Why Natural Gas Prices Are Swinging With the Weather This Summer

U.S. natural gas cost $2.81 per MMBtu on August 26, 2026, up 1.42% from the day before. MMBtu stands for "million British thermal units," a standard way to measure energy. The reason: late-summer heat across the Gulf Coast, Midwest, and Mid-Atlantic kept air conditioners running, and those air conditioners run on electricity that often comes from burning natural gas. The Commodity Weather Group said forecasts had shifted hotter, with above-average temperatures expected across all three regions. CME Henry Hub futures (the main U.S. natural gas price benchmark, called NGV26) last traded at 2.857 on August 25, up 0.036 or 1.28%, on volume of 2,097 contracts.

It has been a bumpy summer for gas prices. Futures averaged $3.19 per MMBtu for the month through June 24, 2026, supported by strong gas production, according to the American Gas Association. Prices then dropped below $3 when a cooler weather outlook reduced expected demand from power plants, even though demand from LNG export facilities picked up. (LNG, or liquefied natural gas, is gas that has been super-chilled into liquid form so it can be shipped overseas.) The market then reversed higher as temperature forecasts were revised upward again. By late July, futures added to gains on expectations that late-summer heat would keep power-sector demand elevated.

The demand story extends beyond U.S. borders. U.S. natural gas exports to Mexico via southern border pipelines exceeded 8 Bcf/d in August 2026. Bcf/d means "billion cubic feet per day," a way of measuring gas volume. Hot weather in Mexico boosted their own cooling demand. The EIA (Energy Information Administration, a government agency) estimates total U.S. pipeline gas exports will average 9.6 Bcf/d in 2026, rising to 10.0 Bcf/d in 2027, up from 9.5 Bcf/d in 2025. On the industrial side, the EIA expects the natural gas-weighted manufacturing index to increase 1.5% in 2026 and 0.7% in 2027, contributing to slightly higher industrial gas consumption.

Storage data tells a different side of the story. Think of natural gas storage like a checking account: you deposit gas during warm months and withdraw it during cold months. U.S. working gas in storage stood at 3,169 Bcf as of August 14, 2026, a net deposit of 16 Bcf for the week. Earlier in the year, inventories had dropped to 5.6% below the five-year average following the winter heating season. However, maintenance at U.S. LNG export terminals reduced demand for gas to be shipped overseas, pushing storage levels above the five-year average in the South Central region. Nationally, inventories are relatively healthy, but the rate of deposits is expected to slow as cooling demand absorbs more supply in coming weeks. A hotter weather outlook was expected to bring the strongest cooling demand of the season and much lighter storage deposits in the weeks ahead.

The broader context here is a market caught between two forces. On one side, strong gas production has kept supply ample through the summer, limiting price increases even when weather turns hot. On the other, demand is growing from multiple directions: Mexican exports above 8 Bcf/d, rising industrial consumption, and peak air-conditioning load all compete for the same gas. The result is a market that swings sharply on weather forecast changes rather than big structural shifts. A few degrees of forecast change in the Gulf or Midwest can move prices by 3–5% in a single day.

For traders and risk managers, the key variable to watch is the rate of storage deposits over the next several EIA weekly reports. If deposits come in well below the 16 Bcf pace seen in mid-August, the storage cushion shrinks and prices become more sensitive to further heat. Conversely, if export-terminal maintenance ends and overseas demand picks up again, that could pull supply away from storage and tighten the balance further. The direction of prices likely depends less on production trends, which have been stable, and more on whether the late-summer heat persists into September or breaks earlier than expected. The EIA's pipeline export forecast for 2027 at 10.0 Bcf/d also implies continued demand growth that the market will need to account for as the warm-weather deposit season gives way to the next winter withdrawal cycle.