Working gas in storage in the Lower 48 states stood at 3,922 billion cubic feet when the injection season ended, according to Energy Information Administration estimates based on the November 7 storage report. That is the most at the start of a winter since 2016, and 6% above the 2019 to 2023 average. For a market that will face rising LNG exports in 2025, it is a comfortable starting position.
How the market reached it is the interesting part. Net injections over the summer were 21% below the five-year average. Storage ended full not because a lot of gas went in, but because very little came out the previous winter, and because producers deliberately held back supply when prices collapsed. That pattern says something about how the US gas market now balances itself.
A full tank from a light draw
At the end of March 2024, inventories totaled 2,282 Bcf, 25% more than a year earlier and 40% above the five-year average for that time of year. The record-warm winter of 2023 to 2024 meant storage operators started the injection season far ahead of their targets.
That headstart let them finish with smaller injections. Net injections from April through October totaled 1,640 Bcf. Weekly injections ranged from 96 Bcf in late May to just 10 Bcf in mid-July, when a heat wave pushed gas burn for power to records. In some weeks, the South Central and Pacific regions saw net withdrawals during the summer, which is unusual but not unprecedented.
The final two weeks of the season, ending October 25 and November 1, saw injections above their five-year averages, a late boost that took inventories to the season's final total.
Production curtailment as a balancing tool
The EIA notes that low prices in 2024 encouraged producers to curtail output. That is a significant change in behavior. In earlier periods of oversupply, gas producers often kept drilling and producing, either because they had hedged their output at higher prices, because they needed cash flow to service debt, or because they were contractually committed to drilling programs.
In 2024, several large dry gas producers in Appalachia and the Haynesville explicitly reduced production and deferred completions in response to prices that, in March, fell to their lowest inflation-adjusted level since at least 1997. That self-restraint did two things. It limited how far prices fell, and it left gas in the ground rather than forcing it into storage. Without the curtailments, inventories would have been even higher and prices even lower.
The practical result is a market with two layers of flexibility. Storage absorbs weather surprises within a season. Production curtailment, by producers with low-cost reserves and the balance sheets to wait, absorbs price surprises across seasons. Both make the market more stable.
The western exception
Not every region shared in the recovery from the spring lows. In the Northwest and western Canada, prices hit historic lows through October 2024. At Westcoast Station 2, the western Canadian benchmark near Fort St. John in British Columbia, daily spot prices averaged $1.04 per MMBtu in 2024 through October, with a monthly low of $0.31 in September. The EIA attributes this to robust production in the Western Canadian Sedimentary Basin and high regional inventories.
That market is waiting for an outlet. LNG Canada, under construction on the British Columbia coast, is designed to take western Canadian gas to Asian markets. Until it starts, gas in the region has limited places to go, and prices reflect that. For the Pacific Northwest, the low Canadian prices are a benefit to consumers and a reminder of how much regional price outcomes depend on pipeline and export capacity.
What winter looks like from here
The EIA's November outlook forecasts withdrawals during the 2024 to 2025 heating season of 1,957 Bcf, with inventories ending winter 6% above the five-year average. That would be a solid outcome, leaving room for injections in 2025 even as new export capacity starts up.
For households, the EIA's Winter Fuels Outlook expects most to spend about the same or less on heating than last winter. Lower prices this winter are expected to be offset by colder temperatures than the unusually mild 2023 to 2024 season. Because weather is the largest source of uncertainty, the agency also publishes cases with temperatures 10% colder or 10% warmer than its base forecast.
The risk is not in the storage number
With storage this full, the risk of a price spike from a single cold snap is lower than in recent winters. The more meaningful risks are elsewhere.
The first is a sustained cold winter combined with production freeze-offs, of the kind seen in early 2024 when the system had to draw 326 Bcf in a single week. A full inventory handles that well. A full inventory drawn down hard in December and January handles it less well in February.
The second is the pace of the production recovery. Producers who curtailed output in 2024 will want to bring it back as prices improve. If they move slowly, waiting for clearer signals, the market could tighten in early 2025 just as new LNG export capacity ramps up.
The third is the power sector. Gas burn for electricity set records in summer 2024 and has become the most price-responsive part of demand. A cold winter with weak wind could drive power burn higher than heating-focused forecasts assume.
A market that has learned restraint
The headline is a full storage system entering winter. The more important story is that the US gas market balanced a severe surplus in 2024 without a collapse in production capacity or a wave of producer bankruptcies. Producers chose to hold back, storage did its job, and the power sector absorbed cheap gas.
That is a more mature market than the one that went through the price crashes of 2012, 2016 and 2020. It is also one in which producer decisions, rather than weather alone, will increasingly set prices. As export demand rises in 2025, those decisions will matter more than the size of this winter's starting inventory.