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 price risks currently indicated by forward markets 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 5
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.
Texas/ERCOT
ERCOT publishes the Monthly Outlook for Resource Adequacy (MORA), which assesses the likelihood of resource inadequacy by considering various weather and operational risks across the state. The February report, released in early December, highlights the potential for controlled outages (the industry's term for rolling blackouts). Unlike summer, when the risk of insufficient resources peaks in the evening around sunset, winter brings the highest risk between 7:00 and 8:00 AM. During these hours, temperatures are at their lowest, heating demand from buildings and homes surge, and solar power is not yet contributing to the grid.
ERCOT's MORA indicates that under normal load conditions, the risk of resource inadequacy is minimal. However, as demand exceeds 83,000 MW (the load forecast for a winter event comparable to Winter Storm Elliot) the likelihood of a load-shedding event approaches 10%. In the case of a cold snap similar to February 2021's Winter Storm Uri, demand could exceed 90,000 MW, surpassing all historical winter and summer peak demands in ERCOT's history. This scenario raises the risk of controlled outages (forced load shedding) to 30% or higher. Figure 2 shows the coldest days in North Texas over the last thirteen years with Winter Storm Elliott (12/23/22) and Winter Storm Uri (2/16/21) in bold text. Enhanced planning efforts, ERCOT's generation inspections, improved power plant resiliency, and significant growth in solar and battery installations have helped to partially offset the sharp increases in peak demand caused by economic and population growth across the state.
Figure 2. Coldest Days in North Texas, by 5
As shown in Figure 3, prices for January and February 2025 were trading around $55/MWh in late December, just before the January contract expired. However, winter prices for 2026, 2027, and 2028 are significantly higher, at approximately $72, $84, and $85/MWh, respectively. This reflects both rising fuel costs and the growing risk associated with Texas's increasing load, which is outpacing the development of new thermal, dispatchable generation to meet higher demand.
Figure 3. ERCOT North Electricity On Peak, by 5
PJM
In PJM, the memory of Winter Storm Elliot remains vivid. While operators have taken steps to mitigate the risk of a similar storm causing comparable disruptions, challenges remain. Since December 2022, PJM's forecasted winter peak demand has risen by 4,000 MW, even as the number of thermal generation resources has declined. Although nearly 180 GW of resources appears sufficient to meet the projected demand of 141 GW, the reliability of those resources, the availability of their fuel, and the demands of neighboring ISOs that depend on PJM are all critical factors in ensuring the region can meet its electricity needs.
NERC's WRA highlighted both benefits and risks associated with Transco's Regional Energy Access pipeline project, which recently went into service. The project will provide about 44% of its capacity to PJM’s natural gas-fired generation, supporting nearly 20 GW of gas-fired power across eastern Pennsylvania, New Jersey, and Delaware. While any potential shut-ins or failures of this pipeline could pose a risk to power reliability in the region, its successful operation as planned would ultimately reduce that risk as reported in the WRA.
As shown in Figure 4, forward winter power prices exhibit a similar "stair-step" pattern, with each subsequent year seeing higher prices. Winter 2025 has recently been trading within a range of $60 to $70/MWh, while winters from 2026 to 2028 are trading between $80 and $90/MWh.
Figure 4. PJM East Electricity, by 5
New York and New England
New York's winter price risk is essentially split into two regions: Western New York, which is closely tied to and follows PJM prices, and Downstate and Eastern New York, which are more aligned with ISO-NE and face similar natural gas price risks as New England. Due to limited natural gas pipeline capacity in Eastern New York and New England, the marginal price of gas in these areas, particularly in New England, is influenced by the market price of LNG imported into Boston. Unlike previous years, forward European LNG prices for winter delivery have been relatively lower, with forward gas prices this winter around $14/MMBtu in Boston and closer to $6/MMBtu in New York City. While neither of these regions faces a resource adequacy issue during winter months like PJM or ERCOT, both experience significant daily volatility in natural gas prices, which leads to power price fluctuations. For example, even the moderately cold temperatures in December 2024 caused average Day-Ahead prices in NYC to reach $73/MWh, the highest monthly average since 2022. Similarly, ISO-NE's December average Day-Ahead prices were around $90/MWh, marking the highest winter prices since December 2022 and Winter Storm Elliot. Current strip prices for January to February over the next four years in New York City and Boston are shown below in Figures 5 and 6.
Figure 5. NYISO Zone J (NYC) Electricity, by 5
Figure 6. ISO-NE NE Massachusetts (Boston) Electricity, by 5
Although it is too early to evaluate the performance of these systems halfway through winter, the moderate seasonal weather has posed some challenges for most ISOs during the first half of January. Nevertheless, there is no sign of an impending system failure; in fact, the outlook is quite the opposite.
While Texas experienced typical cold and freezing precipitation in the second week of January, the scarcity risk in ERCOT was negligible. Similarly, the Midwest and PJM regions, despite moderately cold weather, did not witness significant price spikes in natural gas or electricity. In contrast, New York and New England saw daily natural gas prices rise to match international LNG prices ($14 to $18 per MMBtu), with wholesale power prices reflecting a modest spark spread, trading between $100 and $150 per MWh throughout the week.
These prices are reasonable given the gas and power demand at this level of weather severity. However, as NERC has cautioned, it's not the moderate weather that poses a threat but rather extreme winter weather events that pose the greatest risk to grid stability.