Before each winter, many organizations responsible for overseeing North America's power grids release risk assessments. These reports primarily focus on reliability and resiliency, with less emphasis on wholesale prices. Although wholesale prices can indicate risk, forward prices do not always fully capture the potential risk of energy scarcity. Conversely, forward price volatility may sometimes reflect risks that are less likely than the prices suggest. This article summarizes some of these risk assessments and highlights the risks currently indicated by forward market prices for January and February 2025.

To start, the North American Electric Reliability Corporation (NERC) releases a Winter Reliability Assessment (WRA) each fall, covering key markets and regions across North America, including PJM, New York, New England, and Texas. This year’s report largely aligns with expectations, indicating that most deregulated regions face reliability risks during periods of "above-normal" load conditions. This risk summary is shown below in Figure 1.

Figure 1. Winter Reliability Risk Area Summary, by NERC

According to NERC, the primary risk facing most regions this winter is the availability of natural gas. While the power industry has made significant strides since 2021 to enhance power plant performance, much of this progress has focused on improvements in planning and forecasting. However, the most significant challenge remains the capacity of natural gas pipelines and maintaining adequate pipeline pressure levels during periods of extreme cold, which continue to pose the greatest threat to reliable power production during the winter months.

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).

DALLAS, July 16, 2024

Industry veteran Tracy Hodge joins 5, a leading energy advisory firm in North America, as Senior National Energy Advisor.

5 is pleased to announce that industry veteran Tracy Hodge has joined the company. Tracy brings an impressive background spanning nearly two decades in the retail energy sector to her new role at 5. Prior to joining 5, Tracy managed the Interactive Energy Group (IEG) brokerage business, where she drove significant growth and innovation. IEG is a wholly owned subsidiary of Just Energy. She also held key roles at Ambit Energy and Save On Energy, developing strategic partnerships and leading product marketing initiatives that substantially enhanced customer experiences and business profitability.

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.  

On behalf of the team at 5, I am pleased to forward our May 2024 market letter.  In this edition, we discuss several interrelated topics.  First, we look at ongoing legal challenges to two new federal energy regulations, (i) the SEC’s climate change reporting rules, and (ii) the EPA’s new power plant emission standards. Second, we address a question we are hearing often from our clients, especially those faced with rising energy prices: “Could President Trump’s election reduce the price of electricity?”  

On January 30, 2024, the Texas Supreme Court heard oral arguments in a ground-breaking case related to Winter Storm Uri. At the heart of the case is the question of whether the Texas PUC had the authority to manually set the ERCOT rates paid by electricity suppliers to $9,000 per MWh during the four days of Winter Storm Uri. Attorneys representing the PUC (supported by attorneys representing numerous energy companies, including NRG, Calpine, and Talen Energy) stated that this action was necessary to avoid a weeks-long blackout for much of the state.  In response, attorneys for numerous energy companies suffering losses as a result (including Luminant and Pattern Energy) argue that the PUC acted outside of the authority granted by the Texas legislature in taking such action.  The Texas Third Circuit Court of Appeals in Austin previously ruled against the PUC in March, and the PUC appealed to the Texas Supreme Court. 

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.