Good morning, and thank you for joining us on APA Corporation's Second Quarter 2025 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John Christmann; Ben Rodgers, CFO, will then provide further color on our results and outlook. Steve Riney, President; and Tracey Henderson, Executive Vice President of Exploration, are also on the call and available to answer questions. We will start with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you've had the opportunity to review our financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude noncontrolling interest in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. The full disclaimer is located in the supplemental information on our website. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. On today's call, I will provide an overview of our second quarter results, share an update on our cost reduction initiatives and provide color on our outlook for the second half of the year. Overall, this was an excellent quarter for APA, showcasing strong operational and financial performance, continued capital returns to shareholders and significant debt reduction. I want to first acknowledge the strides we continue to make in strengthening the balance sheet and improving our capital structure. We reduced net debt by more than $850 million during the quarter and returned approximately $140 million to shareholders through our dividends and buybacks. We remain firmly committed to shareholder returns and balance sheet strengthening through debt reduction. Ben will provide more color on this topic shortly. Turning specifically to second quarter operational performance. Production volumes across the portfolio generally exceeded guidance while remaining on plan for company-wide capital investment. In the Permian, oil production exceeded guidance, primarily driven by faster turn-in lines enabled by efficient field execution. Capital investment came in slightly above guidance, largely due to the ongoing capture of efficiency gains across drilling and completions. Put simply, we are delivering more activity with fewer rigs and frac crews. Last quarter, we noted that these efficiency gains would allow us to keep Permian oil production flat with 6.5 rigs instead of 8. As a result of further progress, we are currently delivering flat go-forward oil production with 6 drilling rigs. Our continued improvement in drilling performance is evident. Our D&C cost per foot are now among the lowest in the Midland Basin and in line with offset peers in the Delaware Basin. Our teams are committed to finding new ways to further improve efficiencies across the basin. In Egypt, we again exceeded…

Thank you, John. For the second quarter, under generally accepted accounting principles, APA reported consolidated net income of $603 million or $1.67 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $219 million after-tax gain on the New Mexico divestiture that closed in June and $106 million unrealized after-tax gain on derivatives. Excluding these and other smaller items, adjusted net income for the second quarter was $313 million or $0.87 per share. LOE came in below guidance, primarily driven by cost savings realized in our international assets. G&A was also lower due to continued progress in simplifying our organizational structure. While the majority of the variance stems from these structural improvements, both LOE and G&A were modestly impacted by timing-related shifts in spend, which are expected to land in the second half of this year. APA generated $134 million of free cash flow during the second quarter, all of which was returned to shareholders through our base dividend and share repurchases. Our free cash flow is expected to be second half weighted, driven by Permian capital timing and continued growth in Egypt gas volumes and price realizations. During the quarter, we also made significant progress on debt reduction. We eliminated outstandings on our revolver and reduced net debt by over $850 million, a decrease of more than 15%. This was driven by proceeds from the New Mexico asset sale and positive working capital inflows primarily associated with payments from Egypt. In total, for the second quarter, nearly $1 billion was returned to investors through dividends, buybacks and debt reduction. I would like to take a moment to step back and highlight the meaningful progress we've made over the past several years under our capital returns framework.…

[Operator Instructions] Our first question comes from John Freeman with Raymond James.

Congratulations on the continued progress on the cost savings initiatives. Along those lines with the new $3 billion long-term net debt target that Ben outlined, do you have a time line for achieving that target? And maybe if you could provide some details on the plan and whether or not divestitures might be used as a tool to kind of accelerate that time line or possibly exceed kind of that debt target kind of on the heels of what you did with the recent New Mexican sale.

Sure, John. When we outlined that target, we thought it was responsible really to commit to the specific target and not really a date, which could move around and ostensibly be artificial. There's a lot of macro volatility and regulatory shifts that could just distort short-term movement in optics in that. So we just thought that putting a target out there was more prudent. Now that being said, at what we think is mid-cycle pricing, which is pretty close to what we have seen last year and this year, we'll achieve that target likely by close to the end of this decade, so call it in the next 4 plus or minus years. If prices are higher, then that can be accelerated, and we might be able to achieve that earlier, call it, in a couple of years. And if prices for that entire time period are below, then it could take a little bit longer, call it, 5 years. But we expect to do that just through our organic free cash flow generation and really a commitment of that 40% that's not being returned to equity being directed towards getting our net debt down. And it's just going to provide a lot of flexibility. That still includes us managing our ARO and decommissioning spend, and we're getting that liability managed. It allows us to invest in the future for exploration and other projects that we see necessary to continue to help the future of Apache. And so we didn't want to put a specific time on it. We just feel very confident in the durability of our cash flows that we'll be able to achieve it, like I said, call it, in the next 3 to 5 years.

And then shifting gears and looking at kind of what you have outlined on Slide 11 with Egypt, given the impact of the recent gas pricing agreements, the consistent outperformance on the production side, along with the recent award of the additional 2 million acres in Egypt. When you sort of look out to next year, would this sort of indicate that there might be a shift to a larger percentage of the total CapEx budget being allocated to Egypt?

Yes, John, if you just step back and look big picture at Egypt, I'll just give -- it is a big award, and I'll give a little bit of context. We've been in the Western Desert now for over 3 decades. And for those first 3 decades, we spent the majority of that time looking for oil. Along the way, we found some gas and some material gas, feel like costs are over 3 Tcf and then a lot of associated gas and some rich gas. And so we spent 3 decades looking for oil and trying to really stay away from gas. If you look at the Western Desert, you've got 15,000 to 18,000 feet of stacked pay. It's all sand. It's high quality. We knew drilling deeper, you would find it. So if you go back, what changed for Egypt is they went from an exporter of LNG to an importer of LNG. And with the change in the new minister last summer, early on, we set a goal in place to -- let's put a new gas price in place that would incentivize us to get after drilling. And we also had our eye on some acreage that is prospective for both oil and gas. So we've worked through that direct award. We've gotten after the program. And Steve can talk a little bit about the impact we're having on the gas program. And then I'll let Tracey talk about what she sees as longer-term upside for gas in the Western Desert, which we think is very prospective.

Yes. Thanks, John. As John said, historically, we've been -- we've done what we could for the last 30 years to avoid gas, but we have encountered gas, sometimes in large enough quantities that was worth developing, sometimes rich enough with enough associated liquids that it was worth developing. But sometimes we left it either undeveloped or underdeveloped simply because the gas price that prevailed at the time wasn't economic enough to deliver -- to develop the asset when we had more oil opportunities. And in 9 months now, we've focused on going back after those opportunities, mostly things that we left undeveloped or underdeveloped. And the results have been quite striking. There are more known opportunities to go. So there is more to do in that space. And the good thing is that through that, we're actually derisking what I would call kind of minor step-out type of, if you want to call it, exploration, the step-out opportunities beyond what we know is there. We're derisking those, and there's quite a bit of those for the near-term future as well. And so the obvious question is, well, how long can this type of performance run and actually potentially for quite some time. But at the same time, we're also stepping back and Tracey's team is looking at, well, let's just step back and look at the whole regional geology around the 7.5 million acre position that we have now. and what's the potential for even larger scale gas opportunities. And I'll let Tracey talk about that.

Sure. So with the new acreage additions, we're going to be really well positioned to both expand our existing proven plays for both oil and gas and test some new concepts to add inventory. So for example, in the western portion of our acreage in the Faghur, Shushan region, we've had some recent success by drilling deeper to the Paleozoic and have encountered some really good discoveries for gas. And so we're really building on that success there by extending the Paleozoic plays both to the west and to the south into the direct award acreage, where we believe we have mature gas prone source rocks in the Paleozoic. So we see that deep play continuing, and we think we've got a lot of running room because that's a very underexplored play in a mature area. And in the AG Basin, which was in the southern central portion of our acreage, this is one area where we've previously focused and only limited ourselves to oil prospectivity in the shallower Cretaceous targets. And now this is a big area for us for big gas and a big focus. So we're quite excited about this because this is an area that's a proven basin, but it's been underexplored because we've been avoided drilling for gas. So the gas pump portions of this basin, we think we have a lot of running room in. The last area that I'll touch on is the acreage to the east, which will allow us to expand our oil plays as well. So we picked up a block there with only 8 wells drilled in it. So it's very underexplored for a very sizable area. And we see evidence on seismic that some of our proven Cretaceous plays in the Western Desert expand into this area. So we've got some new play tests there as well. So we're really encouraged by what we're seeing on 3D seismic, and we'll be testing some of those later this year. So we're in a really good position to both leverage what we know in the desert and test some new concepts. And I'm really optimistic on what we're going to be able to deliver in Egypt for the exploration program.

If I could just wrap that up. I mean, we're operating now in a 7.5 million acres in what's obviously a hydrocarbon-rich basin. And with the new gas price agreement, we can actually operate in a way where we don't have to avoid certain types of hydrocarbons. So we can just pursue the best prospects and were really almost indifferent over time to whether it's oil or gas.

Our next question comes from Doug Leggate with Wolfe Research.

John, this is starting to look a lot like a turnaround. So congrats on the quarter, but there's a lot of things to dig into. I'm going to pick 2, if I may. And it's the one sore point perhaps for the market, which is there's still no visibility on inventory in the Permian. So you haven't commented on that in quite some time. So I wonder if you could address that and the associated run rate capital we should expect for that maintenance of the new production level that you highlighted in your comments?

Yes, Doug, I'll jump in. And the first thing I'll say is we're always culturally looking for how do we continuously improve and drive innovation. And if you look at the impact you're seeing on the capital efficiency today in the Permian, those are results that are really a credit to both the technical teams and the field staff for really focusing on operations excellence over the last 2 years. We've continued to build a lot of momentum. You're seeing those results come in. And quite frankly, there's a lot of upside and more we still see to bring forward. In my prepared remarks, I outlined how our Permian development strategy is evolving in a lot of areas now where we're drilling more wells per section with smaller fracs, and it's really a function of getting the cost down and being able to drive the capital efficiencies and where we are, we're in the process of characterizing all of our inventory and all of the upside zones in the Permian. I have seen what I'd call the core inventory and where we historically would have said to the end of the decade, I can tell you today, looking at what I would call core development inventory, we're now well into the 2030s with run rate in terms of existing pace and time. And there's a lot more we're still working on. It's a very iterative process. The teams have been working hard on it, and we should be in a position either late this year or early next year to give some more color on that. But it's progressing. I'm excited about the impact we're seeing. and Steve can get into some of the results. But if you look at some of the pads we're drilling today, we've gone back into overfill areas and are having fantastic results. So very excited. We will be at the Permian on our existing portfolio for a long time.

Yes, John, just -- if people will indulge me a bit with a bit of time. I think if you just step back, capital efficiency changes everything in our industry, and that's always been true in our industry and the lower cost leads to the ability to access more resource. And all you have to do is look at the history of the Permian conventional to see that where as costs came down, people went from 40-acre spacing to 20-acre spacing to 10-acre spacing, increasing well density and even promoting resource from economic to -- uneconomic to economic status. in the unconventional space in the Permian, that increasing well density also enables, as you alluded to, lowering frac intensity, which then further compounds the lower cost structure that you have on a per well basis. And so for us, capital efficiency has really led to -- here recently to a step function change in our capital efficiency and is leading to pretty meaningful changes in our development patterns. And I don't use the term step function change very lightly either because I think that's an adequate descriptor of what we've done over the last several quarters. We're increasing well count. We're decreasing frac intensity, as you alluded to. That generally lowers average well productivity, yes. But at the DSU level, the drilling spacing unit level, we're increasing total resource access and lowering breakeven oil prices. We talked about in Callon, in 2023, Callon had a $78 WTI oil breakeven price. In 2024, we lowered that to $61. Currently, in the Permian, we are running on average in the low 40s across the entire Permian in terms of a WTI breakeven oil price. In Midland Basin, we're running in the high 30s. And in the Delaware Basin, we're in the low…

Gosh. Very thorough answer, Steve. I appreciate that. I wonder if I could just put a bow on it. What is the sustaining capital in the Permian production? What is the spending run rate into '26?

Doug, I think if you looked at us today, 6 rigs -- and if you adjust our numbers for the New Mexico sale this year, we're in the low 120 range. So I would say, going into '26 right now, 6 rigs, 120. And I think you need to look at a capital number, back half of this year will be lighter than that. So you're probably more in the 6 rigs range. Ben?

Yes. I think, Doug, just -- if you annualize second quarter through fourth quarter of this year, that will give you a decent proxy for next year, which is lower than '25 full year as expected with the cost savings initiatives, and we think there's even upside to that. But just from where we sit right now, if you annualize our second quarter through fourth quarter spend this year, that will give you a decent proxy for what to look at for next year on U.S. capital.

All right. Guys, I had five more questions, but you've taken a long time to answer this one. I'm going to turn it back to someone else.

Our next question comes from Michael Scialla with Stephens.

I know Total pushed back on their second quarter call on the possibility they were ahead of schedule on Suriname and you're sticking with first oil in mid-'28. But is it fair to say that the fact you're increasing the budget for GranMorgu milestone payments reflects that the project is moving more quickly, at least than you anticipated?

Mike, what I'd say is, first of all, I really want to compliment Total. I mean they stepped in, we FID'd this thing last fall, and they have gotten after it and they're really validating that we picked the right partner for Suriname. What I would say is overall project is moving as scheduled. What's actually moved is from early next year payments to this year, you're seeing some milestones on some of the things like the FPSO moving a little quicker, but nothing that's going to change the overall project at this point or increase the overall cost. So it's just some of the noise, I'd call it, between a calendar year of what's getting paid because as you complete certain aspects of the infrastructure and things, those are due. So no real change at this point, but things are progressing very, very well.

Okay. Sounds good. I wanted to ask on Alaska. You gave a little bit of detail on that. I guess, on the technical work that's being done there, did I hear you correctly that it's just seismic reprocessing for a while and no drilling until the '26-'27 winter? I guess I wanted to get a progress report there and what you're looking at with the reprocessing.

No, Mike, if you step back 2 years ago when our partner originally spud 3 wells, 3 prospects on the block there. The only one that got down, we ran into a shortened winter and they had some drilling challenges with the equipment. The only well we TD-ed was King Street, and it was a successful discovery in the Brookian play. What King Street told us is that you could move 90 miles from any of the offset development, and we had a really high-quality sand. So when we looked at this year's program, we wanted to go in and drill one well. The well we elected to drill with Sockeye. It is not the largest prospect. But the reason we prioritized Sockeye this year was it had the highest quality seismic data. And what we were hoping to prove with Sockeye is one, oil; two, high-quality sands. We did both of those, 25 feet of net pay. It's amplitude supported over 25,000 to 30,000 acres, really high-quality sand, and it's all oil. So -- and then the flow test confirmed the perm is much better than what's being developed. So we're very, very happy. When you step back, as I said, Sockeye was not the biggest prospect. We've got a bunch of different seismic surveys. And so with the success we've now had on both the east and the west side of the block, the next big step is really let's reprocess the seismic, put all these together because, quite frankly, where we place the next exploration well and then the timing and the plan on how we appraise Say are important and a better picture across the whole block from a regional perspective is what's key right now. And it takes a little bit of time. And so there's a lot of data to integrate. It won't be just the seismic. The technical teams are doing -- are going to be working. But yes, it's likely winter of '26 before we move a rig back out there. And Tracey, anything you want to say?

John, I think you covered it. I think the most exciting thing, as John mentioned, was that we proved the play concept moving from the Pikka and Willow discoveries to the block on the other side of Prudhoe Bay, which was a really big story. And I think we've just really been bolstered by the success that we've seen at Say as well that further demonstrates a working hydrocarbon system with really good reservoir quality and an oil charge.

Our next question comes from Betty Jiang with Barclays.

It's great to see North Sea taxes coming down so much in next year. Could you help us just unpack what exactly is driving that drop? Does it mean the ARO spend is going up in a meaningful way next year? And if you could just remind us what's the general trajectory of that decommissioning activity over the next few years?

Sure. Really, I'll just step back, when you look at the U.K. this year, the team has done a really great job with the asset. As you can tell in the first half, we've gotten production higher than expected, and we've been -- and the team has been cutting a lot of costs there. And that's increased taxable income for this year. But when you step back and consolidate everything, that means that free cash flow for that asset is also up. At some point, with production continuing to decline without investment in the asset in the future, it will be at a tax loss position and at strip pricing and at current investment levels, we think that, that's likely going to happen in 2026. Until then, we'll continue to manage productivity and cost on that asset and the profitability of that asset. But at some point, it will get to a tax loss position just inherently through the asset standing alone from -- regardless of the ARO spend. And so then you put ARO on there, it will increase next year compared to this year as we start to do more planning and decommission certain assets in the North Sea. What Steve said, I think, a few quarters ago about the shape of that is it will increase pretty steadily from '25 and kind of peak in the 2030, 2031 context and then decline from there into 2038. So all the while, the team is focused on safety and really managing those assets for profitability. The tax regime there has been challenging. But for us, we expect at some point, likely in the next, call it, 12 months or so, some point next year, there won't be taxable income there, and so we won't be paying cash taxes on that asset.

Got it. That's helpful color. My follow-up is on the free cash flow profile of the Egypt business. Just given the gas price improvements that you're seeing, the cost saving initiatives that's being implemented now, maybe one way of looking at the Egypt business is how much free cash flow do you think that business can generate on a sustainable basis?

Sure. I think when you step back this year and you look at the beginning of the year where we were, we had some expectations for what we were going to do on the gas side, and we've clearly exceeded a lot of that this year. And with the increased gas production as well as the step change in the gas price, which you've seen quarter-on-quarter delivery, free cash flow for that asset net is up, and that includes the modest decline in oil that you'll see just year-on-year '24, '25 and at this activity set with the oil investment that we're doing with about 2/3 of the activity on oil and 1/3 on gas, it will likely decline next year as well. But that's going to be more than offset by gas production and the gas price. And so BOEs, we expect will continue to grow and they'll grow this year and I think that, that trend can continue next year. And that implies a modest free cash flow increase year-on-year as well.

Our next question comes from Paul Cheng with Scotiabank.

I don't know -- Ben. I don't know if it's for John or for Steve. Just curious that, I mean, as you move to doing more gas from an organizational capability standpoint as well as the equipment availability in [indiscernible], how big is the program you can do? I mean, if we set aside, say, the capital constraint, just looking at organizational capability, where is the constraint? Can we do the program? I mean, because it seems like you're so attractive on those development. Can you do it faster? Do you have that capability? And also if the market equipment can support it?

Paul, it's a great question. I'll jump in here and then Steve can add if need be. But from an organizational standpoint, we've got the capacity. And if you step back and look in the Western Desert in the supplement, we put a picture in there that shows a lot of the infrastructure. We developed in the early 2000s, a field Caser that came on about 750 million a day, 3 Tcf. So when you step back, I mean, I think the biggest thing for us is characterizing on the exploration side. I mean we've historically been focused on oil for 3 decades. We've now been looking for gas for 9 months. And so with the new acreage and the seismic, it's just -- it's letting the team have time to work up some of the larger exploration prospects and prioritizing those and drilling some of those are going to be the keys to setting us up in terms of what can we do in Egypt on the gas side. But it's a very, very gas-prone basin. There's a lot of potential. I think it's just going to take a little bit of time for us to work the entire -- it's 7.5 million acres.

And John, just curious on...

Yes, John, I'd just add on the gas processing side, if you look at field infrastructure, on the gas processing side, we've got a significant amount of haulage there. We've got -- we produce around 500 million cubic feet a day today. We've actually got plant processing capacity of about 800 million cubic feet a day. the limitation for us is really in the field around gathering and transport to the facilities. And in new areas, it's a need for trunk lines, and that's kind of fairly simple. In the producing areas, the legacy producing areas, we're dealing with pressure regimes as you're dealing with older legacy production that's lower pressure with the new gas discoveries and gas production volume that comes in at higher pressure. And that's a bit more complex in dealing with that. We've been working through those limitations actually extremely effectively, but more infrastructure eventually will be needed if we have the exploration success that we actually anticipate we have for the long term. We'll need to develop low-pressure and high-pressure systems. We will need compression. And there are some other actually other existing or anticipated facilities in the area, third-party facilities where we're actually having conversations already with some of these third parties about could we get access to your capacity, which would lead to additional capacity much more easily available to us and at a lot less capital and in some cases, readily available actually today. And I think in the longer term, exploration, as you mentioned, is going to determine the way forward around cost -- I mean, around growth.

Okay. Steve, just curious, in the past, when you're developing oil, you have said you need about 2 workover rigs for 1 drilling rig. And that become a bottleneck because you just could not find enough of the workover rig. That's why you scale back in your program in oil. In gas, based on your experience that, what's that ratio?

Yes. In gas, it's not going to share the same ratio. And actually, we don't necessarily -- that ratio doesn't stay constant even on the oil side because we -- I think you were probably talking about the situation that we had a year or so ago, a couple of years ago when we were running -- at one point, we were running as many as 21 drilling rigs. And I think we had about 20 or 21 workover rigs running at the same time. And the issue on the oil side is that a lot of the oil wells have to be completed by a workover rig and the drilling rig is not actually equipped to do that. We've actually moved to today, we can do more, not all, but more of the completions with the drilling rig. And because we're drilling more gas wells, you don't need as many workover rigs to handle the completions also.

Yes. And the other factor that comes into play there is the deliverability of the gas wells and the targets. We've been looking for oil for 30 years, and gas, we've just started. So you'll have bigger targets relative. But -- so not a major problem on the workover rig count at this point.

Great. Final question. Steve, when you're talking about an upside to the 350, where you think that is the biggest source of that upside?

Sure. I'll start and hand it over to Steve. I'll start on the G&A or overhead part. We've made a lot of progress there. As I said in my prepared remarks, there's been some kind of quick wins that we've done. Right now, we've got a lot of simplification efforts ongoing in some of our larger corporate groups. And when you take all of those together, it's about 7 different projects we're working on right now. It's about 1/3 of our total overhead. And so we'll work through that. The focus there is streamlining processes and making sure that we're being efficient with the use of technology. There's potential for AI to help out in that, and we're evaluating that. And the -- and it's also just making sure that everyone is being efficient with time and doing things that actually add value. So we're starting with those 7 groups, but that doesn't cover the whole organization. So you move into next year, the following year, there will be other groups that will be going through these simplification efforts. And we think that as we do that and streamline everything with a company that has manageable activity in front of it that there's going to be upside to the overhead savings that we have, and we've already captured this year. I'll turn it over to Steve to talk about additional on capital and LOE.

es. On the capital side, I think in the Midland Basin, we believe on a drilling and completion basis, we're actually competitive today with some of the best in the industry. And that doesn't mean that there's not opportunity for continued improvement because our competitors continue to improve as well. So obviously, we'll keep pushing for improvement there. In the Delaware Basin, drilling and completions, we've improved quite a bit, but we're running at about industry average now. Now that Delaware Basin is not as homogeneous as the Midland Basin is. So it's not necessarily comparable across the entire basin. But we do -- and we do think we're very good in some areas, but we do think there's also areas where we can continue to improve. I think across the entire basin, things like more use of simul-frac, more drillout optimization, which we've made some good strides there, drill out post completion that is -- and we've accomplished quite a bit in the Midland Basin, particularly because of the pressure regime that we find in the Midland Basin, which is much lower than what we find in the Delaware Basin. But some of the things that we've done in the Midland Basin, can we transition or translate some of those in some form into the Delaware Basin, things like changes in casing programs, casing designs, drilling fluids, bottom hole assemblies and things like that, that we might be able to get into the Delaware Basin as well that have been instrumental in getting to improved rate of penetration in the Midland Basin and lowering total well costs. I'd say also on the facilities side, we've probably -- we're moving away from greenfield type of facility construction, which we've done quite a bit of in the past. We're moving more…

Our next question comes from David Deckelbaum with TD Cowen.

I wanted to follow up -- I appreciate it. I was hoping for a little bit more detail on the additional Egyptian acreage and the award there. Just to confirm, one, that -- is there any performance that APA needs to perform in terms of activity levels, et cetera, to earn into this award? Or should we just view this as a concession because you've been a solid operator in the area? And then how do you all think about the incremental acreage from an infrastructure perspective? It looks like aerially that things are well tied in. But I guess as we think about over the next couple of years, is this an area that you're going to have to add additional infrastructure capital to?

Yes. It's something we integrate in. Some of the acreage we've had in the past, some of it we haven't. There is a bonus we pay that gets netted off of our past due receivables. And there are a number of wells we'll drill, which get rolled into the program. So in general, you should think of it as just adding to our existing program and our merged concession, which is how this acreage gets rolled in and gets treated. It becomes really just part on the infrastructure side of both the oil and gas programs. With success in areas, we'll need to build out and add on. But as you see from the map in the supplement, we've got quite a good backbone across the desert. And so it's something that we will look to add to and build on with success. So -- but just think of it as adding to our going concern Egypt, we've gone up from 5.5 million acres now to 7.5 million. Activity levels today are going to stay the same, but we'll be drilling on this acreage in the fourth quarter.

Appreciate that, John. And then just for my follow-up, as you think about this new long-term net debt target of $3 billion, which appears like you're going to achieve in relatively short order, especially with the benefits of taxation next year, when you get there, how do you think about capital from beyond that in terms of free cash, just given the fact that you have a fairly robust exploration portfolio relative to returns of capital?

Yes. I mean, if you -- I mean I'll step back and then let Ben jump in, but we've tried to be really smart, right? I mean, when you look at what we did in Suriname when we brought in a partner, we banked on the fact that to really get value for this block, we needed to FID a project. And we structured the agreement accordingly. So as you're now going through development scenario, Total is carrying a large portion of our capital, and it enables us to stick to our returns framework without having to sell a lot of assets or do other things. And so we've tried to be really smart and think longer term about the balance sheet and think about how do you fund these types of projects in the future.

Yes. And we made it a net debt target from time to time, we'll have cash on the balance sheet. I think that provides a lot of flexibility. To your point, just organically expect to get there in the foreseeable future. But when you have different priorities, like John mentioned, whether it's exploration and investing in the future or decommissioning assets, which we know is coming in the coming years and has been. We've been decommissioning for quite a few years now. It really helps us to manage that risk and deliver returns. It's the responsible way to do it without eroding shareholder value. And so it really provides flexibility. And just stepping back, one comment you mentioned on the taxes. The one big beautiful bill, the intent of that was -- of that legislation really was for the favorable tax treatment for industries like ours that are highly capital intensive for tax treatment for intangible drilling costs to be beneficial. And so when we look at that, we think it's durable and will continue for years as long as that legislation is intact. And that provides a lot of tailwinds for the industry and definitely for Apache. And so that helps when you think about shareholder returns and when you think about deleveraging, there's a lot of positive momentum for that. And we'll be flexible with how we deploy that capital, but focused on shareholder value, that net debt target once we do achieve that, we'll step back and reevaluate. But but believe that the durability of our cash flows and a lot of other momentum that we have, we'll be able to get there as well as invest in the future and return capital to shareholders.

Thank you. Our strong second quarter results reflect the hard work of our entire organization and specifically the integration of the technical teams in the field and the execution across everywhere. We've built strong momentum for the back half of the year and well into 2026. We are outpacing our expectations on capital efficiency gains and cost reduction initiatives while continuing to make progress on net debt reduction and shareholder returns. We have bolstered our core assets with a step change in capital efficiency in the Permian and the direct award of 2 million acres in Egypt, along with the early success of the gas program. The GranMorgu project in Suriname is progressing on schedule, and we remain very optimistic on the impact of our exploration portfolio and what it can have on the corporation. With that, I will turn the call back over to the operator, and thank you very much for joining us today.

This concludes today's conference call. Thank you for participating. You may now disconnect.