Defying gravity Why US Henry Hub natural gas prices are set to rise

Demand

US gas demand growth

Instead of simply absorbing supply, the US gas market is hungry for more. Power sector load is surging, driven by data centres and artificial intelligence (AI) investment, necessitating even more gas-fired generation to support it – to the tune of an extra 17 bcfd by the mid-2030s, an increase of nearly 50% from 2025 levels.

Meanwhile, final investment decision for new US LNG exports hit a record high in 2025 and more projects have already reached final investment decision in 2026. This will lead to US LNG capacity more than doubling compared to current levels, with more growth expected. The aggregate demand picture is one of continued expansion into the 2040s, with few opportunities for near-term substitution that could meaningfully reduce the gas intensity of the US energy system.

Figure 1: US gas demand 2015-35: continuing on the same trajectory

Supply

The best rock is found and producing

While substantial acreage remains undrilled across major US gas plays, producers have been leaning into the sweet spots for years. This has resulted in a form of perpetual high-grading that has consumed the best inventory year after year. As the best parts of the Marcellus, Permian and Haynesville are developed, the gas drilling projects that remain ‒ which are critical for growing production ‒ will be, by definition, of lower quality. Breakeven costs are flattening out after falling for years and future wells will be less productive on both production and reserve metrics, have more complex geology and often be further from market. Operators’ response will be to keep lowering well costs to combat productivity losses. Supply costs will rise, not because of declining operational efficiency, but because reservoirs have matured. And no new US basins of scale sit untapped. 

Figure 2:  Breakeven cost of supply over time ‒ flattening in the 2020s

Source: Wood Mackenzie Lens Gas & LNG, Lower 48 solution 

Future technology gains in mature plays appear incremental

The gains from re-engineering well designs or drilling longer laterals in gas plays have mostly played out already. And potential technology applications for the original shale gas basins, such as refracturing, have never really broken out.  Rather, technology efforts to unlock resource have been replaced by more robust gas marketing strategies instead. Deep gas plays have promise, but some of the main companies are struggling to find the right technology applications to lower costs.

This is quite unlike oil plays, where substantial R&D investment, led by the Majors, has unleashed stretch targets such as doubling recovery factors. But until gas margins compete with liquids plays, material technology investment will remain oil-biased.

Figure 3: Gas well efficiency still improving but step change was a decade ago

Source: Wood Mackenzie and Novi Labs, Inc. Sample set includes 48,000 horizontal gas wells in the Marcellus, Barnett, Eagle Ford, Haynesville and Fayetteville plays; dates represent first production year.

Decreasing impact of associated gas

Associated gas, produced as a co-product of oil drilling and effectively low- to zero-cost supply, has had a huge impact on the US gas supply landscape over the past decade. At its peak, Permian-driven associated gas growth materially offset the need for dedicated gas drilling, suppressing the price signal required to incentivise new supply. That dynamic is now slowing.

As the Permian Basin matures, more companies are focusing on boosting margins rather than volumes. Only those with differentiated value-chain integration continue to expand. As smaller operators preserve top inventory, the growth in associated gas will similarly decelerate as a function of less rig activity. Permian gas will still grow, but the rate of growth will change. Over the last 10 years, associated gas has accounted for about half of US gas supply growth, but over the next 10, it will account for less than 20%. This will amplify the need for gas-focused drilling to increase supply, requiring higher prices to be economic.

E&P capital discipline

Listed US exploration and production (E&P) companies remain committed to returning capital to shareholders, managing balance sheets and requiring genuinely attractive returns before committing to incremental drilling ‒ even choking back production when cash prices fall below operating costs. The implication for gas markets is that price signals will have to rise further and persist for longer before these operators are motivated to materially increase investment. Consequently, with the elasticity of supply to price declining, domestic gas prices are having to do more work to balance the market than in the past. As demand rises, price forecasts will have to rise as well to bring supply to market.

Henry Hub is the benchmark, but it is still a local price

Henry Hub serves as the central pricing benchmark for US gas markets. At the same time, it remains a localised price, shaped by supply, demand and infrastructure conditions in southern Louisiana. As demand and export growth have been concentrated in Texas and Louisiana, Henry Hub has evolved into a representation of the US demand market. Increasingly, it is influenced less by the lowest-cost supplies hundreds of miles away and more by the investment in midstream infrastructure required to bring supply to the region. While this transition began in the last decade, its growing impact – as pipeline developments to cover longer distances become more costly, requiring greenfield investment and/or facing increased local opposition – continues to be reflected in our forecast, which sees Henry Hub rising not only with underlying supply costs, but also with increasing midstream costs.

Source: Wood Mackenzie M&A Service

The inventory runs deeper still

Beyond active plays, two further categories of resource could add scalable supply: dormant plays that lost out to better economics, and frontier plays that have yet to be commercially developed.

Numerous US pre-shale gas plays were abandoned early because they lost the cost-of-supply battle to more prolific alternatives. However, modern well designs and drilling efficiencies could produce substantially better economics than their historical record implies. A prime example of this is tight gas acreage in the Rockies, driven by data-centre proximity and emerging private equity interest.

Then there are frontier resources that have never been fully commercially assessed. The western extension of the Haynesville/Bossier is the most visible instance today, and some operators are even targeting ultra-deep, high-pressure conventional reservoirs in Louisiana in light of proximate demand. Deep gas along the Texas Gulf Coast is always a price-sensitive supply option, too. Scale is a consideration. A handful of successful deeper developments could add a few bcfd in aggregate ‒ modest, but meaningful at the margin.

Technology wildcards

US E&Ps have been remarkable in their ability to bring down costs; the question is what comes next. If a wildcard technology emerges that fundamentally shifts recovery factors or significantly lowers breakevens, it could flatten the price curve outlined in our forecast.

Source: Wood Mackenzie Lens Gas & LNG; vintages annual Strategic Planning Outlooks

LNG dominance also creates vulnerability

We remain confident in the long-term Asian demand story that is driving investment in US LNG exports. It is worth noting, however, that as the marginal supplier to the global market, the US would feel any slowdown in the pace of demand growth disproportionately. The conflict in the Middle East is already testing the demand growth story. This has potentially significant implications for feedgas demand and Henry Hub prices.

And there is a further dimension to this risk. With US LNG capacity set to exceed one-third of global supply in the early 2030s, buyer concerns about over-concentration of supply are already emerging. Conflict-driven pressure to diversify could provide meaningful momentum for LNG projects outside North America ‒ Argentina being a credible recent example, or even a return of Russian supplies ‒ reducing the share of incremental demand flowing to US facilities. US LNG's scale, currently a commercial strength, risks becoming a liability when buyers begin to treat supplier diversity the way they treat shipping routes or counterparty diversity.

Figure 6: Global LNG supply – the US versus the rest of the world

Source: Wood Mackenzie Lens Gas & LNG

A pipeline renaissance

As mentioned, Henry Hub is increasingly influenced by the investment in midstream infrastructure required to bring supply to the region. Were the US to rapidly develop new pipelines to connect low-cost supply basins to market, this would compress basis differentials and erode the cost premium of moving molecules from supply to demand centres ‒ something last seen at scale during the 2010s shale boom, when thousands of miles of new pipeline were built in relatively quick succession.

Getting back there would require an easing of the underlying challenges that have stifled development: local opposition, state-level regulatory intervention and litigation have made new interstate pipeline projects slow, costly and high risk, deterring capital and leaving few projects even reaching the proposal stage. Some of those barriers may be softening, and early project revivals suggest conditions could be improving. Lead times are long and the barriers remain real, but a sustained shift in the development environment is a credible wildcard that could reduce basis spreads and put downward pressure on Henry Hub.