Permian Resources Corporation (NYSE:PR) Q3 2024 Earnings Call Transcript

Permian Resources Corporation (NYSE:PR) Q3 2024 Earnings Call Transcript November 7, 2024

Operator: Good morning, and welcome to Permian Resources Conference Call to discuss its Third Quarter 2024 2024 Earnings. Today’s call is being recorded. A replay of the call will be accessible until November 21, 2024, by dialing 800-839-5495 and entering the replay access code 26601 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 some opening remarks. Please go ahead.

Hays Mabry : 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 Oliphint, our Chief Financial Officer. 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 or 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. Although we believe the expectations expressed are based on reasonable assumptions, they are 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.

Will Hickey: Thanks, Hays. We are excited to discuss our third quarter results this morning. During the quarter, we successfully closed our Barilla Draw 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 beat 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 D&C 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 and 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 free 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 4. This updated version of a slide we shared at an investor conference a couple of 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, midterm 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 free cash flow per share with total shareholder returns expected to follow. Slide 5 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 TILs were 15% 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.

James Walter: Thanks, Will. Turning to Slide 6, 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’s 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%.

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 have historically focused our midstream and marketing efforts more on flow assurance and on optimizing netbacks. And we’ve been extremely effective in ensuring all of our hydrocarbons can get to market with zero interruptions over the past five years. But as our business grew the scale it is today, particularly with the Erskine acquisition we closed 12 months ago, we have 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% 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 marketing is an area we expect to improve performance and drive meaningful incremental free cash flow in the coming years. And fortunately, we have a lot of levers to pull to do just that. We have significant flexibility to improve downstream sales contracts for both crude and natural gas. We expect to be able to leverage our scale in the basin to reserve space on existing on haul 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 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 several years. 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% to $0.60 per share annually. Our current base dividend yield is over 4%, 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’ve had since inception, where we use the buyback opportunistically and in periods of clear market dislocations rather than targeting consistent monthly or formulaic approach to buybacks.

When we do choose to execute on the 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% of Permian Resources today and we approach decisions with the 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 us well for continued outsized 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 times. We’ve increased the average maturity of our outstanding bonds to approximately six years.

We’ve meaningfully increased our liquidity position from the start of the year today and are actively building cash. Between our cash balance and our undrawn 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’re over 25% hedged heading into Q4 at $74 and similarly hedged as we head into 2025. Going forward, we’re highly focused on achieving investment grade ratings in 2025 and were upgraded by all three agencies this past quarter. Our financial strategy is the same as it has been in the last nine years: to maintain a fortress balance sheet with low leverage and maximum liquidity so 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’ve seen on the drilling and completion side are allowing us to accelerate wells in production while maintaining CapEx within our original guidance range. We continue to optimize our cash costs for 2024, realizing better tax synergies from the Erskine merger than we had previously expected. As such, we are reducing our current tax guidance for 2024 to $10 million 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% up from our original guidance, with over 70% of this outperformance coming from our base business. We think this continued outperformance demonstrates the strength and quality of our business. I’ll be concluding today’s prepared remarks on Slide 10, where we reemphasize our value proposition for investors. The strength of our business is underpinned by an industry leading cost structure, low breakevens 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%, 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 Session

Operator: Thank you. The question-and-answer session will be conducted electronically. [Operator Instructions] Thank you. Our first question will come from Neal Dingmann with Truist Securities. Please go ahead.

Neal Dingmann: Good morning, guys. Outstanding quarter. Guys, my first question is just on your future operational plans. I’m just wondering, will 2025 D&C regional focus? I’m 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 operationally for you all?

Will Hickey: I think ’25 will look similar to what the last couple of years have. Majority of the capital spend in New Mexico, with the balance probably being Texas, Delaware and kind of keeping Midland as sub-ten percent. 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 and we probably moved that to the Barilla Draw acquisition on the Texas side, but kind of majority of 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 pads, which is nice to have but not a need to have.

Neal Dingmann: Great points, Will. And then just for second question, the help you asked around your Slide 6. Specifically, could you discuss, I don’t know, what type of plans you can do with those 25,000 surface acres and the 40% taking high end gas? What upside does that optionality provide?

James Walter: Yeah. 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. We’ve got a big royalties business. We’ve got a modest midstream business. But I think specific to the surface, I think 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 center 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 tailwind and should help in basin 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 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 tailwind on the gas side of the business in the coming years. And to answer your third question or second part of your second question, the ultimate goal of 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, about half those volumes are selling at the Gulf Coast today. So if you kind of took the 40% and the 30% there, I think over time could ultimately have between 60% 70% of our gas pricing in kind of non-Waha markets, but that does take some time to get there.

Neal Dingmann: Thank you, both.

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

Scott Hanold: Yeah. Thanks, all. Hey, I want to hit a little bit on how you view 2025. I know it’s probably for you guys too early to give some firm numbers. But certainly on our side of the table, I mean, it’s obviously a very 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. 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 into next year at current strip prices and what does that mean roughly for CapEx?

Will Hickey: Yeah, Scott, I mean, I think we’re going to continue on now a long standing 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 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 for us it’s really too early to tell what next year looks like. I think Will referenced it in his prepared remarks.

Like our returns are really attractive today, but I do think there’s some potential 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.

Scott Hanold: Got it, got it. So yeah, just sort of what’s the point I was trying to get to like what would it take to kind of keep that 4th quarter run rate flat? Is that that’s obviously from your view maintenance plus kind of level, is that correct?

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

Scott Hanold: Okay. That’s clear. And obviously, you’ve seen some pretty good progressions on reducing D&C well cost down to 800. Can you give us thoughts on where you see some upside opportunity or maybe the other way is like what are the tensions to actually pushing that to, I don’t know, call it 750 at some point?

Guy Oliphint : 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 days side. We’ve made a lot of progress this year, cut a couple of days per well off the spud rig release. But majority of your costs on the drilling side are variable in nature. And if we can keep cutting days and I think that we still have a lot of room to go relative to what people are doing in the Midland Basin, and we keep trying to learn from that side of the basin and trying to cut days every quarter. So if we can cut another day, that’s $100,000 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.

We’ve made some strides on using more natural gas and more compressed natural gas. But if we could take that to using 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. We’ve made progress every single quarter this year, some more than others. But given just where the overall market is, rig count continues to fall, I think we’re very confident that this 800 number is here to stay and there’s probably upside from here.

Scott Hanold: Thank you.

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

John Freeman : Good morning, guys.

Will Hickey: Good morning.

John Freeman : Hi. The first one, on the three final facts you all did during the quarter, just any color on sort of the cost savings that you all saw on those maybe relative to the metrics that you all show on Slide 5?

Will Hickey: I think it’s like $10 to $15 a foot.

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

Will Hickey: I think that 50%, we’re very, very happy to get there. I think that, that has become an unbelievably useful tool for 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 win situation. I think there’s room to continue to increase it. If we could get to two thirds of our water or maybe even three fourth, I think that would probably be where it taps out at some there’s always going to be about a quarter of your fracs 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 midstream, so it’s not a big capital expenditure for us.

We give them a little bit of margin. They spend the CapEx, and we both benefit from the 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 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 at least that part to stay in there every year, if not slightly increase as we continue to pursue more water recycling over time.

John Freeman : Very helpful. Thanks. Appreciate it.

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

Neil Mehta: Yeah. Good morning, team and very strong execution this quarter. The first question is 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 we assess some of those headlines?

James Walter: Yes, that’s a good question. And I think the real answer on setbacks is that we don’t believe there’s any substance to 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 report that the committee issued 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 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 assurances are highly confident the state would not adopt something like statewide setbacks that would impact our ability to continue to operate efficiently in New Mexico. And we think it should be business as usual there for a long time.

Neil Mehta: 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 just curious what your perspective is on?

James Walter: Yeah, I mean, I think the opportunity set today definitely feels more like bolt on M&A. 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 outsized 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 outsized shareholder 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 those smaller bolt ons, the kind of more cash deals that just what we’re doing are accretive to our inventory life and compete for capital day one. So I think we’re always open to evaluating all these things. And as they come along, if we’ve done the right one, we’d obviously be excited to do it. But a lot of the time and momentum today seems to be more on more of the bolt on acquisitions.

Neil Mehta: Very clear. Thanks guys. Thank you.

Operator: Thank you. Our next question will come from Gabe Daoud with TD Cowen. Please go ahead.

Gabe Daoud: 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 spend 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?

Will Hickey: Yeah. I mean, we’re still working through 2025. I can confirm you’re correct that we had call it, $100 million of infrastructure spend associated with the Earthstone acquisition that came through in 2024. So 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 Tascosa, [Indiscernible] and then the Oxy acquisition, we’ve done quite a few acquisitions over the course of this year as well. So I don’t know if that means that it would have been down 100, but now it’s only down 50 or 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 exactly what that looks like yet though.

Gabe Daoud: Okay. Okay. No, that’s helpful. Thanks for confirming that. And then I guess just as a follow-up, you noted in the release in the prepared remarks, I guess, this is the prepared remarks, but taking equity 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’re referring to Apex or Blackcomb or is it something more longer data? Just trying to get a sense of when that could materialize. Thanks guys.

James Walter: No, I think not going to go into specifics on any conversations that may be ongoing today. But I do think if an equity stake made sense both kind of ensuring we had the right downstream interconnectivity and sales points and confident we can 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 specific we can share today, but I’d say kind of all potential options like that are on the table.

Gabe Daoud: Understood. Thanks, guys.

James Walter: Thanks.

Operator: Thank you. Our next question will come from John Abbott with Wolfe Research. Please go ahead.

John Abbott: 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 costs by approximately $1 million compared to last year. If you repeated if you have those costs today, where would you think your CapEx for 2024 would first shake out at?

Will Hickey: So, maybe I’ll ask that a different way. We reduced it off of $1 million off of ’23, yes. So, 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 to 20 tilts to the year. So maybe that’s a better way to answer what you’re saying?

John Abbott: 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 fair. Then my next question is that you have had been various 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 frac 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?

Will Hickey: Our team over the last couple of years with acquisitions has really shown the ability to pick up, change out and drop rigs and frac 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 frac 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 with changing out all the rigs after the Earthstone acquisition, picking up a rig, dropping a rig, etcetera, 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, 3.5 frac 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.

John Abbott: 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 DUCs or do you don’t see any value for building DUCs?

Will Hickey: I mean, if oil went to we built DUCs back in COVID. So if oil went to 30 or 40, we would build DUCs. 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.

John Abbott: All right. Thank you very much for taking our questions.

Will Hickey: Thank you.

Operator: Thank you. Our next question will come from Zach Parham with JPMorgan. Please go ahead.

Zach Parham: Yeah. 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?

Will Hickey: Yeah. We made a little progress over the last few quarters on the kind of true deflation. A lot of it in materials, things like sand, the two biggest ones being sand and water. I think water is probably more on the efficiency side with recycling, but sand being one where just we’ve seen a little bit of reduction there. The big ticket service company stuff has been stickier. We made a little progress in areas where we found some win wins or there’s a little price concession here or there. So I think that the balance of power is 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.

Zach Parham: Thanks. That makes sense. And then just one follow-up on cash taxes. You lowered the estimate to $10 million 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 KMT next year?

James Walter: Yes, thanks. The reduction is really just a lot of refinement, not just 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.

Zach Parham: Thank you.

Operator: Our next question will come from Leo Mariani with ROTH. Please go ahead.

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

Will Hickey: Yeah. I think that CapEx should be down quarter over quarter. A lot of that’s just kind of a function of working interest in the quarter. So you’ll see we’ll keep running our 12 rigs through the end of the year and into next year. But our quarter over quarter CapEx we’re expecting to be kind of slightly down Q4 from Q3, but it’s more of a function of just kind of the well mix we’re drilling.

Leo Mariani : Okay. Appreciate that. And then just following up on that, you kind of alluded to this already in some of your comments here, but clearly we’re able to go a lot faster this year and you got 20 extra wells with the 12 rigs. 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 do that with 11 rigs? How are you thinking about that? Just trying to get a sense of your thinking about trying to capture some of those efficiencies and put it more into kind of CapEx savings as opposed to just kind of doing more with the same capital?

Will Hickey: We definitely could drill 250 wells next year with 11 rigs if that’s what we wanted to do. So I think that 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 rig count is.

Leo Mariani : Okay, thanks.

Will Hickey: Thank you.

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

Oliver Huang: Good morning, team, and thanks for taking the questions. I know in the past, you all spoken to 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 to potentially expanding on the average number of wells per pad as potentially a lever to further drive down well cost even further or maybe potentially tacking on an incremental zone in certain areas of the program when kind of considering the plan for the 12-24 months?

Will Hickey: I’d say our plan kind of on a unit by unit basis is it’s 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 rock needs. There are 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 barriers that allow us to break different zones into different development packages. So that’s what we’ll do.

We’ll kind of let the rock 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 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 we still had some 25 well pads this year because that’s what the rock dictated in certain places. And we’re not scared to do that and we’ll continue to do that in the areas where we need to.

Oliver Huang: Awesome. That’s helpful color. And maybe for a follow-up question. Just wanted to see if you all had any thoughts around power liability 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 TIL scheduled?

Will Hickey: I think the right way to think about is when we have reliable power, you can see from our operations like we have never and don’t expect to ever kind of downtime or 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. 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 maybe new the kind of new federal regulations, etcetera, may help speed that up a little bit. But 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 view 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.

Oliver Huang: Perfect. Thanks for the time.

Will Hickey: You bet.

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

Kevin MacCurdy: 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, to ask 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?

Will Hickey: Yes, probably slightly just because if you think about it, we didn’t have that January 1 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 $2.75 or something. I don’t know what exactly, but it’s probably slightly more than the $2.70.

Kevin MacCurdy: Got you. 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 price has been relatively solid. What’s changed there? Is that a representative of the change in production mix in drilling? Or is there a change in how you’re marketing your NGLs?

Will Hickey: Really just more ethane recovery driven by weak Waha like weekend basin gas pricing. So we’re basically recovering NGLs, slightly less gas, but an overall uplift to BOEs.

Kevin MacCurdy: Thank you.

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

Phillips Johnston: Thanks for the question. First is on GP&T unit cost. Looks like you’re expecting to be sort of at that high in the guidance range sort of implying an uptick in the back half of the year versus the first half. I seem to recall that [Indiscernible] properties include some midstream ownership there. So can you maybe talk about the drivers there?

Will Hickey: Yeah. 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. Oxy’s midstream assets, but that’s a little bit separate than GP&T. It will have modest upward pressure on GP&T, but we’re talking pennies.

Phillips Johnston: 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 Barilla Draw deal and a few other moving parts?

Will Hickey: I don’t think our decline rate is going to change much. The Barilla 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 the last year or two.

Phillips Johnston: Yeah. Okay. Sounds good. Thank you.

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

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

James Walter: Yeah, we’re highly confident it will 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 you saw in 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 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 in the last four months, I think that definitely widens bid ask spreads. But over time, we’ll see some more consistency or people will get used to the volatility, and I think we’ll continue what’s been a really strong pace the last couple of years on the ground game side.

Paul Diamond: Got it. Appreciate it. And just one quick follow-up on the talked about 60%, 70% kind of longer term goal on Gulf Coast or non-Waha pricing. Just wanted to get an idea of like how we should think about that in cadence over next several years. Is that more linear or will it be more lumpy? I guess how should we think about that progression?

James Walter: I think it’ll be more linear. I think 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 going to be more slow burn. But I think it was trying to get there as over the next couple of years, not kind of next quarter. Kind of some — we should have some fruits from our labor that we can share much sooner than that. But I think over time, we’ll just be chipping away at it.

Paul Diamond: Understood. Appreciate your time.

James Walter: Thank you.

Operator: Thank you. [Operator Instructions] Our next question will come from Noah Hungness with Bank of America. Please go ahead.

Noah Hungness: Good morning, guys. I guess I wanted to start off on LOE. Just it seems like your LOE costs continue to trend below the low end of 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?

Will Hickey: Yeah. I mean, so just as a reminder, we’ve kind of always said, yes, 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 Oxy, Barilla Draw. That asset, I’d say, we expect really quickly to get it back to something close to where PR historically is. But for the 1st month of Q4, it was still operated by Oxy. So you’ll see a slight uptick in Q4. And then I think as we get into next year, we hope to get LE 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.

Noah Hungness: Makes sense. And then the next question is just kind of 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?

James Walter: Yeah. I mean, I think kind of what we do with 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. If we see the right accretive acquisitions that that’s still 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 of 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 just kind of further enhances our liquidity profile and the Fortress balance sheet that we’re really proud of.

Noah Hungness: Great to hear, guys. Thank you so much.

Operator: 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.

James Walter: 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 years to come. As we head into next year, we plan to build on our track record as the lowest cost operator in the Delaware to continue to drive outsized returns for our shareholders. Thanks to everyone for joining the call today and for continuing to follow the Permian Resources story.

Operator: Thank you. This does conclude the Permian Resources Q3 2024 earnings call. Please disconnect your line at this time and have a wonderful day.