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 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.

Thanks, Todd, and thank you all for joining us. On the call today are Will Hickey and James Walter, our Co-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.

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 Permian Resources 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 drilling and completion 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 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 Permian Resources 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 as 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 drill 250 wells with 12 rigs and are now on track to drill 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.

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 all know, the economics of Permian Resources' business are primarily oil driven. They always have been and will continue to be. But it's worth pointing out that Permian Resources 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 to 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 from $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 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.

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.

Good morning, guys. Outstanding quarter. Guys, my first question is just on your future operational plans. I'm just wondering, will 2025 drilling and completion regional focus stay essentially the same when you look at New Mexico and Texas? Will that stay essentially the same? And just wondering if any potential loosening of restrictions by the administration, particularly maybe in New Mexico or wherever, might have any sort of changes operationally for you all?

I think 2025 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 probably moved that to the Barilla Draw acquisition on the Texas side, but the majority of New Mexico development will continue just like we've been for the last couple of years. We're well ahead of the permitting and all the needs. So having a looser or easier kind of regulatory environment probably doesn't change anything from our side. On balance, it probably gives us a little bit of flexibility if we want to make some more last-minute changes around different pads, which is nice to have but not a need to have.

Great points, Will. And then just for a second question, the help you asked around your Slide 6. Specifically, could you discuss what type of plans you can do with those 25,000 surface acres and the 40% taking higher-end gas? What upside does that optionality provide?

On the surface side, I think that's just one of several non-upstream assets we're constantly working through, how we can maximize value for our shareholders for something that's 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, an outright sale could be an option, but we think there's potentially some interesting developments that ultimately take time, but could provide ways for us to work with infrastructure-related parties to fully optimize the value from that surface. Embedded in your question, 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, natural gas is really well positioned to be a beneficiary of changes in the power consumption landscape going forward. We think 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. In the Permian, we've got abundant natural gas, a supportive regulatory environment, a very rural landscape and a tremendous long-dated inventory with a lot of gas that historically has been pretty cheap. So we're optimistic that can provide a tailwind on the gas side of the business in the coming years. To answer the second part of your 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. On the slide you referenced, of the 60% we have that's currently committed, about half those volumes are selling at the Gulf Coast today. So if you took the 40% and moved it, over time we could ultimately have between 60% and 70% of our gas pricing in 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 how you view 2025. I know it's probably too early to give some firm numbers. But conceptually, can you help us think through: 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?

Scott, we're going to continue our long-standing policy of not providing much of a look at 2025 guidance until we get to February of next year. That policy served us and our shareholders really well the last couple of years. It gives us a couple of months to further refine our plan and, just as importantly, to assess the macroeconomic backdrop and the service cost environment. Our approach to what the next year and what growth looks like hasn't changed. We're targeting a growth range of zero to 10% based on the prior year's average. It's too early to tell what next year looks like. Our returns are attractive today, but there are potential storm clouds on the horizon or some questions on the oil price from a macro standpoint. Q4 is a strong exit to the year and we'll have to wait until next year to see what the balance of the year looks like.

Got it, got it. So what's the point I was trying to get to — what would it take to keep that fourth quarter run rate flat? That's obviously from your view maintenance-plus level, is that correct?

Historically we've talked about maintenance CapEx using the prior full year average, which would be that $1.585 billion number at the back of the deck. 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 something that looks about like what we've spent this year would be a good round number, but that's preliminary and not something we're ready to come firmly to market with today.

Okay. That's clear. And obviously you've seen some pretty good progressions on reducing D&C well costs down to $800. Can you give us thoughts on where you see some upside opportunity or maybe what the tensions are to pushing that to, say, $750 at some point?

On the two biggest spending buckets — drilling and completion — 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, cutting a couple of days per well off the spud-to-rig-release. Majority of drilling costs are variable in nature. If we can keep cutting days we still have a lot of room to go relative to what people are doing in the Midland Basin, and we keep learning from that side of the basin and trying to cut days every quarter. If we can cut another day, that's roughly $100,000 per well, plus or minus. On the completion side, we're starting to push the upward limit of pumping hours per day, so it will require something creative. We've made strides using more natural gas and more compressed natural gas. If we could take that to using field fuel gas or continue to optimize water recycling, there are creative, outside-the-box ways to cut completion costs. Given the overall market, rig count continues to fall; we are confident that the $800 number is here to stay and there'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.

Good morning.

On the three frac fleets you all did during the quarter, any color on the cost savings that you saw on those relative to the metrics that you show on Slide 5?

I think it's like $10 to $15 a foot.

Got it. And on water recycling, you are up to 50% recycled water on completions. Looking out over the next couple of years, what would be sort of the goals on that percent of recycled water and what investments would need to be made to achieve it?

That 50% is a great milestone. It's been an unbelievably useful tool — it saves us money on CapEx and LOE, and it's environmentally the right thing to do. There's room to increase it. If we could get to two-thirds or maybe even three-fourths of our water, I think that would be where it taps out — there's always going to be about a quarter of your fracs or a quarter of your water that you can't recycle. So getting to two-thirds to three-fourths is a reasonable goal over the next two years. The majority of our water recycling is contracted through third-party midstream, so it's not a big capital expenditure for us. We give them a little margin; they spend the CapEx, and we both benefit. Some of it is in our infrastructure budget that makes up the last quarter of our CapEx budget. I'd expect that to at least 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.

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 investor feedback was a lot of that seemed more media reports than things that would impact the business. You probably spend a lot of time with New Mexico thinking through this. How should we assess some of those headlines?

That's a good question. We don't believe there's any substance to some of the concerns raised over the past few weeks. There was a report commissioned by the Legislative Finance Committee a couple of weeks ago, and that report came to what we think was the right conclusion: it confirmed that such actions would be costly and detrimental to the state and people of New Mexico. We don't think there's any chance something like statewide setbacks would get through the legislature in New Mexico. The state has long been supportive of and dependent upon oil and gas development in a way that we believe is mutually beneficial for responsible operators like Permian Resources and the people of New Mexico. So we're highly confident the state would not adopt statewide setbacks that would impact our ability to continue to operate efficiently in New Mexico. 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. 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? Curious what your perspective is.

The opportunity set today definitely feels more like bolt-on M&A. We've been successful over the past nine years buying the right deals at the right times in a way that's driven outsized returns for shareholders. We want to buy assets and businesses that make our base business better and allow us to drive outsized returns. With the quality of the business we have today, the bar is very high. Many deals out there don't achieve our return hurdles and don't make our business better. The focus lately has been on smaller bolt-ons — more cash deals that are accretive to our inventory life and compete for capital day one. We're always open to evaluating all opportunities. If the right transformational deal came along and met our criteria, we'd consider it, but momentum today seems more toward bolt-ons.

Very clear. Thanks, guys.

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

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

We're still working through 2025. I can confirm you're correct that we had about $100 million of infrastructure spend associated with the Earthstone acquisition that came through in 2024. So absent acquisitions, I'd expect infrastructure spend to be down year over year. We've done quite a few acquisitions over this year as well, so I don't know exactly what the delta will be, but it's fair to expect infrastructure spend to be slightly down year over year.

Okay, that's helpful. And then taking equity in a natural gas long-haul pipe over the next couple of years — are you referring to specific projects like Apex or Blackcomb or something longer-term? When could that materialize?

I'm not going to go into specifics on any conversations that may be ongoing today. If an equity stake made sense — ensuring we had the right downstream interconnectivity and sales points and confident we can earn a return on our investment — it's certainly on the table. It's one of the tools at our disposal, and we feel like we've got a good plan on that whole strategy. Nothing specific to share today, but all potential options like that are on the table.

Understood. Thanks, guys.

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

Hey, thank you very much for taking our questions. I want to approach 2025 a little differently. I want to start with 2024. In your remarks you noted you reduced well costs by approximately $1 million compared to last year. If you repeated that cost environment today, where would you think your CapEx for 2024 would shake out?

We reduced about $1 million off of 2023, yes. An easier way to answer is we're expecting to come in near the midpoint of our CapEx guidance and we've added 20 TILs to the year. So maybe that's a better way to think about it.

I'm trying to get a sense if you had your cost today and were to repeat your program, where CapEx would come in. Then strategically, when you think about operations, is there a certain number of rigs and a certain number of frac crews that are important to maintain efficiency going forward?

Our team has shown the ability to pick up, change out and drop rigs and frac fleets without missing a beat. The 12-rig program is great and working well. But I have 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. A couple years ago I would have had hesitation bouncing rig count around, but given what we've done with acquisitions, picking up and dropping rigs, the new rigs perform like our existing rigs within a well or two. The 12-rig, 3.5-fleet program seems really efficient, but there's no operational nerves for me about picking up or dropping a rig if that's the right answer.

One quick follow-up: would you ever be willing to build DUCs?

We built DUCs back in COVID. If oil went to $30 or $40, we would consider building DUCs. But spending a bunch of capital and leaving it in the ground for a long time without bringing production online is not something we would do at normal oil price scenarios.

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

Thank you.

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

Thanks for taking my questions. First, you've talked a lot about efficiency gains on the call and that driving costs lower. Can you talk a little bit about what you're seeing on the service side? Any thoughts on how potential deflation might trend in 2025?

We made some progress over the last few quarters on true deflation, especially in materials like sand — one of the biggest ones — and water (water is more efficiency-driven via recycling). The big-ticket service company stuff has been stickier. We've made progress in areas where we found win-wins or small price concessions. The balance of power is probably in our hands, but this feels like an environment where we try to be constructive and find win-wins rather than squeeze margins just to maintain efficiencies.

Thanks. And then one follow-up on cash taxes. You lowered the estimate to $10 million to $15 million. That's a big reduction versus the beginning of the year. Any thoughts on how cash taxes will trend in 2025? And do you expect to be subject to KMT next year?

The reduction is due to a lot of refinement and optimization from our accounting and tax team around Earthstone. We have to finalize our work, but we don't expect to be subject to KMT in 2025. We'll provide more detail in February. We do expect to continue to have meaningful tax deferral in 2025 as well.

Thank you.

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

Just wanted to ask on activity heading into the fourth quarter. Are you expecting to see activity tick down a little bit in Q4 versus Q3? You went really fast in Q3 and had more TILs than expected. Should we expect CapEx and activity to be down a little bit in Q4 versus Q3?

CapEx should be down quarter over quarter. A lot of that is a function of working interest in the quarter. We'll keep running our 12 rigs through the end of the year and into next year, but quarter-over-quarter CapEx is expected to be slightly down in Q4 from Q3 due to the well mix we're drilling.

Appreciate that. You were able to go a lot faster this year and got 20 extra wells with 12 rigs. Are you considering getting back to the previously planned pace of closer to 250 wells by running 11 rigs? How are you thinking about capturing efficiencies and putting them into CapEx savings rather than just doing more with the same capital?

We could drill 250 wells next year with 11 rigs if we wanted to. Whatever plan we roll out in February will reflect the efficiencies we've picked up over the last two quarters. We're not yet finalized on exactly how much capital we want to spend and what the right rig count is.

Okay, thanks.

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

Good morning, team, and thanks. In the past you've spoken to running a repeatable program targeting a similar zone mix, pad sizes and regional allocation. Given the increased size and scale of the business, is there any consideration to expand the average number of wells per pad as a lever to further drive down well cost or potentially tack on an incremental zone in certain areas for the 12–24 month plan?

Our plan on a unit-by-unit basis has been consistent and is still the right balance for developing the assets. We're specific to different areas and let the rock dictate the right answer. Some DSUs, especially on the Texas side, need co-completion of benches; in New Mexico some benches can be separated. Our tolerance for larger pad sizes is higher today than last year as the total number of rigs and scale of the business gets bigger; that lumpiness can be masked better. I expect pad size to be slightly higher next year than this year, but we'll still run smaller pads where the rock dictates it.

Thanks. Follow-up on power reliability: any investments beyond the norm that might need to be made to stay ahead of the TIL schedule and ensure reliability?

When we have reliable power, we have not had downtime or production misses due to power reliability. There's an opportunity for efficiency gains that would show up in LOE. Our New Mexico position is still very generator-heavy due to grid limitations and build times. I hope new federal regulations may help speed that up. We're looking at working with utilities and also building some solutions ourselves. I wouldn't view reliability as a concern — it's more about efficiency gains if we can get off generators and onto overhead power or use our own gas in the field, which would yield cost savings.

Perfect. Thanks for the time.

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

Following up on the drilling efficiencies with faster cycle times, how many more wells does that translate to a year? Does 12 rigs and three to four completion crews equal more than 270 wells a year using your leading-edge rates?

Yes, probably slightly more. We didn't have that run rate on January 1 this year; we've ramped. If you took our true run rate now, it might be a bit higher than 270 — maybe closer to 275 — but I don't have the exact number offhand.

Appreciate that. As a follow-up, NGLs stepped up the last two quarters and price has been solid. What's changed there? Is that a change in production mix or how you're marketing NGLs?

It's really more ethane recovery driven by weak Waha-type basin gas pricing. We're recovering more NGLs, slightly less gas, but an overall uplift to BOEs.

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

First, on GP&T unit cost. It looks like you're expecting to be sort of at the high end of the guidance range, implying an uptick in the back half of the year versus the first half. I recall that Oxy's properties include some midstream ownership. Can you talk about the drivers there?

GP&T is going to vary where we pop wells and there's slight variance in contract rates depending on that mix. Nothing out of the ordinary. Oxy's midstream assets will have modest upward pressure on GP&T, but we're talking pennies.

And then can you talk about where you expect to end the year in terms of the next-12-months PDP decline rate and how that might look relative to where you came in the year given the Barilla Draw deal and other moving parts?

I don't think our decline rate is going to change much. Barilla Draw helps a little, but the organic growth this year offsets it. I'd call it the same mid-to-high 30s that we've been in the last year or two.

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

Good morning. Quick one on the ground game: has current pricing volatility shifted bid-ask spreads or is that still a consistent part of the organic growth story going forward?

We're highly confident it will remain part of our growth story. The ground game has been a strength for nine years; our business development and land teams are very good. Volatility in Q3 caused it to be a bit slower on the ground game side — volatility widens bid-ask spreads — but over time people get used to the volatility and we'll continue the strong pace we've had the last couple years.

Got it. One quick follow-up: the 60%–70% longer-term goal of Gulf Coast or non-Waha pricing — how should we think about cadence over the next several years? Linear or lumpy?

I think it'll be more linear. Some initiatives will have nearer-term effects and others will be slow burn. We're chipping away at it, and we should have some fruits of our labor sooner than later, but the move toward more Gulf Coast pricing is a multi-year effort.

Thank you. Our next question will come from Noah Hungness with Bank of America. Please go ahead.

Good morning, guys. I wanted to start on LOE. Your LOE costs continue to trend below the low end of guidance. What's driving that? Is it fair to assume Q3 LOE is a good go-forward assumption?

We've always said the low end of the guidance range was where we'd be. We integrated Earthstone better and faster than we thought, which had us trending into the $5.50 per BOE range. In Q4 you'll see a slight uptick due to the Oxy Barilla Draw assets — those assets were still operated by Oxy for part of Q4 — but we expect to get those back to Permian Resources' historical levels quickly. Over the medium term, we hope to get LOE back down to around $5.50–$5.60 per BOE.

Makes sense. On use of cash, with the revolver paid down, how should we think about free cash flow moving forward excluding the base dividend? Should we expect it to build on the balance sheet?

What we do with free cash flow depends on reinvestment opportunities. If we see the right accretive acquisitions, we'll pursue those. If we see clear dislocations in the stock price, we'll lean into buybacks. Absent those opportunities, we're excited to put cash on the balance sheet. That could include paying down long-term debt, like we did earlier this quarter, or simply accruing cash to enhance liquidity. We value strategic flexibility and the fortress balance sheet we've built.

Great to hear, guys. Thank you so much.

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 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.

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