On the Texas grid in summer the hardest hour to serve comes after sunset, when air-conditioning load is still high and solar output has collapsed, and ERCOT's monthly reliability outlooks for July, August and September 2026 placed the hour with the highest reserve-shortage risk between hour ending 20 and hour ending 22. We looked at how that hour was served this summer compared with last, using hourly balancing-authority data that ERCOT reports to the US Energy Information Administration.
For each day from 1 July to 30 September we found the hour with the highest net load, defined here as demand minus wind and solar output, and recorded what every fuel was doing in that hour. Both years have 92 days. In 2026 that hour averaged 63,848 MW of net load, against 58,902 MW in 2025, an increase of 4,946 MW. Battery output in the same hours averaged 8,555 MW, against 4,818 MW. The battery increase of 3,737 MW is equal to about 76% of the net-load increase.
Gas-fired output at the net-load peak was almost unchanged: 39,445 MW in 2026 and 39,327 MW in 2025, a difference of 118 MW. Coal rose by 852 MW. Nuclear, hydro and the residual category moved by less than 60 MW each, and net imports over the DC ties changed by about 100 MW.
Where the peak sits
The net-load peak fell in hour ending 21 (8 to 9 p.m. Central Daylight Time) on 54 of the 92 days in 2026 and on 57 days in 2025. Most of the remainder fell in hour ending 20. Its timing barely moved even as solar capacity grew. Solar output in the peak hour averaged about 1 GW in 2026 and 0.7 GW in 2025, so the sun had largely set by then in both years.
Total demand at that hour rose faster than net load did. It averaged 79,078 MW this summer, against 71,296 MW last summer, a gap of 7.8 GW. Wind made up 2.4 GW of that gap and late solar another 0.4 GW, which is how a 7.8 GW rise in demand became a 4.9 GW rise in net load.
The single hardest hour of each summer shows the same pattern at a larger scale:
- 18 August 2025, hour ending 21: net load 68,781 MW, gas 46,614 MW, batteries 5,904 MW, wind 9,702 MW.
- 22 July 2026, hour ending 21: net load 75,208 MW, gas 47,031 MW, batteries 11,316 MW, wind 8,690 MW.
Net load in the worst hour was 6.4 GW higher. Gas supplied about 0.4 GW more, and batteries 5.4 GW more.
The installed base behind it
ERCOT's monthly Capacity Changes by Fuel Type workbook, drawn from its generator interconnection status data, listed 15,485 MW of operational battery storage in the September 2025 edition and 21,537 MW in the September 2026 edition, a 39% increase. The June editions show 14,137 MW and 21,158 MW.
Battery output at the net-load peak rose 78%, about twice as fast as the installed fleet. Dividing average output at the peak hour by the September operational figure gives 31% for 2025 and 40% for 2026. These ratios are rough. Installed capacity changed during each quarter, and some units are registered as co-located with solar and may face interconnection limits on combined output. Even so, the fleet was delivering a larger share of its rated power in the hour that mattered most.
The largest single hourly value in the EIA data for July to September 2026 was 11,928 MW, in hour ending 20 on 2 September. The 2025 maximum was 6,990 MW, on 4 September. Hourly averages sit below the five-minute peaks that ERCOT's own dashboards display. Battery output reached at least 5 GW in some hour on 85 of the 92 days this summer, and at least 10 GW on 21 days. In 2025 the 5 GW mark was reached on 44 days.
Charging moved into the middle of the day
In 2026 the hourly averages show batteries charging from hour ending 9 through hour ending 18, with the deepest average charging of about 7,970 MW in hour ending 10. Discharge starts in hour ending 19 and peaks at 7,822 MW in hour ending 21. At the daily gross-demand peak, which mostly fell in hour ending 17 or 18, the fleet was a net buyer on average, at minus 507 MW.
On the highest-demand hour of the summer, hour ending 18 on 22 July 2026, ERCOT served 91,075 MW of demand with 28,708 MW of solar and 43,172 MW of gas while batteries were still charging at 487 MW. Three hours later on the same day came the hardest net-load hour listed above.
The 2025 figures cannot be compared like for like in the midday hours. Before 5 December 2025, ERCOT modeled each battery as a generation resource and a separate controllable load resource. The charging side counted as load and did not appear as negative generation in the EIA series, which for 2025 shows battery values of zero or above in every hour. Under the Real-Time Co-optimization plus Batteries (RTC+B) design that went live that day, each battery became a single energy storage resource, and charging now appears as negative output. Demand figures for the two years also differ slightly in the charging hours for this reason. In the evening hours examined above, charging is close to zero in both years, so the comparison holds.
Summed over the quarter, EIA data show 2.28 TWh of battery discharge in 2026 and 2.89 TWh of charging, implying a round-trip ratio of about 79% before any netting within the hour. For 2025 only discharge, 1.53 TWh, is visible.
RTC+B and the evening hours
The core of RTC+B is that energy and ancillary services are now procured together every five minutes in security-constrained economic dispatch, rather than ancillary service awards being fixed day-ahead or in supplemental procurement. ERCOT's protocol revisions for the change (NPRR 1014 for the single-model storage resource, NPRR 1204 for the overall RTC+B design and NPRR 1282 for the ancillary service duration limits) moved batteries into a single bid and offer curve that spans charging and discharging, with state of charge tracked by ERCOT.
Before the change, much of the Texas battery fleet earned most of its revenue by holding capacity for ancillary services. Under co-optimization, the dispatch engine can shift a battery from reserves to energy within the hour if that is cheaper overall. This summer's evening data are consistent with more of the fleet's capacity being made available as energy at the net-load peak, though the hourly EIA series cannot separate the effect of RTC+B from the effect of 6 GW of additional installed storage.
The risk is moving later
ERCOT's Monthly Outlook for Resource Adequacy for August 2026, released in June and later revised, put the hour with the highest probability of an Energy Emergency Alert at hour ending 22, at 5.96%, with hour ending 23 at 4.95%. Its explanation was that newly energized large loads, dominated by data centers and cryptocurrency mining, keep demand high later into the evening, "resulting in less available battery discharge energy to supplement dispatchable and wind generation." For September the outlook moved the highest-risk hour back to hour ending 20, citing a faster evening load decline. Every hour in these outlooks stayed below the 10% EEA probability ERCOT treats as elevated risk.
The hourly profiles from this summer show the same shape. Average demand in hour ending 23 was 71,833 MW in 2026, 7.1 GW above 2025, and in hour ending 24 it was 6.9 GW higher. Battery output in those hours was small: 1,504 MW in hour ending 23 and 54 MW in hour ending 24. Gas output in hour ending 24 averaged 34,887 MW, 2.2 GW more than a year earlier, which is a larger year-on-year rise than gas showed at the net-load peak itself.
Evening discharge energy, summed over hours ending 17 to 24, averaged 22,957 MWh a day in 2026 and 12,909 MWh in 2025. Dividing each by the average daily maximum hourly output gives about 2.7 hours in both years. That is a crude stand-in for how long the fleet sustains its peak output, and it did not change even as the fleet grew. Hours after 10 p.m. will be met mostly by thermal plants and wind unless the average duration of new storage increases or late-evening demand flattens.
Method notes
Data: EIA Form 930 Hourly Electric Grid Monitor, balancing authority ERCO, six-month balance files for July to December 2025 and July to December 2026, downloaded on 23 October 2026. We used the adjusted columns. Hours are hour ending in local prevailing time (Central Daylight Time for the whole period). The 2026 data for September are recent and may still be revised by EIA.
Net load is demand minus wind and solar net generation, both excluding integrated battery storage. Battery storage is the EIA "battery storage" net generation series. The daily net-load peak is the single hour with the highest net load on each day. Shares and ratios are computed from these hourly averages. Installed battery capacity is the "Cumulative MW Operational" value in the Battery Chart sheet of each ERCOT Capacity Changes by Fuel Type workbook.