Permian Resources Aktie

Good morning, and welcome to Permian Resources conference call to discuss its second quarter 2026 earnings. Today's call is being recorded. A replay of the call will be available by visiting the company's website at www.permianres.com.

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

Thanks, Eldi, 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 risks 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. Q2 is a standout quarter for Permian Resources. We delivered record free cash flow of $751 million, an increase of almost 50% quarter-over-quarter and record free cash flow per share of $0.88. These results reflect our team's ability to respond quickly and decisively to a volatile commodity environment. Our activities this quarter are a reminder of the uniqueness of PR's business model. We can respond quickly to market conditions. We have a differentiated approach to sourcing and executing acquisitions, and we are relentlessly improving the capital efficiency of our business on a go-forward basis. All of these characteristics support the goal we are all aligned on, increasing free cash flow per share over the long term to create shareholder value.

Turning to the quarter. Oil production came in at approximately 198,000 barrels per day, up 3% quarter-over-quarter. Slide 4 shows the key drivers that drove that oil production growth. When oil prices moved higher, our team in the field responded immediately. We increased the number of workover rigs by 50%, which improved run times and quickly accelerated incremental barrels. At the same time, our successful ground game drove working interest in completed wells to approximately 82% for the quarter, up materially from our original expectations of 75%. Combined with strong well performance, these actions generated 6,000 barrels per day of oil growth quarter-over-quarter for cash capital expenditures of $521 million.

One thing I'd highlight is our continued success in increasing working interest ahead of development. This has always been part of the PR playbook, but our BD and land team have executed at an exceptionally high level this year. We view these acquisitions as some of the highest rate of return deals that we do, given that their near-term impact as evidenced from our higher working interest not only in Q2, but also for the remainder of the year. Incremental workovers and ground game transactions are exactly the types of investments we want to make in a volatile market. Both generate incremental oil production and cash flow almost immediately, allowing us to recycle capital quickly and derisk returns through shorter payback periods.

Turning to natural gas. Our team demonstrated their relentless focus on maximizing free cash flow as they navigated a severely depressed WAHA market during the quarter. As many of you are aware, WAHA natural gas prices averaged negative $3.14 per Mcf during Q2 and traded as low as negative $9.52 per Mcf. So rather than selling natural gas at negative prices, we proactively curtailed production on high-GOR wells with WAHA exposure, reducing natural gas production by approximately 20% quarter-over-quarter. The curtailments, combined with our firm transportation and hedging, allowed us to realize a natural gas price of $0.38 per Mcf for the quarter and an uplift of over $75 million of revenue on our natural gas sales. When WAHA pricing improved in late June, we returned all previously curtailed wells to production without any operational issues. I want to give a big shout out to the field team for putting in the hard work to make this possible during the quarter.

On the D&C side, we offset inflationary pressures from rising diesel prices with continued operational efficiency gains through longer laterals, increased water recycling, deployment of water-based mud and new wellbore designs. We've also begun surfactant trials on completion and production operations. We're still early in evaluating surfactants, but we're encouraged by the initial results. Between continued operational efficiency gains and the potential to improve recoveries, there are a lot of ways for us to continue our path of increasing capital efficiency.

As you can see from today's results, the quality of our assets, combined with our basin-leading cost structure, has driven a step change improvement to our business over the last several years. As a result, we achieved record free cash flow in Q2 of $751 million. This is more than we generated in all of 2023, and we expect full year '26 free cash flow to be nearly double what we generated in 2024.

And with that, I'll turn it over to James.

Thanks, Will. Before we start talking about what's been a great start to our 2026 BD effort, we want to discuss how Permian Resources approaches acquisitions and how that fits with our value creation story. When we founded Colgate in 2015, we moved to Midland with exactly 0 acres, 0 production and Will and I were sharing a single 200-square-foot office. Our goal at the beginning was to buy high-quality assets, operate them efficiently and underwrite them conservatively so that our invested capital would generate real cash-on-cash unlevered equity returns. And from those humble beginnings, we grew Colgate from an idea to the business it is today with over 500,000 net acres and over 200,000 barrels of oil per day. But our focus was never to build a large-scale business as Permian Resources now, but rather to maximize the return of every dollar we invested in the business.

So how do we get here? Because we've honored the same strategy and philosophy in how we underwrite and how we operate, we're working relentlessly to find deals that meet our very high underwriting standards and targeted full cycle returns. And we use that time and time again, small deals add up, you create value for shareholders, and the business naturally gets bigger. With that, I'm excited to talk about what we've done in 2026 to date.

Starting with the largest deal on Slide 8, we closed on an acquisition of approximately 2,000 net acres and 5,000 Boe a day in Ward County for $520 million. This acreage directly offsets our existing asset base is 100% held by production, and provides an extended runway of high-return inventory. Shortly after we closed on the Ward County asset in July, we signed a trade agreement with an offset operator, utilizing a combination of the recently acquired bolt-on acreage, the legacy PR acreage and some other acreage that we have. This acreage helps address some of the challenges with the stand-alone Ward County acquisition, namely, being majority non-operated, low working interest and somewhat scattered. The trade also increases the number of operating net locations from 50 to 120, while increasing the average lateral length by 20%. We view this trade as a true win-win for PR and our counterparty, who is a valued industry partners as it helps them to further core up their acreage position and increase their working interest in their own operated units. We expect the trade to close during Q3.

Finally, the Parkway bolt-on project in Eddy County is a great example of how our proprietary data and Midland relationships create opportunities others simply do not see. Following the success of a delineation well we drilled in late 2025, we quietly assembled a contiguous position of approximately 15,000 net acres with 2-mile lateral lengths and an 82.5% 8/8ths NRI. Our partner in this deal, Tascosa Energy Partners actually brought this deal to us over drinks in Midland. We've been fortunate to know this team for a long time and bought a big deal from them a couple of years back. But I think more importantly, this deal is a scaled example of the Midland-born deals that we do with our friends and partners on a regular basis, and that we think provides a real competitive advantage to Permian Resources.

In total, year-to-date, we've acquired approximately 55,000 net acres in the core of the Delaware Basin for a total consideration of approximately $1.05 billion, executed through roughly 190 separate transactions. These acquisitions added approximately 330 high confidence, high NRI locations that immediately compete for capital in our portfolio. Ultimately, we think the valuation metrics for the deals we have done so far this year speak to the strength of our approach. $13,000 per net acre, $8,000 per net royalty acre and $2.5 million per net location.

Slide 11 summarizes why we believe our acquisition strategy is truly differentiated. Our focus is on buying high-quality assets, pursuing accretive transactions where PR has a commercial technical or operational advantage. We continuously hunt for off-market deals and look for areas where we have distinct advantages or can create an edge that allows PR to underwrite higher full cycle returns. The edge can come from our leading cost structure, proprietary service information or simply access to a deal that isn't widely marketed. While this is not easy and requires a ton of work, we pride ourselves on being creative and not afraid to lean into harder, less obvious deals. We are confident we'll be able to continue this successful track record for years to come.

Our financial discipline allows us to execute meaningful transactions like we have announced today, while retaining a fortress balance sheet, with Q2 leverage of approximately 0.5x and expected year-end leverage of approximately 0.5x. All of this leads us to our updated and improved plan for 2026. As Will mentioned in his prepared remarks, the success of our ground game has allowed us to significantly increase our working interest for full year 2026. This will allow us to meaningfully grow production while maintaining the same completion crews, rig count and operating efficiencies we have achieved this year. Our updated production guidance of 199,000 barrels of oil a day for the full year 2026 is 10% higher than 2025, while our CapEx midpoint of $1.95 billion is approximately 1% lower than the capital we spent last year. This all highlights the strides that our team is making to continue to improve the capital efficiency of our business and to grow free cash flow per share every year.

Concluding with Slide 14, our focus on full cycle returns has allowed the company to generate outsized value creation for our investors. $1 invested in Colgate in 2015 would be worth nearly $50 today, representing a greater than 50% compounded annual return. And we've continued that same philosophy and performance at scale with Permian Resources, nearly tripling our total shareholder returns since formation in 2022. Most importantly, our business model has not changed. We are confident in the combination of our high-quality asset base, peer-leading cost structure and differentiated approach to acquisitions will continue our track record of long-term value creation. We live in an industry that in some ways has been defined by consolidation and scale, but we'd like to be defined by prudent investment of capital, free cash flow per share growth and ultimately leading total shareholder returns for our investors.

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

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

Obviously, the ground game M&A has been a staple of you all for the last number of years. And it looks like you had a pretty successful run here in the last couple of months. Can you give us a sense of what you see moving forward on the M&A landscape? And also how do you kind of compare and contrast the activity you've been doing versus looking at some of the larger packages that are a little bit more, I guess, competitive like the federal lease sale or marketed deals?

Yes. Thanks, Scott. I mean, I think on the ground game side, I think that's an effort that's been kind of building and consistent for the whole 11 years we've been running this business. We've got pretty much the same team, the same people that are kind of operating at an extremely high level. So I mean that may ebb and flow a little bit from quarter-to-quarter, but I think over years, we are really confident we can continue to kind of execute and grow that part of our business. I think the opportunity set in front of us looks as good as it ever has, and we're kind of excited and confident that we can continue that, but it may not be the same every single quarter, but we really do believe in the kind of long-term viability of that part of our business.

In terms of larger packages, look, we've always -- we kind of look at everything in the Delaware. I think you should assume we are kind of in the mix and evaluating any package of quality that is out there on the publicly marketed side. I think what we've seen in some of these deals and some of these federal lease sales or state lease sales is that, they're good assets. I mean the kind of -- there's been some really good stuff that transacted this year, but I think our focus on full cycle returns and generating outsized equity returns for investors, I think, has us being really disciplined on purchase price. And I think kind of -- are some of those assets that transacted assets we'd like to own? Absolutely. But we're we able to get to those purchase prices and still achieve our targeted returns? The answer is no.

So I think for us, it's all about focusing on kind of full cycle and long-term value creation. And if there's bigger packages that meet those return thresholds and standards, then we'll be excited to do them and not -- and we'll continue to be patient.

Got it. And my follow-up question is more kind of Permian, I guess, macro related. Certainly, with new egress coming on for pipelines. You're seeing probably a next surge of gas coming, including your production was offline. But like how do you see activity pace from a lot of kind of offset operators, any kind of non-operated activity with improved egress? And do you expect a surge of production? And I'm just kind of curious on oil takeaway capacity, if you think that becomes a constraint in the next couple of years or so.

Go ahead.

I'd say kind of hitting the last part first, we feel really good about oil takeaway capacity for the next few years. I think I'm kind of -- we're also hopeful that we've all learned a good lesson on kind of the gas situation we've been in the past 12 months that you got to get out there years ahead. We're fortunate on the oil side, we've got a lot of capacity today and expect that to be the case. We continue to grow for years to come in the Permian, which I think is not guaranteed, but certainly possible. I'd say at this point, we're confident our midstream partners will be working with people like us to kind of get further ahead of that.

And on the gas side, we haven't seen any meaningful reaction kind of from an activity level. I think it seems like the pipelines that are coming online this quarter we're able to handle the new gas that we brought back online, kind of any incremental growth today. And I think we're hopeful that we're entering a new era in WAHA gas where you get past this period of dislocations, and we have pipeline capacity that's now going to be able to keep up with Permian growth. So I'd certainly say the environment and the attitude has changed. I think there's a new eagerness and desire to build pipelines coming out of the basin. And people do believe this basin is going to grow its gas volumes for a long time. And there's a lot of exciting downstream demand things. So I think we feel a lot better about kind of both crude and gas than we have gas in the last few months.

Your next question is from the line of Neal Dingmann with William Blair.

James, maybe staying on the same vein, my first question just around M&A specifically. Is it fair to say that the Parkway bolt-on suggests you all continue to have more confidence as you move northwest to Eddy County? And just wondering either there or again, further into Lea, would you all continue consider moving just further north in New Mexico overall?

Yes. I mean I think that kind of Eddy County area where this Parkway bolt-ons has been -- that's been a tremendous asset for Permian Resources since we bought our first deal there back in summer of 2016. And I think, we've seen it continue to work as you push modestly west and modestly north. I'd say we've been surprised by how strong the well performance is, for example, in the kind of area that you're referencing today. And I think we see a lot of white space. I also think the white space maybe moving north and maybe moving west, but there's also still a lot to do kind of in and amongst our existing position. There's a lot of white space on the map between our existing assets. And I think I'd say, honestly, most of the bolt-on activity, that's active now is more kind of in between the yellow on the map, if you will. But we still see a lot to do in what we call the Parkway area of Eddy County and are certainly excited about the well results we've seen and excited about what we think could be coming.

Perfect. And then my follow-up just on capital allocation, maybe for you or Guy or Will. Just specifically, we've seen at least a couple of your peers, if not more, now recently boost activity, I guess, in the last few months. Do you all believe production growth in this environment is appropriate given the commodity backdrop and maybe if not, is the plan just to keep building cash?

Look, we don't like to forecast our plan for next year or anything like that. I'd say with regards to 2026 and what oil prices did kind of at the beginning of this year. I think we were strong believers that this was an environment where it made sense to invest a little more capital and grow production more than the kind of flattish expectations we had coming into the year. Like Will has talked about in his prepared remarks, we're proud of team, how quickly we could respond, and how quickly we could bring those barrels.

As far as growth from here or growth next year, I think that's just really going to depend on the returns environment. We've always talked about growth in the returns-driven framework, and we have high oil prices, low service costs, like you'll probably see us in growth mode. And inversely, if we have lower oil prices and higher service costs, I think you'll see us back to maintenance mode. So I think it's just going to depend on kind of how the macro settles out. I think today, it's probably too early to tell what next year looks like, but we'll keep watching it and we've proven we can react quickly when the time comes.

Your next question is from Neil Mehta with Goldman Sachs.

Yes. Just continued operational momentum as we think about your production. And so James, I'm wondering if you can talk a little bit about some of the things that you're deploying out in the field to stay ahead of the expectations operationally.

Yes. I mentioned a few in the prepared remarks, I'd say one that I feel like I hit on every quarter, which is really, really important to the kind of both the production and the completion cost of the business is water recycling. And so we had another tick up on percent water recycled in Q2. I think it's the highest quarter we've had in PR history. So we are continuing to make progress on kind of incremental water recycling. We've got a great relationship with a big water company in New Mexico. And as they continue to build out an integrated system, I'd say we are a big beneficiary of that.

And then on the drilling side, which is I think if you think back to kind of my Q1 comments where I thought there was some low-hanging fruit or maybe not low anymore, but kind of the next level of step-up would be on the drilling side. And we're making a few changes there. I'd say, one, we started to introduce water-based mud in areas where we take losses typically and with oil at high prices, I'd say the payback on taking a little bit of a loss of water-based is pretty meaningful, kind of, call it, $5, $6, $7 a foot of savings on those wells.

And then the last one would be, we've kind of transitioned to a slimmer hole design in New Mexico. Same long stream still run 5.5-inch all the way back to surface, but running it inside 8 5/8s instead of 9 5/8s. And that savings in steel, especially as casing prices are projected to run up in the back half of the year, savings in time, just smaller holes drilled faster and then savings in cement. So I think that kind of if you think about looking forward, obviously, we are willing to take the increased diesel prices with the increased oil revenue, but we do have some inflationary pressures with respect to diesel and casing. And to date, have been able to offset that through gains like what I just talked through.

That's helpful. And then just your perspective on lateral lengths, too. I mean I would imagine with these bolt-ons, you'll be able to extend these laterals through -- given you're able to block up the acreage a little bit more. But give us a sense as you think about the portfolio, how long you can get these laterals to? And what does that mean from a P&L perspective?

Yes. I mean lateral length is the most effective way to reduce D&C per foot, I think we've slightly ticked up every year for the last 2 or 3 years, kind of moving from just under 2 miles to now kind of right at 11,000 feet. We mentioned in the deck that we drilled our first 4-mile lateral in Q2, and that was a big success. So I think what it really means is the combination of our willingness to drill longer our ability to drill U-turns when needed and the blockiness of the position that you'll continue to see lateral length tick up over time. I don't think that we are in a place where you're going to see some like step change where we go from 11,000 to 15,000 year-over-year, but I do think the kind of 500 plus or minus feet longer each year is probably typical of what you should expect going forward.

Your next question is from John Freeman with Raymond James.

In the slide deck, you sort of show the capital allocation strategy and at least the first half of the year, it's been pretty skewed to these really nice accretive acquisitions along with debt repayment. You've got leverage now at the bottom end of sort of your kind of leverage target range. So just sort of thinking, I guess, going forward, if there's any sort of maybe change in the way you all think about your cash priorities across kind of acquisitions, balance sheet, buybacks, maybe even growing the dividend?

Yes. I mean I think growing the base dividend consistently over time is a priority and always has been a priority. So I think that's something you'll continue to see for us kind of in the future. I'd say other than that, we don't have any plans to change our capital allocation program. I think we have is working really well today. Obviously, the business is generating a lot of cash. We've been able to both pay down considerable amounts of debt over the past 2 years and do a lot of acquisition activity, all while delevering the business to the 0.5x it is today. So I think now for the foreseeable future, I think our capital allocation strategy is working, and you'll kind of see us hold the course.

Okay. And then on the back of all the accretive acquisitions, obviously, most of these have been just the perfect deal where you're just increasing working interest and field you're already there, but there are some examples of you all doing some transactions continuing to push the boundaries further out on your acreage footprint. Does that necessitate any sort of infrastructure investments that we should be thinking about in the upcoming years?

No. I mean, nothing outside of what's already baked in our plan and our budget for the year. I think these areas that we're kind of more active in are still right next to existing PR offset operations today. So I think it probably is pretty easy. We've got the right partners where we need on the midstream side. And frankly, kind of all the stuff we're doing really is 1 mile or 2 away from the existing PR ops. So kind of nothing out of the ordinary there.

I think the only exception that would be the Ward County bolt-on, there'll be a minimal, call it, like $25 million of incremental CapEx associated with just taking over a new asset.

Your next question is from the line of Kevin MacCurdy with Pickering Energy Partners.

I guess for the first one, can you guys bridge the old production guidance to the new production guidance and did the same thing on CapEx, maybe breaking out the contribution from the higher working interest, the production you bought and then any pull forward or outperformance?

Kevin, it's Guy. On production side, we were at 192,500 barrels a day at Q1, our guidance after Q1 are at 199,000 today. The only production we acquired with this $1 billion of acquisitions was 2,500 barrels a day of production at the time we closed the Ward County bolt-on a week ago. When you take that over a year, that's 1,000 barrels of the 6,500 barrels a day increase. The significant majority of the remainder is just higher working interest in our 2026 projects, as we talked about, with a little bit of contribution from accelerated workovers.

On the capital side, we're up $100 million, $25 million of that is just kind of some of the takeover costs associated with the Ward County bolt-on just putting in equipment that's our standard and things like that. And the remainder is also just higher working interest in the '26 TILs. We took our guidance from 75% to 80% to over 80% working interest in 2026 TILs. So I think when you put all that together, it's really capital efficient. And you can see that in the kind of increase in capital relative to the increase in production.

I appreciate that detail, Guy. And then maybe for the follow-up, is your gas production back online now that WAHA prices are better? And can you give us any kind of sense of the cash flow uplift you're seeing for the back half of the year just from better gas prices?

All the wells are back online. We brought them online kind of at the very end of June, right when WAHA rebounded, and we've had all the wells online since. So Q3 and Q4 will be much more normal looking with respect to gas.

And Kevin, on cash flow uplift, I think we're probably hesitant to forecast gas prices in the back half. But we produce over 750 million a day net. So regardless of where we end up, given where WAHA is today, $1.50, $2 in HSC and [indiscernible]. It will contribute in the back half of '26. And that's why we put the commentary in there about '27 as we think about growing free cash flow over time. We've done that with the real headwind of realizing almost nothing from our dry gas stream. And I think both the curves and our transportation in '27 set us up for a much better answer year-over-year.

Great. I appreciate that. And totally understandable, you wouldn't want to predict gas prices in this market.

Your next question is from the line of John Abbott with Wolfe Research.

So a question is really on CapEx and recognizing that you don't want to give -- talk too much about 2027. But for 2026 from the increased working interest and also from some carryover from Ward, you've increased full year guidance by about $100 million on the midpoint. If you kind of annualize that as maybe it's $200 million, is that a reasonable step-up as one sort of thinks about 2027, if you were going to maintain flat production, or are there other factors that need to be taken into account as you sort of think about the CapEx next year?

I mean I think one thing just to correct is the majority of that $100 million increase happened in Q2. And so I don't think you can double it to annualize it. I think that is the annualized increase. If you want to think about this year, we came into it, we were going to spend $1.85 billion and grow production minimal. And now we're going to spend $1.95 billion and grow production by 10,000 barrels a day. So it is a very meaningful kind of increased production and that $100 million is annualized.

I think if you look going forward, I guess if the question is, where is maintenance CapEx. I think if we continue to spend at, call it, the $1.95 billion to $2 billion range, we will continue to grow production. So maintenance is south of there. And that's a growth case. And I think where we stand in '27 between do we want to grow, or do we want to be in a maintenance cases, obviously, very much subject to what the markets look like when we get there.

But I mean like that $1.95 billion grew production 10%. I think that's a pretty substantial growth rate. And like I'd say as we think about it, that's highly capital efficient. So I'd say if you think about our business today, that's 17,000 barrels per day year-over-year growth and 10%. So I think that's a pretty cool capital efficiency story.

Extremely helpful. And then just you had the step-up in activity on the workover activity in 2Q. How does this workover activity sort of trend for the remainder of the year?

It will normalize. The step-up in Q2 basically chewed through our entire backlog of workovers. So we are back at normal course just kind of fixing wells as they come offline, and that will be with a rig cadence that's more like what we've done in Q1 in the past.

Your next question is from Phillip Jungwirth with BMO Capital Markets.

Can you provide some background information just on what you did here in Ward County with the bolt-on and subsequent acreage swap? I mean it looks like you executed acreage trades between 2 or more parties that gave you a larger operated position. Just wondering if there's similar opportunities where you have large operators with legacy checkerboard acreage positions and just how much of a discount you typically see for non-op acreage?

Yes, sure. No, that was a really cool deal. I think kind of a lot of things came together kind of our team, great collaboration with, as you mentioned, multiple counterparties on the kind of the trades in the Ward County bolt-on, and yes, I think we love it when you can find opportunities like that, that are win-wins and make your position better. I think actually, it's an interesting question. I'd say, honestly, this year, we haven't talked a lot about it. And maybe we should in our next release, but this has been a really busy year for us on the trade front. I think we're finding more opportunities to kind of net up our own working interest, trade out of non-op and into operated positions, like you see here.

So yes, I don't know if we'll see any that are kind of as big as this in the back half of the year, but we've certainly done some big ones to start the year, and it's something that we're always working on.

Okay. Great. And then can you talk about some of the productivity initiatives such as surfactants, completion design changes? Just how many wells you're looking to deploy surfactants on this year? And you mentioned you're encouraged by early time results. Just any color here or expectations for incremental costs?

Sure. On the completion side, we've pumped 2 surfactant trials on 2 different pads with kind of test -- or control wells and test wells. One of those is online. One is we've pumped the fracs, but the wells are not yet online. That's probably where we'll stop for this year. We'll look at that data kind of see what we see early time with water-to-oil ratios and see what we see kind of over the 60-, 90- and 180-day period as we kind of head into next year should be in a good place to have a feel for how big of the program that could be.

I'd say on that side, it's just too early to tell. And then on the production side, there's 2 or 3 pads across both basins that we have pumped kind of surfactant more in late life kind of typically around an ESP failure and have seen, I'd say, uplifts up to north of 100 barrels a day and some that are kind of de minimis. On the average, that program has been very economic, kind of, call it, sub 1-year payouts on the aggregate, inclusive of the wells that we saw basically no uplift.

So that's where we're very encouraged is that even with the dispersion of results from really, really effective to less effective that the program on average has been very economic. And so I'd say what the team is working on now is how do we do more of the 100-barrel a day uplift and less of the 0, or what could we do differently on the wells that we didn't see an uplift? But I think that's going to be something that probably is a real part of the program to go forward. It's just kind of -- we got to figure out exactly how much and exactly where we're going to do it before we can kind of roll it out as part of the go-forward plan.

Your next question is from Oliver Huang with TPH Research.

Just kind of looking at what you all picked up on the New Mexico side. I think one of the things that goes overlooked sometimes is just how this is fairly virgin rock, you're picking up. You all referenced the Tascosa well in the Northwest Parkway area being a bit more of a step out. Are you all 100% confident at this point with carrying out your development program there? Or are you going to need to do a bit more basal work up there to feel comfortable with the entirety of that block?

Yes, that's a good question. I think we're really comfortable in the primary zones. I actually think that's a great kind of nuanced question that we didn't address in our script. Like I'd say, our base case underwriting kind of the deals that the locations that we actually paid for, we are highly confident. And I do think as you get to some upside zones potential, I think whether that's 2 or 3 productive zones or 4 or 5 productive zones is still TBD. So I do think we'll continue to learn about the Parkway area and that kind of Tascosa acquisition specifically over time. But have a really high degree of confidence in what we're calling kind of proven locations that kind of go into that 330 locations that were underwritten. And I think over time, hopeful and would expect to see some of those upside locations kind of proven up and coming into the money.

Okay. Perfect. And maybe just for a follow-up, just on the op side. Could you maybe provide a bit more detail in terms of just -- I mean, you all call out wellbore design improvement, which Will spoke to earlier, but just optimization of the power supply compression fleet as well. Just how much of that is already flowing through the financials today, and how much more running room do you see on both of those fronts.

Well, I think that there's a decent amount flowing through the financials today. I mean we've run at this point, 7 or 8 microgrids across New Mexico and areas where we historically have been on generator power. If you want to think about run room of that going forward, like there's definitely more to do, but it's really going to be New Mexico-centric as we are on line power in the Texas, Delaware.

Same thing on the compression side, like as we're optimizing that, it's going to be in areas where -- what we've seen is where we have -- we end up with better run times across the board if we're on microgrid as opposed to kind of one-off generators, just think about flipping the light switch like cycling it on and off is not good for run time of equipment like ESPs and things like that. But really, all of this just kind of comes together to, I think we've seen a tremendous ability for us to kind of hold LOE flat or even reduce it over time, which is not, I think, not normal and not what you'd expect. I mean we kind of -- I feel like we've always been at $5.50 a Boe LOE company. And if you look at where we were in Q1 and even where we were in Q2 with a meaningful amount of our Boe shut in due to gas curtailment, we're still kind of pushing closer to $5 per Boe.

And I think that's a testament to what we've done in the short term. And there is still stuff to do. I feel like beating a dead horse, but the water recycling side is a big needle mover on water disposal is our largest LOE cost. And the more we can recycle the more we defer and ultimately save on the LOE side. So those are the initiatives that we're working on real time. I think all of them matter, but if you can do them all together, that's when you really move the needle.

Your next question is from Josh Silverstein with UBS.

Just want to see if we can get a bit more detail on the royalty acquisitions versus the leasehold acquisitions here. Were these done in separate transactions done together where you have both the leasehold and the royalty? And I guess maybe along the same lines, like we typically think of the royalty value was a bit higher, you guys are having a lower price paid for the royalty acreage versus the leasehold. So just a little bit more detail there would be great.

Yes. I mean, I think kind of -- I'd say the royalties historically and in this first half of the year come as a mix of kind of straight minerals and royalties acquisitions versus kind of high NRI leasehold. I'd say for us, it's tended to be more weighted towards kind of higher NRI leasehold. I think the minerals and royalties on a stand-alone basis can get really expensive. And frankly, we struggled to always -- to be able to buy very much at kind of our return thresholds.

But yes, I think -- going forward, I think we will continue to target both. I think it's probably safe to expect more of our royalty acquisitions to come paired with leasehold because I think we can bring kind of the full suite of PR competitive advantages to bear on the cost-bearing interest combined with the royalty.

In terms of prices, look, I think what you're seeing on low dollar per net royalty acre values, it's just kind of the output of us acquiring these deals at attractive prices. Like I think we talked a lot about the creative things that we've done. And those creative things allow us to buy both, I'd say, the leasehold and the royalty interest at what we view as really attractive and you may view as lower prices. But I think that's a really good thing, and it's something we're hopeful to continue to be able to do.

Yes. Thanks for that detail here. And then maybe just along the same lines, I was curious to see if there's any shift in development plans given the leasehold and royalty acreage that you've acquired? Do you now have a bit more capital going towards the Texas assets? Do you still favor New Mexico? And I'm guessing, the goal is to try to keep your working interest now at higher and higher levels. So any update there would be great.

I think it's about -- it's going to be basically the exact same as it's always been. It will be, call it, 70% of the development, maybe a little north of that on the New Mexico assets and the rest in Texas, and that's consistent with where we've been the last 2 or 3 years.

Your next question is from the line of Gabe Daoud with Truist.

I know it's hard to kind of nail down these opportunities. But I was curious, guys, if you could maybe frame what the spend on land could be the rest of the year? You've done $1 billion or so year-to-date. Just curious if you maybe have any kind of framework around additional spend from here?

I think the answer is no, we don't. We kind of -- we're always looking. We're always on the hunt and we're going to continue to buy things and we can find high-quality assets at prices that make sense for generating attractive full cycle returns. But now, I think, we've got good momentum. I think we're kind of the ground game continues to chug along, and we're having a lot of success there. But I think in terms of trying to predict exactly what it looks like over the kind of next 12 months, I think that's hard to do.

Okay. Okay. Understood. No, that's fair. And then I guess just a quick follow-up for me, you talked about the surfactants and productivity, potentially improving from here. Just curious, maybe can you quantify or talk about what else you're doing on the productivity side, and if we should expect -- still expect flat productivity from PR year-over-year, particularly with all the new assets?

I'd say like, look, there's a long list of things we're doing. The hot topic today is surfactants. And if you want to think back 6 months ago, it was on lightweight proppant. And in the middle, there's been a bunch of tweaks of cluster spacing, completion design strategies, et cetera. I think the right kind of approach that you all should think about PR is that we are testing, trialing and studying all of it, and we'll probably -- I think we're better suited to speak to exactly which ones are the big winners kind of once we get there.

But really what it means for well productivity, I'd say not driven by step changes in oil recovery percentages, but really just by the duration and depth of the inventory, I think your expectation is the '27 or rest of '26 and '27 productivity will be the same as it's been in '24, '25, '26. We are still kind of marching across our position in both New Mexico and Texas drilling the same benches in the same way and expect the same productivity as we've seen in the past.

Your next question is from the line of Leo Mariani with ROTH.

I was hoping if you can provide a little bit more detail on kind of where cost per foot may be headed here. In the second half, you mentioned some inflationary pressures. I think in some of your prepared materials. You kind of said well cost per foot are pretty flat in 2Q versus 1Q. Do you expect those to go up at all with inflation in the second half? Do you think efficiencies can basically counteract all that? And I think you had talked about a $675 per foot target at one point. I just want to get a sense of are we there at this point? Or is that something you're hoping to get to later this year?

Yes, I'd say obviously, the run-up in crude and kind of demand on steel, et cetera, associated with the war has put some pressure on where we were targeting for the year. But we've done a really, really good job offsetting that. I mentioned some of the efficiencies we've picked up on the drilling side, on the water recycling side. We've had got some small wins on the sand side. So it's not all inflationary pressures. We've had some kind of big wins on the efficiency side to get here to date. I think a lot of that shows up just with the incremental. Now we're just north of 80% working interest in the back half of the year, and we're still able to keep CapEx sub $1 billion kind of speaks to -- are we going to achieve $675? I'd say that feels like a longer putt than it was when we came into the year, but we're still very much on target as far as where we came into the year at and at least holding the line flat or maybe slightly improving.

So it's really a hard answer to give, Leo, just given like fuel is such a big component of our of our spending, and I just have no idea where fuel and crude prices are going to be between now and year-end. But I think that if oil prices dip and fuel resets back to where we came into the year, I think $675 is absolutely in our sights. And if oil runs, I think it's probably less likely, but we'll take it on the revenue side.

Right. Okay. Makes sense. I know it's really difficult to forecast your success on the M&A front, but maybe you can just talk about the deal pipeline? Is it sounds like it's very robust right now. Certainly, you executed a lot of deals in the first half. Is the deal pipeline just as robust today as it was in the past handful of months. So are you getting a lot of looks here.

Yes. I mean I'd say just kind of we've spent $1 billion in the last 2 years, kind of '24 full year and '25 full year. We've kind of already achieved that same pace halfway through or a little over halfway through 2026, I think it's probably safe to say we will exceed the last 2 years average this year. But yes, the ground game, we're seeing a lot of stuff. I think that, like we've said in the past, that's pretty consistent kind of every month in, every month out, we're finding opportunities on the ground game side, and the bigger stuff can be lumpier. But I'd say we're getting a lot of looks.

I think we'll reference like there are a ton of deals kind of coming to market at the beginning of the year. I think we've seen maybe half of those kind of run their course and there's still some out there that could be interesting. But I think for us, definitely nothing big, imminent to kind of -- there's some ground game stuff that's always getting done day in, day out. But for us, it's just taking it as it comes and making sure we do the right opportunities at the right price and pass on the deals that don't make sense for us, and we've done a really good job of that. So we've got a ton of confidence it will keep working going forward.

Your next question is from Paul Diamond with Citi.

So we've seen a lot of discussion about emerging benches across the Midland and Delaware. I guess, how do you guys see that developing on your footprint? And I guess any update from the last time we spoke about it?

Last time we spoke about this, I'd say, I mentioned kind of the success of the Avalon and kind of some of the deeper Wolfcamps moving north in Lea County. And I'd say that is happening and happening extremely well and very quickly, so to speak. I mean our -- we had drilled a few Avalon up that far north as of the call last quarter. But I'd say since then like full development, stacking Avalon, it's been some of the most productive wells we've drilled.

So those types of emerging benches, think of it as benches that have been developed historically on the state line area moving up north into our Lea County and our Eddy County position is very much happening. We're seeing the same thing on our Eddy County position with something like the deeper Wolfcamp. Typically, we've drilled first sand, second sand, third sand and X, Y on the North Eddy, and we're starting to see deeper Wolfcamp move in that direction.

As far as like the total new benches, which are where I think you were alluding Woodford, Brushy, things like that. We own it on some of our assets, and other assets, we don't. But I'd say it's something that we're keeping our eye on, but it's not a core bench. It's not something that's going to be a big part of our development plan or really any part of our development plan in '27. I think that it is -- we've seen some of the most prolific wells in the basin drilled in the Woodford and some of the biggest dogs. And so we're just kind of going to watch and see and hopefully let serendipity kind of come our way to the extent it does.

Got it. Understood. And then I guess, over the course of like the last year or so, you guys have worked pretty diligently to kind of rightsize the realization expectations around nat gas. Are you guys happy at the current level on a go-forward basis? Or should we expect a bit more movements in kind of those, whether it's FT or hedging or just kind of how you think about locking that, what is this, the volatile pricing down?

Paul, it's Guy. I think we feel great about the deals we did. We identified this as an issue a couple of years ago. And I think the -- not just the long haul that we are kicking in kind of late this year and early next year, but the interim agreements we had with some of those partners this year have served us really well. And I think the capacity we have going into '27 covers roughly all of our net volume. So we're always thinking about what else should we do to optimize the portfolio, how do we handle growth in gas volumes that could occur as we continue to grow oil production and grow through acquisition.

And I think on the hedging front, we're just going to be opportunistic like we have. I think that we spend a lot of time thinking about appropriate basis and where we want to sell gas, but I view that more as optimization rather than something we have to do.

Your next question is from the line of Sean Mitchell with Daniel Energy Partners.

Will, you talked a little bit in the commentary about offsetting some rising costs by using water-based mud versus oil-based mud in the drilling, are you seeing anything in terms of drill time that is interesting? Or is it coming down with water-based versus oil-based?

No. I don't think water-based will be a time savings versus oil based. It's more just -- we've got some areas where you'll take some losses. And if you can run water-based instead of oil-based in areas you take losses, you save money really, really quick.

Okay. So it's more on cost savings than drill time?

Yes, that's right. I mean our drill time wins have been in this slim-hole design. I mean, obviously, when you go to 8 5/8s intermediate as opposed to 9 5/8s, you can drill a smaller hole and kind of everything goes faster. So that's -- if you want to think about the savings associated with slim hole, it's been like 50% of the savings is on drill times. We save almost a day a well.

Your last question is from the line of John Annis with Texas Capital.

John, do you have your mute on? We can't hear you. Okay. Operator, I think we can hand it back.

We can close the question-and-answer session. Absolutely. There are no further questions at this time. So I will now turn the call back to James Walter for closing remarks. Please go ahead.

Thank you. As you can tell from this morning's results, the business is performing at the highest level in PR's history. We delivered record free cash flow this quarter, responded quickly and decisively to a volatile commodity environment and add high-quality inventory at attractive valuations. All while maintaining an investment-grade balance sheet and the lowest cost structure in the Delaware Basin. We believe we are exceptionally well positioned to continue compounding free cash flow per share and delivering outsized returns for investors going forward. Thanks to everyone who joined the call today and for following the Permian Resources story.

This concludes today's call. Thank you for attending, and you may now disconnect.

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 20, 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, 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.

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

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?

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.

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?

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.

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

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.

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.

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.

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?

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.

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

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?

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.

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?

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.

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

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?

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.

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?

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.

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

Yes.

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

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?

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.

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?

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.

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

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.

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.

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?

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.

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

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?

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.

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?

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.

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

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?

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.

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

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?

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.

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?

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.

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

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.

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.

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?

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

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?

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.

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?

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.

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.

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

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?

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.

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?

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.

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 returns for our investors.

Thanks to everyone for joining the call today and for following the Permian Resources story.

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

Good morning, and welcome to Permian Resources Conference Call to discuss its Fourth Quarter and Full Year 2025 Earnings. Today's call is being recorded. A replay of the call will be accessible until March 13, 2026, by dialing 888-6606-264 and entering the replay access code 23999, or by visiting the company's website at www.permianres.com.

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

Thanks, [indiscernible], and thank you all for joining us. On the call today are Will Hickey and James Walter, our Chief Executive Officer; and Guy Oliphint, our Chief Financial Officer.

Many of the comments during this call are forward-looking statements that involve risks and uncertainties that could affect our actual results and are discussed in more detail in our filings with the SEC. We may also refer to non-GAAP financial measures. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation.

With that, I will turn the call over to Will Hickey, Co-CEO.

Thanks, Hays. We're excited to discuss our fourth quarter results as well as our 2026 plan this morning. We set records across every key operational metric in Q4, including our highest oil production, lowest D&C cost per foot and lowest controllable cash cost in PR's history. Our strong Q4 performance capped off an excellent 2025 with free cash flow per share increasing 18% year-over-year to $1.94 per share. This performance was achieved alongside meaningful debt reduction, demonstrating the strength and consistency of our core operations. We believe 2025 represents a highly repeatable year and a clear demonstration of the strength of our business.

As we look to 2026, our focus remains the same: maximize shareholder value through disciplined execution of our highly capital-efficient Delaware Basin program, and we're proud to lay out a '26 plan that we expect will continue to drive free cash flow per share growth going forward.

Moving into quarterly results. Q4 production exceeded expectations with oil production of [ 188,600 ] barrels of oil per day and total production of [ 401,500 ] barrels of oil equivalent per day. Our D&C team continued to execute at a high level, reducing D&C cost per foot to $700, resulting in $481 million of cash CapEx for the quarter and $1.97 billion for the year. In addition, we delivered leading cash costs supporting strong margins with Q4 LOE of $5.26 per BOE, cash G&A of $0.80 per BOE and GP&T of $1.18 per BOE. Strong production results paired with low cash costs and CapEx resulted in adjusted operating cash flow of $884 million and adjusted free cash flow of $403 million.

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

On Slides 4 and 5, I just want to highlight how strong 2025 was for Permian Resources. This marked our third consecutive year of strong operational execution as a public company, building on our previous track record as a private company dating back to 2015. The depth and experience continues to translate directly into results in the field. Including the bolt-on acquisitions we closed during the year, we delivered 5% higher oil production than our original '25 guidance more than half of that outperformance coming from improvements in the base business. That speaks to the quality and durability of our underlying asset base. At the same time, the team continued to structurally lower cost. On the drilling side, we increased drilling feet per day by 6% year-over-year by continuing to optimize BHAs and targeting in the lateral. In completions, completed lateral feet per day increased 20% year-over-year due to increased time frac efficiencies and other improvements.

And on the operating side, initiatives like our microgrid projects and runtime improvements led to a 3% reduction in LOE per BOE. We also strengthened the corporate cost structure by reducing debt by over $600 million, enhancing netbacks through marketing optimization and holding nominal G&A flat despite a larger production base. All of this directly benefits our '26 plan, which James will outline shortly. Given the marginal nature of free cash flow in our business, operating as a low-cost leader is a critical part of our plan to increase free cash flow per share over time.

Slide 6 highlights the details of the meaningful progress we've made improving our gas realizations by reducing WAHA. We laid the groundwork in '24 with key hires across midstream and marketing department, and we continued building that capability through 2025. As a result of the agreements we've executed, we expect to sell approximately 400 million cubic feet per day out of the basin in 2026, increasing to roughly 700 million cubic feet per day in 2027 and beyond.

Combine that with our existing hedge position reduces WAHA exposure to approximately 10% of total gas volumes in 2026 and improves unhedged gas realizations. Specifically, in 2025, we expect our gas realizations to be a roughly $0.40 discount versus WAHA. Through these recent efforts, we now expect to realize a $0.50 premium to WAHA this year.

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

Thanks, Will. Turning to Slide 7. We wanted to highlight the continued success of our acquisition strategy. During Q4, we closed on approximately 140 transactions totaling $240 million. This particular set of acquisitions was heavily inventory weighted and added 7,700 net acres, 1,300 net royalty acres and approximately 70 net locations at attractive valuations. The Q4 acquisitions capped off a great 2025 M&A program and our confidence in continuing to execute on this strategy going forward is as high as ever. We completed approximately $1.1 billion of acquisitions during the year, adding about 250 locations and 13,000 BOE a day within our existing operating areas. These 700 acquisitions consist of a large asset deal from Apache in New Mexico, several medium-sized bolt-on acquisitions and a substantial ground game that totaled over 675 smaller transactions.

For the third consecutive year, PR acquired more inventory than we drilled during the year, both increasing our inventory life and enhancing the quality of our go-forward plan. In addition to the 250 high rate of return locations that PR acquired through the year, PR also added another 200 locations through organic inventory expansion. We believe that our local presence in Midland, our peer-leading cost structure in the Delaware provide a competitive advantage as we pursue transactions that create long-term value for shareholders. Over the next 12 to 24 months, we are confident in our ability to continue to find attractive deals that drive value for investors and make our business better, just like we have the last 10 years.

Turning to Slide 9. We are excited to discuss our 2026 plan, which is focused on maximizing returns and free cash flow per share through consistent, thoughtful capital allocation and low-cost execution. This plan is a product of significant collaboration across the organization, and we want to thank our entire team for the commitment and effort behind it. For the full year 2026, we expect total production to average 415,000 BOE per day oil production to average 189,000 barrels of oil per day. We expect to spend $1.85 billion of CapEx for the year with approximately $400 million of that coming from non-D&C spend. Overall, this plan delivers production in 2026 that is approximately 5% higher than 2025 for CapEx that is $120 million lower.

Our development program in wellness will be largely the same as last year, and we'll continue to be focused on our high-returning Delaware Basin assets, with the New Mexico portion of the Delaware accounting for about 65% of activity and the Texas Delaware accounting for about 30%. We expect our average working interest, [indiscernible] & [ Walmex ] by zone to be very similar to last year. The combination of the same or better well productivity with lower costs across the board, drives meaningfully improved capital efficiency and lower breakevens, which we can go through in more detail on Slide 10.

As we've been saying for a while now, we are drilling the same wells in the same areas this year as we have in the past few years, and as a result, expect 2026 productivity to be in line or slightly better than '24 and '25, which are basically on top of one another. And we continue to see meaningful improvements in our cost structure with our anticipated 2026 costs of $675 a foot, approximately 20% cheaper than we were in 2024. The combination appears consistent well productivity and lower operating costs allow PR to continue to improve our capital efficiency and deliver a 2026 plan that has 20% higher oil volumes and 10% less CapEx than when compared to 2024.

Turning to Slide 11 and go back to 2023 to highlight the continued execution that has helped drive the outsized investor returns we will highlight in the next slide. Our sole focus today is on increasing free cash flow per share and creating long-term value for investors. From 2024 to 2026, we've increased oil production by 30,000 barrels of oil per day, while reducing our CapEx budget by $250 million. Free cash flow per share has grown from $1.13 in 2023 when oil is at 78 to almost $2 per share this past year with oil averaging $65 per barrel, representing a CAGR of approximately 30%. PR's consistent free cash flow per share growth prove strong execution can overcome commodity price volatility and create outsized returns for investors.

Finally, Slide 12 helps summarize the free cash flow per share growth we have achieved over the past years. With our team's efforts leading to free cash flow share in 2025 that is 72% higher than it was in 2023. This is what we have our entire team focused on durable long-term free cash flow per share growth. And what the other two graphs show are: one, that free cash flow per se growth has driven our outsized shareholder return; and two, that shareholder return has occurred without a re-rating of our business. And so our plan is to keep growing free cash flow per share. We are confident that executing on that plan will drive continued appreciation in our share price with or without a re-rating of our multiple.

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

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

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

Yes. I mean I think there's definitely different ways to grow free cash flow per share. You can kind of grow it via the numerator, which has largely been our strategy, kind of both organic and inorganic, free cash flow growth over the last couple of years. And you can also grow it through the denominator. I think that's probably a different business model than we have pursued as you outlined, but I don't think there's that makes it wrong. I think it reflects -- yes, like you said, I think an opportunity set an inventory quality and really just the maturity of our business, like I think kind of a lot of businesses that are kind of shifting to a reduced the denominator, buyback share strategy. I think those are kind of typically more mature businesses and more mature basins. And I'd say for us, we're fortunate. I think we're in the most exciting oil basin in North America that has a ton of running room. So you've seen us do more free cash flow per share growth in the terms of organic growth and growth through acquisitions, and that's been a really good recipe for us. And I think we're really fortunate that that opportunity set for the next few years feels as good or better than it's been the last couple.

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

Yes. I think we had a great slide in our deck, Slide 16. And I think really fortunately, we've got kind of free cash flow coming in. And for us, our plan is to use every tool we've got in the toolkit kind of as the opportunities persist, I think capital allocation is something we've really prided ourselves on. I think we've done a great job of that, the past decade. And look, we're going to allocate capital to the opportunity in front of us that we think will drive the greatest return over the long term. Obviously, the base dividend is first and foremost. And we're proud of our track record of continuing to grow that dividend year in and year out. And then beyond that, it's going to really depend on the opportunity set. I think if we have opportunities for really attractive, accretive acquisitions, we'll pursue those to the best of our ability. And if we don't, I think we're always excited to accrue cash to the balance sheet because we know this is a cyclical business. And I think paying down debt and saving dollars for the future has been a great return for us in the past. And finally, as dislocations exist. We are excited to buy back shares. Obviously, we landed heavily for a week or two in April and haven't had a lot of opportunities there since then. But for us, capital allocation really is all of the above, and we don't see any need to kind of limit or restrict ourselves going forward.

Your next question comes from Neal Dingmann with William Blair.

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

Yes. I mean our ground game, the small blocking and tackling stuff has been remarkably consistent for a decade. I think if anything, as we've gotten the larger position we have today, we've gotten kind of our team in place. I think it's probably -- the prospects are better and 2025 is probably our best year ever from a ground game perspective. So that feels really good. I think a lot of these deals that we're doing are kind of less subject to market pricing and fluctuations. I think about the ground game and most of the bolt-ons that we've done. Those are kind of one-off negotiated deals that were sourced through relationships we have in Midland, industry partners, relationships we have in New Mexico that go back the better part of the decade. So I think we've been fortunate to see that those have been less price sensitive, and we've been able to find a lot of good values. And look, I mean, we're paying, I think, real prices for high-quality assets. That's always been key to our business model, but we're definitely still seeing opportunities that make a lot of sense. And I think more insulated for market fluctuations. With regards to ABS changes in markets, we've been pursuing inventory weighted deals kind of for the entirety of our existence. We kind of stayed away from assets that were larger percentage of production, higher decline, things like that. So I think for us, I haven't seen a lot of pressure from the ABS market on the type of acquisitions we like to buy just because we're pursuing more inventory weighted deals.

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

Yes. I mean, we said in the past, we own 25,000 surface acres across the Delaware Basin. The majority of that is in Reeves County on the Texas side of the basin. And really, it is in -- we've got a few kind of blockier big chunks that I think are in pretty opportunistic spots with respect to power generation to the extent we wanted to pursue it. I'm not by no means messaging that this is on the near term and something that you should hear us announce in the next coming quarters, but it is something that I think we are exploring kind of what that market could look like and trying to better understand it. There are absolutely data centers that are coming to West Texas on kind of ranches nearby ours. So I think we'll get to see a good kind of case study for the commerciality of what that looks like. But I think for us, it's just a balance of -- I mean, the surface acres are also very key to our day-to-day oil and gas operations. We've got water wells on them, SWDs on them, recycling pits on them, and we drive them every day. So I think we're just trying to balance what's the value proposition of some sort of monetization or partnership as compared to just the day-to-day leveraging it to reduce our cost structure on the upstream assets.

Your next question comes from John Freeman with Raymond James.

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

Yes, I'd say we don't target a super specific reinvestment rate. I think there's a lot of things that factor in, and macro is certainly one of them. I think we've said this a lot in the past, like we're typically focused on growing production in an environment where we see kind of free cash flow accretion in the 12- to 18-month period. So you need wells that are very quick payouts, high-returning I think you could argue we're in that environment today. But I think for us, we are conscious of the macro environment that we're in. I think we've had a risk as we headed into 2026 that feels a little better, frankly, today than it did, that we could be in a meaningfully oversupplied market. So kind of even with the widget like we have that checks a lot of our criteria, I think for us, it just has felt prudent as we've headed into planning for 2026 to be to be cautious on growth. I think until we have more certainty in the macro and kind of longer-term oil prices that are kind of stable and higher. I think we've chosen to hold off on that growth. But yes, you're right, we've got the inventory base. We've got the widget, frankly, today that would justify growth, but are being patient kind of knowing that time will come.

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

I'd say most, if you want to use the word exploration, that may be a little bit of a stretch, but most exploration we do is going to be just better understanding what we have uphole and downhole kind of within the 4,000-foot column that is the Delaware Basin. If you think about our development plan in '24, '25, and what will be our development plan for '26, it's has been very consistent as far as we're developing Bone Springs down through kind of the Wolfcamp XY or top of the Wolfcamp, and that's about it. And if you look at offset operators and I say recently, we've added some Avalon and some kind of deeper Wolfcamp to our development plans, that's the type of exploration that we're doing. I'd say we're very much surprised as what people are doing as far as kind of pushing the play boundaries or even jumping into kind of some more unique conventional pay. But for the most part, I think you can kind of given how vast our position is today, and we feel good about the existing inventory quality and duration. I'd say it's more of just what do we have on our existing footprint. So I can round up that full answer. If you think about the what we called organic additions of inventory on that inventory slide -- on the deal side of Slide 8. That's what that was. That was we we've been watching kind of as you move further north away from the state line, I'd say we didn't typically take credit for Avalon, and we watch some other operators at Avalon. We went ahead and added it to a few of our development plans very successfully. And so on the heels of that kind of added Avalon to the inventory stack and same thing with Wolfcamp B or C, whatever nomenclature you may use.

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

I think that the conversation around site well product is impressive, and it certainly helps drive [indiscernible] much, much better than anticipated. I think a big part of that certainly hopefully doesn't get under shadow is how you guys have really reduced D&C costs quite a bit over the last couple of years. And can you give us a sense of like -- they not say how they oilfield service costing, but you can sort of add some commentary there if he likes. But like what are some additional leverage you guys can pull can they continue to move that D&C cost per foot now?

Yes. I mean if you think about just how we got here, it was a tremendous amount of progress on cutting days on the drilling side and then really just kind of riding the completion efficiencies that the whole industry has picked up as we've gone from single well to zipper to simul frac and leveraging recycled water with it. I'd say go forward, I think there is more juice to squeeze on the cost side on the drilling side of the business. I just -- if I look at where -- for us, given where our cost structure is in the Delaware, I think where we look for someone to go chase is typically we go look at Midland Basin operators. If we're going to be at $6.75 per foot in the Delaware, then there's kind of $100-plus per foot delta between our well cost and Midland Basin well cost. And so -- and if you look at the biggest delta between the two, it's going to be on the drilling side. If we're going to average, call it, 13 days spud to rig release on a 2-mile well. Midland Basin is going to be 5-plus days faster than that. And call it, $100,000 to $125,000 a day spread rate, like that's another $500,000, $600,000, $700,000 a well that we could go get. So that's what we're focused on. If you look at drilling speed, drilling times, we cut 6% year-over-year. I think last year, we cut even more. So I think we have a track record of doing it. But very specifically to your question, it's an all of the above approach. There's no easy wins or silver bullet. But I think if I had to pick one, it will be kind of reducing days on the drilling side, which likely means increased ROP in the lateral.

Got it. My follow-up question is on M&A, and can you give us a sense of what you're seeing on the M&A market in terms of growing in and larger stuff right now, but because I'm really special interested in state and federal retails, like what is your expectation on things that could come up as that been encouraging what you're seeing that could all be for [ Altera, ] and how competitive is that? Is that something that when you look at where return on time growing stuff, is lease sales do they prevent the better opportunity, or are those much more competitive in terms of trying to capture?

Those are great questions. I think on a kind of deal pipeline in general, feels really strong. Like I said, to Kevin's call at the beginning, like our ground game feels like it's just building momentum, kind of the opportunity sets probably widening and growing and accelerating, not shrinking. It really feels like that's sustainable for the next handful of years at a minimum. And we're seeing good kind of $500 million to $1 billion assets like what we bought with Oxy's [ Barilla ] Draw, Apaches to Mexico exit. It's a great pipeline to those. I think it's interesting, too, like we're starting to hear rumors and kind of see signs of larger packages coming. Obviously, there's been a ton of consolidation in the Delaware and the Permian more broadly. We think we're starting to be on the front end of seeing some of the larger companies who have been the consolidators have some kind of divestitures that make sense on the backside of that. The that we've always thought we'd see. We've seen kind of go back over the history of oil and gas. I think the largest companies consolidated and then kind of a deconsolidation wave comes a few years later. And frankly, we haven't seen really any of that in COVID. It does feel like we could be kind of entering a phase of that over the next couple of years, which kind of I think only adds to the opportunity set. I'd say finally, with regards to your commentary about federal lease sales, we think it's great that the kind of administration in Washington has been pushing those lease sales out. We think that's good for the country, we think that's good for the oil and gas business. I'd say with regards to our participation, I think historically, we've seen most of the time those lease sales are really competitive. Anybody can get on their computer and bid on them. So I do think we've seen more often than not, those tend to be more expensive than most of the acquisitions we've looked at. And as a result, we probably haven't been as competitive in in that arena as we have been in others. But we definitely bought things over the last 7 or 8 years in kind of both New Mexico state Texas state and federal lease sales. But that's typically because we have an edge. We have a strategic advantage. We have an information advantage and -- but that doesn't apply to all of them. So I think it's certainly something we look at. It's something we participated in the past, but more not tone to be pretty competitive.

Your next question comes from Zach Parham with JPMorgan.

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

I'd start with, Zach, we're not that good at -- I mean, this is -- let's call it flat. Just I think there's a little bit of visually, if you put them all on top of each other, it's messy and also we're not so good that we can dial it in within 0.5%. But to answer your general question, I mean this is what we've been saying about our business since 2023 that we have a very consistent development plan where we develop kind of all of the benches that need to be codeveloped at the same time, and we are developing the same benches methodically across our position. And so '25 was no different than '24 and '26 is no different than '25. And '27 will be no different than '26. So I think it's a testament to a very consistent development methodology with an inventory position that allows us to do it and an M&A machine that continues to replenish the top quartile in a way that I think is really sustainable. So this is a big part of our -- if you follow the free cash flow per share growth, we've done in spite of dramatically reducing commodity prices. And the only way to do it is that you hold well productivity flat. We cut costs more than more than oil prices hurt you. And so I think that's what we've done in the past, and we plan to continue to do it going forward.

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

It's interesting, I think, that maybe you probably could find some transcripts from 2 years ago, where I said 2 miles is the optimal linked in the Delaware Basin, and I had my own reasons why 3 wasn't. It was kind of around how much total fluid our wells make, and they're trying to flow back 3 miles worth of fluid up 5.5-inch casing is you end up kind of delaying barrels in a way that offsets your D&C savings. I'd say that is, although conceptually true is probably not perfectly true. I think that the optimal lateral length may be 2.5 or something like that now. And so really, as you look at how we develop our position, if we have a 4-mile fairway, we're going to drill two 2-mile wells. If we have a 5-mile fairway, we're going to drill two 2.5-mile wells. If we have a 6-mile fairway, I think it will be a debate depending on where we are. Are we going to drill 2, 3 milers or the miles, and that's kind of how close it is. But I think technically, we have proven our ability to drill 2-mile wells, 3-mile wells in the case of this longest well, 3.5-mile well. And so the drilling team has absolutely proven what they can do. The question is just what generates the most -- the highest rate of return, you get $1 per foot savings on one end, but you kind of delay peak production on the other. And at that point, it's just a math problem.

You now have a question from Derrick Whitfield with Texas Capital.

Congrats on an exceptional year end. With my questions, I wanted to lean in really a last couple of questions that you received. When we think about your consistency of well performance, as you highlighted on Slide 10. I mean it has been remarkably consistent over the last 3 years and a clear standout. As you work kind of forward in time, will how comfortable are you in continuing to generate that level of productivity? And you commented on 2027 and just in the earlier answer, but it feels like the depth there is good for 5 years or so.

Yes, I think that's right. I can say with real confidence that for the next 4 to 5 years, I think this is what you should expect to see. And the only reason I'd say pass that is I don't really know exactly what the world looks like, what other benches were adding, what the M&A machine ends up once you get kind of past the end of the decade. But as we build out specific schedules and work with our planning team, this is something that we can continue to maintain for quite some time.

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

We've got some kind of call it mixes of surfactants and kind of acids, et cetera, on existing producing wells, kind of typically when you get your first ESP failures about the time we do it. I'd say to mixed results. We've had some that have been wildly successful, adding double, tripling the existing production rate, some that you've seen kind of a muted response. I'd say I'm going to lump surfactants whether it's kind of bringing back what used to be common -- or normal surfactant on the frac side that we all pumped in kind of 2017, 2018 time frame, with kind of new technology today, whether your pumps are back on the production side, I'd say the new kind of also bringing back lightweight proppant, you think it wasn't 5, 10 years ago, people were pumping kind of man-made lightweight proppants and now with pet coke and other tests going on, there's a big lightweight proppant push. And even though enhanced oil recovery in that bucket, I think there are -- there is more focus on how do we increase recoveries and productivity than there has ever been. And although I'm not willing to pick the winner, I can say with confidence that there will be big wins that I think you'll see quickly adopted across the industry and for companies like Permian Resources, who have great assets in great basins, it will be a big tailwind. But I'm very confident that there will be -- we will solve this in a way that if you think the last 3 or 4 years, it was a huge effort of cutting cost out of the system. I think I wouldn't be surprised the next 3 or 4 years is an equally effort on adding barrels and adding barrels make a much bigger difference in cutting costs in the long term.

We now have a question from Neil Mehta with Goldman Sachs.

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

Yes, sure. I mean I think this year, it's kind of forward core and indicate and broader consensus out as well. I think there's definitely going to be potential for challenges kind of over the course of 2026, it depends on how the kind of "winter" finishes up, and what weather and interruptions planned and unplanned look like kind of through the course of the year, but I do think there'll be certainly a bumpy road and could be some challenges on the way. I think we're confident as you get into 2027 and beyond that without a change in unexpected step change in Permian gas growth, I think we could be kind of close to getting there. We actually have the right pipeline takeaway capacity as a basin to mitigate some of the volatility or even potentially all of the volatility that we've seen at WAHA the last couple of years. I think with regards to PR, we're pretty well insulated from WAHA volatility kind of this year and going forward. As we talked a lot about, like we have made a tremendous effort to get better in the gas marketing department. And we feel like we've really -- we kind of pretty much gotten there. As you can see on our Slide 6, 90% of our gas this year will price either kind of hedged that attracted WAHA prices or price at non-WAHA destinations. So I think we kind of same with 2027. So I think for us, we think this will be a little challenged kind of more broadly, next year should get better. But PR is in the fortunate position today after a lot of hard work that we're pretty insulated from that from all the work that we've done.

Yes. That's very clear. The follow-up is on Slide 12. So I really like this free cash flow per share framework. I think it makes a lot of sense and agree that it's a good predictor of long-term value creation. Maybe the biggest risk with taking a near-term free cash flow per share framework is the risk of under investment, right? So there's some -- how do you manage the business on this free cash flow framework per share framework over the long term? And what are the pitfalls of using this framework because there -- it could be a double edged toward if you don't execute it, right?

Yes. When we talk about free cash flow per share being what we're focused on, that's over the very long term. I think kind of not looking at single discrete years, certainly not looking at single discrete quarters. Like our goal is to be able to do what we've done on Slide 12 for the next 5 years, the next 10 years, the next 20 years. And you can't you can't under-invest in the business and generate that kind of free cash flow per share growth over the long term. So I think like I got at the beginning of the call, there's different ways to focus on free cash flow per share. I think where our business is today, that's certainly more numerator-focused and denominator focused, just kind of the opportunity that we have organically to reinvest in the business and grow and inorganically through our acquisition effort that's been really successful. So I think for us, the right way for us to do it is to look out over the long term, like I said, 5, 10, 20 years. And I think the right way for you guys to do it, is to look over the kind of longer-term periods as well and not focus overly on kind of this year or next year or this quarter or that quarter. And look at the arc of free cash flow per share growth over the long term.

You now have the question from John Abbott with Wolf Research.

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

Yes. I mean, I think kind of like you said, like we are kind of flat over the course of the year from Q1 to Q4 in this environment. But I do think it's worth pointing out that kind of our production growth is 5% higher in 2026 and 2025. And for us, that probably is a yellow light. That's not the same way everybody uses it. But I think as we look into the future, it doesn't take it much for a business of our size with our nimble operating team, our kind of lean culture to return to a more growth scenario. I do think we want to be confident in the macro and don't want to get out ahead of that. So I think for us, we'll be looking for real confidence that there's a better supply-demand balance that shapes up well to need our barrels over the coming years. And then I think growth for us, it just depends on the macro environment, what the oil price is and what the service cost environment is. I think historically, we've grown closer to 10% per year. That feels that starts to feel higher, but I think something in the kind of mid- to high single digits and an attractive reinvestment and capital deployment environment is certainly something we can get excited about and something we've got to inventory but to go prosecute.

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

Yes, this is Guy. We're a little bit less hedged than that for '26. But our target, as we've talked about consistent 30%, 20%, 10% year, 1, 2 and 3 out. The macro weighs in too much into kind of how we hedge. We think those targets make sense and hedging still make sense despite our strong sheet because it's more capital that we have to put down. And if we just think about taking those hedge proceeds when there's $50 oil, there's likely buybacks do acquisitions to make those sorts of things. And really, where we try to be flexible on the hedging targets is just lean in when we have these kind of periods of what we've seen over the last year is those are pretty short. And so we kind of -- we hedge into those opportunistically, but we're also not going to pramatically hit our targets at lower oil prices than weaker mid-cycle just to force it. But we've done a good job of getting to those targets despite all that. We feel good about it. I feel like it dips into how we think about capital allocation, particularly in a downturn.

The next question comes from Phillip Jungwirth with BMO.

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

Yes. I mean I think for us, we're in the really fortunate position of ample liquidity, low leverage and hopefully on the cusp of achieving investment-grade status. I'd say, for us, I think the limiter is not going to be access to capital. It's going to be kind of our comfort with leverage. I think we certainly have the capacity to do $1 billion, $2 billion or even $3 billion of deals with -- over the next year or two, kind of within our leverage comfort zones at $60 or $65 oil. I think as you spend more dollars, I think you do need to get more picky on making sure the transactions are the right ones. So I do think -- we believe we have the horsepower to do whatever is coming down the horizon, but we are going to be thoughtful. We've said a million times on these calls. We're not going to lever up the business or risk the business to pursue kind of near-term free cash flow accretion, for example, like to kind of go back to Neil's question. So I think for us, we certainly feel like we've got the right balance sheet and the right dry powder to kind of pursue the deals that we see coming. But are conscious that we aren't going to risk the business, and we're not going to overextend ourselves.

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

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

Your next question comes from Josh Silverstein with UBS Financial.

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

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

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

Yes. I mean I think we've stayed away from giving any explicit stats about our royalty business today, and I think that probably still makes sense with where it stands in the maturity of that asset of that business today. We certainly thought about it. I think we've got an awesome royalty business, but that awesome Royalty business fits really, really well within our upstream business. It's like our royalty business is well over 90% Permian Resources operated. And I think allocating capital to that -- to those higher NRI and kind of royalty weighted assets has been a really important part of our capital efficiency story the last few years. So I think we love having it in the business. That said, I think we're always looking for ways to create incremental value for shareholders. And if we were convinced that, that business could create more value for shareholders as a stand-alone or kind of subsidiary type business. That's certainly something we have been thinking about, and we'll continue to think about. We just kind of haven't seen or had the right level of conviction around that, the kind of value creation story today. But definitely something that's on our radar, something we're continuing to think through and kind of we'll keep evaluating as the kind of months, quarters and years come.

We now have a question from Marion Marney with ROTH.

I wanted to see if you could talk a little bit about sort of cadence on the year. in terms of capital or production. Historically, you guys have been a little bit more front half weighted on CapEx. Is that something we're going to see again here in 2026. And do you see kind of production. Obviously, if you look at your forecast here, oil is roughly flat with 4Q, was there any downtime at all in 1Q on the storms and then a rebound in the second quarter. Just curious any moving parts along any of those lines.

Okay. I'll hit it all. Production should be flat throughout the year. We I got to give a shout out to the team in the field and in the office, but they work their absolute tail off to keep the overwhelming majority of our production online or in the storm. And I mean crazy amounts of work. I -- it really is impressive what they do, and how bode in they are to what we're trying to do. So production flat, you will not see a Q1 dip due to the storm. The last question was CapEx, I believe. I mean, it's flat throughout the year. It's not -- there's nothing dramatic. You may see some kind of fluctuations between Q1 and Q2 and Q2 and Q3, but first half, second half, it's all -- it's relatively equally weighted.

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

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

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

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

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

Your next question comes from Noah Hungness with Bank of America.

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

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

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

I'd say the existing position, like maybe on the margin, there's a few places that we -- now that we're comfortable going longer can. But for the most part, like we've done all the work, we've done all the trades, and we've set it up for how we're going to drill it. And so kind of if you look at it just quick glance, you can see like most of the units are set up pretty well for, oh, that makes sense, they'll drill 2 miles, or they'll drill 2.5 or in some cases, drill 3. I think where you could see it change over time is as we are buying new assets, coring up new assets. I think the land team has been given the kind of ideal lateral length is probably closer to 2.5 than it was to 2. And so they will do the work accordingly to try to kind of extend laterals further. If you added an extra, call it, 2,500 feet of lateral linked, I don't have the exact number what that would reduce on D&C per foot. It will be in the kind of -- it will only help. It will be in the kind of double -- probably low double digits as far as dollar per foot reduction, something like that, $20 a foot, $25 a foot would be my gas off hand.

[Operator Instructions] Your next question comes from Paul Diamond with Citi.

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

Yes. I think 2025 is certainly more New Mexico heavy in terms of inventory acquisitions. I think that's going to be largely just like just opportunity set driven. I think we love our Texas asset. We did a pretty pretty inventory-heavy acquisition in Texas in 2024 with that [ Barilla ] Draw transaction. And that was a heck of a deal. We're really excited about that at the time and probably even more excited about that. today. So I think it's more opportunity in, I do think there's probably just generally more inventory available and likely to come in New Mexico than in Texas over the next 5 years. So I'd say more likely to do deals up there that is excess. But I mean, we're kind of agnostic. We'd love to do more in Texas if the right opportunity came along. It's just going to depends on what's out there, what's for sale and what we can get at a price that we think creates value for shareholders.

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

I mean I think the -- why are we focused on investment grade? It fits with our strategy. We want to reduce our cost of capital. We want to have long-term capital availability. And then I think from a timing perspective, where we've been more insistent is just the fact that we've been at investment-grade credit ratings for a long time now. Our financial policies have conformed with investment-grade financial policies. And we've kind of built the business quickly, but always consistent with our financial policies. And so we do think it has clear benefits going forward, and we do think we meet the criteria today.

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

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

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

Good morning, and welcome to Permian Resources conference call to discuss its third quarter 2021 earnings. Today's call is being recorded. A replay of the call will be accessible until November 20, 2025, by dialing 888-660-6264 and entering [indiscernible] access code 91750 or by visiting the company's website at www.permianres.com.

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

Thank you, Jimmy, 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 risks and uncertainties that could affect our actual results and are discussed in more detail in our filings with the SEC. We may also refer to non-GAAP financial measures. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation.

With that, I will turn the call over to Will Hickey co-CEO.

Thanks, Hays. We're excited to discuss our third quarter results this morning. This marks the 12th consecutive quarter of strong operational performance by the PR team, culminating in our highest quarterly free cash flow per share since inception despite a suppressed commodity environment. Our business is firing on all cylinders as we were able to deliver strong execution in the field, progress our accretive acquisition strategy, improve our balance sheet and continue delivering strong returns to our shareholders.

We think this performance is a testament to both the quality of our people and the quality of our assets and should continue to set PR up for strong and growing free cash flow going forward. In Q3, production exceeded expectations with oil production of 187,000 barrels of oil per day, up 6% from Q2 and total production of 410,000 barrels of oil equivalent per day. Our production outperformance was driven by continued strong execution, particularly from a large-scale Texas development that was brought online in the quarter.

On the cost side, our operations team continues to set the standard in the Delaware Basin. We reduced controllable cash costs by 6% quarter-over-quarter, primarily driven by reducing LOE approximately $0.30 to $5.07 per BOE and D&C costs by 3%, averaging $7.25 per foot in the quarter. Both metrics are below full year guidance, and we see additional room for improvement on the D&C side as we head into next year. The combination of strong production and lower cost drove adjusted operating cash flow of $949 million and record adjusted free cash flow of $469 million with $480 million of cash CapEx.

Our outstanding operating performance and conservative financial strategy further enhance our fortress balance sheet. During the third quarter, we called our 2026 senior notes and redeemed the legacy Centennial convert, reducing outstanding debt by over $450 million and further simplifying our capital structure. In July, we received our first investment-grade credit rating from Fitch. And earlier this week, Moody's upgraded us to a positive outlook, bringing us 1 step closer to investment grade. Our credit metrics have long matched our investment-grade peers, and we appreciate the recognition.

Slide 5 highlights our strong Haley production outperformance that underpinned Q3 production results. We frequently talk about our Delaware Basin leading cost structure, but this development is a great example of how our technical team approaches every project to maximize recoveries and value across our position. Our proprietary subsurface characterization dictated how we space, stack, sequence and customized completions for each of these 17 wells. The combination of these technical refinements drove 45% oil outperformance versus offset wells in the first 90 days. The recipe here is the same 1 we've used to consistently improve results across our portfolio, data-driven spacing and targeting interval specific completions and precise wellbore placement, all supported by PR's cutting-edge technology and long history of technical expertise in the Delaware Basin.

Having our entire team based in Midland, close to our assets allows us to seamlessly translate technical insights to the field driving lower cost and superior execution. On the back of our strong well results and stellar operational execution this quarter, we're raising the midpoint of our full year production guidance to 181,500 barrels of oil per day and 394,000 barrels of oil equivalent per day, while keeping our CapEx guidance unchanged. This plan reflects an increase to the original full year production guide of 5% and while lowering the capital budget by 2%, demonstrating continued improvements in capital efficiency.

With that, I will turn it over to James.

Thanks, Will. Turning to Slide 7. We wanted to provide a little more context and background about how we build Permian Resources into the business it is today. When we started Colgate Energy and moved to Midland in 2015, we had no assets and no production. We quickly realized that building a business of quality and scale is not going to be easy. And if we are going to be successful, we would have to focus on doing the hard things that other companies didn't want to do. We built Colgate by working harder and being scrappier than the company that surrounded us. We were also fortunate that our entire team was in Midland. This allowed us to have great real-time information and to build long-lasting relationships with mineral owners, brokers and legacy operators. It also gave us access to real-time intel on the latest technology will results in information in a rapidly changing environment.

Having our headquarters and entire team in Midland allowed us to truly ingrain ourselves within the Permian Basin ecosystem, which was our first competitive advantage. Today, we are fortunate to have another true competitive advantage, which is our peer-leading cost structure in the Delaware Basin. As you can see in the graph on the top of Slide 7, we're able to drill, complete and operate wells at a cost structure that is meaningfully lower than the companies around us and the results speak for themselves. We have completed over 2,000 transactions in the past 10 years and have built a track record of driving the highest equity returns in the oil and gas business, but that's a private company before and now as a public company. And our momentum and opportunity set is only growing.

We are on pace this year to do more transactions than any other year, and I think the acquisitions we are doing today are as good as any deals we have done in the history of the company. We are proud that our team has continued to maintain the same culture of doing the small things and doing the hard things. This culture is clear in our approach to acquisitions and divestitures, but more importantly, it is deeply ingrained in every department and every part of our business. Doing the hard things not only supports our M&A effort, but leads to the best in-basin cost structure that allows it all to happen. And all of this shows itself more specifically than what we were able to accomplish in Q3. We closed 250 deals, primarily in New Mexico, adding 5,500 net leasehold acres and 2,400 net royalty acres for approximately $180 million.

The acreage we bought in Q3 fits could go out with our existing position and the locations will compete for capital in our high-quality portfolio from day 1. Our acquisition pipeline remains robust, and we feel good about PR's ability to continue to do accretive deals that increase our inventory life and drive long-term value for investors.

Slide 9 shows the progress we have made increasing the amount of gas we sell at a basin and improving our netbacks. Pure and [ oil ] agreements to sell approximately 330 million cubic feet per day over the basin in 2026, increasing a 700 million cubic feet per day in 2028. As a result, at current strip, the volumes associated with these agreements are expected to realize approximately $1 per Mcf higher pricing net of fees in 2026, resulting in a greater than $100 million uplift to free cash flow next year. As a result of these agreements and our existing hedges, the company has reduced its [indiscernible] exposure to approximately 25% of total gas volumes in 2026.

Longer term, these agreements put [ Terna ] position to benefit from growing natural gas demand and higher realized prices on a larger portion of its natural gas production.

Moving to Slide 10. We want to point out that PR is in the fortunate position of having the flexibility to allocate capital to whatever part of our business we think is going to drive the most long-term value. Capital allocation is the most important thing we do, and our strong balance sheet allows the company to pursue an all of the above approach to value creation. We can allocate capital to the highest return opportunities rather than having to focus our efforts on a single capital allocation strategy.

Just this year, we've seen opportunities to deploy $800 million into acquisitions, $75 million to buybacks, all while reducing our total debt by $630 million and maintaining 1 of the highest base dividends in the sector. Having the flexibility to allocate capital to whatever we believe creates the most long-term value has been a key part of our business model for the last 10 years and remain a core part of our strategy going forward.

Thank you for tuning in today. And now we will turn it back to the operator for Q&A.

[Operator Instructions]

Your first question is from Scott Hanold from RBC.

I know it's a bit early on 2026, but obviously, it's very topical for investors. So -- can you just give us a general sense of how you're thinking about the activity pace and what that could just high level mean about oil production and relative CapEx.

Yes. Sure, Scott. I'd say, look, per our long-standing policy, we're not going to put out a soft guide or anything like that at this time. As we've done in the last few years, we think it makes a lot more sense running this business to wait until February to put out 2026 guidance. I'd say obviously, 4 months from now, we think we'll know a lot more about the macro, the service cost environment, what we think commodity prices look like heading into the balance of the year. So I think -- what I'd tell you is, look, we're fortunate that our business continues to have a ton of flexibility next year, and we should be in a position to react to whatever the macro environment looks like.

And I think if that's an environment that is supportive of and encouraging to higher reinvestment, quicker payback, higher returns and ultimately, production growth, we can do that and do that quickly. And if it's an environment that has weaker commodity prices kind of lower returns, then we're in a position to deliver a really capital-efficient kind of lower or no growth program. That's probably not as much detail as you'd like. But what I can tell you is that 2026 is shaping up to be a really strong year, whichever the various paths we do end up using. I think we think it's setting up to be the most capital-efficient year we have ever had.

Look, we continue to get more efficient on the upside as you see this quarter and make substantial and sustainable improvements really all parts of our cost structure. Our productivity remains strong. We think next year should be just as good as this year, which was just as good as the years before that. And as we talked about a couple of times in this deck in the last deck, our realizations are meaningfully better next year. We talked about on the prior earnings call that we expect to realize $0.50 a barrel higher on the crude side. And we think our net gas that could be $0.20 an Mcf better based on the agreements we signed the last couple of months. So -- all in, I think the next year should be a really good strong year for Permian Resources, but we're going to wait and see what the macro brings before we formalize the plan.

Okay. I appreciate that context. If we could take a look at that Haley, that Haley kind of the pad, you all drilled or at least set of wells, obviously, fantastic results. But as you step back and look at your acreage holistically, are there any other opportunities like that across your asset base, whether smaller or larger or similar size? And -- and why was that so like uniquely good on a relative basis?

Yes. Thanks, Scott. Haley was unique to us in that it was kind of more of like a one-off block that we own and is not contiguous with the greater PR position. And as such, I think it gave our team and ability to demonstrate what they do so well, both from the cost side and the productivity side as compared to offset results. But if you take a step back, I'd say on an absolute basis, the performance from the Haley pad is kind of right in the middle of performance of PR's overall position. This was a -- it caught us off guard because we built expectations based on offset production and significantly outperformed that over the first 90 days. But if you just look at kind of productivity of that pad, it should fall pretty much in line with our overall portfolio.

So it was a nice surprise to the upside, and I think really demonstrate what our team does very well. But -- it's not a -- the rest of our portfolio will continue to perform as good, if not better, than Haley, which is consistent with previous years.

And your next question is from John Freeman from Raymond James.

Nice to see the continued progress. So you had the gas marketing agreements, obviously, looks like in a couple of years out '27, '28, you'll have 90% plus of those gas volumes being priced outside the basin. And I'm just trying to get maybe some color on maybe the optionality that you all have in terms of like the gas that's being moved to kind of the DFW market versus the options to move it to the Gulf Coast. I mean just looking at some of the agreements you've got like the heat Brenton line. I know that, that stops and May Pearl -- DFW, I believe it has optionality to go to K. You've got [indiscernible] that goes directly to Katy. Just trying to get a sense of kind of when I look at DFW versus the Gulf Coast markets, just kind of the optionality that you've got these agreements with decade?

Yes, I think we do have quite a bit of flexibility to kind of shift volumes from the Houston Ship Channel, the DFW market. I think what that looks like for us out in '27 or '28 is going to depend on what the market looks like at the time. So I think for us, I do think specifically, most of our gas will go to Houston Ship Channel or DFW and probably somewhere close to 50-50 in a base case with the ability to swing that 10% or 15% in either direction depending on what we're seeing in the market. But I do think we've got some flexibility there. But in any case, we'll have gas going to both DFW and the Gulf Coast markets.

Got it. And then on the bottom of that Slide 5, we all highlight a number of different leading-edge things you've been doing to improve recoveries, lower costs. I'm just -- some of those, I think you've been doing for all year. I'm just trying to get a sense of kind of what you all would characterize as more maybe more recent developments, things that maybe are just starting to flow through operations results? Just anything I could highlight on that front?

Yes, I'd say we are always kind of tinkering and trying new things to both reduce cost and increase recoveries. Not to sound repetitive with kind of other conversations I'd say, like recent breakthroughs have been on the drill-out side for longer laterals. We've kind of been testing and had a lot of success with a new technique that I'd say is meaningfully reduced drill-out cost. We're going to continue to kind of tinker with it and see exactly how well it fits across our whole portfolio, but I'd say especially on extended reach laterals, it has been a kind of a step change in efficiencies and costs on the drill-out side.

On the recovery side, we are kind of continuing to play with optimal landing targets combined with kind of the right completion design that those details change on every well we drill. But this is something that I'd say our team prides ourself on is we are, I think, have been deemed the leader on the cost side in the basin, but we put just as much effort on the recovery side as well to make sure that we are maximizing value of every acre that we own. And I think the team has done a really good job.

And your next question is from Neal Dingmann from William Blair.

Nice quarter. James, just to jump in right into my first question. I think really notable on that Slide 11 to all the above slide. My question is, I can't help see the comment where you mentioned the dividends supported around $40. So -- my question is sort of on when you book in that if prices do fall, let's say, in the near term around that, could we see mostly just leaning just that quarterly bid and then the other side of that when prices once oil does rebound, do you anticipate sort of again all the above where you would look at dividends, buybacks, debt repayment and acquisitions?

That's a great question. I mean I think that Slide 10 is our favorite slide in the deck. I'm glad you pointed it out. But I'd say, look, like the way we're trying to run this business is that we would be able to deploy this all of the above strategy and really in any commodity price environment, including something as low as $40 or below. I think as you see, like we've got leverage and liquidity in a place where we want to be able to deploy capital to whichever of these acquisitions, buybacks is the most attractive return. And we want to be able to do that even in the darkest days of a down cycle.

So I think for us, like the way we've positioned our balance sheet the liquidity, the leverage, like we want to be doing this all of the above strategy at any environment because I think we've seen it at the bottom of the cycles, the best opportunities arise and don't want to have to be on the sidelines that $35, $40 whatever kind of most various prices, we probably don't think will happen, but I want to make sure we're ready for it. So I'd say this all of the above strategy is something we're going to deploy in any part of the down cycle. And as dark as it gets. And just fortunate the business is in a position that we think we can do that in pretty much any commodity price environment.

And then just lastly, sort of bolting on to that, my second question, just on M&A specifically. You guys were very active. I know there's always a runway and said, oh, they can't find any more acreage yet. You not only find that you plan at a lower cost. I guess my question is, are there continue to be small deals out there in your thoughts about there was obviously some big prices paid on the -- some of the New Mexico resales, and there's another 1 coming up this month. Just your thoughts on sort of ground game versus other M&A.

Yes. I mean, I think kind of to the beginning of your question, I'd say our ground game and M&A pipeline is as full as it's ever been. You can see in the graph on Slide 7, like we've actually done more transactions through the first 9 months of this year than any other year in company history. So I'd say rather than kind of dry opportunity set drying out, it seems to be expanding. And we're having to look harder and turn over more rocks and probably do more deals and more small deals to find the values that you see add up to the really attractive price that you see on Slide 8.

Like I'd say, as you mentioned, there have been some big prices paid in New Mexico. It's the best rock in the world. And fortunately, operating in what we think is the best base in. And -- but also fortunate that we have, I think, a true differentiated and proprietary access to deal flow that other people don't see. We're on the ground here in Midland. We're kicking over every rock and still willing to do the small and hard stuff, like I said in my introductory remarks. So I think for us, this rock is incredibly valuable, but we're in a fortunate position of having a lot of different ways to find deals and kind of pursuing all of the above strategy here, too.

And your next question is from Neil Mehta from Goldman Sachs.

Yes. Great execution, guys. There have been multiple quarters of it. And so I guess my first question is beyond just the operational volume improvement. The balance sheet is getting better recognized. You went to a positive watch, I believe, at Moody's, and you're pretty close to turn in investment grade. So can you talk about -- what are the next steps there? And what does move into investment grade mean for Permian Resources?

Neil, it's Guy. Thanks for the question. Yes, we were happy with both the Fitch and the Moody's outcomes here recently. We think it recognizes what we've communicated to our investors and to the rating agencies, which is we have an investment-grade balance sheet and financial strategy. And we've grown fast and the rating agencies are following that along with us. What do we have to do from here? We just continuing our dialogue with the agency. So I think really understand our story, and we've got a great shot at getting to investment grade in the near term. I think what it does for us is we continue to think about protecting the balance sheet through the cycle, availability of capital through the cycle and lowering our cost of capital. And this does all of those things. So it's very complementary to all the things that we're doing as a business today. and recognition of how we've grown the business the right way.

Yes. And then just the follow-up is just on the Permian broadly, we've seen strong growth year-over-year, I think led by the majors. But I think companies like yourself have also outperformed expectations. There's a big debate out there. Are we at peak Permian or not, obviously has macro implications. I know you guys spend more time thinking about your operations and trying to predict the oil price, but you got [indiscernible] perspective in Midland. How far away from peak Permian do you think we are?

That's a good question. I don't think we pretended to the answer to that. I think what we do know though is activity has definitely been slowing down out here. I mean I think you've seen it in the rig count. You see it in completions activity that there's a lot of kind of slowdown. I'd say it will come. I think we've seen the Permian historically be more resilient than maybe people thought. I think it's kind of TBD if that continues, but it definitely feels like you can feel it on the streets of Midland, there's fewer people. There's fewer rigs, there's fewer completion crews.

And eventually, we think that, that manifests itself in production growth slowing and ultimately flattening and then I think eventually declining. But I think it's kind of too early to tell when exactly that turnover happens.

Your next question is from Kevin MacCurdy from Pickering Partners.

I wanted to ask on CapEx cadence this year and how that could translate going forward. The first half of this year, you're around $500 million a quarter the back half is around -- it's closer to $480 million to $485 million, given 3Q results in the 4Q guide. And then is that just a function of lower well cost throughout the year? Or are there any activity changes that affected that CapEx? And how could we kind of think about that quarterly cadence setting forward?

No, it's been pretty flat activity. So I'd say well costs and kind of normal ebbs and flows in working interest would drive any kind of quarter-to-quarter differentiation, but well costs being the main driver of what you're seeing in the back half of the year.

That's helpful. And I wanted to ask again about the ground game and transactions. And just wanted to get your perspective, I mean we've seen the M&A market kind of heat up and there's an assumption that large operators are hunting big deals. Just kind of curious if this reflects what you're seeing on the ground? And is that making it harder or easier to do kind of the smaller deals that you're known for?

Honestly, it's easier to do the smaller deals than it's ever been. I think we've always had a good sourcing pipeline, but I think our cost structure advantage is as wide as we see it today as it's ever been. And I think people with our activity levels are kind of in basin in Midland on the ground knowledge of everything going on. Like it feels like we've got a more sustainable competitive advantage on the small deal side than we've ever had. And I don't think we've seen the kind of pressure at the top. Neil previously referenced some big prices paid in large-scale auctions, like that tends to not trickle down. I'd say the people who are chasing larger deals aren't chasing the deals at the smaller end of the spectrum. That's just kind of not how the ecosystem has been set up or has worked historically, and we don't see that pressure at the bottom of the day and really don't see it kind of coming down over time.

Your next question is from Paul Bomar from Citi.

Just a quick one, sticking on the ground game. As mentioned, it's the strongest pipeline you've seen. But has any reason volatility kind of shifted the balance of those deals you're looking at between more of the working interest heavy versus those more to block out your acreage?

No, I don't think so. I'd say I think the macro the smaller end, the kind of smaller size deals tend to be more stable and just kind of come at the pace, frankly, that we find them. A lot of those deals are us turning over rocks themselves and kind of finding the deals and drawing them out. So we -- that kind of tends to go as fast as we can go. And I do think that pace accelerate a little bit with our larger footprint. I'd say, honestly, a renewed focus on the ground game. It's something we talk a lot about in the office today. I think volatility can have a bigger effect on larger deals. I'd say we got an Apache deal done in April, May.

But besides that, the large deal pipeline was pretty quiet over that time period. I think people -- but it seems like the kind of the macro environment has settled down a little bit. I think we would expect buyers and sellers to deals in the hundreds of millions of dollars to kind of be able to get there in this environment. I think if you saw oil sharply go to 40 or 80 that might put things on pause again for a little while. But the beat goes on. I think that the deals that are going to come to market are going to come to market and the rock that we're going to turn over, we're going to turn over. So I'd say they can have 1 or 2 months slowdowns or accelerations. But by and large, it's pretty steady over here.

Got it. Makes perfect sense. And then just sticking on the net gas FT and sales agreements. Moving to 50, 25, 25. But I guess, over time, where do you guys see the right balance of that? Do you want more on that 75% number in FT and sales agreements? Or is the hedging going to remain a pretty substantial part?

I think a lot of -- I think we likely continue to hedge as we move forward. I think hedging could look different, right? Like today, our hedges are largely hedges that we have placed that Waha because that's where the gas -- corresponding gas sales are. I think over time, we'll be in the fortunate position that we're selling more and more gas in the downstream market at DSW and along the Gulf Coast. I think we'll have a different question of -- do we want to hedge the Houston Ship Channel price and lock that in. I think we're fortunate about that as we'd expect less volatility and less dislocations, but further downstream you get from the Permian Basin. So I have more flexibility there.

But yes, I think we'll continue to hedge actual financial hedging like we've done. But I think more importantly, what we're doing is it's more of a physical hedge. We're actually physically selling more of all volumes at the end markets that we think will be better markets over the long term. So probably reduces the amount of hedging going forward, but I think that's going to be dependent on the market and the pricing as we see it in the future.

Your next question is from David Deckelbaum from with Citi Bank.

A follow-up just on some of the gas marketing questions. I just wanted to get some color from your perspective, why sign these agreements now versus other periods in the past? And I guess, how should we be thinking about the impact to your cost structure beyond '27.

I mean, I think we probably should have signed a lot of these agreements 3 or 4 years ago. That's probably on us. I think a lot of people missed it, too. But I'd say, look, as we've run the business most of the time in the last decade. Our #1 focus has been on flow assurance, and we bought a lot of assets that came with legacy contracts that had lots of restrictions on what amount of gas we could take in kind, how we could sell downstream from there. So I'd say we've been pretty transparent that over the last 2 years, maximizing our netbacks on not just crude volumes, which I think we've done an awesome job on the last 10 years, but on gas volumes as well has been 1 of, if not the top priority at the company.

And we've been making as much progress as we can. And I think it's all kind of coming together this year and the past couple of quarters, but we're convinced it's the right decision. We're convicted that for all your hydrocarbons that's selling further downstream closer to end users is going to get to a higher netback on the average over time. And you're seeing that play out in a big way in 2026, and we think although the kind of futures market doesn't imply as big enough lift in years beyond that, we think it will continue to outperform and pay dividends for years to come.

I appreciate that color. And maybe just to expand a little bit. I know that you said you didn't want to give any self guidance on '26. But I think you did remark you think it's going to be your most capital efficient year ever. Is that more in reference to the uplift that you see in realizations? Or are there -- it sounded like your expectation is that while productivity is pretty static. I mean, what sort of motivates your enthusiasm around capital efficiency next year?

I mean, in short answer, we think that well productivity will be consistent with the last 2 or 3 years, and our well costs are as low as they've ever been. And I think that we probably have a little bit of room from here to continue to kind of reduced them a little bit from here. And so lowest well cost ever with consistent productivity and better realizations is a recipe for more capital-efficient business. And so I think that what James alluded to earlier is that is going to be a great year. The decision that we ultimately need to make over the next few months is do we let that incremental capital efficiency accrue to more production or less CapEx. And I think that's what we're going to work through over the next few months.

Your next question is from Jack Charm Daniel Energy Partners.

Guys, there's a lot to geek out on Slide 5. But kind of wondering about when I see the 6% decline in controllable costs, you call out chlorine dioxide as a treatment to increase base production. I'm kind of wondering what other sort of initiatives you're taking on that side to sort of manage base production and keep lowering your LOEs in particular?

I mean those guys are always trying to make the business better. We've had a lot of success in New Mexico, where power is terrible on kind of combining well site generation to more central larger-scale generation. I think we took 26 generators out of the field in Q3 over the 3 microgrids we put in. I think we've got 1 or 2 more between now and year-end. So that's a step change both in cost of power, but also in run time. I'd say a big part of our production outperformance over the course of this year has been improved run time. And if you can go stack lots of compressor -- lots of power generation on 1 site. You get much better run time than you do when it's spread out over lots of different places.

Yes, the [indiscernible] dioxides an interesting one, just as older wells have more buildup around the -- when we have a failure and we're running in, a lot of times, we'll pump some kind of [indiscernible] an asset to clean up purse clean up near wellbore. And as we've seen in some places where you have a remarkable increase in production, 5x to 10x where you were temporarily and ultimately, it kind of declines back to something that is still materially better than you were before.

Look, I think that the Permian Basin is a place where innovation is always happening, and we've built a team and a culture of always trying to kind of have our ear to the ground. So we're the fastest follower in places where we are not innovating the new ideas. And in other cases, we are kind of truly pioneering new things. And I think that, that will show up in hopefully better run time, better well cost and better productivity over time.

Got you. So I mean, it still sounds like it's potentially kind of early days for some of these initiatives. Is that fair?

So I'd say it's always early days, like I don't think [indiscernible] the I mean has slowed at all. Like it feels like every day, every month, every year, like the opportunity set to make the business better across all facets, production optimization specifically, but it's always good. I don't think we see it slowing down. And it may be early days on 1 or 2 of these technologies. And there's another technology coming around next year that we're not even talking about today. So I don't think that pace of innovation is slowing by any means. And we Permian Resources, I think, probably on the front end, but the whole industry is finding ways to continue to get better.

Your next question is from John Abbott from Wolfe Research.

Guy, maybe just a really quick question. You've had a little bit more time to examine the 1 big beautiful bill. Anything incremental as far as future cash taxes at this point in time?

No but different from last quarter.

All right. That's helpful. And then the other question is, I mean, you have a very low corporate breakeven with the dividend. How do you think about the pace of future dividend growth at this period of time? As you sort of look at what you're doing is your ability to generate free cash flow?

Yes. I mean I think kind of, look, for us, I'd say having a sustainable and growing base dividend is a core part of our strategy is Permian Resources. It's what we view as a core quality of any high-quality business in this sector or really in any sector. So I'd say growing the dividend over time is a priority and something you will see consistently from us year in, year out. I think the pace of what we've done in the last couple of years probably close from here. It's been pretty exceptional from a CAGR perspective. But I'd say, January next year, that's something we'd expect to finalize on side our February budget.

But I'd say the business is firing all cylinders, the ability to continue to grow the dividend given the capital efficiency we've referenced on this call is as strong as ever. So you should see it continue to grow next year and for years to come.

Your next question is from Paul Cheng of Scotiabank.

I'm just curious that I think the whole industry and including your sales that is looking at the data link and you are saying that you are seeing some success if I look at from a land position standpoint, where you see the opportunity set? What's the time of your program could be in the 3 miles? And also, have you passed on the alternative shape. And whether that you think that will be a good split for you? That's the first question.

Yes. Look, I'd say the [indiscernible] pad was a great example of a really successful 3-mile development. I think we drilled quite a few 3 milers this year. I say it's become a larger part of our program, and we're very impressed with how well our teams executed on the longer [indiscernible]. We mentioned some great technology on the Jill outside we've applied I think our land position sets up really well. We've got a blocky position in Texas and New Mexico that could set up for long laterals. I think for us, the honest answer is we don't see that much of a capital efficiency step-up in the Delaware Basin today and most of the areas that we operate going from 2 miles to 3 miles.

Obviously, 3 miles are better on a D&C per foot basis. But just given how much oil and gas and fluid we make in the Delaware, we often don't see the corresponding one-for-one uplift in initial production. So you drill and complete keeper, but you make closer to the same amount of oil in the early times. So on a discounted cost of capital rate of return basis, you're not seeing major uplift from going from 2 miles to 3. I think the short answer is anywhere from 2 to 3 is a pretty good place to be. And the vast majority of our position sets up for long laterals in that window and should be the majority of our program going forward.

How about on the alternative shape. Have you guys at looked at that or test it out?

You turn wells. I think we've drilled 10 new turns year-to-date. I'd say it's not an important part of our go-forward program. I think there's been some cool examples of us like where you had a legacy 1-mile well on a DSU and the rest of the pads set up for 2-mile laterals perfectly, and you had a legacy well that you could do a U-turn or J-Hook around. That's been a really cool tool. It's a more efficiently drained resource, probably add an extra stick that otherwise wouldn't have been economic, but we're really fortunate our land position sets up for 2- and 3-mile straight wells. So aren't going to have to drill a lot of U-turns going forward.

Okay. And on the opportunities buyback, can you share that what kind of quite or matrix that you guys are using in terms of that decide whether that this is the way time to be buyback or low.

Yes. I think we've only said we're going to buy back shares when there are material dislocations in the share price. I think most -- more often than not, that's driven by the macro. I think rather than tell ever on our specific criteria, as you think kind of pointing to what we did in April, immediately after "Liberation Day." We saw a material reaction downward in the Permian Resources stock price and had a awesome opportunity to buy shares in the $10 to $11 range. And is that as hard as we could that whole week. I'd say the stock recovered pretty quickly and that opportunity window closed.

But I'd say for us, it's going to be a material dislocation is going to be kind of what we use as the criteria. And frankly, we're always going to be weighing that against our other opportunities. I'd say -- our acquisition pipeline remains robust. So we'll be constantly weighing do we think we'll generate a higher long-term return, buying back shares or doing acquisitions or frankly, putting cash on the balance sheet for future opportunities. So I'd say any 1 of those is on the table at any given time, and we're constantly evaluating the opportunity set more broadly and going to allocate capital to whatever we think generates the highest rate of return and create the most long-term value for shareholders.

Your next question is from Noah Hungness from Bank of America.

I'd like to start off on just maintenance CapEx, given the D&C efficiencies you've seen, how can we think about maintenance CapEx levels? And then also how your dividend breakeven evolves over time through '26 and beyond.

Sorry, I hit the first part. Can you repeat the second part of that question?

Yes. The dividend breakeven, just how that evolves over time, like through 2026 and after.

Cool, maintenance CapEx, I'd say, kind of just generally speaking, we've quoted about $1.8 billion of maintenance CapEx, plus or minus. And I think what you've seen transpire this year is we've grown production pretty meaningfully. So the base is a lot bigger, but we've reduced cost and kept well productivity the same. So I think that plus or minus, those probably offset each other and you get to something that is in that range or slightly higher or something like that on the maintenance CapEx side. Dividend and the breakeven?

Yes. Dividend breakeven the goals for it to get better over time or stay the same, but there's a proportionate increase in our base dividend. So I think for us, the business is getting better. So that should either lower our dividend breakeven over time or give us greater capacity to pay out the base dividend and lower commodity prices. So I think that's a TBD capital allocation decision, but the business is getting better, so you should be able to pay a larger base dividend with the same level of protection or lower the breakeven.

No, that makes a ton of sense. And then for my second question, I know you guys touched on this a little bit, but -- regarding the additional FTE that you guys took on and you mentioned the strength of Waha kind of in the forward curve and how Waha basis kind of closes in back half of '26 and '27. What was the advantage of signing up for the FT versus just hedging out the forward curve?

Yes. I mean, obviously, there's a really large near-term benefit to these FT deals we signed up to the tune of over $100 million uplift from gas alone at strip. I do think it's our expectation and clearly the market's expectation that as some of these pipelines come online, the Waha differential should close, kind of more or less to the cost of shipping. So for us, I think -- over the long term, I think we've seen -- trying to hedge gas ultra long term, it's just not the liquidity to do so. And we think you're ultimately better off selling your gas closer to end users and further downstream.

I think although the long-term futures market doesn't reflect it, like I said, we do think you're kind of downside skew for any regional hub like Waha is worse and more impactful than your upside. So I think the way we think about it is over the long term, we think we will be better off and realize better pricing from '27 and beyond selling its Houston Ship Channel in DSW than we will at Waha. And I think that may not be every month, but I think the way we think about it is most months, it will be a push. But when you win, you'll win big, just like you've seen historically.

[Operator Instructions]

And your next question is from Leo Mariani from Rock Capital Partners.

You guys obviously did a good job lowering D&C cost yet again this quarter. You guys commented in some of your prepared remarks that there could be more downside into 2026. Could you provide a little bit more color around that? Are you starting to see leading-edge oilfield service costs make another step down here? And maybe it's a combination of that and some other things you're working on the efficiency front.

Yes. I think that, I mean, obviously, with oil prices where they are and the amount of activity being shut down and pulled out, we've seen a pretty meaningful reduction in service costs over the last few quarters, and you kind of combine that with the efficiencies we've picked up, and that's what's driven the kind of cost reduction year-to-date down to the $725 a foot level. I'd say my comments on where it can go from here is really just we are continuing to get better in the field, and I don't see at this crude price and based on activity levels of kind of the basin cost snapping back anytime soon. And so if we can maintain kind of this level of service cost and keep picking up efficiencies in the field, which we are. I think there's probably more upside or lower prices is more likely than higher from here, but I don't know what the tune is a couple of percent, something like that.

Okay. Helpful. And I guess just on the share buyback, obviously, a number of questions around it. I get trying to be opportunistic if we get in the lower for longer oil environment, hopefully be down in 2026, could you guys be a bit more programmatic if oil is kind of consistently in the 50s for a while? Or will you just kind of say, hey, it's a good time in the cycle to buy stock.

I don't think it will ever be that programmatic. I think that fails to factor in the other opportunity sets and 1 of the other things you could do with capital? And what's your view on things looking like going forward. I'd say for us, I think if we're in the 50s for a long period of time, you should expect us to buy back more stock than we have historically. I think that's pretty easy from our perspective. But I don't think it will ever be programmatic. We think we are able to create more value for us and our investors by being thoughtful and making each decision to buy back shares, do an acquisition or put cash on the balance sheet as a decision made in that time with all the facts and information we have in that moment.

So I think for us -- we don't think the programmatic strategy creates the maximum value and we're going to keep on this kind of this path that we've been on.

And your next question is from John Annis from Texas Capital.

For my first one, on Slide 5, you highlight leveraging AI to expand play boundaries, I wanted to ask if you could expand on this? And then more broadly, how do you see the opportunity for organic inventory expansion through additions of second theory zones from here?

Yes. Look, if you look at -- I think Eddy County is a good example of we have been both 1 of the most active buyers of acreage and also 1 of the most active drillers in Eddy County over the last few years. And so as such, we have a significant informational advantage over really anyone in Eddy County. We get production information, logs, incremental seismic information faster than anyone else does, just given everything that we drill is there's a 6-month plus lag before it's public. And what our team has been able to do is just kind of the workflows that we had internally, which may have previously taken weeks or months to get incorporated into passing that through to the A&D team or passing that through to the next development package.

I'd say a lot of these large language models allow us to do that in minutes. And so really, it's just speeding up the passing of information across our team to something that's kind of more real time, and that allows all the different groups, the land team, the BD team, the drilling team, the [indiscernible] engineering team, et cetera, to kind of benefit from what truly is an informational advantage that we have, albeit short term.

And then with new zones, I'd say that that's 1 that is unique, I'd say to some degree, we are seeing tons of shallow and deep, but newer zones drilled across the New Mexico Delaware. And New Mexico, Delaware has a huge benefit of state and federal leases don't have few clauses. When you drill 1 well, you hold all depths basically forever, which is, I'd say, unique to New Mexico. And given Permian Resources deep inventory position of kind of the same benches we've drilled over the last few years. I'd say that is not a huge part of our program, and we have the benefit of getting to kind of wait, watch and see.

And so we've had a, I'd say, a ton of organic inventory expansion via offset operators drilling programs that it's obviously the cheapest way to go add inventory is to kind of let others do it for you around us. I think you'll see that we'll drill, call it, 5 or 10 wells a year in kind of the more upside or kind of organic inventory expansion benches. But for the most part, we've had the luxury of getting to kind of sit back and let that get proven up by people around us.

And I think that's 1 of the things that's so special about being in the Delaware Basin is that the rate of new inventory additions really hasn't slowed over the last decade. Like every year, it seems like PR and offset operators finding a new zone. And I just 1 I think the ones that we're discovering, the zones that we're delineating actually compete with capital with the best parts of the basin. So it's not like we're finding secondary and tertiary zones that are marginal. We're finding new zones that can compete for capital day 1, and we think that's a really big differentiator in what we think is the best and most exciting basin in North American E&P.

Great color. I appreciate that. For my follow-up, staying on Slide 5. Could you expand on the microseismic Azmeh analysis? And then maybe more specifically, to what degree are you altering the astat to optimize completion efficiency relative to the analysis?

Yes, I'd say -- I mean, a lot of this is things we've been doing a long time. I think we've just gotten better, faster and further along in how to leverage it. But I mean, look, on not a large percentage, but on some amount of our program, we'll go ahead and run microseismic and microphones to really understand where fracs are going. And really, the goal is just to optimize our design. We want to pump more or stimulate more where the rock is good, and we don't want to waste a bunch of capital in places where recoveries will not be as good. And so I think what you're starting to see is just the incorporation of that in the business, both either increasing recoveries in some instances or just lowering costs in others.

I'd say that microseismic has been around a long time, but the use of it and kind of the way that people are using it today is slightly better and more efficient.

There are no further questions at this time. I will now hand the call back to William Hickey for the closing remarks.

Thank you. As you can tell by today's results, the business is firing on all cylinders. Importantly, we can continue to find ways to improve the business each and every day. Given our high-quality asset base and fortress balance sheet, we believe we can continue this execution and value creation going forward in any commodity price environment. Thanks to everyone for joining the call today and following the Permian Resources story.

Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect your lines.