Why the Permian Basin won’t replace lost Middle East oil, with Jai Singh and Matthew Bernstein

**Let's Talk Energy — What's Next for the Permian Basin?** Host: Noah Brenner Guests: Jay Singh, Head of US Oil & Gas Research, Rystad Energy · Matthew Bernstein, Product Manager, Shale Research, Rystad Energy *This transcript has been lightly edited for clarity.* [00:00] Noah: This is Let's Talk Energy, your go-to podcast for smart energy insights. I'm Noah Brenner. I hope our listeners in the Northern Hemisphere had a fantastic summer break — I know I did — and I'm excited to be back talking energy with you again. We're going to kick it off with a simple query: what's next for the Permian Basin? You could argue this has been the single most important question to understanding global oil supply — if not the entire oil industry — for much of the past decade. Permian production has more than tripled since the start of the US tight oil revolution around 2014, and now sits well above 6 million barrels of oil per day — almost half of all US oil output — and well more than 20 billion cubic feet of natural gas per day. In the process, hundreds of companies sprang up, rapidly drilled, merged, drilled a bit slower, and merged again into giants as they sought to win over investors whose demands shifted from rapid growth to cash returns. While the days of jaw-dropping production gains are probably over, the basin remains one of the most important sources of flexible oil supply, and is the crown jewel in the portfolios of many of the largest US oil firms. But there are still questions to answer. How much affordable oil is left in the Permian, and how long might operators keep up current rates of production? Which companies control the highest number of choice locations, and do they have enough to earn the confidence of investors keen to know whether their cash returns are sustainable? And finally, what are the implications of the rising volumes of natural gas that are trading at much higher prices than in the past? To help us understand what's next for the biggest oil field in the world's largest oil producer, I'm joined from Houston by Jay Singh, who leads our oil and gas research team in the US. Jay, welcome back to the program. Jay Singh: Thanks, Noah. Noah: And from Oslo, I have Matthew Bernstein, product manager for Rystad Energy's shale research. Matt, good to have you back as well. Matthew Bernstein: Great to be here, Noah. Thanks. Noah: Well, gentlemen — let's talk energy. Jay, I want to start with what's happening today. What have we seen in terms of activity this year in the Permian? There's been a ton of debate among companies about whether to ramp up and capture some of the higher oil prices we see on some days and not others. But at the same time, many are predicting prices go down if we see an end to the war. So how are companies responding to these extraordinary circumstances? Jay Singh: For precisely that reason, we haven't seen much of a response from the Permian on production. We came into this year with the basin producing about 6.7 million barrels per day, and we'll probably exit at about 170,000 barrels per day higher. That's a pretty muted response — less than 3% in our forecast. The reason is the uncertainty around where the price will land. The front month is typically much higher than looking six or seven months out — by which time, once you've added a rig, prices may be substantially lower. So we haven't seen much of a reaction. For those accustomed to shale being extremely responsive, this is not the same shale industry that, from mid-2017 to mid-2018, added a million barrels per day. That's when oil prices ran from about $50 to $70 — and of course that was from a smaller base, going from two and a half million to three and a half million barrels per day. The industry is no longer set up to be very responsive to oil prices, and you can see that most starkly in the Permian. [04:00] Noah: The two of you have just released your latest report on undrilled wells — the remaining locations in the basin. Give us two or three headline takeaways, and how those factors feed back into that slower, more measured growth or plateau you just described. Matthew Bernstein: The key headline is that when you think about the longer-term picture for the basin — which is really the premier shale supply and premier oil supply in the world — we think there's enough inventory to sustain 16 years of drilling at the pace we've seen over the past few years. And that's of sub-$55-per-barrel wells, on a PV20 basis — so very commercial wells in the grand scheme of things. But as Jay alluded to, this isn't the same Permian Basin we were looking at five to ten years ago, when you had all these wildcatters and very actively drilling companies. That 16 years of inventory has become incredibly consolidated — to the point where five companies (ExxonMobil, ConocoPhillips, Diamondback, Devon and Occidental) hold about half of that remaining inventory. In the Midland Basin it's even more stark, with ExxonMobil and Diamondback holding about half of that premium inventory. So it's really these large operators running very disciplined programs, navigating the bulk of production based on what their shareholders want — which is consistent cash returns. Noah: Jay, help me understand from a macro perspective: what does a slower response from the Permian say about the ability of US oil production overall to grow? The Permian makes up almost half of US oil, so if it's slower to respond, I'd assume US output overall is too. Jay Singh: The short answer is the US can grow — we just don't expect it to mimic the growth patterns of the past, in part because of all the capital that's already been deployed. There's lots of resource in the Gulf of America, lots in Alaska, and of course lots in shale. One thing I'd add to what Matt said about inventory: there's plenty of running room. When I see reports saying tier one is waning in the Permian and therefore X, Y or Z, it's important to keep perspective. The larger operators we tend to talk about are looking for the next decade. EOG isn't going to the UAE shales because there's a problem right now in the Permian or a lack of running room — it's to set themselves up for the next decade. So there's no crisis per se; there's plenty of resource. For a decade now, many of the smaller E&Ps — a lot of them publicly traded and since acquired — burned through cash in pursuit of production growth. Now the name of the game is cash flow and returns. So you have large, highly consolidated companies that aren't going to be as responsive to prices, because they're managing for returns and capital efficiency. Why go out and sanction new gathering or processing capacity when, if you slow the development pace, you can drill to fill facilities and be very capital efficient? [08:00] Jay Singh: So for the growth we've had this year, I'd venture that when we look back, it'll be mostly smaller names and private companies adding the production. Noah: Matt, was there anything that surprised you in the results? And, as an aside for those not driving around the Permian — when we talk tier one, two, three and four acreage, tier one is the best: the locations that break even and make money at very low oil prices, on up through tiers two, three and four. Matthew Bernstein: Perhaps not a surprise, but it paints a stark picture of a couple of things. One is the development of the stacked formations we've seen over the past eight years or so. If you look at the number of stacked formations companies are drilling within a given spacing unit, it went from five or six at the high end a decade ago — or even less — to certain units in the core of the Permian Delaware and Permian Midland where you're now targeting nine or ten separate intervals within a single spacing unit. So it's this idea Jay alluded to that the basin isn't going away anytime soon. Call it the "permanent" basin. Noah: [laughs] We can't take credit for that. Matthew Bernstein: It's a good one. There's always talk of inventory depletion, but as much as companies have drilled in the past decade, we're now targeting more and more formations — and there's a new frontier of deeper zones, the Woodford and Barnett, that are becoming part of the core inventory for a lot of operators. Secondly, on the corporate side — again, maybe not a surprise, but it strengthened the view on the conundrum some of these medium-cap publicly traded firms face. As Jay said, you're looking out to the next 10 to 20 years and asking how you keep this proposition of consistent cash returns to shareholders. For a company like EOG — which is maybe on the lower end of remaining years of Permian drilling — they're large, with assets across US shale and around the world, and they continue to explore. But a lot of medium-cap pure Permian or pure shale firms are being punished in the public equity markets, where their valuations lag the larger-cap firms even if they have an industry-average 10 to 15 years of remaining drilling. They lack that absolute scale — companies like Permian Resources, Matador, SM Energy — and investors want them to go out and build scale further, which is very challenging in a basin that's already so consolidated. Noah: Could the Permian still surprise us to the upside? Is there potential for enhanced oil recovery, refracs, or opportunities to drill the other formations Matt mentioned? Jay Singh: We shouldn't underestimate technology. Exxon touts that they're looking at deploying about 40 technologies. Add that to what everyone else is experimenting with, and you get a sum of incremental gains — a constant efficiency improvement that drives down cost per foot of lateral drilled. [12:00] Jay Singh: It's important to note that our inventory figures — quite healthy, at 16 years of premium sub-$55-per-barrel, NPV20 breakeven — are a snapshot in time. That's at today's costs and today's technology. So what's tier four in our models today could be a much better well in the future. We geospatially place the lateral into the formation and call it tier four based on what we think the well would cost and produce — and both of those are dynamic. That's why we stay on top of this and constantly evolve our models. We've got people going out to Midland; I was there earlier this week trying to assess what's actually happening on the ground. As Matt mentioned, the Woodford and Barnett are heavy in the discussions now — deeper, and toward the fringes of the core of the basin, which is the name of the game in shale. Kimmeridge put out an interesting note on deeper formations becoming much more viable, and in some ways more attractive on a returns basis than some of the shallower ones. So it's definitely evolving, and we're nowhere near done in the shale patch on efficiencies and technology. We can just keep chipping away at cost per foot. Noah: Matt, we've mentioned companies are cautious about production growth, and investors want cash returns that are sustainable and underpinned by strong production. The one difference in strategy might be ExxonMobil — the largest US oil company — which is trying to push Permian production from around 1.8 million barrels of oil equivalent per day to about 2.5 million. What's different? Why is ExxonMobil pursuing growth, and what about its portfolio enables it? Matthew Bernstein: That 2.5 million is 2.5 million barrels of oil equivalent per day in the Permian by 2030. From today's 1.8 million — and last year averaging 1.6 — you're really getting a CAGR in the upper single-digit percentages, whereas most companies are trying to maintain and slightly grow year on year. So a very big difference. The way I see it, Exxon has the right acreage, the scale, and the quality of scale. They're by far the largest acreage and inventory holder in the Permian — in our analysis, over 14,000 gross operated locations spread across New Mexico and Texas, Midland and Delaware. A very large position, and predominantly premium inventory. So absolute scale and quality of scale. [16:00] Matthew Bernstein: Then, as Jay referenced with those 40 technologies, they've become something of a leader in what everyone's trying to do — not necessarily growing via rig additions, but by extracting more oil and gas per well and drilling more wells faster. If you look at what's happening with other companies today, a lot that aren't adding rigs are still broadcasting zero to two percent growth as a result of efficiencies and recoveries. What Exxon's been able to do at its scale is deploy well-designed techniques — for example, over half their wells in the last year being ultra-long laterals over 13,000 feet, and using a proprietary petroleum coke, or petcoke, in their proppant, which they've indicated leads to higher well recoveries. They're doing everything they can to lower finding and development costs — lowering well cost while increasing EURs. That's become the name of the game. Noah: People ask why Chevron — two very large companies with big Permian positions — is approaching things so differently. Jay, from your analysis of Chevron's Permian acreage, why might that strategy make sense for them? Jay Singh: The underlying assets are fundamentally different. The big one is that Chevron is much larger as a non-operated player in the Permian, by virtue of the legacy and transactions that built their scale there — lots of royalties, minerals and so on. So they have a smaller operated position, and they'll grow the Permian partly through their non-ops. The whole industry has been burned by chasing prices. For a company that's just added Guyana — Hess — to the portfolio, where their operating partner Exxon is adding a ninth FPSO and it's really growing, and where in the Permian they have a healthy decade-plus (about 15 years) of premium drilling remaining, I think they'd much rather develop that deliberately, with all the technology improvements and efficiencies likely to come, rather than juice the basin and get ahead of what they'd already planned just to realize potentially higher prices. They're too large to want to add a rig and hedge production for next year — it wouldn't be worth their while. Part of the reason Exxon is growing is that they were planning to do it before the war. So it's steady as she goes for some of these larger players. For the supermajors, what makes the Permian attractive is that it's a giant conventional project now — you can manage facilities and capital deployment in a much more structured, efficient way. Mike Wirth has that track record of emphasizing returns and hurdle rates. So it's a different ballgame for Chevron in the Permian, precisely because of portfolio. It always comes down to portfolio. [20:00] Noah: We've said a couple of times that investors pay a premium for companies with more inventory — a longer runway of good locations. How much inventory does a company need? Is there a number where investors say, "Okay, ten years, that's good, I'll buy your stock"? Or does it change company to company? Jay Singh: It's really company-dependent. If you're a Permian pure play, you've got a very different challenge. Larger E&Ps especially are thinking about options for the next decade. Even during the post-COVID years people asked, "Why explore? We don't need to." But it's always about adding attractive options to your portfolio. We've mentioned EOG exploring shale in the UAE — really exciting so far, though still exploration. They're not exploring the UAE for the 2020s; they're exploring it for the 2030s, to give them another option — the same way Shell drilling a deepwater exploration well gives them an option to bring to production many years down the line after appraisal. Whereas Matador, a Permian pure-play company, has a different challenge: they're not going to Vaca Muerta or the Beetaloo Basin, they're not going international. The Permian is their playground, and that's where you want to keep extending your inventory life through constant transactions and land deals. Noah: You and your colleagues have argued there's more to come here. Where should we look for the next deal? You mentioned Matador and these Permian pure plays that need to add inventory — are those the companies that might be buyers or sellers in the churn? Jay Singh: We've been calling for public-to-public consolidation as the next wave. To put it in perspective, the top nine producers in the Permian now control two-thirds of the oil supply. That's up from 40% — accounting for M&A, not organic growth — just since 2023, as those same entities. That was driven by mega-deals: Exxon acquiring Pioneer, Diamondback acquiring Endeavor, Oxy acquiring CrownRock — very large deals in 2023 and 2024 that transformed the basin and the shale patch more broadly. As we've seen this divergence between companies with scale and companies without, we've looked to public-to-public mergers as the next way to build scale, because a lot of the smaller privates right now — outside Mewbourne and Continental — just aren't the needle-movers that an Endeavor was for Diamondback, where you enter a new league of scale. We've already seen it kick off: Devon merged with Coterra — [24:00] Jay Singh: — and SM Energy with Civitas. Those deals over the past six to twelve months are what we'd been expecting, and I think that next phase continues, perhaps even with some smaller mid-cap Permian companies. Noah: Is there still public and private leasing to be had in the basin, or is it all leased up? Jay Singh: It's still a very dynamic land market in West Texas — it never seems dull. Even through the crash of 2015 there was a flurry of land deals, and the transactions market out there is extremely active. Individual deals are small by global industry standards, but for the Permian pure plays they add up and are really important. Permian Resources is probably the poster child. It's a pure play built to constantly evaluate and add acreage around what they have. They disclosed on their second-quarter earnings that they acquired about 54,000 net acres year to date for total consideration of about a billion dollars — but the kicker is that it came through 190 transactions. You're not going to have a team from Chevron or Exxon doing that kind of small-ball M&A. They'll do deals, but not on that scale. It speaks to the liquidity — how much can get done. Permian Resources' CEO was quoted quite a bit from second-quarter earnings, saying a great deal came to them over drinks in Midland. That still happens. The average was about $13,000 per acre on those leases, according to management — which is pretty good. Noah: Given what we've seen at some of the BLM public sales, that's pocket change compared to what's transacting. Jay Singh: Exactly. Federal lease sales are another way to add acreage. Recently we saw the New Mexico lease sales, where Devon and Matador bid very aggressively to win what they see — probably rightfully — as tier one acreage. The eBay-style bidding makes it interesting, and the federal government set it up through an efficient market. If you win a parcel for $351,000 an acre, that means someone else was at $350,000 — a dollar lower. So it was really two key operators driving those results. Some parcels went for more than $300,000 an acre. Matador rightfully faced questions on earnings about whether they were overpaying — [28:00] Jay Singh: — and they were correct to point out that they were thought to be overpaying in 2018, when they took federal leases with some parcels as high as $95,000 an acre, and those deals turned out really well. So they'd say they've earned the benefit of the doubt. Noah: Let's talk about gas. There's a ton of it in the Permian, and its importance is growing as prices improve. For those not familiar with the basin: gas trades at the Waha hub in West Texas — that's where a lot of it goes — and prices there have often fallen into negative territory because there isn't enough infrastructure to handle all the production and get it to the hub. That's changing, with new pipelines coming online. We've seen prices jump from an all-time low this spring of around negative $9.60 to a bit over $2 today. That's a large swing, and it has implications. Matt, what does a higher gas price mean for activity in the basin? Matthew Bernstein: Two things. First, the Permian is still — and for the foreseeable future will be — an oil-producing basin. Companies are drilling for oil, driven by oil economics, but producing a lot of natural gas as a result from the same wells — associated gas. Especially as companies get more efficient and drill fewer wells, natural gas becomes a larger share of total production, because gas declines at a much slower pace than oil. So as they drill, they're putting more and more gas to market, which is why we've seen so many takeaway constraints this year. Looking into 2027, with improved takeaway it will lead to improved well-level economics and alleviate some headaches — earlier this year companies were actually shutting in wells in certain cases, where even at $80-per-barrel oil it wasn't worth taking the hit on the natural gas. That should be alleviated in the short term. Overall, even if oil prices are lower next year, drilling will still be concentrated on oil economics. That said, looking into the future — a lot of what we've discussed is about extending your resource lifetime. One of those potential avenues is the deeper zones in the Permian: the Wolfcamp D, the Wolfcamp C, and the Woodford and Barnett. There's been very limited drilling and a very limited universe of wells to judge results, because there's never really been, in the modern shale era, an incentive to drill for natural gas in the Permian — it's more something you get as a result. [32:00] Matthew Bernstein: So if we get improved gas takeaway next year, then as we look into the 2030s and beyond — when you could have a very bullish demand story for US natural gas at large — this next year or so will give operators the opportunity to start delineating some of these deeper benches and gas-heavier wells, in a way where you're probably still realizing returns even if you're just testing them. Drilling will still be oil-focused, but you'll start to see more testing of natural gas zones in the mix. Noah: And overall — with the LNG liquefaction and data-center demand — how are companies thinking strategically about this gas opportunity? Jay Singh: The Permian gas story really started to reshape this year, and not just because of price. Waha is about two dollars today — roughly a dollar under Henry Hub. When Waha is negative, it essentially means you're paying someone else to take it. When everyone was in growth mode, it made sense to just deal with the nuisance of natural gas. Now, even among the Permian pure plays, they have the luxury of thinking more strategically about how they monetize their gas. Yes, it's an oil-driven basin, but if you're getting three or four dollars for your Waha gas sometime in the future, that changes your oil breakeven. Noah: Meaning they think about it in terms of the return on the well, not just how much they're getting for their oil. Jay Singh: Exactly — they're interested in making money more than in making barrels. So it's increasingly part of the equation. Two developments this week brought it home. First, Exxon — after saying on Q2 earnings that they weren't particularly interested in targeting their gassier formations — went out and signed a 20-year gathering, processing and transportation agreement with Targa to handle a massive increase in gas production from both Midland and Delaware, adding to their acreage dedications to Targa. So a long-term focus on getting a handle on all of this gas, which is coming mostly as a result of trying to grow their oil. Second, Whitewater Midstream — successful developers of several pipelines, including Matterhorn — announced twin 48-inch pipelines from the Permian to Katy, scalable to about 5 Bcf per day. That's extremely impressive. We knew they had a project up their sleeve, but the scale took me by surprise. It speaks to more and more E&Ps leaning into their gas marketing plans, preferring to commit to a pipeline project like this rather than risk paying others to take their gas by selling into Waha. It's a de-risking of future operations — allowing oil to grow while getting, on a risk-adjusted basis, better money for their gas. Those two developments this week really speak to how the Permian gas story deserves a lot more attention. Noah: Gentlemen, we could talk about the Permian — or the "permanent" basin — forever. But let's wrap up. Any parting thoughts? Anything we haven't touched on that we should be? Matthew Bernstein: Something we've started to see at the cutting edge this year: certain well designs — four-mile laterals, horseshoe wells — that were almost science fiction a couple of years ago, in the early 2020s, are now gaining prominence. [36:00] Matthew Bernstein: These aren't just cool feats of drilling technology — they're really helping companies, whether with smaller spacing units in the case of horseshoe wells, or, for companies with contiguous acreage, bringing down the drilling cost per foot and improving finding and development costs on the wells they're drilling. That's one reason that, despite the capital discipline we've talked about so much, the basin continues to grow and continues to surprise to the upside for a lot of folks. Jay Singh: I'll bring it back to gas. With recent activity trends and our modeling of deeper formations and the mix over time, our base case calls for — let's call it — 36 or 37 Bcf per day from the Permian, peaking in the 2030s. I think that number could be as high as the low 40s; we're still tweaking our upside case, with a combination of inventory and inventory mix developing over time. That's a welcome development for all of this data-center, power and LNG story we've talked about ad nauseam. Every conference in Houston is inevitably pivoting to AI, power and LNG, because those three combined are going to drive US gas demand to new heights. Without the Permian, frankly, we'd be looking at some very high prices — but when we put associated gas from the Permian into our models, it really keeps a lid on Henry Hub. That's an important function for all these other industries to work. If you want to model Henry Hub, probably the most important input is Permian associated gas — so it's something we keep a very close eye on. Noah: Really good points from both of you. Jay, thank you for joining us — appreciate you coming back to the program. Jay Singh: Thanks for having us. Noah: Matt, thanks for joining. Matthew Bernstein: Sure thing. Thank you, Noah. Noah: Let's recap. Permian operators have plenty of wells left to drill that offer strong returns even at low oil prices — about 16 years' worth — and the basin will continue to grow, albeit modestly, into the early 2030s. Nevertheless, operators without assets outside the basin — the pure plays — will need to find ways to keep adding acreage to keep investors happy, whether through leasing or merging with competitors. And finally, while the Permian will always be synonymous with oil production, natural gas is poised to play a large and growing role in corporate strategies over the next decade. Thanks for listening to Let's Talk Energy. This podcast is produced by Rystad Energy. Check out the show notes for further analysis on the topics we've discussed, and find us on social media — we're @RystadEnergy on all major platforms. While you're there, please give us a like, leave us a review, and hit that subscribe button. You can also keep up to date on our website. If you'd like to send us questions, reflect on today's show, or share an idea for our next episode, email us directly at podcast@rystadenergy.com. And finally, as we mentioned before our summer break, both of our regular producers are taking some much-deserved parental leave over the coming months, meaning the frequency of our episodes will be reduced for the remainder of the year to roughly two per month. So keep an eye on your feed, and please join us again soon for more Let's Talk Energy.