What Winter Storm Fern reveals about the complicated relationship between domestic gas prices and LNG exports

In 2025, U.S. LNG exports shattered 2024’s records, averaging 3.27 Bcf per day more than the previous year. In December alone, 19.23 Bcf/d was delivered to LNG export facilities, representing 17% of all production from the lower 48, underscoring how far the market has shifted since 2015, when the U.S. was a net importer of LNG.

Much has been written about the impact of LNG exports on domestic natural gas prices in the U.S. Arguments over how much domestically produced natural gas should be supercooled into a liquified state, loaded onto ships and sold to markets thousands of miles away are still raging, even as the trade continues to grow. Compounding the debate, federal policy has reversed over the last two administrations, with the current White House approving and streamlining new LNG projects, mostly along the Gulf Coast.  

Originally a supply-driven location where no less than a dozen major pipelines intersect, the Henry Hub allowed supplies of natural gas to be redirected towards just about any market around the country. However, with the addition of three major LNG export facilities along the Louisiana coast over the past decade, totaling ~12 Bcf/d, the Henry Hub has shifted from a supply-push pricing hub to one driven by demand from LNG exporters.  

The impact of Winter Storm Fern in January provided useful insights into how LNG exports interact with short-term Henry Hub price signals. The chart below shows the relationship between LNG feedgas deliveries and Henry Hub spot prices from December 1, 2025, through January 31, 2026.  

From December 1 to January 2026, LNG export feedgas averaged a relatively flat 19.2 Bcf/d, while Henry Hub spot prices averaged $3.81 MMBtu, dipping to $3.13 on January 20. When Fern arrived the week of January 23, Henry Hub spiked to $30.57/MMBtu on January 27 (NGI price data).  

Notably, over the same period, LNG feedgas deliveries 9.4 Bcf in three days, to just 9.9 Bcf/d on January 26 (Bloomberg data), highlighting an inverse relationship between feedgas volumes and price. 

The drop in LNG export volumes during the price spike wasn’t coincidental — it was economics. Several LNG export facilities use tolling structures whereby the offtaker procures gas and transport and pays a fixed fee to the terminal operator to cover liquefaction and operating costs. A growing number of LNG offtake agreements are indexed to Henry Hub but source gas from non-Henry Hub indices via pipeline capacity that is controlled by the LNG offtaker. When U.S. regional spot prices rise above Henry Hub, keeping gas in the domestic market can be more profitable, at least during price spikes. On January 27, when Henry Hub spot pricing was at its peak, the national average spot price of all the other indices was $48.40/MMBtu, $18 higher than HH. As temperatures rose, spot prices fell back below $10/MMBtu, and LNG feedgas rebounded, averaging 18.2 Bcf/d from January 29 to February 2.  

Details of why each LNG facility reduced demand haven’t been made public. Most likely, operators cut feedgas to take advantage of high domestic prices or to protect liquefaction equipment from extreme cold. But the effect was clear: more gas remained onshore to meet increased domestic demand as several LNG facilities diverted gas back into the domestic market.  

Two competing arguments follow. Without rising LNG demand, U.S. production might not have expanded enough to cover winter peaks, and the system may not have been able to cope absent feedgas reductions during the winter storm. Then again, with lower LNG demand, pricing might not have spiked as sharply, making the episode an unnecessary cost burden for domestic consumers.  

The debate over how much LNG export is “too much” continues.