​Real-time settlement prices in ERCOT peaked at $561/MWh on August 23 and $781/MWh on August 26. On both evenings prices in the Real-Time Market (RTM) were in the mid-triple-digits for multiple hours.

However, on both days, the Day-Ahead Market (DAM) never rose above $100/MWh.

​Instead, RTM settled above DAM in nearly every interval on both days, and by hundreds of dollars through the evening peak.

​The two evenings shared a setup:

• more thermal capacity on outage than expected for the summer peak,
• wind below its day-ahead forecast,
• and BESS running low on energy before the highest-priced hour arrived.

Some key differences between the two days were:

• an increase in thermal generation outages between DAM clearing and RTM operations on the 23rd,
• a larger wind forecast miss on the 23rd, but lower wind generation overall on the 26th,
• and severe transmission congestion driving separation in prices between zones on the 26th.

Key Takeaways

• ​RTM prices peaked at $561/MWh on August 23 and $781/MWh on August 26, both times after BESS discharge had already peaked.
• Thermal outages were elevated on both days, averaging 10.8 GW across the evening of the 23rd and 8.7 GW on the 26th, against a 90th percentile August expectation of 8.5 GW.
• The 23rd escalated late: thermal outages climbed 2.9 GW after the DAM closed, and wind landed 41.8% below forecast at the peak hour.
• The 26th started short: wind bottomed below 2 GW at midday, peak net load hit 74.6 GW, and batteries had discharged 9.9 GWh before noon against a 2.4 GWh average.
• Congestion reached far more of the system on the 26th. 480 of 1,047 nodes cleared $50/MWh above the hub, against 65 on the 23rd.

​What was consistent across both days

​Thermal outages were high before either evening began. Dispatchable capacity on outage averaged 10.8 GW through the evening of the 23rd, and 8.7 GW on the 26th. ERCOT's 90th percentile expectation for August is 8.5 GW, according to the Monthly Outlook for Resource Adequacy (MORA).

Wind then came in under forecast on both days, on each day providing more than 2.5 GW less than what was forecast at the time of DAM clearing across the evening peak.

The DAM forecast for demand was nearly spot on, but it was near an all-time high each day, continuing to demonstrate the load growth that the ERCOT network has experienced in the past year.

Both days peaked around 90 GW, in line with the rest of that week.

This confluence of events resulted in elevated Real-Time prices, and that volatility resulted in higher-than-average BESS discharge through the early evening.

On both days, this meant that the RTM price peak landed after BESS discharge peaked. Discharge topped out at 19:50 on the 23rd, but prices peaked at 21:00. On the 26th, discharge peaked at 20:05 and prices at 22:15.

​As state of charge ran lower throughout the evening, the economic dispatch moved further up the offer stack.

What was unique to August 23rd

​Outages went from high to extreme. At DAM close, 7,958 MW of dispatchable capacity was expected on outage for the evening of the 23rd. By real-time operations on the following evening, that had risen to a peak of 11,003 MW.

That extra 2.9 GW wasn’t priced into DAM. It also took the evening within 700 MW of 11.7 GW of thermal generation outages, the worst case ERCOT models.

Wind generation was also substantially lower than the assumption at the time of the DAM clear. At 20:00, when net load peaked at just over 75 GW, total wind generation was 8.6 GW. This was 41.8% lower than the day-ahead forecast of 14.8 GW.

​What was unique to August 26th

Across the evenings of August 19 to 23, wind averaged 11.4 GW. On the 23rd, it averaged 9.8 GW.

However, on the 26th, it averaged 5.8 GW, roughly half the week's norm, and it bottomed at 1.2 GW in the early afternoon. Wind also ran 2.3 GW under forecast at the peak hour, similar to the 23rd.

This extreme low in wind generation contributed to the highest net load of the month at nearly 76 GW.

One other major difference was the lack of available stored energy in batteries.

Going back to the BESS discharge chart from the previous section, the morning of the 26th carries a spike the 23rd does not. Batteries discharged 9.9 GWh before noon, against a two-week average of 2.4 GWh, chasing a morning congestion event in South Texas.

Much of that discharged energy was not restored throughout the day. Midday RTM prices averaged $48/MWh against a $22/MWh two-week norm and a DAM price that was generally between $20 and $20/MWh.

This meant that many batteries were reluctant to charge at elevated Real-Time prices, leaving the total amount of energy stored across all BESS lower than the typical 25 GWh observed on most operational days this summer.

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​Congestion showed up in RTM, not DAM

In the Real-Time Market, eleven unique transmission constraints saw their shadow prices rise above $1,000/MWh on the 23rd, and eighteen on the 26th. In DAM, just one did on each day, which contributed to price separation being limited to less than $50/MWh between zones.

On the 26th, separation between load zones was as high as $300/MWh between Load Zones South and West in the evening hours.