U.S. natural gas futures closed higher on Friday, February 15, 2026, as market participants digested evolving weather projections for the latter part of the month and consistent demand from liquefied natural gas export facilities. The March contract for Henry Hub, the benchmark U.S. pricing point, settled at $3.243 per million British thermal units, marking an increase of 2.6 cents, or 0.81%.
Weather and Demand Dynamics in Focus
The primary driver for the session was the latest assessment of late-February temperatures. Analysts noted that the market remains highly sensitive to short-term weather patterns, which directly influence heating demand. A sustained warmer trend across the Midwest and Southern U.S. could rapidly reduce consumption, while a colder shift toward month's end would tighten the supply-demand balance, especially with LNG feedgas volumes holding firm.
Data indicated that dry natural gas production in the Lower 48 states was approximately 113.9 billion cubic feet per day on Friday. Total demand was estimated at 95.3 bcf/d, with net flows to LNG export terminals running near 19.2 bcf/d, providing a steady source of demand support.
Mixed Signals from the Rig Count
Supply-side indicators presented a nuanced picture. According to the latest weekly data from Baker Hughes, the number of active U.S. rigs drilling for natural gas increased by three, reaching a total of 133 for the week ending February 13. Conversely, the oil-directed rig count declined by three to 409. This left the overall national rig count unchanged at 551.
"Natural gas prices are unlikely to lose their volatility anytime soon," remarked Bryce Erickson of Mercer Capital. He identified weather variability, storage inventory levels, and global LNG trade flows as the key factors behind near-term price movements. "What has changed is the industry's ability to respond," he added, referencing the market's adaptive supply mechanisms.
Longer-Term Supply and Price Outlook
Beyond immediate weather models, the market is also weighing a longer-term production narrative. The U.S. Energy Information Administration forecasts that U.S. marketed natural gas output will average 120.8 bcf/d in 2026, climbing to 122.3 bcf/d in 2027. The agency anticipates growth will be concentrated in major shale plays, including Appalachia, the Haynesville, and the Permian Basin.
Concurrently, the EIA projects the average annual Henry Hub spot price to rise to $4.31 per mmBtu in 2026, up from an estimated $3.52 in 2025. This outlook reflects expectations for stronger demand and price levels sufficient to support ongoing drilling activity.
Infrastructure and Demand Growth
Pipeline operators are positioning for this anticipated expansion. In a recent earnings discussion cited by Reuters, management at TC Energy projected that North American natural gas demand could grow by roughly 45 bcf/d between 2025 and 2035. This growth is expected to be fueled by power generation needs, industrial expansion, and rising LNG exports.
For the immediate future, however, the daily market dynamic remains a tug-of-war. Cold weather forecasts can propel prices upward swiftly, while warmer revisions and robust production figures exert downward pressure just as quickly. While strong LNG exports can mitigate price declines, they may not fully offset the impact of rising domestic output.
Market Risks and Upcoming Catalysts
The primary downside risk remains straightforward: a sustained shift toward warmer weather into late February and March could cause heating demand to fade. This scenario would leave the market confronting elevated production levels, a higher rig count, and a consequently looser supply-demand balance.
When trading resumes, investors will scrutinize the next round of U.S. temperature forecasts, daily LNG feedgas data, and any signs of production disruptions. The next significant scheduled data release is the weekly U.S. natural gas storage report from the EIA on Thursday, February 19, followed by the subsequent weekly rig count update on February 20.
