Permian Resources (NYSE:PR) reported third-quarter financial results on Thursday. The transcript from the company’s third-quarter earnings call has been provided below.
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Summary
Permian Resources reported record free cash flow of $0.98 per share for Q3, with increased oil production despite lower oil prices compared to Q2.
The company announced $1.15 billion in acquisitions, including Ridge Runner Resources, which adds high-return inventory and is expected to generate at least 5% free cash flow per share accretion over the next decade.
Oil production averaged 208,000 barrels per day, with a 10,000-barrel increase from Q2, driven by organic growth and acquisitions.
Controllable cash costs were reduced by 6% to $7.05 per BOE, the lowest in company history, through optimization efforts including AI-powered monitoring.
Permian Resources expects to generate approximately $300 million in additional free cash flow for the full year, with an increased oil production guidance of 202,000 barrels per day.
The company plans to continue focusing on high-return projects and disciplined acquisitions to enhance shareholder value.
Management noted the success of their acquisition strategy and maintaining flexibility in gas marketing, with plans to increase gas deliveries to 700 million cubic feet per day by Q2 2027.
Full Transcript
OPERATOR
Replay of the call will be available by visiting the company’s website at www.permianres.com. At this time, I will turn the call over to Hayes Mabre, Permian Resources Vice President of Investor Relations, for some opening remarks. Please go ahead.
Hayes Mabre (Vice President of Investor Relations)
Thanks, Kristen, and thank you all for joining us on the call. Today are Will Hickey and James Walter, our Chief Executive Officers, and Guy Oliphant, our Chief Financial Officer. Many of the comments during this call are forward-looking statements that involve risk 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.
Will Hickey (Co-Chief Executive Officer)
Thanks, Hayes. We are extremely excited to discuss our third quarter results this morning. Q3 was an outstanding quarter for PR. We grew production across all three streams in response to stronger commodity prices and generated record free cash flow of $0.98 per share despite lower oil prices compared to Q2. More importantly, the same execution that drove our strong quarterly results has allowed us to meaningfully improve our full-year outlook. We’ve worked hard to optimize nearly every aspect of our business and now expect to generate approximately 300 million of incremental free cash flow compared to our original plan, normalized for commodity prices. We’ve also continued executing on our decade-long acquisition strategy, announcing 1.15 billion of highly attractive acquisitions that add significantly high-return inventory to our portfolio. Overall, I think this quarter demonstrates that our business model is working.
We have the right team, assets, and strategy in place to continue growing free cash flow per share over the long term regardless of the commodity cycles. Starting with our operating results on Slide 3, oil production averaged 208,000 barrels per day and total production averaged 458,000 barrels of oil equivalent per day. We grew oil production by approximately 10,000 barrels per day compared to Q2, including over 8,000 barrels per day of organic growth. This was driven by our team’s relentless focus on improving every aspect of the business. We increased workover activity to reduce downtime to the lowest level in PR history, closed over 100 acquisitions of incremental working interest in our existing units, and continued reducing cycle times to bring new wells online faster.
The remaining 2,000 barrels per day of growth came from our Ward County bolt-on acquisition. I note this is not growth for growth’s sake; this is responding to market conditions to increase near-term free cash flow for our shareholders. Importantly, we were able to accelerate production while continuing to drive down costs. Our team has been optimizing power generation and compression equipment, deploying AI-powered artificial lift monitoring to improve runtime, and executing a highly successful workover program. Combined with higher production, these efforts reduced controllable cash cost by 6% quarter over quarter to $7.05 per BOE, the lowest level in PR history. LOE declined to $5.11 per BOE and cash G&A declined to $0.73 per BOE.
We spent 518 million of cash capex during the quarter. Consistent with Q2, our drilling and completion teams continued to improve execution through longer laterals, expanded water recycling, and reduced cycle times. In fact, we drilled five of the ten fastest wells in PR history during Q3, including our fastest well ever which averaged more than 2,700 ft per day. These efficiency gains are helping offset inflation in diesel and steel while supporting lower D&C cost per foot year over year.
Slide 4 shows the complete picture. Higher production, improved gas and NGL realizations, lower controllable cash cost per BOE, and consistent capex drove almost 100 million of additional free cash flow compared to Q2 despite lower oil prices. We can’t always overcome commodity price fluctuations quarter over quarter, but we do believe our team’s commitment to disciplined investment and high-return, rapid payback projects and premier execution capabilities can consistently improve the business and translate to long-term free cash flow growth across cycles.
Turning to natural gas, Q3 was a great example of the flexibility we discussed on our last call. In Q2, we curtailed high GOR wells when Waha prices were deeply negative. As prices improved, we brought those wells back online, increasing natural gas production by 42% quarter over quarter to approximately 787 million cubic feet per day. As you can see on Slide 5, our unhedged realized gas price improved by $2.48 per Mcf compared to Q2. We also began delivering gas through Hugh Brunson during the quarter, bringing the percentage of our volumes priced at Gulf Coast and DFW markets to approximately 80%.
The combination of higher volumes and better realizations drove a significant improvement in our natural gas revenue, going from negative 90 million in Q2 to over positive 50 million in Q3, a $140 million improvement before hedges. Including the benefit of our hedges, we realized $1.12 per Mcf during the quarter. We spent a lot of time over the last year positioning our gas portfolio to access better markets and we’re now starting to see the benefits of that work.
Today we’re selling over 600 million cubic feet per day downstream of Waha, which will increase to over 700 million cubic feet per day in Q2 of ’27. This gives us access to markets closer to the end users and growing demand while maintaining flexibility across delivery points. Looking forward, we believe natural gas represents a meaningful opportunity for additional free cash flow generation. We’ve already seen the impact of better realizations in Q3 and, as you can see on Slide 5, we have line of sight to further natural gas revenue growth in ’27.
With growing LNG and power demand, we are well positioned to benefit from the potentially higher downstream prices over time. To wrap it all up, I think what our team accomplished so far this year is pretty remarkable. We responded quickly to higher commodity prices, finding ways to bring additional production online while continuing to drive down cost. To put that in perspective, we’re on track to grow oil production by 11% this year while reducing every component of our cost structure on a year-over-year basis. I think that’s a great testament to the quality of the people and their relentless focus on improving the business every day, and I want to thank them for all their hard work.
With that, I’ll turn it over to James to discuss our recent acquisitions and updated outlook.
James Walter (Co-Chief Executive Officer)
Thanks, Will. Since our last earnings call we’ve continued to execute on the same acquisition strategy we’ve followed for years: buy high-quality assets where our existing operations, subsurface knowledge, and cost structure allow us to generate outsized full-cycle returns at mid-cycle prices. In the third quarter we completed approximately 175 transactions to add an additional 24,000 net acres, 9,000 net royalty acres, and 13,000 BOE per day of production.
Combined, these acquisitions will add over 200 net locations and an 80% ADA center I that should immediately compete for capital within the Permian Resources portfolio. Combined upfront consideration was approximately $1.15 billion. The transactions include Ridge Runner Resources for just over $1 billion and another $120 million of bolt-ons and smaller ground game transactions. After backing out the value of PDP at $500 million, that works out to $22,000 per net leasehold acre, $14,000 per net royalty acre, and $3 million per net 10,000-foot location, which is consistent with our historical acquisition metrics.
We closed Ridge Runner on October 30th and the rest of the transactions closed during Q3. Slide 7 provides a bit more color on our long-standing approach to M&A and how the Ridge Runner deal fits with that strategy. When we are looking at potential transactions, we want to buy assets that make our existing business better and can generate outsized returns for our investors. That means that the asset quality has to be extremely high and the acquired locations need to compete for capital within our existing portfolio from day one.
Our existing footprint in the Delaware Basin allows us to enhance returns by bringing our information, cost, and execution advantages to bear, and we think the Ridge Runner acquisition is another great example of the differentiated way we approach M&A. To start, we’ve known Ridge Runner CEO Scott German for over 10 years. We all live in Midland and, in fact, one of the first deals we looked at way back in 2016 was actually being sold by Scott when he was at BC Operating. We didn’t get that deal back in 2016, but stayed in touch and built a great friendship over the years. So naturally we have followed what the Ridge Runner team has put together with their current iteration and entered into discussions with them in late spring when they initially marketed their business.
But for a lot of reasons it didn’t make sense for us at the time: asset mix, commodity pricing, and ultimately price expectations. After it did not transact, we entered into a bilateral dialogue a few months later to get to work with the Ridge Runner team to see if we could find a transaction that made sense for both parties as a true win-win. And all that dialogue paid off. Ultimately we struck a deal to include Ridge Runner’s royalty company that wasn’t included in the initial marketing process while excluding the Woodford and Northwest Shelf assets that weren’t a good fit for Permian Resources.
The final piece of the deal was that the sellers wanted to be paid for the potential upside in oil prices and Permian Resources was stubborn in our focus on making sure we could underwrite strong full-cycle returns at mid-cycle prices. At the time full-year 2027 oil strip was hovering around $72 per barrel. To bridge that gap, we added the contingent payment that let us both participate in the upside if commodity prices outperformed in 2027 and 2028.
So when we combine great assets with the purchase price and structure we worked hard to get right, we get an acquisition that generates attractive full-cycle returns at mid-cycle prices. Specifically, at flat $70 per barrel and $2 per MCF, we expect at least 5% free cash flow per share accretion over 2, 5, and 10 years. We are confident we can continue to execute on this disciplined acquisition strategy and drive shareholder value for years to come.
Turning to slide 8 on guidance, we are increasing our full-year oil production midpoint to 202,000 barrels per day, which represents approximately 11% growth over last year and a 7% increase from the guidance we provided in February. Approximately 85% of the year-to-date increase in oil guidance comes from standalone improvements. Strong base and new well performance, higher working interest, and increased workover activity have been the primary drivers.
Ward County and Ridge Runner add to that growth, but the largest contribution has come from improving the business we already own. We are updating our full-year cash capex midpoint to $2.025 billion. Approximately $20 million of the increase is associated with Ridge Runner, with the remainder primarily driven by additional working interest acquired through the ground game and increased workover activity. These are investments that add production and cash flow to the business in the very near term.
For the fourth quarter, we expect oil production of more than 210,000 barrels per day, including approximately 4,000 barrels per day from Ridge Runner, with cash capex spending similar to what we did in Q3. To conclude on slide 9, we wanted to take a step back and walk through the things we’ve done this year to improve upon our original plan laid out for investors back in February. When oil prices rose earlier this year, we reacted quickly and took steps to increase production by investing in the shortest-cycle projects in our portfolio while maintaining a disciplined focus on cost reduction.
We drilled higher working interest wells as a result of our ground game, did more workovers to improve our base production, and accelerated activity where it made sense, all while keeping activity levels flat from the start of the year and delivering the lowest cash costs in company history. This allowed us to spend more capital and generate more production, revenue, and ultimately cash flow for our investors this year. As a result, full-year 2026 free cash flow will be approximately $300 million, or $0.35 per share, higher than our original plan would have achieved when adjusted for the latest actual pricing.
Our goal remains constant: to grow free cash flow per share and maximize long-term equity value for shareholders. This quarter shows how we do that through our existing operations, our marketing portfolio, and disciplined acquisitions. Thank you for joining us today. With that, we’ll turn it back to the operator for Q&A.
OPERATOR
Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing star, then the number one on your telephone keypad. If you would like to withdraw your question, press star one. Again, we ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster.
Your first question comes from the line of Neil Digman with William Blair. Your line is open. Please go ahead.
Neil Digman (Analyst at William Blair)
Morning, guys. Thanks for the time. Will, my first question is likely for you. Could you speak to the further rapid payback initiatives you all continue to see? I mean, you’ve certainly done a great job with incremental low-cost growth in the recent high-price oil environment, and just wondering if you could continue at this, you know, what I’d call a notable pace.
Will Hickey (Co-Chief Executive Officer)
Yeah, I mean, look, I’d say that’s what’s one of the best things about the PR business is that the widget that we produce, especially on the new wells we drill, is some of the highest-return and fastest-payback wells, I think, across the industry. That is, you know, we’re in the right spot in the Delaware Basin, and with our cost structure we can generate a lot of cash from the wells we drill. We’ve talked about it historically, kind of as we’re looking at payback—it’s an important thing that we look at when we think about is it a time to grow or kind of how do we want to allocate capital.
If you think, you know, in normal times you may see paybacks on picking up an incremental rig in, call it, the 12- to 18-month range. In bad times it may slip longer than 18 months, and in good times it’s shorter. And I think this year it is well inside of 12 months. I mean, you’ve seen it: this year we kind of increased capital spend by, call it, $150 million-ish, and we’ve generated an incremental $300 million of free cash flow in the same year we did it.
So these are some of the shortest-cycle paybacks we’ve got—that’s been, you know, increased net wells through incremental working interest as well as the production team finding capital projects in the field that have been crazy quick paybacks. You know, think turning on wells that have been offline for a while. Think, you know, small little refrac jobs or surfactant jobs, you know, or other artificial lift optimization.
Neil Digman (Analyst at William Blair)
No, very notable. Nice job on those. And then my second question, James, maybe for you just on M&A. You talked about this already—looking at it, just kind of looking at the maps, over the last couple of years you’ve done a great job blocking up a lot of your core areas in, you know, Eddy, Lea, Reeves, etc. Sort of two questions here: is there still additional white space to fill? And secondly, you know, would you all consider adding assets beyond, you know, I’d call these core areas?
James Walter (Co-Chief Executive Officer)
Yeah, I’d take the second question first. I mean, we’re—the name’s Permian Resources, so you can rest assured we’ll stay in the Permian Basin. And, man, we see so many opportunities in the core of the Delaware I don’t see a reason in the near term, probably the midterm either, that we’d be looking in kind of what we’d call different areas. Like, we do think, to answer your first question, there’s a ton of white space. Like, I’d say our momentum on the small-ball stuff, the ground game, is as good as it’s ever been.
That kind of stuff, quarter over quarter, has been really good for Permian Resources. I think those are some of the highest-returning, most near-term acquisitions that we do. And, you know, I think the bigger stuff, looking out the next couple of years, I think we feel really good about. I think there’s a good pipeline of businesses to buy. I’d say there’s nothing imminent, nothing near term for us. But, you know, over the next year or two or three, I think we’ll continue to find acquisitions like this Ridge Runner deal, like the Ward County acquisition we did earlier this year, or the Apache one we did last year.
Neil Digman (Analyst at William Blair)
Thank you all.
James Walter (Co-Chief Executive Officer)
Thanks, Neil.
OPERATOR
Your next question comes from the line of Kevin McCurdy with Pickering Energy Partners. Your line is open. Please go ahead.
Kevin McCurdy (Analyst at Pickering Energy Partners)
Hey, good morning. Sounds like you’ve been working the Ridge Runner deal for a while. I think we’re all pleasantly surprised that you can continue to do those attractive bolt-ons. Can you talk a little bit about the importance of the royalty program and how much of the acreage is covered by the higher NRI and what that does to your 2027 program?
James Walter (Co-Chief Executive Officer)
Yeah, sure. No, like I said, getting that royalty business alongside the kind of working interest assets is really important to us. I think it’s safe to say the vast majority of those 9,000 acres we have on slide six are kind of overlaid on the pink Ridge Runner acreage we saw on that same slide—so kind of exactly where you’d want them. And obviously I think it’s pretty simple, but it really helps enhance our returns because that’s incremental barrels and incremental cash flow that you don’t have to spend dollars to achieve.
So I think our royalty position has been a really good, important part of our capital efficiency story, and we love having the opportunity to buy high-NRI stuff like this.
Kevin McCurdy (Analyst at Pickering Energy Partners)
And as a clarification, how many wells can you execute on that Ridge Runner annually?
James Walter (Co-Chief Executive Officer)
How many wells could we… I mean… A lot. A lot. I mean, that’s all pretty drill-ready stuff in existing areas that we already operate. You know, I think kind of for simple modeling purposes it’s probably, you know, a little less than a rig, something like that. But, but no, to answer your direct question, you could drill it, you could drill it a lot quicker than that. And I think we might. You know, I think for us after we buy things we no longer think about a RidgeRunner versus Permian Resources. We think about it as the combined business and make the right capital allocation decisions from there.
Will Hickey (Co-Chief Executive Officer)
I think we’re going to take it quarter for quarter. Obviously we had a lot of growth into Q3 with the acquisitions. There’s a little growth into Q4. If you kind of look at what we’re projecting, I think next year we will just probably keep it close to the vest until we get there. I think you’re right in that, I mean the strip still looks good even with the pullback this week and service costs are, I’d say we’ve been able to mitigate a lot of the diesel-related inflation we’ve seen year to date.
So, I mean, the return profile as we sit here today still looks very attractive. But, I mean, this is a dynamic world and things are changing quickly. And so I think that there’s one thing we’ve demonstrated that we can do really, really effectively is we can make very quick pivots in the schedule like we did this year. If you think about this year, we entered on the lowest capex we’ve ever put out at 1.85 billion and basically a no-growth mode. And then sometime mid-March we decided this is a very unique money-making environment and we are now going to project to do over 10% year-over-year organic growth in the same year.
So I think that allows us to kind of wait till we actually get there to see what the world looks like. But I think we’ll do everything we can to do it within the existing rig and frac fleet count, you know, to kind of continue to pick up efficiencies and grow the right way where the cost structure does not increase in spite of the growth, but we can maintain being the low-cost operator, and then we can make the decision on is it the return environment that justifies growth or not.
OPERATOR
Just a reminder to limit yourself to one question and one follow-up. Your next question comes from the line of John Freeman with Raymond James. Your line is open. Please go ahead.
John Freeman (Analyst at Raymond James)
Thanks. Good morning. Y’all mentioned in the release that the record low controllable cash costs were driven by the lower LOE from the optimization of the power and compression projects that led to the company’s record run times. Can y’all just sort of elaborate a little bit on these power and compression projects and if there is still more optimization to be done across y’all’s position, and could this be sort of a continued kind of tailwind into next year for you all?
Will Hickey (Co-Chief Executive Officer)
Yeah, I mean the details would be on the power side this is just the evolution of us continuing to install more microgrids across New Mexico to lower our power costs in areas where we’re not hooked up to the grid. Compression, I’d say we have a lot of compression in the field and it’s been a big effort of the team a long time to continue to have, I’d say, industry-leading runtime on the compression, which helps with the BOE part of the equation and with the cost side on the maintenance.
And then really I think this quarter we got a big tailwind on the artificial lift side. We have had the lowest failure rate I think we’ve ever printed, which obviously reduced costs and increases runtime, as well as just optimization across the whole artificial lift fleet, primarily on the ESP side, of just really kind of finding that sweet spot of moving the max amount of fluid while also keeping failure rate as low as possible. So this is just, I’d say, a function of probably a little bit of everything went right this quarter combined with a lot of small changes we’ve made over the last year kind of all coming together in a way that we were able to put out such impressive numbers.
I think going forward, yeah, we are building sustained, durable changes in the cost structure of the business. I’m not sure that what we printed in Q3 is necessarily the new norm. This was a uniquely good quarter from a weather and from a failure rate perspective that I’m not sure is the new norm. But it definitely is improving where we’ve been historically.
John Freeman (Analyst at Raymond James)
Thanks. And then on the gas takeaway topic, obviously you’ve got over 700 million a day of FT out of the basin next year, obviously going to see some nice improvement on the realizations. We’ve seen some other operators recently in the basin that have added some more FT on some newly proposed pipes. Just maybe how are y’all thinking about longer term, sort of the trade-off of maybe looking to add even more FT when you look to the out-years versus maybe expecting some improvement just in-basin demand, and just sort of the trade-off and the analysis y’all are going through when y’all kind of make that decision process on whether to add more or not?
James Walter (Co-Chief Executive Officer)
Yeah, I think we certainly think that in-basin Waha pricing should improve. That said, our goal is to sell the vast majority of our molecules further downstream. We just think over the long term being closer to end users for oil and gas is going to be the right long-term answer. That said, our contracts allowed us to preserve some optionality to kind of shift some sales back to Waha if, you know, that market were to change and be the favorable place for Permian Resources in the future.
I’d say, you know, with 700 million a day of firm takeaway next year growing to 800 in 2028, we feel like our gas is pretty well covered for the near term. You know, I think as we think out beyond that, I do think as we see, or if we see, continued gas growth in Permian Resources that we’d look to evaluate and likely kind of participate in taking out firm on some of the longer-dated pipelines. But that’s something we’re constantly evaluating, trying to figure out which markets make sense, which operate best with what we’re trying to do.
But yeah, I think the strategy of selling further downstream, closer to end users, is something that we’ll continue to stick with.
John Freeman (Analyst at Raymond James)
Thanks, guys. Appreciate it.
Will Hickey (Co-Chief Executive Officer)
See you, John.
OPERATOR
Your next question comes from the line of Philip Junworth with BMO Capital Markets. Your line is open. Please go ahead.
Philip Junworth (Analyst at BMO Capital Markets)
Yeah, thanks. Good morning, guys. On a Permian competitor call, there was some discussion around optimal multi-zone co-development and maximizing NPV per section. Recognize it’s different parts of the basin, but just curious how you would characterize PR’s approach to balancing DSU recovery with the returns, and just how optimal do you feel you’re at on the development design now, recognizing it varies by area.
Will Hickey (Co-Chief Executive Officer)
I think, just starting with the approach, we take a very similar approach to the competitor you’re referencing where we are looking at the marginal returns of the incremental well, and at some point that bends over to a place where it no longer makes sense and thus you are maximizing NPV per section and really the resource that we own. This has been something we’ve been doing for a long time. If you follow PR’s development plan since COVID, it’s been very, very similar.
I do think what is uniquely different in the Delaware is we are still very much in the camp of discovering new zones every day in the Delaware. You know, if you think about what were core zones in the Delaware Basin just two years ago, it didn’t include what people have done across the whole basin: the Avalon, the Harkey, the Penn Shale, the deeper Wolfcamp, and now the Woodford. So I think if there’s any difference between us and our competitors, I’d say that we are still very much learning every day the way to most optimize NPV per section given just the changing of the benches and the resource in the Delaware.
And we’re still in early innings, but I think from a methodology perspective we approach it very similarly, trying to just maximize value over the resource over the long term.
James Walter (Co-Chief Executive Officer)
And the other really cool thing we’ve talked about before about the Delaware Basin is just that the amount of height in the oil-producing column in Delaware is massive, and we’ve got the benefit of lots of stacked pay like other basins. I think what we have unique in the Delaware is we have a lot of barriers that kind of create frac barriers. So there are some parts of our assets that you probably do need to develop the whole top-to-bottom stack together.
But there are other parts where you’ve got two, three, four distinct tanks that don’t have to be developed at the same time as the other 10. So, like Will said, that’s a real big advantage when you’re discovering new zones, as most of the time the new zones that we’ve discovered we found actually don’t have to be co-developed with what we’ve developed historically. So that allows us to kind of particularly benefit from that serendipity going forward and allows us to make more capital-efficient decisions as we think about a development plan without sacrificing any NPV.
Philip Junworth (Analyst at BMO Capital Markets)
No, that’s great. And then there’s a small amount of cash tax creep this year, just the higher crude prices. Wondering how you see this playing out at the strip over the next couple of years. And not that this drives any decision-making, but you guys don’t stay static. So is the ground game plus organic growth something that could push this out a bit further?
James Walter (Co-Chief Executive Officer)
Yeah, I mean big picture, we still anticipate being full cash taxpayers in ’28 and somewhere in between on ’27. And we’re always taking taxes into account on, you know, investment decisions. I wouldn’t say that’s a giant needle mover on the ground game, but we’re always taking that into account.
Philip Junworth (Analyst at BMO Capital Markets)
Got it. Thank you.
Will Hickey (Co-Chief Executive Officer)
Thanks, Phil.
OPERATOR
Your next question comes from the line of Neil Mehta with Goldman Sachs. Your line is open. Please go ahead.
Neil Mehta (Analyst at Goldman Sachs)
Yeah, good morning, team. Just wanted to start off on your hedging philosophy and how you’re thinking about both the ’27 and ’28 hedge book. Obviously a lot of backwardation, balance sheet’s in good shape here, but we could be at an interesting inflection point if you want to do something around hedges. I’m just curious about that.
Will Hickey (Co-Chief Executive Officer)
Yeah, I mean, I think I’ll kick it off. I’d say, look, we’ve always taken an approach that we need to do whatever it takes to protect the business so that we can survive and thrive during a downturn. Frankly, when Permian Resources was smaller and had leverage in the kind of one-times range, that began a certain level of hedges. I’d say where we stand today with leverage at 0.5 times and delevering quickly combined with an investment-grade rating and great access to capital, I think hedging to protect the business is no longer a need.
But I do think we’ve said before that we like the concept of being opportunistic in hedging, and, you know, with commodity prices where they are today, we’ve seen some interesting windows to layer on some additional hedges. But I don’t think it’s a need anymore. It’s a nice-to-have, and you’ll see us be opportunistic rather than kind of prescriptive going forward.
Neil Digman (Analyst at William Blair)
That’s great, guys. And just the follow-up is I’d be curious on where you guys are in terms of extending recoveries. I’m thinking surfactants and secondary zone work. Just talk about what you’re doing out in the field and what inning do you think you are, and is it translating into actual improvement in recovery rates.
Will Hickey (Co-Chief Executive Officer)
Yeah, I mean we have been, I’d say, testing, studying on the surfactant side for probably a year now. We have done quite a few of, I’d say, post-production surfactant jobs on the production side. And honestly, some of that is when I say production-related capital expenditures in the quarter are, in fact, exactly that. You know, go pull an ESP that’s two years old and, with a pump truck out there, pump some surfactant in there. And I’d say on both the production side and on the initial completion side, we have seen some cases of tremendous uplift from surfactants, and this is tremendous uplift from legacy wells in the area and control wells on the exact pad. What’s been challenging for us is really kind of sifting through the variability of the results to date. You know, there are some wells where you see uplifts, you know, 30, 40-plus percent relative to a control and other wells where you see no uplift or, in some cases, even slightly worse wells as compared to the control.
And so I think what’s encouraging is if you look at it on an aggregate basis, both on the production and on the completion side, from the capital we’ve spent, we have generated a sub-one-year payback and really returns that are competitive with the existing program on the aggregate. The complexity is really trying to dig into, I’d say, question one of: Is this true EUR enhancement recoveries, or is this just acceleration of barrels you would have already got?
And then two, how do we fine-tune this where we do more 30–40% increases and less zero or even decreases? And so what inning are we in? It’s got to be early, you know, the second inning. But I do think that unlike other things we and others in the industry have tried over the last couple of years, this one has encouraging results early. It’s just going to be very—it’s going to be a long trial-and-error process to get it to kind of get the right recipe where you can model it, predict it, and talk about what it’s going to look like in the future.
Neil Digman (Analyst at William Blair)
Okay, that’s helpful, Will, thank you.
Will Hickey (Co-Chief Executive Officer)
Thanks, Neil.
OPERATOR
Your next question comes from the line of Arun Jaram with J.P. Morgan. Your line is open. Please go ahead.
Arun Jaram (Analyst at J.P. Morgan)
Yeah, good morning, Will and James. You guys have always been really strategic and nimble on how you’ve managed your supply chain as well as your contracting strategy in the Permian. I was wondering how you guys are thinking about that philosophy or executing that strategy or philosophy in 2027, where we do have some inflationary headwinds largely associated with consumables, but, you know, frac activity could get a little bit tighter. And how do you think also about the natural gas versus diesel arbitrage when you’re thinking about, you know, the type of fleets that you may want to be working next year?
James Walter (Co-Chief Executive Officer)
No, I think everything you just said is on our mind. We have, I’d say, even earlier this year or even last quarter, thought about how far out should we be prior-purchasing casing, given the run-up in HRC and potential kind of tariff-related casing increases that are projected into ’27. We have been looking long and hard on, you know, putting DGB-type kits on our rigs to reduce diesel consumption. I’d say e-fleets are on the table for us, which has been something that has not been in the past.
I think that our strategy as to how we have approached contracting and partnerships with our service companies has not changed. I just think that the balance of where the value is is shifting from, you know, if we can pump less diesel, that moves the needle a lot more than it did in the past. And so, you know, maybe it makes sense to spend some capital to convert a fleet or increase horsepower hours slightly to reduce diesel consumption because, at the end of the day, that delivers a lower cost per foot wellbore.
But no, I think that you’re correct in that diesel and casing are headwinds. Look, there’s been other areas that we have seen deflation over the last quarter. Like, it’s not all up and to the right. We have seen some areas that, you know, the efficiencies that the service companies have provided allowed a little bit of deflation, or deflation in other areas. But no, we’re going to do everything we can to kind of continue to be the cost leader in the Delaware going into ’27.
Arun Jaram (Analyst at J.P. Morgan)
Great. And I just had a follow-up on your fourth-quarter guidance. Sorry for splitting hairs here, but you produced 208 in 3Q. You’re adding 4 KBD from the Ridge Runner, the old partial quarter of the Ridge Runner, and you guided above 210. So the question we’ve got is, you know, do you expect the 208 that you produced in 3Q—expect it to be flat, go down a little bit, up? Just a little bit of color around that would be helpful.
James Walter (Co-Chief Executive Officer)
Yeah, that’s a good question. I think probably some rounding in guidance, etc. But we expect Q4 to be more or less flat from Q3, with the addition of the Ridge Runner barrels.
Arun Jaram (Analyst at J.P. Morgan)
Thanks for clarifying. Appreciate it.
OPERATOR
Your next question comes from the line of Josh Silverstein with UBS. Your line is open. Please go ahead.
Josh Silverstein (Analyst at UBS)
Thanks. Good morning, guys. Given all the acquisitions you’ve done year to date, can you just talk about the runway of your inventory and well productivity trends? You know, is the new acres that you’re adding— is this just extending the duration of your current productivity, or can you guys actually, you know, increase that well productivity kind of average profile with the new inventory? Thanks.
James Walter (Co-Chief Executive Officer)
No, I think that what the acquisitions do is they probably extend the top quartile of our inventory, if that’s how you want to think about it. So I would expect flat year-over-year well productivity into next year, just as we saw over the last five years. I mean we’re buying rock that shares lease lines, extends laterals, and is incremental working interest in our existing units. So all this is just more of our ability to prosecute the exact same development plan with the same capital allocation that we’ve done historically.
Josh Silverstein (Analyst at UBS)
Got it. And then I was curious if there are any gating items around the ground game, you know, in regards to the, you know, the balance sheet leverage. Do you want to keep that below a certain level? And how do you balance this versus shareholder returns?
James Walter (Co-Chief Executive Officer)
Yeah, I mean, I think we’re always conscious of not putting the business at risk when we do anything—acquisitions, development, capital. Our balance sheet’s in unbelievable shape. We’re less than half a turn levered, de-levering quickly with a ton of cash flow coming off the business, and investment-grade rating. So I’d say the balance sheet is by no means a limiting factor today. I do think, kind of as we think about shareholder returns and other things, as the balance sheet continues to de-lever from here, that kind of makes us take another look at some of the other means to create value for shareholders—acquisitions, share buybacks, increasing the dividend further, etc. And it’s always been kind of weighing the opportunity set against each other and seeing which of the four or five capital allocation decisions we think are going to make the most value for shareholders over the long term.
And, you know, I’d say our framework and how we think about it hasn’t changed, but the balance sheet is in really good shape.
Josh Silverstein (Analyst at UBS)
Thanks, guys.
James Walter (Co-Chief Executive Officer)
Thanks, Josh. Thanks, Josh.
OPERATOR
Your next question comes from Oliver Huang with TPH Research. Your line is open. Please go ahead.
Oliver Huang (Analyst at TPH Research)
Good morning, James, Will, and team, and thanks for taking our questions. Just on my first question on capital allocation, I know you all aren’t ready to speak to 2027 quite yet, but just given all the ground game work, the bolt-ons done this year, could we potentially see the New Mexico side of the play garner much more capital as a portion of the corporate?
James Walter (Co-Chief Executive Officer)
It’ll be pretty consistent. I mean, we bought that Ward County bolt-on last quarter. So I kind of think our acquisitions have been directionally weighted the same as our capital has been historically. And Michael said we think capital allocation development decisions should look a lot like they have the last few years, which, as you mentioned earlier, is extremely strong.
Oliver Huang (Analyst at TPH Research)
Okay, makes sense. And just for my second question on the Ridge Runner assets, any sort of color you can provide on what the working interest is on that specific acquisition? I just know that you all spoke to leaning into higher working interest over the course of the year multiple times and just trying to understand what the opportunity set might be for this specific footprint.
James Walter (Co-Chief Executive Officer)
Yeah, I mean that working interest is in line with kind of what we’ve been drilling. You know, I think what will be cool about that acquisition is it does give us opportunity to go buy some new non-ops out that we haven’t had before. You know, I’d say every time we’ve done an acquisition historically, that just creates more ground game opportunities to take that working interest from, you know, 75 or 80 to 90, and that will, I think, provide a good ground game runway to continue to net those working interest ups from here.
Oliver Huang (Analyst at TPH Research)
Perfect. Thanks for the time.
OPERATOR
Your next question comes from the line of Gabe Dowd with Truist Securities. Your line is open. Please go ahead.
Gabe Dowd (Analyst at Truist Securities)
Hey, Sophia. Hey guys. Morning. Thanks for taking my questions. Was hoping we can maybe just go back to the capital allocation and, just given how focused you are on driving free cash flow per share growth, the question, I guess, is would the buyback become a greater—like a bigger tool in you driving that free cash flow per share growth higher over time? As you noted, the balance sheet is in really good shape. So, just curious, I guess, how does the buyback and your view on using the buyback change over time?
James Walter (Co-Chief Executive Officer)
Yeah, I mean, I think we’ve always said we wanted to buy back shares. I think that’s always been an important part of our capital allocation strategy. I’d say the last four years we’ve seen better opportunities on the cash acquisition and the kind of balance sheet side. I do think, though, to your point, as the balance sheet gets better and better, I think the attractiveness of buybacks, especially with our really good feeling for how the business develops and grows free cash flow per share over the next five and ten years, I do think that net-net buybacks do become more attractive.
I’d say, that said, we are cautious to do buybacks that end up being procyclical. But I do think, to your very smart question, as the balance sheet is stronger and stronger over time and, frankly, we’re more and more confident in the long-term durability of this free cash flow per share growth, I do think that buybacks become more attractive.
Gabe Dowd (Analyst at Truist Securities)
No, that’s helpful. Appreciate that, James. And then I guess it’s a quick follow-up. Could you maybe just tell us, just given all the deals and you’re kind of guiding to greater than 80% working interest—like how greater is greater than 80? Is it 90? Like, how much has that moved up this year, just given all the deals that you’ve done?
James Walter (Co-Chief Executive Officer)
It’s a little bit over 80. Probably the right way to frame it.
Gabe Dowd (Analyst at Truist Securities)
Not 85. Okay, okay, okay. Got it, got it. All right, thanks guys.
OPERATOR
Your next question comes from the line of John Abbott with Wolfe Research. Your line is open. Please go ahead.
John Abbott (Analyst at Wolfe Research)
Hey, good morning, and thank you for taking our questions. So, really, two quick ones for me. First, you continue to improve your base business. Can you remind us where your underlying decline rate is at and the opportunities to improve upon that as well? And the second question, I’m going to go back to workovers. Asked about it last quarter, at that time it seemed that you had pretty much exhausted the opportunities. But this quarter you’ve highlighted them again. What has changed on the workover front? What is the opportunity running room there at this point in time? Those are my two questions.
Will Hickey (Co-Chief Executive Officer)
Love it. I’ll take them both. Thanks, John. Our baseline really hasn’t changed. It’s still in the high 30s on an oil basis and call it mid-30s on a boe basis. Just the growth, the organic growth that the business has demonstrated over the last few years is obviously offset to what would have naturally been an arresting base decline. And then on the… yeah, on the capital workover side, it’s very astute of you. It did feel like at the end of Q2 we had kind of run the course of finding workover-related projects. I’d say two things changed. One, if you think about we took over operations on that Ward County bolt-on, which was a legacy asset of a much larger company, which I’d say is normal course for us is us to go kind of work over and get those wells back online. But in this particular case, given oil price, I’d say we aggressively worked over that asset.
So new assets came in that created new opportunities, as well as kind of… I think my definition of workover may have expanded quarter over quarter where the team has found, you know, not just take wells that were down and get them back online, but think more proactive projects to convert, you know, gas lift to ESP in cases where ESP made sense. Things like surfactant jobs or other acid jobs kind of… historically, I’ve always thought of workovers if you’ve got a backlog of wells that are down and you can go fix them.
And in reality, when oil’s in the 90s, the team can go find ways to add barrels on a more proactive basis.
John Abbott (Analyst at Wolfe Research)
Appreciate it. Thank you for the color.
OPERATOR
Your next question comes from the line of Paul Diamond with Citi. Your line is open. Please go ahead.
Paul Diamond (Analyst at Citi)
Thank you. Good morning. Thanks for taking the call. As you talk about increased takeaway and recovering Waha, I guess pricing matrix, does that shift the development plan at all? Is there any room for maybe a few higher GOR wells, or is it all still going to remain largely oil-driven?
Will Hickey (Co-Chief Executive Officer)
Yeah, I mean the economics is still oil-driven at anything resembling these prices. I wouldn’t say it changed capital allocation at all, but it does make the returns of our wells meaningfully higher. You know, I think every well that you drill makes a lot of gas, and higher gas prices from better downstream makes every single well we drill more economic, faster paybacks, more free cash flow. So it’s all really good but doesn’t change capital allocation.
Paul Diamond (Analyst at Citi)
Got it. And then just a quick follow-up: as you guys, you know, especially with Ridge Runner and the transactions last quarter, you guys are seeing a rising component of royalty interest across the portfolio. I guess, can you talk about the strategy of those within the portfolio? Is there any potential for monetization at a certain scale, or do you like them where they are?
Will Hickey (Co-Chief Executive Officer)
I mean the first kind of driving reason we’ve always targeted high NR acreage is because it makes the economics better. It makes every well you drill return stronger, payback shorter, and more free cash flow for the same capital. So that’s kind of the root driver and kind of has always been. But I will say as the business has grown, I do think we’ve got a really high-quality royalties business that’s probably underappreciated by the market, both what it means to the upstream business but also what it means kind of on a standalone basis.
So I think for us for now we like having it kind of where it sits today. But, you know, I think over time, especially, we’re convinced that could make sense and unlock additional value for shareholders. We consider ways to kind of enhance and maximize value there. But I’d say for now it’s still largely upstream-driven from a rationale standpoint, and we like where it sits.
Paul Diamond (Analyst at Citi)
Understood. Appreciate the clarity. I’ll leave it there.
OPERATOR
Your next question comes from the line of Leo Mariani with Roth. Your line is open. Please go ahead.
Leo Mariani (Analyst at Roth MKM)
Hi guys. Sort of speak to the M&A environment a little bit more. Obviously you guys have done a number of deals. You know, was this Ridge Runner kind of a competitive marketed deal? Are you seeing most of the deals in the Permian come with kind of more competition these days? Just trying to get a sense of what you’re seeing on deal flow and then sort of competition from others?
Will Hickey (Co-Chief Executive Officer)
Yeah, I think generally the bigger deals that we see tend to have some amount of competition. Kind of the $500 million and bigger tend to have some sort of competition. I think for us we’ve only ended up buying deals that we thought we had a unique edge, unique angle, and typically a one-on-one dialogue with the seller, which is how Ridge Runner ended up. And then on the smaller stuff we still buy most of our ground game and bolt-on stuff on a bilateral negotiated basis that’s not marketed and tends to not have any other buyers in the room as negotiations go on.
Leo Mariani (Analyst at Roth MKM)
Okay, appreciate that. And I guess just wanted to also get a sense of whether or not you guys are continuing to maybe, you know, look harder at some of the secondary zones, potentially the Woodford, as we get into 2027, particularly in light of the better gas environment.
Will Hickey (Co-Chief Executive Officer)
Yeah, look, I’d say generally speaking, yes, we’re always looking at secondary zones and ways to kind of find free resource over our existing position. I’d say that what’s happened so far on kind of the eastern margins of the basin, the Woodford is exciting if you look at the same kind of… You’ve seen a lot of pin shale development across Lea and Eddy counties over the last few years, as well as kind of some co-development in the Harkey and the Avalon in ways we have not seen in the past.
So look, the Delaware Basin, I said this earlier, is like we are still very much in the middle innings of discovering the optimal cube across the entire basin. And as such, new benches like the Woodford, Pin Shale, etc., continue to get discovered. Look, I think for our position in New Mexico, you can assume we own all depths, including all the way through the Woodford across the whole position. And in Texas, it’ll be, you know, most of it. We will not due to the Pugh clauses, but we’ll own it on a kind of a small percentage of it across the Texas position.
Leo Mariani (Analyst at Roth MKM)
Okay, thank you.
OPERATOR
Just a reminder, if you would like to ask an additional question, please press star one. If you would like to withdraw your question, press star one again. Your next question comes from the line of Jeff J. with Daniel Energy Partners. Your line is open. Please go ahead.
Jeff J. (Analyst at Daniel Energy Partners)
Hey guys, a very quick one for me, kind of a follow-up to John Freeman’s question earlier. I guess I’m curious, you know, the AI monitoring, the biggest contribution to the low failure of lift, and then kind of the follow-up to that is just how broadly is that now deployed? Is it kind of fully integrated across the acreage?
Will Hickey (Co-Chief Executive Officer)
I don’t want to give the AI that much credit. I think our team has been optimizing this stuff forever. I do think them getting it into a single dashboard with an artificial intelligence engine sitting on top has been very enlightening. I think of it as if a production engineer working the Haley asset, kind of on the eastern edge of Reeves County, makes a change to the number of hertz to fix a warning or fix a problem, the AI engine learns that that worked.
And then when an engineer working Lea County encounters the same problem, it immediately tells him, hey, somebody did this yesterday and it fixed it. Why don’t you try this? So it’s not… I don’t want to give it credit that it’s solving things we couldn’t solve. It’s just disseminating information in a way that we could never have done really quickly. And then as to where it sits, I’d say all of our ESPs are on it. So I think we run about 600 ESPs as a company and all 600 are in this application that has real-time monitoring. I’d say where we’re headed now is to try to get gas lift, rod pump, etc., so we can make the same dissemination of information on, like, what type of… you know, if you see GLRs move in one direction, if you could have the AI engine say, hey, I recommend you shift this from gas lift to ESP or vice versa, as opposed to just optimizing the lift that’s already on it.
Jeff J. (Analyst at Daniel Energy Partners)
Excellent. Great color. Thank you.
Will Hickey (Co-Chief Executive Officer)
Thanks, Jeff.
OPERATOR
Your next question comes from the line of Noah Hungness with Wells Fargo. Your line is open. Please go ahead.
Noah Hungness (Analyst at Wells Fargo)
Morning. For my first question here, given all of the M&A and just the base business improvements as well that people have been touching on, could you help us how we can think about what a maintenance capex kind of program looks like now?
Will Hickey (Co-Chief Executive Officer)
Yeah, I’d say kind of at the, call it north of 200,000 barrels of oil per day rate that we printed this quarter, the business is 10% bigger. I’d say maintenance capex is probably between 1.9 and 2 billion.
Noah Hungness (Analyst at Wells Fargo)
Is that also inclusive of the Ridge Runner? And then I guess for my second question is kind of going off of the gas marketing and your guys’ push to get closer to the end user. Getting the gas to the Gulf Coast obviously gets you closer to the end user, but is there a desire to take a step further and try to set up supply agreements with an actual end user? Or, you know, we’ve seen some of your peers sign up to work with offtakers around LNG. Are these kind of options that you guys are exploring, or is it interesting?
Will Hickey (Co-Chief Executive Officer)
No, absolutely. That’s a great question, something we spend a lot more time on. I think you said that our first priority was moving further downstream to get away from Waha and closer to end users, and I think we’ve done a tremendous job of that — pretty close to mission accomplished, like I said earlier. But that’s just step one. I think as we think about continuing to optimize how we market and sell our molecules, fortunately we have a ton of flexibility kind of downstream from there, and I’d say we’re looking at all options today — LNG deals, kind of final end users, you know, potential infrastructure investments, etc. But I think that said, we have a really high bar for investment returns. So I think we’re being very thoughtful as we think about how we spend dollars, if we spend dollars, and where we want to sell molecules for not just the next year but the next decade plus. So I think that’s kind of step two and step three after a really successful step one, but something we spend a long time on and so should have more to share over the next year or two.
Noah Hungness (Analyst at Wells Fargo)
Great color, thank you.
OPERATOR
There are no further questions at this time. I will now turn the call back to James Walter, Co-Chief Executive Officer, for closing remarks.
James Walter (Co-Chief Executive Officer)
Thanks again to everyone for joining the call. As you can see, Q3 was an outstanding quarter. The combination of higher production and lower cash costs led to record free cash flow, and our acquisition strategy continues to improve our free cash flow and inventory. We look forward to building on that progress and continuing to drive value for our shareholders for years to come. Thanks again.
OPERATOR
This concludes today’s call. Thank you for attending. You may now disconnect.
Disclaimer: This transcript is provided for informational purposes only. While we strive for accuracy, there may be errors or omissions in this automated transcription. For official company statements and financial information, please refer to the company’s SEC filings and official press releases. Corporate participants’ and analysts’ statements reflect their views as of the date of this call and are subject to change without notice.
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