Natural gas prices spent most of 2024 at historically low levels, with the U.S. benchmark at Henry Hub averaging just $2.19 per million BTU for the year. That’s roughly 40% below the five-year average. Several forces converged to push prices down: record production volumes, mild winter weather, bloated storage inventories, and limited export capacity to move surplus gas overseas. Prices have since climbed into the $3 to $4 range in 2025, but understanding why they dropped so far helps explain where the market is headed.
Record Production Keeps Outpacing Demand
The U.S. is producing more natural gas than ever, and much of that supply hits the market regardless of what gas actually sells for. The reason is associated gas, the natural gas that comes up as a byproduct when companies drill for oil. In 2024, associated gas production averaged 18.5 billion cubic feet per day, a 6% jump from the year before. Because oil is the primary revenue source for these wells, operators keep drilling even when gas prices crater. The gas is essentially a free extra that floods the market.
The Permian Basin in West Texas and southeastern New Mexico drives most of this growth. Permian associated gas production rose 8% in 2024 to 12.5 billion cubic feet per day, accounting for nearly half of the region’s total gas output. Other oil-rich basins pile on: the Bakken in North Dakota produced 2.3 billion cubic feet per day of associated gas, and the Eagle Ford in South Texas added another 1.8 billion. Together, associated gas made up 37% of total production from these five major regions. That’s an enormous volume of supply that doesn’t respond to low prices the way a standalone gas well would.
Mild Winters Left Storage Tanks Full
Warm weather compounded the supply glut. The winter of 2023-2024 was notably mild across the eastern United States, which is where most residential heating demand is concentrated. Homes and businesses simply burned less gas than usual, leaving underground storage facilities unusually full heading into spring. By mid-2024, inventories sat 7% above the five-year average. Even by the end of the injection season in October, storage was still projected at 2% above normal levels.
High inventories act as a ceiling on prices. When storage is already brimming, there’s less urgency for utilities and traders to buy gas and lock in supply, which keeps downward pressure on the market throughout the year.
Pipeline Bottlenecks Created Negative Prices
The supply glut hit extreme levels in parts of West Texas, where production growth far outstripped the pipeline capacity needed to move gas to customers. At the Waha Hub, the main pricing point near the Permian Basin, natural gas traded at negative prices on 42% of trading days in 2024. That means producers were literally paying someone to take their gas off their hands rather than shut down oil wells.
Relief arrived in October 2024 when the Matterhorn Express Pipeline entered service, adding 2.5 billion cubic feet per day of capacity from the Permian Basin to the Texas coast. Since mid-November 2024, Waha prices have stayed above zero. But the months of negative pricing illustrate just how badly production outran infrastructure in the region.
Limited LNG Export Capacity
One natural outlet for excess gas is shipping it overseas as liquefied natural gas, where buyers in Europe and Asia pay higher prices. But U.S. export terminals were running near full capacity throughout 2024, with North American LNG export capacity sitting at about 11.4 billion cubic feet per day at the start of the year. Surplus gas had nowhere to go internationally.
That’s changing. Plaquemines LNG in Louisiana shipped its first cargo in December 2024, and two more facilities began sending out cargoes in early 2025. Five additional export projects are under construction along the Gulf Coast, with a combined capacity of about 10 billion cubic feet per day. If all planned projects come online on schedule, U.S. liquefaction capacity will more than double by 2029, reaching roughly 25 billion cubic feet per day. Pipeline construction delays remain a risk, but the wave of new export capacity should absorb a significant share of the domestic surplus over the next few years.
Cheap Gas Fueled Record Power Generation
Low prices did boost demand in one major sector. Natural gas powered 45% of U.S. electricity generation during the summer of 2024, up from 29% a decade earlier. On August 2, 2024, gas-fired power plants produced more than 7 million megawatt-hours in a single day, a new record. Hotter summer temperatures, new gas-fired generating capacity, and the price advantage over coal all contributed. But even this surge in electricity demand wasn’t enough to absorb the flood of new supply hitting the market.
Why Prices Are Climbing in 2025
The market has tightened considerably since the lows of early 2024. Henry Hub prices jumped to $4.13 in January 2025 and have generally held in the $3 to $4 range through the year, with December 2025 reaching $4.26. The shift reflects a colder start to the 2024-2025 winter drawing down storage, new LNG export terminals pulling more gas out of the domestic market, and some producers voluntarily curtailing output after months of unprofitable prices.
The Energy Information Administration projects the Henry Hub spot price will average $3.53 in 2025, rising to $4.31 in 2026 and $4.38 in 2027. The upward trajectory is driven largely by new LNG export demand. As each terminal begins commercial operations, it creates a permanent new source of consumption for domestically produced gas, tightening the balance between supply and demand that was so lopsided in 2024.
Still, the same structural forces that crushed prices haven’t disappeared. Permian oil production continues to grow, dragging associated gas along with it. If export projects face construction delays or if another mild winter reduces heating demand, prices could soften again. The era of sub-$2 gas may be fading, but the U.S. remains a market defined by abundant, low-cost supply.