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DATE

Thursday, Feb. 26, 2026 at 10:00 a.m. ET

CALL PARTICIPANTS

  • Co-CEO — William M. Hickey
  • Co-CEO — James H. Walter
  • Chief Financial Officer — Guy M. Oliphint

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TAKEAWAYS

  • Q4 Oil Production -- 188,600 barrels per day, contributing to total production of 401,500 BOE per day, exceeding internal expectations and original 2025 guidance by 5%.
  • D&C Cost per Foot -- $700 in Q4, with 2026 guidance of $675 per foot, roughly 20% lower than 2024 levels, reflecting process improvements and increased drilling efficiency.
  • Cash Costs -- Q4 LOE at $5.26 per BOE, cash G&A at $0.80 per BOE, and GP&T at $1.18 per BOE, all supporting improved operating margins.
  • Adjusted Operating Cash Flow -- $884,000,000 in Q4 fueled by operational efficiency and production outperformance.
  • Adjusted Free Cash Flow -- $403,000,000 in Q4, with annual free cash flow per share up 72% from 2023 and showing a 30% CAGR since that year.
  • Cash CapEx -- $481,000,000 for Q4 and $1,970,000,000 for 2025, with 2026 CapEx guidance at $1,850,000,000—$120,000,000 lower year over year, including $400,000,000 for non-D&C spend.
  • Base Dividend Increase -- Quarterly base dividend raised to $0.16 per share, marking a 7% increase and extending a 40% CAGR in the base dividend since 2022.
  • Net Debt Reduction -- Debt reduced by over $600,000,000 in 2025, supporting liquidity and strengthening the balance sheet.
  • Acquisitions -- Closed approximately $1,100,000,000 in acquisitions during 2025, adding about 250 locations and 13,000 BOE per day of production, underpinned by 700 transactions including major deals with Apache and others.
  • Inventory Life -- For the third straight year, more inventory gained than drilled, further enhanced by 200 additional locations from organic expansion.
  • Gas Marketing Exposure -- 400,000,000 cubic feet per day will be sold out of basin in 2026, reducing Waha exposure to 10% of total gas volumes, with expectations of a $0.50 premium to Waha (versus prior $0.40 discount).
  • 2026 Guidance -- Production targeted at 415,000 BOE per day (oil: 189,000 bbl/d), representing 5% growth year over year, with a development plan mirroring 2025’s well mix and zone allocation.
  • Well Productivity -- 2026 productivity expected to be comparable or slightly above 2025/2024 levels, as stated by management.
  • Operational Cadence -- Both CapEx and production are forecasted to remain flat throughout 2026, with no Q1 dip attributed to storms and field activity balanced across the year.
  • Hedging Policy -- Management targets 30%, 20%, and 10% hedged volumes for years one, two, and three out, maintaining hedging for downside protection but remaining opportunistic during volatility.

SUMMARY

Permian Resources Corporation (PR +1.47%) delivered Q4 2025 production and free cash flow metrics that surpassed prior guidance, driven by disciplined capital allocation, reduced operating costs, and aggressive portfolio optimization. Strategic acquisitions, efficient cost structure, and further improvement in gas marketing drove enhanced returns and reduced exposure to regional gas price volatility, setting the stage for increased shareholder distributions and continued investment in core Delaware Basin assets. Management reiterated confidence in inventory depth, long-term productivity visibility, and adaptability to market conditions, while providing clarity on capital spending and hedging discipline supporting a multi-year growth outlook.

  • Management stated “production in 2026 that is approximately 5% higher than 2025 for CapEx that is $120,000,000 lower,” underscoring improved capital efficiency.
  • “For the third consecutive year, Permian Resources Corporation acquired more inventory than we drilled during the year,” maintaining long-term development visibility.
  • “90% of our gas this year will price either hedged at attractive Waha prices or at non-Waha destinations,” shielding cash flows from regional volatility.
  • Total debt reduction surpassed $600,000,000 in 2025, strengthening credit metrics and supporting a prospective investment-grade rating, which management described as aligned with their strategic goals.
  • Non-D&C CapEx is guided at $400,000,000 for 2026, with leadership noting reduced efficiency gains in this category compared to drilling-related activities.
  • Management anticipates no material cash tax payments until at least 2028, reflecting favorable carryforwards or timing effects.
  • The company “expect 2026 and the years to come to look a lot like the past few years,” emphasizing operational consistency and ongoing focus on free cash flow per share growth.

INDUSTRY GLOSSARY

  • D&C: Drilling and completion – the combined process of drilling wells and installing necessary completion equipment for production.
  • LOE: Lease operating expense – ongoing costs to operate and maintain oil and gas properties.
  • GP&T: Gathering, processing, and transportation costs – expenses for moving product from wellhead to market.
  • BOE: Barrels of oil equivalent – a standard measure combining oil and gas volumes for reporting purposes.
  • BHA: Bottomhole assembly – the lower portion of a drilling string, critical for drilling efficiency.
  • Simul-frac: Simultaneous hydraulic fracturing – a technique to improve completion speed by fracturing multiple wells at once.
  • Waha: Refers to the Waha Hub—major natural gas pricing point in West Texas.
  • AHNRI: Average horizontal net revenue interest – an ownership metric per well for horizontal shale drilling.
  • ESP: Electric submersible pump – artificial lift technology used to boost well production.
  • FEP: Front-end processing or pipeline capacity; in this context, refers to enhanced pipeline capacity for gas egress to markets.

Full Conference Call Transcript

William M. Hickey: 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. We are proud to lay out a 2026 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 188,600 barrels of oil per day and total production of 401,500 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 $481,000,000 of cash CapEx for the quarter and $1,970,000,000 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 $884,000,000 and adjusted free cash flow of $403,000,000. Lastly, I want to highlight we are increasing our 2026 quarterly base dividend to $0.16 per share, a 7% increase.

Since inception in 2022, Permian Resources Corporation 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 four and five, I want to highlight how strong 2025 was for Permian Resources Corporation. 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 continues 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 2025 guidance, with more than half 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 costs. 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. 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 $600,000,000, enhancing netbacks through marketing optimization, and holding nominal G&A flat despite a larger production base.

All of this directly benefits our 2026 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 six highlights the details of the meaningful progress we have made improving our gas realization by reducing Waha exposure. We laid the groundwork in 2024 with key hires across our midstream and marketing department, and we continued building that capability through 2025.

As a result of the agreements we have executed, we expect to sell 400,000,000 cubic feet per day out of the basin in 2026, increasing to roughly 700,000,000 cubic feet per day in 2027 and beyond. Combined with our existing hedge position, this reduces Waha exposure to approximately 10% of total gas volumes in 2026 and improves unhedged gas realizations. Specifically, in 2025, we expected our gas realizations to be at roughly a $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 will turn it over to James to walk through our BD efforts and our 2026 guidance.

James H. Walter: Thanks, Will. Turning to slide seven, we wanted to highlight the continued success of our acquisition strategy. During Q4, we closed on approximately 140 transactions totaling $240,000,000. 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. Our confidence in continuing to execute on the strategy going forward is as high as ever. We completed approximately $1,100,000,000 of acquisitions during the year, adding about 250 locations and 13,000 BOE per 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 game that totaled over 675 smaller transactions. For the third consecutive year, Permian Resources Corporation 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 Permian Resources Corporation acquired through the year, we 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 twelve to twenty-four months, we are confident in our ability to continue to find attractive deals, drive value for investors, and make our business better, just like we have the last ten 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 $1,850,000,000 of CapEx for the year, approximately $400,000,000 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 $120,000,000 lower. Our development program and well mix will be largely the same as last year. We will continue to be focused on our high-returning Delaware Basin asset, 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, AHNRI, 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 breakevens, which we can go through in more detail on slide 10. As we have been saying for a while now, we are drilling the same wells in the same areas this year as we have the past few years. As a result, we expect 2026 productivity to be in line to slightly better than 2024–2025, which are basically on top of one another. And we continue to see meaningful improvements in our cost structure, with our anticipated 2026 cost of $675 per foot approximately 20% cheaper than we were in 2024.

The combination of Permian Resources Corporation’s consistent well productivity and lower operating costs allows us to continue to improve our capital efficiency and deliver a 2026 plan that has 20% higher oil volumes on 10% less CapEx when compared to 2024. Turning to slide 11 and going back to 2023 to highlight the continued execution that has helped drive the outsized investor returns. Our sole focus today is on increasing free cash flow per share, creating long-term value for investors. From 2024 to 2026, we have increased oil production by 30,000 barrels of oil per day while reducing our CapEx budget by $250,000,000.

Free cash flow per share has grown from $1.13 in 2023 when oil was at $78 to almost $2.00 per share this past year with oil averaging $65 per barrel, representing a CAGR of approximately 30%. Permian Resources Corporation’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 have achieved over the past few years. Our team’s efforts led to free cash flow per 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.

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 rerating of our business. 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 rerating of our multiple.

James H. Walter: Thank you for tuning in today, and I will 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 the star, then the number one, on your telephone keypad. If you would like to withdraw your question, please press the pound key. Your first question comes from Kevin Moreland MacCurdy with Pickering Energy Partners. Please go ahead.

Kevin Moreland MacCurdy: Hey, great. Thank you for taking my question. Maybe a strategy question to start. You have 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 are doing right that others are missing, or is this just kind of an outcome of inventory quality?

James H. Walter: Yeah. I mean, I think there are 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 is probably a different business model than we have pursued, as you outlined, but I do not think there is—

William M. Hickey: I mean, that makes it wrong. I think it reflects, yeah, like you said, I think an opportunity set and inventory quality and really just the maturity of our business. Like, think kind of a lot of business—

Kevin Moreland MacCurdy: —businesses that are kind of shifting to a reduce-the-denominator buyback-share strategy. I think those are typically more mature businesses and more mature basins. And I would say for us, we are fortunate. I think we are in the most exciting oil basin in North America that has a ton of running room. So you have seen us do more free cash flow per share growth in terms of organic growth and growth through acquisitions. And that has been a really good recipe for us. And I think we are really fortunate that the opportunity set for the next few years feels as good or better than it has been the last couple. 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 are thinking about the various uses of cash this year?

James H. Walter: Yeah. I think we had a great slide in our deck, slide 16. And I think really for sure, we have got kind of free cash flow coming in. And for us, our plan is to use every tool we have got in the toolkit as the opportunity persists. I think capital allocation is something we really pride ourselves on. I think we have done a great job of that the past decade. And, look, we are going to allocate capital to the opportunities in front of us that we think will drive the greatest return over the long term.

Obviously, base dividend is first and foremost, and we are proud of our track record of continuing to grow that dividend year in and year out. And then beyond that, it is going to really depend on the opportunity set. I think if we have opportunities for really attractive, accretive acquisitions, we will pursue those to the best of our ability. And if we do not, I think we are 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, when dislocations exist, we are excited to buy back shares. Obviously, we leaned in heavily for a week or two in April and have not had a lot of opportunities there since then. But for us, I think capital allocation really is all of the above, and we do not see any need to limit or restrict ourselves going forward.

Kevin Moreland MacCurdy: Appreciate that, and congratulations on the results.

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

Neal Dingmann: Good morning, guys. Nice quarter. My question is maybe sticking with this a little bit is on the ground game specifically. Just curious, though, how active do you all believe you can continue to be on ground game and maybe just M&A in general given, you know, a couple things. One, I mean it is pretty notable your peers out there paying record prices for leases and, you know, even the ABS market continues to heat up. So, you know, it certainly seems to be, you know, a bit of a seller's market out there. So just you seem to have confidence both on ground game and just external growth overall. Would love to hear where that confidence comes from.

James H. Walter: Yeah. Our ground game, the small blocking-and-tackling stuff, has been remarkably consistent for a decade. I think, if anything, as we have gotten the larger position we have today and we have gotten our team in place, I think 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 are doing are less subject to market pricing and fluctuations. You know, think about the ground game and most of the bolt-ons that we have done.

Those are one-off negotiated deals that were sourced through relationships we have in Midland, industry partners, and relationships we have in New Mexico that go back the better part of a decade. So I think we have been fortunate to see that those have been less price sensitive, and we have been able to find a lot of good values. And, look, we are paying, I think, real prices for high-quality assets. That has always been our business model, but we are definitely still seeing opportunities that make a lot of sense and I think are more insulated from market fluctuations.

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

Neal Dingmann: Okay. Well said. And then my second question just on potential for ancillary businesses. Specifically, you know, you have talked in the past. I mean, you have got a fair amount of surface acreage. You know, there is potential for you and some other guys in the basin for power deals. And, you know, I know we have talked about maybe even how actually are you looking at, I do not know, either things like lithium extraction or other byproducts of your produced water.

William M. Hickey: Yeah. I mean, we have 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, we have a few blockier big chunks that I think are in pretty opportunistic spots with respect to power generation to the extent we wanted to pursue it. I am not by any means messaging that this is 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—what that market could look like—and trying to better understand it.

There are absolutely data centers that are coming to West Texas on ranches nearby ours. So I think we will get to see a good case study for the commerciality of what that looks like. But I think for us, it is just a balance. The surface acres are also very key to our day-to-day oil and gas operations. So we have got water wells on them, SWDs on them, recycling pits on them, and we drive them every day. So I think we are just trying to balance what is 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 on the upstream assets.

Neal Dingmann: Great details. Thanks, Will. Yep.

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

John Christopher Freeman: Thanks. Good morning, guys. 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 are going through the budgeting process, is there maybe a reinvestment rate that you all are targeting when setting the budget, and then just also what impact is the geopolitical-driven volatility we have seen in oil this year kind of play into that thought process?

James H. Walter: Yeah. I would say we do not target a specific reinvestment rate. I think there are a lot of things that factor in, and macro is certainly one of them. I think we have said this a lot in the past: we are typically focused on growing production in an environment where we see free cash flow accretion in a twelve- to eighteen-month period. So you need wells that are very quick payouts, high returning. I think you could argue we are in that environment today, but I think for us, we are conscious in the macro environment that we are in.

I think we have 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 even with a widget like we have that checks a lot of our criteria, I think for us, it has just felt prudent as we headed into planning for 2026 to be cautious on growth. You know, I think until we have more certainty in the macro and longer-term oil prices that are stable and higher, I think we have chosen to hold off on that growth. But, yeah, you are right.

We have got the inventory base and we have the widgets, frankly, today that would justify growth, but we are being patient, knowing that time will come.

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

William M. Hickey: I would say most—if you want to use the word exploration, 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 within the 4,000-foot column that is the Delaware Basin. If you think about our development plan in 2024–2025 and what will be our development plan for 2026, it has been very consistent as far as we are developing Bone Spring down through the Wolfcamp XY or top of the Wolfcamp, and that is about it. And if you look at offset operators—and I say recently—we have added some Avalon and kind of deeper Wolfcamp to our development plans.

That is the type of exploration that we are doing. I would say we are very much apprised of what people are doing as far as pushing the play boundaries or even jumping into some more unique conventional pay. But for the most part, given how vast our position is today, and we feel good about the existing inventory quality and duration, I would say it is more of just what do we have on our existing footprint. So to round out that full answer, if you think about what we call the organic additions of inventory on that inventory slide on the deal slide, slide eight, that is what that was.

We have been watching as you move further north away from the state line. I would say we did not 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, added Avalon to the inventory stack. And the same thing with the Wolfcamp D or C, whatever nomenclature you may use.

John Christopher Freeman: Thanks, guys. Well done. Thanks, John.

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

Scott Michael Hanold: Yeah. Thanks. Good morning. Yeah. On consistent well performance is impressive, and it certainly helps drive things forward much, much better than anticipated. I think a big part of that, certainly, hopefully, it does not get overshadowed, is how you guys have really reduced D&C cost quite a bit over the last couple of years. And can you give us a sense of, and agnostic to wholesale service costing, but you can add some commentary there if you would like. But what are some additional levers you guys can pull? Can they continue to move that D&C cost per foot down?

William M. Hickey: 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 riding the completion efficiencies that the whole industry has picked up as we have gone from single well to zipper to simul-frac and leveraging recycled water with it. I think going forward, I think there is more juice to squeeze on the cost side on the drilling side of the business. If I look at where, for us, given where our cost structure is in the Delaware, where we look for someone to go chase is typically Midland Basin operators.

If we are going to be at $675 per foot in the Delaware, then there is a $100-plus per foot delta between our well cost and Midland Basin well cost. And if you look at the biggest delta between the two, it is going to be on the drilling side. If we are going to average, call it, thirteen days spud to rig release on a two-mile well, Midland Basin is going to be five-plus days faster than that, and, call it, a $100,000 to $125,000 a day spread rate. That is another $500,000 to $700,000 a well that we could go get. So that is what we are 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 is an all-of-the-above approach. There are no easy wins or silver bullets, but if I had to pick one, it will be reducing days on the drilling side, which likely means increased ROP in the lateral.

Scott Michael Hanold: Got it. Thanks for that. My follow-up question is on M&A. And can you give us a sense of what you are seeing in the M&A market in terms of ground game and larger stuff right now? But could you—you know, I am really interested in state and federal lease sales. What is your expectation on things that could come up with that? Are you encouraged by what you are seeing that could be put out there and how competitive is that? Is that something that is, when you look at rate of return on ground game stuff, are lease sales—do they present a better opportunity, or are those much more competitive in terms of trying to capture?

James H. Walter: Those are great questions. I think on a deal pipeline in general, it feels really strong. Like I said, to Kevin’s question at the beginning, our ground game feels like it is building momentum. The opportunity set is probably widening, growing, and accelerating, not shrinking. It really feels like that is sustainable for the next handful of years at a minimum. And we are seeing the good kind of $500,000,000 to $1,000,000,000 assets like what we bought with Oxy’s Berea Draw and Apache’s New Mexico exit, and we see a great pipeline to those. I think it is interesting, too. We are starting to hear rumors and see signs of larger packages coming.

Obviously, there has been a ton of consolidation in the Delaware and the Permian more broadly. I think we are starting to be on the front end of seeing some of the larger companies who have been the consolidators have some divestitures that make sense on the backside of that. The thing we have always thought we would see was—you can go back over the history of oil and gas—I think the largest companies consolidate, and a deconsolidation wave comes a few years later. Frankly, we had not seen really any of that since COVID. It does feel like we could be entering a phase of that over the next couple years, which only adds to the opportunity set.

I would say, finally, with regards to your commentary about federal lease sales, I think it is great that the administration in Washington has been pushing those lease sales out. We think that is good for the country. We think that is good for the oil and gas business. I would say with regards to our participation, I think historically we have seen most of the time those lease sales are really competitive. Anybody can get on their computer and bid on them. So I do think more often than not, those tend to be more expensive than most of the acquisitions we have looked at.

And as a result, we probably have not been as competitive in that arena as we have been in others. But we have definitely bought things over the last seven or eight years in New Mexico state, Texas state, and federal lease sales. But that is typically because we have an edge. We have a strategic advantage; we have an information advantage, and that does not apply to all of them. So I think it is certainly something we look at. It is something we have participated in the past, but that has often been pretty competitive.

Scott Michael Hanold: Great. Thank you, Scott. Yes. Thank you.

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

Zach Parham: Question. James, you mentioned this in your prepared remarks, and it is also in the slide deck, but you have a well cume plot comparing the last few years. And 2026 expectations are flattish to slightly up on a lateral-foot-adjusted basis. Can you just talk a little bit about what is driving that expectation for actually slightly better productivity year over year? Is that pretty different than what we are seeing across the industry?

William M. Hickey: I would start with, Zach, we are not that good at predicting. I mean, let us call it flat. I think there is a little bit of visually—if you put them all on top of each other, it is messy. And also, we are not so good that we can dial it in within half a percent. But to answer your general question, I mean, this is what we have been saying about our business since 2023: we have a very consistent development plan where we develop 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 2025 was no different than 2024, and 2026 is no different than 2025. And 2027 will be no different than 2026. So I think that it is 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 have done in spite of dramatically reducing commodity prices. And the only way to do it is that you hold well productivity flat. We cut costs more than oil prices hurt you.

And I think that is what we have done in the past and plan on continuing to do going forward.

Zach Parham: Another thing you mentioned was drilling the longest lateral in company history in 4Q, around 17,000 feet. Is that something you are considering doing more of? Is that something that can help drive costs lower, or I am curious how you think about those extra-long laterals?

William M. Hickey: You know, it is interesting. I think that maybe you probably could find some transcripts from two years ago where I said two miles is the optimal length in the Delaware Basin, and I had my own reasons why three was not. It was kind of around how much total fluid our wells make, and trying to flow back three miles’ worth of fluid up five-and-a-half-inch casing, you end up delaying barrels in a way that offsets your D&C savings. I would say that is, although conceptually true, probably not perfectly true. I think that the optimal lateral length may be two and a half or something like that now.

And so really, as you look at how we develop our position, if we have a four-mile fairway, we are going to drill two-mile wells. If we have a five-mile fairway, we are going to drill two-and-a-half-mile wells. If we have a six-mile fairway, I think it will be a debate depending on where we are: are we going to drill two three-milers or three two-milers? And that is kind of how close it is. But I think, technically, we have proven our ability to drill two-mile wells, three-mile wells, and in the case of this longest well, a three-and-a-half-mile well. And so the drilling team has absolutely proven what they can do.

The question is just what generates the highest rate of return. You get a dollar-per-foot savings on one end, but you kind of delay peak production on the other, and at that point, it is 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. 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 highlight on slide 10, it has been remarkably consistent over the last three years and a clear standout. As you look forward in time, Will, how comfortable are you in continuing to generate that level of productivity? And you commented on 2027 just in the earlier answer, but it feels like the depth there is good for five years or so.

William M. Hickey: Yeah. I think that is 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 will not say past that is I do not really know exactly what the world looks like—what other benches we are adding, what the M&A machine gins up—once you get 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 are not highlighting surfactants, the driver-based production optimization on today’s call, maybe could you speak to where you are in assessing its potential positive impact to production? We have published some—

William M. Hickey: —mixes of surfactants and acids, etc., on existing producing wells, typically when you get your first ESP failures is about the time we do it. I would say it is mixed results. We have had some that have been wildly successful—adding double or tripling the existing production rate—and some where you have seen a muted response. I would lump surfactants—whether it is kind of bringing back what used to be common surfactant on the fracture side that we all pumped in the 2017–2018 time frame with new technology today, your permutations back on the production side.

I would say the new bringing back lightweight proppant—if you think, it was not five, ten years ago people were pumping man-made lightweight proppants, and now with petcoke and other tests going on, there is a big lightweight proppant push. And I even throw enhanced oil recovery in that bucket. I think there is more focus on how do we increase recoveries and productivity than there has ever been. And although I am not willing to pick the winner, I can say with confidence that there will be big wins that I think you will see quickly adopted across the industry.

And for companies like Permian Resources Corporation who have great assets and great basins, it will be a big tailwind. But I am very confident that 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 would not be surprised if the next three or four years is an equal effort on adding barrels. And adding barrels can make a much bigger difference than cutting costs in the long term.

Derrick Whitfield: Terrific. Great update. Great execution.

William M. Hickey: Thanks.

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

Neil Singhvi Mehta: Yeah. Good morning, Will, Guy, James. Question really on the gas macro in the Permian specifically. And as I look at slide six where you talk about how you have been managing through your gas marketing portfolio, you have mitigated a lot of that risk in terms of near-term local prices. So I guess there are two questions. One is what is 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 till we get to the other side?

James H. Walter: Yeah, sure. I think this year, as forward curves indicate and broader consensus would as well, there is definitely going to be potential for challenges over the course of 2026. It depends how the winter finishes up and what weather and interruptions—planned and unplanned—look like through the course of the year. But I do think there will be a bumpy road and there could be some challenges on the way. I think as you get into 2027 and beyond that, without a change and unexpected step change in Permian gas growth, I think we could be 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 have seen at Waha the last couple of years. I think with regards to Permian Resources Corporation, we are pretty well insulated from Waha volatility this year and going forward. As we have talked a lot about, we have made a tremendous effort to get better in the gas marketing department, and we feel like we have pretty much gotten there. As you can see on our slide six, 90% of our gas this year will price either hedged at attractive Waha prices or at non-Waha destinations. So I think the same with 2027.

For us, this year will be a little challenged more broadly. Next year should get better, but Permian Resources Corporation is in a fortunate position today after a lot of hard work that we are pretty insulated from that from all the work that we have done.

Neil Singhvi Mehta: Yeah. No. That is very clear. The follow-up is on slide 12. I really like this free cash flow per share framework. I think it makes a lot of sense and agree that it is 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. So how do you manage the business on this free cash flow per share framework over the long term? And what are the pitfalls of using this framework? Because it could be a double-edged sword if you do not execute it right.

James H. Walter: Yeah. When we talk about free cash flow per share being what we are focused on, that is over the very long term. I think kind of not looking at single discrete years, certainly not looking at single discrete quarters. Our goal is to be able to do what we have done on slide 12 for the next five years, the next ten years, the next twenty years, and you cannot underinvest in the business and generate that kind of free cash flow per share growth over the long term. So I think, like I said at the beginning of the call, there are different ways to focus on free cash flow per share.

I think our business today is certainly more numerator-focused than denominator-focused, given the opportunities that we have organically to reinvest in the business and grow, and inorganically through our acquisition effort that has been really successful. So I think for us, the right way to do it is to look out over the long term—five, ten, twenty years. And I think the right way for you to do it is to look over longer-term periods as well and not focus overly on 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 Singhvi Mehta: That makes a lot of sense. Thanks, team.

Operator: You now have a question from John Holliday Abbott with Wolfe Research. Go ahead, John.

John Holliday Abbott: Hey. Good morning, and thank you for taking our questions. The question is really on growth. I mean, you are sort of in this yellow-light scenario, to use one of the phrases from one of your peers. You know, we could see a more constructive environment in the second half of the year or maybe into 2027. As you look at your crystal ball, what is your likelihood that you could start to grow in 2027, and when would you make that decision? And just, given inventory in hand, given ground game, can you remind us on the extent that you are willing to grow over a multiyear basis?

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

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

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

Guy M. Oliphint: Yeah. John, this is Guy. We are a little bit less hedged than that for 2026. But our targets, as we have talked about consistently, are 30%, 20%, 10%—year one, two, and three out. I do not know that the macro weighs in too much into how we hedge. We think those targets make sense, and hedging still makes sense despite our strong balance sheet because it is more capital that we have to deploy in the downturn. If we just think about taking those hedge proceeds when there is $50 oil, there are 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 periods of volatility. What we have seen in the last year is those are pretty short. And so we hedge into those opportunistically, but we are also not going to programmatically hit our targets at lower oil prices than we think are mid-cycle just to force it. But we have done a good job of getting to those targets despite all that. We feel good about it. We feel like it fits into how we think about capital allocation, particularly in a downturn.

John Holliday Abbott: Appreciate it, Guy. Thank you very much.

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

Phillip J. Jungwirth: 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. Just given how much you have grown the company over the last couple of years, wondering if there is an upper limit on transaction size, and just remind us of balance sheet parameters when you consider larger-sized deals.

James H. Walter: I mean, I think for us, we are in the really fortunate position of ample liquidity, low leverage, and, hopefully, on the cusp of achieving investment-grade status. I would say for us, I think the limiter is not going to be access to capital. It is going to be our comfort with leverage. I think we certainly have the capacity to do $1,000,000,000, $2,000,000,000, or even $3,000,000,000 of deals over the next year or two within our leverage comfort zones at $60 or $65 oil. I think as you spend more dollars, you need to get more picky on making sure that 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—we have said it a million times on these calls—we are not going to lever up the business or risk the business to pursue near-term free cash flow accretion, for example, to go back to Neil’s question. So I think for us, we certainly feel like we have the right balance sheet and the right dry powder to pursue the deals that we see coming. But we are conscious that we are not going to risk the business, and we are not going to overextend ourselves.

Phillip J. Jungwirth: Okay. Great. And then you guided to a $0.25 to $0.75 premium to Waha in 2026. Just based on the FEP and the marketing agreements, when you look at the 2027 strip, is there any good framework for how to think about that premium? Or maybe it is 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 M. Oliphint: Yeah. This is Guy. If you look at that graph, you will see that the significant majority, 90% plus, of our exposure in 2027 is HSC or DFW. So really, we will be talking about pricing relative to those benchmarks, which, if you want to, you can convert to relative to Hub. So I think next year we will be not guiding or not thinking about gas on a Waha basis and thinking about it on a Gulf Coast, TexArk basis.

Phillip J. Jungwirth: Thanks.

Operator: Your next question comes from Josh Silverstein with UBS Financials. Go ahead, Josh.

Josh Silverstein: Hey. Thanks. Good morning, guys. Maybe just along the same line, with the additional FEP 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 am curious if you changed at all just given that step up in capacity.

William M. Hickey: No. It will not change. I think we will benefit from the tailwinds of a lot better gas price on the 700,000,000 of residue gas that we sell today. But we will not allocate capital differently because of that. Oil still drives the day based on our assets.

Josh Silverstein: Gotcha. Then also on the value creation front, can you talk a bit about what the royalty opportunity is for Permian Resources Corporation? You guys are now over 100,000 net acres. What is the royalty percent of your total production, and any thoughts on whether you would consider putting this into another vehicle?

James H. Walter: Yeah. I mean, I think we have stayed away from giving any explicit stats about our royalty business to date. And I think that probably still makes sense with where it stands in the maturity of that asset or that business today. Certainly thought about it. I think we have got an awesome royalty business, but that awesome royalty business fits really, really well within our upstream business. You know, our royalty business is well over 90% Permian Resources Corporation-operated, and I think allocating capital to those higher NRI and 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 are always looking for ways to create incremental value for shareholders. And if we were convinced that business could create more value for shareholders as a stand-alone or subsidiary-type business, that is certainly something we have been thinking about and will continue to think about. We just have not seen or had the right level of conviction around that value-creation story today. But definitely something that is on our radar, something we are continuing to think through and we will keep evaluating as the months, quarters, and years come.

Josh Silverstein: Thanks,

Operator: We now have a question from Leo Paul Mariani with Roth. Leo, please go ahead.

Leo Paul Mariani: Hey. Hey, guys. Wanted to see if you could talk a little about cadence on the year.

Guy M. Oliphint: In terms of capital or production.

William M. Hickey: Historically, you guys have been a little bit more front-half weighted on CapEx. Is that something we are going to see again here in 2026? And do you see production—obviously, if you look at your forecast here, your oil is roughly flat with 4Q. Was there any downtime at all in 1Q on the storms and then a rebound in second quarter? Just curious about any moving parts along any of those lines. Okay. I will hit it all. Production should be flat throughout the year.

I have got to give a shout-out to the team in the field and in the office, but they worked their absolute tails 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 are trying to do. So production flat. You will not see a Q1 dip due to the storm. The last question was CapEx, I believe. It is flat throughout the year. There is nothing dramatic. You may see some fluctuations in Q1 and Q2 and Q2 and Q3, but first half, second half, it is relatively equally weighted.

Leo Paul Mariani: Alright. 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 said there was around $400,000,000 this year. It seemed like maybe a bit higher percentage than years past. Can you maybe talk about what the focus is there and what you plan to achieve with that?

William M. Hickey: I would say it is short. We have not quite seen the same amount of deflation on the non-D&C spend as we have seen in other parts of the business. It is a lot of tanks and vessels and steel, compression, things like that, which have been less deflationary would be one part of it.

James H. Walter: Yeah. I think the other part is we have not seen—the efficiency gains we have seen on the D&C side have been pretty extraordinary, and our teams responsible for the other CapEx components have done a really good job. But as Will said, that has been more trying to stem the tide of tariff-driven inflation. And so I think over time, we are 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 have not seen the same reduction, for the reasons Will outlined.

Leo Paul Mariani: Okay. That makes sense for sure. And then just on cash taxes, basically, hardly anything this year in terms of what you said. What is the outlook? Does that start to pick up in 2027, or is it more of a 2028 thing? Just how are you thinking about that high level?

Guy M. Oliphint: Yeah, this is Guy. Our guidance is kind of consistent with what we have discussed before. We thought 2026 would be low. We thought 2027 would be low based on strip, and that has all played out. So based on where we are today, we do not see ourselves being a full cash taxpayer until 2028 or beyond.

Leo Paul Mariani: Okay. Thank you.

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

Noah B. Hungness: I wanted to start off here on the balance sheet. You guys increased your accounts receivable by $20,000,000 quarter over quarter. Could you just talk about what drove that and if you would expect that to unwind through 2026?

Guy M. Oliphint: Yeah. On that, we have seen AR and AP grow, so working capital pretty constant even though those gross balances are the same. And really, this is just as our business scales up, it is correlated with that. So you see there was not 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 B. Hungness: That is helpful. And the other question here is on your average lateral length. You guys have continued to increase it. Here this year, you are going to be at 11,000 feet for your average lateral length. Do you think there is further upside where you could get to that two and a half miles that you just talked about? And if so, what do you think that does for your D&C per foot costs?

William M. Hickey: I would say the existing position—maybe on the margin there are a few places that we, now that we are comfortable going longer, can. But for the most part, we have done all the work, we have done all the trades, and we have set it up for how we are going to drill it. And if you look at it, just a quick glance, you can see most of the units are set up pretty well for, oh, that makes sense—they will drill two miles, or they will drill two and a half, or in some cases, drill three.

I think where you could see a change over time is as we are buying new assets, coring up new assets. I think the land team has been given that the ideal lateral length is probably closer to two and a half than it was to two. And so they will do the work accordingly to try to extend laterals further. If you added an extra, call it, 2,500 feet of lateral length, I do not have the exact number of what that would reduce on D&C per foot. It will be—it will only help.

It will be in the probably low double digits as far as dollar-per-foot reduction, something like that. $20 a foot, $25 a foot would be my guess offhand.

Noah B. Hungness: Okay. Yeah. That is really helpful. Thanks, guys.

Guy M. Oliphint: Thank you.

Operator: As a reminder, if you wish to ask a question, please press star followed by the one. Your next question comes from Paul Michael Diamond with Citi. Paul, please go ahead.

Paul Michael Diamond: Good morning. Thanks for staying on the call. Just a quick one on reserve replacement. You have done well replacing drilling locations over the last few years, but we have seen the geographic focus up in the Northern Delaware. Should we expect the same? Is that the plan to try and replace more up there, or does that just happen to be where recent deals have been?

James H. Walter: Yeah. I think 2025 is certainly more New Mexico-heavy in terms of inventory acquisitions. I think that is going to be largely opportunity set driven. I think we love our Texas asset. We did a pretty inventory-heavy acquisition in Texas in 2024 with that Berea Draw transaction. That was a heck of a deal. We are really excited about that at the time and probably even more excited about that today. So I think it is more opportunity set driven. I do think there is probably just generally more inventory available and likely to come for sale in New Mexico than in Texas over the next five years.

So I would say more likely to do deals up there than in Texas. But we are kind of agnostic. We would love to do more in Texas if the right deal came along. It is just going to depend on what is out there, what is for sale, and what we can get at a price that we think creates value for shareholders.

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

Guy M. Oliphint: I mean, I think the why are we focused on investment grade fits with our strategy. We want to reduce our cost of capital. We want to have long-term capital availability. And then from a timing perspective, where we have been more insistent is just the fact that we have been at investment-grade credit ratings for a long time now. Our financial policies have conformed to investment-grade financial policies. And we have 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 Michael Diamond: Understood. Appreciate the time. I will leave it there. Thank you.

Operator: There are no further questions, so I will turn the call over to James H. Walter for closing remarks. Please continue.

James H. Walter: Thank you. Having gotten 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 Corporation story.

Operator: Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation. You may now disconnect.