The US natural gas production story in May 2026 is one of conflicting signals. On one hand, the headline number — 108.4 Bcf/d of Lower 48 dry gas production — was flat week-over-week, suggesting a market stuck at current output levels. On the other hand, drilling and completion activity is clearly accelerating, with the frac spread count rising for four consecutive weeks and the rig count climbing to a two-month high. The disconnect between activity growth and actual production tells a story of infrastructure bottlenecks and associated-gas dynamics that are reshaping the US supply outlook.
Rig and frac activity is rising. Primary Vision data shows that producers added another five frac spreads in the latest week, bringing the Lower 48 total to 184. This marks the fourth consecutive week that the benchmark has increased by either four or five spreads — a sustained acceleration that typically translates into higher production volumes within 4–8 weeks as completed wells are brought online. Baker Hughes data corroborates the trend: Lower 48 operators added three more rigs last week, lifting the total to 551, the highest level since mid-March.
FACT: The sustained increase in frac spreads is notable because it signals that producers are committing capital to completing drilled-but-uncompleted (DUC) wells and new wells despite the relatively low $2.86 Henry Hub spot price. This suggests that associated gas from oil-directed drilling (particularly in the Permian Basin) is the primary driver, rather than pure-play gas economics.
The Permian paradox: growth and bottlenecks. The Permian Basin is the engine of US natural gas production growth, but its pipeline infrastructure is struggling to keep pace. The EIA's May STEO projects that the Permian region will produce 29.2 Bcf/d of natural gas in 2026, a 6% increase from 2025. However, the region faces severe pipeline takeaway constraints, as evidenced by persistently negative Waha Hub spot prices, which have averaged below zero for eight of the last nine months.
Waha, the pricing point for Permian natural gas, has traded in negative territory for extended periods because production routinely exceeds available pipeline egress capacity. When pipelines are full, producers must pay buyers to take gas — or, more commonly, are forced to flare or shut in wells. The negative Waha prices do not reflect a lack of demand for Permian gas; they reflect a lack of pipeline capacity to move it to premium markets. This dynamic creates a growing disconnect: rising Permian associated gas production that cannot reach Henry Hub or Gulf Coast LNG terminals efficiently, even as LNG demand rises.
New pipeline capacity is in development — including the Matterhorn Express and other projects — but these face regulatory delays, construction timelines, and cost overruns that have pushed in-service dates into 2027 for several key projects.
Associated gas dynamics. A critical feature of the current supply environment is the role of associated gas — natural gas produced as a byproduct of oil drilling. The Permian is predominantly an oil-producing region, and operators there are influenced primarily by crude oil prices. With Brent crude above $100/bbl, high oil prices are incentivising vigorous oil-directed drilling, which in turn produces growing volumes of associated gas regardless of natural gas prices.
The EIA forecasts that Lower 48 marketed natural gas production will increase 3% in 2026 compared with 2025, averaging 118.9 Bcf/d for the year, rising to 124.0 Bcf/d in 2027. This growth is driven mainly by the Permian and is supported by higher crude oil prices throughout 2026. The implication is that US gas production will continue to climb even if Henry Hub stays below $3, because the primary economic driver is oil, not gas.
Looking ahead. The combination of rising Permian associated gas output and constrained pipeline egress creates a two-tier market. For Gulf Coast LNG terminals and premium demand centres with pipeline access, gas is available at Henry Hub-linked prices. For Permian producers, effective realised prices are significantly lower — often negative — which constrains the economics of gathering, processing, and transport investments.
Market participants should watch the Permian basis differential as a leading indicator. If Waha prices remain deeply negative through summer, it signals that pipeline constraints are tightening rather than easing, which could cap the pace of production growth despite rising rig activity. If and when new pipeline capacity comes online, the release of constrained Permian supply could weigh on Henry Hub prices — but that relief is unlikely before 2027.
The Permian pipeline bottleneck creates both risk and opportunity. For buyers with access to Permian supply, the deeply negative Waha basis represents a potential discount relative to Henry Hub-indexed contracts — if they can secure firm transportation to deliver gas to premium markets. For buyers without Permian connectivity, the effective cost of Permian gas is Henry Hub plus transport, not Waha plus transport, so the negative basis is not directly accessible. Monitor Permian egress capacity additions and Waha basis trends: a narrowing of the Waha discount would signal that relief is coming, while persistent deep negativity suggests the bottleneck will continue to constrain effective supply growth.