Good morning, and welcome, everyone, to Permian Resources conference call to discuss its first quarter 2024 earnings conference call. Today's call is being recorded. A replay of the call will be accessible until May 22, 2024, by dialing 1 (800) 938-2488 and entering the replay active code 24995 or by visiting the company's website at www.permianres.com. At this time, I will turn the call over to Mr. Hays Mabry, Permian Resources Vice President of Investor Relations for some opening remarks. Please go ahead, Mr. Mabry.

Thanks, Bill, and thank you all for joining us on the company's first quarter 2024. On the call today are Will Hickey and James Walter, our Chief Executive Officers and Guy Oliphint, our Chief Financial Officer. Yesterday, May 7, we filed a Form 8-K with an earnings release reporting first quarter results. We also posted an earnings presentation to our website that we will reference during today's call. I would like to note that many of the comments during this earnings call are forward-looking statements that involve risks and uncertainties that could affect our actual results and plans. Many of these risks are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our filings with the SEC, including our Form 10-Q, which is expected to be filed later this afternoon. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially. We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation, which are both available on our website. With that, I will turn the call over to Will Hickey, Co-CEO.

Thanks, Dave. I truly believe that the first quarter was the most compelling quarter Permian Resources has delivered so far. We were able to deliver production and free cash flow above our expectations, close out the integration of Earthstone ahead of schedule while increasing our annual synergy target by $50 million and continue to execute on accretive A&D with approximately $270 million of acquisitions announced this quarter. It takes an incredible team to deliver such strong execution quarter after quarter, and I look forward to sharing some more detail on Q1 today. Moving into quarterly results, I'm pleased to announce Q1 production exceeded expectations with total production of 320,000 barrels of oil equivalent per day and oil production of 152,000 barrels of oil per day. Our strong production was attributable to multiple factors, including accelerated Earthstone D&C efficiencies and higher operational run times. Strong production results and CapEx of $520 million in the quarter resulted in adjusted operating cash flow of $844 million or $1.09 per share and adjusted free cash flow of $324 million or $0.42 per share. We remain highly focused on sustaining a strong balance sheet with leverage of approximately 1x and increased liquidity to over $2 billion. As part of our regularly scheduled spring bank redetermination process, we increased aggregate lender commitments under the credit facility from $2 billion to $2.5 billion, while maintaining a borrowing base of $4 billion. Turning to return of capital. Our strategy remains consistent. We delivered on our previously announced increased base dividend of $0.06 per share, a 20% increase from previous quarters. For the variable portion of our return of capital, first, we repurchased a total of 2 million shares in the quarter. The remainder of our capital return will be paid out via a variable dividend of $0.14 per share, bringing the all-in quarterly return of capital to $0.24 per share. Now I'd like to spend a little time talking about the efficiencies and synergies that impacted the business in such a positive way this quarter. We rolled out the Earthstone acquisition, we were highly confident that we could reduce drilling days and completion days and improve production operations, driving material synergies to be fully realized by year-end 2024. We have already achieved that and more. In just under five months, we've high-graded all legacy Earthstone rigs and completion crews. This, combined with PR best practices, helped drive an 18% reduction in Earthstone drilling days per well and approximately 50% reduction in completion days per well in the first quarter, which we were initially anticipating achieving by midyear 2024. Additionally, we are seeing some efficiency gains in the Midland Basin that were not originally forecasted which is a testament to our team's ability to unlock value on new assets quickly. In addition, run times improved as a result of better compression performance, optimized artificial lift and improved chemical programs. The combination of accelerated activity and better run times was the primary driver of the strong production performance in Q1. The impact of the combined PR teams integration execution is that we have already achieved $175 million per year of synergies and are increasing our synergy target to an annual run rate of $225 million. As I mentioned earlier, the main drivers of this increase are operational. For D&C, we increased our per well savings from $1.2 million to $1.5 million. Similarly, we expect to be able to improve margins by approximately $1 per BOE by year-end, but we've already implemented stages in the field to realize the majority of this improvement today. Drivers of the margin improvement include reduced trucking, upgraded electrical infrastructure, rationalizing vendors and optimizing midstream agreements. Integrations are never easy, but what our team accomplished over the last six months is a testament to a lot of hard work and dedication, and we're proud to say that Earthstone is fully integrated. With that, I'll turn it over to James to talk to A&D and an update on our 2024 plan.

Thanks, Will. I'd like to quickly reiterate what we led off with today that PR's results this quarter are the best results we have had as a public company and adapt to every department and every discipline at Permian Resources. This now marks our seventh consecutive quarter of strong operational execution as a public company and our ninth year as a leading operator in the Delaware Basin. We are highly focused on continuing to increase our track record of consistent results in low-cost operations. Our team is firing on all cylinders, positioning us very well for the remainder of the year. While successfully executing in the field and wrapping up the integration of Earthstone, our business development and land teams continue to source, evaluate and close attractive deals in and around our enhanced footprint. Our overall objective when it comes to A&D is to target acquisitions that enhance the quality of our business and drive value for shareholders. For us, that means seeking our acquisitions to increase the quality and duration of our current inventory at prices that make sense and our recent acquisitions achieve all of these goals. Yesterday, after market closed, we announced two separate bolt-on transactions directly offset our legacy Parkway asset in Eddy County. This asset is characterized by low D&C costs and high oil cuts that make it one of the most capital efficient assets in our portfolio. This is why we're so excited to bolster our position here with the addition of high-quality, high NRI locations that immediately compete for capital. In addition to these bolt-ons, we remain highly active on the grassroots side of the business, completing approximately 150 smaller transactions ahead of the close. These smaller deals target near-term development and are among the highest rate of return acquisitions that we find. All in, these transactions add over 11,000 net leasehold acres and approximately 110 gross operated locations for a purchase price of $270 million, of which we expect $245 million to be paid in the second quarter. After accounting for production value, this works out to a little less than $10,000 per net leasehold acre and approximately $1 million per gross location or $1.5 million per net location. Our presence in Midland has been one of the key drivers of our successful acquisition program, and the vast majority of the acres we are acquiring in today's announcement come from Midland-based counterparties who we have long-standing relationships with. As Will mentioned earlier in the call, our team's successful execution has reduced our drilling and completion times, allowing us to bring barrels forward into Q1 and increase overall production for the year. As such, we are increasing our stand-alone production guidance to 150,000 barrels of oil per day and 320,000 barrels of oil equivalent per day. This represents a 2% increase compared to our original guidance ranges with no change in CapEx or other guided categories. Coming out of this acceleration of production in the first quarter, we anticipate a relatively flat production profile in the second quarter, with modestly lower stand-alone production in the second half of the year. The slight decline is driven by normal course fluctuations in working interest that occurred during a large-scale development program. The revised guidance outlined on Slides 10 and 14 reflect Permian Resources' stand-alone projections and do not include the impact of the acquisitions we're announcing today. We expect those acquisitions to add an average of approximately 3,500 BOE a day during the second half of the year. Given the high-quality inventory we acquired in these assets, we do expect to begin development in the second half of the year, which we anticipate resulting in $50 million of incremental CapEx. In summary, this is a terrific start to the year, and we are proud of what we've accomplished so far in 2024. I'd like to conclude today's prepared remarks on Slide 11, which helps to reemphasize our value proposition for current and future investors. We think that the announcement today really highlights the quality of Permian Resources' business and the multiplied approach we have to driving outsized shareholder value. Since the company reported in 2022, we have delivered best-in-class returns for our sector, amounting to over 3x the annualized return to the S&P 500 during that same time period. Our performance over the last years has been driven primarily by low-cost execution and accretive transactions. And as a result, PR makes a compelling value within large capital oil and gas, particularly when recognized in the Permian. Permian Resources is now the second largest Permian pure play in the sector. Thank you for tuning in today, and now we will turn it back to the operator for Q&A.

Thank you, Mr. Walter. We'll go first this morning to Neal Dingmann at Truist Securities.

My first question, James, maybe on your D&C plan for you, Will, correct me if I'm wrong, but I believe you're currently running about 11, 12 rigs, three to four spreads or about the same as PR and Earthstone was separately. And I'm just wondering, given your notable continued efficiencies that you certainly highlighted today, I'm just wondering, and I believe the goal of relatively flat production, maybe could you talk a little about potential to drop rigs or spreads or maybe just how you see the maintenance plan on a go-forward?

Yes. I mean I think you're right. Like if you think about the plan this year, we were originally saying we drilled about 250 wells and we thought that would take about 12 rigs. With the efficiencies we're seeing today, I think it's very realistic that we could continue to execute on the same plan to whether that's 11 rigs or somewhere between 11 and 12. I think if we can keep these efficiencies, it's very much on the table. If you think back to the Colgate CDEV merger, it's a very similar playbook; if you think originally, that was an eight-rig combined business that we were able to get down to six with the same level of efficiency. So we've done this before. I do think it's worth calling out we're not solving for some maintenance plan or production per se. It's much more just an input of what's the return environment, what can macro look like from a supply-demand perspective and what service costs look like so that production is more of an output. So if we continue to see strong oil prices and reduced service costs, I think it's very realistic that we could decide to keep the 12 rigs or even add rigs from here to grow production. But what you see in our revised guide is more of that stick to the 250 wells and we think there's a chance we could do that with less equipment.

Good to hear, Will. And then secondly, just quick on the bolt-ons, such as the recent two that you all highlighted. You all seem just to have continued to have better success adding these accretive bolt-ons versus it just seems like I don't see as many of your peers been able to do this. So I'm just wondering what are the keys behind this? And can you continue at this pace of adding a couple two, three — it seems like almost every quarter?

Yes. I think that's a pretty easy answer. I think first and foremost it's something we're focused on and prioritizing. It's something we've done for a long time and continue to be really good at. And I think that's driven by a couple of things. I think, first and foremost, we have the lowest cost structure in the Delaware Basin, which allows us to earn higher returns on the same assets. And as a result, naturally over time, assets like these tend to flow to the low-cost operator. I'd say second, we're based in Midland. That's the heart of the Permian, the heart of the deal flow, and we've got a great reputation across the market of being good partners that people want to be across the aisle from on the transaction side, and that goes a long way. And finally, for today's example, I mean, this is a really good area where I think we do have a unique edge from activity and therefore, the information side of things. We have more rigs running in this area than anybody else and therefore, more proprietary data to pull from and better understanding. So I think you take all that together, it does feel like something that is definitely sustainable. Will we do this every quarter? Probably not, but it's something we expect over the long term to continue to be a big part of the story.

We go next now to John Freeman at Raymond James.

It's a great quarter. When I'm looking at Slide 6 and 7 and just these huge efficiency gains that you all continue to get out of the legacy Earthstone properties, I'm just trying to get a sense of what maybe that remaining gap is, if any, between legacy Earthstone and PR on whatever metrics you use, whether it's cost per well, drilling days, completion days, production downtime, just some sense of how that compares to PR. Just trying to see if there's still any gap left.

I think on the D&C side, the gap is very small, if not nonexistent at this point. We have different efficiencies and different assets in different areas, but we view different areas — whether it's legacy or senior legacy — PR no longer matters. It's more it's all PR and I think on the D&C side, that gap has closed. Where I think there's still some room is on the LOE side. We've made tremendous progress in the short amount of time of improving margins through what we've done on the contract side, but also just reducing LOE. But a lot of the other LOE stuff, I think like SWD disposal agreements or recycling agreements have some time to them and require more work and more time to get fully incorporated. So as I think about where the last kind of gap remains between legacy Earthstone and PR would be more LOE focused, if that makes sense.

That's perfect. And then just the follow-up for me. Gas takeaway has been pretty topical, what's going on at Waha. Just any updated thoughts on how you all are thinking about gas takeaway and how to address that longer term?

Yes. I mean I think it's pretty obvious running the call, pricing at Waha has been challenged this year and probably will be until we get closer to new pipes coming online in the fourth quarter. And I think that is what it is. We're fortunate that dry gas only makes up about 5% of our revenue in any given year. So the business really isn't affected materially. But I think worth pointing out that only about half of our gas is exposed to Waha pricing this year; the other half is either covered by attractive basis hedges or sales at better regional hubs today. But yes, something we're always trying to focus on and work on. We sell about one quarter of our gas at hubs other than Waha today and are constantly looking to find ways we can get more sold at Houston pricing next year. We actually have a contract we expect to get signed in the next week or two that should allow us to get more volumes sold at Houston pricing next year. So more to come on that front. I'd say that's something we've been working on for a long time and continue to chip away at. But I think the most important thing is we've got excellent partners on the midstream side. We've got firm capacity and our molecules are going to flow even if we saw regional constraints later this year.

We go next now to Scott Hanold at RBC.

I was wondering if you can go back to sort of the outlook through the balance of the year. And just holistically, how you guys like to think about the business. Obviously, your cycle times are improving. So you pulled for a little bit more of your activity and production in 1Q. And so like you said it does taper and you have a soft decline in the back half of this year. But how do you think about the setup then for '25 with that? Would you guys into '25 and over the long term, like to see more flattish growth? Do you want to see some more moderate growth? And if you could talk about any cadence variability through the year? Would you like to keep things constant? Or do you think there will be some cadence depending on the cycle times?

I mean, first and foremost, as we think about the trajectory from a production perspective of the company, I've said it many times, I'll say it again, it really is a returns-driven input and production is just an output. Obviously, over the last two weeks ago, I'd say the returns environment was extremely good. And we've made some headway on the service cost side over the balance of the year. So it was looking good. I think that today, it's still good, but not quite as good as it was a few weeks ago, and I don't yet know what the world will look like six months from today as we go into '25. I would say that if you think about what happened over the course of this year so far it's just the whole schedule has shifted forward. We're drilling wells faster. We're completing wells faster. And as such, given the natural working interest changes over large-scale development, the back half of the year dip is just a little bit less working interest on the few wells that moved in from the next year. And that naturally corrects itself. Said differently, if we maintain the same pace, call it 250 to 260 wells per year, that actually does set up for a really good 2025. It's a slight decline in the back half of the year and then bounces back in '25. I'm not saying that is our final plan; we're going to spend a lot of time over the next six months to work out exactly what we want to do for '25. I think it could be anywhere from 11 to 13 rigs based on commodity prices and we'll see what makes sense there. But I wouldn't think of this kind of slow tapering in the back half of the year as an indication of the future trajectory of the production profile in outer years.

Yes. This plan sets us up, like we always do, with really good optionality because we don't know what the world is going to look like in '25 and it puts us somewhere in the middle of that 0% to 10% growth over the long term that we talked about, and we can make a decision as we get closer to that year.

I appreciate the commentary. And in your prepared comments, you also mentioned that you're seeing some better performance or efficiencies in the Midland and it sounds like you weren't necessarily expecting that. Could you give a little color and context behind exactly what that is and where the benefits were? Was it more well productivity? Or is it cycle times or just cost reductions on OpEx?

It's really just D&C CapEx. We have not drilled a lot of wells in the Midland Basin. I didn't expect to be able to cut near the amount of cost in the Midland Basin side we have on the Delaware, and we've been surprised to the upside in that regard. I still think we have a ways to go to catch up with where the leading operators in the Midland Basin are from a CapEx perspective, but we've made big strides that surprised us to the upside.

And was that more on just the cycle time drilling and completion time in those markets?

Just cycle times, casing design, everything that would lead to a lower CapEx per foot on a Midland Basin well.

We go next now to Gabe Daoud at TD Cowen.

I understand it's certainly a little bit too early to be thinking about '25, but I guess just piggybacking off that question here. If we just think about all the synergy capture and efficiency gains and maybe this year being a little bit heavier on midstream spend or infrastructure spend, is it fair to assume maybe '25, assuming similar activity levels, CapEx is probably a bit lower than where we are today?

Yes. I think certainly maintenance CapEx would be lower than what we've outlined this year, just given where the business is and the efficiency gains. I think that's definitely a fair assumption.

And then maybe as a follow-up, noted you talked about egress a bit. So just curious in that Northern New Mexico area, both Eddy and Lea, are you seeing any processing capacity tightness or any other midstream matters that are worth mentioning? I recognize there's no rigs over in that headcount you said, is that driven by constraints at all? Or are you guys just planning on getting out to that in the second half of this year?

Yes. I mean I think the lack of rigs in any area today is just driven by our focus on doing some of these larger developments and making sure when we put rigs on it, we're doing it as quickly and as efficiently as possible and co-developing all parts of the cube that need to be co-developed. So no, I think macro-wise, gas processing constraints actually feel really good this year. I think last year, around Q2 and Q3, there were more challenges on processing, but even more in-field compression and plumbing issues in the middle of last year, but those have all really resolved themselves. Our midstream partners have done a ton of work and spent a ton of money and gas processing in the New Mexico Delaware looks like a great spot today. Frankly, we're thankful not to have any constraints of that nature or anything else preventing us from doing what we want up there.

We'll go next now to Derrick Whitfield at Stifel.

With my first question, I wanted to lean in on your D&C efficiencies to better understand the rate of improvement you're seeing. If we were to compare PR Q4 to Q1 on Slide 6, how do these cycle times in the Northern Delaware compare with your Q4 averages?

PR from Q4 to Q1, we've gotten better, but it's going to be a single-digit percent improvement as compared to the big improvement you see if you compare legacy Earthstone to PR.

Great. And then maybe shifting over to Slide 9. The identified location count of 110 gross locations appears conservative to us on the surface. Can you offer any color on the degree of legacy operator development and your general underwriting assumptions for this part of the basin?

Yes. It's a good question and very astute. To answer your second question first, it's pretty undeveloped acreage position; there's a handful of wells on it, but it's undeveloped as any asset we've looked at in a long time, which is great because it allows us to come in, take advantage of clean fairways and do what PR does best. With regards to inventory, yes, I think it probably is conservative. I think we're trying to book locations that we have a very high degree of confidence in here. Is it more likely to have more zones come into the money here? I think the answer is probably yes. But we feel good about what we put out as being a real base case and something that we can stand behind.

We'll go next now to Leo Mariani at Roth MKM.

I wanted to dig in a little bit to your comments around flattish second quarter production and then slightly lower in the second half. If I heard your comments right, it sounded like a lot of this was just based on working interest changes. I was hoping maybe you could quantify some of that? I think you guys are talking about 75% average working interest, but maybe it's a little higher in the first half and lower in the second. Just any help on that would be great.

Yes. I think it's just normal fluctuations when you're running a multi-rig program like this, especially when stacking rigs to pursue the full field development strategy that we've been pursuing for a long time. Like one quarter may be 70% and one may be 80% to get back to an average of 75%. That's just how it is. I think you see this especially over time as you have more concentration of rig counts on particular developments, but it's all normal and evens out over time.

Okay. But it definitely sounds like working interest is a little higher in the first and a little lower in the second half. And then how would that translate into CapEx? Would that basically give you CapEx a little lower in the second half standalone versus first half?

Yes. I think that's a good assumption.

We'll go next now to Oliver Huang at TPH.

I wanted to start on the A&D side. I can't help notice you all have been fairly active in this area of Eddy County looking back at the Q1 bolt-ons and the latest two transactions. So just wondering if you all might be able to speak to if there is anything specific that you're seeing in the area that's driving an increased focus from an A&D perspective for you all?

That's a great question. And I think post-closing of Earthstone to today, we just saw a real market window where we were able to go buy four extremely attractive bolt-ons and quite a few grassroots deals at prices that were really attractive to us. And I think the reason we're able to do so, which I touched on a little bit with Neal's question at the beginning, was because we've been the most active operator in this part of Eddy County for a long time and therefore, had a lot of really exciting proprietary results, both on zones, well performance, and most importantly, the cost side where we're doing this cheaper up here than I think anybody would expect. So it's unique. It's one of those windows that we saw an opportunity, and we hit it hard. And I think these are some of the best deals we've done. So yes, I think it wasn't guaranteed we'd get all of these deals the way we did, but it's a great outcome, and that's really core inventory and our most capital-efficient asset.

Makes sense. And for my follow-up, just wondering if you all could provide an update on your royalty position. It seems like an aspect of the business where you all have been able to steadily pick up some decent interest over the past nine months or so that's kind of gone under the radar. So any color there would be helpful.

Yes. I mean I think we're always trying to buy acreage and inventory that competes for capital, and a big part of that is what is the royalty burden. So we target assets that have advantaged NRIs and lower royalties that really just help our capital efficiency. I think today, we've built a royalty position that we're really proud of — 75,000 net royalty acres is not insubstantial. I think it's strategic with what we have planned with that today. But I do think that's a big part of our capital efficiency story. We're getting more free cash flow for every dollar of CapEx that we spend as a result. So I think ultimately, it's something that just makes our widget better and helps our value creation increase over time. So it's something that we're proud of, focused on, and probably a little underappreciated by the market, but it really ultimately comes down to helping us earn better returns on every dollar that we spend.

We go next now to Geoff Jay at Daniel Energy Partners.

I know you referenced your power infrastructure build-out. I'd love to hear what's happening there, what the scale of that is, how big that's going to be for you guys. It's obviously a pressing issue these days.

Yes. Look, line power in the entire Permian is tough — in Texas it is tough and in New Mexico it is tough. So we're trying our best to stay in front of it. I'd say as you think about our power needs, if we can be on line power, that's obviously preferred. After that, if we can leverage natural gas power generators that's probably the second best answer, and that's what you'll see for the majority of our New Mexico infrastructure. But it's a priority for us. We're actively looking at ways to improve that position, collaborating with others to look at building incremental substations and really anything we can do, but it doesn't come quick, and I think it will be a challenge for the industry for the next few years. I don't think it means we won't be able to produce our wells. It's just a little bit less efficient to be on natural gas power generators than it would be to be all on line power.

We'll go next now to Paul Diamond with Citi.

Just a quick one, talking about the acquisition pipeline. As you're looking forward to what's next, are you seeing any movement on the bid-asks based on scale or location? Or is it all pretty much pre-cohesive and correlated?

Look, I think our pipeline on the A&D side feels really good. I think there's a lot of opportunities in the Delaware. And I think our position as a preferential party for a lot of sellers and a low-cost operator in the basin positions us well. Assets come for sale both in marketed deals, which we participate in successfully, but also, importantly, off-market assets, which has been a large chunk of our acquisition program historically. It feels good. I don't think that's the size of deals you saw hitting the market in '22 and '23 in the Delaware, which I think we largely stayed on the sidelines from. But I think we're seeing a lot of stuff that fits the grassroots side and the momentum there is good, and we're still seeing lots of bolt-ons probably coming down the pipe this year. Will we acquire all of them? Definitely not. But some could fit. I'd like to think so. We're really picky, and we want to buy assets to make our business better and earn a higher rate of return and drive value for shareholders. So if we can continue to do that, that's great. But we said it before, we don't need to do anything. We've got an incredible inventory base and an incredible stand-alone business. So if we find those opportunities, we'll be excited to pursue them, but we certainly don't see any pressure to do so.

Understood. And just a quick follow-up. So that's why I guess you've been pretty balanced in your shareholder return framework. Is there anything you guys are seeing in the markets that would tip that scale one way or the other?

I mean I think we're going to naturally bias towards the dividend. I think that the variable dividends are our base case, and we'll be opportunistic on potentially increasing share buybacks at some point in the future if dislocations and large opportunities exist. But no, I'd say really steady as she goes on the capital return strategy. I think it's worth mentioning, we did show a 20% increase in our base dividend this year, which will be reflected in the upcoming quarterly dividend payment and a nice increase in our variable cash dividend as well. So it feels like that's working really well, and we're excited about it.

We'll go next now to Kevin MacCurdy at Pickering Energy Partners.

To follow up on an earlier question about M&A, your last couple of deals have been concentrated in the Northern Delaware. Just a general question on how you are viewing opportunities in the Southern Delaware versus the Northern Delaware — are there as many opportunities out there? And how do you compare the two?

Yes. I mean I think that's a great question. Looking back historically, the first consolidation wave in the Delaware was Texas-focused. If you think like 2017, 2018, 2019, a lot of Texas businesses and that's where the Delaware got started and activity was faster to begin. So I think you've seen a natural consolidation wave in the Delaware as of late. I think for us specifically, we've got a great Texas position today with some really high return go-forward drilling to do. If we could find opportunities in Texas that compete for capital like what we've seen in New Mexico, we'd be really excited about it. I think those opportunities do still exist. I just think the majority of assets that we've seen that make the business better from a capital efficiency standpoint have been in New Mexico over the last couple of years, but I think that could change and we'd be really excited if we could find similar opportunities on the Texas side.

Great. And changing gears a little bit. You mentioned an additional 3,500 barrels a day equivalent and an additional $50 million of capital once you close the bolt-on acquisitions later this quarter. Just to clarify, is the 3,500 barrels a day flowing? Is that currently production now? And if so, what will be the production impact of the additional $50 million capital spend?

Yes. That production is online now. The majority of that is from an acquisition we haven't closed and don't close until the end of this quarter. So it's online now, but it's not ours yet. And then that $50 million is CapEx we're going to spend in the back half of this year on some high-return inventory that is really exciting to get our hands on. Because we don't own it today, we can't give all the production guidance you'd see from that asset until we own it, but it delivers really strong returns and so we're excited to get after it once we close.

And gentlemen, it appears we have no further questions this morning. Mr. Walter, I'd like to turn things back to you, sir, for any closing comments.

Having gotten off to a great start in 2024, our primary goal remains the same as it was when we announced the Colgate Centennial merger in May of 2022: to maximize shareholder value for the long term. 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. Thanks to everyone for joining the call today and for following the Permian Resources story.

Thank you, gentlemen. Again, ladies and gentlemen, that will conclude today's Permian Resources First Quarter Earnings Conference Call. Again, thanks so much for joining us today, and we wish you all a great day.