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. 

While it has become common over the last few years for the bears of the natural gas market in the US to rule the month of December and drive down the coming winter’s (January and February) contract, this fall it seems like December came early. For almost the entire month of November, warmer-than-normal weather forecasts, both weekly and monthly, have been relentless for any traders holding on to long positions.  Since Halloween, the Dec. ’23 – Feb. ’24 strip has dropped about 75¢, from $3.65 down to $2.90 per MMBtu as shown in the blue line in Figure 1. This chart also shows that prices have fallen for the April 2024 to November 2024 strip (black line) over the last several weeks. 

This summer, temperatures in Texas have been significantly higher than average, with record-breaking ERCOT demands and Real-Time prices reaching their maximum cap on multiple days in both June and August. In fact, between June and August, ERCOT eclipsed the 2022 maximum demand of 80,148 MW on 47 different days, with this summer’s maximum of 85,464 MWs set on August 10. Figure 1 shows the effect of the record breaking heat on spot electricity prices in North Texas in the months of June through August, 

With growing energy demand in Texas, there is a need for more power-generating resources to maintain the grid's reliability and to ensure there is a balance between available power supplies and demand. Intermittent sources like wind and solar cannot be dispatched on-demand, making it unreliable during hours when electricity supplies are tight.

This summer, the grid’s vulnerability to insufficient reserve margins was demonstrated multiple times after the sun set, solar output dropped to zero, and wind output was low due to insufficient wind speeds across the state. Ancillary services are ERCOT’s market mechanism to ensure that power-generating assets are on standby and available to produce electricity on days when solar and wind outputs are low and demand on the grid is high.

Before this summer, there were four market-procured ancillary services: Regulation Up, Regulation Down, Responsive Reserve Service, and Non-Spin Reserve Service. A few years ago, ERCOT and the Public Utility Commission (PUC) decided these four services were insufficient to provide adequate levels of responsive reserves. To address this need, ERCOT added a fifth ancillary service, the first to be added since the market opened in 2002, called ERCOT Contingency Reserve Service (ECRS), which went into effect on June 10, 2023.

ECRS can be seen as an intermediate product between Non-Spin and Responsive Reserve capacity that can respond within 10 minutes to address operational issues. These services secure additional power capacity beyond regular supply and are purchased in the Day-Ahead Market. This new ancillary service is intended to address unforeseen disruptions like generator failures or sudden demand spikes and to provide a rapid response backup to the grid. These contingency reserves are provided by power plants (or other resources such as load) that are capable of quickly ramping up their generation (or reducing their consumption) to help balance the grid during times of reduced reserves.

On behalf of the team at 5, I am pleased to forward our September market letter. If you had any doubts that the energy transition is happening, recent events in Texas and New York confirm that the answer is yes. As discussed below, these states have very different approaches to energy regulation, and both have struggled to incorporate intermittent resources in the energy mix. For clients in Texas, New York, or any other deregulated market, planning for the challenges of the energy transition, including increased regulatory risk, should be a key component of your energy management strategy.

Many are surprised to learn that there are several cost components that are added together to establish the rate in cents per kilowatt-hour in an electricity supply contract. Those components are summarized in Figure 1, which shows that the two largest are energy and capacity. It’s important to note that both energy and capacity are market-based, which means that the price of both is based on the forces of supply and demand. And while it may not be obvious, regulations and legislation can have a significant effect on the forces of supply and demand and thus the power markets. Between April 2018 and May 2019, the price of energy in New York City increased nearly 40% largely driven by a carbon tax proposed by the NYISO. Doubts around implementing that carbon tax caused prices to dramatically fall to just fourteen months later. This is an example of how regulatory forces can move market prices. Today, regulations in New York State are causing a dramatic increase in the price of capacity, the second largest cost component in a retail electricity supply price (See Figure 1).