Beyond the Henry Hub headlines: A perspective on the path to 2030

September 11, 2026Over the next five years, the US natural gas system could face new demand, maturing supply, and constrained infrastructure all at once. This transition is likely to be bumpy, with mismatched development timelines that may lead to periodic dislocations as the market evolves. Some perspectives warn of possible market failure, gas shortages, and Henry Hub prices sustained above $5 per million British thermal units (MMBTU) by 2030.¹ While companies should test for a wide range of variables as part of their business planning process, several indicators point to critical “shock absorbers” in the system.

McKinsey analysis suggests a base case of $3.50 to $4.50/MMBTU by 2030 (in real 2025 dollars), up from the current $2.50 to $3.00/MMBTU,² with volatility expected to increase both through 2030 and beyond. This range depends on assumptions across four key factors: the composition of upstream production; the availability of new long-haul transmission capacity; the rise of power demand, especially from data centers; and the growth in liquefied natural gas (LNG) exports (exhibit).

1. Upstream production: Concentrated supply, offset by efficiency gains

Over the past decade, North American gas supply growth has been concentrated in three basins—Appalachia, the Permian, and Haynesville—which together produced about 75 percent of total supply growth.³ Output rose from approximately 90 billion cubic feet per day (bcfd) to about 126 bcfd between 2015 and 2025.⁴ These three basins, along with Western Canada’s Montney and Duvernay plays, could continue to account for the majority of North America’s gas supply for the next decade and beyond.⁵

Despite this maturing resource base and growing demand, two trends are emerging that counter concerns about substantially costlier future drilling. First, the share of associated gas—the gas that is produced alongside oil drilling—has grown from about 19 percent to 29 percent of total supply since 2014, reducing reliance on higher-cost dry gas.⁶ Second, shale breakevens fell by 30 to 40 percent between 2014 and 2018, driven by scale and technological advancements.⁷ While there is a risk that Tier-1 inventory (gas with breakevens below $2.30/MMBTU) is depleting, several technologies are now being tested that could, if scaled, cut oil and gas breakevens and reclassify Tier-2 sites across North America, extending the runway of cost-competitive gas supply.⁸

2. Long-haul transmission: Tight corridors with a significant bottleneck already easing

Pipeline capacity is tight on several major corridors, particularly out of Appalachia. New greenfield projects remain difficult to permit, but the system is not static. Expansions of existing Northeast pipelines⁹ have added nearly 5 bcfd over the past five years¹⁰ and can often be built faster than greenfield capacity, although this cost-competitive basin is likely to remain constrained.

West Texas is further along in its response. More than 15 bcfd of Permian egress projects are underway, which could ease today’s Waha constraint over the next two years.¹¹ More Permian gas reaching the market reduces the call on costlier supply and could ease pressure on national prices. Infrastructure is likely to remain a constraint in places, but the evidence does not suggest that every bottleneck will persist through 2030.

3. Power and data center demand: Growing, but still a small share of total demand

Data centers could materially increase gas consumption, particularly in already constrained regions. However, their impact on the North American balance may be smaller than what is forecast by some commentators. Our base case projects data center demand at roughly 3 to 5 percent of total North American natural gas demand by 2030.¹²

Project realization is also uncertain. In the first quarter of 2026, roughly 20 proposed US projects—more than 3.5 gigawatts and $40 billion of investment—were canceled.¹³ Data centers could therefore have an outsized impact on regional power and gas prices without being the primary determinant of Henry Hub.

4. LNG exports: A fast-growing market that follows the price rather than sets it

The United States already has about 15 bcfd of LNG export capacity, with another 13.5 bcfd expected to be post final investment decision (FID) or under construction by 2030.¹⁴ But capacity does not equal throughput. US LNG is often the marginal source of global supply due to higher operating costs, which makes exports responsive when global markets loosen or Henry Hub prices rise. If TTF (Title Transfer Facility) or JKM (Japan Korea Marker) prices fall, or Henry Hub prices rise, the economics of marginal US cargoes weaken and utilization could ramp down. This flexibility can reduce feedgas demand below nameplate capacity, softening the impact of LNG growth on the domestic gas balance.

Among a wide range of plausible outcomes, base case predicts a middle ground

The range of possible outcomes remains wide. Slower efficiency gains or faster demand growth could push prices higher, while stronger supply response, faster pipeline buildout, or slower demand growth could pull them lower. Our analysis suggests that upstream efficiency gains will continue, that pipeline capacity will be built where it is most economically viable (including some pipelines from Appalachia), and that LNG and data center demand will materialize at a measured pace to 2030. Together, these assumptions support a base case of $3.50 to $4.50/MMBTU, with increased volatility, by 2030.

However, a balanced national market can still produce pronounced regional imbalances, as seen historically.¹⁵ Low-cost supply basins can trade at persistent discounts when takeaway capacity is constrained, while high-demand regions can simultaneously trade at significant premiums when inbound pipeline capacity is tight. In other words, a balanced national price could coexist with materially higher or lower regional prices.

Looking at any single driver in isolation could support a case for structurally higher prices. Considered together, however, the evidence suggests a system that flexes rather than breaks. This is our base case analysis, not a certainty, as forecasting a market five years out warrants ongoing scrutiny. In part two of this series, we will examine the evidence in more depth and consider the implications for players across the gas value chain.

The authors wish to thank Gabriela Vargas, Maria Lopes, and Yinsheng Li for their contributions to this blog.

_{¹ “Analytical US natural gas price forecast: Outlook 2026–2030,” FXOpen, March 19, 2026.
² Natural gas, “Natural gas products,” US Energy Information Administration, accessed September 3, 2026.
³ McKinsey Energy Solutions North America Supply Model.
⁴ Based on dry gas content from upstream production, including ethane rejection; excludes offshore production and Alaska. For further reading, see Luciano Di Fiori, Brandon Stackhouse, Iqra Nadeem, and Kelsey French, “The infrastructure imperative: Who benefits from pipeline expansion?,” McKinsey, November 6, 2025.
⁵ McKinsey Energy Solutions North America Supply Model.
⁶ Calculated from total onshore dry gas content in North America (excludes offshore, Alaska, and oil sands) from McKinsey Energy Solutions North America Supply Model.
⁷ “Shale’s bold new era: What it means and how to succeed,” McKinsey, July 8, 2025.
⁸ “Shale’s next surge: How 27 innovations could unlock a new growth era,” McKinsey, March 17, 2026.
⁹ Including added compression, reversals, laterals, and pipeline “looping” (installing new parallel pipes to bolster capacity in one segment).
¹⁰ Natural gas, “Natural gas pipeline projects,” US Energy Information Administration, accessed August 2026.
¹¹ Natural gas, “Natural gas pipeline projects,” US Energy Information Administration, accessed August 2026.
¹² Andrew Warrell, Dumitru Dediu, and Parker Moore, “Capturing the $7 billion value in US and Canadian natural gas trading,” McKinsey, January 21, 2026.
¹³ McKinsey analysis.
¹⁴ Natural gas, “US liquefaction capacity,” US Energy Information Administration, accessed August 2026; McKinsey Global Gas Projects Database.
¹⁵ “Market dynamics vary at key natural gas pricing hubs,” US Energy Information Administration, October 23, 2024.}