With temperatures starting to cool down and the days shortening by almost two minutes per day, it seems like the summer might be in the rearview mirror. With the clarity of hindsight, we thought a market review across the regions and the ISOs for the summer would be appropriate.
Figure 1. Mean Temp (F) ending Sept 30, 2023, by NOAA Figure 2. Mean Temp (F) ending Sept 30, 2024, by NOAA
Since weather is one of the biggest short-term drivers of electricity demand and volatility, let’s start with a quick look at the difference between the last two summers compared to the 30-year averages, according to the National Weather Service.
Texas
Given the elevated temperatures and wholesale electricity prices last summer, many entered this summer hoping for the best but fearing the worst. But thankfully, both weather and prices greatly underperformed. As shown in Figure 1, in 2023, large areas of Texas were more than 6º F above normal for the 90 days ending September 30, 2023. Figure 2 shows the same data for the 90-day period ending this past September. This chart shows that most of the large population centers in Texas were within 1º F of normal (1991 – 2020) temperatures this summer.
Figure 3. Spot Electricity ERCOT Load Zone North Real-Time LMP, by 5
While lower temperatures helped, the significant amount of new utility-scale solar and batteries installed since last summer helped the grid maintain adequate reserve generation on peak demand days. Batteries were especially helpful during late afternoon peaks as the sun was beginning to set and the output from solar resources was reduced. These grid-level batteries helped to mitigate prices during those sunset hours that were highly volatile last summer. Figure 3 shows that the amount of real-time summer price volatility in Texas was significantly lower in 2024 compared to the previous two summers.
Lastly, the solar and battery combination (and a continued growth in residential-installed solar) caused the peak demand (the single highest 15-minutes of grid usage) to decrease by 326 MW or nearly 0.38% from last summer. Not bad compared to the 5,000 MW growth over each of the previous two summers.
Speaking of peak demands, the 4 Coincidental Peak (4CP) intervals this year were more heavily influenced by a small number of grid-scale batteries that were charging during the peak hours (counts as load in certain ERCOT reports). This moved the peak demand days and times around a little more this year than in the past. One such anomaly was that for the first time, a 4CP event occurred on a Sunday evening. This summer’s preliminary 4CP intervals are shown below:
- Sunday, June 30, 5:30 to 5:45 PM (IE 17:45)
- Monday, July 1, 4:45 to 5:00 PM (IE 17:00)
- Tuesday, August 20, 4:45 to 5:00 PM (IE 17:00)
- Friday, September 20, 3:45 to 4:00 PM (IE 16:00)
PJM (Midwest & Mid-Atlantic)
In PJM, the summer of 2024 was a few degrees warmer than 2023 across most regions, on average, with the mid-July heat wave helping set the highest Hourly Demand in PJM in over 10 years. In contrast to previous years, all five maximum hours were in the 5:00 to 6:00 PM ET hour (see Table 1). A facility's usage during these highest five hours will determine its daily capacity obligation (Cap Tag) starting June 1, 2025. The distribution of peak demand days in PJM over the last nine years is shown in Figure 4.
Table 1: PJM's 2024 5 Peak Hours, by 5
Figure 4. 5CP Day Distribution, by 5
Speaking of PJM capacity, there was a lot of news this summer around the record-high capacity prices which cleared during the August auction and going into effect on June 1, 2025 (see our previous webinar on this topic). Last week, PJM reported that the auction previously scheduled to take place this December is now postponed for at least 6 months. All of the auctions scheduled to occur after the December 2024 auction are also delayed. This latest delay is to give PJM and FERC enough time to reconsider the inclusion of Reliability Must Run contracted power plants in the auction.
While the possible inclusion of these plants in the auction could (and should) dramatically lower the auction price, it also continues to shorten the window from auction results to implementation for this and the next four auctions. This makes it difficult for new generation projects to participate in the auction and continues the trend of significant regulatory involvement and adjustments to PJM’s capacity pricing model. This adds regulatory uncertainty around the very price signals that PJM holds sacred to these auctions, and the underlying and fundamental principle function of the auction, which is to give actionable forward price signals, indicating when capital should be spent on new generation assets.
Figure 5 shows that spot energy prices in PJM this summer were up slightly compared to the same months last year. Very inexpensive natural gas prices helped keep prices in check, and much lower than in 2022, which saw much higher summer natural gas prices.
Figure 5. Spot Electricity PJM West Real-Time LMP, by 5
New York
Figures 6 and 7 show that spot power prices in both Upstate and Downstate New York share a similar story to PJM. Like its neighboring ISO, NYISO spot prices in all summer months were up slightly compared to the same months in 2023. However, these charts also show that prices are considerably lower than in 2022, due to much lower natural gas prices.
Figure 8 shows that the maximum hourly demand took place earlier this summer, on July 8, during the Hour Ending 6:00 PM ET (HE 18). The preliminary peak demand of 28,990 MW was about 2,550 MW below the NYISO’s “normal weather” baseline forecast published in their 2024 Load and Capacity Data Report. This was an increase of only 0.9% compared to last summer’s peak demand.
Figure 6. Spot Electricity NYISO New York City Real-Time LMP, by 5
Figure 7. Spot Electricity NYISO Zone C Real Time LMP, by 5
Figure 8. NYISO 2024 Deal Peak Dembands, by 5
Overall, it was a rather mild summer compared to 30-year averages, which looks rather cool compared to what has been defined as “normal” in the short-term. The peak demands in all three ISOs were below what was forecasted. This along with low frequency, high-demand days allowed all three grids to perform adequately. Given that the consensus in May was that all three grids were vulnerable, this summer turned out to be very favorable in terms of both stability and price volatility. Cheap natural gas also helped. This summer saw some of the lowest natural gas prices in NYMEX history (when adjusted by CPI) which kept marginal costs down for gas fired power plants across the country.
