Permian Resources Corp Q4 2025 Earnings Call Transcript

Permian Resources Corp (NYSE: PR) Q4 2025 Earnings Call dated Feb. 26, 2026

Presentation

Operator

Good morning, and welcome to Permian Resources conference call to discuss its fourth quarter and full-year 2025 earnings. Today’s call is being recorded. A replay of the call will be accessible until March 13th, 2026, by dialing 888-660-6264 and entering the replay access code 23999, or by visiting the Company’s website at www.permianres.com.

At this time, I will turn the call over to Hays Mabry, Permian Resources Vice President of Investor Relations, for opening remarks. Please go ahead.

Hays Mabry — Vice President, Investor Relations

Thanks, Natasha, 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 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, Hays. We’re excited to discuss our fourth quarter results as well as our 2026 plan this morning. We set records across every key operational metric in Q4, including our highest oil production, lowest D&C cost per foot, and lowest controllable cash cost in PR’s history. Our strong Q4 performance capped off an excellent 2025, with free cash flow per share increasing 18% year-over-year to $1.94 per share. This performance was achieved alongside meaningful debt reduction, demonstrating the strength and consistency of our core operations. We believe 2025 represents a highly repeatable year and a clear demonstration of the strength of our business. As we look to 2026, our focus remains the same: maximize shareholder value through disciplined execution of our highly capital-efficient Delaware Basin program. And we’re proud to lay out a ’26 plan that we expect will continue to drive free cash flow per share growth going-forward.

Moving into quarterly results, Q4 production exceeded expectations, with oil production of 188.6,000 barrels of oil per day and total production of 401500 barrels of oil equivalent per day. Our D&C team continued to execute at a high level, reducing D&C cost per foot to $700, resulting in $481 million of cash capex for the quarter and $1.97 billion for the year. In addition, we delivered leading cash costs, supporting strong margins with Q4 LOE of $5.26 per BOE, cash G&A of $0.80 per BOE, and GP&T of $1.18 per BOE.

Strong production results, paired with low cash costs and capex, resulted in adjusted operating cash flow of $884 million and adjusted free cash flow of $403 million.

Lastly, I want to highlight we’re increasing our 2026 quarterly base dividend to $0.16 per share, a 7% increase. Since inception in ’22, Permian Resources has grown its quarterly base dividend at a 40% CAGR, reflecting the company’s commitment to delivering a sustainable and growing base dividend.

On slides 4 and 5, I just want to highlight how strong 2025 was for Permian Resources. This marked our third consecutive year of strong operational execution as a public company, building on our previous track record as a private company dating back to 2015. The depth and experience continued to translate directly into results in the field.

Including the bolt-on acquisitions we closed during the year, we delivered 5% higher oil production than our original ’25 guidance, with more than half of that outperformance coming from improvements in the base business. That speaks to the quality and durability of our underlying asset base. At the same time, the team continued to structurally lower cost. On the drilling side, we increased drilling feet per day by 6% year-over-year by continuing to optimize BHAs and targeting in the lateral. In completions, completed lateral feet per day increased 20% year-over-year due to increased simul frac efficiencies and other improvements. And on the operating side, initiatives like our microgrid projects and runtime improvements led to a 3% reduction in LOE per BOE.

We also strengthened the corporate cost structure by reducing debt by over $600 million, enhancing netbacks through marketing optimization, and holding nominal G&A flat despite a larger production base. All of this directly benefits our ’26 plan, which James will outline shortly.

Given the marginal nature of free cash flow in our business, operating as a low-cost leader is a critical part of our plan to increase free cash flow per share over time.

Slide 6 highlights the details of the meaningful progress we’ve made improving our gas realizations by reducing Waha exposure. We laid the groundwork in ’24, with key hires across midstream and marketing department. And we continued building that capability through 2025.

As a result of the agreements we’ve executed, we expect to sell approximately 400 million cubic feet per day out of the basin in 2026, increasing to roughly 700 million cubic feet per day in 2027 and beyond. Combining that with our existing hedge position, reduces Waha exposure to approximately 10% of total gas volumes in 2026 and improves unhedged gas realizations.

Specifically, in 2025, we expect our gas realizations to be a roughly $0.40 discount versus Waha. Through these recent efforts, we now expect to realize a $0.50 premium to Waha this year.

With that, I’ll turn it over to James to walk through our BD efforts and our 2026 guidance.

James Walter — Co-Chief Executive Officer

Thanks, Will. Turning to Slide 7, we wanted to highlight the continued success of our acquisition strategy. During Q4, we closed on approximately 140 transactions totaling $240 million. This particular set of acquisitions was heavily inventory weighted and added 7,700 net acres, 1,300 net royalty acres, and approximately 70 net locations at attractive valuations. The Q4 acquisitions capped off a great 2025 M&A program and our confidence in continuing to execute on this strategy going forward is as high as ever. We completed approximately $1.1 billion of acquisitions during the year, adding about 250 locations and 13,000 BOE a day within our existing operating areas.

These 700 acquisitions consist of a large asset deal from Apache in New Mexico, several medium-sized bolt-on acquisitions, and a substantial ground gain that totaled over 675 smaller transactions. For the third consecutive year, PR acquired more inventory than we drilled during the year, both increasing our inventory life and enhancing the quality of our go-forward plan. In addition to the 250 high rate of return locations that PR acquired through the year, PR also added another 200 locations through organic inventory expansion. We believe that our local presence in Midland and our peer-leading cost structure in the Delaware provide a competitive advantage as we pursue transactions that create long-term value for shareholders.

Over the next 12 to 24 months, we are confident in our ability to continue to find attractive deals that drive value for investors and make our business better, just like we have the last 10 years.

Turning to Slide nine, we are excited to discuss our 2026 plan, which is focused on maximizing returns and free cash flow per share through consistent, thoughtful capital allocation and low-cost execution. This plan is a product of significant collaboration across the organization, and we want to thank our entire team for the commitment and effort behind it. For the full-year 2026, we expect total production to average 415,000 BOE per day and oil production to average 189,000 barrels of oil per day.

We expect to spend $1.85 billion of capex for the year, with approximately $400 million of that coming from non-D&C spend. Overall, this plan delivers production in 2026 that is approximately 5% higher than 2025 for capex, that is $120 million lower. Our development program in well mix will be largely the same as last year and will continue to be focused on our high-returning Delaware Basin assets, with the New Mexico portion of the Delaware accounting for about 65% of activity and the Texas, Delaware accounting for about 30%. We expect our average working interest 8/8ths NRI, and well mix by zone to be very similar to last year.

The combination of the same or better well productivity with lower costs across-the-board drives meaningfully improved capital efficiency and lower breakeven, which we can go through in more detail on Slide 10. As we’ve been saying for a while now, we are drilling the same wells in the same areas this year as we have in the past few years. And, as a result, expect 2026 productivity to be in line or slightly better than ’24 and ’25, which are basically on-top of one another. And we continue to see meaningful improvements in our cost structure, with our anticipated 2026 costs of $675 a foot, approximately 20% cheaper than we were in 2024.

The combination of PR’s consistent well productivity and lower operating costs allow PR to continue to improve our capital efficiency and deliver a 2026 plan that has 20% higher oil volumes on 10% less capex than when compared to 2024.

Turning to Slide 11 to go back to 2023, to highlight the continued execution that has helped drive the outsized investor returns we will highlight in the next slide. Our sole focus today is on increasing free cash flow per share and creating long-term value for investors. From 2024 to 2026, we’ve increased oil production by 30,000 barrels of oil per day, while reducing our capex budget by $250 million.

Free cash flow per share has grown from $1.13 in 2023, when oil was at $78, to almost $2 per share this past year, with oil averaging $65 per barrel, representing a CAGR of approximately 30%. PR’s consistent free cash flow per share growth proves strong execution can overcome commodity price volatility and create outsized returns for investors. Finally, slide 12 helps summarize the free cash flow per share growth we’ve achieved over the past years, with our team’s efforts leading to free cash flow share in 2025, that is 72% higher than it was in 2023. This is what we have our entire team focused on, durable, long-term free cash flow per share growth. And what the other two graphs show are, one, that free cash flow per share growth has driven our outsized shareholder return, and two, that shareholder return has occurred without a re-rating of our business. And so our plan is to keep growing free cash flow per share. We are confident that execution on that plan will drive continued appreciation in our share price, with or without a re-rating of our multiple.

Thank you for tuning in today, and now we’ll turn it back to the operator for Q&A.

Question & Answers

Operator

[Operator Instructions] Your first question comes from Kevin MacCurdy with Pickering Energy Partners. Please go ahead.

Kevin MacCurdy — Analyst, Pickering Energy Partners

Hey, great. Thank you for taking my question. Maybe a strategy question to start. You’ve had a relentless and very successful focus on free cash flow per share growth over the past few years. But whereas your free cash flow focus has led you to grow volumes, a lot of your peers are trying to grow free cash flow with flat or even declining volumes. What do you think you’re doing right that others are missing? Or is this just kind of an outcome of inventory quality?

Will Hickey — Co-Chief Executive Officer

Yeah., I mean, I think there’s definitely different ways to grow free cash flow per share. You can kind of grow it via the numerator, which has largely been our strategy, kind of both organic and inorganic free cash flow growth over the last couple of years. And you can also grow it through the denominator. I think that’s probably a different business model than we have pursued, as you outlined, but I don’t think there’s anything that makes it wrong. I think it reflects, yeah, like you said, I think an opportunity set, an inventory quality and really just the maturity of our business.

Like, I think kind of a lot of businesses that are kind of shifting to a reduce the denominator buyback shares strategy, I think those are kind of typically more mature businesses and more mature basins. And I’d say for us we’re fortunate. I think we’re in the most exciting oil basin in North America that has a ton of running room. So you’ve seen us do more free cash flow per share growth in the terms of organic growth and growth through acquisitions. And that’s been a really good recipe for us. And I think we’re really fortunate that opportunity set for the next few years feels as good or better than it’s been the last couple.

Kevin MacCurdy — Analyst, Pickering Energy Partners

Thanks. And maybe a follow-up on capital allocation. You have a lot of free cash flow coming your way in 2026. The balance sheet is in a great position. Can you talk about maybe how you’re thinking about the various uses of cash this year?

Will Hickey — Co-Chief Executive Officer

Yeah, I think we have a great slide in our deck, Slide 16, and I think we’re really fortunate. We got a ton of free cash flow coming in. And for us, our plan is to use every tool we’ve got in the toolkit kind of as the opportunities persist. I think capital allocation is something we’ve really prided ourselves on. I think we’ve done a great job of that the past decade. And look, we’re going to allocate capital to the opportunities in front of us that we think will drive the greatest return over the long term.

Obviously, the base dividend is first and foremost, and we’re proud of our track-record of continuing to grow that dividend year in and year out. And then beyond that, it’s going to really depend on the opportunity set.

I think if we have opportunities for really attractive, accretive acquisitions, we’ll pursue those to the best of our ability. And if we don’t I think we’re always excited to accrue cash to the balance sheet because we know this is a cyclical business, and I think paying down debt and saving dollars for the future has been a great return for us in the past. And finally, dislocations exist. We are excited to buy back shares. Obviously, we leaned in heavily for a week or two in April and haven’t had a lot of opportunities there since then. But for us, I think capital allocation really is all of the above, and we don’t see any need to kind of limit or restrict ourselves going forward.

Kevin MacCurdy — Analyst, Pickering Energy Partners

Appreciate that, and congratulations on the results.

Operator

Your next question comes from Neal Dingmann with William Blair. Please go ahead.

Neal Dingmann — Analyst, William Blair

Good morning, guys. Nice quarter. James, my question is maybe sticking with this a little bit, is on-the-ground game, specifically just pure sale. How active do you all believe you can continue to be on ground game and maybe just M&A in general, given a couple of things? One, I mean, it’s very notable your peers are out there paying record prices for leases, and even the ABS market continues to heat up. So it certainly seems to be a bit of a sellers’ market out there. So just you seem to have confidence both on ground game and just external growth overall. I would love to hear where that confidence comes from.

Will Hickey — Co-Chief Executive Officer

I mean, our ground game, the small blocking and tackling stuff, has been remarkably consistent for a decade. I think if anything, as we’ve gotten the larger position we have today, we’ve gotten kind of our team in place. I think it’s probably — the prospects are better and 2025 is probably our best year ever from a ground game perspective. So that feels really good.

I think a lot of these deals that we’re doing are kind of less subject to-market pricing and fluctuations. I think about the ground game and most of the bolt-ons that we’ve done, those are kind of one-off negotiated deals that were sourced through relationships we have in Midland, industry partners, relationships we have in New Mexico that go back the better part of a decade.

So, I think we’ve been fortunate to see that those have been less price-sensitive, and we’ve been able to find a lot of — lot of good values. And look, I mean, we’re paying, I think, real prices for high-quality assets. That’s always been key to our business model, but we’re definitely still seeing opportunities that make a lot of sense. And I think more insulated from market fluctuations.

With regards to ABS, changes in markets, we’ve been pursuing inventory-weighted deals kind of for the entirety of our existence. We’ve kind of stayed away from assets that were larger percentage of production, higher decline, things like that. So I think for us, haven’t seen a lot of pressure from the ABS market on the type of acquisitions we like to buy, just because we’re pursuing more inventory-weighted deals.

Neal Dingmann — Analyst, William Blair

Okay. Well said. And then my second question, just on potential for ancillary businesses, specifically you all talked in the past, I mean, you’ve got a fair amount of surface acreage. There’s potential for you and some other guys in the basin for power deals. And I know we’ve talked about maybe even how actively are you looking at, I don’t know, either things like lithium extraction or other byproducts of your produced water.

Will Hickey — Co-Chief Executive Officer

I mean, we’ve said in the past, we own 25,000 surface acres across the Delaware Basin. The majority of that is in Reeves County, on the Texas side of the basin. And really, it is in — we’ve got a few kind of blockier, big chunks that I think are in pretty opportunistic spots with respect to power generation, to the extent we wanted to pursue it.

And I’m not by no means messaging that this is on the near term and something that you should hear us announce in the next coming quarters, but it is something that I think we are exploring, kind of what that market could look like and trying to better understand it. There are absolutely data centers that are coming to West Texas on kind of ranches nearby ours. So I think we’ll get to see a good kind of case study for the commerciality of what that looks like. But I think for us, it’s just a balance of — I mean that the surface acres are also very key to our day-to-day oil and gas operations.

So we’ve got water wells on them, SWDs on them, recycling pits on them, and we drive them every day. So I think we’re just trying to balance what’s the value proposition of some sort of monetization or partnership, as compared to just the day-to-day, leveraging it to reduce our cost structure in the upstream assets.

Neal Dingmann — Analyst, William Blair

Great details. Thanks, Will.

Operator

Your next question comes from John Freeman with Raymond James. Go ahead, John.

John Freeman

Thanks. Good morning, guys.

Will Hickey — Co-Chief Executive Officer

Good morning.

John Freeman

Given the continued cost reductions that you all continue to see, obviously, from a return perspective, you all could always choose to flex activity higher. When you’re going through sort of the budgeting process, is there like a — maybe either a reinvestment rate that you all are sort of targeting when setting the budget? And then just sort of also kind of what impact is sort of the geopolitical kind of driven volatility we’ve seen in oil this year kind of play into that thought process?

James Walter — Co-Chief Executive Officer

Yeah, I’d say we don’t target a super-specific reinvestment rate. I think there’s a lot of things that factor in, and macro is certainly one of them. I think we’ve said this a lot in the past, like, we’re typically focused on growing production in an environment where we see kind of free cash flow accretion in a 12 to 18-month period. So you need wells that are very quick payouts, high-returning. I think you could argue we’re in that environment today. But I think for us, we are conscious of the macro-environment that we’re in. I think we’ve had a risk as we headed into 2026 that feels a little better, frankly, today than it did, that we could be in a meaningfully oversupplied market. So kind of even with a widget like we have that checks a lot of our criteria, I think for us, it just has felt prudent as we’ve headed into planning for 2026 to be cautious on growth.

I think until we have more certainty in the macro and kind of longer-term oil prices that are kind of stable and higher., I think we’ve chosen to hold-off on that growth. But yeah, you’re right. We’ve got the inventory base, we’ve got the widgets, frankly, today, that would justify growth, but are being patient, kind of knowing that time will come.

John Freeman

Great. And my follow-up, you all added 200 locations last year just through kind of organic inventory expansion. It’s been pretty topical this earning season with some of your Permian peers that are talking about sort of increased exploration efforts, looking at some new benches or areas. Just anything else that you all are looking at that sort of has you all intrigued right now on sort of newer areas or benches?

Will Hickey — Co-Chief Executive Officer

I’d say most — if you want to use the word expiration, that may be a little bit of a stretch, but most exploration we do is going to be just better understanding what we have uphole and downhole, kind of within the 4,000-foot column that is the Delaware Basin. If you think about our development plan in ’24, ’25, and what will be our development plan for ’26, it’s been very consistent as far as we’re developing Bone Spring down through kind of the Wolfcamp XY or top of the Wolfcamp, and that’s about it. And if you look at offset operators and I say recently, we’ve added some Avalon and some kind of deeper Wolfcamp to our development plans. That’s the type of exploration that we’re doing.

I’d say we’re very much surprised as what people are doing as far as kind of pushing the play boundaries or even jumping into kind of some more unique conventional pay. But for the most part, I think you can kind of given how vast our position is today, and we feel good about the existing inventory quality and duration, I’d say it’s more of just what do we have on our existing footprint. So I’d say to round out that full answer, if you think about what we called organic additions of inventory on that inventory slide, on the deal side, Slide 8, that’s what that was.

That was we — we’ve been watching kind of as you move further north away from the state line, I’d say we didn’t typically take credit for Avalon, and we watched some other operators add Avalon. We went ahead and added it to a few of our development plans very successfully. And so on the heels of that, kind of added Avalon to the inventory stack. And same thing with Wolfcamp D or C, whatever nomenclature you may use.

John Freeman

Thanks, guys. Well done.

Will Hickey — Co-Chief Executive Officer

Thanks, John.

Operator

We now have a question from Scott Hanold with RBC Capital Markets. Please go ahead

Scott Hanold

Yeah, thanks. Good morning. [Indecipherable] consistent well productivity is impressive, and it certainly helps drive like things forward much, much better than anticipated.

I think a big part that certainly hopefully doesn’t get undershadowed is how you guys have really reduced D&C costs quite a bit over the last couple of years. And can you give us a sense of like — and agnostic, obviously, oilfield service cost gain, but you can sort of add some commentary there if you’d like. But like what are some additional levers you guys can pull to kind of continue to move that D&C cost per foot down?

Will Hickey — Co-Chief Executive Officer

Yeah. I mean if you think about just how we got here, it was a tremendous amount of progress on cutting days on the drilling side and then really just kind of riding the completion efficiencies that the whole industry has picked up as we’ve gone from single well to zipper to simul frac and leveraging recycled water with it.

I’d say go forward, I think there is more juice to squeeze on the cost side on the drilling side of the business. I just — if I look at where — for us, given where our cost structure is in the Delaware, I think where we look for someone to go chase is typically we go look at Midland Basin operators.

If we’re going to be at $6.75 per-foot in the Delaware, then there’s kind of $100 plus per foot delta between our well cost and Midland Basin well cost. And so — and if you look at the biggest delta between the two, it’s going to be on the drilling side. If we’re going to average, call it, 13 days spud to rig release on a 2-mile well. Midland Basin is going to be five-plus days faster than that. And call it, $100,000 to $125,000 a day spread rate, like that’s another $500,000, $600,000, $700,000 a well that we could go get. So that’s what we’re focused on.

If you look at drilling speed, drilling times, we cut 6% year-over-year. I think last year, we cut even more. So I think we have a track record of doing it. But very specifically to your question, it’s an all-of-the-above approach. There’s no easy wins or silver bullet. But I think if I had to pick one, it will be kind of reducing days on the drilling side, which likely means increased ROP in the lateral.

Scott Hanold

Got it. Thanks for that. My follow-up question is on M&A. And could you give us a sense of what you’re seeing on the M&A market in terms of ground game and larger stuff right now? But could you — I’m really particularly interested in state and federal lease sales. Like what is your expectation on things that could come up? Is that encouraging what you’re seeing that could also be put out there? And how competitive is that? Is that something that when you look at rate of return on ground game stuff, is lease sales, do they present a better opportunity? Or are those much more competitive in terms of trying to capture?

Will Hickey — Co-Chief Executive Officer

Those are great questions. I think on a kind of deal pipeline in general, feels really strong. Like I said, to Kevin’s call at the beginning, like our ground game feels like it’s just building momentum, kind of the opportunity sets probably widening and growing and accelerating, not shrinking. It really feels like that’s sustainable for the next handful of years at a minimum.

And we’re seeing a good kind of $500 million to $1 billion assets like what we bought with Oxy, Barilla Draw, Apache’s New Mexico exit. See a great pipeline to those. I think it’s interesting, too, like we’re starting to hear rumors and kind of see signs of larger packages coming.

Obviously, there’s been a ton of consolidation in the Delaware and the Permian more broadly. We think we’re starting to be on the front-end of seeing some of the larger companies who have been the consolidators have some kind of divestitures that make sense on the back side of that. That’s something we’ve always thought we’d see. We’ve seen kind of if you go back over the history of oil and gas, I think the largest companies consolidate and it’s kind of a deconsolidation wave comes a few years later.

And frankly, we haven’t seen really any of that in COVID. It does feel like we could be kind of entering a phase of that over the next couple of years, which kind of I think only adds to the opportunity set.

I’d say finally, with regards to your commentary about federal lease sales, we think it’s great that the kind of administration in Washington has been pushing those lease sales out. We think that’s good for the country. We think that’s good for the oil and gas business. I’d say with regards to our participation, I think historically, we’ve seen most of the time those lease sales are really competitive. You think about anybody can get on their computer and bid on them.

So I do think we’ve seen more often than not, those tend to be more expensive than most of the acquisitions we’ve looked at. And as a result, we probably haven’t been as competitive in that arena as we have been in others. But we’ve definitely bought things over the last seven or eight years in kind of both New Mexico state, Texas state and federal lease sales. But that’s typically because we have an edge, we have a strategic advantage, we have an information advantage and — but that doesn’t apply to all of them. So I think it’s certainly something we look at. It’s something we’ve participated in the past, but more often not found to be pretty competitive.

James Walter — Co-Chief Executive Officer

Great. Thank you, Scott.

Scott Hanold

Yes. Thank you.

Operator

Your next question comes from Zach Parham with JPMorgan. Please go ahead.

Zach Parham — Analyst, JPMorgan

[Indecipherable] question. James, you mentioned this in your prepared remarks and it’s also in the slide deck, but you have a [Indecipherable] comparing the last few years and 2026 expectations are flattish to — it looks like slightly up on a lateral foot-adjusted basis. Can you just talk a little bit about what’s driving that expectation for actually slightly better productivity year-over-year? Is that’s pretty different than what we’re seeing kind of across the industry?

Will Hickey — Co-Chief Executive Officer

I’d start with — Zach, we’re not that good at — I mean, this is — let’s call it flat. Just — I think there’s a little bit of visually, if you put them all on top of each other, it’s messy. And also we’re not so good that we can dial it in within 0.5%.

But to answer your general question, I mean, this is what we’ve been saying about our business since 2023 that we have a very consistent development plan where we develop kind of all of the benches that need to be co-developed at the same time, and we are developing those same benches methodically across our position. And so ’25 was no different than ’24 and ’26 is no different than ’25 and ’27 will be no different than ’26.

So I think that it is a — it’s a testament to a very consistent development methodology with an inventory position that allows us to do it and an M&A machine that continues to replenish the top-quartile in a way that I think is really sustainable. So this is a big part of our — if you follow the free cash flow per share growth, we’ve done it in spite of dramatically reducing commodity prices. And the only way to do it is that you hold well productivity flat and you cut costs more than oil prices hurt you. And so I think that’s what we’ve done in the past, and we plan to continue to do it going forward.

Zach Parham — Analyst, JPMorgan

Another thing you mentioned was drilling the longest lateral in company history in 4Q, around 17,000 foot. Is that something you’re considering doing more of? Is that something that can help drive costs lower? Just curious how you think about those extra-long laterals.

Will Hickey — Co-Chief Executive Officer

Yeah, it’s interesting. I think, that maybe you probably could find some transcripts from two years ago, where I said 2 miles is the optimal length in the Delaware Basin. And I had my own reasons why three wasn’t. It was kind of around how much total fluid our wells make, and they’re trying to flow back 3 miles worth of fluid up 5.5-inch casing is you end up kind of delaying barrels in a way that offsets your D&C savings.

I’d say that is, although conceptually true is probably not perfectly true. I think that the optimal lateral length maybe 2.5 or something like that now. And so really, as you look at how we develop our position, if we have a 4-mile fairway, we’re going to drill two 2-mile wells. If we have a 5-mile fairway, we’re going to drill two 2.5-mile wells. If we have a 6-mile fairway, I think, it will be a debate depending on where we are. Are we going to drill two, 3 milers or three 2 milers, and that’s kind of how close it is.

But I think technically, we have proven our ability to drill 2-mile wells, 3-mile wells in the case of this longest well, 3.5-mile well. And so the drilling team has absolutely proven what they can do. The question is just what generates the most — the highest rate of return, you get $1 per foot savings on one end, but you kind of delay peak production on the other and at that point, it’s just a math problem.

Operator

Thank you. You now have a question from Derrick Whitfield with Texas Capital. Please go ahead.

Derrick Whitfield

Good morning all and congrats on an exceptional year-end.

Will Hickey — Co-Chief Executive Officer

Thank you.

Derrick Whitfield

With my questions, I wanted to lean in really on the last couple of questions that you received. When we think about your consistency of well performance, as you highlighted on Slide 10. I mean, it has been remarkably consistent over the last three years and a clear standout. As you look kind of forward in time, Will, how comfortable are you in continuing to generate that level of productivity? And you commented on 2027 and just in the earlier answer, but it feels like the depth there is good for five years or so.

Will Hickey — Co-Chief Executive Officer

Yeah, I think that’s right. I can say with real confidence that for the next four to five years, I think this is what you should expect to see. And the only reason I’ll say pass that is, I don’t really know exactly what the world looks like, what other benches we’re adding, what the M&A machine gins up [Phonetic] once you get kind of past the end of the decade. But as we build out specific schedules and work with our planning team, this is something that we can continue to maintain for quite some time.

Derrick Whitfield

Great. And then while acknowledging you’re not highlighting surfactant as the driver of base production optimization on today’s call, maybe just could you speak with where you are in assessing its potential positive impact to production?

Will Hickey — Co-Chief Executive Officer

We’ve got some kind of call it mixes of surfactants and kind of acids, etc., on existing producing wells, kind of typically when you get your first ESP failures about the time we do it. I’d say it’s mixed results. We’ve had some that have been wildly successful, adding double, tripling the existing production rate, some that you’ve seen kind of a muted response.

I’d say I’m going to lump surfactants whether it’s kind of bringing back what used to be common — or normal surfactant on the frac side that we all pumped in kind of 2017, 2018 time frame, with kind of new technology today, whether you’re pumping surfactants on the production side, I’d say the new kind of also bringing back lightweight proppant. You think it wasn’t five, 10 years ago, people were pumping kind of man-made lightweight proppants and now with pet coke and other tests going on, there’s a big lightweight proppant push. And I even throw enhanced oil recovery in that bucket.

I think there are — there is more focus on how do we increase recoveries and productivity than there has ever been. And although I’m not willing to pick the winner, I can say with confidence that there will be big wins that I think you’ll see quickly adopted across the industry. And for companies like Permian Resources who have great assets in great basins, it will be a big tailwind. But I’m very confident that there will be — we will solve this in a way that if you think the last three or four years, it was a huge effort of cutting cost-out of the system. I think I wouldn’t be surprised if the next three or four years is an equally effort on adding barrels and adding barrels can make a much bigger difference in cutting costs in the long term.

Derrick Whitfield

Terrific. Great update, great execution.

Will Hickey — Co-Chief Executive Officer

Thanks.

Operator

We now have a question from Neil Mehta with Goldman Sachs. Neil, please go ahead.

Neil Mehta

Yeah, good morning, Will, Guy, James. Question really on the gas macro in the Permian specifically. And as I look at the Slide 6 where you guys talk about how you guys have been managing through your gas marketing portfolio, you’ve mitigated a lot of that risk in terms of near-term local prices. So I guess there’s two questions. One is, what’s your perspective on how Waha is going to evolve over the next couple of years? And two, how are you managing through this period of commodity softness until we get to the other side.

Will Hickey — Co-Chief Executive Officer

Yeah, sure. I mean I think — I think this year, as kind of forward curves indicate and broader consensus would as well, I think there’s definitely going to be potential for challenges kind of over the course of 2026 and it depends how the kind of quote-unquote winter finishes up and what weather interruptions, planned and unplanned, look like kind of through the course of the year, but I do think there’ll be certainly a bumpy road and could be some challenges on the way.

I think we’re confident as you get into 2027 and beyond that without a change — unexpected step-change in Permian gas growth, I think, we could be kind of close to getting there. We actually have the right pipeline takeaway capacity as a basin to mitigate some of the volatility or even potentially all of the volatility that we’ve seen at Waha the last couple of years.

I think with regards to PR, we’re pretty well insulated from Waha volatility kind of this year and going forward. As we talked a lot about, like we have made a tremendous effort to get better in the gas marketing department. And we feel like we’ve really — we’ve kind of pretty much gotten there. As you can see on our Slide 6, 90% of our gas this year will price either it’s kind of hedged at attractive Waha prices or will price at non-Waha destinations. So I think — and kind of same with 2027.

So I think for us, we think this year will be a little challenged kind of more broadly, next year should get better, but PR is in a fortunate position today after a lot of hard work that we’re pretty insulated from that from all the work that we’ve done.

Neil Mehta

Yeah. No, that’s very clear. The follow-up is on Slide 12. So I really like this free cash flow per share framework. I think it makes a lot of sense and agree that it’s a good predictor of long-term value creation. Maybe the biggest risk with taking a near-term free cash flow per share framework is the risk of underinvestment, right? So there’s some — how do you manage the business on this free cash flow framework — per share framework over the long term? And what are the pitfalls of using this framework because there — it could be a double-edged sword if you don’t execute it, right?

James Walter — Co-Chief Executive Officer

Yeah. When we talk about free cash flow per share being what we’re focused on, that’s over the very long-term. I think kind of not looking at single discrete years, certainly not looking at single discrete quarters. Like our goal is to be able to do what we’ve done on Slide 12 for the next five years, the next 10 years, the next 20 years. And you can’t — you can’t under-invest in the business and generate that kind of free cash flow per share growth over the long term.

So I think like I got at the beginning of the call, there’s different ways to focus on free cash flow per share. I think where our business is today, that’s certainly more numerator-focused than denominator focused, just kind of the opportunity set we have organically to reinvest in the business and grow and inorganically through our acquisition effort that’s been really successful.

So I think for us, the right way to — right way for us to do it is to look out over the long-term, like I said, five, 10, 20 years. And I think the right way for you guys to do it, is to look over the kind of longer-term periods as well and not focus overly on kind of this year or next year or this quarter or that quarter. And look at the arc of free cash flow per share growth over the long term.

Neil Mehta

Yeah, that makes a lot of sense. Thanks, team.

Operator

We have a question from John Abbott with Wolfe Research. Go-ahead, John

John Abbott

Hey, good morning, and thank you for taking our questions. The question is really on growth. I mean, you’re sort of still in this sort of yellow light scenario, to use one of the phrases from one of your peers. We could see a more constructive environment in the second half of the year and maybe into 2027. As you kind of sort of look at your crystal ball, what is your likelihood that you could grow — start to grow in 2027? When would you make that decision? And just given inventory in-hand, given ground game, can you remind us on the extent that you’re willing to grow on a multiyear basis?

James Walter — Co-Chief Executive Officer

Yeah. I mean, I think kind of — just like you said, like we are kind of flat over the course of the year from Q1 to Q4 in this environment. But I do think it’s worth pointing out that kind of our production growth is 5% higher in 2026 than 2025. And for us, that probably is a yellow light. That’s not the same way everybody uses it. But I think as we look into the future, it doesn’t take much for a business of our size with our nimble operating team, our kind of lean culture to return to a more growthy scenario. I do think we want to be confident in the macro and don’t want to get out ahead of that.

So I think for us, we’ll be looking for real confidence that there’s better supply-demand balance that shapes up well to knead our barrels over the coming years. And then I think growth for us, it just depends on the macro-environment, what the oil price is and what the service cost environment is. I think historically, we’ve grown closer to 10% per year. That feels — that starts to feel higher, but I think something in the kind of mid-to-high single-digits in an attractive reinvestment and capital deployment environment is certainly something we can get excited about and something we’ve got the inventory base to go prosecute.

John Abbott

And then for the follow-up question, I guess, it still sort of relates to the macro. You’re about 50% hedged for oil this year. How are you thinking about hedges as you sort of think to 2027? How are you approaching that if we have a more positive oil environment? How are you thinking about hedges?

Guy Oliphint — Executive Vice President and Chief Financial Officer

Yeah, John, this is Guy. We’re a little bit less hedged than that for ’26. But our targets, as we’ve talked about consistently are 30%, 20%, 10% year, one, two and three out. I don’t know that the macro weighs in too much into kind of how we hedge. We think those targets make sense and hedging still makes sense despite our strong balance sheet because it’s more capital that we have to deploy in the downturn. If we just think about taking those hedge proceeds when there’s $50 oil, there’s likely buybacks to do, acquisitions to make, those sorts of things. And really, where we try to be flexible on the hedging targets is just lean in when we have these kind of periods of volatility.

What we’ve seen over the last year is those are pretty short. And so we kind of — we hedge into those opportunistically, but we’re also not going to programmatically hit our targets at lower oil prices than we think are mid-cycle just to force it. But we’ve done a good job of getting to those targets despite all that. I feel good about it. Feel like it fits into how we think about capital allocation, particularly in a downturn.

John Abbott

Appreciate it, Guy. Thank you very much.

Operator

Thank you. The next question comes from Phillip Jungwirth with BMO. Go ahead.

Phillip Jungwirth

Thanks. Good morning. You mentioned earlier just some of the historical consolidators in the Permian now looking to divest assets, and we saw news reports of one such deal in the last week. And just given how much you’ve grown the Company over the last couple of years, I’m wondering if there’s an upper limit on transaction size and just remind us of balance sheet parameters when you consider larger-sized deals?

James Walter — Co-Chief Executive Officer

Yeah. I mean, I think for us, we’re in a really fortunate position of ample liquidity, low leverage and hopefully on the cusp of achieving investment-grade status. I’d say, for us, I think, the limiter is not going to be access to capital. It’s going to be kind of our comfort with leverage.

I think we certainly have the capacity to do $1 billion, $2 billion or even $3 billion of deals with — over the next year or two, kind of within our leverage comfort zones at $60 or $65 oil. I think as you spend more dollars, I think, you do need to get more picky on making sure the transactions are the right ones.

So I do think — we believe we have the horsepower to do whatever is coming down the horizon, but we are going to be thoughtful. We’ve said a million times on these calls. We’re not going to lever up the business or risk the business to pursue kind of near-term free cash flow accretion, for example, like to kind of go back to Neil’s question.

So I think for us, we certainly feel like we’ve got the right balance sheet and the right dry powder to kind of pursue the deals that we see coming. But are conscious that we aren’t going to risk the business, and we’re not going to overextend ourselves.

Phillip Jungwirth

Okay. Great. And then you guided to a $0.25 to $0.75 premium to Waha in ’26. Just based on the FT and the marketing agreements, when you look at the ’27 strip, is there any good framework for how to think about that premium? Or maybe it’s less about a premium to Waha and more discount to Henry Hub? Just wondering how you see that further step-up next year with Waha tightening, which is another nice step-up in cash-flow for you guys.

Guy Oliphint — Executive Vice President and Chief Financial Officer

Yeah, this is Guy. I mean, if you look at that graph, you’ll see that the significant majority, 90% plus of our exposure in 2027 is HSC or DFW. So really, we’ll be talking about pricing relative to those benchmarks, which if you want to, you can convert to you relative to hub. So I think next year will be not guiding or not thinking about gas on Waha basis and thinking about it on a Gulf Coast, Texas [Phonetic] basis.

Phillip Jungwirth

Thanks.

Operator

Your next question comes from Josh Silverstein with UBS Financial. Go ahead, Josh.

Joshua Silverstein

Hey, good morning guys. Maybe just along the same line. With the additional FT capacity coming to the portfolio next year, does it change the development strategy at all? Do you drill in areas that have similar kind of oil flow rates, but with greater gas mix to it? I’m curious if you change at all just given that step-up in capacity.

Will Hickey — Co-Chief Executive Officer

No, it won’t change. I think we’ll benefit from the tailwinds of a lot better gas price on the kind of, call it, $700 million of residue gas that we sell today, but we won’t allocate capital differently because of that. It’s still — oil still drives the day kind of based on our assets.

Joshua Silverstein

Got you. And then also on the value-creation front, can you talk a bit about what the royalty opportunity is for PR? You guys are now over 100,000 net acres. What’s the royalty percent of your total production? And any thoughts on whether you consider putting this into another vehicle?

James Walter — Co-Chief Executive Officer

Yeah. I mean, I think we’ve stayed away from giving any explicit stats about our royalty business today, and I think that probably still makes sense with where it stands in the maturity of that asset or that business today. We certainly thought about it. I think we’ve got an awesome royalty business, but that awesome royalty business fits really, really well within our upstream business. It’s like our royalty business is well over 90% Permian Resources operated. And I think allocating capital to that — to those higher NRI and kind of royalty weighted assets has been a really important part of our capital efficiency story the last few years.

So I think we love having it in the business. That said, I think we’re always looking for ways to create incremental value for shareholders. And if we were convinced that, that business could create more value for shareholders as a standalone or kind of subsidiary type business. That’s certainly something we have been thinking about, and we’ll continue to think about. We just kind of haven’t seen or had the right level of conviction around that kind of value creation story today. But definitely something that’s on our radar, something we’re continuing to think through and kind of we’ll keep evaluating as the kind of months, quarters and years come.

Joshua Silverstein

Thanks guys.

Operator

We now have a question from Marion Marney [Phonetic] with ROTH. Marion, Please go ahead.

Marion Marney

Hey, guys. Wanted to see if you could talk a little bit about sort of cadence on the year in terms of capital or production. Historically, you guys have been a little bit more front-half weighted on capex. Is that something we’re going to see again here in 2026? And do you see kind of production?

Obviously, if you look at your forecast here, oil is roughly flat with 4Q. Was there any downtime at all in 1Q on the storms and then a rebound in the second quarter? Just curious any moving parts along any of those lines.

Will Hickey — Co-Chief Executive Officer

Okay. I’ll hit it all. Production should be flat throughout the year. We — I got to give a shout out to the team in the field and in the office that they worked their absolute tail off to keep the overwhelming majority of our production online during the storm. And I mean crazy amounts of work. It really is impressive what they do, and how bought in they are to what we’re trying to do. So production flat, you will not see a Q1 dip due to the storm.

The last question was capex, I believe. I mean, it’s flat throughout the year. It’s not — there’s nothing dramatic. You may see some kind of fluctuations between Q1 and Q2 and Q2 and Q3, but first-half, second-half, it’s all — it’s relatively equally weighted.

Marion Marney

All right. Appreciate that color here. And I was hoping you guys could talk about the non-D&C spend, if I heard you right. I think you guys said there was around $400 million this year. It seemed like maybe a bit higher percentage than years past. Can you maybe kind of talk about what the focus is there, and what you plan to achieve with that.

Will Hickey — Co-Chief Executive Officer

I mean, I’d say it’s short, we haven’t quite seen the same amount of deflation on the non-D&C spend as we’ve seen in other parts of the business. Like it’s a lot of tanks and vessels and steel compression, things like that, which have been less deflationary would be one part of it.

James Walter — Co-Chief Executive Officer

Yeah, I think the other part is we haven’t seen — the efficiency gains we’ve seen on the D&C side have been pretty extraordinary. And our kind of teams responsible for the other capex components, have done a really good job. But as Will said, that’s been more kind of trying to stem the tide of kind of tariff-driven inflation. And so I think kind of over-time, we’re still confident as the business matures, we should be able to reduce our spending on infrastructure and other capex. But this year, I think it makes sense that you haven’t seen the same reduction for the reasons Will outlined.

Marion Marney

Okay. No, that makes sense for sure. And then just on cash taxes, basically, hardly anything this year in terms of what you said. What’s the outlook? Does that start to pick-up in ’27, or is it more of a ’28 thing? Just how are you kind of thinking about that high level?

Guy Oliphint — Executive Vice President and Chief Financial Officer

Yeah, this is Guy. Our guidance is kind of consistent with what we’ve discussed before. We thought ’26 would be low. We thought ’27 would be low based on strip, and that’s all played out. So based on where we are today, we don’t see ourselves being a full cash taxpayer until ’28 or beyond.

Marion Marney

Okay. Thank you.

Operator

Your next question comes from Noah Hungness with Bank of America. Noah, please go ahead.

Noah Hungness

Good morning. I wanted to start off here on the balance sheet. You guys had a — you guys increased your accounts receivable by $320 million quarter-over-quarter. Could you just talk about what drove that? And if you would expect that to unwind through ’26?

Will Hickey — Co-Chief Executive Officer

Yeah. No. On that, we’ve seen kind of AR and AP grow. So working capital is pretty constant even though those gross balances are the same. And really, this is just as our business scaled up kind of correlated with that. So you kind of see there wasn’t really a change in total working capital or a draw on working capital, just those balances increasing as the size of the business grows.

Noah Hungness

That’s helpful. And then the other question here is on your average lateral length. You guys have continued to increase it. I hear this year, you’re going to be at 11,000 feet for your average lateral length. And do you think there is further upside where you could get to kind of that 2.5 miles that you all — that you just talked about? And if so, what do you think that does for your D&C per-foot costs?

Will Hickey — Co-Chief Executive Officer

I’d say the existing position, like maybe on the margin, there’s a few places that we — now that we’re comfortable going longer can. But for the most part, like we’ve done all the work, we’ve done all the trades, and we’ve set it up for how we’re going to drill it. And so kind of if you look at it just quick glance, you can see like most of the units are set-up pretty well for, oh, that makes sense, they’ll drill 2 miles, or they’ll drill 2.5 or in some cases, drill 3.

I think where you could see it change over-time is as we are buying new assets, coring up new assets, I think the land team has been given the kind of ideal lateral length is probably closer to 2.5 than it was to 2. And so they will do the work accordingly to try to kind of extend laterals further.

If you added an extra, call it, 2,500 feet of lateral length, I don’t have the exact number what that would reduce on D&C per foot. It will be in the kind of — it will only help. It will be in the kind of double — probably low double digits as far as dollar per-foot reduction, something like that, $20 a foot, $25 a foot would be my gas offhand.

Noah Hungness

Okay. Yeah, no, that’s really helpful. Makes sense.

Operator

[Operator Instructions] [Operator Instructions] Your next question comes from Paul Diamond with Citi. Paul, please go ahead.

Paul Diamond

Good morning, all. Thanks for taking the call. Just a quick one on reserve replacement. You have done well replacing and drilling locations over the last few years, but at least you’ve seen a geographic focus up in kind of in the Northern Delaware. Should we expect the same? Is that the strategy to try and replace more up there, or does that just happen to be where recent deals have been?

James Walter — Co-Chief Executive Officer

Yeah. I think kind of 2025 is certainly more New Mexico heavy in terms of inventory acquisitions. I think that’s going to be largely just like just opportunity set driven. I think we love our Texas asset. We did a pretty inventory-heavy acquisition in Texas in 2024 with that Barilla Draw transaction. And that was a heck of a deal. We’re really excited about that at the time and probably even more excited about that today.

So I think it’s more opportunity. I do think there’s probably just generally more inventory available and likely to come for — in New Mexico than in Texas over the next five years. So I’d say more likely to do deals up there than in Texas. But I mean, we’re kind of agnostic. We’d love to do more in Texas if the right opportunity came along. It’s just going to depend on what’s out there, what’s for sale and what we can get at a price that we think creates value for shareholders.

Paul Diamond

Got it. Understood. And just one quick follow up on your — as you guys approach investment-grade or investment grade ratings across all three agencies, I guess, how do you think about any potential shift in your financial strategy on the other side? Does it move the needle at all, or is it just business as usual?

Will Hickey — Co-Chief Executive Officer

I mean, I think why are we focused on investment grade? It fits with our strategy. We want to reduce our cost of capital. We want to have long-term capital availability. And then I think from a timing perspective, where we’ve been more insistent is just the fact that we’ve been at investment grade credit ratings for a long time now.

Our financial policies have conformed with investment grade financial policies. And we’ve kind of built the business quickly, but always consistent with our financial policies. And so we do think it has clear benefits going forward, and we do think we meet the criteria today.

Paul Diamond

Understood. Appreciate the time. I’ll leave it there.

Operator

Thank you. There are no further questions. So I will turn the call over to James Walter for closing remarks. Please continue.

James Walter — Co-Chief Executive Officer

Thank you. Having gone off to a great start for 2026, our primary goal remains the same: to maximize shareholder value over the long term by growing free cash flow per share. We expect 2026 and the years to come to look a lot like the past few years. And to do that, we plan to continue to build on our track-record of delivering consistent results with the lowest-cost structure in the Delaware Basin. Thank you to everyone for joining the call today and following the Permian Resources story.

Operator

[Operator Closing Remarks]