Permian consolidation is far from over, but the next deals will look different from the last

By Stephen Whitfield, Senior Editor

The Permian Basin has spent the better part of two years absorbing one mega-merger after another, but according to Matthew Bernstein, VP – North America Oil and Gas at Rystad Energy, the consolidation story is far from finished. Rather, it’s just entering a phase with fewer, and different, players.

According to Rystad data, the nine largest producers in the Permian now operate more than two-thirds of the basin’s total gross oil output, up from around 50% just three years ago.

That shift has been driven by a now-familiar list of transactions that took place in 2023 and 2024: ExxonMobil’s purchase of Pioneer Natural Resources, Diamondback Energy’s acquisition of Endeavor Energy Resources and Occidental’s deal for CrownRock.

What’s notable to Mr Bernstein is that the pace has not slowed since then. It’s simply changed shape, with a second wave of public-to-public deals that include Crescent Energy’s acquisition of Vital Energy, and the Devon Energy-Coterra Energy merger.

“This is the kind of consolidation activity that Rystad has been calling for, really, since 2024. We’re seeing this next phase of public-to-public mergers, and that’s something we really think is likely to continue,” Mr Bernstein said.

Why the next deals will look different

The logic driving further consolidation in the Permian isn’t just strategic – it’s structural. Mr Bernstein noted that there are not that many large private operators left to acquire, and the ones that remain are commanding steep prices.

Coterra’s diversified portfolio at the time of the merger announcement in February 2026 with Devon was valued at approximately $35,500 per net acre. By comparison, Rystad has tracked organic lease sales in the Permian this year fetching as much as $300,000 per net acre. The kind of scarcity premium seen this year is evidence of just how thin the remaining pool of available inventory has become, Mr Bernstein said.

In his view, that scarcity leaves potential acquirers with only one realistic lever left to pull: “For companies to really gain the kind of scale that investors are looking for, that public-to-public consolidation is the clearest route that we would expect to see.”

Among private operators, Mr Bernstein pointed to Mewbourne Oil and Continental Resources as the two largest remaining names in the basin, and both are notable for being family- or founder-owned rather than being backed by private equity. This sets them apart from typical private E&Ps driven by financial sponsors in how they’re run and, likely, how open they are to a sale.

Below that tier, a group of smaller private operators – Mr Bernstein pointed to Fasken Oil, BTA Oil Producers, Spur Energy and Double Eagle Energy, among others – has been notably responsive to this year’s stronger oil prices. They have added rigs to build production and increase the value of their proved developed producing assets, or oil and gas reserves from existing wells that are already drilled, completed and actively generating revenue. This action is often the prelude to a sale, he noted.

Firebird Energy’s sale to Continental in August 2026, and Birch Resources’ sale to Diversified Energy in the following month, are the most recent examples of the dynamic playing out among smaller operators, although such merger & acquisition (M&A) activities can only have limited impact on the Permian as a whole. “It’s not something that is going to lead to a portfolio-transformative acquisition, like what we saw with Endeavor or with CrownRock,” he said.

That’s why his attention is increasingly on the public side of the ledger. Specifically, he noted two companies focused on the Delaware Basin: Permian Resources and Matador Resources. Both are effectively pure-play Permian operators with high concentrations of premium inventory, and both have grown organically through lease sales and bolt-on deals, rather than through transformative M&As.

According to Rystad’s analysis, Permian Resources ranks as the sixth-largest inventory holder in the basin. It has roughly 5,500 remaining locations, more than 4,000 of which are classified as premium; this means that its remaining drilling inventory is commercially developable under a $55/bbl WTI price. Matador is smaller in scale but holds an even higher-quality book, with more than 90% of its remaining inventory falling below that $55/bbl breakeven.

Despite that quality, Mr Bernstein noted that both companies’ valuations have lagged the broader market of larger-scale Permian operators. It’s that valuation gap, more than anything else, that shapes his read on where the two companies are headed.

“Those companies either become very attractive acquisition targets, or they potentially could merge together to form what I think would be a pretty formidably sized, Delaware-focused E&P,” Mr Bernstein said.

If those two companies merge or if either is acquired by another party, a familiar value-creation playbook will likely unfold, he said: two companies that had been growing production aggressively combine, drop rigs on the back of operational synergies and still grow output.

The changing efficiency story

Capital efficiency has been the name of the game in the Permian for several years now, especially with the region’s sub-$55/bbl breakeven inventory now concentrated in the hands of a small number of large, disciplined operators. However, Mr Bernstein pushed back on the notion that there’s not much more efficiency left to wring out.

The 2010s shale revolution, he said, was fundamentally about spending capital to drill more wells and improve productivity. It was a race to add locations and push initial production rates higher. Today’s efficiency gains, he said, are focused less on how many wells get drilled and more on how much value gets extracted from each one.

The clearest evidence of that shift, according to Rystad, is in rig efficiency in the Delaware Basin. Applying 2022-level drilling efficiency to the 2026 rig count would not be enough to keep production growing, yet Rystad expects Delaware output to keep climbing. Mr Bernstein said this was not a contradiction.

“It not that operators are running meaningfully more rigs, it’s that the number of rigs needed just to hold production flat has fallen sharply as rigs have gotten faster and well designs have evolved,” he said.

Lateral length is the most visible sign of that shift. As recently as 2022, wells with laterals measuring 3 miles or longer were barely on the map – accounting for less than 5% of Permian footage drilled and completions, according to Rystad. By August 2026, they were making up 17% of Permian completions and 26% of total footage drilled.

This continued push for longer and longer laterals is rational from an economic perspective, he noted. While Rystad analysis found that a lateral can see up to a 20% degradation in per-foot productivity over a length of 3 miles, that’s typically still within the tolerated range for operators. Operators still see more cost savings from having to drill and complete fewer wells, with the longer lengths offsetting some lost productivity per foot.

Operators have also adopted innovative well designs like horseshoe wells to make these longer wells even more productive. These U-shaped laterals that once seemed like just a novelty have quietly become close to standard practice in smaller or non-contiguous spacing units over the past several years.

Innovations like this, Mr Bernstein said, represent exactly the kind of “grow without spending” mindset that now defines the Permian’s leading edge. Rather than drilling an uneconomical 1-mile lateral on a small, isolated parcel, operators can use a horseshoe design to recover oil from a much larger share of the reservoir beneath that acreage.

“The horseshoe wells have really enabled companies to, frankly, improve production more efficiently and be able to grow production without spending the money, and that’s always the name of the game,” he said.

Playing things cautious on costs

While 2026 has been a volatile year for oil prices, with the WTI swinging between the $60s to upwards of $100, inflation has not yet become a serious concern for E&Ps in the Permian, and that’s all due to operator behavior. Even in the face of higher oil prices, many of them are wary of price volatility and have not increased activity levels such that it would strain the supply chain.

Even growth-oriented E&Ps like Permian Resources and Matador have not added rigs this year in response to the price rally. Instead, E&Ps remain focused on squeezing more output from existing programs, leaning on workover activity and pulling forward completions. In some cases, they’re working through drilled-but-uncompleted (DUC) well inventories rather than deploying additional rigs, although he noted operators have shown a reluctance to fully deplete their DUC inventories just to chase a short-term price window.

Even ExxonMobil, which Mr Bernstein said is in “high-growth mode” and is targeting 2.5 million boed from the Permian by 2030, has not responded to oil price fluctuations. The company, he pointed out, is already an exception for targeting significant production growth while its peer group is mostly focused on either maintaining steady production or just modest growth.

“They’re staying put. They’re not going to add rigs. They’re going to continue to stick to their plan, and they don’t really care what the oil price does in the short term,” Mr Bernstein said.

Of course, ExxonMobil enjoys a scale advantage that most of their peers don’t have – the company holds more 14,000 gross operated locations in the Permian, spread across New Mexico and Texas in the Midland and Delaware basins. Such a position makes their production growth target credible – and is a reflection of how much the Permian’s growth story hinges on who holds the best acreage rather than who is willing to spend the most to develop it.

“What we’re seeing in the Permian is a smaller set of well-capitalized operators consolidating the best acreage, extracting more value per well through smarter design rather than brute force drilling and, for now, keeping their cost structures firmly in check,” he said.  DC