The article below is an excerpt from our Q1 2025 commentary.
In previous letters, we’ve written at length about our conviction that North American natural gas might well prove to be the best-performing commodity in the years to come. The reasoning, though perhaps inconvenient to consensus, is rooted in arithmetic: Henry Hub prices remain a staggering 70% below both the global gas benchmark and oil on an energy-equivalent basis. This discount, once a passing oddity, has now lingered for over fifteen years. But we suspect its time is up. If we are right—and markets have a way of confirming or refuting such suspicions with a kind of merciless clarity—then gas prices here at home could well double or even triple. Not many asset classes can make such a claim.
The reason North American gas prices have remained so chronically, stubbornly low lies in a phenomenon that once dazzled investors and policymakers alike: the shale revolution. Since its early stirrings in the mid-2000s, U.S. shale gas production has surged with almost maniacal consistency, reaching an astonishing 85 billion cubic feet per day. To translate for those more accustomed to oil metrics, that’s the rough equivalent of 14 million barrels per day—enough to rank as the second-largest hydrocarbon stream in the world, eclipsed only by U.S. crude itself. It has been, in every sense, a triumph of technology and scale. But as with all great triumphs, the shadow of excess has followed close behind.
So prolific was the surge in natural gas production that the United States, almost by accident, transformed itself. Coal-fired power plants were mothballed in favor of cleaner-burning gas. Towering petrochemical complexes and nitrogen fertilizer plants sprang up like so many totems to industrial confidence. And then, most improbably, the U.S. emerged as the world’s largest exporter of liquefied natural gas—an outcome few would have predicted when shale was still a curiosity.
And yet, even with this broad new tapestry of demand, production outpaced it all. Inventories swelled. Prices sagged. The gas was too cheap, too abundant, and altogether too eager to find a home.
But even the most bountiful feast must one day dwindle. Shale formations, for all their scale, are not inexhaustible. The era of unbridled growth is behind us. As with their oil-rich cousins, the best gas drilling sites—those easy, prolific, almost arrogant wells—have been tapped. We first flagged the risk of a production peak in 2019, when such talk was still theoretical, the stuff of conference panels and footnotes. Today, it is no longer academic. It is happening.
The numbers, as always, tell the tale—if one knows where to look and has the nerve to believe them. According to the EIA, U.S. dry gas production reached its zenith in February 2024, peaking at 104.8 billion cubic feet per day. Since then, output has quietly receded by a full billion cubic feet per day. It is a modest figure at first glance, but in context, it marks one of the most acute year-over-year declines in the history of shale development. Our own models, which have proven uncomfortably accurate before, suggest this descent is only beginning.
The great gas fields of the shale era have already whispered their farewells. The Marcellus in Pennsylvania—still the heavyweight of American gas—topped out at 27.8 bcf/d in late 2023. It now sits 1.2 bcf/d, or roughly 5%, below that high-water mark. The Haynesville, a once-bustling engine of supply in Louisiana and East Texas, crested at 14.7 bcf/d in May of last year; it has since fallen by 2.6 bcf/d—nearly 20%. Only the Permian Basin, clocking in at 20.2 bcf/d, has yet to exhibit clear signs of decline. But we believe that, too, is merely a matter of time.
Our neural networks help clarify the story. In the Marcellus, dry gas production grew steadily—by about 2.1 bcf/d per year—from 2015 to 2021. But starting in 2021, growth stopped, and by 2023, production peaked. The reason was geological. As operators exhausted the most productive core areas, they were forced to drill in less productive parts of the basin. New production per lateral foot also peaked in 2021 and is now 8% lower. At the same time, total lateral footage drilled per month has remained flat. As a result, new production couldn’t offset the natural declines from existing wells. By 2023, total output reached its high and has been falling since.
In the Permian, dry gas production growth has held up better, increasing by about 200 mmcf/d each month on average over the past few years. Like the Marcellus, new production per lateral foot peaked in 2021 and is now 8% lower. But unlike the Marcellus, where drilling activity has stayed flat, the total lateral footage drilled each month in the Permian has doubled. That’s largely because oil is the main target in much of the Permian, with natural gas produced as a byproduct. This has kept drilling activity more robust than in gas-focused basins like the Marcellus, allowing the region to better offset falling productivity with more wells.
Still, every basin facing geological depletion eventually runs into limits. More drilling can delay the effects, but it cannot prevent them. That point now seems close. The Permian rig count has already dropped 10% over the past year—from 310 to 282. Given the decline in well productivity and the lower rig count, we believe the current pace of drilling is no longer enough to replace declining base production. Field output is likely to begin falling.
With the Permian as the last major source of growth, its slowdown marks a turning point. Total U.S. dry gas production now appears poised to decline meaningfully from here.
This reversal in supply couldn’t come at a worse moment. Demand is accelerating. Gas-fired power generation—much of it built to serve the exploding needs of data centers—is already ramping up. At the same time, LNG export capacity continues to expand, with the U.S. setting new records for outbound volumes in recent months. Taken together, these trends point to the fastest growth in domestic gas demand in recent memory, arriving just as the supply curve begins to bend downward.
Had the shales still been in their prime, they might have risen to meet this surge in demand. But with productivity falling and production rolling over, it now seems nearly certain that the market will slip into deficit.
The winters of 2022–2023 and 2023–2024 dealt a heavy blow to North American natural gas, with unusually mild temperatures that sharply reduced heating demand. As a result, inventories swelled to multi-year highs. This past winter, however, returned to more typical patterns, allowing both the new demand base and tightening supply trends to assert themselves. The shift was dramatic: inventories fell from nearly 700 bcf above seasonal norms at the end of the prior winter to 214 bcf below average by March. That swing points to a market running a 2.5 bcf/d deficit—the tightest balance since the polar vortex winter of 2014.
While this past winter was colder than the two that preceded it, it was hardly extreme. Temperatures came in just 1% below the five-year average and remained nearly 15% warmer than the polar vortex winter of 2014—the last time the gas market was this tight. The difference now is demand. It has surged from new, structural sources.
When strong, steady demand collides with falling production, prices typically have only one direction to go. Investors in North American natural gas have had to wait longer than expected, as unusually warm winters postponed the inevitable. But as we often say, bear markets don’t last forever, rather they often live on borrowed time. In the case of North American gas, that time appears to have run out.
Curious to learn more? Read more in our Q1 2025 research newsletter, available for download below.
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