Permian Resources Corporation Class A

Good morning and welcome to Permian Resources Conference Call to discuss its third quarter 2024 earnings. Today's call is being recorded. A replay of the call will be accessible until November 21, 2024 by dialing -839-5495 and entering the replay access code 26601 or by visiting the company's website at .permianres.com. At this time, I will turn the call over to Hayes Mabry, Permian Resources Vice President of Investor Relations, for some opening remarks. Please go ahead.

Thanks Todd and thank you all for joining us. On the call today are Will Hickey and James Walter, our Chief Executive Officers, and Guy Oliphant, our Chief Financial Officer. I would like to note that many of the comments during this earnings call are forward-looking statements that involve risk and uncertainties that could affect our actual results or plans. Many of these risks are beyond our control and are discussed in more detail in the risk factors and the forward-looking statement sections of our pilings with the SEC. Although we believe the expectations expressed are based on reasonable assumptions, they're not guarantees of future performance and actual results 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. With that, I will turn the call over to Will Hickey, Co-CEO.

Thanks Hayes. We are excited to discuss our third quarter results this morning. During the quarter, we successfully closed our BriaDRAW bolt-on acquisition and continued driving operational efficiencies that have led to further well-cost reductions. Notably, we are raising our full-year production guidance for the third consecutive quarter while maintaining our CAPEX guide. Overall, the PR team continues to perform at a very high level across the organization, which translates into improved capital efficiency and strong free cash flow generation, details of which we look forward to sharing this morning. Moving into quarterly results, Q3 production beats expectations with oil production of 161,000 barrels of oil per day and total production of 347,000 barrels of oil equivalent per day. Our strong performance is attributable to multiple factors, including continued DNC efficiency gains and consistent well performance. Based on these results, we are raising our full-year oil guidance again this quarter, amounting to an 11,000 barrel of oil per day increase compared to our initial guidance in February. Notably, nearly 8,000 barrels of oil per day of our guidance increase this year is a direct result of the outperformance of our base business, with the balance resulting from executing on highly accretive M&A. Importantly, we are doing so without changing our original CAPEX guide, despite bringing online more wells this year than originally budgeted. We were able to accomplish this due to our reduced cycle times and further cost optimization. We continue to deliver leading cash costs that support strong margins, with Q3 LOE of $5.43 per BOE, cash G&A of $0.95 per BOE, and GP&T of $1.57 per BOE. Strong production results paired with low cash costs and CAPEX of $520 million in the quarter resulted in adjusted operating cash flow of $823 million and adjusted pre-cash flow of $303 million. While we'll hit on this later, it's worth noting we achieved these results despite modest contributions from our gas and NGL production streams, particularly where we had another weak quarter for Waha Gas. This demonstrates the strong underlying performance of the PR business model and the potential upside we see from improving natural gas realizations. Turning to slide four, this updated version of a slide we shared at an investor conference a couple months ago emphasizes not just the growth of the company, but how we've been able to transform our business. First, we've been consistent with what we believe creates value, which is shown on the right-hand side of the page. These value drivers are really the same as when James and I founded the predecessor company Colgate in 2015. Our focus remains on the Delaware Basin, which we believe is the top oil shale play in the lower 48. The single basin focus, along with our Midland headquarters, has established us the most efficient cost structure in the Delaware, which in turn drives outsized returns on acquisitions. These acquisitions not only improve the quality of our business, but also provide near-term, mid-term, and long-term accretion. At the core of our strategy is a relentless focus on creating long-term value for our shareholders, which we measure on a per share basis. Our primary goal is to grow long-term pre-casual per share with total shareholder returns expected to follow. Slide five illustrates how our basin expertise and cost leadership have continued driving efficiencies throughout this year. On the drilling front, we set a record this quarter of 13 days spud to rig release. To put this in perspective, we began the year expecting to till 250 wells with 12 rigs and are now on track to till 270 wells with that same rig count, effectively adding an entire rig's worth of wells through efficiency gains. On the completion side, we've increased pumping hours per day again this quarter to 22 hours per day and now run all dual fuel frac fleets, which represent a material savings in the current gas price environment. As a result, our Q3 tills were 15 percent cheaper than last year on a per foot basis, translating to over $1 million per well in savings. Given these reductions are mostly due to efficiencies, we expect they will be here to stay. And with that, I will turn the call over to James.

Thanks, Will. Turning to slide six, we wanted to spend some time discussing how Permian Resources is approaching the marketing of our hydrocarbons. As you guys all know, the economics of Permian Resources business are primarily oil driven. They always have and will continue to be. But it is worth pointing out that PR is also one of the largest natural gas producers in the Permian Basin, producing approximately 600 million cubic feet per day of residue gas. This creates the potential for significant upside to free cash flow generation if natural gas prices improve going forward, as is widely expected. For example, a $1 increase to our residue natural gas realization increases annual free cash flow by approximately $200 million, and a $3 increase would increase free cash flow by almost 50 percent. At Permian Resources, we are incredibly proud of our performance operationally and pride ourselves on being a leader in the basin across almost all metrics. But given our rapid growth, we've historically focused our midstream and marketing efforts more on flow assurance and optimizing netbacks. And we've been extremely effective at ensuring all of our hydrocarbons can get to market with zero interruptions over the past five years. But as our business grew to the scale it is today, particularly with the Earth's own acquisition we closed 12 months ago, we've shifted our focus to also enhance the prices we receive for our oil and natural gas. And we've been successful working to optimize our netback so far in 2024. For example, we have increased the amount of natural gas we sell at the Gulf Coast by almost 50 percent, and netting an extra dollar on those molecules as compared to selling them at Waha like we had historically. But we aren't satisfied with where we are today. Midstream and marketing is an area we expect to improve performance and drive meaningful incremental free cash flow in the coming years. Unfortunately, we have a lot of levers to pull to do just that. We have significant flexibility to improve downstream sales contracts with both crude and natural gas. We expect to leverage our scale in the basin to reserve space on existing oil pipes, take equity in future pipeline projects, and ultimately increase our access to Gulf Coast oil and gas markets. The expectation that the U.S. will see a step change in power demand over the next 15 years has created opportunities for increasing dialogue around the potential for power generation and data projects within the Permian Basin. We are also exploring opportunities to more efficiently power our operations using in-basin gas. Although most discussions are in the early innings, we are excited about the potential demand implications for Permian gas over the next In early September, we updated our Return of Capital policy to further emphasize the base dividend as our primary form of capital return. We increased the base dividend by 150 percent to 60 cents per share annually. Our current base dividend yield is over 4 percent, which puts us well above our peers and highlights the relative value that Permian Resources stock represents today. Our base dividend as a percentage of free cash flow remains below our peer average, reinforcing the dividend sustainability across cycles. We will continue to approach buybacks with the same philosophy we have had since inception, where we use the buyback opportunistically and in periods of clear market dislocations rather than targeting a consistent monthly or formulaic approach to buybacks. When we do choose to execute on a buyback program, we expect to do so in a meaningful way, and as such have increased the buyback authorization for $500 million to $1 billion. Our management team owns over 6 percent of Permian Resources today, and we approach decisions with a strong alignment that comes with being meaningful owners of the business. Our goal every day is to drive total return for our shareholders, and we think this updated policy positions as well for continued outside value creation. Turning to slide 8, we are really proud of where our balance sheet is today and all we have accomplished this year. We have deployed over $1 billion on acquisitions while maintaining leverage right at one time. We have increased the average return of our outstanding bonds to approximately 6 years, and we have meaningfully increased our liquidity position from the start of the year today and are actively building cash. Between our cash balance and our un-drawn RBL, we have almost $2.8 billion of liquidity that should be available through up and down cycles. We have also protected our downside through hedging. We are over 25 percent hedged heading into Q4 at $74 and similarly hedged as we head into 2025. Going forward, we are highly focused on achieving investment grade ratings in 2025, and we are upgraded by all three agencies this past quarter. Our financial strategy is the same as it has been the last nine years. To maintain a fortress balance sheet with low leverage and liquidity, we can capitalize on opportunities across multiple cycles. Turning to slide 9, we continue to be proud of our track record of operational execution and financial performance. We are increasing our full-year oil guidance for the third consecutive quarter by 6,500 barrels per day, with the majority of this outperformance coming from our legacy business rather than recent acquisitions. The outperformance comes from a combination of accelerated cycle times and strong well performance. The efficiency we have seen on the drilling and completion side are to accelerate wealth and production while maintaining capex within our original guidance range. We continue to optimize our cash cost for 2024, realizing better tax synergies from the Earth-Stone merger than we had previously expected. As such, we are reducing our current tax guidance for 2024 to $10 to $15 million from $50 million previously. Looking back at the full year, we have increased oil production guidance by 11,000 barrels per day, or 7 percent up from our original guidance, with over 70 percent of this outperformance coming from our base business. We think this continued outperformance demonstrates the strength and quality of our business. I will be concluding today's prepared remarks on slide 10, where we re-emphasize our value proposition for investors. The strength of our business is underpinned by an industry-leading cost structure, low breakeven, and long-dated high return inventory, which together have driven leading free cash flow per share growth for our investors. When we talk about having generated leading shareholder returns since inception, we think it's important to highlight that these outsized returns have been driven by strong operational performance and accretive acquisitions rather than multiple expansion. Since the beginning of 2023, we have meaningfully increased the size and quality of the business, but more importantly, have increased oil production and free cash flow per share by 50 percent, all while improving the strength of our balance sheet. As large owners of the Permian Resources business, we are highly aligned with shareholders to continue to drive outsized shareholder returns for years to come. Thank you for tuning in today, and now we will turn it back to the operator for Q&A.

Q&A Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing star, then the number one on your telephone keypad. If you would like to withdraw your question, press star two. Once again, to ask a question, please press star one. Our first question will come from Neil Dingman with Truett Securities. Please go ahead.

Good morning, guys. Outstanding quarter. Guys, my first question is just on your future operational plans. I'm just wondering, will 2025 DNC regional focus, and just wondering when you look at New Mexico and Texas, will that stay essentially the same? And just I'm wondering, maybe probably nothing here, but just wondering if any potential loosening of restrictions by the administration, particularly maybe in like New Mexico or wherever, might have any sort of changes to the capital?

I think 2025 will look similar to what the last couple of years have. The majority of the capital spent in New Mexico with the balance probably being Texas, Delaware, and kind of keeping Midland as sub 10%. I think there's a chance that you see a little bit less even in the Midland Basin than we had this year as we probably moved that to the Bria draw acquisition on the Texas side. But kind of majority New Mexico development just like we've been for the last couple of years. We're well ahead of the permitting and all the needs. So like really having a looser or easier kind of regulatory environment, I think probably doesn't change anything from our side. If on balance, it probably gives us a little bit of flexibility if we want to make some kind of more last minute changes around different paths, which is nice to have, but not a need to have.

Great points, Will. And then just for second question, can't help but ask around your slide specifically, could you discuss, you know, I don't know what type of plans you can do with those 25,000 surface acres and, you know, the 40% taking high end gas, you know, what upsides is that optionality provide?

Yeah, you know, on the service side, I think that's just that's really just one of several non upstream assets. We're constantly working through how we can maximize value for our shareholders for something that's, I think, a little more under the radar than our base business. You know, big royalties business, we've got a modest midstream business, but I think specific to the surface, I think we an outright sale could be an option. But I think really, we think there's potentially some interesting developments that I think ultimately take time, but could provide ways for us to work with more infrastructure related parties to really fully optimize the value from that surface. I mean, I think kind of embedded in your question, I think, as we look at AI data centered demand, we think that's going to be real in the United States going forward. And I think especially with administration changes, I think natural gas is really well positioned to be a beneficiary of changes in the power consumption landscape going forward. And we think that the Permian basin and Permian resources, particularly should be very well positioned to benefit from that tail end and should help in based on natural gas prices over time. I mean, if you think about the Permian, we've got abundant natural gas, we've got a supportive regulatory environment, we've got a very rural landscape and, you know, a tremendous long dated inventory with a lot of gas that historically has been pretty cheap. So I think we're really optimistic that that can provide a tail end on the gas side of the business in the coming years. And answer your third question or second part of your second question, the ultimate goal at that 40% of the gas would be to move as much of those volumes over time to more favorable downstream markets, specifically the Gulf Coast. And I think it's important to point out on that slide you referenced, I think of that 60% we have that's currently committed, but half those volumes are selling at the Gulf Coast today. So if you kind of took the 40 and the 30 there, you know, I think over time could ultimately have between 60 and 70% of our gas pricing and kind of non-Waha markets, but that does take some time to get there. Thank you both.

Thank you. Our next question will come from Scott Hanold with RBC. Please go ahead.

Yeah, thanks all. Hey, I want to hit a little bit on, you know, how you view 2025. I know it's probably for you guys too early to give, you know, some firm numbers, but, you know, certainly on our side of the table, I mean, it's obviously a very, you know, strong point of emphasis right now. So just conceptually, can you help us think through, like, look, you guys are really peaking on production in fourth quarter, you know, as you look at strip commodity prices from that peak level or average levels in 2024. How should we think about the progression of production in the next year at current strip prices? And what does that mean roughly for CapEx?

Yeah, Scott, I mean, I think we're going to continue on now longstanding policy of not providing much of a look at 2025 guidance until we get to February of next year. I think that policy served us and our shareholders really well the last couple of years. I think that gives us a couple of months to further refine our plan. But I think just as importantly to assess the kind of background, the macroeconomic backdrop and the kind of service cost environment, I think really our approach to what the next year and what growth looks like hasn't changed. I think we're targeting a growth range of zero to 10% based on the prior year's average. And I think, you know, for us, it's really too early to tell what next year looks like. I think we'll reference it as prepared to mark. Like our returns are really attractive today, but I do think there's some potential, you know, storm clouds on the horizon or some questions on the oil price from a macro standpoint. So for us, it's really too early to tell what it could look like. I think you're right in pointing out that Q4 is a really strong exit to the year. And we'll kind of have to wait until next year to see what the balance of the year looks like.

Got it. So yeah, just, you know, it was sort of, it wasn't the point I was trying to get to, what would it take to kind of keep that fourth quarter run rate flat? That's obviously, from your view, a maintenance plus kind of level, is that correct?

Yeah, I mean, I think historically we've talked about maintenance capex. We've talked about the prior full year average, which would be that 158.5 we got at the back of the deck. And I think we've talked about maintenance capping in the past as, you know, a few hundred million dollars below what we've spent this year, which is about $2 billion at the midpoint. So, you know, I think to answer your question, something that looks about like what we spent this year would be a good round number, but that's all really preliminary and not something we're ready to come, probably, to market with today.

Okay, that's clear. And obviously you've seen some pretty good progressions on reducing DNC well cost down to 800. Can you give us thoughts on where you see some upside opportunity or maybe the other ways? Like, what are the tensions to actually pushing that to, I don't know, call it 750 at some point?

Yeah, I mean, on the two biggest spending on the drilling and completion side, I think what you'll see is on the drilling side, if we're going to keep cutting costs, it's going to come on the day side. You know, we've made a lot of progress this year, cut a couple days per well off the spud to rig release, but, you know, majority of your costs on the drilling side are variable in nature. And if we can keep cutting days, and I think that, you know, we still have a lot of room to go relative to what people are doing in the Midland Basin. And, you know, we keep trying to learn from that side of the basin and trying to cut days every quarter. So, you know, we could cut another day that's a hundred thousand bucks a well plus or minus. And then I think the completion side, we're starting to push the upward limit of pumping hours per day. So it's going to require kind of something creative. You know, we've made some strides on using more natural gas and more compressed natural gas. But if we could take that to using, you know, field fuel gas or continue to optimize water recycling, I think there's some kind of creative outside of the box ways to cut costs on the completion side. And so I'd say that's where we're focused. You know, we've made progress every single quarter this year, some more than others. But, you know, given just where the overall market is, rig count continues to fall, you know, I think we're very confident that there's 800 numbers here to stay and it's probably upside from here.

Thank you.

Thank you. Our next question will come from John Freeman with Raymond James. Please go ahead.

Good morning,

guys. Morning.

Morning.

Hi. The first one on the three final facts y'all did during the quarter, just any color on sort of the cost savings that y'all saw on those, maybe relative to, you know, the metrics that y'all show on slide five.

I think it was like $10 to $15 a foot.

Wow. Got it. And then I guess on the last topic you touched on water recycling, which, you know, y'all are up to the 50% recycled water on the completions. If y'all were sort of looking out over the next couple of years, like, what would be sort of the goals on that, you know, percent of recycled water and just sort of any, you know, what investments would need to be made to kind of

I think that 50% were very, very happy to get there. I think that that has become an unbelievably useful tool for, you know, it saves us money both on the CAPEX side, but also on the LOE side, not to mention it's just environmentally the right thing to do. So this is a real kind of -win-win situation. I think there's room to continue to increase it. You know, if we could get to two-thirds of our water or maybe even three-fourths, I think that would probably be where it taps out at some, you know, there's always going to be about a quarter of your fraction or a quarter of your water that you can't recycle. So maybe that's a good goal over the next two years that we can push it up to two-thirds to three-fourths. And then the majority of the water recycling we do is kind of contracted through third-party midstreams. So it's not a big capital expenditure for us. You know, we give them a little bit of margin. They And then the rest of the water recycling, I'd say, I don't know if that's two-thirds or half somewhere in there. And so the balance of that obviously is us. And that's what's part of that is what's in that infrastructure budget that we, that makes up the last quarter of our CAPEX budget. And so I would expect that to, or at least that part to stay in there every year, if not slightly increase as we continue to pursue more water recycling over time.

Very helpful. Thanks. Appreciate it.

Thank you. Our next question will come from Neil Mehta with Goldman Sachs. Please go ahead.

Yeah. Good morning, team and very strong execution this quarter. The first question is there's, there are a lot of headlines around New Mexico and potential risks around things like setbacks. And I think the investor feedback was a lot of that seemed more media reports than things that would impact the business. But you guys probably spend a lot of time with New Mexico thinking through this. How should, how should we assess some of those headlines?

Yeah, no, that's a good question. And I think the real answer on setbacks is that we don't believe there's any substance that some of the concerns raised over the past few weeks, especially there was an article out a couple of weeks ago about a report commissioned by the legislative finance committee. And honestly, that, that report that the committee ensued came to what we think was the right conclusion, which was it confirms that these sorts of actions would be costly and detrimental to the state and people of New Mexico. And as such, we don't think there's any chance that something like that would ever get through the legislature in, in New Mexico. The state of Mexico has long been supportive of and dependent upon oil and gas development in a way that we firmly believe is mutually beneficial for both responsible operators like Permian Resources and the people of New Mexico. So I'd say the service is highly confident the state would not adopt something like statewide setbacks that would impact our ability to continue to operate officially in New Mexico. And we think it should be business as usual there for a long time.

That's very clear. And then just your perspective on the M&A market, you guys have done a great job with consolidation. But as we think about transformative M&A versus bolt on M&A, is it fair to say that right now the focus would be more bolt on M&A? But curious what your perspective is

on. Yeah, I mean, I think the opportunity set today definitely feels more like like bolt on M&A. You know, I think for us, we've been really successful over the past nine years, buying the right deals at the right times in a way that's driven outside return for shareholders. And I think a really important part of that for us is we've always wanted to buy assets and buy businesses that make our base business better and our company can drive outside share returns for years to come. And with the quality of the business that we've got today, I'd say that raises the bar really, really high. And I think a lot of the deals that are out there and all the deals we've looked at lately just don't achieve our return hurdles and don't make our business better. So I think the focus that kind of lately has been on smaller bolt on the kind of more cash deals that this what we're doing are accretive to our inventory life and compete for capital day one. So I think, you know, we're always open to evaluating all these things. And as they come along, if we found the right one, we'd obviously be excited to do it. But, you know, a lot of the time and momentum today seems to be more on on more of the bolt on acquisitions.

Very clear. Thanks, guys.

Thank you. Our next question will come from Gabe Dowd with TD Cowan. Please go ahead.

Thanks. Hey, morning, guys. Just wanted to go back to, I guess, infrastructure spend for 2024. You guys actually just noted a couple of questions ago that 25% or so of the capital is towards infrastructure. But I do think this year was a bit elevated, just given some some spin around Earthstone's assets. So could you maybe just confirm that's the case? And how should we expect infrastructure capital to trend into 2025?

Yeah, I mean, we're still working through 25. I can confirm you're correct that we had, you know, called 100 million dollars or of infrastructure spent associated with the Earthstone acquisition that came through in 2024. So, you know, absent any acquisitions, I'd expect infrastructure spend to be down year over year. We've done quite a few not Earthstone size, but between, you know, Tascosa, Breeden Stevens and then the Oxy acquisition, we've done quite a few acquisitions over the course of this year as well. So, you know, I don't know if that means that it's, you know, would have been down 100, but now it's only down 50 or, you know, I'm just spitballing exactly what it looks like. But I think it's fair that infrastructure spend should be slightly down year over year. I don't know, Jack, what that looks like yet,

though. Okay. Okay. Well, that's helpful. Thanks for confirming that. And then I guess this is a follow up you noted in the release and the prepared remarks, I guess it's prepared remarks, but taking an equity stake potentially in a natural gas long haul pipe over the next couple of years. Well, I guess, yeah, the question would be you referring to Apex or Blackcomb or is it something more longer dated, just trying to get a sense of when that can materialize. Thanks, guys.

No, I think not going to go into specifics on any conversations that may be ongoing today, but I do think, you know, if an equity stake made sense, both kind of ensuring we had the right downstream interconnectivity and sales points and confident we could earn a return on our investment, it's something that's certainly on the table, but that's more intended to be one of the tools at our disposal today. And we feel like we've got a really good plan on that whole strategy. So nothing, nothing specific we can share today, but I'd say kind of all, all potential options like that are on the table.

Understood,

understood. Thanks,

guys. Thank you. Our next question will come from John Abbott with Wolf Research. Please go ahead.

Hey, thank you very much for taking our questions. I want to approach 2025 a little bit differently. I want to start with 2024. So in your remarks, in your press release, you reduced well cost by approximately a million dollars compared to last year. If you repeated, if you had those costs today, where would you think your cap X for 2024 would first shake out at?

So maybe ask that a different way. We reduced it off of a million dollars off of 23.

Oh,

yes. So maybe, maybe I think the easier

way I put it is we're expecting to come in near the midpoint of our capex guidance and we've added 20, 20 tills to the year.

So yeah,

maybe that's a better way to answer what you're saying.

Yeah, I'm just, I was just trying to get a sense if you had your cost today and you were sort of to repeat your program today where your capex would sort of come in, but that's, that's there. Then my next question is that you have, you've had been very, if your operations are doing extraordinarily well, there are benefits to maintaining consistent operations. Strategically, when you think about your operations, is there a certain number of rigs and a certain number of frag crews that you think are important as you sort of just strategically, just to keep going from an efficiency perspective as you think about activity going forward?

You know, our team over the last couple years with acquisitions has, has really shown the ability to pick up, change out and drop rigs and frag fleets without missing a beat. So I think that the 12 rig program we're running is great and it's working really well, but I'd say I have the confidence in their ability to go to 11 rigs, go to 13 rigs and run anywhere between two and four frag fleets without missing a beat. And that's something new. I'd say there was a point in time a couple of years ago where I would have had a lot of hesitation to kind of bounce rig count around. And given what I've seen, you know, with changing out all the rigs after the air stone acquisition, you know, picking up a rig, dropping a rig, et cetera, like they do it, we pick up new rigs and they are just as good as the rest of ours within a well or two. So probably two different ways to answer your question. I think the 12 rig, three and a half frag fleet program seems to be really efficient and working well, but I am not, there's no operational nerves for me of picking up or dropping a rig if that's what the right answer is. And

then just one really quick follow up to all that. So just to think about terms of efficiency operations and you think about whether or not you think about growth into next year, would you ever just be willing to build ducks or do you don't see any value for building ducks?

I mean, if oil went to, we built ducks back in COVID. So if oil went to 30 or 40, we would build ducks. But I don't think there's, to spend a bunch of capital and leave it in the ground for a long time without getting the production is not something that we would do at a normal oil price scenario.

All right. Thank you very much for taking our questions. Thank

you. Thank you. Our next question will come from Zach Parham with JP Morgan. Please go ahead.

Hey guys, thanks for taking my questions. First, you've talked a lot about efficiency gains on the call and that driving costs lower, but can you talk a little bit about what you're seeing on the service side? I'm sure you're going through the negotiating process now, but any thoughts on how potential deflation might trend in 2025?

Yeah, we've seen,

we made a little progress over the last few quarters on the kind of true deflation. A lot of materials, things like sand, the two biggest ones are being sand and water. I think water is probably more on the efficiency side with recycling, but the sand being one, we're just, we've seen a little bit of reduction there. The big ticket service company stuff has been stickier. We've made a little progress in areas where we found some win-wins or there's a probably in our hands, but it feels like this is an environment where we're trying to be constructive and find win-wins before we really go kind of squeeze margins just to continue to maintain efficiencies.

Thanks. That makes sense. And then just one follow-up on cash taxes. You lowered the estimate to 10 to 15 million. That's quite a bit lower than you were at the beginning of the year. Any thoughts on how cash taxes will trend in 2025 and do you expect to be subject to the AMT next year?

Yeah, thanks. The reduction is really just a lot of refinement and optimization from our accounting and tax team really around Earthstone. So that's been great progress there. We have to finalize our work, but we don't expect to be subject to KMT in 2025. We'll provide more detail on that in February. We do expect to continue to have meaningful tax deferral in 2025 also, so we'll provide more detail, but good work so far.

Thank you.

Our next question will come from Leo Mariani with Roth. Please go ahead.

Yeah, I just wanted to kind of ask on activity heading into the fourth quarter here. Are y'all expecting to see activity tick down a little bit in 4Q versus, you know, the 3Q? Obviously, guys went really fast in 3Q and I think had probably certainly, you know, kind of more tills you know than expected. So should we kind of expect CapEx and activity be down a little bit in 4Q versus 3Q?

Yeah, I think that CapEx should be down quarter over quarter. A lot of that's just kind of a function of work interest in the quarter. So you'll see we'll keep running our 12 breaks through the end of the year and into next year, but our quarter over quarter CapEx are expecting to be kind of slightly down Q4 from Q3, but it's more of a function of just kind of the well mixer drilling.

Okay, appreciate that. And then just following up on that, you kind of alluded to this already in some of your comments here, but you clearly were able to go a lot faster, you know, this year and you got, you know, 20 extra wells, you know, with the 12 rigs, you know, are you giving kind of consideration to trying to kind of get back to the previously planned pace of say closer to 250 wells and, you know, do that with 11 rigs? How are you thinking about that? Just trying to get a sense of you're thinking about trying to capture, you know, some of those efficiencies and put it more into kind of CapEx savings, you know, as opposed to just kind of, you know, doing, you know, more with the same capital.

We definitely could drill 250 wells next year with 11 rigs if that's what we wanted to do. So I think that, you know, whatever plan we roll out in February will reflect the efficiencies we've picked up over the last two quarters. But we're not there yet on exactly how much capital we want to spend and what the right recount is.

Okay, thanks.

Thank

you. Thank you. Our next question will come from Oliver Huang with TPH. Please go ahead.

Good morning, teams. And thanks for taking the questions. I know in the past you all spoke into running a fairly repeatable program targeting a similar zone mix, pad sizes, regional allocation. Just kind of given the increased size and scale of the business today, is there any consideration potentially expanding on the average number of wells for pad as potentially a lever to further drive down well costs even further or maybe potentially tacking on an incremental zone in certain areas of the program when kind of considering the plan for the next 12, 24 months?

I'd say our

plan kind of on a unit by unit basis is been consistent over the last few years and is still what we believe is the right balance of kind of how to develop our assets going forward. Just as a reminder, we are kind of very specific to the different areas we're developing and what the ROC needs. There's some DSUs, a lot of them on the Texas side where you need to go co-complete kind of all the different benches and that's the strategy that we execute there. As we move to New Mexico, there are some benches that need to be co-completed but others that have plenty of height separation or frac areas that allow us to break different zones into different development packages. So that's what we'll do. We'll kind of let the ROC dictate what the right answer is and I would say our tolerance for larger pad sizes is higher today than it was last year and higher last year than it was the year prior just as the total number of rigs, number of wells and size and scale of the business gets bigger, kind of the lumpiness from really driving up pad size is, you know, we can mask it better within the business. So all that to be said, I bet pad size is slightly higher next year than it was this year just because of the tolerance we have but, you know, we still had some 25 well pads this year because that's what the ROC dictated in certain places and, you know, we're not scared to do that and we'll continue to do that in the areas where we need to.

Awesome, that's helpful color and maybe for a follow-up question, just wanted to see if you had any thoughts around power reliability these days, just any sort of investments from a capital side beyond the norm that might need to be made with just kind of how fast you all are working to ensure you're staying ahead of the till schedule.

I think the right way to think is when we have reliable power you can see from our operations like we have never and don't expect to ever kind of quote downtime or a production miss due to power reliability. I do think that's an opportunity for a lot of future efficiency gains that probably shows up to the LOE side. You know, our New Mexico position is still very generator heavy across the entire state and that's a function of just where the grid is, the kind of time it takes to get things built to us and just overall where that state is. I'm hopeful that, you know, maybe new, federal regulations, etc. may help speed that up a little bit but, you know, on balance that's something that we'd like to continue to improve. I don't know if that's working with the utilities which we are or building some of that out ourselves which we are also looking into but I wouldn't do it as a reliability concern. It's more just the efficiencies of if we can get off of generator and onto overhead power or onto using our own gas in the field. I think you'll see a cost savings that comes alongside it.

Perfect. Thanks for the time.

Thank you. Our next question will come from Kevin McCurdy with Pickering Energy Partners. Please go ahead.

Hey, good morning guys. Following up on the drilling efficiencies with the faster cycle times, how many more wells does that translate to a year? I guess that's another way. Does the 12 rigs and I think you said three to four completion crews, does that equal something more than 270 wells a year kind of using your leading edge rates?

Yeah, probably slightly just because if you think about it, you know, we didn't have that January 1st of this year and we have it now so there's some amount of the 20 we added this year are was growing over the course of the year. If you took our true run rate now maybe it's 275 or something. I don't know it exactly but it's probably slightly more than the 270.

That's appreciate that. And as a follow up, I wanted to touch on NGLs. The last two quarters have seen a big step up in NGL volumes and prices been relatively solid. What's changed there? Is that a representative of a change in production mix in drilling or is there a change in how you're marketing your NGLs?

Really just more ethane recovery driven by weak WAHOP like weak in-base gas pricing. So we're basically recovering NGLs, slightly less gas but

an overall uplift to BOEs.

Thank you. Thank you. Our next question will come from Phillips Johnston with Capital One. Please go ahead.

Thanks for the question. First is on GP&T unit calls. Looks like you're expecting to be sort of at that pie in the guidance range sort of implying an uptake in the back half of the year versus the first half. I seem to recall that the religious properties include some midstream ownership there. So can you maybe talk about the drivers there?

GP&T is always just going to be kind of where we pop wells and there's slight variance in kind of contract rates depending on that mix. So nothing out of the ordinary there. Oxygen is midstream assets but that's a little bit separate than GP&T. It'll have modest upward pressure on GP&T but we're talking pennies.

Okay sounds good and then can you maybe talk about where you expect to end the year in terms of the next 12 months PDP decline rate and what that might look like relative to where you came in the year given the Brilla draw deal and a few other moving parts?

I don't think our decline rate is going to change much.

You know the the Brilla draw helps a little but the growth that we've had this year from an organic basis probably offsets it so I'd call it same kind of mid to high 30s that we've been in for for the last year or two.

Yeah okay sounds good. Thank you.

Thank you. Our next question will come from Paul Diamond with Citi. Please go ahead.

Good morning. Thanks for taking the call. Just a quick one on the ground game. Current pricing volatility really shifted any of those bid asks or is that still something that's you're going to be a consistent part of that organic growth story going forward?

Yeah we're highly confident it'll be a part of our growth story going forward. I think that's been something we've been doing successfully out here in Midland for nine years and our business development team and our land teams are extremely good at. I do think the volatility on Q3 definitely caused it to be a bit of a slower quarter on the ground game side. I think that there's a lot of natural fluctuations and that that can end up being pretty lumpy on when deals actually get done but yeah I think when you see the kind of volatility we've seen the last four months I think that definitely widens bid ask spreads but you know over time we'll see some more consistency or people will get used to the volatility and I think we'll you know continue what's been a really strong pace the last couple years on on the ground game side.

Got it appreciate it. Minister one quick follow-up on the talked about 60-70 percent kind of longer term goal on you know Gulf Coast or non-Waha pricing just wanted to get an idea of like how we should think about that in Cairns over the next several years is that more linear or will it be more lumpy I guess how should we think about that progression?

I think it'll be more linear you know I think there's there's some stuff that we're working on today that should have effect on in a much nearer term capacity and I think some of the things are are going to be more slow burn but I think I think it was trying to get there as over the next couple of years not not kind of next quarter kind of some we should have some fruits from our labor that we can share you know much sooner than that but I think over time we'll just be chipping away at it.

Understood appreciate your time.

Thank you as a reminder to ask a question please press star one. Our next question will come from Noah Hungness with Bank of America. Please go ahead.

Morning guys um I guess I wanted to start off on LOE. It just seems like your LOE costs continue to trend below the low end to guidance. What's driving that and then could we is it fair to assume that kind of where 3Q LOE was is kind of a good go-forward assumption?

Um yeah

I mean so just as a reminder we've kind of always said yeah the low end of the guidance range is where we thought we'd be. We got the earthstone stuff integrated better and faster than we thought which kind of had us trending in that 550 range. I do think you'll see in Q4 a slight uptick from there due to the oxybrea draw. That that asset I'd say we expect really quickly to get it back to something close to where PR historically is but for for the first month of Q4 it was still operated by oxy. So you'll see a slight uptick in Q4 and then I think as as we get into next year we hope to get LOE kind of back down to that call it 550 range. So yes not I don't think below the guidance range but somewhere in the 550-560 range is probably where we are over the next kind of medium term.

Makes sense and then the next question is just on use of cash. I mean with the revolver paid down and how should we kind of think about the use of the free cash flow moving forward excluding the payment for the base dividend? Should we just expect it to build on the balance sheet?

Yeah I think kind of what we do with our our free cash flow is going to be dependent on the kind of reinvestment opportunities we see in front of us. I think we've been really clear you know if we see the right accretive acquisitions that that's what we're trying to do strategically we're going to pursue those. I think if we see the right dislocations in the stock price we'd be excited to lean in heavily on the buyback but kind of absent either those opportunities we're excited to kind of put that cash to the balance sheet. I think that the balance sheet could be kind of paying down some debt like long-term debt like we did earlier this quarter or frankly I think we like accruing some amount of cash on the balance sheet today. I think we like the strategic flexibility that that gives us and you know just kind of further enhances our liquidity profile and the fortress balance sheet that we're really proud of.

Great to hear you guys thank you so much.

Thank you at this time I'm showing no further questions in queue. I will now turn the call back to James Walter for closing remarks.

As you can see from the results we reported today the business continues to perform at a very high level which sets the company up well for the quarters and years to come. As we head into next year we plan to build on our track record as the lowest cost offer in the Delaware to continue drive outsize returns for our shareholders. Thanks to everyone for joining the call today and for continuing to follow the Permian Resources story.

Thank you this does conclude the Permian Resources third quarter 2024 earnings call. Please disconnect your line at this time and have a wonderful day.