Permian Resources Corporation (NYSE:PR) Q3 2025 Earnings Call Transcript

Permian Resources Corporation (NYSE:PR) Q3 2025 Earnings Call Transcript November 6, 2025

Operator: Good morning, and welcome to Permian Resources conference call to discuss its third quarter 2025 earnings. Today’s call is being recorded. A replay of the call will be accessible until November 20, 2025, by dialing (888) 660-6264 and entering the replay access code 91750 or by visiting the company’s website at www.permianres.com. At this time, I will now turn the call over to Hays Mabry, Permian Resources Vice President of Investor Relations, for some opening remarks. Please go ahead.

Hays Mabry: Thank you, Jimmy, and thank you all for joining us. On the call today are Will Hickey and James Walter, our Chief Executive Officers; and Guy Oliphint, our Chief Financial Officer. Many of the comments during this call are forward-looking statements that involve risks and uncertainties that could affect our actual results and are discussed in more detail in our filings with the SEC. We may also refer to non-GAAP financial measures. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation. With that, I will turn the call over to Will Hickey, Co-CEO.

William Hickey: Thanks, Hays. We’re excited to discuss our third quarter results this morning. This marks the 12th consecutive quarter of strong operational performance by the PR team, culminating in our highest quarterly free cash flow per share since inception despite a suppressed commodity environment. Our business is firing on all cylinders as we are able to deliver strong execution in the field, progress our accretive acquisition strategy, improve our balance sheet and continue delivering strong returns to our shareholders. We think this performance is a testament to both the quality of our people and the quality of our assets and should continue to set PR up for strong and growing free cash flow going forward. In Q3, production exceeded expectations with oil production of 187,000 barrels of oil per day, up 6% from Q2 and total production of 410,000 barrels of oil equivalent per day.

Our production outperformance was driven by continued strong execution, particularly from a large-scale Texas development that was brought online in the quarter. On the cost side, our operations team continues to set the standard in the Delaware Basin. We reduced controllable cash costs by 6% quarter-over-quarter, primarily driven by reducing LOE approximately $0.30 to $5.07 per Boe and D&C cost by 3%, averaging $7.25 per foot in the quarter. Both metrics were below full year guidance, and we see additional room for improvement on the D&C side as we head into next year. The combination of strong production and lower costs drove adjusted operating cash flow of $949 million and record adjusted free cash flow of $469 million with $480 million of cash CapEx. Our outstanding operating performance and conservative financial strategy further enhance our fortress balance sheet.

During the third quarter, we called our 2026 senior notes and redeemed the legacy Centennial Convert, reducing outstanding debt by over $450 million and further simplifying our capital structure. In July, we received our first investment-grade credit rating from Fitch. And earlier this week, Moody’s upgraded us to a positive outlook, bringing us one step closer to investment grade. Our credit metrics have long matched our investment-grade peers, and we appreciate the recognition. Slide 5 highlights our strong Haley production outperformance that underpinned Q3 production results. We frequently talk about our Delaware Basin leading cost structure, but this development is a great example of how our technical team approaches every project to maximize recoveries and value across our position.

Our proprietary subsurface characterization dictated how we space, stack, sequence and customize completions for each of these 17 wells. The combination of these technical refinements drove a 45% oil outperformance versus offset wells in the first 90 days. The recipe here is the same one we’ve used to consistently improve results across our portfolio, data-driven spacing and targeting, interval-specific completions and precise wellbore placement, all supported by PR’s cutting-edge technology and long history of technical expertise in the Delaware Basin. Having our entire team based in Midland close to our assets allows us to seamlessly translate technical insights to the field, driving lower costs and superior execution. On the back of our strong well results and stellar operational execution this quarter, we’re raising the midpoint of our full year production guidance to 181,500 barrels of oil per day and 394,000 barrels of oil equivalent per day, while keeping our CapEx guidance unchanged.

This plan reflects an increase to the original full year production guide of 5%, while lowering the capital budget by 2%, demonstrating continued improvements in capital efficiency. With that, I will turn it over to James.

James Walter: Thanks, Will. Turning to Slide 7. We wanted to provide a little more context and background about how we built Permian Resources into the business it is today. When we started Colgate Energy and moved to Midland in 2015, we had no assets and no production. We quickly realized that building a business of quality and scale was not going to be easy. And if we were going to be successful, we would have to focus on doing the hard things that other companies didn’t want to do. We built Colgate by working harder and being scrappier than the companies that surrounded us. We were also fortunate that our entire team was in Midland. This allowed us to have great real-time information and to build long-lasting relationships with mineral owners, brokers and legacy operators.

It also gave us access to real-time intel on the latest technology, well results and information in a rapidly changing environment. Having our headquarters and entire team in Midland allowed us to truly ingrain ourselves in the Permian Basin ecosystem, which was our first competitive advantage. Today, we are fortunate to have another true competitive advantage, which is our peer-leading cost structure in the Delaware Basin. As you can see in the graph at the top of Slide 7, we’re able to drill, complete and operate wells at a cost structure that is meaningfully lower than the companies around us. And the results speak for themselves. We have completed over 2,000 transactions in the past 10 years and have built a track record of driving the highest equity returns in the oil and gas business, both as a private company before and now as a public company.

And our momentum and opportunity set is only growing. We are on pace this year to do more transactions than any other year and think the acquisitions we are doing today are as good as any deals we have done in the history of the company. We are proud that our team has continued to maintain the same culture of doing the small things and doing the hard things. This culture is clear in our approach to acquisitions and divestitures, but more importantly, it is deeply ingrained in every department and every part of our business. Doing the hard things not only supports our M&A effort, but leads to the best-in-basin cost structure that allows it all to happen. And all of this shows itself more specifically in what we were able to accomplish in Q3.

We closed 250 deals primarily in New Mexico, adding 5,500 net leasehold acres and 2,400 net royalty acres for approximately $180 million. The acreage we bought in Q3 fits like a glove with our existing position and the locations will compete for capital in our high-quality portfolio from day 1. Our acquisition pipeline remains robust, and we feel good about PR’s ability to continue to do accretive deals that increase our inventory life and drive long-term value for investors. Slide 9 shows the progress we have made increasing the amount of gas we sell of the basin and improving our netbacks. PR now has agreements to sell approximately 330 million cubic feet per day out of the basin in 2026, increasing to 700 million cubic feet per day in 2028.

As a result, at current strip, the volumes associated with these agreements are expected to realize approximately $1 per Mcf higher pricing net of fees in 2026, resulting in a greater than $100 million uplift to free cash flow next year. As a result of these agreements and our existing hedges, the company has reduced its Waha exposure to approximately 25% of total gas volumes in 2026. Longer term, these agreements put PR in a position to benefit from growing natural gas demand and higher realized prices on a larger portion of its natural gas production. Moving to Slide 10. We want to point out that PR is in the fortunate position of having the flexibility to allocate capital to whatever part of our business we think is going to drive the most long-term value.

Capital allocation is the most important thing we do, and our strong balance sheet allows the company to pursue an all-of-the-above approach to value creation. We can allocate capital to the highest return opportunities rather than having to focus our efforts on a single capital allocation strategy. Just this year, I’ve seen opportunities to deploy $800 million into acquisitions, $75 million into buybacks, all while reducing our total debt by $630 million and maintaining one of the highest base dividends in the sector. Having the flexibility to allocate capital to whatever we believe creates the most long-term value has been a key part of our business model for the last 10 years and remain a core part of our strategy going forward. Thank you for tuning in today.

And now we will turn it back to the operator for Q&A.

Q&A Session

Operator: [Operator Instructions] Your first question is from Scott Hanold from RBC.

Scott Hanold: I know it’s a bit early on 2026, but obviously, it’s very topical for investors. So can you just give us a general sense of how you’re thinking about the activity pace and what that could just high level mean about oil production and relative CapEx?

James Walter: Yes. Sure, Scott. I’d say, look, for our long-standing policy, we’re not going to put out a soft guide or anything like that at this time. As we’ve done in the last few years, we think it makes a lot more sense running this business to wait until February to put out 2026 guidance. I’d say, obviously, 4 months from now, we think we’ll know a lot more about the macro, the service cost environment, what we think commodity prices look like heading into the balance of the year. So I think what I’d tell you is, look, we’re fortunate that our business continues to have a ton of flexibility next year, and we should be in a position to react to whatever the macro environment looks like. And I think if that’s an environment that is supportive of and encouraging to higher reinvestment, quicker paybacks, higher returns and ultimately production growth, we can do that and do that quickly.

And if it’s an environment that has weaker commodity prices, kind of lower returns, then we’re in a position to deliver a really capital-efficient kind of lower or no growth program. That’s probably not as much detail as you’d like. But what I can tell you is that 2026 is shaping up to be a really strong year, whichever the various paths we do end up choosing. I think — we think it’s setting up to be the most capital-efficient year we have ever had. Look, we continue to get more efficient on the ops side, as you see this quarter and make substantial and sustainable improvements to really all parts of our cost structure. Our productivity remains strong. We think next year should be just as good as this year, which was just as good as the years before that.

And as we talked about a couple of times in this deck and the last deck, our realizations are meaningfully better next year. We talked about on the prior earnings call that we expect to realize $0.50 a barrel higher on the crude side. And we think our gas netback could be $0.20 an Mcf better based on the agreements we’ve signed in the last couple of months. So all in, I think next year should be a really good strong year for Permian Resources, but we’re going to wait and see what the macro brings before we formalize the plan.

Scott Hanold: Okay. I appreciate that context. If we could take a look at that Haley kind of that pad you all drilled or at least set of wells. Obviously, fantastic results. But as you step back and look at your acreage holistically, are there any other opportunities like that across your asset base, whether smaller, larger or similar size? And why was that so like uniquely good on a relative basis?

William Hickey: Yes. Thanks, Scott. Haley was unique to us in that it was kind of more of like a one-off block that we owned and is not contiguous with the greater PR position. And as such, I think it gave our team an ability to demonstrate what they do so well, both from the cost side and the productivity side as compared to offset results. But if you take a step back, I’d say on an absolute basis, the performance from the Haley pad is kind of right in the middle of performance of PR’s overall position. This was a — it caught us off guard because we built expectations based on offset production and significantly outperformed that over the first 90 days. But if you just look at kind of productivity of that pad, it should fall pretty much in line with our overall portfolio.

So it was a nice surprise to the upside, and I think really demonstrate what our team does very well. But it’s not a — the rest of our portfolio will continue to perform as good, if not better, than Haley, which is consistent with previous years.

Operator: And your next question is from John Freeman from Raymond James.

John Freeman: Nice to see the continued progress on the gas marketing agreements. Obviously, it looks like in a couple of years out, ’27, ’28, you’ll have 90% plus of those gas volumes being priced outside the basin. And I’m just trying to get maybe some color on maybe the optionality that you all have in terms of like the gas that’s being moved to kind of the DFW market versus the options to move it to the Gulf Coast. I mean just looking at some of the agreements you’ve got like the Hugh Brinson line, I know that, that stops in April, South of DFW, I believe it has optionality to go to Katy. You’ve got Matterhorn that goes directly to Katy. Just trying to get a sense of kind of when I look at DFW versus the Gulf Coast markets, just kind of the optionality you all got with these agreements, if you could?

James Walter: Yes. I think we do have quite a bit of flexibility to kind of shift volumes from the Houston Ship Channel to DFW markets. I think what that looks like for us out in ’27 or ’28 is going to depend on what the market looks like at the time. So I think for us, I do think specifically, most of our gas will go to Houston Ship Channel or DFW and probably somewhere close to 50-50 in a base case with the ability to swing that 10% or 15% either direction depending on what we’re seeing in the market. But I do think we’ve got some flexibility there. But in any case, we’ll have gas going to both DFW and the Gulf Coast markets.

John Freeman: Got it. And then on the bottom of that Slide 5, we all highlight a number of different leading-edge things you all have been doing to improve recoveries, lower costs. I’m just — some of those, I think you’ve all been doing for all year. I’m just trying to get a sense of kind of what you all would characterize as more maybe more recent developments, things that maybe are just starting to flow through operations results. Just anything you all could highlight on that front?

William Hickey: Yes. I’d say we are always kind of tinkering and trying new things to both reduce costs and increase recoveries. Not to sound repetitive with kind of other conversations, but I’d say like recent breakthroughs have been on the drill-out side for longer laterals. We’ve kind of been testing and had a lot of success with a new technique that I’d say has meaningfully reduced drill-out cost. We’re going to continue to kind of tinker with it and see exactly how well it fits across our whole portfolio, but I’d say especially on extended reach laterals, it has been a kind of a step change in efficiencies and costs on the drill-out side. I’d say on the recovery side, we are kind of continuing to play with optimal landing targets combined with kind of the right completion design those details change on every well we drill.

But this is something that I’d say our team prides ourself on as we are, I think, have been deemed the leader on the cost side in the basin, but we put just as much effort on the recovery side as well to make sure that we are maximizing value of every acre that we own. And I think the team has done a really good job.

Operator: And your next question is from Neal Dingmann from William Blair.

Neal Dingmann: Nice quarter. James, just jumping right into my first question. I think really notable on that Slide 11, all the above slide. My question is, I can’t help see the comment where you mentioned that dividend supported around $40. So my question is sort of on when you book in that, if prices do fall, let’s say, in the near term around that, could we see mostly just leaning just that quarterly dividend and the other side of that when prices — once oil does rebound, do you anticipate sort of again, all of the above where you would look at dividends, buybacks, debt repayment and acquisitions?

James Walter: That’s a great question. I mean I think that Slide 10 is our favorite slide in the deck. I’m glad you pointed it out. But I’d say, look, like the way we’re trying to run this business is that we would be able to deploy this all of the above strategy and really in any commodity price environment, including something as low as $40 or below. I think as you see, like we’ve got leverage and liquidity in a place where we want to be able to deploy capital to whichever of these acquisitions, buybacks is the most attractive return. And we want to be able to do that even in the darkest days of a down cycle. So I think for us, like the way we positioned our balance sheet, the liquidity, the leverage, like we want to be doing this all-of-the-above strategy at any environment because I think we’ve seen it at the bottom of these cycles, the best opportunities arise and don’t want to have to be on the sidelines at $35, $40, whatever kind of most bearish prices, we probably don’t think will happen, but want to make sure we’re ready for it.

So I’d say this all-of-the above strategy is something we’re going to deploy and in any part of the down cycle and as dark as it gets. And just fortunate that the business is in a position that we think we can do that in pretty much any commodity price environment.

Neal Dingmann: And then just lastly, sort of bolting on to that, my second question, just on M&A specifically. You guys were very active. I know there’s always the rumblings that they can’t find any more acreage yet. You not only find it, you find it at a lower cost. And so I guess my question is, are there continue to be small deals out there and your thoughts about — there was obviously some big prices paid on some of the New Mexico lease sales, and there’s another one coming up this month. Just your thoughts on sort of ground game versus other M&A.

James Walter: Yes. I mean I think kind of to the beginning of your question, I’d say our ground game and M&A pipeline is as full as it’s ever been. You can see in the graph on Slide 7, like we’ve actually done more transactions through the first 9 months of this year than any other year in company history. So I’d say rather than kind of drying — opportunity set drying out, it seems to be expanding. And we’re having to look harder and turn over more rocks and probably do more deals and more small deals to find the values that you see add up to the really attractive prices you see on Slide 8. Like I’d say, as you mentioned, there have been some big prices paid in New Mexico. It’s the best rock in the world and fortunately to be operating in what we think is the best basin and — but also fortunate that we have, I think, a true differentiated and proprietary access to deal flow that other people don’t see.

We’re on the ground here in Midland. We’re kicking over every rock and still willing to do the small and hard stuff, like I said in my introductory remarks. So I think for us, this rock is incredibly valuable, but we’re in a fortunate position of having a lot of different ways to find deals and kind of pursuing an all of the above strategy here, too.

Operator: And your next question is from Neil Mehta from Goldman Sachs.

Neil Mehta: Yes. Great execution, guys, have been multiple quarters of it. And so I guess my first question is beyond just the operational volume improvement, balance sheet is getting better recognized. You went to a positive watch, I believe, at Moody’s and you’re pretty close to turn an investment grade. So can you talk about what are the next steps there? And what does move into investment grade mean for Permian Resources?

Guy Oliphint: Neil, it’s Guy. Thanks for the question. Yes, we were happy with both the Fitch and the Moody’s outcomes here recently. We think it recognizes what we’ve communicated to our investors and to the rating agencies, which is we have an investment-grade balance sheet and financial strategy, and we’ve grown fast and the rating agencies are following that along with us. What do we have to do from here? We’re just continuing our dialogue with the agencies who I think really understand our story, and we’ve got a great shot at getting to investment grade in the near term. I think what it does for us is we continue to think about protecting the balance sheet through the cycle, availability of capital through the cycle and lowering our cost of capital, and this does all of those things. So it’s very complementary to all the things that we’re doing as a business today and a recognition of how we’ve grown the business the right way.

Neil Mehta: Yes. And then just the follow-up is just on the Permian broadly, we’ve seen strong growth year-over-year, I think, led by the majors. But I think companies like yourself have also outperformed expectations. There’s a big debate out there. Are we at peak Permian or not? It obviously has macro implications. I know you guys spend more time thinking about your operations than trying to predict the oil price, but you got an on-the-ground perspective in Midland. How far away from peak Permian do you think we are?

James Walter: Neil, that’s a good question. I don’t think we pretend to know the answer to that. I think what we do know, though, is activity has definitely been slowing down out here. I mean I think you’ve seen it in the rig count. You see it in completions activity that there’s a lot of kind of slowdown. I’d say it will come. I think we’ve seen the Permian historically be more resilient than maybe people thought. I think it’s kind of TBD if that continues, but it definitely feels like you can feel it on the streets in Midland, there’s fewer people, there’s fewer rigs, there’s fewer completion crews. And eventually, we think that manifests itself in production growth slowing and ultimately flattening and then I think eventually declining. But I think it’s kind of too early to tell when exactly that turnover happens.

Operator: Your next question is from Kevin MacCurdy from Pickering Partners.

Kevin MacCurdy: I wanted to ask on CapEx cadence this year and how that could translate going forward. The first half of this year, you’re around $500 million a quarter. The back half is around — it’s closer to $480 million to $485 million given 3Q results and the 4Q guide. And is that just a function of lower well costs throughout the year? Are there any activity changes that affected that CapEx? And how can we kind of think about that quarterly cadence heading forward?

William Hickey: No, it’s been pretty flat activity. So I’d say well costs and kind of normal ebbs and flows in working interest would drive any kind of quarter-to-quarter differentiation. But well costs being the main driver of what you’re seeing in the back half of the year.

Kevin MacCurdy: That’s helpful. And I wanted to ask again about the ground game and transactions. And just wanted to get your perspective. I mean, we’ve seen the M&A market kind of heat up and there’s an assumption that large operators are hunting big deals. Just kind of curious if this reflects what you’re seeing on the ground? And is that making it harder or easier to do kind of these smaller deals that you’re known for?

James Walter: Honestly, it’s easier to do the smaller deals than it’s ever been. I think we’ve always had a good sourcing pipeline, but I think our cost structure advantage is as wide as we see it today as it’s ever been. And I think people with our activity levels, our kind of in-basin in Midland, on-the-ground knowledge of everything going on, like it feels like we’ve got a more sustainable competitive advantage on the small deal side than we’ve ever had. And I don’t think we’ve seen the kind of pressure at the top. Neil had previously referenced some big prices paid in large-scale auctions, like that tends to not trickle down. I’d say the people who are chasing larger deals aren’t chasing the deals at the smaller end of the spectrum. It’s just kind of not how the ecosystem has been set up or has worked historically. And we don’t see that pressure at the bottom of the day and really don’t see it kind of coming down over time.

Operator: Your next question is from Paul Diamond from Citi.

Paul Diamond: Just a quick one, sticking on the ground game. You guys mentioned the strongest pipeline you’ve seen. But has any recent volatility kind of shifted the balance of those deals you’re looking at between more of the working interest heavy versus those more blockout your acreage?

James Walter: No, I don’t think so. I’d say — I think the macro — the smaller end, the kind of smaller sized deals tend to be more stable and just kind of come at the pace, frankly, that we find them. A lot of those deals are us turning over rocks themselves and kind of finding the deals and drawing them out. So we — that kind of tends to go as fast as we can go. And I do think that pace has accelerated a little bit with our larger footprint. I’d say, honestly, a renewed focus on the ground game. It’s something we talk a lot about in the office today. I think volatility can have a bigger effect on larger deals. I’d say we got an Apache deal done in April, May. But besides that, the large deal pipeline was pretty quiet over that time period.

I think people — but it seems like the kind of the macro environment has settled down a little bit. I think we would expect buyers and sellers of deals in the hundreds of millions of dollars to kind of be able to get there in this environment. I think if you saw oil sharply go to 40 or 80, that might put things on pause again for a little while. But the beat goes on. I think that the deals that are going to come to market, are going to come to market and the rocks that we’re going to turn over, we’re going to turn over. So I’d say they can have 1 or 2 month slowdowns or accelerations. But by and large, it’s pretty steady over here.

Paul Diamond: Got it. Makes perfect sense. And then just sticking on the nat gas FT and sales agreements, moving to 50, 25, 25. I guess, over time, where do you guys see the right balance of that? Do you want more in that 75% number in FT and sales agreements? Or is the hedging going to remain a pretty substantial part?

James Walter: I think a lot of — I think we likely continue to hedge as we move forward. I think hedging could look different, right? Like today, our hedges are largely hedges that we have placed at Waha because that’s where the gas — corresponding gas sales are. I think over time, we’ll be in a fortunate position that we’re selling more and more gas in the downstream market at DFW and along the Gulf Coast. So I think we’ll have a different question of do we want to hedge the Houston Ship Channel price and lock that in. I think we’re fortunate about that as we’d expect less volatility and less dislocations the further downstream you get from the Permian Basin. So I have more flexibility there. But yes, I think we’ll continue to hedge actual financial hedging like we’ve done.

But I think more importantly, what we’re doing is it’s more of a physical hedge. We’re actually physically selling more of our volumes at the end markets that we think will be better markets over the long term. So probably reduces the amount of hedging going forward. But I think that’s going to be dependent on the market and the pricing as we see it in the future.

Operator: Your next question is from David Deckelbaum from TD Bank.

David Deckelbaum: A follow-up just on some of the gas marketing questions. I just wanted to get some color from your perspective, why sign these agreements now versus other periods in the past? And I guess, how should we be thinking about the impact to your cost structure beyond ’27?

James Walter: I mean I think we probably should have signed a lot of these agreements 3 or 4 years ago. That’s probably on. I think a lot of people missed it, too. But I’d say, look, as we’ve run the business most of the time in the last decade, our #1 focus has been on flow assurance, and we bought a lot of assets that came with legacy contracts that had lots of restrictions on what amount of gas we could take in kind, how we could sell downstream from there. So I’d say we’ve been pretty transparent that over the last 2 years, maximizing our netbacks on not just crude volumes, which we think we’ve done an awesome job on the last 10 years, but on gas volumes as well, has been one of, if not the top priority at the company. And we’ve been making as much progress as we can.

And I think it’s all kind of coming together this year and the past couple of quarters, but we’re convicted it’s the right decision. We’re convicted that for all your hydrocarbons that selling further downstream, closer to end users is going to get you a higher netback on the average over time. And you’re seeing that play out in a big way in 2026. And we think although the kind of futures market doesn’t imply as big of an uplift in years beyond that, we think it will continue to outperform and pay dividends for years to come.

David Deckelbaum: I appreciate that color. And maybe just to expand a little bit. I know that you said you didn’t want to give any self guidance on ’26, but I think you did remark you think it’s going to be your most capital-efficient year ever. Is that more in reference to the uplift that you see in realizations? Or are there — it sounds like your expectation is that well productivity is pretty static. I mean what sort of motivates your enthusiasm around capital efficiency next year?

William Hickey: I mean in short answer, we think that well productivity will be consistent with the last 2 or 3 years, and our well costs are as low as they’ve ever been. And I think that we probably have a little bit of room from here to continue to kind of reduce them a little bit from here. And so lowest well cost ever with consistent productivity and better realizations is a recipe for more capital-efficient business. And so I think that what James alluded to earlier is that ’26 is going to be a great year. The decision that we ultimately need to make over the next few months is do we let that incremental capital efficiency accrue to more production or less CapEx. And I think that’s what we’re going to work through over the next few months.

Operator: Your next question is from Geoff Jay from Daniel Energy Partners.

Geoff Jay: There’s a lot to geek out on Slide 5, but kind of wondering about when I see the 6% decline in controllable costs, you call out chlorine dioxide as a treatment to increase base production. I’m kind of wondering what other sort of initiatives you’re taking on that side to sort of manage base production and keep lowering your LOEs in particular?

William Hickey: I mean those guys are always trying to make the business better. We’ve had a lot of success in New Mexico where power is terrible on kind of combining well site generation to more central larger scale generation. I think we took 26 generators out of the field in Q3 over the 3 microgrids we put in. I think we’ve got 1 or 2 more between now and year-end. So that’s a step change both in cost of power, but also in run time. I’d say a big part of our production outperformance over the course of this year has been improved run time. And if you can go stack lots of compressor or lots of power generation on one site, you get much better run time than you do when it’s spread out over lots of different places. Yes, I’d think the chlorine dioxide is an interesting one, just as older wells have more buildup around the perfs when we have a failure and we’re running in, a lot of times, we’ll pump some kind of chlorine dioxide and acid to clean up perfs and clean up near wellbore.

And we’ve seen in some places where you have a remarkable increase in production, 5x to 10x where you were temporarily. And ultimately, it kind of declines back to something that is still materially better than you were before. Look, I think that the Permian Basin is a place where innovation is always happening, and we’ve built a team and a culture of always trying to kind of have our ear to the ground. So we’re the fastest follower in places where we are not innovating the new ideas. And in other cases, we are kind of truly pioneering new things. And I think that, that will show up in hopefully better run time, better well cost and better productivity over time.

Geoff Jay: Got you. So I mean — but it still sounds like it’s potentially kind of early days for some of these initiatives. Is that fair?

James Walter: I’d say it’s always early days. Like I don’t think the pace of innovation has slowed at all. Like it feels like every day, every month, every year, like the opportunity set to make the business better across all facets, production optimization specifically, but it’s always good. I don’t think we see it slowing down, and it may be early days on 1 or 2 of these technologies, but there’s another technology coming around next year that we’re not even talking about today. So I don’t think that pace of innovation is slowing by any means. And we Permian Resources, I think, probably on the front end, but the whole industry is finding ways to continue to get better.

Operator: Your next question is from John Abbott from Wolfe Research.

John Abbott: Guy, maybe just a really quick question. You’ve had a little bit more time to examine the one big beautiful deal. Anything incremental as far as future cash taxes at this point in time?

Guy Oliphint: Nothing different from last quarter.

John Abbott: All right. That’s helpful. And then the other question is, I mean, you have a very low corporate breakeven with the dividend. How do you think about the pace of future dividend growth at this period of time as you sort of look at what you’re doing on and your ability to generate free cash flow?

James Walter: Yes. I mean I think kind of — look, for us, I’d say having a sustainable and growing base dividend is a core part of our strategy of Permian Resources. It’s what we view as a core quality of any high-quality business in this sector or really in any sector. So I’d say growing the dividend over time is a priority and something you will see consistently from us year in, year out. I think the pace of what we’ve done in the last couple of years probably slows from here. It’s been pretty exceptional from a CAGR perspective. But I’d say, as the end of next year, that’s something we’d expect to finalize alongside our February budget. But I’d say the business is firing all cylinders. The ability to continue to grow the dividend, given the capital efficiency we’ve referenced on this call is as strong as ever. So you should see it continue to grow next year and for years to come.

Operator: Your next question is from Paul Cheng from Scotiabank.

Paul Cheng: I was just curious that I think the whole industry and including yourselves that is looking at the vessel length and you are saying that you are seeing some success. If I look at from a land position standpoint, where you see the opportunity set, what percent of your program could be in the 3 miles? And also, have you tested on the alternative shape and whether that you think that will be a good fit for you? That’s the first question.

James Walter: Yes. Look, I’d say the Haley Pad was a great example of a really successful 3-mile development. I think we drilled quite a few 3 milers this year. I’d say it’s become a larger part of our program. And we’re very impressed with how well our team has executed on the longer laterals. We mentioned some great technology on the drill-out side we’ve applied. I think our land position sets up really well. We’ve got a blocky position in Texas and New Mexico that could set up for long laterals. I think for us, the honest answer is we don’t see that much of a capital efficiency step-up in the Delaware Basin today in most of the areas that we operate going from 2 miles to 3 miles. Obviously, 3 miles are better on a D&C per foot basis.

But just given how much oil and gas and fluid we make in the Delaware, we often don’t see the corresponding one-for-one uplift in initial production. So you drill and complete cheaper, but you make closer to the same amount of oil in the early time. So on a discounted cost of capital rate of return basis, you’re not seeing major uplift from going from 2 miles to 3. I think the short answer is anywhere from 2 to 3 is a pretty good place to be. And the vast majority of our position sets up for long laterals in that window and should be the majority of our program going forward.

Paul Cheng: How about on the alternative shape? Have you guys ever looked at that or tested out?

William Hickey: U-turn wells.

James Walter: We — I think we’ve drilled 10 U-turns year-to-date. I’d say it’s not an important part of our go-forward program. I think there’s been some cool examples of us like where you had a legacy 1-mile well on a DSU and the rest of the pads set up for 2-mile laterals perfectly and you had a legacy well that you could do a U-turn or a J-hook around. That’s been a really cool tool. It’s allowed us to more efficiently drain resource, probably add an extra stick that otherwise wouldn’t have been economic. But we’re really fortunate our land position sets up for 2- and 3-mile straight wells, so aren’t going to have to drill a lot of U-turns going forward.

Paul Cheng: Okay. And on the opportunistic buyback, can you share that what kind of criteria or matrix that you guys are using in terms of that decide whether that this is the right time to do buyback or not?

James Walter: Yes. I think we’ve always said we’re going to buy back shares when there are material dislocations in the share price. I think most — more often than not, that’s driven by the macro. I think rather than tell everyone our specific criteria, I do think kind of pointing to what we did in April, immediately after “Liberation Day,” we saw a material reaction downward in the Permian Resources stock price and had an awesome opportunity to buy shares in the $10 to $11 range and hit that as hard as we could that whole week. I’d say the stock recovered pretty quickly and that opportunity window closed. But I’d say for us, it’s going to be a material dislocation is going to be kind of what we use as the criteria. And frankly, we’re always going to be weighing that against our other opportunities.

I’d say our acquisition pipeline remains robust. So we’ll be constantly weighing do we think we’ll generate a higher long-term return buying back shares or doing acquisitions or frankly, putting cash on the balance sheet for future opportunities. So I’d say any one of those is on the table at any given time, and we’re constantly evaluating the opportunity set more broadly and going to allocate capital to whatever we think generates the highest rate of return and creates the most long-term value for shareholders.

Operator: Your next question is from Noah Hungness from Bank of America.

Noah Hungness: I’d like to start off on just the maintenance CapEx. Given the D&C efficiencies you’ve seen, how can we think about maintenance CapEx levels? And then also how your dividend breakeven evolves over time through ’26 and beyond?

William Hickey: Sorry, I get the first part. Can you repeat the second part of that question?

Noah Hungness: Yes. The dividend breakeven, just how that evolves over time, like through 2026 and after.

William Hickey: Cool. Maintenance CapEx, I’d say, kind of just generally speaking, we’ve quoted about $1.8 billion of maintenance CapEx plus or minus. And I think what you’ve seen transpire this year is we’ve grown production pretty meaningfully. So the base is a lot bigger, but we’ve reduced cost and kept well productivity the same. So I think that plus or minus those probably offset each other and you get to something that is in that range or slightly higher, something like that on the maintenance CapEx side. Dividend breakeven.

James Walter: Yes, dividend breakeven. The goal is for it to get better over time or stay the same, but there’s a proportionate increase in our base dividend. So I think for us, the business is getting better. So that should either lower our dividend breakeven over time or give us greater capacity to pay out the base dividend and lower commodity prices. So I think that’s a TBD capital allocation decision, but the business is getting better, so you should be able to pay a larger base dividend with the same level of protection or lower the breakeven.

Noah Hungness: Got you. No, that makes a ton of sense. And then for my second question, I know you guys touched on this a little bit, but regarding the additional FT that you guys took on, and you mentioned the strength of Waha kind of in the forward curve and how Waha basis kind of closes in back half of ’26 and into ’27. What was the advantage of signing up for the FT versus just hedging out the forward curve?

James Walter: Yes. I mean, obviously, there’s a really large near-term benefit to these FT deals we signed up to the tune of over $100 million uplift from gas alone at strip. I do think it’s our expectation and clearly the market expectation that as some of these pipelines come online, the Waha differential should close kind of more or less to the cost of shipping. So for us, I think — over the long term, I think we’ve seen trying to hedge gas ultra long term, there’s just not the liquidity to do so. And we think you’re ultimately better off selling your gas closer to end users and further downstream. I think although the long-term futures market doesn’t reflect it, like I said, we do think your kind of downside skew for any regional hub like Waha is worse and more impactful than your upside.

So I think the way we think about it is over the long term, we think we will be better off we realize better pricing from ’27 and beyond, selling at Houston Ship Channel and DFW than we will at Waha. And I think that may not be every month, but I think the way we think about it is most months, it will be a push. But when you win, you’ll win big, just like you’ve seen historically.

Operator: [Operator Instructions] And your next question is from Leo Mariani from ROTH Capital Partners.

Leo Mariani: You guys obviously did a good job lowering D&C costs yet again this quarter. You guys commented in some of your prepared remarks that there could be more downside into 2026. Could you provide a little bit more color around that? Are you starting to see leading edge oilfield service costs make another step down here? And maybe it’s a combination of that and some other things you’re working on the efficiency front?

William Hickey: Yes. I think that — I mean, obviously, with oil price where they are and the amount of activity being shut down and pulled out, we’ve seen a pretty meaningful reduction in service costs over the last few quarters, and you kind of combine that with the efficiencies we’ve picked up, and that’s what’s driven the kind of cost reduction year-to-date down to the $725 a foot level. I’d say my comments on where it could go from here is really just we are continuing to get better in the field, and I don’t see at this crude price and based on activity levels of kind of the basin cost snapping back anytime soon. And so if we can maintain kind of this level of service cost and keep picking up efficiencies in the field, which we are, I think there’s probably a more upside or lower prices is more likely than higher from here. But I don’t know what the tune is a couple of percent, something like that.

Leo Mariani: Okay. Helpful. And I guess just on the share buyback, obviously, a number of questions around it. I guess, trying to be opportunistic. If we get in the lower for longer oil environment, hopefully, we don’t in 2026, could you guys be a bit more programmatic if oil is kind of consistently in the 50s for a while? Or will you just kind of say, hey, it’s a good time in the cycle to buy stock?

James Walter: I don’t think it’ll ever be that programmatic. I think that fails to factor in the other opportunity sets and what are the other things you can do with capital and what’s your view on things looking like going forward. I’d say for us, I think if we’re in the 50s for a long period of time, you should expect us to buy back more stock than we have historically. I think that’s pretty easy from our perspective. But I don’t think it will ever be programmatic. We think we are able to create more value for us and our investors by being thoughtful and making each decision to buyback shares, do an acquisition or put cash on the balance sheet as a decision made in that time with all the facts and information we have in that moment. So I think for us, we don’t think the programmatic strategy creates the maximum value and going to keep on this kind of — this path that we’ve been on.

Operator: And your next question is from John Annis from Texas Capital.

John Annis: For my first one, on Slide 5, you highlight leveraging AI to expand play boundaries. I wanted to ask if you could expand on this. And then more broadly, how do you see the opportunity for organic inventory expansion through additions of secondary zones from here?

William Hickey: Yes. Look, if you look at — I think Eddy County is a good example of we have been both one of the most active buyers of acreage and also one of the most active drillers in Eddy County over the last few years. And so as such, we have a significant informational advantage over really anyone in Eddy County. We get production information, logs, incremental seismic information faster than anyone else does, just given everything that we drill is there’s a 6-month plus lag before it’s public. And what our team has been able to do is just kind of the workflows that we had internally, which may have previously taken weeks or months to get incorporated into passing that through to the A&D team or passing that through to the next development package.

I’d say a lot of these large language models allow us to do that in minutes. And so really, it’s just speeding up the passing of information across our team to something that’s kind of more real time, and that allows all the different groups, the land team, the BD team, the drilling team, the completion engineering team, et cetera, to kind of benefit from what truly is an informational advantage that we have, albeit short term. And then with new zones, I’d say that’s one that is unique, I’d say, to some degree of — we are seeing tons of shallow and deep, but newer zones drilled across the New Mexico Delaware. And New Mexico and Delaware has a huge benefit of state and federal leases don’t have few clauses when you drill one well, you hold all depths basically forever, which is, I’d say, unique to New Mexico.

And given Permian Resources deep inventory position of kind of the same benches we’ve drilled over the last few years, I’d say that is not a huge part of our program, and we have the benefit of getting to kind of wait, watch and see. And so we’ve had a, I’d say, a ton of organic inventory expansion via offset operators’ drilling programs that it’s obviously the cheapest way to go add inventory is to kind of let others do it for you around us. I think you’ll see that we’ll drill, call it, 5 or 10 wells a year in kind of the more upside or kind of organic inventory expansion benches. But for the most part, we’ve had the luxury of getting to kind of sit back and let that get proven up by people around us.

James Walter: And I think that’s one of the things that’s so special about being in the Delaware Basin is that the rate of new inventory additions really hasn’t slowed over the last decade. Like every year, it seems like PR and offset operators finding a new zone. And not just a new one, I think the zones that we’re discovering, the zones that we’re delineating actually compete with capital with the best parts of the basin. So it’s not like we’re finding secondary and tertiary zones that better margin. We’re finding new zones that can compete for capital day 1. And we think that’s a really big differentiator in what we think is the best and most exciting basin in North American E&P.

John Annis: Great color. I appreciate that. For my follow-up, staying on Slide 5, could you expand on the microseismic azimuth analysis? And then maybe more specifically, to what degree are you altering the azimuth to optimize completion efficiency relative to the analysis?

William Hickey: Yes. I’d say — I mean, a lot of this is things we’ve been doing a long time. I think we’ve just gotten better, faster and further along in how to leverage it. But I mean, on not a large percentage, but on some amount of our program, we’ll go ahead and run microseismic and microphones to really understand where fracs are going. And really, the goal is just to optimize our design. We want to pump more or stimulate more where the rock is good, and we don’t want to go waste a bunch of capital in places where recoveries will not be as good. And so I think what you’re starting to see is just the incorporation of that in the business, both either increasing recoveries in some instances or just lowering costs in others. I’d say that microseismic has been around a long time, but the use of it and kind of the way that people are using it today is slightly better and more efficient.

Operator: There are no further questions at this time. I will now hand the call back to Will Hickey for the closing remarks.

William Hickey: Thank you. As you can tell by today’s results, the business is firing on all cylinders. Importantly, we can continue to find ways to improve the business each and every day. Given our high-quality asset base and fortress balance sheet, we believe we can continue this execution and value creation going forward in any commodity price environment. Thanks to everyone for joining the call today and following the Permian Resources story.

Operator: Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect your lines.