Image source: The Motley Fool.

DATE

Thursday, Aug. 6, 2026 at 10:00 a.m. ET

CALL PARTICIPANTS

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

TAKEAWAYS

• Adjusted Free Cash Flow -- $751 million, representing a record high for the company and a sequential increase of approximately 50%.
• Free Cash Flow Per Share -- $0.88, reflecting management's response to the commodity environment and operational improvements.
• Total Average Production -- 376.4 MBoe/d, including oil production of 198.1 MBbls/d, 86.2 MBbls/d of NGLs, and 552.9 MMcf/d of natural gas.
• Oil Production Growth -- 3% quarter over quarter, driven by increased workover activity and higher working interest in completed wells.
• Natural Gas Curtailment -- 20% sequential reduction in natural gas production, implemented to avoid selling production into a negative Waha market.
• All-in Natural Gas Realization -- $0.38 per Mcf, achieved through a combination of firm transportation, hedging, and proactive curtailment strategies.
• Lease Operating Expenses -- $5.55 per Boe, benefiting from optimized power and compression infrastructure despite lower total production volumes.
• Total Controllable Cash Costs -- $7.49 per Boe, coming in below the midpoint of the company's full-year guidance range.
• Year-to-Date Acquisitions -- $1.05 billion, encompassing approximately 54,000 net leasehold acres and 20,000 net royalty acres across approximately 190 separate transactions.
• Ward County Acquisition -- $520 million, adding 2,000 net acres and 5,000 Boe/d of production at the time of closing on July 31, 2026.
• Acquisition Valuation Metrics -- $13,000 per net acre, $8,000 per NRA, and $2.5 million per net 10,000-foot location for transactions executed year-to-date.
• Full-Year Oil Production Guidance -- 197,000 to 201,000 barrels per day, representing a 10,000 barrel per day increase from previous expectations.
• Full-Year Capital Expenditures Guidance -- $1.9 billion to $2.0 billion, reflecting higher working interest and $25 million in integration costs for the Ward County asset.
• Average Working Interest -- over 80% for the full year 2026, an increase from original expectations of 75% due to successful ground-game transactions.
• Net Debt-to-LQA EBITDAX -- 0.5x as of June 30, 2026, which management expects to maintain through the end of the year.
• Debt Reduction -- 35% total reduction since the end of 2024, with total debt decreasing from $4.2 billion to $2.7 billion.
• Annual Interest Savings -- $75 million, realized following the redemption of legacy Earthstone senior notes.
• Lateral Lengths -- approximately 11,000 feet on average, including the drilling of the company's first 4-mile lateral in the second quarter.
• Water Recycling -- reached record levels in the second quarter of 2026, serving as a key offset to inflationary pressures in drilling and completion costs.
• Inventory Addition -- approximately 330 high-confidence locations added through year-to-date acquisitions that immediately compete for development capital.

Need a quote from a Motley Fool analyst? Email [email protected]

RISKS

• Hickey stated, "WAHA natural gas prices averaged negative $3.14 per Mcf during Q2 and traded as low as negative $9.52 per Mcf," which required the company to proactively curtail production on high-GOR wells.
• Hickey noted, "we do have some inflationary pressures with respect to diesel and casing," which the company aims to offset through drilling efficiency gains and wellbore design improvements.

SUMMARY

Management at Permian Resources Corporation (PR -0.05%) reported record financial performance for the second quarter of 2026, driven by operational flexibility and a disciplined acquisition strategy. The company adjusted its full-year oil production targets, capital expenditure guidance, and average working interests to reflect the integration of the Ward County acquisition and successful ground-game activity. Strategic focus remained on capital efficiency and free cash flow generation, as management implemented proactive natural gas curtailments to mitigate regional price dislocations and optimized workover activity to capture higher oil prices. The company continues to deleverage its balance sheet while executing over 190 accretive transactions to expand its core Delaware Basin inventory.

• Co-CEO Hickey stated, "lateral length is the most effective way to reduce D&C per foot," as the company reported average laterals of 11,000 feet.
• The company implemented a slim-hole well design in New Mexico, which Co-CEO Hickey noted "save[s] almost a day a well" in drilling time while reducing cement and steel costs.
• Management confirmed that year-to-date acquisitions were executed at an attractive weighted average front-month WTI price of $72.50 per barrel.
• Co-CEO Walter described the Parkway bolt-on as a "scaled example of the Midland-born deals that we do with our friends and partners on a regular basis."
• The company began surfactant trials on completion and production operations to evaluate potential improvements in fluid recovery and late-life well productivity.
• Management reported that natural gas firm transportation capacity going into 2027 covers approximately all net volumes, providing long-term protection against regional basis volatility.

INDUSTRY GLOSSARY

• Delaware Basin: A primary sub-basin of the Permian Basin located in West Texas and Southeast New Mexico, known for high-quality oil and gas reserves.
• Waha: A major natural gas pricing hub in West Texas frequently subject to price dislocations due to pipeline capacity constraints.
• LOE (Lease Operating Expenses): The daily costs incurred to operate and maintain wells and related equipment after drilling and completion.
• NGL (Natural Gas Liquids): Hydrocarbons such as ethane, propane, and butane that are separated from natural gas and sold as liquid products.
• NRA (Net Royalty Acre): A unit of measurement for mineral or royalty interests equivalent to one acre at a standard 1/8th royalty rate.
• TILs (Turn-in-lines): A metric representing the number of new wells that have been connected to production facilities and have begun selling product.
• GOR (Gas-to-Oil Ratio): The ratio of produced natural gas to produced oil, used to evaluate well productivity and facility requirements.
• ESP (Electric Submersible Pump): An artificial lift system used to pump fluids from the wellbore to the surface in lower-pressure wells.
• GP&T (Gathering, Processing, and Transportation): The costs associated with moving oil and gas from the wellhead to centralized processing facilities and end markets.
• D&C (Drilling and Completion): The capital-intensive process of drilling a wellbore and preparing it for production through hydraulic fracturing.
• Firm Transportation: A guaranteed contractual commitment for pipeline capacity to ensure product can reach the market regardless of daily fluctuations.
• Surfactants: Chemical additives used in completion or production operations to reduce surface tension and potentially increase hydrocarbon recovery rates.
• Slim-hole design: A wellbore configuration using smaller diameter casing and holes to reduce drilling time and material costs.
• MBoe/d: Thousand barrels of oil equivalent per day.
• MBbls/d: Thousand barrels of oil per day.

Full Conference Call Transcript

Operator: Good morning, and welcome to Permian Resources conference call to discuss its second 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 now turn the call over to Hays Mabry, Permian Resources Vice President of Investor Relations, for some opening remarks. Please go ahead.

Hays Mabry: Thanks, Eldi, 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. Q2 is a standout quarter for Permian Resources. We delivered record free cash flow of $751 million, an increase of almost 50% quarter-over-quarter and record free cash flow per share of $0.88. These results reflect our team's ability to respond quickly and decisively to a volatile commodity environment. Our activities this quarter are a reminder of the uniqueness of PR's business model. We can respond quickly to market conditions. We have a differentiated approach to sourcing and executing acquisitions, and we are relentlessly improving the capital efficiency of our business on a go-forward basis.

All of these characteristics support the goal we are all aligned on, increasing free cash flow per share over the long term to create shareholder value. Turning to the quarter. Oil production came in at approximately 198,000 barrels per day, up 3% quarter-over-quarter. Slide 4 shows the key drivers that drove that oil production growth. When oil prices moved higher, our team in the field responded immediately. We increased the number of workover rigs by 50%, which improved run times and quickly accelerated incremental barrels. At the same time, our successful ground game drove working interest in completed wells to approximately 82% for the quarter, up materially from our original expectations of 75%.

Combined with strong well performance, these actions generated 6,000 barrels per day of oil growth quarter-over-quarter for cash capital expenditures of $521 million. One thing I'd highlight is our continued success in increasing working interest ahead of development. This has always been part of the PR playbook, but our BD and land team have executed at an exceptionally high level this year. We view these acquisitions as some of the highest rate of return deals that we do, given that their near-term impact as evidenced from our higher working interest not only in Q2, but also for the remainder of the year.

Incremental workovers and ground game transactions are exactly the types of investments we want to make in a volatile market. Both generate incremental oil production and cash flow almost immediately, allowing us to recycle capital quickly and derisk returns through shorter payback periods. Turning to natural gas. Our team demonstrated their relentless focus on maximizing free cash flow as they navigated a severely depressed WAHA market during the quarter. As many of you are aware, WAHA natural gas prices averaged negative $3.14 per Mcf during Q2 and traded as low as negative $9.52 per Mcf.

So rather than selling natural gas at negative prices, we proactively curtailed production on high-GOR wells with WAHA exposure, reducing natural gas production by approximately 20% quarter-over-quarter. The curtailments, combined with our firm transportation and hedging, allowed us to realize a natural gas price of $0.38 per Mcf for the quarter and an uplift of over $75 million of revenue on our natural gas sales. When WAHA pricing improved in late June, we returned all previously curtailed wells to production without any operational issues. I want to give a big shout out to the field team for putting in the hard work to make this possible during the quarter.

On the D&C side, we offset inflationary pressures from rising diesel prices with continued operational efficiency gains through longer laterals, increased water recycling, deployment of water-based mud and new wellbore designs. We've also begun surfactant trials on completion and production operations. We're still early in evaluating surfactants, but we're encouraged by the initial results. Between continued operational efficiency gains and the potential to improve recoveries, there are a lot of ways for us to continue our path of increasing capital efficiency. As you can see from today's results, the quality of our assets, combined with our basin-leading cost structure, has driven a step change improvement to our business over the last several years.

As a result, we achieved record free cash flow in Q2 of $751 million. This is more than we generated in all of 2023, and we expect full year '26 free cash flow to be nearly double what we generated in 2024. And with that, I'll turn it over to James.

James Walter: Thanks, Will. Before we start talking about what's been a great start to our 2026 BD effort, we want to discuss how Permian Resources approaches acquisitions and how that fits with our value creation story. When we founded Colgate in 2015, we moved to Midland with exactly 0 acres, 0 production and Will and I were sharing a single 200-square-foot office. Our goal at the beginning was to buy high-quality assets, operate them efficiently and underwrite them conservatively so that our invested capital would generate real cash-on-cash unlevered equity returns. And from those humble beginnings, we grew Colgate from an idea to the business it is today with over 500,000 net acres and over 200,000 barrels of oil per day.

But our focus was never to build a large-scale business as Permian Resources now, but rather to maximize the return of every dollar we invested in the business. So how do we get here? Because we've honored the same strategy and philosophy in how we underwrite and how we operate, we're working relentlessly to find deals that meet our very high underwriting standards and targeted full cycle returns. And we use that time and time again, small deals add up, you create value for shareholders, and the business naturally gets bigger. With that, I'm excited to talk about what we've done in 2026 to date.

Starting with the largest deal on Slide 8, we closed on an acquisition of approximately 2,000 net acres and 5,000 Boe a day in Ward County for $520 million. This acreage directly offsets our existing asset base is 100% held by production, and provides an extended runway of high-return inventory. Shortly after we closed on the Ward County asset in July, we signed a trade agreement with an offset operator, utilizing a combination of the recently acquired bolt-on acreage, the legacy PR acreage and some other acreage that we have. This acreage helps address some of the challenges with the stand-alone Ward County acquisition, namely, being majority non-operated, low working interest and somewhat scattered.

The trade also increases the number of operating net locations from 50 to 120, while increasing the average lateral length by 20%. We view this trade as a true win-win for PR and our counterparty, who is a valued industry partners as it helps them to further core up their acreage position and increase their working interest in their own operated units. We expect the trade to close during Q3. Finally, the Parkway bolt-on project in Eddy County is a great example of how our proprietary data and Midland relationships create opportunities others simply do not see.

Following the success of a delineation well we drilled in late 2025, we quietly assembled a contiguous position of approximately 15,000 net acres with 2-mile lateral lengths and an 82.5% 8/8ths NRI. Our partner in this deal, Tascosa Energy Partners actually brought this deal to us over drinks in Midland. We've been fortunate to know this team for a long time and bought a big deal from them a couple of years back. But I think more importantly, this deal is a scaled example of the Midland-born deals that we do with our friends and partners on a regular basis, and that we think provides a real competitive advantage to Permian Resources.

In total, year-to-date, we've acquired approximately 55,000 net acres in the core of the Delaware Basin for a total consideration of approximately $1.05 billion, executed through roughly 190 separate transactions. These acquisitions added approximately 330 high confidence, high NRI locations that immediately compete for capital in our portfolio. Ultimately, we think the valuation metrics for the deals we have done so far this year speak to the strength of our approach. $13,000 per net acre, $8,000 per net royalty acre and $2.5 million per net location. Slide 11 summarizes why we believe our acquisition strategy is truly differentiated. Our focus is on buying high-quality assets, pursuing accretive transactions where PR has a commercial technical or operational advantage.

We continuously hunt for off-market deals and look for areas where we have distinct advantages or can create an edge that allows PR to underwrite higher full cycle returns. The edge can come from our leading cost structure, proprietary service information or simply access to a deal that isn't widely marketed. While this is not easy and requires a ton of work, we pride ourselves on being creative and not afraid to lean into harder, less obvious deals. We are confident we'll be able to continue this successful track record for years to come.

Our financial discipline allows us to execute meaningful transactions like we have announced today, while retaining a fortress balance sheet, with Q2 leverage of approximately 0.5x and expected year-end leverage of approximately 0.5x. All of this leads us to our updated and improved plan for 2026. As Will mentioned in his prepared remarks, the success of our ground game has allowed us to significantly increase our working interest for full year 2026. This will allow us to meaningfully grow production while maintaining the same completion crews, rig count and operating efficiencies we have achieved this year.

Our updated production guidance of 199,000 barrels of oil a day for the full year 2026 is 10% higher than 2025, while our CapEx midpoint of $1.95 billion is approximately 1% lower than the capital we spent last year. This all highlights the strides that our team is making to continue to improve the capital efficiency of our business and to grow free cash flow per share every year. Concluding with Slide 14, our focus on full cycle returns has allowed the company to generate outsized value creation for our investors. $1 invested in Colgate in 2015 would be worth nearly $50 today, representing a greater than 50% compounded annual return.

And we've continued that same philosophy and performance at scale with Permian Resources, nearly tripling our total shareholder returns since formation in 2022. Most importantly, our business model has not changed. We are confident in the combination of our high-quality asset base, peer-leading cost structure and differentiated approach to acquisitions will continue our track record of long-term value creation. We live in an industry that in some ways has been defined by consolidation and scale, but we'd like to be defined by prudent investment of capital, free cash flow per share growth and ultimately leading total shareholder returns for our investors. Thank you for tuning in today, and now we'll turn it back to the operator for Q&A.

Operator: [Operator Instructions] Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold: Obviously, the ground game M&A has been a staple of you all for the last number of years. And it looks like you had a pretty successful run here in the last couple of months. Can you give us a sense of what you see moving forward on the M&A landscape? And also how do you kind of compare and contrast the activity you've been doing versus looking at some of the larger packages that are a little bit more, I guess, competitive like the federal lease sale or marketed deals?

James Walter: Yes. Thanks, Scott. I mean, I think on the ground game side, I think that's an effort that's been kind of building and consistent for the whole 11 years we've been running this business. We've got pretty much the same team, the same people that are kind of operating at an extremely high level. So I mean that may ebb and flow a little bit from quarter-to-quarter, but I think over years, we are really confident we can continue to kind of execute and grow that part of our business.

I think the opportunity set in front of us looks as good as it ever has, and we're kind of excited and confident that we can continue that, but it may not be the same every single quarter, but we really do believe in the kind of long-term viability of that part of our business. In terms of larger packages, look, we've always -- we kind of look at everything in the Delaware. I think you should assume we are kind of in the mix and evaluating any package of quality that is out there on the publicly marketed side.

I think what we've seen in some of these deals and some of these federal lease sales or state lease sales is that, they're good assets. I mean the kind of -- there's been some really good stuff that transacted this year, but I think our focus on full cycle returns and generating outsized equity returns for investors, I think, has us being really disciplined on purchase price. And I think kind of -- are some of those assets that transacted assets we'd like to own? Absolutely. But we're we able to get to those purchase prices and still achieve our targeted returns? The answer is no.

So I think for us, it's all about focusing on kind of full cycle and long-term value creation. And if there's bigger packages that meet those return thresholds and standards, then we'll be excited to do them and not -- and we'll continue to be patient.

Scott Hanold: Got it. And my follow-up question is more kind of Permian, I guess, macro related. Certainly, with new egress coming on for pipelines. You're seeing probably a next surge of gas coming, including your production was offline. But like how do you see activity pace from a lot of kind of offset operators, any kind of non-operated activity with improved egress? And do you expect a surge of production? And I'm just kind of curious on oil takeaway capacity, if you think that becomes a constraint in the next couple of years or so.

William Hickey: Go ahead.

James Walter: I'd say kind of hitting the last part first, we feel really good about oil takeaway capacity for the next few years. I think I'm kind of -- we're also hopeful that we've all learned a good lesson on kind of the gas situation we've been in the past 12 months that you got to get out there years ahead. We're fortunate on the oil side, we've got a lot of capacity today and expect that to be the case. We continue to grow for years to come in the Permian, which I think is not guaranteed, but certainly possible.

I'd say at this point, we're confident our midstream partners will be working with people like us to kind of get further ahead of that. And on the gas side, we haven't seen any meaningful reaction kind of from an activity level. I think it seems like the pipelines that are coming online this quarter we're able to handle the new gas that we brought back online, kind of any incremental growth today. And I think we're hopeful that we're entering a new era in WAHA gas where you get past this period of dislocations, and we have pipeline capacity that's now going to be able to keep up with Permian growth.

So I'd certainly say the environment and the attitude has changed. I think there's a new eagerness and desire to build pipelines coming out of the basin. And people do believe this basin is going to grow its gas volumes for a long time. And there's a lot of exciting downstream demand things. So I think we feel a lot better about kind of both crude and gas than we have gas in the last few months.

Operator: Your next question is from the line of Neal Dingmann with William Blair.

Neal Dingmann: James, maybe staying on the same vein, my first question just around M&A specifically. Is it fair to say that the Parkway bolt-on suggests you all continue to have more confidence as you move northwest to Eddy County? And just wondering either there or again, further into Lea, would you all continue consider moving just further north in New Mexico overall?

James Walter: Yes. I mean I think that kind of Eddy County area where this Parkway bolt-ons has been -- that's been a tremendous asset for Permian Resources since we bought our first deal there back in summer of 2016. And I think, we've seen it continue to work as you push modestly west and modestly north. I'd say we've been surprised by how strong the well performance is, for example, in the kind of area that you're referencing today. And I think we see a lot of white space. I also think the white space maybe moving north and maybe moving west, but there's also still a lot to do kind of in and amongst our existing position.

There's a lot of white space on the map between our existing assets. And I think I'd say, honestly, most of the bolt-on activity, that's active now is more kind of in between the yellow on the map, if you will. But we still see a lot to do in what we call the Parkway area of Eddy County and are certainly excited about the well results we've seen and excited about what we think could be coming.

Neal Dingmann: Perfect. And then my follow-up just on capital allocation, maybe for you or Guy or Will. Just specifically, we've seen at least a couple of your peers, if not more, now recently boost activity, I guess, in the last few months. Do you all believe production growth in this environment is appropriate given the commodity backdrop and maybe if not, is the plan just to keep building cash?

James Walter: Look, we don't like to forecast our plan for next year or anything like that. I'd say with regards to 2026 and what oil prices did kind of at the beginning of this year. I think we were strong believers that this was an environment where it made sense to invest a little more capital and grow production more than the kind of flattish expectations we had coming into the year. Like Will has talked about in his prepared remarks, we're proud of team, how quickly we could respond, and how quickly we could bring those barrels. As far as growth from here or growth next year, I think that's just really going to depend on the returns environment.

We've always talked about growth in the returns-driven framework, and we have high oil prices, low service costs, like you'll probably see us in growth mode. And inversely, if we have lower oil prices and higher service costs, I think you'll see us back to maintenance mode. So I think it's just going to depend on kind of how the macro settles out. I think today, it's probably too early to tell what next year looks like, but we'll keep watching it and we've proven we can react quickly when the time comes.

Operator: Your next question is from Neil Mehta with Goldman Sachs.

Neil Mehta: Yes. Just continued operational momentum as we think about your production. And so James, I'm wondering if you can talk a little bit about some of the things that you're deploying out in the field to stay ahead of the expectations operationally.

William Hickey: Yes. I mentioned a few in the prepared remarks, I'd say one that I feel like I hit on every quarter, which is really, really important to the kind of both the production and the completion cost of the business is water recycling. And so we had another tick up on percent water recycled in Q2. I think it's the highest quarter we've had in PR history. So we are continuing to make progress on kind of incremental water recycling. We've got a great relationship with a big water company in New Mexico. And as they continue to build out an integrated system, I'd say we are a big beneficiary of that.

And then on the drilling side, which is I think if you think back to kind of my Q1 comments where I thought there was some low-hanging fruit or maybe not low anymore, but kind of the next level of step-up would be on the drilling side. And we're making a few changes there. I'd say, one, we started to introduce water-based mud in areas where we take losses typically and with oil at high prices, I'd say the payback on taking a little bit of a loss of water-based is pretty meaningful, kind of, call it, $5, $6, $7 a foot of savings on those wells.

And then the last one would be, we've kind of transitioned to a slimmer hole design in New Mexico. Same long stream still run 5.5-inch all the way back to surface, but running it inside 8 5/8s instead of 9 5/8s. And that savings in steel, especially as casing prices are projected to run up in the back half of the year, savings in time, just smaller holes drilled faster and then savings in cement. So I think that kind of if you think about looking forward, obviously, we are willing to take the increased diesel prices with the increased oil revenue, but we do have some inflationary pressures with respect to diesel and casing.

And to date, have been able to offset that through gains like what I just talked through.

Neil Mehta: That's helpful. And then just your perspective on lateral lengths, too. I mean I would imagine with these bolt-ons, you'll be able to extend these laterals through -- given you're able to block up the acreage a little bit more. But give us a sense as you think about the portfolio, how long you can get these laterals to? And what does that mean from a P&L perspective?

William Hickey: Yes. I mean lateral length is the most effective way to reduce D&C per foot, I think we've slightly ticked up every year for the last 2 or 3 years, kind of moving from just under 2 miles to now kind of right at 11,000 feet. We mentioned in the deck that we drilled our first 4-mile lateral in Q2, and that was a big success. So I think what it really means is the combination of our willingness to drill longer our ability to drill U-turns when needed and the blockiness of the position that you'll continue to see lateral length tick up over time.

I don't think that we are in a place where you're going to see some like step change where we go from 11,000 to 15,000 year-over-year, but I do think the kind of 500 plus or minus feet longer each year is probably typical of what you should expect going forward.

Operator: Your next question is from John Freeman with Raymond James.

John Freeman: In the slide deck, you sort of show the capital allocation strategy and at least the first half of the year, it's been pretty skewed to these really nice accretive acquisitions along with debt repayment. You've got leverage now at the bottom end of sort of your kind of leverage target range. So just sort of thinking, I guess, going forward, if there's any sort of maybe change in the way you all think about your cash priorities across kind of acquisitions, balance sheet, buybacks, maybe even growing the dividend?

James Walter: Yes. I mean I think growing the base dividend consistently over time is a priority and always has been a priority. So I think that's something you'll continue to see for us kind of in the future. I'd say other than that, we don't have any plans to change our capital allocation program. I think we have is working really well today. Obviously, the business is generating a lot of cash. We've been able to both pay down considerable amounts of debt over the past 2 years and do a lot of acquisition activity, all while delevering the business to the 0.5x it is today.

So I think now for the foreseeable future, I think our capital allocation strategy is working, and you'll kind of see us hold the course.

John Freeman: Okay. And then on the back of all the accretive acquisitions, obviously, most of these have been just the perfect deal where you're just increasing working interest and field you're already there, but there are some examples of you all doing some transactions continuing to push the boundaries further out on your acreage footprint. Does that necessitate any sort of infrastructure investments that we should be thinking about in the upcoming years?

James Walter: No. I mean, nothing outside of what's already baked in our plan and our budget for the year. I think these areas that we're kind of more active in are still right next to existing PR offset operations today. So I think it probably is pretty easy. We've got the right partners where we need on the midstream side. And frankly, kind of all the stuff we're doing really is 1 mile or 2 away from the existing PR ops. So kind of nothing out of the ordinary there.

William Hickey: I think the only exception that would be the Ward County bolt-on, there'll be a minimal, call it, like $25 million of incremental CapEx associated with just taking over a new asset.

Operator: Your next question is from the line of Kevin MacCurdy with Pickering Energy Partners.

Kevin MacCurdy: I guess for the first one, can you guys bridge the old production guidance to the new production guidance and did the same thing on CapEx, maybe breaking out the contribution from the higher working interest, the production you bought and then any pull forward or outperformance?

Guy Oliphint: Kevin, it's Guy. On production side, we were at 192,500 barrels a day at Q1, our guidance after Q1 are at 199,000 today. The only production we acquired with this $1 billion of acquisitions was 2,500 barrels a day of production at the time we closed the Ward County bolt-on a week ago. When you take that over a year, that's 1,000 barrels of the 6,500 barrels a day increase. The significant majority of the remainder is just higher working interest in our 2026 projects, as we talked about, with a little bit of contribution from accelerated workovers.

On the capital side, we're up $100 million, $25 million of that is just kind of some of the takeover costs associated with the Ward County bolt-on just putting in equipment that's our standard and things like that. And the remainder is also just higher working interest in the '26 TILs. We took our guidance from 75% to 80% to over 80% working interest in 2026 TILs. So I think when you put all that together, it's really capital efficient. And you can see that in the kind of increase in capital relative to the increase in production.

Kevin MacCurdy: I appreciate that detail, Guy. And then maybe for the follow-up, is your gas production back online now that WAHA prices are better? And can you give us any kind of sense of the cash flow uplift you're seeing for the back half of the year just from better gas prices?

William Hickey: All the wells are back online. We brought them online kind of at the very end of June, right when WAHA rebounded, and we've had all the wells online since. So Q3 and Q4 will be much more normal looking with respect to gas.

Guy Oliphint: And Kevin, on cash flow uplift, I think we're probably hesitant to forecast gas prices in the back half. But we produce over 750 million a day net. So regardless of where we end up, given where WAHA is today, $1.50, $2 in HSC and [indiscernible]. It will contribute in the back half of '26. And that's why we put the commentary in there about '27 as we think about growing free cash flow over time. We've done that with the real headwind of realizing almost nothing from our dry gas stream. And I think both the curves and our transportation in '27 set us up for a much better answer year-over-year.

Kevin MacCurdy: Great. I appreciate that. And totally understandable, you wouldn't want to predict gas prices in this market.

Operator: Your next question is from the line of John Abbott with Wolfe Research.

John Abbott: So a question is really on CapEx and recognizing that you don't want to give -- talk too much about 2027. But for 2026 from the increased working interest and also from some carryover from Ward, you've increased full year guidance by about $100 million on the midpoint. If you kind of annualize that as maybe it's $200 million, is that a reasonable step-up as one sort of thinks about 2027, if you were going to maintain flat production, or are there other factors that need to be taken into account as you sort of think about the CapEx next year?

William Hickey: I mean I think one thing just to correct is the majority of that $100 million increase happened in Q2. And so I don't think you can double it to annualize it. I think that is the annualized increase. If you want to think about this year, we came into it, we were going to spend $1.85 billion and grow production minimal. And now we're going to spend $1.95 billion and grow production by 10,000 barrels a day. So it is a very meaningful kind of increased production and that $100 million is annualized. I think if you look going forward, I guess if the question is, where is maintenance CapEx.

I think if we continue to spend at, call it, the $1.95 billion to $2 billion range, we will continue to grow production. So maintenance is south of there. And that's a growth case. And I think where we stand in '27 between do we want to grow, or do we want to be in a maintenance cases, obviously, very much subject to what the markets look like when we get there.

James Walter: But I mean like that $1.95 billion grew production 10%. I think that's a pretty substantial growth rate. And like I'd say as we think about it, that's highly capital efficient. So I'd say if you think about our business today, that's 17,000 barrels per day year-over-year growth and 10%. So I think that's a pretty cool capital efficiency story.

John Abbott: Extremely helpful. And then just you had the step-up in activity on the workover activity in 2Q. How does this workover activity sort of trend for the remainder of the year?

William Hickey: It will normalize. The step-up in Q2 basically chewed through our entire backlog of workovers. So we are back at normal course just kind of fixing wells as they come offline, and that will be with a rig cadence that's more like what we've done in Q1 in the past.

Operator: Your next question is from Phillip Jungwirth with BMO Capital Markets.

Phillip Jungwirth: Can you provide some background information just on what you did here in Ward County with the bolt-on and subsequent acreage swap? I mean it looks like you executed acreage trades between 2 or more parties that gave you a larger operated position. Just wondering if there's similar opportunities where you have large operators with legacy checkerboard acreage positions and just how much of a discount you typically see for non-op acreage?

James Walter: Yes, sure. No, that was a really cool deal. I think kind of a lot of things came together kind of our team, great collaboration with, as you mentioned, multiple counterparties on the kind of the trades in the Ward County bolt-on, and yes, I think we love it when you can find opportunities like that, that are win-wins and make your position better. I think actually, it's an interesting question. I'd say, honestly, this year, we haven't talked a lot about it. And maybe we should in our next release, but this has been a really busy year for us on the trade front.

I think we're finding more opportunities to kind of net up our own working interest, trade out of non-op and into operated positions, like you see here. So yes, I don't know if we'll see any that are kind of as big as this in the back half of the year, but we've certainly done some big ones to start the year, and it's something that we're always working on.

Phillip Jungwirth: Okay. Great. And then can you talk about some of the productivity initiatives such as surfactants, completion design changes? Just how many wells you're looking to deploy surfactants on this year? And you mentioned you're encouraged by early time results. Just any color here or expectations for incremental costs?

William Hickey: Sure. On the completion side, we've pumped 2 surfactant trials on 2 different pads with kind of test -- or control wells and test wells. One of those is online. One is we've pumped the fracs, but the wells are not yet online. That's probably where we'll stop for this year. We'll look at that data kind of see what we see early time with water-to-oil ratios and see what we see kind of over the 60-, 90- and 180-day period as we kind of head into next year should be in a good place to have a feel for how big of the program that could be. I'd say on that side, it's just too early to tell.

And then on the production side, there's 2 or 3 pads across both basins that we have pumped kind of surfactant more in late life kind of typically around an ESP failure and have seen, I'd say, uplifts up to north of 100 barrels a day and some that are kind of de minimis. On the average, that program has been very economic, kind of, call it, sub 1-year payouts on the aggregate, inclusive of the wells that we saw basically no uplift. So that's where we're very encouraged is that even with the dispersion of results from really, really effective to less effective that the program on average has been very economic.

And so I'd say what the team is working on now is how do we do more of the 100-barrel a day uplift and less of the 0, or what could we do differently on the wells that we didn't see an uplift? But I think that's going to be something that probably is a real part of the program to go forward. It's just kind of -- we got to figure out exactly how much and exactly where we're going to do it before we can kind of roll it out as part of the go-forward plan.

Operator: Your next question is from Oliver Huang with TPH Research.

Hsu-Lei Huang: Just kind of looking at what you all picked up on the New Mexico side. I think one of the things that goes overlooked sometimes is just how this is fairly virgin rock, you're picking up. You all referenced the Tascosa well in the Northwest Parkway area being a bit more of a step out. Are you all 100% confident at this point with carrying out your development program there? Or are you going to need to do a bit more basal work up there to feel comfortable with the entirety of that block?

James Walter: Yes, that's a good question. I think we're really comfortable in the primary zones. I actually think that's a great kind of nuanced question that we didn't address in our script. Like I'd say, our base case underwriting kind of the deals that the locations that we actually paid for, we are highly confident. And I do think as you get to some upside zones potential, I think whether that's 2 or 3 productive zones or 4 or 5 productive zones is still TBD. So I do think we'll continue to learn about the Parkway area and that kind of Tascosa acquisition specifically over time.

But have a really high degree of confidence in what we're calling kind of proven locations that kind of go into that 330 locations that were underwritten. And I think over time, hopeful and would expect to see some of those upside locations kind of proven up and coming into the money.

Hsu-Lei Huang: Okay. Perfect. And maybe just for a follow-up, just on the op side. Could you maybe provide a bit more detail in terms of just -- I mean, you all call out wellbore design improvement, which Will spoke to earlier, but just optimization of the power supply compression fleet as well. Just how much of that is already flowing through the financials today, and how much more running room do you see on both of those fronts.

William Hickey: Well, I think that there's a decent amount flowing through the financials today. I mean we've run at this point, 7 or 8 microgrids across New Mexico and areas where we historically have been on generator power. If you want to think about run room of that going forward, like there's definitely more to do, but it's really going to be New Mexico-centric as we are on line power in the Texas, Delaware.

Same thing on the compression side, like as we're optimizing that, it's going to be in areas where -- what we've seen is where we have -- we end up with better run times across the board if we're on microgrid as opposed to kind of one-off generators, just think about flipping the light switch like cycling it on and off is not good for run time of equipment like ESPs and things like that. But really, all of this just kind of comes together to, I think we've seen a tremendous ability for us to kind of hold LOE flat or even reduce it over time, which is not, I think, not normal and not what you'd expect.

I mean we kind of -- I feel like we've always been at $5.50 a Boe LOE company. And if you look at where we were in Q1 and even where we were in Q2 with a meaningful amount of our Boe shut in due to gas curtailment, we're still kind of pushing closer to $5 per Boe. And I think that's a testament to what we've done in the short term. And there is still stuff to do. I feel like beating a dead horse, but the water recycling side is a big needle mover on water disposal is our largest LOE cost.

And the more we can recycle the more we defer and ultimately save on the LOE side. So those are the initiatives that we're working on real time. I think all of them matter, but if you can do them all together, that's when you really move the needle.

Operator: Your next question is from Josh Silverstein with UBS.

Joshua Silverstein: Just want to see if we can get a bit more detail on the royalty acquisitions versus the leasehold acquisitions here. Were these done in separate transactions done together where you have both the leasehold and the royalty? And I guess maybe along the same lines, like we typically think of the royalty value was a bit higher, you guys are having a lower price paid for the royalty acreage versus the leasehold. So just a little bit more detail there would be great.

James Walter: Yes. I mean, I think kind of -- I'd say the royalties historically and in this first half of the year come as a mix of kind of straight minerals and royalties acquisitions versus kind of high NRI leasehold. I'd say for us, it's tended to be more weighted towards kind of higher NRI leasehold. I think the minerals and royalties on a stand-alone basis can get really expensive. And frankly, we struggled to always -- to be able to buy very much at kind of our return thresholds. But yes, I think -- going forward, I think we will continue to target both.

I think it's probably safe to expect more of our royalty acquisitions to come paired with leasehold because I think we can bring kind of the full suite of PR competitive advantages to bear on the cost-bearing interest combined with the royalty. In terms of prices, look, I think what you're seeing on low dollar per net royalty acre values, it's just kind of the output of us acquiring these deals at attractive prices. Like I think we talked a lot about the creative things that we've done. And those creative things allow us to buy both, I'd say, the leasehold and the royalty interest at what we view as really attractive and you may view as lower prices.

But I think that's a really good thing, and it's something we're hopeful to continue to be able to do.

Joshua Silverstein: Yes. Thanks for that detail here. And then maybe just along the same lines, I was curious to see if there's any shift in development plans given the leasehold and royalty acreage that you've acquired? Do you now have a bit more capital going towards the Texas assets? Do you still favor New Mexico? And I'm guessing, the goal is to try to keep your working interest now at higher and higher levels. So any update there would be great.

William Hickey: I think it's about -- it's going to be basically the exact same as it's always been. It will be, call it, 70% of the development, maybe a little north of that on the New Mexico assets and the rest in Texas, and that's consistent with where we've been the last 2 or 3 years.

Operator: Your next question is from the line of Gabe Daoud with Truist.

Gabe Daoud: I know it's hard to kind of nail down these opportunities. But I was curious, guys, if you could maybe frame what the spend on land could be the rest of the year? You've done $1 billion or so year-to-date. Just curious if you maybe have any kind of framework around additional spend from here?

James Walter: I think the answer is no, we don't. We kind of -- we're always looking. We're always on the hunt and we're going to continue to buy things and we can find high-quality assets at prices that make sense for generating attractive full cycle returns. But now, I think, we've got good momentum. I think we're kind of the ground game continues to chug along, and we're having a lot of success there. But I think in terms of trying to predict exactly what it looks like over the kind of next 12 months, I think that's hard to do.

Gabe Daoud: Okay. Okay. Understood. No, that's fair. And then I guess just a quick follow-up for me, you talked about the surfactants and productivity, potentially improving from here. Just curious, maybe can you quantify or talk about what else you're doing on the productivity side, and if we should expect -- still expect flat productivity from PR year-over-year, particularly with all the new assets?

William Hickey: I'd say like, look, there's a long list of things we're doing. The hot topic today is surfactants. And if you want to think back 6 months ago, it was on lightweight proppant. And in the middle, there's been a bunch of tweaks of cluster spacing, completion design strategies, et cetera. I think the right kind of approach that you all should think about PR is that we are testing, trialing and studying all of it, and we'll probably -- I think we're better suited to speak to exactly which ones are the big winners kind of once we get there.

But really what it means for well productivity, I'd say not driven by step changes in oil recovery percentages, but really just by the duration and depth of the inventory, I think your expectation is the '27 or rest of '26 and '27 productivity will be the same as it's been in '24, '25, '26. We are still kind of marching across our position in both New Mexico and Texas drilling the same benches in the same way and expect the same productivity as we've seen in the past.

Operator: Your next question is from the line of Leo Mariani with ROTH.

Leo Mariani: I was hoping if you can provide a little bit more detail on kind of where cost per foot may be headed here. In the second half, you mentioned some inflationary pressures. I think in some of your prepared materials. You kind of said well cost per foot are pretty flat in 2Q versus 1Q. Do you expect those to go up at all with inflation in the second half? Do you think efficiencies can basically counteract all that? And I think you had talked about a $675 per foot target at one point. I just want to get a sense of are we there at this point? Or is that something you're hoping to get to later this year?

William Hickey: Yes, I'd say obviously, the run-up in crude and kind of demand on steel, et cetera, associated with the war has put some pressure on where we were targeting for the year. But we've done a really, really good job offsetting that. I mentioned some of the efficiencies we've picked up on the drilling side, on the water recycling side. We've had got some small wins on the sand side. So it's not all inflationary pressures. We've had some kind of big wins on the efficiency side to get here to date. I think a lot of that shows up just with the incremental.

Now we're just north of 80% working interest in the back half of the year, and we're still able to keep CapEx sub $1 billion kind of speaks to -- are we going to achieve $675? I'd say that feels like a longer putt than it was when we came into the year, but we're still very much on target as far as where we came into the year at and at least holding the line flat or maybe slightly improving.

So it's really a hard answer to give, Leo, just given like fuel is such a big component of our of our spending, and I just have no idea where fuel and crude prices are going to be between now and year-end. But I think that if oil prices dip and fuel resets back to where we came into the year, I think $675 is absolutely in our sights. And if oil runs, I think it's probably less likely, but we'll take it on the revenue side.

Leo Mariani: Right. Okay. Makes sense. I know it's really difficult to forecast your success on the M&A front, but maybe you can just talk about the deal pipeline? Is it sounds like it's very robust right now. Certainly, you executed a lot of deals in the first half. Is the deal pipeline just as robust today as it was in the past handful of months. So are you getting a lot of looks here.

James Walter: Yes. I mean I'd say just kind of we've spent $1 billion in the last 2 years, kind of '24 full year and '25 full year. We've kind of already achieved that same pace halfway through or a little over halfway through 2026, I think it's probably safe to say we will exceed the last 2 years average this year. But yes, the ground game, we're seeing a lot of stuff. I think that, like we've said in the past, that's pretty consistent kind of every month in, every month out, we're finding opportunities on the ground game side, and the bigger stuff can be lumpier. But I'd say we're getting a lot of looks.

I think we'll reference like there are a ton of deals kind of coming to market at the beginning of the year. I think we've seen maybe half of those kind of run their course and there's still some out there that could be interesting. But I think for us, definitely nothing big, imminent to kind of -- there's some ground game stuff that's always getting done day in, day out. But for us, it's just taking it as it comes and making sure we do the right opportunities at the right price and pass on the deals that don't make sense for us, and we've done a really good job of that.

So we've got a ton of confidence it will keep working going forward.

Operator: Your next question is from Paul Diamond with Citi.

Paul Diamond: So we've seen a lot of discussion about emerging benches across the Midland and Delaware. I guess, how do you guys see that developing on your footprint? And I guess any update from the last time we spoke about it?

William Hickey: Last time we spoke about this, I'd say, I mentioned kind of the success of the Avalon and kind of some of the deeper Wolfcamps moving north in Lea County. And I'd say that is happening and happening extremely well and very quickly, so to speak. I mean our -- we had drilled a few Avalon up that far north as of the call last quarter. But I'd say since then like full development, stacking Avalon, it's been some of the most productive wells we've drilled.

So those types of emerging benches, think of it as benches that have been developed historically on the state line area moving up north into our Lea County and our Eddy County position is very much happening. We're seeing the same thing on our Eddy County position with something like the deeper Wolfcamp. Typically, we've drilled first sand, second sand, third sand and X, Y on the North Eddy, and we're starting to see deeper Wolfcamp move in that direction. As far as like the total new benches, which are where I think you were alluding Woodford, Brushy, things like that. We own it on some of our assets, and other assets, we don't.

But I'd say it's something that we're keeping our eye on, but it's not a core bench. It's not something that's going to be a big part of our development plan or really any part of our development plan in '27. I think that it is -- we've seen some of the most prolific wells in the basin drilled in the Woodford and some of the biggest dogs. And so we're just kind of going to watch and see and hopefully let serendipity kind of come our way to the extent it does.

Paul Diamond: Got it. Understood. And then I guess, over the course of like the last year or so, you guys have worked pretty diligently to kind of rightsize the realization expectations around nat gas. Are you guys happy at the current level on a go-forward basis? Or should we expect a bit more movements in kind of those, whether it's FT or hedging or just kind of how you think about locking that, what is this, the volatile pricing down?

Guy Oliphint: Paul, it's Guy. I think we feel great about the deals we did. We identified this as an issue a couple of years ago. And I think the -- not just the long haul that we are kicking in kind of late this year and early next year, but the interim agreements we had with some of those partners this year have served us really well. And I think the capacity we have going into '27 covers roughly all of our net volume. So we're always thinking about what else should we do to optimize the portfolio, how do we handle growth in gas volumes that could occur as we continue to grow oil production and grow through acquisition.

And I think on the hedging front, we're just going to be opportunistic like we have. I think that we spend a lot of time thinking about appropriate basis and where we want to sell gas, but I view that more as optimization rather than something we have to do.

Operator: Your next question is from the line of Sean Mitchell with Daniel Energy Partners.

Sean Mitchell: Will, you talked a little bit in the commentary about offsetting some rising costs by using water-based mud versus oil-based mud in the drilling, are you seeing anything in terms of drill time that is interesting? Or is it coming down with water-based versus oil-based?

William Hickey: No. I don't think water-based will be a time savings versus oil based. It's more just -- we've got some areas where you'll take some losses. And if you can run water-based instead of oil-based in areas you take losses, you save money really, really quick.

Sean Mitchell: Okay. So it's more on cost savings than drill time?

William Hickey: Yes, that's right. I mean our drill time wins have been in this slim-hole design. I mean, obviously, when you go to 8 5/8s intermediate as opposed to 9 5/8s, you can drill a smaller hole and kind of everything goes faster. So that's -- if you want to think about the savings associated with slim hole, it's been like 50% of the savings is on drill times. We save almost a day a well.

Operator: Your last question is from the line of John Annis with Texas Capital.

Hays Mabry: John, do you have your mute on? We can't hear you. Okay. Operator, I think we can hand it back.

Operator: We can close the question-and-answer session. Absolutely. There are no further questions at this time. So I will now turn the call back to James Walter for closing remarks. Please go ahead.

James Walter: Thank you. As you can tell from this morning's results, the business is performing at the highest level in PR's history. We delivered record free cash flow this quarter, responded quickly and decisively to a volatile commodity environment and add high-quality inventory at attractive valuations. All while maintaining an investment-grade balance sheet and the lowest cost structure in the Delaware Basin. We believe we are exceptionally well positioned to continue compounding free cash flow per share and delivering outsized returns for investors going forward. Thanks to everyone who joined the call today and for following the Permian Resources story.

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