Good morning, and welcome to the Permian Resources First Quarter 2026 Earnings Conference Call. Today's call is being recorded, and a replay of the call will be accessible until May 20th, 2026 by dialing 800-770-2030 and entering the replay access code 1442298, or by visiting the company's website at www.permianres.com. It is now my pleasure to turn the call over to Hays Mabry, Permian Resources Vice President of Investor Relations, for opening remarks. Please go ahead. Thank you, Amy, 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. Q1 represented another quarter of strong operational execution, delivering free cash flow per share of $0.60, the highest in PR history. In addition, we set records on both drilling and completion cost per foot, continued to deliver peer-leading controllable cash cost, and accelerated oil production volumes in response to higher oil prices in March. I'd note that the current market volatility reinforces what has always been core to the Permian Resources strategy: maintain a peer-leading cost structure, stay singularly focused on the Delaware Basin, the best onshore shale basin in the U.S., and preserve the flexibility as market conditions change. Periods like this give us an opportunity to demonstrate our team's ability to react quickly to create long-term shareholder value. We don't know where the market's headed. We are excited about our position and the flexibility we have to continue to capitalize on opportunities as they emerge. Turning to the quarter, Q1 production exceeded expectations with oil production of 192,000 barrels a day and total production of 413,000 barrels of oil equivalent per day. Production outperformance was driven by better than expected results from recent wells and significantly reduced downtime in March due to picking up additional work over rigs as a result of higher prices. In addition to wins on the production side, our D&C team continued to drive down cost. We reduced D&C cost to approximately $685 per lateral foot, with both drilling cost per foot and completion cost per foot setting new company records. On the drilling side, we delivered the fastest well in company history, averaging over 2,500 ft per day and delivered our longest quarterly average lateral length in company history, with roughly a quarter of our wells coming in over 2.5 mi. On the completion side, we achieved record recycled water utilization rates of approximately 70%. This not only lowers completion cost, but also saves on LOE and something you'll continue to see us focused on going forward. On the production side, the team installed four microgrids in the quarter, eliminating over 25 generators and reducing electricity costs on the associated well sites by roughly 30%. I also want to recognize the field team's response to January's Winter Storm Blair. We navigated the storm with minimal impact and recovered the production quickly. That kind of execution is a credit to our team in the field who runs our operations every day. Controllable cash costs came in well within our 26 guidance with LOE of $5.19 per BOE, GP&T of $1.36 per BOE, and cash G&A of $0.77 per BOE. To wrap it all up, strong production performance combined with further extending our Delaware Basin cost leadership resulted in record free cash flow of over $500 million for the quarter. Turning to natural gas, we continue to benefit from our approved natural gas portfolio, with the largest impact still ahead of us in 2027 and beyond. During Q1, we saw material weakness in Waha gas pricing. Despite this market backdrop, in Q1, our realized natural gas price, including hedges, was $1.33 per Mcf, a $2.44 premium to Waha during the quarter. Notably, roughly half this uplift is from firm transportation agreements that we entered into over the last few years with the balance from existing natural gas hedges. Today, we have approximately 400 million cubic feet a day of firm transportation to Gulf Coast and DFW markets, growing to over 700 million cubic feet a day in 2027 and beyond, as the full impact of our long-haul agreements comes online. Longer term, with 1 Bcf a day of gross production and an attractive end market portfolio, PR is well-positioned to participate in the growth in U.S. natural gas demand. With that, I'll turn the call over to James. Thanks, Will. Turning to slide 7, we wanted to emphasize a major milestone that our entire company is excited about and proud of. We received our second and third investment-grade ratings. We are now officially an investment-grade company from all three major agencies. This is a reflection of the financial philosophy that has been a core tenet of our business since the beginning. Investment-grade status lowers our cost of debt and ensures access to capital across cycles. We continue to prioritize balance sheet strength and have used our robust free cash flow to reduce absolute debt by approximately $1.2 billion since the beginning of 2025. It is important to note that our capital allocation framework does not change in this environment, but it does allow us to prioritize capital to the uses that we believe will generate the highest risk-adjusted long-term returns. The base dividend is our first priority, and we remain committed to consistent long-term growth. Beyond that, our priorities in the current environment are debt repayment, accruing cash to the balance sheet, and continuing to pursue accretive acquisitions. The strength of the business is that we do not have to choose between only one or two capital allocation levers. We can lean into whichever one creates the most long-term value at any given moment. As shown on slide 7, we believe that alignment between management and shareholders is critical to creating long-term value in oil and gas, and it is our belief that Permian Resources has as strong of investor alignment as any company in this sector. All of our employees receive common equity as part of their annual compensation. Officer compensation is heavily weighted towards equity and performance shares. Finally, co-CEO compensation is entirely performance-based, with Will and I receiving no cash salary and no cash bonus. Again, it's something I'm probably most proud of is our significant employee ownership. In total, PR employees own roughly 7% of the company, representing over $1 billion in equity value, creating the best possible alignment with shareholders. Slide 9 lays out how the business is operating in today's environment and how we are thinking about the rest of the year. Our priorities today are straightforward. In Q1, our focus was on accelerating near-term barrels by increasing high return workovers and maximizing runtime. You can see on this slide that we roughly doubled our workover rig count from January to March, which drove approximately half of our production beats for the quarter. Looking ahead to Q2, we expect to further accelerate production by continuing to run an elevated workover program and by taking steps to accelerate additional POPs into the quarter. Our team in the field is doing everything they can to accelerate barrels into this higher price environment. As a result of both higher workover counts and more turn lines in the quarter, we expect production in CapEx in Q2 to be modestly higher than Q1. For the second half of the year, we're in the fortunate position of having maximum flexibility to respond to an uncertain macro environment. If crude prices remain strong, we would expect to come out at the high end of both our production and capital ranges. We would do so with the existing rig and equipment we have today. Conversely, if conditions were to soften materially, we would expect to reduce activity and come to the lower end of both our production and capital ranges. Our activity levels and growth continue to be driven by the same principles that have always informed our investment decisions, which is maximizing free cash flow in the near term, midterm, and long term. We expect any range of these outcomes to generate higher free cash flow in 2026 than our original guidance. Turning to slide 10, we want to conclude by reminding our investors that PR's business plan remains the same. Every day, our focus is on driving long-term free cash flow growth, which we believe is the foundation of durable value creation in oil and gas. Since we became a public company in the middle of 2022, Permian Resources has delivered the highest free cash flow per share growth of any E&P company. In 2023, our first year as a public company, we generated $1.13 per share in free cash flow at an oil price of $78. In 2024, we grew free cash flow per share by nearly 50% to $1.64 at lower prices than the prior year. In 2025, we grew free cash flow per share from $1.64- $1.94, representing nearly 20% free cash flow per share growth at an oil price that was more than $10 lower than the prior year. We think it's important to be very clear how we have grown free cash flow per share. We've done so by doing three things consistently over that period. One, by being the lowest cost operator in the Delaware Basin, continuing to drive D&C efficiency and cost reductions. We've averaged a greater than 10% per year reduction in D&C every year since 2022. Two, by using our high quality long life inventory to organically grow production returns and macro environment justify growth. We have averaged greater than 10% annualized growth since inception. Three, by pursuing high-quality accretive acquisitions that make our business better and enhance our ability to grow free cash flow per share over the long term. We have acquired over $1 billion in high-quality assets each of the past three years. The co-combined effect of pulling all three of these levers year in, year out is that we have grown free cash flow per share at a 30% CAGR over the past three years, despite a market where the average oil price declined every single year. The emphasis on each of the three pillars that drive our free cash flow growth may change from one year to the next based on the macro environment and opportunity set, but our business model remains the same, as does our expectation that we can continue to generate outsized free cash flow per share growth, which will result in correspondingly high returns for our investors through the cycles. Thank you for tuning in today, and now we'll turn it back to the operator for Q&A. Thank you. The floor is now open for questions. To enter the queue, please press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press star one. If you are called upon to ask your question and are listening via loudspeaker on your device, please pick up your handset and ensure that your phone is not on mute when asking your question. We do request for today's session that you please limit to one question and one follow-up. Again, press star 1 to enter the queue. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Scott Hanold with RBC Capital. Your line is now open. Thanks. Good morning, all. Good quarter. I was wondering if you could talk through some of the dynamics of pulling forward some of the production into this environment. Obviously, it sounds like a lot of workovers occurring. You know, so the question is how many workovers, you know, do you have? I mean, is that something that's gonna persist mostly through Q2? Then, you know, beyond that, is it just organically, you know, pulling forward completions and, you know, at the current pace, like, how many more completions could you get, you know, into this year? I'll hit the first part. I mean, yeah, I think you hit it best. Like, the plan today with oil, you know, I guess above 90 on WTI basis is we're doing everything we can with the existing equipment to accelerate TILs and accelerate barrels into what's a very constructive oil price environment. Yeah, I mean, workover rig count's doubled. You know, we probably have gone from round numbers doing, call it 30 workovers, 40 workovers a month to something that looks closer to, like, 70 workovers, 80 workovers, maybe upwards of 90 workovers a month. I do think long term, like you end up chewing through your backlog, and at some point that normalizes out where you're just kind of working over any well that makes sense when it goes down. Obviously at $90, $100 oil, a lot more wells make sense to work over quickly than they would at, say, $50 crude. I said the other side of it would be we are getting faster and more efficient every day. We saw kind of a step change in Q1 and are continuing kind of real time today to show efficiency improvement on really both the completion side and the drilling side. If you combine that with kind of also working in between the drilling and completion process to reduce overall cycle time, I'd say we have the flexibility that with the existing kind of equipment we're running today, we can accelerate wells above and beyond what our original base plan highlighted. I say just we're maintaining flexibility. We may to do lots of things as the market changes. I'd say the general plan today is to really kind of hit the gas pedal but do it within the confines of the equipment we're running today, not pick up any kind of additional rigs. Thanks for that. My follow-up question is, you know, really kind of talk it through. You know, obviously, the strip's come down, especially the front month the last, you know, couple of days, but still pretty healthy. When you look at your free cash flow builds you got through the year, you know, look, it's not gonna take too long into 2027 before we have the conversation being, you know, net debt zero, right? Like, can you give us a sense of, like, in this macro environment, how do you think about, like, utilizing that? Or are you willing to kinda build that cash for black swan events or M&A if needed? I mean, I think we've always been comfortable running this business with leverage and think that's a good way to enhance equity returns. I'd kind of point you back to slide 7 where we talk about our capital allocation framework. You know, I think we're constantly evaluating the landscape and the kind of current environment to see what of our, you know, reinvestment opportunities is gonna drive the highest rate of return for shareholders. In some scenarios, that could be share buybacks, in others it could be debt repayment and accruing cash, and in others it could be spending that cash on acquisitions or raising our dividends. I think for us, we'd be comfortable going to kind of zero debt. I think in a certain set of scenarios, a certain context, I think it's probably less likely for us 'cause we've seen, you know, year in, year out really attractive reinvestment opportunities across the business that, you know, outcompeted the cash build scenario. I think for us it's all about optimizing around best risk-adjusted return for our cash flow and our dollars. Sure, there could be a scenario where kind of debt repayment to zero makes sense. I think that's probably less likely for us 'cause the opportunity set in the Delaware has been so robust. Appreciate that. Thanks. Thank you. Your next question comes from the line of Neal Dingmann with William Blair. Your line is now open. Morning, guys. Nice quarter. My first question is just on future activity. Specifically, maybe James for you or Will, is activity wondering these days constrained at all by power supply and maybe how much is that same activity influenced by the negative Waha? I did hear about the ET talk about potentially pre-flowing Hugh Brinson Pipeline and so maybe Waha improves soon. Just wondering around power and negative gas prices. I think the short answer would be no. Activity today is not constrained, kind of relative activity across the position. There really is no constraints. We're allocating capital as we see fit. I think the kind of more nuanced answer would be from a take a step back perspective, like power is less significant, but negative Waha is a real meaningful input into our calculation of returns. You know, alongside gas prices matter, crude prices matter, service costs matter. As you know, kind of in our framework, we're willing to grow when returns are great and paybacks are short. In other times, we're willing to kind of be more of a low growth or even hold flat business. Generally speaking, you know, Waha, which moves the needle more than electricity costs, may dictate a little bit of activity. No, we feel unconstrained across the position and are allocating capital as we see fit. On Waha, like, incremental growth, you know, in a meaningful way is gonna be weighted towards the back half of the year, or at least the middle of the year, where we expect Waha prices to improve and ultimately be resolved, you know, in the late third or fourth quarter. I don't think Waha is gonna meaningfully dictate plans over the next couple years. We actually think it's a situation that gets resolved in 2026 as we see it. Yeah, I agree with you, James. James, my second question just on capital allocation. Specifically, given the pristine balance sheet, I'm just wondering does your capital spent on acquisitions during any quarter influence what you might or might not pay out to shareholders that same quarter? You know, I guess I'm just thinking like should we assume shareholder return is solely an economic decision based on macro and specific variables or what else is influence there? Yeah. I mean, I think kind of as we look at our capital allocation framework, it's we're gonna allocate capital to whichever we think is gonna generate the best returns over the long term for our investors. You know, I do think we are weighting those against each other. You know, if we, if we do more acquisitions, that would accrue less cash to the balance sheet and, you know, could ultimately impact our dividend trajectory over time. I do think the kind of acquisitions that we're doing are so good for the business that probably only bolsters our longer term kind of base dividend trajectory. Yeah, I'd say we're constantly looking at anything we can invest dollars on and allocate capital to and pitting them against each other and saying, "What makes the most sense in the environment we see today and where we see the world going? Thanks, guys. Thank you. Your next question comes from the line of Neil Mehta with Goldman Sachs. Your line is now open. Yeah. Thanks, team. Again, a good quarter here. I just want to build on the M&A comment here. Clearly, the ground game has been very consistent. It does feel like it could be an active period, especially as the conflict hopefully gets towards resolution in the A&D market. Do you feel PR is well positioned to be active in that market? I mean, I think that we said in February coming into this year that we thought it was setting up from what we could see in the beginning of the year to be a really active kind of Delaware Basin market. I'd say two months in, kind of two months on from February, that really has played out. You know, I think we're seeing more deals for sale or planning to be for sale this year than we've seen any year in the last couple. You know, I'd say it's been interesting for us. There's been kind of more of them in our, in our part of the world in the Delaware, and frankly, higher quality than we've seen in the last few years. I think we are certainly well-positioned to take advantage of that at the right price. I mean, we talk about it a lot, but we do think our lowest cost structure in the Delaware and our in-basin, Midland-based kind of knowledge really does give us a differentiated competitive advantage when it comes to Delaware Basin deals. We've got an awesome based business. I'd say kind of any excitement is going to be tempered with, we're only going to do deals at the right prices, and if we're highly convicted, they make our existing business better, which is a high bar. Then, you know, just talk a little bit about the operations here. Again, you guys made some good progress on the drilling side, in particular with just the speed of wells, and it's translated ultimately into your cost metrics. You know, what are you guys doing on the D&C side in particular, to keep this momentum going? I mean, this is kind of just ingrained in our culture. This is what the guys do every day. You know, we're tinkering with BHAs in different areas to try to speed up kind of ROP in the lateral. We're trying to, you know, reduce bit trips. We can get down to kind of one-bit runs like what we'll see in the Midland Basin. If we can get that in the Delaware Basin, I think that means a lot of days on our side. Then you saw this quarter kind of we had the benefit of pushing lateral lengths. You know, drilling 25% of our wells over 2.5 mi definitely helps accrue to the cost side of the equation. Look, I mean, when we set out a lofty target this year, we wanted to get down to $6.75 per foot over the course of the year. We entered the year at $700 a foot. We chopped that down to $685 in Q1, and I'd say the efficiencies are well on track to achieve it. I'd say any headwind we have from this point forward will be kind of inflation related. Fortunately, we haven't seen much of that yet. Okay. Thanks, team. Thank you. Your next question comes from the line of John Freeman with Raymond James. Your line is now open. Thanks. Good morning, guys. Just following up on the last question, Neil's question on the M&A side and ground game. It was interesting, you know, obviously another strong quarter on the ground game with $200 million or so. What I thought was interesting is the last few quarters, you kind of averaged that same amount, about $200 million or so a quarter, but it's tended to be somewhere around $150 million, $200 million transactions each quarter to get to that. This one was only 40 deals. I'm just wondering if that speaks to, is there some change in, you know, whether it's bigger, lumpier sort of transactions that you're looking at? Just anything that may be changing under the surface here on the ground game side. That's really observant. That's a good question. I think it's just normal fluctuations. I think time will tell. You know, I do think we're more focused on the kind of absolute dollars and more importantly, probably the actual absolute value creation as we see it in the number of deals. I think 40 deals on an absolute basis is still a lot of deals for the quarter. You know, that's $150 million, $200 million acquisitions a year run rate if you annualize it, and that still feels really strong. I think there's a couple of factors on why it was lower for the quarter. This quarter was still actually quite a few small transactions. We didn't have any single transactions north of $100 million, and it was really an amalgamation of kind of $500,000 to $15 million or $20 million deals. I think it does look a little different on its face, but I think kind of trajectory rise, I wouldn't read too much into it. You know, we do feel really, really good about the pipeline and the ground game kind of throughout the course of this year. Got it. Then, kind of going back to slide 7, obviously the balance sheet's in great shape, so you don't have to do anything here in the near term. Y'all did mention that, you know, you see some upcoming callable notes that present some further opportunities. When I look at it looks like the, you know, next month the 2029s are callable at par, but that's also your lowest cost debt versus the 2031s that's your most expensive kind of remaining paper, but those aren't callable at par for a few years. I'm just wondering, maybe a question for Guy, like how you sort of think about that dynamic about, you know, you can take out your really cheap debt at par here soon, or, you know, you potentially either pay a premium to take out some of the more expensive debt or you just accrue cash. Yeah. Luckily, bond math is easier than asset acquisition return. My job is simpler, and we just put it in the same framework. If we take out those bonds at par versus taking out the older stone bonds at first call, and generally with that high of a keep on, even with the first call, that's a better return. In this world, kind of given our overall liquidity, I'd say maturity profile of the bond's less relevant just given how long our existing maturity profile is and the amount of liquidity we have. It goes in the same bucket James has talked about. We're looking at dollars that come into business and how we allocate them. I think under that framework, most of the time the older stone bonds will win out. Okay. Just to make sure I understood, Guy, it's, it may be more likely the 2031 ones would be the ones that would be tackled. Yes. Okay. Got it. Thanks, guys. Good quarter. Thanks. Thank you. Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Hey, good morning. You made the comment earlier on the call about growth kind of being back half weighted, when, you know, gas takeaway was more readily available. Just kind of curious how you see production trajectory throughout the year if you kind of keep this current activity pace. Any thoughts on, you know, where you could end up on an exit rate, if that would be kind of higher than your full year guidance? Thanks. Yeah. Yeah. I think kind of parsing that question a little bit, I'd say the question was on further growth from what we'd outlined, and if you are gonna go further from Q2, it would by definition be back half weighted. I wasn't trying to say anything beyond that. Kind of if you talk about longer term growth, you know, years, not months and quarters, I do think that should be in an environment where Waha is less of an issue. Frankly, we're pretty well protected already today and only getting stronger. I think if you think about kind of growth over the long term, growth's always been extremely free cash flow focused for us. You know, I think we've been pretty clear with the framework that we're gonna grow more in environments where the returns are higher and the payouts are shorter. You know, we're gonna grow less and kind of go back to more of a maintenance case in worse returns environments with longer payouts and lower returns. That's driven by a combination of, you know, oil prices, gas prices we realize, and the service cost environment. I think today I do think we're really excited about the barrels we're producing and the barrels we're accelerating into the environment that we're in, you know, Q1 and Q2. I do think longer term, there's just more uncertainty on the macro on when the conflict in Iran ends and what that means for kind of the go forward trajectory of supply and demand balances. I think the reason you've seen us be a little bit cautious on specifics today is it does feel like there's a pretty wide band of outcomes. I do think the macro's certainly improved from where it was when we were sitting in February. We just don't know how this ends and are in a really fortunate position that we can be flexible and, you know, position the business to react to, you know, higher for longer commodities or for something that reverts to where we were close to the year or really anywhere in between. I think flexibility is a really great position to be in for us. Obviously you've seen it before. We have a business that can kind of pivot, like Will said, with our existing equipment to a meaningful growth program or go back to a maintenance mode, you know, pretty short notice. Great. Thanks for that clarification. Then my follow-up, I just kind of wanted to maybe if you could say again what your comments on inflation? Is there no inflation in the $685 well cost number? You know, do you have any view that inflation or diesel charges or something could pick up here? Yeah, I mean, we started to see diesel prices pick up at like, let's call it the very end of March. So no, maybe not right, but very de minimis inflation in the $685. Obviously, yeah, diesel prices have, you know, depending on what you want to use as your baseline, they're up 50%-70% over the last month or two. Outside of diesel, we have not seen any inflation outside of diesel. It's kind of direct diesel inflation or pass-throughs, you know, deep fuel surcharges pass-throughs from people that do a lot of trucking. Great. Appreciate the answers. Thanks, guys. Thank you. Your next question comes from the line of Phillip Jungwirth with BMO. Your line is now open. Thanks. Good morning. Morning. We spent a lot of time asking you guys about improving gas realizations out of the Permian, but there's also a number of new NGL pipelines or expansions, LPG export terminals, plus G&P additions. Just wondering if there's anything you can do on the NGL net back side to improve realizations versus Mont Belvieu, just given that you now produce over 100,000 barrels of NGLs? I'd say we're constantly chipping away at all our contractual NGL agreements to see where we can optimize. You know, that's kind of pen-pennies per gallon, not transformational things from Waha. I do think that's somewhere that we've been focused on the last couple of years and don't talk a lot about it. I do say kind of when you think of size of the fries on net backs, getting away from Waha has been by far the most material. You know, the basin actually has constraints. We have had no flow assurance issues. We've moved every molecule we've ever produced out of this basin, but we've done so, you know, at times at pretty disadvantageous Waha pricing. That's been our focus. On the NGL side, we've had no constraints. You know, I think we feel good. On the NGL takeaway and the gathering and processing side, frankly, that enough capacity is getting built by our midstream partners to service everything coming out of the basin. It's less of a concern, but, you know, safe to say something we're always optimizing just like we are, you know, every part and every widget of our business. Okay, great. It's gotten more attention in the Midland, but how are you guys viewing the Woodford prospectivity over towards the eastern side of your Lea County acreage and any plans to test it? I'd say Woodford, like we talked about this last quarter, a little bit about like the Wolfcamp D and some Avalon, and kind of how we thought about it and added it to the kind of inventory stack. I'd say Woodford falls generally in that same category where kind of where we own the Woodford and hold those depths, at this point, it's held forever. We've watched kind of what I say Continental, who's probably leading the Woodford charge has done. It's also, it's honestly really exciting. They've drilled some monster wells. I think there's a lot of work to be done on both the gas takeaway and the cost side. It's a very exciting bench that we're probably in the kind of good position that we can be wait and see. We're not aggressively leasing Woodford. We're more kind of holding on to what we own today and watching how it's developed. There may be a few places that we drill a few Woodford wells, but it won't be any kind of big part of the program. Great. Thanks, guys. Thank you. Your next question comes from the line of John Abbott with Wolfe Research. Your line is now open. Hey. Thank you very much for taking our questions. So you made some comments that, you know, you are increasing work over activity. So my question really is on the trajectory of LOE. I mean, you've also discussed how diesel pricing and have also higher diesel prices. So presumably, it seems like your production expenses should move higher. So how do you see your unit costs on the LOE side sort of progressing over the course of year? And what do you see as a normal go forward LOE expense? It's a good question. First thing that I think is worth clarifying is, like most of the workovers we do are probably half are capital and half are LOE. Anything on an ESP or things that we think add a kind of incremental reserves fall on the capital side of the workover equation. It is split, call it 50/50 from CapEx to LOE. Yeah, I do think that we had an abnormally low Q1 on the LOE side due to a myriad of things. That the majority of being that outside of that short winter storm, we had kind of an amazingly low, you know, good temperatured winter. It was a very, very mild winter. I think that the incremental workover activity likely we're gonna be back right where we thought we'd be kind of for the year. Call it I think our midpoint of our guide was $5.45 per BOE on the LOE side. I think that's probably where we will end up averaging for the year. They come with extra barrels, it's not like you don't get anything in the denominator when you do it. That'd probably be our best guess today. All right. Appreciate it. The other question is really back on sort of maintaining it and potentially adding activity. I mean, obviously, you talked about the focus on to free cash, like returns. My question really is how do you sort of think about the price points about adding activity or relowering the activity? If you add activity, do you hedge more? Also, do you if we do see a pickup in the potential future curve, if there's concerns about service costs inflation, do you wanna get ahead of that? How do you sort of think about those variables as you think about possibly adding or reducing activity? I mean, I think as I mentioned earlier, I'd say our kind of activity or reinvestment framework has always been focused on returns, not just oil price. You know, I don't think we don't think about a specific oil price. We don't have one to share. I'd say for us, we have talked about in the past, and it's the same view today, that kind of an attractive payout window is kind of in the 12-18 months. If you're drilling a well and you're going to get all of that capital that you spend back in 12, 13, 14, 15 months, we do view that as a really attractive, you know, return window. If you're seeing 18-24 months, that probably pushes you more towards a maintenance case. I'd say we've always thought about it more from a return standpoint than anything else. I will say it's probably worth pointing out, we haven't said on this call, like we do kind of the current midpoint of our, of our latest guide does show 6% year-over-year growth for 2026 versus 2025. We do think of this as being a growth year, and the kind of growth signals from a return standpoint are there today. We see really attractive returns at today's, you know, environment. I would say the reason to kind of, I think, for growth beyond the 6% we've shown today is just like you've seen, there's still a tremendous amount of volatility and a tremendous amount of uncertainty on when the conflict in Iran ends and what the state of the world looks like when it does. Appreciate it. Thank you very much for taking our questions. You bet. Thank you. The next question comes from the line of Jeff Bellman with Daniel Energy Partners. Your line is now open. Hi, guys. Good morning. I wanted to go back just on Permian gas takeaway. We're tracking like 10 Bcf, close to 11 Bcf a day of new takeaway capacity over the next five years. I'm curious how you guys think about that takeaway, just in terms of future utilization of those pipes, and kind of what does that imply for incremental oil production? If we think all of that gas is gonna be associated volumes, kind of what would be the driver on the oil, on the oil production side of that? Kind of the last part, could you envision a world in two, three years from now where the basin's targeting gassier zones or making gas more of a primary objective? Thanks. Yeah. I mean, I think, you know, we're seeing the same thing. I think people finally realize just building pipes out of the Permian is both necessary and profitable. It kind of makes everything work better. We're, we're super excited about the activity. I was gonna say the pipeline of pipelines, that's probably not the best English, but no, I think we're seeing the same thing. I do think, look, the short answer is we do expect to see continued meaningful gas growth out of the Permian over the next five, 10, maybe plus years. I do think we're gonna see significantly less oil growth, although all of the gas is associated. We've seen that both kind of individual well productivity can get gassy over time and/or, you know, the zones that people are targeting as you go to full cube development, or certainly as you go to deep-deeper zones. We've gotten some questions on the Barnett Woodford. I do think you could see the mix of the whole basin get gassier over time. Specific to Permian Resources, I don't see us in the next 2 to 3 to 4 to 5 years targeting gas zones at anything that looks like the current strip environment. I'd say even with the normalization of Waha pricing, our oil-weighted wells, which is the core of our business, are just so much higher rate of return that capital allocation is naturally gonna flow to oil-weighted development. Do we have, as Permian Resources, kind of gas zones that make money at a normalized environment? Absolutely. It's just not at the same level as our, you know, ultra-high return oil wells that are gonna allocate capital in almost any normal scenario that we see. With regard to the basin, I do think you could see potentially other operators with a different inventory set targeting, you know, deeper or more gas-weighted, you know, developments, but that's not likely to be for us in the environment as we see it. Okay. Thanks, guys. Congratulations. Doing a great job. Good job. Thanks, Jeff. Thank you. The next question comes from the line of Paul Diamond with Citi. Your line is now open. Thank you. Good morning, all. Thanks for taking the call. Just wanted to touch base on the current natural gas curtailments. I guess, how should we think about the return of these? Is this mainly a two-stage story as, you know, capacity comes online and Waha pricing stabilizes? Or are there, I guess, other factors that could, you know, bring that forward? Yeah, I mean, I think, you know, the short answer is we've shut in wells that are gas wells and have extremely high GORs that don't make sense to produce in a negative gas environment, certainly not a -$5 to -$10 range like we've seen the last few weeks. You know, I do think we would plan to return those wells to production when it's economic to produce them again. You know, we would expect that to be in the second half. I think if, for some reason, the kind of the negative Waha environment persisted beyond that, I think we would continue to make the same economically rational decisions that we're making today. We're not gonna make gas well produce just to do so to make Mcf. We're here to make money, and we're gonna always be making decisions around how to maximize cash flow. It seemed to us like the biggest no-brainer to shut in and curtail, you know, gas wells that were losing money. Got it. Makes perfect sense. Then just thinking about M&A. Given the current volatility, we've been hearing a lot of rumors about kind of increased velocity of larger packages being considered coming to market. I guess, can you comment on what you guys have seen as the scale opportunities out there? Yeah, I'd say the velocity of opportunities all trying to come to market at the same time is quite robust. Seems like a lot of deals trying to fit into this, you know, summer, fall window. I think for us. I think that's good. I think we always thought this would be a year with robust opportunities. I'd say if anything, it's looking better than it did in February in terms of kinda high-quality deals. I do think those, for us, are still gonna be in the same scale of deals that we've done historically. Like, we did a $600 million deal last year. We did an $800 million single deal the year before. That's really been our sweet spot and our bread and butter. You know, I think of those as scale deals. I couldn't tell from your question if that would qualify as a deal of scale for you or not. I think that we've seen those are the kind of the highest quality inventory deals, the ones that fit easiest and quickest in our portfolio, and we can extract value kind of the quickest and in order the greatest return for our investors. I think, yeah, we're definitely seeing more deals of scale in this environment and, you know, we think that's a good thing. You know, will we prevail on any or all of them? I think time will tell. I'd say certainly not all of them. We have a pretty robust and rigorous underwriting process and have a great base business. I'd say seeing a lot this year, you know, probably in excess of what we've seen in the last couple of years. All right. Appreciate the time. Over to operator. Thank you. The next question comes from the line of Leo Mariani with ROTH Capital. Your line is now open. Hi. You guys, made mention of, you know, pulling TILs forward. I guess you've got a goal of around 250 TILs this year. Wanted to get a sense if oil prices stay robust and the returns and the paybacks are there, what conceivably could that number move up to? Are we talking, like, 10 extra TILs? Are we talking 20 TILs? Just trying to get a relative order of magnitude here. I think kind of what we talked about today is we could probably add 5% maybe 5%-10% incremental wells with doing the easy things. Easy is probably understating it. My team will slap me for that. I'd say just with really compressing cycle times and then drilling faster, fracking faster, et cetera, I think that's probably achievable. I think James said it best after that. That is really that's what we're doing in Q2. We're kind of on pace for that type of activity in Q2 real time today. Back half of the year, I think we could I mean, there's a return environment that you may contemplate adding incremental activity beyond that to bring in even more wells, or there's a return environment where you may consider dropping activity to get something that was closer to the base plan. For kind of what we're talking about today, I'd call it 5%, probably right around 5%, maybe a little over 5% incremental wells to the year is probably the right number. Okay. That's helpful for sure. Then just jumping back to your $685 a foot, obviously getting very close to your goal of $675 for the year. You guys talked a lot about, you know, speed in terms of drilling and completing and, you know, less, you know, bit trips out of the well to kind of get there. It sounds like a lot of that's in progress. Anything else out there that you may be seeing, maybe, as you look forward, maybe another year or two, you think could be like the frontier of continuing to lower that cost number? If I saw anything, we'd be doing it, is the short answer. We're always tweaking. You know, if you think about just like wins we've had outside of just small incremental wins on the speed side. A couple quarters ago, it was a new way of drilling out wells that kind of materially reduced drill out time, saved us, call it $10-$15 a foot. We bumped up water recycling this quarter, which was pretty material, and I'd like to continue to increase that going forward. You can probably go follow transcripts. Water recycling has been something that I've been harping on the guys about for a long time, given just it's the right thing to do, and it's extremely efficient from a savings perspective on both the CapEx and LOE side. What I think you may see, if you really want me to look out a couple of years, is as we've discussed at length, like there's been a ton of capital put into not saving dollar per foot, but trying to increase recoveries per section. You know, I don't know which one of these kind of tests is going to be the solution or what combination is going to be the winning formula. I think if I had a bet of the next step change in the industry, it's going to be kind of more productivity per acre or productivity per well, which may or may not offset some of the cost savings, but would definitely be a large incremental value creation and kind of increase returns pretty meaningfully. We'll keep cutting costs. We'll keep doing the small things. My bet is the next big win comes with increased recoveries, not another step change in cost. Okay. Thank you so very much. Appreciate it. Thank you. Before we continue with questions, I just want to remind you, if you would like to ask a question, press star one on your telephone keypad now. Your next question comes from the line of John Annis with Texas Capital. Hey, good morning, guys. For my first one, you highlighted that the microgrids that lowered electricity costs by 30% at those sites. How scalable is that program across your asset base? Do you think that's something that could move the needle on LOE at a corporate level over time? I'd say on a site-by-site basis, it moves the needle pretty materially. The reason it's hard to move the corporate needle is I'd say other than New Mexico, we're on grid power everywhere, and grid power is a better solution than a microgrid. We're already at kind of the low-cost solution. Within New Mexico specifically, I'd say our approach is, you know, if there is microgrids, there's an upfront capital expenditure to reduce variable costs via electricity and kind of other generator maintenance over time. In areas where we have a high concentration of generators or really the high concentration in a small area of facilities, those are where we start. We've knocked out eight to date. There are plenty more on the horizon, but this is gonna affect kind of corporate LOE by pennies, not by dollars. That makes- Not by quarters. Got it. For my follow-up, a lot of questions on M&A so far, and I wanted to ask about more organic inventory expansion potential. Do these higher prices allow you more room to take some exploration risk this year by testing either new areas or new benches like the Avalon in Northern New Mexico or moving further west to the Western flank in Eddy? I would say I was going to say no, but those two you just brought up would be areas that we are doing. The short answer would be, generally speaking, I don't think our, like, exploration budget or dollars we put in exploration really changes that much as prices move around. Like, we've had the benefit in the Delaware, for the most part, of being able to kind of watch what others do and then have a little kind of lower risk exploration after we've already seen a few wells put in the ground. I do think that we have been the leader in pushing Eddy County to the north and to the west, and have been very successful in that. The way we've done it has been more kind of, if you think about it, 1 mi at a time, and we just kinda continue to study the geology and make sure that the returns of the, kind of the incremental step out will be just as good as the pad before it. To date, we've had a ton of success with that. Then you hit the other one, Avalon pushing north. Like, yeah, we love the Avalon. We saw I mentioned this a one quarter or two ago. We saw Matador and a few others had put up some Avalon wells further north than others had, and we were very impressed with the results, so we've started to do that ourself. Hopefully that kind of answers the full question. Inventory replacement for us is a really, it's a long-term game, and we're trying to kind of focus on that over years, you know, not quarters and months. I don't think, you know, I think it helps on the margins today, the rates of return, but I don't think it changes our long-term philosophy. Makes sense. I appreciate the time. Thank you. The next question comes from the line of Gabe Daoud with Truist Securities. Your line is now open. Thanks, Operator. Morning, guys. Thanks for the time. Just one for me, going back to the water recycling comment. Just curious, like how much water recycling is currently being done? Just from a disposal standpoint, is that something that, I don't wanna say you worry about, but something that you certainly think about, just given some of the comments around maybe pore space getting pretty full in the basin? The number for this quarter was 70%, so that's up quite a bit from previous quarters, and we've continued to increase that over time. I'd say that for us specifically, which I can speak to, we don't worry about the kind of end disposal need or pore space issues. Really that's just given the partnerships we have with our midstream partners. You know, we're in business with the biggest and the most well-capitalized and furthest in front of our water disposal needs. Contractually, I'd say we those are set up where that is a, you know, a liability that a lot of times they'll wear and that they're responsible for making sure they can house our water. Recycling being the most efficient way for both of us. If it did come a day where we had to go ahead and dispose of more for one reason or another, we're very confident that our midstream partners are ready for that and have the capacity to take the water. Got it. Got it. Okay. That's helpful. Thanks, guys. Actually, just maybe one quick follow-up if Sorry if I missed this, what's the commentary then around inflationary pressures just from service providers attempting to get pricing on some equipment? I mean, The only inflation we've seen to date has been fuel related and at, you know, actual diesel increases for diesel we consume and fuel related surcharges. Got it. Okay. Thanks, guys. You bet. Thank you. There are no further questions at this time. Mr. Walter, I would like to turn the call back over to you for closing remarks. Thank you. As you can tell from this morning's results, the business is in a stronger position today than at any point in PR's history. We have an investment-grade balance sheet, a simplified corporate structure, the lowest cost in the Delaware Basin, and a team that continues to set new records every quarter. Combined with a more constructive commodity environment, we believe we're exceptionally well positioned to continue compounding free cash flow per share and delivering outsized return for our investors. Thanks to everyone for joining the call today and for following the Permian Resources story. That concludes today's conference call. 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