NERC has published a new incident review report to draw attention to the growing challenges to maintaining reliability during the “shoulder seasons” of spring and fall by highlighting multiple occasions of unplanned load shedding by two anonymous entities.

Spring and fall have been called “shoulder seasons” because they fall in between summer and winter, which are traditionally peak load periods in most regions, NERC wrote in the Load-Pocket Shoulder Season Challenges document, released March 4. Utilities tend to use these periods for planned maintenance and construction to prepare for the more demanding seasons ahead, taking advantage of the lower expected load levels to take generation and transmission facilities offline.

However, this historic approach has been complicated in recent years by changes in both the generation mix and load behavior. In many areas, once-comfortable reserve margins have shrunk to the point that grid operators must consider more carefully whether to grant equipment outage requests. NERC’s 2024-2025 Winter Reliability Assessment warned that retirements of coal- and natural gas-fired generation in multiple regions could lead to reliability challenges, which the ERO observed in the new report. (See NERC Sees ‘Reasons for Optimism’ as Winter Approaches.)

The report included four incidents of load shedding — two for each entity — out of six experienced across the ERO in shoulder seasons during an unspecified 13-month period. Each incident occurred in a load pocket — a smaller area of concentrated load within a balancing authority’s footprint that typically also contains some generation.

A load pocket will have “varying degrees of transmission lines that connect [it] to the larger grid,” through which energy must be imported to serve the load when the internal generation does not suffice. Depending on the size of the load, entities may create transmission “rings” around the pocket to provide more options for imports.

Multiple Factors in Load Shedding Incidents

The first two incidents were associated with the same entity, identified as “Entity A” in the report. Entity A reported three load-shedding incidents in 2024 and 2025, occurring in the same load pocket, of which the details for two were included in the report.

Each of Entity A’s incidents involved a combination of the following factors:

• • unavailable generation, either from planned or forced outages, low wind or solar generation output, or emission constraints;
  • differences between actual and forecast load, attributable in large part to line losses on the transmission system, resulting from increased power flow from reduced internal generation output; and
  • planned or forced transmission outages.

The first incident occurred in April — the year was unspecified — when a sustained fault on a 345-kV transmission line caused it to be taken out of service. A planned maintenance outage was already underway on another 345-kV line, leading to increased dependence on internal generation.

A wind facility with a nameplate capacity of 4.7 GW output only 100 MW because of low wind speeds, a separate generator failed to start and solar generation ramped down as expected at the end of the day, all as load increased to its daily peak value. With real-time contingency analysis results indicating imminent voltage instability, operators shed about 150 MW of load.

The second incident occurred in March, also in an unidentified year, when a significant unforecast reduction in wind generation led to increased transmission system flows and line losses. Multiple flexible and dispatchable generation resources were offline because of planned and unplanned outages, and a 345-kV line was out of service for maintenance as well. Operators shed 122 MW of load to return the system to stability.

Additional Incidents from 2 Entities

Two load shedding events were reported by the second entity. Both occurred in April 2025, but details were only provided for the one on April 26.

The report linked to a separate analysis by SPP that provided more details on the location of the event — northwest Louisiana — and the utility involved, American Electric Power.

On the day of the incident, about 3 GW of generation within the load pocket was unavailable because of planned maintenance outages. A 345-kV line and DC tie transmission line were also out of service, “significantly reducing the import capacity into the load pocket.” SPP ordered AEP to shed 140 MW of load, cutting power to about 30,000 customers for about six hours.

The last entity, identified in the report as Entity C, reported a single incident in May, when operators were forced to shed 600 MW of load. The load shedding was required because of planned and unplanned generation outages of about 7.6 GW — 74% of internal generation — combined with 1,732 MW of unavailable capacity on a 500-kV line. Temperatures within the pocket were also about 5 degrees Fahrenheit higher than expected, causing “a substantial increase in load.”

From the four incidents, NERC identified several considerations for entities during shoulder seasons. These include planning for a higher level of operating margin and committing additional generation in load pockets in case of variations in generation, load and weather; including demand-side management in mitigation plans for insufficient capacity; and periodically reviewing planned outages as the date approaches to determine whether conditions could warrant postponing them.