二叠纪资源 (PR) 2026年第三季度业绩电话会：自由现金流创纪录，上调石油指引

Permian Resources（NYSE: PR）公布2026年第三季度业绩，每股自由现金流达到创纪录的0.98美元，主要得益于产量增长、天然气变现价格改善以及可控现金成本创历史新低，抵消了油价环比下跌的不利影响。管理层还上调了全年石油产量指引，并详细披露了约11.5亿美元的并购交易。

核心要点

• 第三季度石油平均产量为208,000桶/日，较第二季度增加约10,000桶/日。其中，内生性增长贡献了超过8,000桶/日，其余增量来自对沃德县（Ward County）资产的收购。
• 总平均产量达458,000桶油当量/日，同时可控现金成本环比下降6%，至公司创纪录的7.05美元/桶油当量。
• 每股自由现金流达到创纪录的0.98美元。尽管油价走低，公司产生的自由现金流仍比第二季度增加了近1亿美元。
• 管理层将2026年石油产量中值指引上调至202,000桶/日，相当于同比增长约11%，较2月份发布的指引上调了7%。
• Permian Resources完成了约175笔交易，总金额约11.5亿美元，新增净面积24,000英亩、净特许权使用费面积9,000英亩、13,000桶油当量/日的产量以及200多个净钻井点位。
• 管理层预计，在根据最新的实际大宗商品价格进行调整后，2026年全年自由现金流将比原计划高出约3亿美元（即每股0.35美元）。

关键财务数据

业务与运营表现

产量增长反映出基础油井与新井表现更为强劲、新增工作权益、修井作业增加以及作业周期缩短。管理层表示，公司将停机时间降至历史最低水平，并在现有单元中完成了100多笔增量工作权益收购。

钻井与完井效率亦有所提升。Permian Resources在第三季度钻成了公司历史上速度最快的前10口井中的5口，其中包括创公司纪录的平均每天钻井逾2,700英尺。更长的水平段、水资源循环利用以及更短的作业周期，帮助抵消了柴油和钢材的通胀压力，并推动每英尺钻完井成本同比下降。

人工举升优化有助于降低成本并提高设备正常运行时间。公司约600台潜油电泵已全部接入由AI引擎支持的实时监控应用程序，该引擎可在各项资产间共享运营解决方案。管理层目前正致力于将该系统推广至气举和有杆泵。

天然气经济效益显著改善。在第二季度Waha枢纽出现深度负油气价期间关停高气油比油井后，公司随着价格回升恢复了生产。第三季度约80%的天然气销量以墨西哥湾沿岸和达拉斯-沃斯堡市场定价，目前在Waha下游销售的天然气已超过600百万立方英尺/日。

并购与资产组合拓展

已公布的约11.5亿美元并购交易包括以略超10亿美元的价格收购Ridge Runner Resources，以及价值1.2亿美元的补强型并购与较小规模交易。对Ridge Runner的收购已于10月30日完成交割，而其他交易均在第三季度内交割。

在将5亿美元价值归因于已证实已开发生产（PDP）资产后，管理层测算的收购指标为：每净租赁英亩22,000美元、每净特许权使用费英亩14,000美元，以及每个净10,000英尺水平井点位300万美元。

管理层预计，在原油价格假设为70美元/桶、天然气价格假设为2美元/千立方英尺的基准下，收购Ridge Runner的交易将在2年、5年和10年期内实现至少5%的每股自由现金流增厚。该交易还包括一项与2027年和2028年潜在油价上涨挂钩的或有付款。

所收购的特许权权益与Ridge Runner的作业区块高度重合。管理层表示，更高的净收益权益有望提高单井回报率、缩短投资回收期，并在不增加开发支出的情况下创造额外的现金流。

管理层业绩指引

今年迄今石油指引增幅中约85%来自独立业务自身的改善。管理层将这一增长主要归因于油井表现更强、工作权益增加以及额外的修井作业，而非并购所致。

公司尚未就2027年增长计划作出承诺。管理层表示，将按季度评估大宗商品价格和服务成本，并争取尽可能在现有钻机和完井机队规模内实现增长。

预计到2027年第二季度，下游天然气日销量将超过700百万立方英尺。管理层还表示，到2028年，确定管道外运能力预计将达到约800百万立方英尺/日。

风险与关注要点

• 管理层提醒称，由于天气状况和设备故障率异常理想，第三季度创纪录的低成本水平可能并不代表新的常态化运行水平。
• 柴油、钢材和套管价格上涨仍是成本端面临的阻力。公司正评估双燃料设备、电驱压裂车队以及提前采购套管等措施，以缓解成本压力。
• 大宗商品价格的波动可能会改变产量增长和资本配置决策。管理层强调了公司迅速调整作业活动的能力。
• 表面活性剂处理的效果存在差异。部分油井相比对照井产量提升了30%至40%甚至更高，而另一些油井则未见改善或表现略有转弱。
• Permian Resources预计将在2028年成为全额现金纳税企业，并预计在2027年处于部分现金纳税状态。

分析师问答要点

管理层表示，2026年增量钻井和油田项目的投资回收期远低于12个月。据公司称，约1.5亿美元的额外资本支出帮助在同年产生了约3亿美元的增量自由现金流。

Permian Resources计划继续聚焦于二叠纪盆地（Permian Basin），特别是特拉华盆地（Delaware Basin）。管理层认为仍有大量的补强并购机会，但表示目前没有即将发生的更大规模交易。预计在未来数年内，类似Ridge Runner、沃德县以及此前阿帕奇（Apache）交易的收购仍有可能发生。

在资本回报方面，管理层表示，得益于投资级评级和良好的融资渠道，杠杆率低于0.5倍且在持续下降。随着资产负债表不断强化，公司预计将重新评估并购、股份回购以及进一步提高股息等事项。管理层指出，回购正变得更具吸引力，但也告诫不要进行顺周期回购。

公司的基础自然递减率方面，石油仍保持在30%高段，按油当量计算则在30%中段。通过新收购的资产以及气举转电潜泵、表面活性剂处理和酸化作业等积极举措，修井机会得到了拓展。

管理层将表面活性剂的应用形容为处于“第二局”（早期阶段）。尽管累计支出实现了不到一年的投资回收期，但公司仍在评估这些成果究竟是代表了更高的最终采收率，还是仅仅加速了产能释放。

财报电话会议完整实录

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完整财报电话会议逐字稿

管理层陈述

Operator

Good morning, and welcome to Permian Resources' conference call to discuss its third quarter 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 Chief Executive Officers; and Guy Oliphint, our Chief Financial Officer. Many of the comments during this call are forward-looking statements that involve risks 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.

William Hickey

Thanks, Hays. We are extremely excited to discuss our third quarter results this morning. Q3 was an outstanding quarter for PR. We grew production across all 3 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 that 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 3. Oil production averaged 208,000 barrels per day and total production averaged 458,000 barrels of oil equivalent 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'd 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 run time 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 continue to improve execution through longer laterals, expanded water recycling and reduced cycle times. In fact, we drilled 5 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 4 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 can't always overcome commodity price fluctuations quarter-over-quarter, but we do believe our team's commitment to disciplined investment in 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 5, 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 at 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're now starting to see the benefits of that work. Today, we're 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 '27. 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've already seen the impact of better realizations in Q3. And as you can see on Slide 5, we have line of sight to further natural gas revenue growth in '27. 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're 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's a great testament to the quality of the people and the relentless focus on improving the business every day, and I want to thank them for all their hard work. With that, I'll turn it over to James to discuss our recent acquisitions and updated outlook.

James Walter

Thanks, Will. Since our last earnings call, we've 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 third quarter, 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 an 80% 8/8ths 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 7 provides a bit more color on our long-standing 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 1. 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've known Ridge Runner's 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 didn't get that deal back in 2016, but has 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. And 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 is 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 the contingent payment that allowed us both to participate in the upside if commodity prices outperformed in 2027 and 2028. So when we combine great assets with the purchase price and structure we worked hard to get right, we did an acquisition that generates attractive full cycle returns at mid-cycle prices. Specifically, at $70 per barrel and $2 per Mcf, we expect at least 5% free cash flow per share accretion over 2, 5 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 8 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 stand-alone 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 and cash flow to the business in the very near term. For the fourth quarter, 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 9, 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 shorter cycle projects in our portfolio while maintaining a disciplined focus on cost reduction. We drilled 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

[Operator Instructions] Your first question comes from the line of Neal Dingmann with William Blair.

分析师问答

Neal Dingmann

Well, my first question is likely for you. Could you speak to the further rapid payback initiatives 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. I'm just wondering if you can continue at this, what I'd call same notable pace.

William Hickey

Yes. I mean, look, I'd say that's what's one of the best thing about the PR business, is that the widget that we produce, especially on the new wells we drill is some of the kind of the highest return and fastest payback wells, I think, across the industry. That is a -- we're in the right spot in the Delaware Basin. And with our cost structure, we can generate a lot of cash from the wells we drill. We've talked about historically kind of 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 kind of how do we want to allocate capital.

And if you think -- in normal times, you may see paybacks on picking up an incremental rig in, 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. And I think this year, it is well inside of 12 months. I mean you've seen it this year, we kind of 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. I think turning on wells that have been offline for a while, I think small little refrac jobs or surfactant jobs or other artificial lift optimization.

Neal Dingmann

No, very notable. Nice job on those. And then my second question, James, maybe for you just on M&A. You talked about this already. Looking at it, just kind of looking at the map 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. Sort of 2 questions here. Is there still additional white space to fill? And secondly, would you all consider adding assets beyond, I'd call these core areas?

James Walter

I answer the second question first. I mean [ we're ] -- the name is Permian Resources. I think you can rest assured we'll stay in the Permian Basin. And we see so many opportunities in the core of the Delaware. I don't see a reason in the near term, probably in the midterm either that we'd be looking in kind of what we'd call different areas. Like we do think to answer your first question, there's a ton of white space. Like 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. And 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 2 or 3, I think we'll continue to find acquisitions like this Ridge Runner deal, like the Ward County acquisition we did earlier this year or the Apache one we did last year.

Operator

Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

Kevin MacCurdy

It 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 higher NRI and what that does to your 2027 program?

James Walter

Yes, sure. No, like I said, getting that royalty business alongside the kind of 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 6 are kind of overlaid on the kind of pink Ridge Runner acreage we show on that same slide. So kind of exactly where you 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

And as a clarification, how many wells can you execute on that Ridge Runner annually?

James Walter

How many wells could we? I mean...

William Hickey

A lot.

James Walter

A lot. 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. But no, you could -- to answer your direct question, you could drill it a lot quicker than that. And 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. And as a follow-up, kind of 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?

William Hickey

I think we're going to take it quarter-over-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 and 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. And so I think that there's one thing we've 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've ever put out at $1.85 billion and basically in no growth mode. And then on 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.

So I think that allows us to wait until the -- until we actually get there to see what the world looks like. But I think we'll do everything we can to do it within the existing rig and frac fleet count to 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.

Operator

[Operator Instructions] Your next question comes from the line of John Freeman with Raymond James.

John Freeman

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 company's record run times. Can you just sort of elaborate a little bit on these power compression projects and if there -- is there still more optimization to be done across Shell's position? And could this be sort of a continued kind of tailwind into next year for you all?

William Hickey

Yes. I mean the details would be on the power side. This is just the evolution of us continuing to install more micro grids across New Mexico to lower our power costs in areas where we're not hooked up to the grid. Compression, I 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 run time on the compression, which helps with the Boe part of the equation and with the cost side on the maintenance.

And then really, I think this quarter, we got a big tailwind on the artificial lift side. Like we have been -- had the lowest failure rate, I think we've ever printed, which obviously reduced cost and increases run time 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 maximum amount of fluid while also keeping failure rate as low as possible.

So this is just, 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, yes, 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 that's the new norm, but it definitely is -- we're improving kind of where we've been historically.

John Freeman

And then 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 you 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 you are going through when you kind of make that decision process on whether to add more or not?

James Walter

Yes. 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 stream -- 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 allowed 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 million 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 in Permian Resources that we 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 and trying to figure out which markets make sense, which operators fit best with what we're trying to do. But yes, I think the strategy of selling further downstream, closer to end users is something that we'll continue to stick with.

Operator

Your next question comes from the line of Phillip Jungwirth with BMO Capital Markets.

Phillip Jungwirth

On the Permian competitor call, there was some discussion around optimal multi-zone co-development and maximizing NPV per section. I recognize it's different parts of the basin, but just curious how you characterize PR's approach to 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?

William 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 -- the marginal returns of the incremental well, and kind of at some point, that bins 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. Like 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 2 years ago, it didn't include what people have done across the whole basin, the Avalon and the Harkey, in the Penn Shale, in the Deeper Wolfcamp and now in the Woodford. And so 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 in 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

And 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 stacked pay like other basins. I think we have that's unique in the Delaware is we have a lot of barriers that kind of create frac barriers. So there are 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 2, 3, 4 distinct tanks that don't have to be developed at the same time as the other tanks. So like Will said, like 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 like actually don't have to be codeveloped with what we've developed historically 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 our development plan without sacrificing any NPV.

Phillip Jungwirth

No, that's great. And then there's a small amount of cash tax creep this year just with the higher crude prices. Wondering how you see this playing out at the strip over the next couple of 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

Yes. I mean, the big picture, we still anticipate being full cash taxpayers in '28 and somewhere in between in '27. 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.

Operator

Your next question comes from the line of Neil Mehta with Goldman Sachs.

Neil Mehta

Just wanted to start off on your hedging philosophy and how you're thinking about both the '27 and '28 hedge book. Obviously, a lot of backwardation, balance sheet is in good shape here, but it could be an interesting inflection point if you want to do something around hedges. So just curious about that.

James Walter

Yes. 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 began a certain level of hedges. I'd say where we stand today with leverage at 0.5x and delevering quickly, combined with an investment-grade 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. And 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 actually improvement in recovery rate?

William Hickey

Yes. 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. And honestly, some of that is when I say production-related capital expenditures in the quarter are, in fact, exactly that. Go pull an ESP that's 2 years old and with a pump truck out there and pump some surfactant in there. And I'd say on both the production side and on the initial completion side, we have seen some cases of tremendous uplift from surfactants. And 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. There are some wells where you see uplifts 30, 40-plus percent 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. And so 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-1-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? And then two, how do we fine-tune this where we do more 30%, 40% increases and less 0 or even decreases? And so 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 very -- it's going to be a long trial and error process to get it 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.

Operator

Your next question comes from the line of Arun Jayaram with JPMorgan.

Arun Jayaram

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. And 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?

William 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 kind of tariff-related casing increases that are projected into '27. 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. It's 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 has -- that moves the needle a lot more than it did in the past. And so 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 wellbore.

But 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. But no, we're going to do everything we can to kind of continue to be the cost leader in the Delaware going into '27.

Arun Jayaram

Great. And I just had a follow-up on your fourth quarter guidance. Sorry for splitting hairs here, but you produced 208 in 3Q. You're adding 4 kb/d from the Ridge Runner, the old partial quarter of the Ridge Runner and you guided above 210. So the question we've got is, do you expect the 208 that you produced in 3Q, 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

Yes. That's a good question. I think probably some rounding in guidance, et cetera, but we expect Q4 to be more or less flat from Q3 with the addition of the Ridge Runner barrels.

Operator

Your next question comes from the line of Josh Silverstein with UBS.

Joshua Silverstein

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?

William Hickey

No, I think that what the acquisitions do is they probably extend the top quartile of our inventory, if that's how you want to think about it. So I would expect flat year-over-year well productivity into next year just as we saw over the last 5 years. I mean we're buying -- we're buying rock that shares lease lines, extends laterals and is incremental working interest in our existing units. So all -- this is just more of our ability to prosecute the exact same development plan with the same capital allocation that we've done historically.

Joshua Silverstein

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

James Walter

Yes. I mean I think we're always conscious of not risk -- putting the business at risk when we do anything, acquisitions, development capital. But our balance sheet is in unbelievable shape, right? We're less than 0.5 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 kind of as we think about shareholder returns and other things. I do think kind of 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 4 or 5 capital allocation decisions we think are going to make the most value for shareholders over the long term. And I'd say our framework and how we think about it hasn't changed, but the balance sheet is in really good shape.

Operator

Your next question comes from Oliver Huang with TPH Research.

Hsu-Lei Huang

Just on my 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

It will be pretty consistent. I mean we did -- 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 we said, kind of 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.

Hsu-Lei Huang

Okay. Makes sense. And just 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 spoken to leaning into higher working interest over the course of the year multiple times. I'm just trying to understand what the opportunity set might be for this specific footprint.

James Walter

Yes. 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 that gives us opportunity to go buy some new non-ops 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 up from here.

Operator

Your next question comes from the line of Gabriel Daoud with Truist Securities.

Gabe Daoud

I was hoping we can 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 is 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

Yes. 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 4 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 5 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 procyclical. 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. I appreciate that, James. And then I guess as 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

A little bit over 80% is probably the right way to frame it. Not 85%.

Operator

Your next question comes from the line of John Abbott with Wolfe Research.

John Abbott

So really 2 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, I asked about it last quarter. At that time, it seemed that you had pretty much exhausted the opportunities. But this quarter, you 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 2 questions.

William 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 -- yes, 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 2 things changed. 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 if you've got a backlog of wells that are down and you can go fix them. And in reality, when oil is in the 90s, the team can go find ways to add barrels on a more proactive basis.

Operator

Your next question comes from the line of Paul Diamond with Citi.

Paul Diamond

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

Yes. 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. And 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, paybacks 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 stand-alone basis. So I think for us, for now, we like having it kind of where it sits today. But I think over time, especially we're convinced that could make sense and unlock additional value for shareholders. We 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.

Operator

Your next question comes from the line of Leo Mariani with ROTH.

Leo Mariani

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

Yes. I think generally, like 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. And then 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. And 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.

William Hickey

Yes. Look, I'd say, generally speaking, yes, we're always looking at secondary zones and ways to kind of find free resource over our existing position. I'd say that what's happened so far on kind of the eastern margin of the basin, the Woodford is exciting. If you look at the same kind of -- you've 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. So 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.

And as such, new benches 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. And then in Texas, it will be -- most of it, we will not do the [ PUDs ], but we'll own it on a kind of a small percentage of it across the Texas position.

Operator

[Operator Instructions] Your next question comes from the line of Geoff Jay with Daniel Energy Partners.

Geoff Jay

A very quick one for 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? And 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?

William 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, that worked. And then when an engineer working Lea County encounters the same problem, it immediately tells them, "Hey, somebody did this yesterday and it fixed it. Why don't you try this?"

So like it's not -- 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. But -- and then 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 information on like what type of -- if you see GLRs move in one direction, if you could have the AI engine and 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.

Operator

Your next question comes from the line of Noah Hungnes with Wells Fargo.

Noah Hungness

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?

William Hickey

Yes. I'd say kind of at the, call it, north of 200,000 barrels of oil per day rate that we printed this quarter, it's -- 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?

William Hickey

Yes.

Noah Hungness

Okay. And then 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? Or we've seen some of your peers sign up for -- sign up to work with offtakers around LNG. Are these kind of options that you guys are exploring? Or is there interest?

James Walter

No, absolutely. That's a great question, something we spend a lot more time on. I think you said that 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.

And I'd say we're looking at all options today, yes, LNG deals, kind of final end users, potential infrastructure investments, et cetera. And -- 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 2 and step 3 after a really successful step 1, but something we're spending a lot of time on and should have more to share over the next year or 2.

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.