‘Golden Age’ of NatGas Comes into Focus as Energy Market Landscape Shifts

Kimmeridge’s Mark Viviano needed only five words to describe the current energy market landscape.

“Something I never thought I’d say in my career, but ‘golden age of natural gas,’” he said onstage during the CERAWeek by S&P Global conference in March.

Oil has been the focus of drilling efforts and M&A activity since U.S. natural gas prices crashed in late 2022.

But natural gas is having a moment once again. Demand is growing from LNG exports, AI and power generation. Forward strip prices are rising.

“Our conviction continues to grow in the role of gas in the overall energy system, and particularly the role of LNG,” said Shell CEO Wael Sawan during the conference.

Shell executives anticipate LNG demand growing 60% between now and 2040—a 10% increase over projections the European supermajor issued just last year.

That’s “roughly 700 million tonnes or so,” between now and 2040, Sawan said.

The prospects for power generation and AI data centers also provide major upside to gas.

Henry Hub strip prices average about $4.58/Mcf during the next 12 months, according to CME Group data.

Prices have turned around quickly. Henry Hub settled at $1.21 on Nov. 8, its lowest level in over 25 years, according to U.S. Energy Information Administration (EIA) figures.

While hope has brightened for gas, the outlook for oil has turned bearish. WTI oil prices dropped below $70/bbl in early March due to tariff uncertainty and OPEC’s announcement  that it plans to increase output by 138,000 bbl/d in April—the cartel’s first increase since 2022.

The WTI strip averages about $65/bbl over the next 12 months; 24-month strip is $64/bbl, per CME Group data.

The new Trump administration’s stated goal of lowering oil prices has E&Ps concerned about oil falling into the $50s. Most producers aren’t willing to massively ramp up oil-focused drilling, however.

Forward prices are signaling the need for drilling activity to shift from oily plays to natural gas basins, like the Haynesville Shale and Appalachian Basin.

But ramping up production will be challenging. As producers increasingly look to the Haynesville to fill demand, Haynesville producers themselves want to see higher prices for a sustained period.

With average gross production of about 3 Bcf/d, Dallas-based Aethon Energy is sitting on multiple decades of Haynesville drilling inventory.

But to increase drilling, Aethon needs to see higher prices—preferably more than $5/Mcf—reflected in the long-term strip.

“We’re starting to see that in 2026, but that really needs to carry beyond ’26 into ’27 and ’28,” said Gordon Huddleston, Aethon president and partner, during CERAWeek.

Appalachia has its own takeaway issues that constrain moving gas production out of the basin. Some Marcellus and Utica producers, like Antero Resources, have managed to navigate notable volumes south into the LNG corridor.

Experts say gas will be needed from every basin to fill the projected demand. The Permian Basin, the Midcontinent and Barnett Shale will contribute.

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Gassed up in the Haynesville

Gas producers have spent the past two years waiting for LNG demand to show up. Now LNG is knocking at the door.

The producers, spurned too many times before, are cautiously watching as strip prices rise.

The Haynesville has the capacity to grow another 4 Bcf/d, according to EIA estimates.

Haynesville production averaged 14.1 Bcf/d in the fourth quarter but is expected to reach 18 Bcf/d by year-end 2026.

But experts and producers generally agree that a $5/Mcf Henry Hub price is needed for Haynesville producers to step up drilling, Jim Wicklund, a managing director with energy investment-banking firm PPHB, wrote after a NAPE dinner hosted by Raymond James.

Aethon Energy, one of the largest privately held U.S. gas producers, plans to keep output flat with a $1 billion in capex this year, Huddleston said.

The company could double its budget up to $2 billion, boosting production by another 500 MMcf/d to 600 MMcf/d after accounting for base declines.

“But these things don’t happen overnight,” Huddleston said, “and that’s why you need higher pricing.”

Scaling Haynesville output relies on just a handful of major operators, including Expand Energy, BP’s shale unit BPX Energy, Comstock Resources and Aethon itself.

BP CEO Murray Auchincloss said the U.K. supermajor is considering boosting U.S. gas output as prices rise.

“The time has come for the Haynesville,” Auchincloss said at CERAWeek.

Smaller operators include Exco Operating, GeoSouthern Energy’s GEP Haynesville, Paloma Natural Gas, Trinity Operating and Silver Hill Energy Partners. Matador Resources, more focused on the Permian Delaware Basin, also retains a small Cotton Valley footprint in the area.

International players also hold keys to scaling Haynesville output. TG Natural Resources is owned by Japan’s Tokyo Gas. Sabine Oil & Gas is owned by Osaka Gas.

Other international players, especially those with longterm LNG offtake contracts, are looking at ways to secure upstream gas supply from U.S. fields, Huddleston told Hart Energy in January.

Haynesville M&A

Experts say buyers want exposure to the Haynesville and other gassy plays as the long-term gas macro improves. But acreage is hard to come by in the Haynesville’s core.

The Haynesville’s top five operators own more than a 70% market share in the basin, making it the second-most consolidated shale play in North America, according to a Kimmeridge analysis from last year. Only the Denver-Julesburg (D-J) Basin is more consolidated.

Data from Enverus Intelligence Research show that the list of sizable Haynesville producers is quite short.

The gas fervor is attracting unlikely new faces. Haynesville producer Paloma Natural Gas sold to hedge fund giant Citadel in February 2025.

The purchase price was approximately $1.2 billion, sources close to the transaction told Hart Energy.

The Citadel deal included approximately 60 undrilled Haynesville locations across several Louisiana parishes.

Paloma, the eighth-largest Haynesville player, produced approximately 382 MMcf/d gross in 2024, according to Louisiana state data.

Paloma was backed by EnCap Investments.

In East Texas, Chevron is marketing a large, mostly undeveloped Haynesville property in Panola County. Chevron still held the acreage as of mid-March, according to Texas Railroad Commission data.

Chevron’s offer last spring was a sale or joint venture of the 71,000 net contiguous acres. Jefferies was the marketer in 2024.

In a flyer, Jefferies described it as “substantial virgin inventory with approximately 300 [potential] operated Haynesville locations.”

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Appalachia rising

EQT, the top pure-play Appalachia gas producer, sits on decades of Marcellus and Utica inventory.

But without pipeline egress to take the gas out of the basin, scaling production from Appalachia faces challenges.

“Simply put, it will take too long to increase gas production to meet this step change increase in demand during such a short time,” EQT CFO Jeremy Knop said in the company’s fourth-quarter earnings call in February.

The company is also closely watching an additional 5 Bcf/d of new takeaway capacity from the Permian slated for completion in late 2026. Qatar is also expected to bring 6 Bcf/d of LNG onto the global market around that time, he said.

“With these medium-term headwinds and the fact that capital spending would not result in additional production until mid-2026, we do not have plans to invest in production growth this year,” Knop said.

The inventory imbalance and higher prices are “a phenomenon of the timing mismatch of supply and demand, amplified by a cold winter and the theme of too little gas storage capacity,” he said.

In March, the EIA revised its outlook for natural gas prices upward due to higher consumption and lower storage inventories.

The EIA expects Henry Hub spot prices to average $4.20/MMBtu in 2025, 11% higher than its forecast last month. In 2026, spot prices should average around $4.50/MMBtu, a 7% increase over the previous year.

Other Appalachia producers are finding their way out of the basin. About 75% of Antero Resources’ 2.2 Bcf/d of gas output is transported into the Gulf Coast LNG corridor.

Antero held 521,000 net acres of gas, NGL and oil properties, primarily in Ohio and West Virginia, as of year-end 2024, regulatory filings show.

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Oil hunkers down

Falling oil prices are beginning to spook the industry.

“You’ve really got to hunker down,” said Scott Sheffield, former Pioneer Natural Resources CEO, during a Bloomberg Television interview at CERAWeek.

“You may have to lay off some people. You’ve got to focus on your best prospects. We’ll see what happens over the next two or three years.”

In February, Chevron announced plans to lay off 15% to 20% of its global workforce by the end of 2026.

U.S. oil output is near record highs. At the same time, the Trump administration is calling on OPEC to increase production, which could “easily push crude prices lower into the second quarter,” BOK Financial’s Dennis Kissler wrote in the March edition of Oil and Gas Investor.

Oil prices have been at relatively stable levels for the past two years. That helped fuel a record amount of shale M&A in oil-focused basins, mostly the Permian.

The major transactions included Exxon Mobil’s $60 billion acquisition of Pioneer. Diamondback Energy picked up private Midland producer Endeavor Energy Resources for $26 billion. And Oxy bought CrownRock for $12 billion.

But prices falling too low—or pushing too high—can have a chilling effect on dealmaking activity, said Andrew Dittmar, Enverus’ principal M&A analyst.

“You may see some bid-ask spread issues there with increased volatility in the market,” he said.