Permian Res (PR) Q3 2026 Earnings Call Transcript

DATE

Nov. 5, 2026

CALL PARTICIPANTS

• Vice President of Investor Relations - Hays Mabry
• Co-Chief Executive Officer - Will Hickey
• Co-Chief Executive Officer - James Walter
• Chief Financial Officer - Guy Oliphint

TAKEAWAYS

• Oil Production -- 208,029 barrels per day, an increase of 5% compared to the prior quarter driven by organic growth and the integration of a Ward County bolt-on acquisition.
• Total Production -- 457,528 barrels of oil equivalent per day, representing a 22% increase quarter over quarter due to the return of curtailed gas wells.
• Adjusted Free Cash Flow -- $846 million, or $0.98 per diluted share, reflecting higher production volumes and improved natural gas realizations.
• Natural Gas Production -- 787.1 million cubic feet per day, increasing 42% quarter over quarter after the company brought curtailed high gas-to-oil ratio wells back online.
• Controllable Cash Costs -- $7.05 per barrel of oil equivalent, the lowest in company history, driven by optimizations in power generation and compression equipment.
• Acquisition Investment -- $1.15 billion for approximately 175 transactions, including the acquisition of Ridge Runner Resources for approximately $1.025 billion.
• Full-Year Oil Guidance -- 201,000 to 204,000 barrels per day, representing 11% growth compared to the prior year.
• Full-Year Capital Expenditure Guidance -- $1.975 billion to $2.075 billion, adjusted to include $20 million for the Ridge Runner acquisition and increased workover activity.
• Inventory Expansion -- 200 net drilling locations added in the core New Mexico Delaware Basin at an 80% net revenue interest.
• Net Debt-to-LQA EBITDAX -- 0.5x, following the redemption of $325 million in legacy Earthstone 9.875% senior notes due 2031.
• Lease Operating Expenses -- $5.11 per barrel of oil equivalent, an 8% reduction from the second quarter due to lower failure rates and record runtimes.
• Cash General and Administrative Expenses -- $0.73 per barrel of oil equivalent, a 16% decrease quarter over quarter through continued cost discipline.
• Natural Gas Realizations -- $1.12 per thousand cubic feet including hedges, supported by a $140 million improvement in unhedged revenue as Waha prices normalized.
• Incremental 2026 Free Cash Flow -- $300 million higher than the original February plan, resulting from investments in short-cycle projects and production optimizations.
• Maintenance Capital Expenditures -- $1.9 billion to $2 billion annually to maintain a production rate exceeding 200,000 barrels of oil per day.
• NGL Production -- 118,312 barrels per day, an increase of 37% compared to the previous quarter.
• Fourth Quarter Production Guidance -- Over 210,000 barrels of oil per day, including a 4,000 barrel per day contribution from the Ridge Runner acquisition.
• Natural Gas Marketing -- 80% of volumes now priced at Gulf Coast and DFW markets, with firm transportation expected to reach 700 million cubic feet per day in 2027.
• Acquired Acreage -- 24,000 net leasehold acres and 9,000 net royalty acres added through recent transactions in the Delaware Basin.
• Drilling Efficiency -- 2,700 feet per day achieved on the fastest well in company history, assisting management in mitigating inflation in steel and diesel costs.
• Quarterly Cash Dividend -- $0.16 per share declared for the fourth quarter, representing an annualized yield of 2.7%.

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RISKS

• Co-CEO Hickey acknowledged that diesel and casing costs represent headwinds for the company's 2027 program, though noted some service company efficiencies are providing partial offsets.
• Oliphint stated, "we still anticipate being full cash taxpayers in 2028," noting that taxes are a consideration in all investment decisions.
• Hickey noted that the company cannot always overcome commodity price fluctuations quarter over quarter despite a focus on disciplined investment and high-return projects.

SUMMARY

Permian Resources Corporation (NYSE:PR) reported record financial and operational performance during the third quarter, highlighted by a pivot from a flat-activity plan to approximately 10% organic growth. Management stated that this increase was achieved by investing in short-cycle projects, such as workovers and incremental working interests, rather than increasing rig or fleet counts. The company also expanded its core Delaware Basin footprint through $1.15 billion in acquisitions, including a $1.025 billion deal for Ridge Runner Resources that includes contingent payments based on future oil prices. Management indicated that the balance sheet remains in a strong position with leverage at 0.5x, allowing for continued capital allocation flexibility across dividends, buybacks, and acquisitions. Strategic efforts in gas marketing have transitioned 80% of natural gas volumes to Gulf Coast and DFW pricing, effectively mitigating the impact of negative regional prices seen earlier in the year.

• Co-CEO Walter stated, "At flat $70 per barrel and $2 per MCF, we expect at least 5% free cash flow per share accretion over two, five, and 10 years" from the Ridge Runner acquisition.
• Management reported that drilling efficiency reached a new milestone with the fastest well in company history, helping to offset inflationary pressures in raw materials.
• Co-CEO Hickey noted the deployment of AI-powered artificial lift monitoring to improve runtime, stating, "It's just disseminating information in a way that we could never have done really quickly."
• The company expects to sell over 700 million cubic feet per day of natural gas downstream of Waha by the second quarter of 2027, further reducing its exposure to regional price volatility.
• Management indicated that surfactants and secondary recovery methods are in early-stage testing, with initial results showing up to 40% production uplift in certain legacy wells.
• Co-CEO Walter noted that the acquisition strategy continues to focus on high net revenue interest assets, which improves capital efficiency and free cash flow without requiring incremental capital.

INDUSTRY GLOSSARY

• BOE: Barrels of Oil Equivalent, a measure used to aggregate oil and natural gas volumes into a single unit based on energy content.
• ESP: Electric Submersible Pump, a type of artificial lift used to bring fluids to the surface in oil wells.
• FT: Firm Transportation, a contractual agreement for the guaranteed movement of natural gas on a pipeline.
• GOR: Gas-to-Oil Ratio, the volume of natural gas produced per unit of oil.
• LOE: Lease Operating Expenses, the day-to-day costs required to operate and maintain oil and gas wells.
• NRI: Net Revenue Interest, the share of production revenue an owner receives after deducting all royalties and other burdens.
• Waha: A major natural gas pricing hub located in the Permian Basin of West Texas.

Full Conference Call Transcript

Operator: Good morning, and welcome to Permian Resources' Conference Call to discuss its Q3 2026 Earnings. Today's call is being recorded. A replay of the call will be available by visiting the company's website at www.permianres.com. At this time, I will turn the call over to Hays Mabry, Permian Resources' Vice President of Investor Relations, for some opening remarks. Please go ahead.

Hays Mabry: Thanks, Kristen, 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. Many of the comments during this call are forward-looking statements that involve risk and uncertainties that could affect our actual results and are discussed in more detail in our filings with the SEC. We may also refer to non-GAAP financial measures. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation. With that, I will turn the call over to Will Hickey, Co-CEO.

Will Hickey: Thanks, Hays. We are extremely excited to discuss our Q3 results this morning. Q3 was an outstanding quarter for PR. We grew production across all three streams in response to stronger commodity prices and generated record free cash flow of $0.98 per share, despite lower oil prices compared to Q2. More importantly, the same execution that drove our strong quarterly results has allowed us to meaningfully improve our full-year outlook. We've worked hard to optimize nearly every aspect of our business and now expect to generate approximately $300 million of incremental free cash flow compared to our original plan, normalized for commodity prices.

We've also continued executing on our decade-long acquisition strategy, announcing $1.15 billion of highly attractive acquisitions to add significantly high-return inventory to our portfolio. Overall, I think this quarter demonstrates that our business model is working. We have the right team, assets, and strategy in place to continue growing free cash flow per share over the long term, regardless of the commodity cycles. Starting with our operating results on slide three, oil production averaged 208,000 barrels per day, and total production averaged 458,000 BOE per day. We grew oil production by approximately 10,000 barrels per day compared to Q2, including over 8,000 barrels per day of organic growth.

This was driven by our team's relentless focus on improving every aspect of the business. We increased workover activity to reduce downtime to the lowest level in PR history, closed over 100 acquisitions of incremental working interest in our existing units, and continued reducing cycle times to bring new wells online faster. The remaining 2,000 barrels per day of growth came from our Ward County bolt-on acquisition. I note this is not growth for growth's sake. This is responding to market conditions to increase near-term free cash flow for our shareholders. Importantly, we were able to accelerate production while continuing to drive down costs.

Our team has been optimizing power generation and compression equipment, deploying AI-powered artificial lift monitoring to improve runtime, and executing a highly successful workover program. Combined with higher production, these efforts reduced controllable cash costs by 6% quarter-over-quarter to $7.05 per BOE, the lowest level in PR history. LOE declined to $5.11 per BOE, and cash G&A declined to $0.73 per BOE. We spent $518 million of cash CapEx during the quarter, consistent with Q2. Our drilling and completion teams continued to improve execution through longer laterals, expanded water recycling, and reduced cycle times.

In fact, we drilled five of the 10 fastest wells in PR history during Q3, including our fastest well ever, which averaged more than 2,700 feet per day. These efficiency gains are helping offset inflation in diesel and steel while supporting lower D&C cost per foot year-over-year. Slide four shows the complete picture. Higher production, improved gas and NGL realizations, lower controllable cash cost per BOE, and consistent CapEx drove almost $100 million of additional free cash flow compared to Q2, despite lower oil prices.

We cannot always overcome commodity price fluctuations quarter-over-quarter, but we do believe our team's commitment to disciplined investment and high-return, rapid payback projects and premier execution capabilities can consistently improve the business and translate to long-term free cash flow growth across cycles. Turning to natural gas. Q3 was a great example of the flexibility we discussed on our last call. In Q2, we curtailed high GOR wells when Waha prices were deeply negative. As prices improved, we brought those wells back online, increasing natural gas production by 42% quarter-over-quarter to approximately 787 million cubic feet per day. As you can see on slide five, our unhedged realized gas price improved by $2.48 per MCF compared to Q2.

We also began delivering gas through Hugh Brinson during the quarter, bringing the percentage of our volumes priced to Gulf Coast and DFW markets to approximately 80%. The combination of higher volumes and better realizations drove a significant improvement in our natural gas revenue, going from negative $90 million in Q2 to over positive $50 million in Q3, a $140 million improvement before hedges. Including the benefit of our hedges, we realized $1.12 per MCF during the quarter. We spent a lot of time over the last year positioning our gas portfolio to access better markets, and we are now starting to see the benefits of that work.

Today, we are selling over 600 million cubic feet per day downstream of Waha, which will increase to over 700 million cubic feet per day in Q2 of 2027. This gives us access to markets closer to the end users and growing demand while maintaining flexibility across delivery points. Looking forward, we believe natural gas represents a meaningful opportunity for additional free cash flow generation. We have already seen the impact of better realizations in Q3, and as you can see on slide five, we have line of sight to further natural gas revenue growth in 2027. With growing LNG and power demand, we are well-positioned to benefit from the potentially higher downstream prices over time.

To wrap it all up, I think what our team accomplished so far this year is pretty remarkable. We responded quickly to higher commodity prices, finding ways to bring additional production online while continuing to drive down cost. To put that in perspective, we are on track to grow oil production by 11% this year while reducing every component of our cost structure on a year-over-year basis. I think that is a great testament to the quality of the people and their relentless focus on improving the business every day, and I want to thank them for all their hard work. With that, I will turn it over to James to discuss our recent acquisitions and updated outlook.

James Walter: Thanks, Will. Since our last earnings call, we have continued to execute on the same acquisition strategy we followed for years. Buy high-quality assets where our existing operations, subsurface knowledge, and cost structure allow us to generate outsized full-cycle returns at mid-cycle prices. In the Q3, we completed approximately 175 transactions to add an additional 24,000 net acres, 9,000 net royalty acres, and 13,000 BOE per day of production. Combined, these acquisitions will add over 200 net locations and 80% 8/8th NRI that should immediately compete for capital within the Permian Resources portfolio. Combined upfront consideration was approximately $1.15 billion.

The transaction included Ridge Runner Resources for just over $1 billion and another $120 million of bolt-ons and smaller ground game transactions. After backing out the value of PDP at $500 million, that works out to $22,000 per net leasehold acre, $14,000 per net royalty acre, and $3 million per net 10,000-foot location, which is consistent with our historical acquisition metrics. We closed Ridge Runner on October 30, and the rest of the transactions closed during Q3. Slide seven provides a bit more color on our longstanding approach to M&A and how the Ridge Runner deal fits with that strategy.

When we are looking at potential transactions, we want to buy assets that make our existing business better and can generate outsized returns for our investors. That means that the asset quality has to be extremely high, and the acquired locations need to compete for capital within our existing portfolio from day one. Our existing footprint in the Delaware Basin allows us to enhance returns by bringing our information, cost, and execution advantages to bear. And we think the Ridge Runner acquisition is another great example of the differentiated way we approach M&A. To start, we have known Ridge Runner CEO Scott Germann for over 10 years.

We all live in Midland, and in fact, one of the first deals we looked at way back in 2016 was actually being sold by Scott when he was at BC Operating. We did not get that deal back in 2016, but have stayed in touch and built a great friendship over the years. So naturally, we have followed what the Ridge Runner team has put together with their current iteration and entered into discussions with them in late spring when they initially marketed their business. But for a lot of reasons, it didn't make sense for us at the time. Asset mix, commodity pricing, and ultimately price expectations.

After it did not transact, we entered into a bilateral dialogue a few months later to get to work with the Ridge Runner team to see if we could find a transaction that made sense for both parties as a true win-win. All that dialogue paid off. Ultimately, we struck a deal to include Ridge Runner's royalty company that wasn't included in the initial marketing process, while excluding the Woodford and Northwest Shelf assets that weren't a good fit for PR.

The final piece of the deal was that the sellers wanted to be paid for the potential upside in oil prices, and PR was stubborn in our focus on making sure we could underwrite strong full-cycle returns at mid-cycle prices. At the time, full-year 2027 oil strip was hovering around $72 per barrel. To bridge that gap, we added a contingent payment that allowed us both to participate in the upside if commodity prices outperformed in 2027 and 2028. When we combine great assets with a purchase price and structure we worked hard to get right, we get an acquisition that generates attractive full-cycle returns at mid-cycle prices.

Specifically, at flat $70 per barrel and $2 per MCF, we expect at least 5% free cash flow per share accretion over two, five, and 10 years. We are confident we can continue to execute on this disciplined acquisition strategy and drive shareholder value for years to come. Turning to slide eight on guidance, we are increasing our full-year oil production midpoint to 202,000 barrels per day, which represents approximately 11% growth over last year and a 7% increase from the guidance we provided in February. Approximately 85% of the year-to-date increase in oil guidance comes from standalone improvements. Strong base and new well performance, higher working interest, and increased workover activity have been the primary drivers.

Ward County and Ridge Runner add to that growth, but the largest contribution has come from improving the business we already own. We are updating our full-year cash CapEx midpoint to $2.025 billion. Approximately $20 million of the increase is associated with Ridge Runner, with the remainder primarily driven by additional working interest acquired through the ground game and increased workover activity. These are investments that add production cash flow to the business in the very near term. For the Q4, we expect oil production of more than 210,000 barrels per day, including approximately 4,000 barrels per day from Ridge Runner, with cash CapEx spending similar to what we did in Q3.

To conclude, on slide nine, we wanted to take a step back and walk through the things we've done this year to improve upon our original plan laid out for investors back in February. When oil prices rose earlier this year, we reacted quickly and took steps to increase production by investing in the shortest cycle projects in our portfolio while maintaining a disciplined focus on cost reduction. We drove higher working interest wells as a result of our ground game, did more workovers to improve our base production, and accelerated activity where it made sense, all while keeping activity levels flat from the start of the year and delivering the lowest cash cost in company history.

This allowed us to spend more capital and generate more production revenue and ultimately cash flow for our investors this year. As a result, full-year 2026 free cash flow will be approximately $300 million, or $0.35 per share, higher than our original plan would have achieved when adjusted for the latest actual pricing. Our goal remains constant, to grow free cash flow per share and maximize long-term equity value for shareholders. This quarter shows how we do that through our existing operations, our marketing portfolio, and disciplined acquisitions. Thank you for joining us today. With that, we'll turn it back to the operator for Q&A.

Operator: 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 one again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Neal Dingmann with William Blair. Your line is open. Please go ahead.

Neal Dingmann: Morning, guys. Thanks for the time. Will, my first question is likely for you. Could you speak to the further rapid payback additions you all continue to see? I mean, you've certainly done a great job with incremental low-cost growth in the recent high-price oil environment, and just wondering if you could continue at this, what I'd call sane buildable pace.

Will Hickey: Yeah, I mean, look, I'd say that's one of the best things about the PR business, is that the widget that we produce, especially on the new wells we drill, is some of the highest return and fastest payback wells, I think, across the industry. That is a We're in the right spot in Delaware Basin, and with our cost structure, we can generate a lot of cash from the wells we drill. We've talked about historically, as we're looking at payback is an important thing that we look at when we think about, is it a time to grow or how do we want to allocate capital?

If you think, in normal times, you may see paybacks on picking up an incremental rig and call it the 12- to 18-month range. In bad times, it may slip longer than 18 months, and in good times, it's shorter. I think this year, it is well inside of 12 months. I mean, you've seen it this year. We increased capital spend by, call it, $150 million-ish, and we've generated an incremental $300 million of free cash flow in the same year we did it. So, these are some of the shortest cycle paybacks we've got.

That's been increased net wells through incremental working interest, as well as the production team finding capital projects in the field that have been crazy quick paybacks. Think turning on wells that have been offline for a while, think small little refrac jobs or surfactant jobs, or other artificial lift optimization.

Neal Dingmann: No, very notable. Nice job on those. My second question, James, maybe for you, just on M&A. You talked about this already. Looking at it, just looking at the maps over the last couple of years, you've done a great job blocking up a lot of your core areas in Eddy, Lea, Reeves, et cetera. So, two questions here. Is there still additional white space to fill? Secondly, would you all consider adding assets beyond, I'd call these core areas?

James Walter: Oh, yeah. Actually, the second question first. I mean, the name's Permian Resources, so you can rest assured we'll stay in the Permian Basin. Man, we see so many opportunities in the core of the Delaware. I don't see a reason in the near term, probably the midterm either, that we'd be looking in what we'd call different areas. We do think, to answer your first question, there's a ton of white space. I'd say our momentum on the small ball stuff, the ground game, is as good as it's ever been. That kind of stuff quarter over quarter has been really good for Permian Resources.

I think those are the best, some of the highest returning, most near-term acquisitions that we do. I think the bigger stuff, looking out the next couple of years, I think we feel really good about. I think there's a good pipeline of businesses to buy. I'd say there's nothing imminent, nothing near term for us, but over the next year or two or three, I think we'll continue to find acquisitions like this with Ridge Runner deal, like the Ward County acquisitions we did earlier this year, or the Apache one we did last year.

Neal Dingmann: Thank you all.

James Walter: Thanks, Neal.

Operator: Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Your line is open. Please go ahead.

Kevin MacCurdy: Hey, good morning. Sounds like you've been working the Ridge Runner deal for a while. I think we're all pleasantly surprised that you can continue to do those attractive bolt-ons. Can you talk a little bit about the importance of the royalty program and how much of the acreage is covered by the high NRI, and what that does to your 2027 program?

James Walter: Yeah, sure. No, like I said, getting that royalty business alongside the working interest assets is really important to us. I think it's safe to say the vast majority of those 9,000 acres we have on slide six are overlaid on the pink Ridge Runner acres we show on that same slide. That's exactly where you'd want them. And obviously, I think it's pretty simple, but it really helps enhance our returns because that's incremental barrels and incremental cash flow that you don't have to spend dollars to achieve. So, I think our royalty position has been a really important part of our capital efficiency story, and we love having the opportunity to buy high NRI stuff like this.

Kevin MacCurdy: As a clarification, how many wells can you execute on that Ridge Runner annually?

James Walter: How many wells could we? I mean, that's all pretty drill-ready stuff in existing areas that we already operate. I think for simple modeling purposes, it's probably a little less than a rig, something like that. No, to answer your direct question, you could drill it a lot quicker than that. I think we might. I think for us, after we buy things, we no longer think about a Ridge Runner versus Permian Resources. We think about it as the combined business and make the right capital allocation decisions from there.

Kevin MacCurdy: Appreciate that. As a follow-up, looking at 2027, in the past, you talked about higher prices and lower service costs leading to growth mode. Prices are still high, but we've seen some move in well costs. Is growth still the mindset, and can you execute that on the same rig frac count?

Will Hickey: I think we're going to take it quarter for quarter. Obviously, we had a lot of growth into Q3, with the acquisitions. There's a little growth into Q4, if you look at what we're projecting. I think next year, we will just probably keep it close to the vest until we get there. I think you're right in that, I mean, the strip still looks good even with the pullback this week. Service costs are, I'd say we've been able to mitigate a lot of the diesel-related inflation we've seen year to date. So, I mean, the widget, the return profile as we sit here today still looks very attractive.

But, I mean, this is a dynamic world and things are changing quickly. I think if there is one thing we have demonstrated that we can do really, really effectively is we can make very quick pivots in the schedule like we did this year. I mean, if you think about this year, we entered on the lowest CapEx we have ever put out at $1.85 billion and basically in no growth mode. Then sometime mid-March, we decided this is a very unique money-making environment, and we are now going to project to do over 10% year-over-year organic growth in the same year.

I think that allows us to kind of wait till we actually get there to see what the world looks like. But I think we will do everything we can to do it within the existing rig and frac fleet count, to kind of continue to pick up efficiencies and grow the right way where the cost structure does not increase in spite of the growth, but we can maintain the kind of being the low-cost operator, and then we can make the decision on is it the return environment that justifies growth or not.

Kevin MacCurdy: Yeah. Good answer and good quarter. Thanks, guys.

Will Hickey: Thanks.

Operator: Just a reminder to limit yourself to one question and one follow-up. Your next question comes from the line of John Freeman with Raymond James. Your line is open. Please go ahead.

John Freeman: Thanks. Good morning. You all mentioned in the release that the record low controllable cash costs were driven by the lower LOE from the optimization of the power compression projects that led to the company's record run times. Can you all just sort of elaborate a little bit on these power compression projects and if there's still more optimization to be done across y'all's position? Could this be sort of a continued kind of tailwind in the next year for y'all?

Will Hickey: Yeah, I mean, the details would be on the power side. This is just the evolution of us continuing to install more microgrids across New Mexico to lower our power costs in areas where we're not hooked up to the grid. Compression, I'd say compression, we have a lot of compression in the field, and it's been a big effort of the team a long time to kind of continue to have, I'd say, industry-leading runtime on the compression, which helps with the BOE part of the equation and with the cost side on the maintenance. Then really, I think this quarter, we got a big tailwind on the artificial lift side.

Like, we have had the lowest failure rate I think we've ever printed, which obviously reduced cost and increases runtime, as well as just optimization across the whole artificial lift fleet, primarily on the ESP side of just really kind of finding that sweet spot of moving the max amount of fluid while also keeping failure rate as low as possible. So, this is just a, I'd say, a function of probably a little bit of everything went right this quarter, combined with a lot of small changes we've made over the last year, kind of all coming together in a way that we were able to put out such impressive numbers.

I think go forward, yeah, like we are building sustained durable changes in the cost structure of the business. I'm not sure that what we printed in Q3 is necessarily the new norm. This was a uniquely good quarter from a weather and from a failure rate perspective that I'm not sure that's the new norm, but it definitely is, we're improving kind of where we've been historically.

John Freeman: Thanks. On the gas takeaway topic, obviously you've got over 700 million a day of FT out of the basin next year. Obviously going to see some nice improvement on the realizations. We've seen some other operators recently in the basin that have added some more FT on some newly proposed pipes. Just maybe how are y'all thinking about just longer term sort of the trade-off of maybe looking to add even more FT when you look to the out years versus maybe expecting some improvement in just in-basin demand and just sort of the trade-off and kind of the analysis y'all are going through when y'all kind of make that decision process on whether to add more or not?

James Walter: Yeah, I mean, I think we certainly think that in-basin Waha pricing should improve. That said, our goal is to sell the vast majority of our molecules further downstream. We just think over the long term, being closer to end users for oil and gas are, it's going to be the right long-term answer. That said, our contracts allow us to preserve some optionality to kind of shift some sales back to Waha if that market were to change and be the favorable place for Permian Resources in the future. I'd say, with 700 million a day of firm takeaway next year, growing to 800 in 2028, we feel like our gas is pretty well covered for the near term.

I think as we think out beyond that, I do think as we see or if we see continued gas growth from Permian Resources that we'd look to evaluate and likely kind of participate in taking out firm on some of the longer dated pipelines. But that's something we're constantly evaluating, trying to figure out which markets make sense, which operators fit best with what we're trying to do. But yeah, I think the strategy of selling further downstream, closer to end users is something that we'll continue to stick with.

John Freeman: Thanks, guys. Appreciate it.

Will Hickey: See you, John.

Operator: Your next question comes from the line of Phillip Jungwirth with BMO Capital Markets. Your line is open. Please go ahead.

Phillip Jungwirth: Yeah, thanks. Good morning, guys.

Will Hickey: Thanks, Phil.

Phillip Jungwirth: On a Permian competitor call, there was some discussion around optimal multi-zone co-development and maximizing PV per section. Recognize it's different parts of the basin, but just curious how you characterize PR's approach, the balancing DSU recovery with the returns, and just how optimal do you feel you're at on the development design now, recognizing it varies by area?

Will Hickey: I think just starting with just the approach, I think we take a very similar approach to the competitor you're referencing, where we are looking at the incremental or marginal returns of the incremental well, and kind of at some point, that bends over to a place where it no longer makes sense, and thus you are maximizing, call it, NPV per section, and really kind of the resource that we own. This has been something we've been doing for a long time. If you follow PR's development plan for the last, call it, since COVID, it's been very, very similar.

I do think what is uniquely different in the Delaware is we are still very much in the camp of discovering new zones every day in the Delaware. If you think about what were core zones in the Delaware Basin just two years ago, it didn't include what people have done across the whole basin, in the Avalon, in the Harkey, in the Penn Shale, in the deeper Wolfcamp, and now in the Woodford. I think if there's any difference between us and our competitors, I'd say that we are still very much learning every day kind of the way to most optimize NPV per section, given just the changing of the benches and the resource in the Delaware.

We're still in early innings. But I think from a methodology perspective, we approach it very similarly, trying to just maximize value over the resource over the long term.

James Walter: The other really cool thing we've talked about before about the Delaware Basin is just the amount of height in the oil-producing column in the Delaware is massive, and we've got the benefit of lots of stack pay. Like other basins, I think we have a unique in the Delaware is we have a lot of barriers that kind of create frac barriers. So, there's some parts of our assets that you probably do need to develop the whole top-to-bottom stack together, but there's other parts where you've got two, three, four distinct tanks that don't have to be developed at the same time as the other tanks.

So, like Will said, that's a real big advantage when you're discovering new zones, is most of the time, the new zones that we've discovered, we found actually don't have to be co-developed with what we've developed historically. So, that allows us to kind of particularly benefit from that serendipity going forward, and allows us to make kind of more capital-efficient decisions as we think about a development plan without sacrificing any NPV.

Phillip Jungwirth: No, that's great. Then there's a small amount of cash tax creep this year, just with the higher crude prices. But wondering how you see this playing out at the strip over the next couple years, and not that this drives A&D decision-making, but you guys don't stay static. So, is the ground game just plus organic growth something that could push this out a bit further?

Guy Oliphint: Yeah. I mean, the big picture, we still anticipate being full cash taxpayers in 2028, somewhere in between in 2027, and we're always taking taxes into account on investment decisions. I wouldn't say that's a giant needle mover on the ground game, but we're always taking that into account.

Phillip Jungwirth: Got it. Thank you.

Guy Oliphint: Thanks, Phil.

Operator: Your next question comes from the line of Neil Mehta with Goldman Sachs. Your line is open. Please go ahead.

Neil Mehta: Yeah. Good morning, team. Just wanted to start off on your hedging philosophy, and how you're thinking about both the 2027 and 2028 hedge book. Obviously, a lot of backwardation, balance sheets in good shape here, but we could be an interesting inflection point if you wanted to do something around hedges, so just curious about that.

James Walter: Yeah, I mean, I think I'll kick it off. I'd say, look, we've always taken an approach that we need to do whatever it takes to protect the business so that we can survive and thrive during a downturn. Frankly, when Permian Resources was smaller and had leverage in the kind of 1x range, that begat a certain level of hedges. I'd say where we stand today with leverage at 0.5x and delevering quickly, combined with an investment rating and great access to capital, I think hedging to protect the business is no longer a need.

But I do think we've said before that I think we like the concept of being opportunistic in hedging, and with commodity prices where they are today, we've seen some interesting windows to layer on some additional hedges, but I don't think it's a need anymore. It's a nice to have, and you'll see us be opportunistic rather than kind of prescriptive going forward.

Neil Mehta: That's great, guys. Then just a follow-up is, I'd be curious on where you guys are in terms of extending recoveries. I'm thinking surfactants and secondary zone work. Just talk about what you're doing out in the field and what inning do you think you are, and is it translating into actual improvement in recovery rates?

Will Hickey: Yeah, I mean, we have been, I'd say, testing, studying on the surfactant side for probably a year now. We have done quite a few of, I'd say, post-production surfactant jobs on the production side. Honestly, some of that is, when I say production-related CapEx in the quarter, are in fact exactly that. Go pull an ESP that's two years old and with a pump truck out there and pump some surfactant in there. I'd say on both the production side and on the initial completion side, we have seen some cases of tremendous uplift from surfactants. This is tremendous uplift from legacy wells in the area and control wells on the exact pad.

What's been challenging for us is really kind of sifting through the variability of the results to date. Some wells where you see uplifts, 30%, 40% plus relative to a control, and other wells where you see no uplift, or in some cases, even slightly worse wells as compared to the control. I think what's encouraging is if you look at it on an aggregate basis, both on the production and on the completion side, from the capital we've spent, we have generated a sub-one-year payback and really returns that are competitive with the existing program on the aggregate.

The complexities is really trying to dig into, I'd say, question one of, is this true EUR enhancement recoveries, or is this just acceleration of barrels you would have already got? Then two, how do we fine-tune this where we do more 30%, 40% increases and less zero or even decreases? What inning are we in? It's got to be early, the second inning. But I do think that unlike other things we and others in the industry have tried over the last couple of years, this one has encouraging results early.

It's just going to be a long trial and error process to kind of get the right recipe where you can model it, predict it, and talk about what it's going to look like in the future.

Neil Mehta: Okay. That's helpful, Will. Thank you.

Will Hickey: Thanks, Neil.

Operator: Your next question comes from the line of Arun Jayaram with JPMorgan. Your line is open. Please go ahead.

Arun Jayaram: Good morning, Will and James. You guys have always been really strategic and nimble on how you've managed your supply chain, as well as your contracting strategy in the Permian. I was wondering how you guys are thinking about that philosophy or executing that strategy or philosophy in 2027, where we do have some inflationary headwinds largely associated with consumables, but frac activity could get a little bit tighter. How do you think also about the natural gas versus diesel arbitrage when you're thinking about the type of fleets that you may want to be working next year?

Will Hickey: No, I think everything you just said is on our mind. We have, I'd say, even earlier this year or even last quarter, thought about how far out should we be purchasing casing given the run-up in HRC and potential tariff-related casing increases that are projected into 2027. We have been looking long and hard on putting DGB-type kits on our rigs to reduce diesel consumption. I'd say e-fleets are on the table for us, which has been something that has not been in the past. I think that our strategy as to how we have approached contracting and partnerships with our service companies has not changed.

I just think that the balance of where is the value is shifting from, if we can pump less diesel, that moves the needle a lot more than it did in the past. Maybe it makes sense to spend some capital to convert a fleet or increase horsepower hours slightly to reduce diesel consumption, because at the end of the day, that delivers a lower cost per foot well bore. No, I think that you're correct in that diesel and casing are headwinds. Look, there's been other areas that we have seen deflation over the last quarter. It's not all up and to the right.

We have seen some areas that the efficiencies that the service companies have provided have allowed a little bit of deflation or deflation in other areas. No, we're going to do everything we can to continue to be the cost leader in the Delaware going into 2027.

Arun Jayaram: Great. I just had a follow-up on your Q4 guidance. Sorry for splitting hairs here, but you produced 208 in Q3. You're adding 4 KBD from the Ridge Runner, the old partial quarter of the Ridge Runner, and you guided above 210. The question we've got is, do you expect the 208 that you produced in Q3, do you expect that to be flat, go down a little bit, up? Just a little bit of color around that would be helpful.

James Walter: Yeah, that's a good question. I think probably some rounding and guidance, et cetera. But we expect Q4 to be more or less flat from Q3 with the addition of the Ridge Runner barrels.

Arun Jayaram: Thanks for clarifying. Appreciate it.

Operator: Your next question comes from the line of Josh Silverstein with UBS. Your line is open. Please go ahead.

Josh Silverstein: Good morning, guys. Given all the acquisitions you've done year to date, can you just talk about the runway of your inventory and well productivity trends? Is the new acres that you're adding, is this just extending the duration of your current productivity, or can you guys actually increase that well productivity kind of average profile with the new inventory? Thanks.

Will Hickey: No, I think what the acquisitions do is they probably extend the top quartile of our inventory, if that's how you want to think about it. I would expect flat year-over-year well productivity into next year, just as we saw over the last five years. I mean, we're buying rock that shares lease lines, extends laterals, and is incremental working interest in our existing units. This is just more of our ability to prosecute the exact same development plan with the same capital allocation that we've done historically.

Josh Silverstein: Got it. I was curious if there were any gating items around the ground game in regards to the balance sheet leverage. Do you want to keep that below a certain level? How do you balance this versus shareholder returns?

James Walter: Yeah, I mean, I think we're always conscious of not putting the business at risk when we do anything, acquisitions, development capital. First of all, our balance sheet's in unbelievable shape, right? We're less than half a turn levered, delevering quickly with a ton of cash flow coming off the business and investment-grade ratings. So I'd say the balance sheet is by no means a limiting factor today.

I do think, as we think about shareholder returns and other things, I do think as the balance sheet continues to delever from here, I think that kind of makes us take another look at some of the other means to create value for shareholders, acquisitions, share buybacks, increasing the dividend further, et cetera. And it's always been kind of weighing the opportunity sets against each other and seeing which of the four or five capital allocation decisions we think are going to make the most value for shareholders over the long term. I'd say our framework and how we think about it hasn't changed, but the balance sheet is in really good shape.

Will Hickey: Thanks, Josh.

James Walter: Thanks, Josh.

Operator: Your next question comes from Oliver Huang with TPH Research. Your line is open. Please go ahead.

Oliver Huang: Good morning, James, Will, and team, and thanks for taking our questions. Just starting with our first question on capital allocation. I know you all aren't ready to speak to 2027 quite yet, but just given all the ground game work, the bolt-ons done this year, could we potentially see the New Mexico side of the play garner much more capital as a portion of the corporate?

James Walter: I think it will be pretty consistent. I mean, we bought that Ward County bolt-on last quarter, so I kind of think our acquisitions have been directionally weighted the same as our capital has been historically. And like Will said, we think capital allocation development decisions should look a lot like they have the last few years, which, as you mentioned earlier, is extremely strong.

Oliver Huang: Okay, makes sense. For my second question on the Ridge Runner assets, any sort of color you can provide on what the working interest is on that specific acquisition? I just know that you all spoke into leaning into higher working interest over the course of the year multiple times, and just trying to understand what the opportunity set might be for this specific footprint.

James Walter: Yeah, I mean, that working interest is in line with kind of what we've been drilling. I think what will be cool about that acquisition, it does give us the opportunity to go buy some new non-op stuff that we haven't had before. I'd say every time we've done an acquisition historically, that just creates more ground game opportunities to take that working interest from 75 or 80 to 90. And that will, I think, provide a good ground game runway to continue to net those working interest ups from here.

Oliver Huang: Perfect. Thanks for the time.

Operator: Your next question comes from the line of Gabe Daoud with Truist Securities. Your line is open. Please go ahead.

Gabe Daoud: Thanks, operator. Hey, guys. Morning. Thanks for taking my questions. Was hoping we could maybe just go back to the capital allocation, and just given how focused you are on driving free cash flow per share growth, the question, I guess, is would the buyback become a greater, like a bigger tool in you driving that free cash flow per share growth higher over time? As you noted, the balance sheet's in really good shape. So just curious, I guess, how does the buyback, in your view, on using the buyback change over time?

James Walter: Yeah, I mean, I think we've always said we wanted to buy back shares. I think that's always been an important part of our capital allocation strategy. I'd say the last four years, we've seen better opportunities on the cash acquisition and the kind of balance sheet side. I do think, though, to your point, as the balance sheet gets better and better, I think the attractiveness of buybacks, especially with our really good feeling for how the business develops and grows free cash flow per share over the next five and 10 years, I do think that net-net buybacks do become more attractive. I'd say, that said, we are cautious to do buybacks that end up being pro-cyclical.

But I do think, to your very smart question, as the balance sheet is stronger and stronger over time, and frankly, we're more and more confident in the long-term durability of this free cash flow per share growth, I do think that buybacks become more attractive.

Gabe Daoud: Okay. Okay, no, that's helpful. Appreciate that, James. Then I guess, just a quick follow-up. Could you maybe just tell us, just given all the deals and you're kind of guiding to greater than 80% working interest, like how greater is greater than 80%? Is it 90%? Like, how much has that moved up this year, just given all the deals that you've done?

James Walter: It's a little bit over 80%, would probably be the right way to frame it. Not 85%.

Gabe Daoud: Okay. Okay. Okay. Got it. Got it. All right. Thanks, guys.

Operator: Your next question comes from the line of John Abbott with Wolfe Research. Your line is open. Please go ahead.

John Abbott: Hey, good morning, and thank you for taking our questions. So really two quick ones for me. First, you continue to improve your base business. Can you remind us where your underlying decline rate is at and the opportunities to improve upon that as well? And the second question, I'm going to go back to workovers, asked about it last quarter. At that time, it seemed that you had pretty much exhausted the opportunities, but this quarter, you've highlighted them again. What has changed on the workover front? What is the opportunity running room there at this point in time? Those are my two questions.

Will Hickey: Love it. I'll take them both. Thanks, John. Our base decline really hasn't changed. It's still in the high 30s on an oil basis and call it mid-30s on a BOE basis. Just the growth, the organic growth that the business has demonstrated over the last few years is obviously offset to what would have naturally been an arresting base decline. And then on the capital workover side, it's very astute of you. It did feel like at the end of Q2, we had kind of run the course of finding workover-related projects. I'd say two things change.

One, if you think about, we took over operations on that Ward County bolt-on, which was a legacy asset of a much larger company, which I'd say is normal course for us, is us to go kind of work over and get those wells back online. But in this particular case, given oil price, I'd say we aggressively worked over that asset.

So, new assets came in that created new opportunities, as well as kind of, I'd say my definition of workover may have expanded quarter over quarter, where the team has found, not just take wells that were down and get them back online, but think more proactive projects to convert gas lift to ESP in cases where ESP made sense, think surfactant jobs or other acid jobs, kind of historically, I've always thought of workovers as if you've got a backlog of wells that are down and you can go fix them. And in reality, when oil's in the 90s, the team can go find ways to add barrels on a more proactive basis.

John Abbott: Appreciate it. Thanks for the color.

Operator: Your next question comes from the line of Paul Diamond with Citi. Your line is open. Please go ahead.

Paul Diamond: Thanks, you all. Good morning. Thanks for taking the call. As you talk about increased takeaway and the recovering Waha, I guess, pricing matrix, does that shift the development plan at all? Is there any room for maybe a few higher GOR wells, or is it all still going to remain largely oil-driven?

James Walter: Yeah, I mean, the economics are still oil-driven at anything resembling these prices. I wouldn't say it changed capital allocation at all, but it does make the returns of our wells meaningfully higher. I think every well that you drill makes a lot of gas, and higher gas prices from better downstream makes every single well we drill more economic, faster paybacks, more free cash flow. So, it's all really good, but doesn't change capital allocation.

Paul Diamond: Got it. Then, just a quick follow-up. As you guys, especially with Ridge Runner and the transaction last quarter, you guys are seeing a rising component of royalty interest across the portfolio. I guess, can you talk about the strategy of those within the portfolio? Is there any potential for monetization at a certain scale, or do you like them where they are?

James Walter: I mean, the first kind of driving reason we've always targeted high NRI acreage is because it makes the economics better. It makes every well you drill returns stronger, payback shorter, and more free cash flow for the same capital. So, that's kind of the root driver and kind of has always been. But I will say, kind of as the business has grown, I do think we've got a really high-quality royalties business that's probably underappreciated by the market, both what it means to the upstream business, but also what it means kind of on a standalone basis. So, I think for us, for now, we like having it kind of where it sits today.

But, I think over time, especially if we're convinced that could make sense and unlock additional value for shareholders, we'd consider ways to kind of enhance and maximize value there. But I'd say for now, it's still largely upstream-driven from a rationale standpoint, and we like where it sits.

Paul Diamond: Understood. Appreciate the clarity on that.

Operator: Your next question comes from the line of Leo Mariani with ROTH. Your line is open. Please go ahead.

Leo Mariani: Hi, guys. I was wondering if you could sort of speak to the M&A environment a little bit more. Obviously, you guys have done a number of deals. Was this Ridge Runner kind of a competitive marketed deal? Are you seeing most of the deals in the Permian come with kind of more competition these days? Just trying to get a sense of what you're seeing on deal flow and then sort of competition from others.

James Walter: Yeah, I think generally, the bigger deals that we see tend to have some amount of competition, kind of the $500 million and bigger tend to have kind of some sort of competition. I think for us, we've only ended up buying deals that we thought we had a unique edge, unique angle, and typically a one-on-one dialogue with the seller, which is how Ridge Runner ended up. On the smaller stuff, we still buy most of our ground game and bolt-on stuff on a bilateral negotiated basis that's not marketed and tends to not have any other buyers in the room as those negotiations go on.

Leo Mariani: Okay. Appreciate that. I guess just wanted to also get a sense of whether or not you guys are continuing to maybe look harder at some of the secondary zones, potentially the Woodford, as we get into 2027, particularly in light of the better gas environment.

Will Hickey: Yeah, look, I would say generally speaking, yes, we are always looking at secondary zones and ways to kind of find free resource over our existing position. I would say that what has happened so far on kind of the eastern margins of the basin, the Woodford, is exciting. If you look at the same kind of, you have seen a lot of Penn Shale development across Lea and Eddy Counties over the last few years, as well as kind of some co-development in the Harkey and the Avalon in ways we have not seen in the past.

Look, the Delaware Basin, I said this earlier, is like, we are still very much in the middle innings of discovering the optimal cube across the entire basin. As such, new ventures like the Woodford, Penn Shale, et cetera, continue to get discovered. Look, I think for our position in New Mexico, you can assume we own all depths, including all the way through the Woodford across the whole position. Then in Texas, it will be, most of it we will not do the PUDs, but we will own it on a kind of a small percentage of it across the Texas position.

Leo Mariani: Okay. Thank you.

Will Hickey: Thank you.

Operator: Just a reminder, if you would like to ask an additional question, please press star one. If you would like to withdraw your question, press star one again. Your next question comes from the line of Geoff Jay with Daniel Energy Partners. Your line is open. Please go ahead.

Geoff Jay: Hey, guys. A very quick one from me, kind of a follow-up to John Freeman's question earlier. I guess I'm curious if it was the AI monitoring the biggest contribution to the low failure of lift. Then kind of the follow-up to that is just how broadly is that now deployed? Is it kind of fully integrated across the acreage?

Will Hickey: I don't want to give the AI that much credit. I think our team has been optimizing this stuff forever. I do think them getting it into a single dashboard with an artificial intelligence engine sitting on top has been very enlightening. I think of it as if a production engineer working the Haley asset, kind of on the eastern edge of Reeves County, makes a change to the number of hertz to fix a warning or fix a problem, the AI engine learns that worked, and then when an engineer working Lea County encounters the same problem, it immediately tells him, "Hey, somebody did this yesterday and it fixed it.

Why don't you try this?" So, I don't want to give it credit that it's solving things we couldn't solve. It's just disseminating information in a way that we could never have done really quickly. As to where it sits, I'd say all of our ESPs are on it. So, I think we run about 600 ESPs as a company, and all 600 are in this application that has real-time monitoring.

I'd say we're headed now is to try to get gas lift, rod pump, et cetera, so we can make the same dissemination of informations on, like, what type of If you see GLRs move in one direction, if you could have the AI engine say, "Hey, I recommend you shift this from gas lift to ESP," or vice versa, as opposed to just optimizing the lift that's already on it.

Geoff Jay: Excellent. Great color. Thank you.

Will Hickey: Thanks, Geoff.

Operator: Your next question comes from the line of Noah Hungness with Wells Fargo. Your line is open. Please go ahead.

Noah Hungness: Morning. For my first question here, given all of the M&A and just the base business improvements as well that people have been touching on, could you help us how we can think about what the maintenance CapEx kind of program looks like now?

Will Hickey: Yeah. I'd say, kind of at the, call it north of 200,000 barrels of oil per day rate that we printed this quarter, the business is 10% bigger. I'd say maintenance CapEx is probably between $1.9 billion and $2 billion.

Noah Hungness: Is that also inclusive of the Ridge Runner?

Will Hickey: Yes.

Noah Hungness: Okay. I guess for my second question is kind of going off of the gas marketing and your guys' push to get closer to the end user. Getting the gas to the Gulf Coast obviously gets you closer to the end user, but is there a desire to take a step further and try to set up supply agreements with an actual end user? We've seen some of your peers sign up to work with off-takers around LNG. Are these kind of options that you guys are exploring, or is there interest there?

James Walter: No, absolutely. That's a great question, something we spent a lot more time on. I think you said it. Our first priority was moving further downstream to get away from Waha and closer to end users, and I think we've done a tremendous job of that. Pretty close to mission accomplished, like I said earlier. But that's just step one. I think kind of as we think about continuing to optimize how we market and sell our molecules, fortunately, we have a ton of flexibility kind of downstream from there. I'd say we're looking at all options today. Yeah, LNG deals, kind of final end users, potential infrastructure investments, et cetera.

But I think, that said, we have a really high bar for investment returns. So I think we're being very thoughtful as we think about how we spend dollars, if we spend dollars, and where we want to sell molecules for not just the next year, but the next decade plus. So, I think that's kind of step two and step three after a really successful step one, but something we've spent a lot of time on and should have more to share over the next year or two.

Noah Hungness: That's great color. Thank you.

Operator: There are no further questions at this time. I will now turn the call back to James Walter, Co-CEO, for closing remarks.

James Walter: Thanks again to everyone for joining the call. As you can see, Q3 was an outstanding quarter. The combination of higher production and lower cash costs led to record free cash flow, and our acquisition strategy continues to improve our free cash flow and inventory. We look forward to building on that progress and continue to drive value for our shareholders for years to come. Thanks again.

Operator: This concludes today's call. Thank you for attending. You may now disconnect.

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