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. 

As we approach the end of August, the focus of the summer typically begins to shift towards things like kids returning to school, parents seeking a more normal schedule, the excitement and optimism of each football team’s upcoming season, and hopefully milder temperatures across our power grids.

Given this, we thought it would be appropriate to give a quick update of how the summer has played out so far, by region and commodity (gas and power).

The good news is that we now know the price of capacity through May 2026. The bad news is that capacity prices have increased by approximately 5x over the last auction. The surge in price was fueled by power plant retirements, rising regional demand, and regulatory requirements seeking to address the participation of renewables and how much capacity they can provide during periods of system stress. Before examining the details of this latest auction, it’s important to review how the capacity market got to where it is today. As a refresher, the PJM Interconnection operates the largest competitive wholesale electricity market in the United States, serving 65 million people across 13 states and the District of Columbia as shown in Figure 1. Its primary function is to coordinate the flow of power and develop market rules such that the system operates reliably and safely. A critical component of PJM's operations is its capacity market, which ensures long-term reliability by securing sufficient resources to meet future electricity demand.  

ERCOT 

There are two words that describe the reaction of most commercial clients shopping for electricity in Texas: Sticker Shock. Figure 1 shows how the wholesale price of electricity for calendar years 2025 through 2028 has traded over the last four years. In ERCOT, electricity markets were at all-time lows of approximately $20/MWh in the months immediately before the pandemic. Over the last 48 months, power prices in ERCOT have more than doubled as wholesale prices are now more than $50/MWh for calendar years 2025 through 2028. The steady rise of electricity prices in ERCOT is largely driven by concerns that there is not enough supply to meet growing demand across the state. This demand is coming from power-hungry data centers used to support the rapid growth in AI, technology, and cryptocurrency mining in addition to manufacturing and population growth throughout the state. While substantial amounts of electricity from new solar and wind-generating assets have come online, those intermittent resources cannot be counted on to operate on demand. These are some of the dominant factors that have pushed up wholesale electricity prices in ERCOT.  

By most accounts, the winter of 2022/2023 was relatively mild. Only 2.3 inches of snow fell in New York City all winter, which is the lowest snowfall total in the 150 years that the National Oceanic and Atmospheric Administration (NOAA) has been tracking this data. Additionally, the price of natural gas fell 25% from the beginning of December through February on moderate temperatures and lower demand for natural gas used for heating throughout the winter. Despite the mild weather, one winter storm nearly brought PJM’s electricity grid to its knees. Winter Storm Elliott, which occurred between December 22 and December 26 last year, drastically affected power markets across the 13 states that make up the PJM Interconnection. The aftermath of Winter Storm Elliott has added a tremendous amount of uncertainty to PJM’s capacity markets and any new fixed-price retail electricity contracts that go beyond May 2025.    

Winter Storm Elliott may not have been an anomaly. This storm was the fifth event in the last eleven years where cold weather-related generation outages jeopardized the reliability of the electricity grid. In February 2021, ERCOT’s electric grid came within four minutes of a complete blackout across Texas from Winter Storm Uri. And while there were no rolling blackouts during Winter Storm Elliott, many describe last year’s storm as a “close call” with disaster. As reported in 5’s February Market Letter, more than 23% of PJM’s entire generation fleet was offline during last year’s storm. Figure 1 shows the extent of the outages in PJM during Winter Storm Elliott. 

Given that we are halfway through July, we thought it would be appropriate to provide an update on how major power markets have performed as they relate to each ISO’s coincident peak demand management program.

So far, both weather and demand on the PJM and NYISO grids have been mild compared to recent summers and average summer temperatures. The mean temperature, compared to the average over the last thirty, fourteen, and seven days for the period ending July 13, is shown in Figures 1, 2, and 3 below. These charts show that summer has not really arrived in the middle of the country and that temperatures in the Northeast are only 2º to 3º F above the average.