Prepared remarks
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.
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.
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 Permian Resources 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 Permian Resources 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 Permian Resources' 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.
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 are 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 efforts 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 one. Our acquisition pipeline remains robust, and we feel good about Permian Resources' 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 out of the basin and improving our netbacks. Permian Resources 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 Permian Resources 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 Permian Resources 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 have 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 remains 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.
Questions and answers
Your first question is from Scott Hanold from RBC.
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?
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, four months from now, we think we'll know a lot more about the macro, the service cost environment, and 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. I think if that's an environment that is supportive 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. 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.
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 uniquely good on a relative basis?
Yes, thank you, Scott. The Haley pad was unique for us as it was more of a singular block that we owned and is not connected to our larger Permian Resources area. This allowed our team to showcase their strengths in both cost efficiency and productivity compared to neighboring results. Looking at it overall, the performance from the Haley pad aligns closely with the average performance of our Permian Resources. We were surprised by the results because we had set our expectations based on the production from adjacent areas, but Haley significantly exceeded those expectations in the first 90 days. In terms of productivity, it should fit well within our overall portfolio. It was a pleasant surprise, highlighting the capabilities of our team. However, I believe that the rest of our portfolio will continue to perform as well, if not better than Haley, which is in line with our historical performance.
And your next question is from John Freeman from Raymond James.
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 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?
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.
Got it. At the bottom of Slide 5, you highlight several cutting-edge initiatives aimed at improving recoveries and reducing costs. I believe some of these have been in the works for the entire year. I'm interested in understanding what you would identify as the more recent developments, particularly those that may be starting to impact operational results. Could you provide any insights on that?
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 ourselves 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.
And your next question is from Neal Dingmann from William Blair.
Great quarter. James, jumping right into my first question, I found it notable on Slide 11 where you mentioned that the dividend is supported around $40. So, I would like to know when you account for that. If prices were to decline, could we primarily rely on just that quarterly dividend? Additionally, when oil prices rebound, do you expect to consider dividends, buybacks, debt repayment, and acquisitions again?
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 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.
Lastly, I have a question about M&A. You have been very active in this area. Although there are discussions about the challenges of finding more acreage, you have managed to secure it at a lower cost. My question is whether there are still opportunities for small deals and your thoughts on the recent high prices for some New Mexico lease sales, with another sale coming up this month. I'd like to hear your perspective on the ground game compared to other M&A strategies.
Yes. To address the beginning of your question, I'd say our ground game and M&A pipeline is more active than ever. As shown in the graph on Slide 7, we've completed more transactions in the first nine months of this year than in any previous year in our company's history. Instead of opportunities drying up, it seems they are actually increasing. We are working harder to discover potential deals, which often requires pursuing more smaller transactions to find the value that leads to the appealing prices reflected on Slide 8. As you mentioned, there have been significant prices paid in New Mexico, which is considered the best area for this resource, and we are fortunate to be working in what we believe is the top basin. Additionally, we have differentiated and exclusive access to deal flow that others may miss. We are actively on the ground in Midland, exploring every opportunity, and are willing to take on both small and challenging projects, as I noted in my introductory remarks. For us, this area is highly valuable, and we are in a favorable position with multiple strategies to identify and pursue deals.
And your next question is from Neil Mehta from Goldman Sachs.
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 turning investment-grade. So can you talk about what are the next steps there? And what does move into investment grade mean for Permian Resources?
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.
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?
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.
Your next question is from Kevin MacCurdy from Pickering Partners.
I wanted to ask about the capital expenditure cadence this year and how that might translate going forward. In the first half of this year, you're averaging around $500 million per quarter. The second half is closer to $480 million to $485 million based on third quarter results and the fourth quarter guidance. Is this primarily due to lower well costs throughout the year? Were there any changes in activity that impacted that capital expenditure? How should we view the quarterly cadence moving forward?
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.
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?
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, it feels like we've got a more sustainable competitive advantage on the small deal side than we've ever had. 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.
And your next question is from Paul Diamond from Citi.
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 block-out acreage?
No, I don't think so. I'd say the smaller sized deals tend to be more stable and come at a pace that we find them. Many of those deals are us actively seeking them out. So, that tends to go as fast as we can manage. I believe that pace has picked up a bit with our larger footprint. There's been a renewed focus on our ground operations, which is a frequent topic in our office discussions. Volatility can impact larger deals more significantly. We completed an Apache deal in April or May, but aside from that, the pipeline for large deals has been fairly quiet during that time. It appears that the macro environment has stabilized somewhat. We expect that buyers and sellers of large deals will be more capable of moving forward in this environment. However, if oil prices sharply drop to 40 or spike to 80, that might cause a temporary pause. Nevertheless, deals that are meant to come to market will do so, and we will continue to identify opportunities. There may be brief slowdowns or accelerations, but overall, things are remaining quite steady on our end.
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?
I believe we will likely continue to hedge as we progress. The nature of our hedging could change; currently, our hedges are primarily at Waha since that aligns with our gas sales. In the future, we expect to increase our gas sales in the downstream market at DFW and along the Gulf Coast. This raises the consideration of whether we want to hedge the Houston Ship Channel price and secure that rate. We're in a good position as we anticipate less volatility and fewer disruptions the further downstream we go from the Permian Basin, which gives us more flexibility. We will continue with our financial hedging as we have been doing, but more importantly, we're focusing on a physical hedge. We're physically selling more of our volumes in end markets that we believe will perform better long-term, which may reduce the need for hedging in the future. However, this will depend on market conditions and pricing as we look ahead.
And your next question is from David Deckelbaum from TD Bank.
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?
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 number one 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.
I appreciate that insight. Just to elaborate a bit, I understand you mentioned that you didn't want to provide specific guidance for 2026, but you did indicate that you believe it will be your most capital-efficient year yet. Is this primarily related to the increase you expect in realizations? It seems like you anticipate well productivity to remain fairly constant. What drives your optimism regarding capital efficiency for next year?
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.
Your next question is from Geoff Jay from Daniel Energy Partners.
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?
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.
Got you. So it sounds like it's still potentially early days for some of these initiatives. Is that fair?
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 one or two 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.
Your next question is from John Abbott from Wolfe Research.
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?
Nothing different from last quarter.
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?
Yes, I believe that for us, maintaining a sustainable and growing base dividend is a key element of our strategy at Permian Resources. We consider it an essential quality for any high-quality business, whether in our sector or others. Therefore, increasing the dividend over time is a priority, and you can expect to see consistent growth from us annually. While the pace of growth we've experienced in recent years may slow down, it has been impressive from a compound annual growth rate standpoint. By the end of next year, we expect to finalize our plans alongside our February budget. The business is performing exceptionally well, and our ability to continue increasing the dividend, given the capital efficiency we've discussed, is stronger than ever. Thus, you should anticipate continued growth in the dividend next year and in the years ahead.
And your next question is from Paul Cheng from Scotiabank.
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.
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.
How about on the alternative shape? Have you guys ever looked at that or tested out?
U-turn wells.
We've drilled 10 U-turns so far this year. I don't consider it a crucial part of our future plans. There have been some interesting instances where we had a legacy 1-mile well within a drilling spacing unit, and the other pads were perfectly arranged for 2-mile laterals, allowing us to utilize a U-turn or J-hook around the legacy well. This has been an effective strategy, enabling us to extract resources more efficiently and potentially add production that wouldn't have been economically viable otherwise. However, we are fortunate that our land position is suitable for 2- and 3-mile straight wells, so we won't need to drill many U-turns moving forward.
Okay. And on the opportunistic buyback, can you share what kind of criteria or matrix that you guys are using in terms of that deciding whether this is the right time to do buyback or not?
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 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 that's 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.
Your next question is from Noah Hungness from Bank of America.
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?
Sorry, I get the first part. Can you repeat the second part of that question?
Yes. The dividend breakeven, just how that evolves over time, like through 2026 and after.
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 costs 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.
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.
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?
Yes, there is a significant immediate advantage to the FT deals we've engaged in, providing over $100 million uplift from gas alone at current market levels. We anticipate that as new pipelines become operational, the Waha differential will decrease to roughly match shipping costs. Long term, our experience shows that hedging gas over an extended period lacks sufficient liquidity. Therefore, it is generally more advantageous to sell gas closer to end users further downstream. While the long-term futures market may not indicate this, we believe that the potential downside for any regional hub like Waha is greater and more impactful than the upside. Consequently, we expect to achieve better pricing from 2027 onwards by selling at the Houston Ship Channel and DFW, rather than at Waha. This might not apply every month, but overall, we believe the outcomes will even out, leading to significant wins when they do occur, as we've observed historically.
And your next question is from Leo Mariani from ROTH Capital Partners.
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?
Yes. With current oil prices and the reduction of activity, we have observed a significant decrease in service costs over the past few quarters. This, combined with the efficiencies we have implemented, has brought our cost reduction down to $725 a foot so far this year. Looking ahead, we are continuing to improve our operations, and given the current crude prices and activity levels, I do not expect a rapid increase in basin costs. If we can maintain our service cost levels while continuing to enhance efficiencies in the field, the potential for prices to decrease further is more likely than an increase. However, I can't specify the exact amount, but it could be a couple of percent or so.
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?
I don't think it will ever be a strictly programmatic approach. There are other opportunities to consider with capital and different perspectives on the future. If we find ourselves consistently in the 50s for an extended period, you can anticipate that we will engage in more stock buybacks than we have in the past. This approach seems straightforward from our point of view. However, we believe that a programmatic strategy doesn’t maximize value. We prefer to create value for ourselves and our investors by being deliberate and making informed decisions on share buybacks, acquisitions, or cash reserves based on the facts available at the time. Therefore, we will continue on the current path we've established.
And your next question is from John Annis from Texas Capital.
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?
Yes. If you look at Eddy County, we have been one of the most active buyers of acreage and drillers in the area over the past few years. This gives us a significant informational advantage over others in Eddy County. We receive production information, logs, and incremental seismic data faster than anyone else because there's typically a six-month lag before this information becomes public. Our team's internal workflows, which once took weeks or months to integrate and relay to the A&D team or the next development package, are now streamlined. Large language models enable us to facilitate this process in minutes, enhancing real-time information sharing across teams such as land, business development, drilling, and completion engineering. This gives us a short-term informational advantage. Regarding new zones, we are observing numerous shallow and deep zones being drilled in the New Mexico Delaware area.
New Mexico has a unique advantage because state and federal leases allow us to hold all depths indefinitely after drilling just one well. Given Permian Resources' strong inventory position in the same benches we have drilled in recent years, new zones are not a significant part of our program right now; instead, we can afford to wait and observe. We have seen significant organic inventory expansion due to drilling programs by offset operators, which is the most cost-effective way to add inventory. We plan to drill about five to ten wells a year in the more promising areas, but we have the advantage of letting others prove up new opportunities around us.
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 Permian Resources 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 one. 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.
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?
Yes, a lot of what we’re doing has been in practice for quite some time. We’ve become more adept at utilizing these methods. For a portion of our program, we will use microseismic and microphones to gain insights into fracture behavior. The objective is to optimize our designs, allowing us to enhance stimulation in the productive rock and avoid wasting resources in areas with lower recovery potential. What you're witnessing is the integration of these techniques into our operations, which helps boost recoveries in some cases and reduce costs in others. While microseismic technology has been available for years, today's application is notably more efficient and effective.
There are no further questions at this time. I will now hand the call back to Will Hickey for the closing remarks.
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.
Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect your lines.