Texas’s normal summer risk rating has a Far West Texas exception

Source finding. NERC assesses most of the Texas Interconnection at normal risk for summer 2026. Its reasons are a 12% increase in anticipated resources and a 4.5% decline in projected net internal demand. NERC attributes the lower demand forecast to updated modeling of how load behaves during peak periods and to more demand response from large computational loads. The rating describes the broader interconnection; it does not say every location faces the same risk. NERC Summer Reliability Assessment [page 6]

ERCOT’s probabilistic reserve risk model (PRRM) reinforces that broad assessment for a particular test: it estimates a 0.43% probability of declaring an energy emergency alert (EEA) in the highest-risk hour of the expected August peak-load day, the hour ending at 9:00 p.m. ERCOT categorizes an hourly EEA probability of 10% or less as “low risk.” NERC reports that the corresponding probability in the 2025 assessment was 3.1% and attributes the decrease to added battery energy storage capacity. These are reported model results, not a calculation of this article’s own. NERC Summer Reliability Assessment [page 17]

Another system-wide measure points in the same direction. NERC reports an anticipated reserve margin of 67.9% against a reference reserve margin of 13.75%, and says ERCOT expects sufficient operating reserves for the August peak-load hour under expected normal summer conditions. NERC also flags a different time-of-day pressure: high loads and declining solar generation raise the risk of emergency conditions in evening hours. Neither statement resolves whether electricity can be delivered without difficulty to every part of ERCOT. NERC Summer Reliability Assessment [page 34]

The Far West Texas exception. NERC explicitly warns that the PRRM does not capture a pre-contingency load-shedding risk in Far West Texas arising from rapid growth in both load and resources in that zone. Its ERCOT dashboard likewise says the projected EEA risk does not account for regional constraints there and that, in certain low-generation scenarios, those constraints may lead to reliance on price-responsive demand. The excerpt does not establish that shedding will occur; it identifies a risk outside the quoted model result. NERC Summer Reliability Assessment [page 6] [page 34]

Editorial interpretation. The two findings answer different questions. The PRRM’s 0.43% figure concerns an EEA declaration in a specified modeled hour on the expected August peak-load day; it is not presented as the probability of Far West Texas load shedding. A favorable interconnection-wide reserve position and a low modeled EEA probability therefore cannot, by themselves, dismiss the regional constraint that NERC says the model omits. This is an inference about the scope of the reported measures, not a new probability estimate. NERC Summer Reliability Assessment [page 17] [page 34]

What remains unknown. The supplied excerpts give no probability of Far West Texas load shedding and no set of model inputs from which to estimate one. They also do not identify, in the quoted Far West Texas finding, a particular transmission element or a timetable for resolving the constraint. No numerical local-risk estimate follows from the 0.43% EEA figure. For a reader assessing Far West Texas specifically, the practical conclusion is to treat “normal risk” as a system-wide assessment with an expressly stated local exception—not as a local guarantee. The last sentence is editorial inference; no additional risk calculation has been made. NERC Summer Reliability Assessment [page 6] [page 17] [page 34]