Permian Resources (PR) Q1 2026 Earnings Transcript

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Date

Thursday, May 7, 2026 at 10 a.m. ET

Call participants

• Co-Chief Executive Officer — William Hickey
• Co-Chief Executive Officer — James Walter
• Chief Financial Officer — Guy Oliphint

Takeaways

• Free cash flow per share -- $0.60, representing the highest quarterly figure in company history.
• Quarterly oil production -- 192,000 barrels per day, surpassing internal expectations due to reduced downtime and workover program acceleration.
• Total production -- 413,000 barrels of oil equivalent per day, exceeding plan, driven by improved well results and operational efficiencies.
• Drilling & completion (D&C) cost -- $685 per lateral foot, with both drilling and completion costs at new company records.
• Free cash flow -- Over $500 million, a new quarterly record, resulting from combined production and cost achievements.
• Controllable cash costs -- Lease operating expense (LOE) at $5.19 per BOE, gathering, processing, and transportation at $1.36 per BOE, and cash G&A of $0.77 per BOE, all within guidance.
• Investment grade ratings -- Achieved ratings from all three major agencies, formalizing investment-grade status.
• Debt reduction -- Reduced absolute debt by approximately $1.2 billion since the start of 2025 utilizing free cash flow.
• Natural gas realizations -- Q1 realized price, including hedges, was $1.33 per Mcf, a $2.44 premium to Waha, mainly from firm transportation (about half) and hedging (balance).
• Firm transportation capacity -- 400 million cubic feet per day currently secured, expected to grow beyond 700 million cubic feet per day from 2027 as new agreements take effect.
• Employee equity ownership -- PR employees collectively own about 7% of outstanding shares, exceeding $1 billion in value.
• Workover activity -- Monthly workovers increased from approximately 35 to 80-90 during the quarter, contributing materially to production gains.
• Microgrid installations -- Four microgrids deployed, eliminating over 25 generators and reducing electricity costs by an estimated 30% at affected sites.
• Water recycling -- Achieved 70% recycled water utilization rate in completions, a company record for operational efficiency and LOE savings.
• D&C efficiency trend -- Averaged more than 10% annual D&C cost reduction since 2022, reflecting a consistent downward trend in costs.
• M&A activity -- Closed approximately $200 million of deals in the quarter across 40 transactions, without any single deal exceeding $100 million.
• Free cash flow per share CAGR -- Maintained a 30% compounded annual growth rate over the past three years, even as average oil prices declined each year.
• Guided production growth -- Management stated current guidance reflects a 6% production increase in 2026 versus 2025.

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Risks

• LOE may trend higher for the remainder of the year due to increased workovers and rising diesel costs, with management expecting to reach the midpoint guidance level of $5.45 per BOE.
• Realized natural gas prices remain exposed to weakness in Waha basis, with certain high GOR gas wells shut in during periods of negative pricing.
• Cost inflation observed in diesel and pass-through fuel surcharges could impact future drilling and LOE metrics, as noted by management.

Summary

Permian Resources (NYSE:PR) reported record quarterly free cash flow per share and total free cash flow, driven by operational efficiency, production outperformance, and cost discipline in both drilling and completion activities. All three major credit agencies granted investment-grade status, and the company reduced debt by $1.2 billion, enhancing financial flexibility. Notably, the quarter’s realized natural gas pricing outperformed local benchmarks, supported by firm transportation and hedging, while the acceleration of workover programs and strong production throughput leveraged elevated commodity prices. Looking forward, management highlighted the ability to flex capital allocation among dividends, debt repayment, and acquisitions, underpinned by a base of meaningful employee ownership and a commitment to maximizing risk-adjusted returns.

• Management emphasized, "value, creating the best possible alignment with shareholders," with over $1 billion in equity held by staff.
• Guidance remains that ongoing efficiency improvements and production optimization may result in higher free cash flow in 2026 than initially forecasted, regardless of macro conditions.
• Volume flexibility is maintained, as the team stated that if crude prices weaken, activity and spending would fall to the low end of guidance ranges; conversely, continued price strength would support output at the top end.
• The company affirmed, "in the middle of 2022, Permian Resources has delivered the highest free cash flow per share growth of any E&P company."

Industry glossary

• D&C (Drilling & Completion): All capital and operational costs related to drilling new wells and conducting the subsequent completion phases prior to placing wells on production.
• LOE (Lease Operating Expense): Direct field-level expenses for maintaining production from existing oil and gas wells, excluding taxes and depreciation.
• Waha: A West Texas natural gas price benchmark reflecting supply-demand dynamics at the Waha hub.
• Firm transportation: Long-term, contractually guaranteed pipeline capacity agreements ensuring the ability to move specified volumes to markets.
• GOR (Gas-Oil Ratio): The ratio of gas produced to oil produced from a well, indicating hydrocarbon phase characteristics.
• TIL (Turn-In-Line): Wells that are completed and connected to production infrastructure, thus commencing contribution to total output.
• Workover: Remedial well intervention operations to restore, maintain, or increase production from an existing wellbore.
• Microgrid: A localized energy generation and distribution system, typically installed on-site to reduce reliance on mobile or off-grid generators.

Full Conference Call Transcript

William Hickey: 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, continue 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 is headed but 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 workover 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 feet per day and delivered our longest quarterly average lateral length in company history, with roughly 1/4 of our wells coming in over 2.5 miles. 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 4 microgrids in the quarter, eliminating over 25 generators and reducing electricity cost on the associated well sites by roughly 30%. I also want to recognize the field team's response to January's Winter Storm Fern. We navigated the storm with minimal impact and recovered to 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 about $0.36 (sic) [ $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 improved natural gas portfolio with the largest impact still ahead of us in '27 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 '27 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. And with that, I'll turn the call over to James.

James Walter: 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, are now officially an investment-grade company from all 3 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's 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 1 or 2 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 a strong 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, 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 run time. 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 beat 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 in this higher price environment. As a result of both higher workover counts and more turn lines in the quarter, we expect production and 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 will do so with the existing rigs and equipment we have today.

Conversely, if conditions were to soften materially, we would expect to reduce activity and come at 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. Importantly, 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 to $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. And we think it's important to be very clear how we have grown free cash flow per share. We've done so by doing 3 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 have 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 and return to macro-environment justified 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 3 years. The combined effect of pulling all 3 of these levers year in, year out is that we have grown free cash flow per share at a 30% CAGR over the past 3 years despite a market where the average oil price declined every single year.

The emphasis on each of the 3 pillars that drive our free cash flow growth may change from 1 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 I'll turn it back to the operator for Q&A.

Operator: [Operator Instructions] Your first question comes from the line of Scott Hanold with RBC Capital.

Scott Hanold: 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. Is -- how many -- so the question is, how many workovers do you have? I mean, is that something that's going to persist mostly through 2Q and then beyond that, is it just organically pulling forward completions? And at the current pace, like how many more completions could you get into this year?

William Hickey: I'll hit the first part. I mean, yes, I think you hit it best. Like the plan today with oil, 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. Yes. I mean workover rig counts doubled. So we probably have gone from, round numbers doing, call it, 30, 40 workovers a month to something that looks closer to like 70, 80, maybe upwards of 90 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. And obviously, at $90, $100 oil a lot more wells make sense to workover quickly than they would at say $50 crude. And then 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.

And so 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 TILs above and beyond what our original base plan highlighted. And so I'd say just, we're maintaining flexibility. We may have 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.

Scott Hanold: My follow-up question is really kind of talking through -- obviously, the strip has come down, especially the front of month -- the last couple of days but still pretty healthy. And when you look at your free cash flow build, you got through the year, look, it's not going to take too long into 2027 before we have the conversation being net debt 0, right? So like just could you give us a sense of like in this macro environment, how do you think about like utilizing that? Or are you willing to kind of build that cash for black swan events or M&A, if needed?

James Walter: Yes. I mean I think we've always been comfortable running this business with leverage. I 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. I think we're constantly evaluating the landscape and the kind of current environment to see what of our reinvestment opportunities is going to drive the highest rate of return for shareholders. In some areas that could be share buybacks and others, it could be debt repayment and accruing cash. And in others it could be spending that cash on acquisitions or raising our dividend.

So I think for us, we'd be comfortable going to kind of 0 debt, I think, in a certain set of scenarios, a certain context. I think it's probably less likely for us because we've seen year in, year out really attractive reinvestment opportunities across the business that outcompeted the cash build scenario. So I think for us, it's all about optimizing around best risk-adjusted return for our cash flow and our dollars. And sure there could be a scenario where kind of debt repayment to 0 made sense. I think that's probably less likely for us because the opportunity set in the Delaware has been so robust.

Operator: Your next question comes from the line of Neal Dingmann with William Blair.

Neal Dingmann: 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, though I did hear about ET talk about potentially pre-flowing Hugh Brinson and so maybe Waha improve soon. So just wondering around power and negative gas prices.

William Hickey: 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 are 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 return alongside gas prices matter, crude prices matter, service costs matter. And as you know, kind of in our framework, we're willing to grow when returns and kind of returns are great and paybacks are short.

And in other times, we're willing to kind of be more of a low growth or even hold flat business. And so generally speaking, Waha, which moves the needle more than electricity costs may dictate a little bit of activity. But no, we feel unconstrained across the position and are allocating capital as we see fit.

James Walter: Yes. Kind of on Waha, like incremental growth in a meaningful way is going to be weighted towards the back half of the year where -- or at least the middle of the year where we expect Waha prices to improve and ultimately be resolved in the late third or fourth quarter. So I don't think Waha is going to meaningfully dictate plans over the next couple of years. We actually think it's a situation that gets resolved in 2026 as we see it.

Neal Dingmann: Yes, I agree with you, James. And then 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 not -- might or might not pay out to shareholders that same quarter? 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 influenced there?

James Walter: Yes. I mean I think kind of as we look at our capital allocation framework, it's -- we're going to allocate capital to whichever we think is going to generate the best returns over the long term for our investors. And I do think we are weighting those against each other. If we do more acquisitions, that would accrue less cash to the balance sheet and 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.

But yes, 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.

Operator: Your next question comes from the line of Neil Mehta with Goldman Sachs.

Neil Mehta: And again, a good quarter here. I just want to build on the M&A comments 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. And do you just feel -- do you feel PR is well positioned to be active in that market?

James Walter: Yes. 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. And I'd say 2 months in -- kind of 2 months on from February, that really has played out. I think we're seeing more deals for sale or planned to be for sale this year than we've seen any year in the last couple.

And I'd say it's been interesting for us to kind of more of them in our part of the world in the Delaware and frankly, higher quality than we've seen in the last few years. So I think we are certainly well positioned to take advantage of that at the right price. I mean we talk about it a lot. 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 but we've got an awesome base business.

So 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.

Neil Mehta: And then 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. So what are you guys doing on the D&C side, in particular to keep this momentum going?

William Hickey: I mean this is kind of just ingrained in our culture. This is what the guys do every day. We're tinkering with BHAs in different areas to try to speed up kind of ROP in the lateral. We're trying to reduce bit trips, so we can get down to kind of 1 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. And then you saw this quarter kind of we had the benefit of pushing lateral length. Drilling 25% of our wells over 2.5 miles definitely helps accrue to the cost side of the equation.

But look, I mean, when we set out a lofty target this year, we wanted to get down to $675 per foot over the course of the year. We ended 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. And fortunately, we haven't seen much of that yet.

Operator: Your next question comes from the line of John Freeman with Raymond James.

John Freeman: Just following up on the last question, Neil's question on the M&A side and ground game. It was interesting, obviously, another strong quarter on the ground game with $200 million or so. But what I thought was interesting is, the last few quarters you've kind of averaged that same amount, about $200 million or so a quarter but it's tended to be somewhere around 150, 200 transactions each quarter to get to that and this one was only 40 deals. And so I'm just wondering if that speaks to -- is there some change in 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?

James Walter: That's really observant. That's a good question. I think it's just normal fluctuations. I think time will tell. 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. That's 150, 200 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 but this quarter was still actually quite a few small transactions.

It's kind of -- we didn't have any single transactions north of $100 million and it was really a amalgamation of kind of $500,000 to $15 million to $20 million deals. So I think it does look a little different on its face but I think kind of trajectory-wise, I wouldn't read too much into it. And we do feel really, really good about the pipeline and the ground game kind of throughout the course of this year.

John Freeman: Got it. And then kind of going back to Slide 7 and obviously, the balance sheet is in great shape. So you don't have to do anything here in the near term. But you all did mention that you see some upcoming callable notes that present some -- further opportunities. And when I look at it, it looks like the next month, the 2029 are callable at par but that's also your lowest cost debt versus the 2031 that's your most expensive kind of remaining paper but those aren't callable at par for a few years.

And so I'm just wondering maybe a question for Guy, like how do you sort of think about that dynamic about you can take out your really cheap debt at par here soon or you potentially either pay a premium to take out some of the more expensive debt or you just accrue cash?

Guy Oliphint: Yes. Luckily, bond math and return is easier than asset acquisition returns. So 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 old Earthstone bonds at first call and generally, with that high of a coupon, even with the first call, that's a better return. And in this world, kind of given our overall liquidity, I'd say maturity profile of the bonds less relevant just given how long our existing maturity profile is and the amount of liquidity we have. So it goes in the same bucket.

James has talked about, we're looking at dollars that come in the business and how we allocate them. And I think under that framework, most of the time, the old Earthstone bonds will win out.

John Freeman: Okay. So just to make sure I understood, Guy, it may be more likely that 2031 would be the ones that would be tackled.

Guy Oliphint: Yes.

Operator: Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

Kevin MacCurdy: You made a comment earlier on the call about growth kind of being back half weighted when gas takeaway was more readily available. But just kind of curious how you see production trajectory throughout the year if you kind of keep this current activity pace? And any thoughts on where you could end up on an exit rate if that would be kind of higher than your full year guidance?

James Walter: Yes, 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 going to go further from Q2, it would, by definition, be back half weighted. I wasn't trying to read -- say anything beyond that. But kind of if you talk about longer-term growth, years, not months and quarters, I do think that should be in a environment where Waha is less of an issue. And frankly, we're pretty well protected already today and only getting stronger. I think as you think about kind of growth over the long term, growth has always been extremely free cash flow focused for us.

And I think we've been pretty clear with the framework that we're going to grow more in environments where the returns are higher and the payouts are shorter and we're going to grow less and kind of go back to more of a maintenance case in worse returns environments with longer payouts and lower returns. And that's driven by a combination of oil prices, gas prices we realize and the service cost environment. So 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 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. So 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 has certainly improved from where it was when we were sitting in February.

We just don't know when or how this ends and are in a really fortunate position that we can be flexible and position the business to react to -- higher for longer commodities or something that reverts to where we were closer to the year or really anywhere in between. So I think flexibility is a really great position to be in for us. And 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 pretty short notice.

Kevin MacCurdy: Great. And 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? And do you have any view that inflation or diesel charges or something could pick up here?

William Hickey: Yes. I mean we started to see diesel prices pick up at like, call it, the very end of March. So no, maybe not right but very de minimis inflation in the $685. Obviously, yes, diesel prices, depending on what you want to use as your baseline, they're up 50% to 70% over the last 1 month or 2. Outside of diesel, we have been able -- we have not seen any inflation outside of diesel. It's kind of direct diesel inflation or pass-throughs, fuel surcharges, pass-throughs from people that do a lot of trucking.

Operator: Your next question comes from the line of Phillip Jungwirth with BMO.

Phillip Jungwirth: 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 netback side to improve realizations versus Belvieu, just given that you now produce over 100,000 barrels of NGLs.

James Walter: Yes. I mean I'd say we're constantly chipping away at all our contractual NGL agreements to see where we can optimize that kind of I think pennies per gallon, not transformational things from Waha. But I do think that's something 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 prize on netbacks, getting away from Waha has been by far the most material, like we -- 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 at times at pretty disadvantageous Waha pricing.

So that's been our focus. On the NGL side, we've had no constraints. 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. So it's less of a concern but safe to say something we're always optimizing just like we are every part and every widget of our business.

Phillip Jungwirth: Okay. Great. And then 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 this?

William Hickey: 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. And we will -- we've watched kind of what I'd say Continental, who's probably leading the Woodford charge has done. 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 but it's a very exciting bench that we're probably in the kind of good position that we can be wait and see. So it's not -- 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.

Operator: Your next question comes from the line of John Abbott with Wolfe Research.

John Abbott: So you made some comments -- you are increasing workover activity. So my question really is on the trajectory of LOE. I mean you've also discussed how diesel is seeing -- and 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 the year? And what do you see as a normal go-forward LOE expense?

William Hickey: Yes, it's a good question. First thing I think is worth clarifying is like most of the workovers we do are, call them half for capital and half for LOE. Anything on an ESP or things that we think add to kind of incremental reserves fall on the capital side of the workover equation. So it is split, call it, 50-50 from CapEx to LOE. But yes, I do think that we had a abnormally low Q1 on the LOE side due to a myriad of things, the majority of it being that outside of that short winter storm, we had kind of an amazingly low, good temperatured winter. It was a very, very mild winter.

I think that the incremental workover activity, likely we're going to be back right wherever we thought we'd be kind of for the year, call it, we're at -- I think our midpoint of our guide was $5.45 per BOE on the LOE side. And I think that's probably where we will end up averaging for the year. They come with extra barrels. So it's not like you don't get anything in the denominator when you do it. So that would probably be our best guess today.

John Abbott: All right. Appreciate it. Then the other question is really back on sort of maintaining and potentially adding activity. So I mean, obviously, you talked about the focus on free cash flow returns. So my question really is, how do you sort of think about the price points about adding activity or [indiscernible] activity? If you add activity, do you hedge more? And also, do you -- if we do see a pickup in the potential future curve, if there's concerns about service cost inflation, do you want to get ahead of that? So how do you sort of think about those variables as you think about possibly adding or reducing activity?

James Walter: Yes. 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. And so 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 to 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 -- that's a really attractive return window.

And if you're seeing 18 to 24 months, that probably pushes you more towards the maintenance case. So 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 latest guide does show 6% year-over-year growth for 2026 versus 2025. So we do think this is -- 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 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.

Operator: The next question comes from the line of Jeff Bellman with Daniel Energy Partners.

Jeffrey Bellman: I wanted to go back just on Permian gas takeaway. So we're tracking like 10 Bs, close to 11 Bcf a day of new takeaway capacity over the next 5 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 going to be associated volumes, kind of what would be the driver on the oil production side of that? And then kind of the last part, could you envision a world in 2, 3 years from now where the basin is targeting gassier zones or making gas more of a primary objective?

James Walter: Yes. I mean I think we're seeing the same thing. I think people finally realize just building pipes out of the Permian is both necessary and profitable and kind of makes everything work better. So we're super excited about the activity. And I'm going to say the pipeline of pipelines, that's probably not the best English. But no, I think we're seeing the same thing. And I do think -- look, the short answer is we do expect to see continued meaningful gas growth out of the Permian over the next 5, 10, maybe plus years.

I do think we're going to 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 the zones that people are targeting as you go to full cube development or certainly as you go to 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, that capital allocation is naturally going to 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 ultra-high return oil wells that are going to 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 deeper or more gas-weighted developments but that's not likely to be for us in the environment as we see it.

Operator: The next question comes from the line of Paul Diamond with Citi.

Paul Diamond: 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 2H story as capacity comes online and Waha pricing stabilizes? Or are there, I guess, other factors that could bring that forward?

James Walter: Yes. I mean I think 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 negative 5 to negative 10 range like we've seen in the last few weeks. I do think we would plan to return those wells to production when it's economic to produce them again. And 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.

And we're not going to make gas wells produce just to do so to make Mcf. We're here to make money and we're going to always be making decisions around how to maximize cash flow. And it seems to us like the biggest no-brainer to shut in and curtail gas wells that we are losing money.

Paul Diamond: Got it. Makes perfect sense. And 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 kind of scale opportunities out there?

James Walter: Yes. I'd say the velocity of opportunities all trying to come to market at the same time is quite robust. It seems like a lot of deals trying to fit into this summer/fall window. I think for us, look, 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 kind of high-quality deals. I do think those for us are still going to 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. 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. But 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 to the greatest return for our investors. So I think, yes, we're definitely seeing more deals of scale in this environment and we think that's a good thing. 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. But I'd say seeing a lot this year, probably in excess of what we've seen in the last couple of years.

Operator: The next question comes from the line of Leo Mariani with ROTH Capital.

Leo Mariani: You guys made mention of pulling TILs forward. I guess you've got a goal of around 250 TILs this year. I 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? Just trying to get a relative order of magnitude here.

William Hickey: I think that kind of what we talked about today is, we could probably add 5% maybe, maybe 5% to 10% incremental TILs with doing the easy things. Easy is probably understating it. My team will slap me for that. But I'd say just like 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, like that is really kind of -- that's what we're doing in Q2 that we are 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 TILs or there's a return environment where you may consider dropping activity to get something that was closer to the base plan. But for kind of what we're talking about today, I'd call it 5 -- probably right around 5%, maybe a little over 5% incremental TILs to the year is probably the right number.

Leo Mariani: Okay. That's helpful for sure. And 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 speed in terms of drilling and completing and less bit trips out of the well to kind of get there. It sounds like a lot of that's in progress. Is there anything else out there that you may be seeing that maybe as you look forward, maybe another 1 year or 2, you think could be like the frontier of continuing to lower that cost number?

William Hickey: If I saw anything, we'd be doing it, is the short answer. We're always tweaking. If you think about just like wins we've had outside of just small incremental wins on the speed side, a couple of quarters ago, it was a new way of drilling out wells that kind of materially reduced drill out time, saved us, call it, $10 to $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 that 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, there's been a ton of capital put into not saving dollar per foot but trying to increase recoveries per section. And I don't know which one of these kind of test is going to be the solution or what combination is going to be the winning formula.

But 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. So 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.

Operator: [Operator Instructions] Your next question comes from the line of John Annis with Texas Capital.

John Annis: For my first one, you highlighted that the microgrids that lowered electricity cost by 30% at those sites. How scalable is that program across your asset base? And do you think that's something that could move the needle on LOE at a corporate level over time?

William Hickey: 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. So we're already at kind of, I'd call it, the low-cost solution. Within New Mexico specifically, I'd say our approach is, if there is microgrids, there's an upfront capital expenditure to reduce variable cost via electricity and kind of other generator maintenance over time. And 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 8 to date.

There are plenty more on the horizon but this is going to affect kind of corporate LOE by pennies, not by dollars, or not by quarters.

John Annis: Got it. For my follow-up, so 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 maybe moving further west to the western flank Ginnetti?

William Hickey: I would say -- I was going to say no but those 2 you just brought up would be areas that we are doing. So 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, very successful in that. The way we've done it has been more kind of if you think about it 1 mile at a time and we just kind of 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. And to date, we've had a ton of success with that. And then you get the other one, Avalon pushing north, like, yes, we love the Avalon.

We saw -- I mentioned this 1 quarter or 2 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 started to do that ourselves. So hopefully, that kind of answers the full question.

James Walter: 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, not quarters and months. So I don't think -- I think it helps on the margins today, the rates of return but I don't think it changes our long-term philosophy.

Operator: The next question comes from the line of Gabe Daoud with Truist Securities.

Gabe Daoud: Just one for me, going back to the water recycling comment. Just curious, like how much water recycling is currently being done? And then just from a disposal standpoint, is that something that -- I don't want to 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?

William Hickey: 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. And really, that's just given the partnerships we have with our midstream partners. We're in business with the biggest and the most well capitalized and furthest in front of our water disposal needs.

And contractually, I'd say we -- those are set up where that is a liability that's 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. But 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.

Gabe Daoud: Got it. Got it. Okay. That's helpful. And actually, just maybe one quick follow-up. If -- sorry if I missed this but just what was -- what's the commentary then around inflationary pressures, just from service providers attempting to get pricing on some equipment?

William Hickey: I mean to date, we have not -- the only inflation we've seen to date has been fuel related and actual diesel increases for diesel we consume and fuel-related surcharges.

Operator: There are no further questions at this time. Mr. Walter, I would like to turn the call back over to you for closing remarks.

James Walter: 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 returns for our investors. Thanks to everyone for joining the call today and for following the Permian Resources story.

Operator: That concludes today's conference call. You may now disconnect.

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