Q2 2025 Earnings Call Transcript

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 our quarterly gas production guidance, driven by the strong performance of our recent discoveries and our ability to continue increasing utilization of existing infrastructure. Oil production declined modestly following our decision to shift rig activity toward increased gas development due to improved gas realizations. However, gross BOEs were consistent quarter-over-quarter. Reported volumes also exceeded guidance, but adjusted production was slightly lower than guidance due to the impacts of higher oil prices and lower operating costs on our allocated volumes under the production sharing contract.

Our capital efficiency in Egypt is benefiting from small refinements across our drilling and infrastructure programs, which collectively result in meaningful time and cost savings. For example, on the drilling side, on average, we are delivering wells more than 2 days faster compared to last year. Lastly, North Sea production was ahead of guidance, a testament to the continued optimization of field operations and maximizing run time as we manage these late-life assets. Our focus remains on safety, operating efficiency and cost management as we prepare for decommissioning.

Turning now to our cost reduction initiatives. At the start of the year, we set forth some important goals for reducing controllable spend over the next 3 years. I just outlined some of the significant capital efficiency improvements we are making in the Permian and Egypt. Ben will provide further details on other cost initiatives, which have also advanced considerably since our last update.

We now anticipate capturing at least $200 million in savings in 2025, up from our prior estimate of $130 million and plan to exit the year at an impressive $300 million annual savings run rate. We are now on a path to achieve our $350 million run rate target sometime in 2026 versus year-end 2027. Moving forward, over the next 2 years, we see considerable opportunities to further streamline our business and simplify the way we operate. Given the magnitude of these opportunities, it is clear we have upside to our 3-year goal. As we begin implementing these initiatives, we will address the scale of that upside in the future.

Looking ahead to the second half of 2025, our supplement released last night outlined our expected Permian activity and production for the third and fourth quarters, adjusted to reflect the recent asset sale that closed in mid-June. With continued efficiency gains, we are delivering our planned number of turn-in lines and expected production volumes, and we now expect to exit the year with a higher DUC inventory than originally planned. We'll continue to optimize our drilling and completion cadence through the second half of the year to ensure we deliver our revised capital guidance and set 2026 up for success.

As an additional benefit, these efficiency gains enable incremental resource development. As previously noted, we are moving toward denser well spacing with smaller frac sizes. While this may result in lower average well productivity, our new development patterns should deliver increased EURs at the spacing unit level and lower breakeven prices per barrel of oil. In turn, this expands economic inventory counts and increases both overall oil recovery and net asset value.

This is a fantastic outcome. In Egypt, underscoring our long-term strategic commitment and the ongoing success of our development program, we have recently secured presidential approval for the award of approximately 2 million net prospective acres in the Western Desert. This represents a greater than 35% increase in our acreage position and meaningfully enhances our already substantial footprint in the region. This acreage benefits from extensive 3D seismic coverage and considerable overlap with our existing operations, presenting compelling prospectivity for both oil and gas.

We are currently in the final steps of the administrative process and plan to initiate drilling activity before the end of 2025. We expect to maintain current activity allocations with around 1/3 of our turn-in lines expected to be gas focused for the remainder of the year. Based on our year-to-date performance, we are once again raising our guidance for gross gas volumes for the next 2 quarters. This also increases our outlook for price realizations as a higher share of volumes will now be subject to the new price negotiated under last year's revised gas sales agreement. On the oil side, we expect production to stabilize for the remainder of 2025 and hold relatively flat to second quarter levels as our workovers, recompletions and waterflood programs help mitigate base decline.

Combined with the success in the gas program, Egypt is now poised for 2025 growth in both BOE volumes and free cash flow relative to our expectations at the beginning of the year. In Suriname, the GranMorgu development continues to advance toward first oil in mid-2028. I would like to commend our partner, Total, on their execution of the project since announcing FID last fall. Manufacturing of the topsides for the FPSO is currently ongoing, and Total was able to secure drilling contracts at very attractive rates earlier this year. We have updated our full year capital guidance to $275 million to reflect additional milestone and progress payments expected later this year.

This just reflects a simple rephasing of spend patterns and total anticipated project costs remain unchanged. Lastly, we announced a discovery and successful flow test at Sockeye-2 in Alaska earlier this spring. As a reminder, the Sockeye prospect is amplitude supported across 25,000 to 30,000 acres, and the discovery well encountered approximately 25 feet of net oil pay in blocky sand. The subsequent flow test validated rock properties, much better than regional analogs now under development.

Given the size and extensive prospectivity of the block, the next best step is to reprocess 3D seismic data across the majority of our acreage position. This will allow us to tie multiple surveys together to refine our technical understanding and provide regional context. This is a key step for both better characterizing additional exploration prospects and for optimizing an appraisal program for Sockeye as well as helping to prioritize between the 2. Given the timing of the seismic reprocessing and subsequent technical data integration, we anticipate drilling activity will resume during the 2026 to 2027 winter season.

In closing, I will leave you with the following: First, our operational and financial performance for the first half of the year was outstanding. This success is due to the collective efforts of our teams and strong alignment among all leaders in the organization. Our momentum is palpable and sets us up extremely well for the remainder of the year and into 2026. Second, our cost reductions initiatives are progressing very well, and we are on the path to achieving significant and lasting improvements to our cost structure. On the capital side, we are capturing efficiency gains through structural improvements to our operations.

This is allowing us to deliver our planned Permian oil production volumes at a reduced rig count and to grow BOE volumes in Egypt at lower capital. Our operating costs are also trending lower in both Egypt and the North Sea, and we continue to capture significant overhead cost savings through our ongoing simplification efforts. Third, our progress in Suriname and our success in Alaska further underscores the value of our diverse portfolio of high-quality exploration opportunities, which represent material catalysts for the future of the company. Finally, we are committed to our capital returns framework, which allows us to further strengthen our balance sheet while maintaining a competitive payout to shareholders.

And with that, I will turn the call over to Ben.

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. Since emerging from the COVID downturn at the end of 2020, APA has strengthened its balance sheet by reducing net debt by more than $4 billion. During that same period, we've returned over $4 billion to shareholders through our base dividend and share repurchase programs.

This underscores our disciplined approach to capital allocation and our ability to consistently navigate commodity cycles while delivering long-term value. Looking ahead, we plan to continue this balanced capital return strategy. To reinforce our focus on financial strength, we are establishing a long-term net debt target of $3 billion. While we remain committed to returning 60% of our free cash flow to shareholders, providing a debt target reflects our confidence in the durability of our cash flows, the resilience of our asset base and our goal of maintaining an investment-grade credit profile through the cycle.

Maintaining low leverage enhances financial flexibility, reduces volatility and positions APA for sustainable success. This approach is not new. It's a continuation of the principles that have guided us, allowing us to fortify the balance sheet while delivering strong shareholder returns. Moving now to our controllable spend reduction initiatives, where we continue to significantly exceed the targets established earlier this year.

This accelerated momentum demonstrates our relentless focus on managing every aspect of our controllable spend across G&A, LOE and capital. Importantly, these increased targets do not represent a stopping point. Instead, they serve as key milestones in our consistent pursuit of operational excellence and our ongoing drive to reduce our cost structure. Slide 4 of our supplement provides further detail between the various categories of cost savings that we expect to capture this year.

While the changes in LOE and G&A savings can be reconciled with the movement in our guidance ranges for those items, our capital savings are partially offset by additional activity in the Permian. With the efficiency gains we've achieved, we're on pace to end the year with approximately 25% more drilled uncompleted wells than previously planned while remaining within our capital guidance range, which will provide operational flexibility as we head into 2026. On the LOE front, costs are trending lower across our international assets. In Egypt, reductions to date have come from 2 of our larger categories, optimizing equipment use and reducing our diesel consumption through recently completed power projects.

Moving forward, we expect to further reduce diesel usage as we progress additional power projects into next year. In the North Sea, we have been streamlining vendors and optimizing the size of our offshore organization as we manage late-life operations. Furthermore, while maintaining our commitment to safety, we've shifted the scope of our maintenance activities to accommodate shorter, more focused pit stops versus extended platform turnarounds. In the Permian, while we expect the bulk of our LOE savings to become evident in 2026, we are already seeing early signs of improvement this year.

Additionally, we are progressing multiple projects in the back half of this year that will deliver meaningful benefits in 2026 and beyond. These projects include, but are not limited to, utilizing owned and operated saltwater disposal facilities that will reduce reliance on third-party providers, consolidating field compression to larger centralized compression stations and reducing our workover fleet based on improved workover rig efficiencies. Across our entire operated asset base, we have moved decision-making authority closer to operations, which enables field personnel to swiftly identify and implement cost savings without compromising safety or performance.

This has gained traction, unlocking a steady stream of small-scale opportunities that collectively drive meaningful financial impact. Turning to overhead. Our initial focus was on executing quick win opportunities, primarily through selective cost-cutting decisions. We implemented the bulk of those near-term actions, which drove the additional $35 million in realized savings since our last update.

Looking ahead, we're advancing several work streams to rethink and reshape broader organizational processes and workflows with a focus on streamlining the business. These efforts, along with other simplification initiatives are expected to deliver further savings in 2026 and beyond. With all of these initiatives gaining traction across the organization, we're confident in reaching our $350 million run rate savings target within 2026, a significant change from our prior time line of end of 2027. We also see meaningful upside beyond that original target, which we will quantify at a later date. What's clear is that the entire organization is aligned and committed.

In just 6 months, we've made real strides toward positioning APA as a cost leader. The focus is relentless and the results speak volumes. Shifting to our oil and gas trading portfolio. At current strip pricing, our full year guidance reflects $650 million in pretax income from our trading operations, a $75 million increase from our May update.

This is a key value driver for us, and the forward curve for 2026 shows favorable LNG pricing and spreads, reinforcing these activities as a meaningful differentiator for APA. I will close by discussing several changes to our U.S. and U.K. tax estimates. Following passage of the One Big Beautiful Bill Act, we expect to benefit from 2 changes to the U.S. tax code. The first being 100% bonus depreciation for taxable income, which is effective as of January 20 of this year. the second being the ability to deduct intangible drilling costs for corporate alternative minimum tax, which comes into effect at the beginning of 2026. For 2025, we expect a significant reduction in our U.S. current tax expense driven by bonus depreciation changes in the recently passed legislation, changes in 2024 tax estimates and other smaller items.

This reduction is largely offset by an increase in U.K. current tax expense where higher revenues and lower operating costs have increased our taxable income. Starting in 2026, at current strip prices, we do not expect our U.K. operations to generate meaningful taxable income. Combined with the expected benefits from the one Big beautiful bill, our total U.S. and U.K. current tax expense will be significantly lower compared to this year. With that, I'll turn the call back to the operator for Q&A.

[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 50s. And most of that Delaware Basin stuff is Callon. And so Callon has come down in 2023 from a $78 breakeven oil price to low 50s at this point.

All of this is increasing net asset value and increasing inventory duration, as you alluded to. And while I say average well productivity is lower, I think it's a focus on average well productivity is actually not the right metric. You really have to focus on the spacing unit because wells in a spacing unit are interdependent. And it's the spacing unit that actually matters.

Just a couple of years ago, a well-followed industry analyst group noted that Apache have -- Apache's wells have 30% more EUR than industry average. And that was just a couple of years ago, and these were highly productive wells. But at today's cost structure that we have, that development pattern with the wider spacing and larger fracs would actually leave a pretty meaningful amount of economic resource behind. And so today, our development patterns, as you said, much tighter, smaller fracs, they're lower EUR per well, lower productivity per well, but more inventory, more resource, more NAV, lower breakeven oil price.

And so if you look at some of our most recent wells using new development patterns, these are delivering -- these wells are delivering as we planned. Some are over planned, some are under plan, as that's always the case. But importantly, some of these ones that are under plan, we're actually learning from those and improving. It's not just because they can't be improved.

It's because there are things that we're learning and improving along the way. And I think some really important context that might not be visible to the market, especially related to some of these recent wells that we've been drilling is that there's been some temporary constraints or curtailments on the productivity impacting perceived well producibility. A few examples of that in the Delaware Basin at the GOR facility, as we noted in the fourth quarter, we're actually curtailing production on those intentionally because of the low oil price that wasn't going to last very long. It was because of some pipeline maintenance that was going on, at a really low price at Waha.

And so we intentionally curtailed production for a while. Drilling and completion in the GOR area also actually significantly outpaced our facility logistics and the facility just wasn't completely ready for that. That was -- that's been fixed since then. Also in the Delaware Basin, there's a facility called Wild Jenny.

We currently have 14 producers into the Wild Jenny facility and they have been producing for the last few months. If you looked at the production of those wells, you say, well, that's not really very exciting. But again, facility logistics, drilling and completions going faster than facilities have also constrained those wells productivity for the last few months. We actually like the underlying performance, and we think the rock quality of those wells are actually really good.

We've got 24 more turn-in-lines into the Wild Jenny facility by the end of this year. And the production from those wells, even though it might not -- on paper, might not look all that great, the production from those have actually derisked those 24 turn-in lines. The facility is being worked on as we speak, being debottlenecked and being completed actually. And we expect that all 38 of those wells will flow unconstrained or nearly unconstrained by the end of this year.

And perhaps most importantly, in the Midland Basin, in the wildfire area, we've got the Silverbelly facility. And the Wildfire is the area where we're going back in and drilling what we call overfills, which is we're drilling shallower zones where we, in prior years, developed on the wider spacing with what we call mega fracs at the time. And there's some doubts or concerns out there about, well, what are these wells going to produce with those mega fracs down below them that have been producing for a few years. Well, at the Silverbelly facility, we've had delays -- we had delays in delivering power to the facility, and we have electric compression there.

So those -- that actually constrained early production from those wells as well. The wells were ready, but the facility wasn't completely ready. That power is now online. The electric compression is up and running and the performance of those wells have actually improved significantly.

So the point to all of this is that it's a bit hazardous looking at either comparing well productivity today to 2 years ago when we were developing at a much different pattern. It's also a bit hazardous looking at short-term production from new wells when there might be constraints or other reasons at facilities. We look at the wildfire production and the wells that are online today, and we actually believe that, that's derisked quite a bit more drilling in that area.

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 towards brownfield activities, which will be less expensive. We've reduced facility spend on the magnitude of $50 million or a bit more from '24 to '25. We still had some greenfield activity even in '25. As we move into '26 and beyond, I think we're going to be predominantly brownfield type of facilities activity. And I think that there's an opportunity for further facilities capital spend reduction as well.

On the LOE side, I'd start with the obvious, and that is we've actually made little to no progress on the dollar side of LOE year-to-date in '25. So it's not contributing a whole lot to our improvement in costs so far this year. We're making progress today, not necessarily visible with the second quarter results, but we are making progress. And actually, second quarter was above our guide for LOE, but it was below first quarter LOE. And actually, the month of July has been the lowest month of LOE in the Permian that we've experienced to date this year.

So we are making progress. Short term, I think we're benefiting from a move of accountability around certain types of costs out to the field closer to where costs are incurred. And we're working more closely with vendors. We're seeing reductions coming in contract labor.

We're seeing reductions in chemical usage. We anticipate more coming up in -- and we've done this in the past, too, the ESP to pump conversions using less power, more tankless batteries. We're seeing workover rig rationalization in the Permian due to efficiency gains in our workover activities. I think longer term, there's some very high return capital investment opportunities that will lower LOE, things around water disposal, because water disposal hits us in 2 ways, actually, which is obviously the cost of third-party water disposal, but also as many operators are experiencing in the Permian today, we're getting water takeaway constraints from time to time and actually, it results in curtailing production volume.

And so when you have control over your own water disposal, it benefits you in both ways. Compression in the field compression, we need to go to larger scale, more centralized and therefore, more efficient and more reliable compression systems and just the overall continuing to improve the leverage of technology around recognizing and addressing issues in the field more timely so that production volume, which might be constrained or offline gets back online quicker and you do it in a more targeted basis instead of the old- fashioned way of someone visiting every site every day and just getting ahead of some of those things in the field and being more preventative instead of reactive.

So I think there's quite a bit of opportunity on the LOE side. And I didn't mention, but good LOE reduction activities going on in Egypt and North Sea as well.

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.