capacity, and the rapid transition to variable resources are reshaping grid dynamics and elevating supply shortfall risks under extreme conditions.

“Summer used to mean flip flops, cold drinks, and maybe a little too much sun. But these days it really means demand curves, battery state of charge levels, and wondering if the heat dome will finally move on,” John Moura, NERC’s Director of Reliability Assessment and Performance Analysis, told reporters in a briefing on Wednesday. “So yes, summer has changed, but so is the grid, and while we continue to see the North American grid that’s growing, it’s being stretched. And as demand expands, grid planners and operators are doing more than ever, but they’re doing it under tighter reserve margins.”

Moura noted that while the grid continues to evolve, with more solar, batteries, and emerging technologies being added, “the pace and performance of that build-out doesn’t yet fully align with the reliability needs of a rapidly electrifying economy. As the sun goes down and the solar fades, if batteries aren’t fully recharged, especially under persistent heat domes, we can find ourselves in really tight spots.”

Extreme Heat and Weather Amplify Grid Reliability Risks Despite Resource Gains

This year, as much of North America braces for above-average summer temperatures, compounded by drought in key regions, the risk of wide-area heat events impacting both generation performance and transmission capacity remains high on NERC’s radar. While substantial resource additions, particularly solar and battery storage, have improved overall resource adequacy for normal conditions, extreme weather continues to present a “hyper-complex” risk environment where coinciding demand spikes, resource variability, and transmission bottlenecks can converge to stress grid reliability.

The SRA, notably, suggests elevated risks of electricity supply shortfalls emerge under plausible extreme conditions in six regions: MISO, NPCC-New England, MRO-SaskPower, SPP, ERCOT, and WECC-Mexico. Risks stem from a combination of accelerating load growth, declining dispatchable capacity, increased reliance on variable renewables, and regional transmission constraints, the report shows.

MISO—August May Be Precarious. The Midcontinent Independent System Operator (MISO) faces an elevated risk of operating reserve shortfalls particularly during August as dispatchable generation declines and variable resource dependence grows, the SRA says.

MISO’s available capacity has declined to 142,793 MW, down from 143,866 MW in 2024, precipitated by the retirement of 1,575 MW of natural gas and coal-fired generation. A reduction in net firm capacity imports poses more complexity, further constraining dispatchable availability, given that external resources opted out of MISO’s planning resource auction. Under extreme conditions, MISO’s projected reserve margins could fall to -1.9%, compared to 24.7% under normal scenarios, NERC reported.

“MISO’s most recent energy assessment revealed that the period of highest energy shortfall risk has shifted from July to August,” said Mark Olson, NERC’s Manager of Reliability Assessments. “This shift is driven by the decline in dispatchable generation and the increasing share that solar and wind resources have in meeting demand. The risk of supply shortfalls increases in late summer as solar output diminishes earlier in the day, leaving variable wind and a more limited amount of dispatchable resources to meet demand.”

ERCOT Grappling With Evening Net Peaks. NERC’s reliability outlook for the Electric Reliability Council of Texas (ERCOT) appears to have improved with substantial additions of 7 GW of solar PV and 7.5 GW of battery storage. That has lowered the probabilistic risk of Energy Emergency Alerts (EEAs) during August evening peaks to 3%, down from over 15% in 2024.

But, system constraints remain, notably linked to the South Texas Interconnection Reliability Operating Limit (IROL). According to the SRA, “Specific unlikely conditions could ultimately require ERCOT system operators to direct firm load shedding to remain within IROL limits and prevent cascading load loss.” Mitigation measures should include dynamic transmission line ratings and switching actions to divert power flows, it suggests.

According to Olson, “battery storage additions have had a significant impact” in Texas. “What we’re seeing is that they’re providing critical energy support during evening hours when solar generation ramps down. However, localized transmission constraints, like the South Texas IROL, continue to pose challenges that could require firm load shedding if extreme conditions align,” he said.

NPCC-New England—Tight Margins, Increased Forced Outages. ISO New England’s outlook shows adequate resources for typical peak demand, but the region’s thin reserve margins and rising forced outage rates have elevated the risk profile for Summer 2025. ISO-NE forecasts a net margin of -1,473 MW (6.0%) under peak demand scenarios, reflecting increased resource retirements and dependency on non-firm imports. An additional 500 MW of expected forced outages further strains reliability. “Some use of New England’s operating procedures for mitigating resource shortages is anticipated,” NERC’s assessment notes. Under extreme high-demand, low-resource conditions, ISO-NE could experience a cumulative Loss of Load Expectation (LOLE) of 4.369 days and 19,847 MWh of unserved energy.

“New England continues to be an area where we see tight margins and an increased dependence on non-firm imports during stress conditions,” Olson said. “The reserve margins are getting tighter, and higher levels of forced outages compared to last summer are a concern.”

Among other elevated risk areas are:

• MRO-SaskPower is projected to face a 21.5% probability of forced outages exceeding 350 MW, resulting in an estimated 0.65 hours of reserve shortfall during the summer peak period.
• Southwest Power Pool (SPP) faces an elevated risk of reserve shortfalls during coincident wide-area heat events, especially when wind generation is low and forced outages are high, despite an Anticipated Reserve Margin of 28.5%.
• WECC-Mexico (Baja California) is at risk of energy supply shortfalls under typical forced outage conditions, requiring non-firm imports from neighboring regions to maintain system reliability during peak demand periods.

Systemic Challenges: IBR Performance, Aging Fleet, Fuel Coordination, and Supply Chains

Beyond regional adequacy concerns, NERC’s 2025 SRA flags persistent systemic challenges that continue to shape grid reliability. These include the performance of inverter-based resources (IBRs), an aging generation fleet with rising forced outages, fuel supply coordination, and lingering supply chain constraints.

IBRs—primarily solar PV and battery storage—continue to introduce new operational challenges as their share of the resource mix grows. Olson warned that while industry progress is being made, operators must remain alert to IBR tripping during grid disturbances. “There’s a message here for operators that they need to be prepared for the potential that large-scale amounts of resources can disconnect during grid disturbance events,” he said. “There’s really a long-term effort underway to address IBR performance issues, and that needs to continue. It’s very urgent.”

NERC has issued new performance alerts and plans to release a Level 3 alert later this month to address identified model quality deficiencies and technical requirements for IBR planning.

NERC also continues to highlight the reliability impact of an aging thermal fleet. Olson emphasized that forced outage rates are trending upward, particularly for older generation assets. “We’re advising the operators to also consider that forced outage rates of generators are possible, and they could be higher than expected,” he said. “As our thermal fleet is aging, the forced outage statistics are trending downward, but higher outage rates can occur in the older generation fleet.”

For the summer season, natural gas supply constraints are not anticipated to impact reliability significantly. Olson noted, “The availability of our natural gas fleet during summer conditions is really good. Summer has been and is postured well to support the gas fleet. The challenge really comes in the winter time.” However, NERC continues to stress the importance of coordination between gas and electric system operators, particularly during maintenance windows, to ensure fuel availability for gas-fired generation.

Meanwhile, though immediate summer reliability is not being critically affected by supply chain disruptions, Olson noted that long-term impacts on infrastructure development remain a concern. “When it comes to summer reliability, we’re assessing pretty much what’s in the system already, so supply chain constraints are not a factor, really, at this point,” he said. “However, trade and other supply chain issues and geopolitical situations are having a longer-term effect and could affect resource and transmission development. It’s another factor of uncertainty that can affect the development and resource additions.”

Recommendations for a Complex Summer

To mitigate the elevated risks flagged in its assessment, NERC is urging grid operators, planners, and regulators to adopt a layered approach that focuses on operational vigilance, demand-side readiness, and resource performance improvements.

Central to NERC’s recommendations is a call for conservative outage coordination and proactive operational adjustments. “Operators should be prepared for the potential for forced outages that are higher than what’s typically seen in planning models,” Olson said. “That means leaning into conservative operations ahead of forecasted extreme conditions to preserve system flexibility.”

NERC also emphasized the need for early engagement with state and provincial regulators to activate demand-side management measures efficiently. “The more we can prepare in advance for demand-side actions, the faster we can respond during stress events,” Olson said. “That readiness can make a measurable difference when reserves get tight.”

Addressing ongoing challenges with IBRs will remain a priority, NERC suggests. It urges generator owners with solar PV and battery assets to fully implement NERC’s 2023 IBR Performance Issues Alert recommendations. Moura noted that while resource additions are positive, “ensuring their performance aligns with grid reliability needs is critical, especially as their share of the resource mix continues to grow.” NERC is also collaborating with industry stakeholders on a forthcoming Level 3 alert, focusing on IBR model quality and planning requirements, which will seek to address gaps that could exacerbate system disturbances.

In addition, NERC encourages ongoing coordination between electric grid operators and natural gas system operators, particularly for maintenance scheduling and outage coordination. While Olson suggested “The availability of our natural gas fleet during summer conditions is really good,” he reiterated that vigilance is required as the grid’s dependence on gas-fired generation continues.

Finally, NERC advises that state regulators and industry stakeholders establish protocols for handling emergency generator requests for air-quality waivers during extreme demand events. If conditions neccessitate it, DOE emergency actions under the Federal Power Act Section 202(c) may be necessary to secure sufficient generation, it noted.

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).