EIA predicts US natural gas output will smash records in 2026 and 2027

Story by Everett Sloane  msn.com

The U.S. Energy Information Administration released its latest Short-Term Energy Outlook on February 10, 2026, projecting that domestic dry natural gas production will set new records in both 2026 and 2027. The forecast arrives just weeks after Winter Storm Fern temporarily slashed output and spiked heating demand, raising questions about whether the country’s shale-driven supply engine can sustain its momentum through weather disruptions and shifting global export patterns. With the Permian Basin and Haynesville Shale expected to carry the heaviest load, the outlook signals that U.S. producers are preparing to push output well beyond levels not seen since the early 1970s.

Record Baseline Sets the Stage for Growth

The EIA’s forecast does not start from a low base. Preliminary data from the agency’s monthly statistics shows that U.S. dry natural gas production hit 110.1 billion cubic feet per day (Bcf/d) in November 2025, the highest monthly figure recorded since 1973. That number already exceeded what many analysts expected heading into winter, and it establishes the floor from which the agency projects further gains. It also underscores how quickly U.S. operators have been able to scale output in response to both domestic demand and global calls for additional supply.

Under the STEO’s baseline scenario, dry gas production is expected to average about 110 Bcf/d in 2026, representing roughly 2% growth over the prior year. The agency then projects output climbing to 111.24 Bcf/d in 2027, adding about another 1%. Those annual averages smooth over monthly swings, including the January dip caused by Winter Storm Fern, but the trajectory is clear: the U.S. is on track to produce more natural gas than at any point in its history. The STEO frames this expansion as part of a broader trend in which shale-driven gains continue to offset declines in older conventional fields, keeping overall production on an upward path.

Permian and Haynesville Drive the Supply Surge

Not all shale basins contribute equally to this growth. The Permian region alone is forecast to add around 1.4 Bcf/d in 2026 and another 0.6 Bcf/d in 2027, according to the EIA’s Today in Energy analysis. Much of this increase depends on new pipeline takeaway capacity coming online in the second half of 2026, which will relieve bottlenecks that have historically forced Permian operators to flare gas or curtail drilling. Higher drilling activity in the Haynesville area is also expected to respond to rising demand signals, particularly from the Gulf Coast LNG corridor where multiple export terminals are ramping up.

The mechanism behind these gains is worth understanding. The EIA’s broader national outlook highlights that much of the incremental gas will come from a handful of prolific shale plays, with the Permian, Haynesville, and Appalachia leading the way. In these basins, productivity improvements and higher initial production rates from new wells help offset the natural decline of older wells. When pipeline constraints ease and drilling economics improve, as the agency expects in the Permian by mid-2026, the balance tips decisively toward net production growth. For the Haynesville, the driver is more straightforward: proximity to LNG export terminals along the Louisiana and Texas coasts makes it a natural supplier as those facilities ramp up throughput and seek reliable feedgas.

Winter Storm Fern Tested the System

The forecast’s optimism is notable given how recently the market absorbed a significant supply shock. Winter Storm Fern swept across major producing regions in January 2026, temporarily cutting natural gas output while simultaneously driving up heating demand. The EIA acknowledged in a recent statement that the storm “caused significant short-term pressure on natural gas markets,” with record weekly storage withdrawals draining inventories faster than at any point during the current heating season. The event revived memories of earlier cold snaps that exposed vulnerabilities in wellhead and pipeline infrastructure, especially in regions unaccustomed to prolonged freezes.

Yet the agency expects production to have returned largely back online by early February, treating the disruption as a temporary setback rather than a structural constraint. That rapid recovery reflects how resilient the U.S. shale production system has become. Unlike conventional fields that take months to restart, shale wells can resume output relatively quickly once freeze-offs clear and surface equipment is restored. The storm did push the EIA to raise its near-term price forecast, but it did not alter the agency’s view that production will grow through both 2026 and 2027. Instead, Fern is framed as a stress test that the system passed, albeit with a reminder that extreme weather remains a wildcard for both supply and demand.

LNG Exports Pull More Gas to Market

Production records do not happen in a vacuum. A major reason the EIA expects output to keep climbing is that demand is growing in tandem, driven in large part by expanding liquefied natural gas export capacity. Facilities such as Plaquemines LNG in Louisiana and the latest expansion at Corpus Christi in Texas are continuing to ramp up toward full operation, pulling additional volumes of gas from domestic markets and sending them overseas. This export pull creates a price signal that incentivizes producers to drill more, particularly in basins with direct pipeline access to Gulf Coast terminals, and it underpins the EIA’s assumption that higher production can be absorbed without a sustained glut.

The connection between LNG exports and domestic production growth deserves scrutiny, though. While higher exports support drilling activity and create revenue for producers, they also tighten the domestic supply balance, which can push up prices for U.S. consumers and industrial users. The EIA’s short-term projections suggest Henry Hub spot prices may ease slightly in 2027 as supply catches up, but that assumes no further weather disruptions and smooth ramp-ups at new export facilities. Any delay at a major terminal, or another polar event like Winter Storm Fern, could quickly shift the balance back toward tighter markets and higher bills, particularly in regions that rely heavily on spot purchases rather than long-term contracts.

What the Forecast Leaves Uncertain

Despite its detailed numbers, the STEO leaves several crucial uncertainties unresolved. One is the durability of productivity gains in the core shale basins that the EIA expects to drive most of the growth. If drilling increasingly moves from “sweet spots” into less prolific acreage, the number of new wells required to maintain production could rise faster than anticipated, putting upward pressure on capital spending and potentially slowing the pace of output gains. The agency’s projections assume that technological improvements and operational efficiencies will continue to offset these geological headwinds, but that balance will only be proven in real time as operators respond to price signals and infrastructure constraints.

Another open question is how policymakers and regulators will respond to the combined effects of record production and surging LNG exports on domestic markets and emissions trajectories. The EIA’s role is to describe, not prescribe. Its outlook implicitly assumes that existing permitting frameworks for pipelines, export terminals, and upstream development remain largely intact through 2027. Any shift in those policies, or a stronger push for electrification and renewable generation that dampens gas demand in the power sector, could alter the path the STEO now sketches. For now, the agency’s latest numbers point to a U.S. gas industry that is doubling down on growth, betting that resilient shale basins, expanding export capacity, and a still-hungry global market will justify another round of record production in the years ahead.