Thanks, Elly, 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 risk and uncertainties that could affect our actual results and are discussed in more detail in our filings with the SEC. We may also refer to non-GAAP financial measures.

For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation. With that, I will turn the call over to Will Hickey, Co-CEO.

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 88 cents. 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 move 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 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 de-risk 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 -$3.14 per Mcf during Q2 and traded as low as -$9.52 per Mcf.

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 38 cents 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. With that, I'll turn it over to James.

Thanks, Will. Before we start talking about what's been a great start to our 2026 BD efforts, 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 zero acres, zero production, and Will and I 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.

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. Our focus was never to build the large-scale business that Permian Resources is now, but rather to maximize the return of every dollar we invested in the business.

How do we get here? Because we've honored the same strategy and philosophy in how we underwrite and how we operate, while working relentlessly to find deals that meet our very high underwriting standards and targeted full-cycle returns.

When you do 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 acres that we had. 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 operated net locations from 50 to 120, while increasing average lateral length by 20%. We view this trade as a true win-win for PR and our counterparty, who is a valued industry partner, 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 years back. 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 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 could come from our leading cost structure, proprietary subsurface 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 will 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 0.5 times and expected year-end leverage of approximately 0.5 times.

All 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 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.

A dollar invested in Colgate in 2015 would be worth nearly $50 today, representing a greater than 50% compounded annual return. We continue that same philosophy and performance at scale with Permian Resources, nearly tripling our total shareholder return since formation in 2022.

Most importantly, our business model has not changed. We are confident 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 will turn it back to the operator for Q&A.

Thanks. Good morning, all.

Obviously, the ground game M&A has been a staple of y'all for the last number of years, and it looks like you've had a pretty successful run here in the last couple months. Can you give us a sense of what you see moving forward on the M&A landscape and also, how do you kind 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?

Thanks, Scott. 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. 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. Look, 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 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 in some of these federal lease sales or state lease sales is that they're good assets. 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.

I think kind of, are some of those assets that transacted assets we'd like to own? Absolutely.

Were we able to get to those purchase prices and still achieve our targeted returns? The answer was no.

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

Got it. Thanks for that.

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 that was off-line.

How do you see activity pace from a lot of kind of offset operators, any kind of non-operated activity with improved egress? Do you expect a surge of production?

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.

Yeah.

Go ahead.

I think kind of hitting last point first, we feel really good about oil takeaway capacity for the next few years. I think 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 3 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. 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 are able to handle the new gas that we brought back online, kind of any incremental growth today. I think we're hopeful that we're entering a new era in Waha gas where we get past this period of dislocations and we have pipeline capacity that's now going to be able to keep up with Permian growth.

I 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, because I think people do believe this basin is going to grow with gas volumes for a long time.

There's a lot of exciting downstream demand things, I think we feel a lot better about kind of both crude and gas than we have gas the last few months.

Thank you.

Morning, guys. Thanks for the time.

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

I think that kind of Eddy County area where this Parkway bolt-on has been, that's been a tremendous asset for Permian Resources since we bought our first deal there back in summer of 2016. 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. I think we see a lot of white space.

I also think the white space may be 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'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.

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.

Perfect. 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?

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 talked about in his prepared remarks, we're proud of our 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 a returns-driven framework. If we have high oil prices, low service costs, you'll probably see us in growth mode.

Inversely, we have lower oil prices and higher service costs, I think you'll see us back to maintenance mode. 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.

Perfect. Thank you.

Thanks, Neal.

Thanks, guys. Just continued operational momentum as we think about your production.

James, Will, love you to talk a little bit about some of the things that you're deploying out in the field to stay ahead of expectations operational.

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.

We had another tick up on percent water recycled in Q2. I think it's the highest quarter we've had in PR history, 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. Then on the drilling side, which is, I think, if you think back to kind of my Q1 comments, were I thought there were some low-hanging fruit, or maybe not low anymore, but kind of the next level of a step-up would be on the drilling side.

We're making a few changes there. I'd say one, we've 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 loss of water-based is pretty meaningful, kind of call it $5, $6, $7 a foot of savings on those wells.

Then the last one would be we've kind of transitioned to a slimmer hole design in New Mexico. Same long string, still run 5 1/2-inch all the way back to surface, but running it inside 8 5/8 instead of 9 5/8.

That's 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 drill faster; and then savings in cement. 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.

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

That's helpful. Then just your perspective on lateral lengths, too?

I would imagine with these bolt-ons, you'll be able to extend these laterals 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. What does that mean from a P&L perspective?

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. 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 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.

Great, guys. Thank you so much.

Thank you.

Good morning. Thanks.

In the slide deck, y'all sort of showed the capital allocation strategy. 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 y'all's kind of leverage target range. Just sort of thinking, I guess, going forward if there's any sort of maybe change in the way y'all think about your cash priorities across kind of acquisitions, balance sheet, buybacks, maybe even growing the dividend?

I think growing the base dividend consistently over time is a priority and always has been a priority, 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 what 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 0.5 times it is today. I think now and for the foreseeable future, I think our capital allocation strategy is working, and you'll kind of see us hold the course.

Okay. Then on the back of all the accretive acquisitions, obviously, most of these have been just the perfect deal where you're just kind of increasing working interest in in-field geology there, but there are some examples of y'all doing some transactions kind of continuing to kind of push the kind of boundaries further out on y'all's kind of acreage footprint.

Does that necessitate any sort of infrastructure investments that we should be kind of thinking about in the upcoming years?

No, 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 operator operations today, 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 this stuff we're doing really is a mile or two away from existing PR ops. Kind of nothing out of the ordinary there.

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

Got it. Thanks, guys.

Hey, good morning, guys, and thanks for taking my question. I guess for the first one, can you guys bridge the old production guidance to the new production guidance, and do 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?

Hey Kevin, it's Guy. On production side, we were at 192,500 barrels a day at Q1, our guidance after Q1, and we're at 199 today.

The only production we acquired with this billion dollars 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 barrel 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 standards and things like that. The remainder is also just higher working interest in the '26 tills.

We ticked our guidance from 75 to 80% to over 80% working interest in 2026 tills. 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.

I appreciate that detail, Guy. Then maybe for the follow-up, is your gas production back online now that Waha prices are better?

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?

All the wells are back online. We brought them online kind of at the very end of June, right when Waha rebounded.

We've had all the wells online since, Q3 and Q4 will be much more normal-looking with respect to gas. Hey, and Kevin, on cash flow uplift, I think we're probably hesitant to forecast gas prices in the back half.

We produce over 700, 750 million a day net, regardless of where we end up, given where Waha is today, a buck 50, $2, and HSC and Texok higher, it'll contribute in 20- the back half of '26. 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. I think both the curves and our transportation in '27 set us up for a much better answer year-over-year.

Great, appreciate that, and totally understandable you wouldn't want to predict gas prices in this market.

Hey, good morning, and thank you for taking our questions. My question is really on CapEx and recognizing that you don't want to talk too much about 2027.

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 mil, 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 to account as you sort of think about CapEx next year?

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 and grow production minimal. Now we're going to spend 1.95 and grow production by 10,000 barrels a day, it is a very very meaningful kind of increased production.

That 100 is annualized. I think if you go forward, I guess if the question is where is maintenance CapEx, I think if we continue to spend, call it, the $1.95 to $2 billion range, we would continue to grow production.

Maintenance is south of there. 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 case is obviously very much subject to what the markets look like when we get there.

That $1.95 billion grew production 10%. I think that's a pretty substantial growth rate.

I'd say, as we think about the world, that's highly capital-efficient. I'd say if you think about our business today, that's 17,000 barrels per day year-over-year growth and 10%.

I think that's a pretty pretty cool capital efficiency story.

Extremely helpful. Then just you had the step-up in activity on the workover activity in 2Q.

How does workover activity sort of trend for the remainder of the year?

It'll normalize. The step-up in Q2 basically chewed through our entire backlog of workovers, we are back at normal course, just kind of fixing wells as they come offline.

That'll be with a rig cadence that's more like what we've done in Q1 in the past.

Appreciate it. Thank you very much for taking our questions.

Thank you.

Thanks. Good morning.

Can you provide some background information just on what you did here in Ward County with the bolt-on and subsequent acreage swap? It looks like you executed acreage trades between two 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.

Sure. I know that was a really cool deal.

I think kind of a lot of things came together: kind of our team, great cooperation with, as you mentioned, multiple counterparties on kind of the trades in the Ward County bolt-on. 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. 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.

Great. 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?

You mentioned you're encouraged by early-time results. Just any color here, expectations for incremental costs?

Sure. On the completion side, we've pumped two surfactant trials on two different pads with kind of test or control wells and test wells.

One of those is online. One, 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-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, it should be in a good place to have a feel for how big of a program that could be. I'd say on that side, it's just too early to tell.

Then on the production side, there's two or three pads across both basins that we have pumped kind of surfactant more in late life, 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-one-year payouts on the aggregate, inclusive of the wells that we saw basically no uplift.

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. I'd say what the team's working on now is how do we do more of the 100-barrel-a-day uplifts and less of the zero, or what could we do differently on the wells that we didn't see an uplift?

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.

Very helpful. Thank you.

Good morning, James, Will, Guy, and team, and thanks for taking our questions. 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 that 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 appraisal work up there to feel comfortable with the entirety of that block?

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. I'd say our base case underwriting kind of the locations that we actually paid for, we are highly confident in.

I do think as you get to some upside zones potential, I think whether that's two or three productive zones or four or five productive zones is still TBD. 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.

I think over time, hopeful and would expect to see some of those upside locations, kind of proven up and coming into the money.

Perfect. Maybe just for a follow-up, just on the ops side, could you maybe provide a bit more detail in terms of just you all call out wellbore design improvement, which Will spoke to earlier, but just optimization of the power supply and 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? I think that

there's a decent amount flowing through the financials today. We've run at this point seven or eight microgrids across New Mexico in areas where we historically have been on generator power.

If you want to think about running room of that going forward, 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.

As we're optimizing that, it's going to be in areas where what we've seen is 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 a light switch, cycling it on and off is not good for runtime of equipment like ESPs and things like that. Really, I think we've seen a tremendous ability for us to kind of hold LOE flat or even reduce it over time, which is I think not normal and not what you'd expect.

We kind of have historically always been a $5.50 a BOE LOE company. 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 bucks per BOE.

I think that's a testament to what we've done in the short term. There is still stuff to do.

I feel like beating a dead horse, but the water recycling side is a big needle mover. Water disposals are our largest LOE cost, and the more we can recycle, the more we defer and ultimately save on the LOE side.

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.

Great. Awesome.

Thanks for the time.

Yep.

Good morning, guys. 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? I guess maybe along the same lines, we typically think of the royalty value as a bit higher.

You guys are having a lower price paid for the royalty acreage versus the leasehold. Just a little bit more detail there would be great.

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 high-NRI leasehold.

I think the minerals and royalties on a standalone basis can get really expensive, and frankly, we've struggled to always be able to buy very much at kind of our return thresholds. 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 is just kind of the output of us acquiring these deals at attractive prices.

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

Thanks for that detail there. 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 acres that you've acquired.

Do you now have a bit more capital going towards the Texas assets? Do you still favor New Mexico?

I'm guessing the goal is to try to keep your working interest now at higher and higher levels. Any update there would be great.

Thanks.

I think it's going to be basically the exact same as it's always been. It'll be, call it 70% of the development, maybe a little north of that, on the New Mexico assets and the rest in Texas.

That's consistent with where we've been the last 2 or 3 years.

Got it. Thanks, guys.

Hey. Thanks, operator.

Morning, everyone. I know it's hard to kind of nail down these opportunities, but 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.

I think the answer is

no, we don't. We kind of were always looking, we're always on the hunt, and we're going to continue to buy things when we can find high-quality assets at prices that make sense for generating attractive full-cycle returns.

No, I think we've got good momentum. The ground game continues to chug along, and we're having a lot of success there.

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.

No, that's fair. Then I guess just a quick follow-up for me.

You talked about the surfactants and productivity improvement from here. Just curious, maybe can you quantify or talk about what else you're doing on the productivity side, and if we should still expect flat productivity from PR year-over-year, particularly with all the new assets?

Thanks, guys.

I'd say, look, there's a long list of things you'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, etc.

I think the right kind of approach that y'all should think about PR is that we are testing, trialing, and studying all of it, and I think we're better suited to speak to exactly which ones are the big winners kind of once we get there. Really, what's it mean 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 productivities we've seen in the past.

Hi. I was hoping to provide a little bit more detail on kind of where costs 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 costs per foot were 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?

I think you had talked about a $675 per foot target at one point. Just want to get a sense, are we there at this point, or is that something you're hoping to get to later this year?

I'd say, obviously the run-up in crude and kind of demands on steel, and etc. associated with the war has put some pressure on where we were targeting for the year.

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 got some small ones on the sand side. 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. It's really a hard answer to give, Leo, just given fuel is such a big component of our spending, and I just have no idea where fuel and crude prices are going to be between now and year-end.

I think that if oil prices dip and fuel resets back to where we came into the year at, I think 675 is absolutely in our sights. If oil runs, I think it's probably less likely, but we'll take it on the revenue side.

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.

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? Are you getting a lot of looks here?

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, and you're probably safe to say we will exceed the last 2 years' average this year.

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, where we're finding opportunities on the ground game side.

The bigger stuff can be lumpier, but I'd say we're getting a lot of looks. I think Will referenced it felt like there were 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. I think, 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.

We've done a really good job of that, we've got a ton of confidence it'll keep working going forward.

Thanks.

Thank you. Good morning, all.

Thanks for taking the call. Continuing on the discussion about emerging benches across the midland Delaware.

How do you guys see that developing on your footprint? I guess any update from the last time you spoke about it?

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 in moving north in Lea County, and I'd say that is happening and happening extremely well and very quickly, to speak. We had drilled a few Avalons up that far north as of the call last quarter, but I'd say since then, full development, stacking Avalon, it's been some of the most productive wells we've drilled.

Those type of emerging benches, think of it as benches that have been developed historically on the stateline 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 some of the deeper Wolfcamp.

Typically we've drilled First Sand, Second Sand, Third Sand, and XY on the North Eddy, and we're starting to see deeper Wolfcamp move that direction. As far as 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 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.

Got it. Understood.

Then I guess over the course of the last year or so, you guys have worked pretty diligently to kind of right-size realization expectations around that gas. Are you guys happy at the current level on the go-forward basis, or should we expect a bit more movement in kind of those whether it's FT or hedging or just kind of how you think about locking that as the volatility goes on?

Hey Paul, it's Guy. I think we feel great about the deals we did.

We identified this as an issue a couple years ago, and I think 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. I think the capacity we have going into '27 covers roughly all of our net volume, we're always thinking about what else should we do to optimize the portfolio, how do we handle growth and gas volumes that could occur as we continue to grow oil production and grow through acquisition.

I think on the hedging front, we're just going to be opportunistic like we have. I think 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.

Got it. Appreciate the clarity.

I'll leave it there.

Morning, guys. Thanks for working me in here.

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?

No. I don't think water-based to 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.

Okay. It's more on cost savings than drill time?

That's right. Our drill time wins have been in this slimhole design.

Obviously when you go to 8 5/8 intermediate as opposed to 9 5/8, you can drill a smaller hole and kind of everything goes faster. If you want to think about the savings associated with slimhole, it's been 50% of the savings is on drill times.

We save almost a day a well.

Okay. All right, that's it.

Thank you.

Thanks, Sean.

Hey, John. John, do you have your mute on?

We can't hear you. Operator, I think we can hand it back.

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 had 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.