It was a record-smashing summer for the Electric Reliability Council of Texas (ERCOT) power grid. The system, which supplies about 90% of the state’s electricity demand, set new peaks in July and August, soaring above previous highs from the hot summer of 2023. However, unlike that year’s large and consistent price spikes, power prices this summer were low and stable—almost boring. The difference: vastly more solar and battery storage in the Lone Star State.
The chart below clearly shows the change that has occurred in ERCOT pricing from 2023 to 2026. In 2023, ERCOT set a daily demand peak record of 85,508 megawatts (MW) on Aug. 10. August 2023 also was the month with the highest average daily peak, at 82,698 MW. But the summer of 2026 shattered both those records. On July 22, demand reached 91,089 MW, a 6.5% jump from 2023’s record. In August, daily peak demand during the month averaged 87,810 MW—5,112 MW higher than the 2023 record. Demand was so strong that there were only five days in August that did not top the record peak from 2023.
Despite this significant increase in demand, prices remained low and stable this summer compared with the 2023 roller-coaster ride.
During the 122 days from June 1 through Sept. 30, 2023, there were 75 days when the day-ahead price in ERCOT settled above $125 per megawatt-hour (MWh), or 61% of the time. In addition, peak prices in 2023 soared above $1,000/MWh on 20 of the 122 days, topping out at $4,213/MWh on Aug. 25. In stark contrast, there were only five days during the same period this year when day-ahead prices topped $125. The highest peak was a mere $229/MWh.
Total monthly generation is another way of looking at the price. ERCOT’s three highest monthly generation totals occurred this summer, with July, August, and September all topping 50 million MWh. The highest occurred in August, when output hit 54.4 million MWh. The only other time monthly generation topped 50 million MWh was in August 2023. As the chart shows, despite this summer’s consistently high demand, prices were low and essentially flat—nothing like the frequent spikes that occurred in 2023.
The key reason prices remained low this year? The rapid buildout of solar and dispatchable battery storage in ERCOT.
In 2023, ERCOT had 22,153 MW of installed solar capacity; by July 2026 that had almost doubled to 41,185 MW. Similarly, in 2023 there was 5,090 MW of installed battery storage capacity; by this July it was four times as high, reaching 21,564 MW. These two resources, both individually and paired, have changed the system’s daily operations, helping to meet both rising overall demand and daily peaks while keeping prices in check.
For example, throughout the record-setting month of August this year, solar supplied almost 33% of daily peak demand. In contrast, in August 2023, solar generation at the peak hour averaged only 13.6%, forcing ERCOT to turn to more expensive gas- and coal-fired generation to meet the daily peak, which contributed to the system’s higher and more volatile prices.
The complementary role of dispatchable battery storage is best demonstrated by examining its role on July 22, when ERCOT set its current peak demand record of 91,089 MW. During the day, solar generation climbed to a high of 33,634 MW and was still at 28,712 MW at the peak hour of 6 P.M., providing 31.5% of total demand. As solar generation began to decline over the next couple of hours, battery output began flowing into the grid. By 8 P.M., batteries were generating 11,400 MW of power and were the second-largest resource on the system, behind gas but ahead of coal and nuclear. At 9 P.M., batteries still accounted for 11.9% of total system demand, sharply reducing the need for gas- and coal-fired generation and helping to keep prices low.
In fact, the market hardly noticed the new peak. In the real-time market, where demand not covered by the day-ahead market gets supplied, the highest price when the system’s new peak was set this summer was $378/MWh for a five-minute interval late in the evening as battery capacity ramped down. That’s far from the $4,477/MWh real-time price reached in 2023 during the peak hour. In addition, real-time prices in 2023 were well over $1,000/MWh for most of the afternoon and early evening of the peak demand day.
The role of dispatchable battery storage also continues to grow in importance. This year, battery discharge to the grid hit a record 11,980 MW during ERCOT’s July 22 peak; that total has already been topped seven times. The current battery discharge record, set Aug. 23, is 13,255 MW, but is almost certain to be eclipsed in the months ahead.
ERCOT’s independent market monitor, Potomac Economics, highlighted the beneficial impact battery storage was already having on the system’s pricing in its 2025 market review, which was released in May 2026: “In the summer of 2025, however, price spikes were 40% less frequent than in the summer of 2024 as additional ESR [energy storage resource] capacity improved ERCOT’s capability to manage the system’s ramp needs.”
That positive price impact has clearly continued into 2026.
ERCOT data shows that wind and solar’s share of total system generation for the first nine months has climbed to 40.3%, up 3 percentage points from a year ago. This growth has taken place even as overall market demand climbed 5.4% through September. In other words, renewable generation has outpaced the rapidly increasing needs of the ERCOT market.
Combined with dispatchable battery storage, renewables are not only providing power to the grid but also helping the whole system do so at low and stable prices. Texas continues to show that a reliable and economic transition away from fossil fuels is happening.
Around North America
Catch up on expert webinars
The North America team has hosted a number of webinars over the summer that are available on our YouTube channel.
First in July, we held a webinar featuring IEEFA analysts Mark Kalegha, Clark Williams-Derry, and Christopher Doleman for a discussion on the new and riskier market landscape faced by Canada's LNG industry.
Then we turned our attention to communities across the U.S., and how many are grappling with the buildout of massive power generation and petrochemical projects, especially in its relation to water availability. IEEFA analysts Dennis Wamsted and Anika Juhn, shared their insights and analysis on nuclear and carbon capture projects in water-strapped Texas, what this means for the communities where these projects are proposed, and the broader national implications.
Finally, we focused in on Texas, and how promises of boosted economic conditions and new jobs have failed to materialize for the Texas cities along the Gulf Coast hosting the wave of petrochemical expansion the industry experienced over the last 15 years. Watch IEEFA energy finance analyst Trey Cowan discuss the findings from our latest report about the petrochemical industry and how it impacts local Texas economies, communities, and health.
