Good morning, 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. Thanks, Gina, 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. 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. We're 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 188.6 thousand barrels of oil per day and total production of 401.5 thousand 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 2022, 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 four and five, 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 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 simulfrac 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 million, 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 6 highlights the details of the meaningful progress we've made improving our gas realizations by reducing Waha exposure. We laid the groundwork in 2024, with key hires across midstream and marketing department. 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. Combine 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. 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 that attract evaluations. The Q4 acquisitions capped off a great 2025 M&A program. 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 game that totaled over 675 smaller transactions. For the 3rd 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 12-24 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, 8/8 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 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, expect 2026 productivity to be in line or slightly better than 2024 and 2025, which are basically on top of one another. 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, resulting in 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. 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. 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. Now we'll turn it back to the operator for Q&A. Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing star, then the number one on your telephone keypad. If you would like to withdraw your question, please press the pound. Your first question comes from Kevin MacCurdy with Pickering Energy Partners. Please go ahead. 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. 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? 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. You can also grow it through the denominator. I think that's probably a different business model than we have pursued, as you outlined. 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, buy back shares strategy, I think those are kind of typically more mature businesses and more mature basins. I'd say for us, you know, we're fortunate. I think we're in the most exciting oil basin in North America that has a ton of running room. 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. 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. Thanks. 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? 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. Look, we're gonna 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. Then beyond that, it's gonna really depend on the opportunity set. I think if we have opportunities for really attractive, accretive acquisitions, we'll pursue those, you know, to the best of our ability. If we don't, you know, I think we're always excited to accrue cash to the balance sheet because we know this is a cyclical business, and I think, you know, paying down debt and saving dollars for the future has been a great return for us in the past. Finally, if dislocations exist, you know, 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. 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. Appreciate that, and congratulations on the results. Your next question comes from Neal Dingmann with William Blair. Please go ahead. 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, you know, do you all believe you can continue to be on ground game and maybe just M&A in general, given, you know, a couple of things? One, I mean, it's pretty notable your peers are out there paying record prices for leases, and, you know, even the ABS market continues to heat up. You know, it certainly seems to be a, you know, a bit of a seller's market out there. Just you seem to have confidence both on ground game and just external growth overall. Would love to hear your where that confidence comes from. 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, 2025 is probably our best year ever from a ground game perspective. 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, you know, the better part of a decade. 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 good values. Look, I mean, we're paying, I think, real prices for high-quality assets. That's, 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, you know, larger percentage of production, higher decline, things like that. 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. Okay, well said. My second question, just on potential for ancillary businesses, specifically, you know, you all talked in the past, I mean, you've got a fair amount of surface acreage. You know, there's potential for you and some other guys in the basin for power deals. You know, 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? 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. 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. 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. I think we'll get to see a good kind of case study for the commerciality of what that looks like. 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. We've got water wells on them, SWDs on them, recycling pits on them, and, you know, we drive them every day. 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 on the upstream assets. Great details. Thanks, Will. Yep. Your next question comes from John Freeman with Raymond James. Go ahead, John. Thanks. Good morning, guys. Morning. Given the continued cost reductions that y'all continue to see, obviously from a return perspective, y'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 y'all are sort of targeting when setting the budget? Just sort of also kind of what impact is sort of the geopolitical kind of driven volatility we've seen in oil, you know, this year kind of play into that thought process? 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. You need wells that are, you know, 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, you know, 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. 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. You know, 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. 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. Great. My, my follow-up, y'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 y'all are looking at that sort of has y'all intrigued right now on sort of newer areas or benches? I'd 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 gonna be just better understanding what we have up hole and down hole, kind of within the 4,000 foot column that is the Delaware Basin. You know, if you think about our development plan in 2024, 2025, and what will be our development plan for 2026, has been very consistent as far as, you know, we're developing Bone Spring down through kind of the Wolfcamp XY or top of the Wolfcamp, and that's about it. 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. For the most part, I think 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? I'd say to round out that full answer, if you think about the, what we called organic additions of inventory on that inventory slide, on the deal slide 8, that's what that was. That was 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. 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. Thanks, guys. Well done. Thanks, John. We now have a question from Scott Hanold with RBC Capital Markets. Please go ahead. Yeah, thanks. Good morning. Yeah, conversation around, you know, consistent well growth is impressive, and it certainly helps drive, like, things forward, you know, much, much better than anticipated. I think, you know, a big part that, you know, certainly, you know, hopefully doesn't get overshadowed is how you guys have really reduced D&C costs, you know, quite a bit over the last couple of years. Can you give us a sense of like, you know, and agnostic, obviously, oil field service costing, but you can serve as some commentary there if you'd like. Like, what are some additional leverage you guys can pull? Can they continue to move that D&C cost per foot down? 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, you know, 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, you know, 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. You know, if we're gonna be at $675 per foot in the Delaware, there's kind of a $100+ per foot delta between our well cost and Midland Basin well cost. If you look at the biggest delta between the two, it's gonna be on the drilling side. You know, if we're gonna average, call it 13 days spud to rig release on a 2-mile well, Midland Basin is gonna be 5+ days faster than that. You know, call it $100,000-$125,000 a day spread rate, like, that's another $5, $6, $7 hundred thousand dollars a well that we could go get. That's what we're focused on. You know, if you look at drilling speed, drilling times, we cut 6% year-over-year. I think last year we cut even more. I think we have a track record of doing it. 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'll be kind of reducing days on the drilling side, which likely means increased ROP in the lateral. Got it. Thanks for that. My follow-up question is on M&A, and can 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? You know, I'm really particularly interested in, you know, state and federal lease sales. What is your expectation on things that could come up? Is that encouraging what you're seeing that could be put out there, and how competitive is that? Is that something that, you know, 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? Those are great questions. I think on a deal pipeline in general feels really strong. Like I said, Kevin's call at the beginning, our ground game feels like it's just building momentum, the opportunity set's 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 continuing to see a good $500 million-$1 billion assets, like what we bought with Oxy's Barilla Draw, Apache's New Mexico exit. See a great pipeline of those. I think it's interesting, too, we're starting to hear rumors and see signs of larger packages coming. Obviously, there's been a ton of consolidation in the Delaware and the Permian, more broadly. I think we're starting to be on the front end of seeing some of the larger companies who've been the consolidators, have some kind of divestitures that make sense on the backside of that. This is what we've always thought we'd see. We've seen kind of, if you go back over the history of oil and gas, you know, I think the largest companies consolidate, then kind of a deconsolidation wave comes a few years later. Frankly, we hadn'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 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 know, 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. You know, we've definitely bought things over the last 7 or 8 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, you know. That doesn't apply to all of them. I think it's certainly something we look at. It's something we've participated in the past, but have, you know, more often than not found to be pretty competitive. Great. Thank you, Scott. Yeah, thank you. Your next question comes from Zach Parham with JP Morgan. Please go ahead. Yeah, question. James, you mentioned this in your prepared remarks, and it's also in the slide deck, but you have a well queue plot comparing the last few years, and 2026 expectations are flattish to 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? As that's pretty different than what we're seeing kind of across the industry. I'd start with, Zach Parham, we're not that good at. I mean, 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%. To answer your general question, I mean, this is what we've been saying about our business since 2023, that, you know, 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. 25 was no different than 24, and 26 is no different than 25, and 27 will be no different than 26. I think that 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. This is a big part of our, you know, 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. I think that's what we've done in the past, and we plan on continuing to do it going forward. 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. You know, it's interesting. I think that you probably could find some transcripts from 2 years ago where I said 2 miles is the optimal length in the Delaware Basin, and, you know, I had my own reasons why 3 wasn't. It was kind of around how much total fluid our wells make, and then trying to flow back 3 miles worth of fluid up 5 and a half 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 may be 2 and a half or something like that now. Really, as you look at how we develop our position, if we have a, you know, 4-mile fairway, we're gonna drill 2 2-mile wells. If we have a 5-mile fairway, we're gonna drill 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 gonna drill 2 3-milers or 3 2-milers, and that's kind of how close it is. I'd say 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. The drilling team has absolutely proven what they can do. The question is just what generates the highest rate of return? You get a $1 per foot savings on one end, but you kinda delay peak production on the other, and at that point, it's just a math problem. Thank you. You now have a question from Derrick Whitfield with Texas Capital. Please go ahead. Good morning, all. Congrats on an exceptional year-end. Thank you. 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, I mean, it has been remarkably consistent over the last 3 years in a clear standout. As you look kind of forward in time, Will, how comfortable are you in continuing to generate that level of productivity? You, you commented on 2027 and just in the earlier answer, but it feels like the depth there is good for 5 years or so. Yeah, I think that's right. I can say with real confidence that, you know, for the next four to five years, I think this is what you should expect to see. you know, the only reason I don't say past that is I don't really know exactly what the world looks like, you know, what other benches we're adding, what the M&A machine gins up once you get kinda past the end of the decade. as, you know, 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. Great. While acknowledging you're not highlighting surfactants, the driver-based production optimization on today's call, maybe just could you speak with where you are in assessing its potential positive impact to production? We've pumped some kind of, call it mixes of surfactants and kind of acids, et cetera, on existing producing wells, kinda 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, you know, adding double, tripling the existing production rate, some that you've seen kind of a muted response. I'd say I'm gonna lump surfactants, whether it's kind of bringing back what used to be common or normal surfactant on the frack side, that we all pumped in kinda 2017, 2018 time frame, with kinda new technology today, whether you're pumping surfactants on the production side. I'd say the new kind of also bringing back lightweight proppant. If you think, you know, it wasn't five, 10 years ago, people were pumping kinda man-made lightweight proppants, and now with petcoke and other tests going on, there's a big lightweight proppant push. I'd even throw, you know, enhanced oil recovery in that bucket. I think there's more focus on how do we increase recoveries and productivity than there has ever been. 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. For companies like Permian Resources, who have great assets and great basins, it'll be a big tailwind. I'm very confident that we will solve this in a way that, you know, 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 a equally effort on adding barrels, you know, adding barrels can make a bit much bigger difference than cutting costs in the long term. Perfect. Great update, great execution. Thanks. You now have a question from Neil Mehta with Goldman Sachs. Neil, please go ahead. Yeah, good morning, Will Hickey, Guy Oliphint, James Walter. Question really on the gas macro in the Permian, specifically. you know, as I look at this, 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. I guess there's 2 questions. One is, what's your perspective on how Waha is gonna evolve over the next couple of years? 2, how are you managing through this period of commodity softness till we get to the other side? Yeah, sure. I mean, I think, you know, I think this year, as kinda forward curves and indicate and broader consensus would as well, I think there's definitely gonna be potential for challenges kinda over the course of 2026. I think it depends how the kinda quote-unquote, "winter" finishes up and what weather and interruptions planned and unplanned look like kinda through the course of the year. I do think there'll be certainly a bumpy road and could be some challenges on the way. I think we're confident that as you get into 2027 and beyond, that, you know, without a change and kind of unexpected step change in Permian gas growth, I think we could be kinda 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 kinda 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 kinda pretty much gotten there. As you can see on our slide six, you know, 90% of our gas this year will price either it's kinda headset at attractive Waha prices or we'll price it non-Waha destinations. You know, I think, and kinda same with 2027. I think for us, we think this year will be a little challenged, kind of more broadly. Next year should get better. PR is in a fortunate position today after a lot of hard work that, you know, we're pretty insulated from that, from all the work that we've done. ... Yeah, no, that's very clear. The, 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's a good predictor of long-term value creation. Maybe the biggest risk with taking in your term, free cash flow per share framework is the risk of underinvestment, right? How do you manage the business on this free cash flow framework, per share framework over the long term? What are the pitfalls of using this framework? You know, it could be a double-edged sword if you don't execute it right. 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 underinvest in the business and generate that kind of free cash flow per share growth over the long term. I think, like we 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 opportunities that we have organically to reinvest in the business and grow, and inorganically through our acquisition effort that's been really successful. I think for us, the right way for us to do it is to look out over the long term, like I said, five, 10, 20 years. 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. Yeah, that makes a lot of sense. Thanks, team. We now have a question from John Abbott with Wolfe Research. Go ahead, John. Good morning, and thank you for taking our questions. The question is really on growth. I mean, you're sort of in this still in this sort of 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, maybe into 2027. As you kind of sort of look at your crystal ball, what is your likelihood that you could grow in 2027? When would you make that decision? Just, you know, just given inventory in hand, given ground game, can you remind us on the extent that you're willing to grow over a multi-year basis? 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. 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. 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. I think for us, we'll be looking for, you know, real confidence that there's better supply-demand balance, that shapes up well to meet our barrels over the coming years. 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, you know, closer to 10% per year. 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. For the follow-up question, I guess this 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? Are you approaching that if we have a more positive oil environment? How are you thinking about hedges? Yeah, John, this is Guy Oliphint. We're a little bit less hedged than that for 2026, but, you know, our targets, as we've talked about consistently, are 30%, 20%, 10%, year one, two, and three out. I don't know. 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 a 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. 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, 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. We've done a good job of getting to those targets, despite all that. Feel good about it. Feel like it fits into how we think about capital allocation, particularly in a downturn. Appreciate it, Guy. Thank you very much. Thank you. The next question comes from Phillip Jungwirth with BMO. Go ahead. 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. Just given how much you've grown the company over the last couple of years, wondering if there's an upper limit on transaction size, and just remind us of balance sheet parameters when you consider larger-sized deals? Yeah, I mean, I think for us, we're in the really fortunate position of, you know, ample liquidity, low leverage, and, you know, hopefully on the cusp of achieving investment-grade status. I'd say, you know, 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. You know, I think we certainly have the capacity to do 1, 2, or even $3 billion of deals over the next year or two, kind of within our leverage comfort zones at $60 or $65 oil. You know, 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. I do think, you know, we believe we have the horsepower to do, you know, whatever is coming down the horizon, but we are going to be thoughtful. We've said it 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, you know, free cash flow accretion, for example, like, to kind of go back to Neil's question. 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. You know, we are conscious that we aren't going to risk the business, and we're not going to overextend ourselves. Okay, great. You guided to a $0.25-$0.75 premium to Waha in 2026. Just based on the FT 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'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. 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. Really, we'll be talking about pricing relative to those benchmarks, which if you want to, you can convert to relative to Hub. I think next year will be not guiding or not thinking about gas on a Waha basis and thinking about it on a Gulf Coast, TETCO basis. Thanks. Your next question comes from Josh Silverstein with UBS. Go ahead, Josh. Hey, thanks. Good morning, guys. Maybe just along the same line. With the additional FC 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. 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. Oil still drives the day, kind of, based on our assets. Got you. Also on the value creation front, can you talk a bit about, you know, what the royalty opportunity is for PR? You guys are now over 100,000 net acres. You know, what's the royalty% of your total production, and any thoughts on whether you consider putting this into another vehicle? Yeah, I mean, I think we've 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. We certainly thought about it. You know, I think we've got an awesome royalty business, but that awesome royalty business fits really, really well within our upstream business. You know, it's like our royalty business is well over 90% Permian Resources operated. I think allocating capital 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. 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 will 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 to date. 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. Thanks, guys. We now have a question from Leo Mariani with Roth MKM. Leo, please go ahead. Hey, guys, wanted to see if you could talk a little about sort of cadence on the year, in terms of, you know, capital or production. Historically, you guys have been a little bit more front half weighted on CapEx. Is Is that something we're going to see again here in 2026? Do you see kind of, you know, production? Obviously, if you look at your forecast here, your oil's roughly flat with 4Q. Was there any downtime at all? 1Q on the storms, and then a rebound in second quarter. Just curious, any moving parts along any of those lines? I'll hit it all. Production should be flat throughout the year. I got to give a shout-out to the team in the field and in the office, but 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. I, it really is impressive what they do and how bought in they are to what we're trying to do. 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 relatively equally weighted. All right. Appreciate that caller here. 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. Seemed like maybe a bit higher percentage than years past. Can you maybe kind of talk about, what the, you know, what the focus is there and what you plan to achieve with that? 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. Yeah, I think the other part is just we haven't seen. Like, the efficiency gains we've seen on the D&C side have been pretty extraordinary, and, you know, our kind of teams responsible for the other CapEx components have done a really good job. As Will said, that's been more kinda trying to stem the tide of kind of tariff-driven inflation. 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. You know, this year, I think it makes sense that you haven't seen the same reduction for the reasons Will outlined. Okay. No, that makes sense, for sure. 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 2027, or is it more of a 2028 thing? Just how are you kind of thinking about that high level? Yeah, this is Guy. Our guidance is kind of consistent with what we've discussed before. We thought 2026 would be low. We thought 2027 would be low based on strip, and that's all played out. Based on where we are today, we don't see ourselves being a full cash taxpayer until 2028 or beyond. Okay, thank you. Your next question comes from Noah Hungness with Bank of America Securities. Noah, please go ahead. 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 2026? Yeah. No, on that, we've seen kinda AR and AP grow, so working capital is pretty constant, even though those gross balances are the same. Really, this is just, as our business scales up, kind of correlated with that. You kinda 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. That's helpful. The other question here is on your average lateral length. You guys have continued to increase it. Here, this year, you're gonna be at 11,000 feet for your average lateral length. Do you think there's further upside where you could get to kind of that 2.5 miles that you just talked about? If so, what do you think that does for your D&C per foot costs? 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. 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 gonna drill it. 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 two miles, or they'll 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 the kind of ideal lateral length is probably closer to two and a half than it was to two. 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 of what that would reduce on D&C per foot. Yeah, it'll only help, it'll be in the kind of double, probably low double digits as far as $ per foot reduction, something like that. $20 a foot, $25 a foot would be my guess offhand. Okay. Yeah, no, that's really helpful. Makes sense. Thank you. As a reminder, if you wish to ask a question, please press star followed by the one. Your next question comes from Paul Diamond with Citi. Paul, please go ahead. Good morning. Thanks. Stay on the call. Just a quick one on reserve replacement. You've done well replacing and drilling locations over the last few years. Recently, we'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? I think kind of 2025 is certainly more New Mexico heavy in terms of inventory acquisitions. I think that's gonna be largely 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, that was a heck of a deal. We're really excited about that at the time, probably even more excited about that today. I think it's more opportunity set driven. I do think there's probably just generally more inventory available and likely to come for sale in New Mexico than in Texas over the next five years. I'd say more likely to do deals up there than in Texas, I mean, we're kind of agnostic. We'd love to do more in Texas if the right opportunity came along. It's just gonna 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. Got it. Understood. Just one quick follow-up on as you guys approach investment grade or investment grade ratings across all three agencies, is how do you think about any potential shift in your financial strategy on the other side? Is it move the needle at all, or is it just business as usual? I mean, I think the why are we focused on investment grade, you know, it fits with our strategy. We wanna reduce our cost of capital, we wanna have long-term capital availability. Then I think from a timing perspective, you know, where we've been more consistent 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. So we do think it has clear benefits going forward, and we do think we meet the criteria today. Understood. Appreciate the time. I'll leave it there. Thank you. There are no further questions, so I will turn the call over to James Walter for closing remarks. Please continue. 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. 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. Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.