Following a highly volatile close to 2025, the January 2026 natural gas contract rallied more than 70 cents, ultimately settling at $4.687, an increase of 26 cents relative to the December settlement. During the second half of December, the market shifted a substantial portion of the winter risk premium into the January contract, as evidenced by the January 2026/February 2026 spread, which widened from approximately 25 cents to 70 cents (see Fig. 1-1). After the elevated settlement, weather forecasts turned warmer to start the new year, triggering a sharp pullback that saw the February 2026 contract decline by roughly 60 cents within the first 6 days of January.

This pronounced price correction has created potential opportunities for end users. Fig. 1-2 shows a historical price chart for a typical winter-weighted usage profile dating back to 2022. Prices reached a cyclical low of $3.17 near the end of the COVID-era demand downturn before rebounding to a peak of $5.16 nine months later. Since that period of heightened volatility, prices for the April 2026/March 2027 winter-weighted term have generally traded within a $4 to $4.50 range. As recently as early December, prices reached $4.59 and, as of close on January 6, declined by approximately 80 cents to $3.80. The current price of $3.80 sits slightly below the 10^th percentile of historical prices dating back to early 2022. While there’s no assurance prices can’t move lower, given the ongoing influence of weather and broader global uncertainties, the lower decile of the historical range has generally served as a constructive signal for customers to consider locking in a portion of their natural gas exposure.

U.S. natural gas storage inventories peaked at approximately 3.96 trillion cubic feet (Tcf) in early November. By the start of 2026, storage levels had declined to 3.256 Tcf, placing inventories 31 billion cubic feet (Bcf) above the 5-year average while remaining 123 Bcf below year-ago levels. Given the prevailing warm weather forecasts, storage balances are expected to surpass last year’s trajectory, which was shaped by a cooler-than-normal January. Looking ahead, analysts project U.S. storage inventories to stand near 1.875 Tcf at the start of the injection season, above typical historical levels, reflecting expectations for reduced winter demand and continued supply stability.

Over the past month, power markets in the PJM Interconnection have been materially affected by capacity market outcomes, accelerating load growth projections, regulatory intervention, and transmission system planning developments. Together, these factors reinforce that capacity costs and forward price risk in PJM remain structurally elevated and increasingly policy driven.

PJM released results for the 2027/2028 Base Residual Auction (BRA) on December 17, 2025. The regional transmission organization (RTO) cleared at the price ceiling of $333.44 per megawatt a day (MW/d), with approximately 134,478 MW unforced capacity (UCAP) procured, representing total capacity market value of roughly $16.4 billion. Despite clearing at the ceiling, the auction didn’t procure sufficient capacity to satisfy PJM’s Installed Reserve Margin (IRM) requirement, resulting in a shortfall of approximately 6.6 gigawatts (GW) UCAP relative to the IRM target. PJM’s sensitivity analysis indicates that absent the price floor and ceiling, the RTO clearing price would have exceeded $500 MW/d, implying substantially higher total auction costs. It’s currently unclear if a floor and ceiling will be established for future auctions, but without regulatory intervention, the capacity auction for 2027/2028 may clear above $500 MW/d.

Recent analysis highlights projected data center load growth is a primary driver of capacity requirements and costs. In their assessment of the auction outcome, Monitoring Analytics has estimated approximately $6.5 billion, or about 40%, of total 2027/2028 capacity auction costs are attributable to data center demand. A significant portion of this attributed load reflects projected facilities not yet constructed but incorporated into PJM’s load forecasts and reliability-planning assumptions. This dynamic increases uncertainty around future capacity procurement while simultaneously exerting upward pressure on clearing prices and reserve requirements.

Regulatory scrutiny intensified on December 18, 2025, when the Federal Energy Regulatory Commission (FERC) directed PJM to clarify tariff rules governing co-location arrangements between generation resources and large loads, including data centers. FERC concluded PJM’s existing interconnection and service framework doesn’t sufficiently address how these facilities should be modeled or how their arrangements may affect system reliability, transmission access, and cost allocation. This order is expected to lead to additional stakeholder processes and potential tariff changes, with implications for large-load interconnection timing and localized congestion impacts.

Transmission expansion planning has also accelerated in response to load-growth projections. On December 10, 2025, PJM advanced discussion of its first Regional Transmission Expansion Plan (RTEP) Window 1 portfolio, which is explicitly designed to address increased demand and power transfer constraints associated with emerging load centers, including in regions of Ohio and Northern Virginia. The preliminary cost estimate for the identified transmission upgrades is approximately $11.6 billion. These investments reflect PJM’s assessment that deliverability limitations, rather than generation availability alone, are increasingly central to maintaining system reliability under high-growth scenarios.

Collectively, developments over the past month indicate PJM is operating under tightening reliability conditions characterized by persistent capacity scarcity relative to targets, strong dependence on load forecasts tied to data center growth, heightened federal oversight of interconnection practices, and substantial transmission investment requirements. These dynamics suggest capacity costs will remain a significant and volatile component of forward power prices, with outcomes increasingly influenced by regulatory decisions and system planning assumptions rather than purely market-clearing fundamentals.

December 2025 finished as the 30^th warmest nationally since 1950 based on gas-weighted heating degree days (HDDs). Disparate temperature anomalies were featured across the U.S., as parts of the West averaged as much as 15 degrees above normal, while portions of the Midwest through Northeast ended 3 to 6 degrees below normal. The East, notably, came in as the 21^st coldest December since 1950 based on gas-weighted HDDs. In fact, only 3 other years since 2000 have finished colder: 2000, 2005, and 2010.

The first half of December featured the most significant cold across the eastern U.S., as temperatures averaged 10 to 15 degrees below normal across the Midwest and Northeast. The first 15 days of the month rank as the fifth coldest, and we haven’t experienced a colder start to the month since 2005.

January is on pace to be one of the top-20 warmest months nationally, as most of the country could potentially come in near to above the 30-year normal. The West continues to feature well above-normal temperatures, while the East holds closer to normal. Colder temperatures are currently in the forecast around the Martin Luther King Jr. holiday in the Midwest and East, but a few days of moderately below-normal temperatures may not be enough to push temperatures below normal for the month in those regions.