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F500-2020-465-Apache

The oil and gas exploration and production company operates in the U.S., Egypt, and the U.K. and has exploration activities offshore of Suriname.

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APA, best known through its Apache subsidiary, is an independent energy company specializing in the exploration, development, and production of oil and natural gas. Operating primarily in the Permian Basin, as well as in Egypt, the North Sea, and Suriname, APA focuses on delivering reliable and affordable energy to meet global demand. The company is committed to sustainable practices and leverages advanced technologies, including artificial intelligence, to enhance operational efficiency and reduce environmental impact.

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APA (APA): Company Profile, Stock Price, News, Rankings

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Day, and thank you for standing by. Welcome to the APA Corporation's Second Quarter twenty twenty five Financial and Operational Results Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. To ask a question during the session, you will need to press 11 on your telephone.

You will then hear an automated message advising your hand is raised. To withdraw your question, please press 11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Stephane Aka, Director of Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's second quarter twenty twenty five financial and operational results conference call. We will begin the call with an overview by CEO, John Christmann. Ben Rogers, CFO, will then provide further color on our results and outlook. Steve Riney, President and Tracy 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 and A.

In conjunction with yesterday's press release, I hope you have 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 supplemental information on our website. 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 $850,000,000 during the quarter and returned approximately $140,000,000 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 or 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 eight. As a result of further progress, we are currently delivering flat go forward oil production with six drilling rigs. Our continued improvement in drilling performance is evident.

Our D and 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 two 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 three 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 $200,000,000 in savings in 2025, up from our prior estimate of $130,000,000 and plan to exit the year at an impressive 300,000,000 annual savings run rate.

We are now on a path to achieve our $350,000,000 run rate target sometime in 2026 versus year end 2027. Moving forward over the next two 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 three year goal. As we begin implementing these initiatives we will address the scale of that upside in the future. Looking ahead to the 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 2,000,000 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 three d 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 2025. We expect to maintain current activity allocations with around one third 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 two 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 Grand Morgu development continues to advance toward first oil in mid-twenty twenty eight. 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 two seventy five million dollars to reflect additional milestone and progress payments expected later this year.

This just reflects a simple rephrasing of spin 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 one blocky sand. The subsequent flow tests 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 three d 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 two. Given the timing of the seismic reprocessing and subsequent technical data integration we anticipate drilling activity will resume during the twenty twenty six to twenty twenty seven 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 $6.00 $3,000,000 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 $219,000,000 after tax gain on the New Mexico divestiture that closed in June, and January unrealized after tax gain on derivatives. Excluding these and other smaller items, adjusted net income for the second quarter was $313,000,000 or $0.87 per share. LOE came in below guidance, primarily driven by cost savings realized in our international assets.

G and 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 and A were modestly impacted by timing related shifts in spend, which are expected to land in the second half of this year. APA generated $134,000,000 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 $850,000,000 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 $1,000,000,000 was returned to investors through dividends, buybacks, and debt reduction. I 'd 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 2020, APA has strengthened its balance sheet by reducing net debt by more than $4,000,000,000 During that same period, we've returned over $4,000,000,000 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 $3,000,000,000 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 controllable spend across G and 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 four 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 and 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 two 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 $35,000,000 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 $350,000,000 run rate savings target within 2026, a significant change from our prior timeline 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 six 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 $650,000,000 in pretax income from our trading operations, a $75,000,000 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 US and UK tax estimates. Following passage of the One Big Beautiful Bill Act, we expect to benefit from two changes to The US tax code, the first being 100% bonus depreciation for taxable income, which is effective as of January 20. The second being the ability to deduct intangible drilling costs for corporate alternative minimum tax, which comes into effect at the 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 UK 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 UK 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 and A.

Star, 11 on your telephone and wait for your name to be announced. To withdraw your question, please press 11 again. In the interest of time, we ask that you please limit yourself to one question and one follow-up. Our first question comes from John Freeman with Raymond James. Your line is open.

Thank you. Good morning. Good morning, John. Congratulations on the continued progress on the cost savings initiatives. Along those lines with the new $3,000,000,000 long term net debt target that Ben outlined, Do have a timeline 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 timeline or possibly exceed kind of that debt target kind of on the heels of what you did with the recent New Mexico 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 move and 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 four 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 years, and if prices for that entire time period are below, then it could take a little bit longer, call it five 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. It's just going to provide a lot of flexibility.

That still includes us managing our ARO and decommissioning spend, we're getting that liability managed. It allows us to invest in the future for exploration and other projects that we seem 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 three to five years.

Thanks for that, Ben. And then shifting gears and looking at kind of what you all have outlined on slide 11 with Egypt, given the impact of the recent gas pricing agreements, the consistent outperformance on the production side, with the recent award of the additional 2,000,000 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?

Yeah, John, if you just step back and look big picture at Egypt, I'll just give, you know, it is a big award and I'll give a little bit of context. We've been in the Western Desert now for over three decades. And for those first three decades, we spent the majority of that time looking for oil. Along the way, we found some gas and some material gas field like costs are over three TCF and then a lot of associated gas and some rich gas. And so, you know, we spent three decades looking for oil and trying to really stay away from gas.

If you look at the Western Desert, you've got 15 to 18,000 feet of stack pay. It's all sand. It's high quality. You know, we knew drilling deeper, would find it. So if you go back, you know, what changed for Egypt is they went from an exporter of LNG to an importer of LNG.

And, you know, with the change in a 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, you know, had our eye on some acreage that is perspective 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 Tracy talk about what she sees is longer term upside for gas in the Western Desert, which we think is a perspective.

Yeah. Thanks, John. As John said, historically we've done what we could for the last thirty 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 develop the asset when we had more oil opportunities. And in nine 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 de risking what I would call minor step out type of, if you want to call it, exploration. The step out opportunities beyond what we know is there, we're de risking 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? Actually, potentially for quite some time. But at the same time, we're also stepping back and Tracy's team is looking at, well, let's just step back and look at the whole regional geology around this 7,500,000 acre position that we have now and what's the potential for even larger scale gas opportunities. I'll just let Tracy talk about that.

Sure, morning John. So with the new acreage additions, we're going to be really well positioned to both expand our existing proven place for both oil and gas and test the new concepts to add inventory. For example, in the western portion of our acreage in the Fugar Shushan region, we've had some recent success by drilling deeper to the Paleozoic and have encountered some really good discoveries for gas. So we're really building on that success there by extending the Paleozoic plays both to the west and to 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 and 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 pulling 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 eight 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 playtests there as well. So we're really encouraged by what we're seeing on three d 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 be able to deliver in Egypt for the exploration program.

Yeah, if I could just wrap that up. I mean, we're operating now in 7,500,000 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. We can just pursue the best prospects And we were really almost indifferent over time to whether it's oil or gas.

Thanks everyone. I really appreciate all the details.

Our next question comes from Doug Leggate with Wolfe Research. Your line is open.

Thanks. Good morning, everyone. 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 two 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, which we should expect for that maintenance of the new production level that you highlighted in your comments.

Yeah, Doug, I'll jump in and the first thing I'll say is, we're always culturally looking for how do we continuous improve and drive innovation. And if you look at the impact you're seeing on the capital 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 two 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, you know, 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, you know, 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. Will be, you know, at Permian on our existing portfolio for a long time.

Yeah, John, 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 that lower costs 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 uneconomic to economic status.

In the unconventional space in 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 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 Callan.

And so Callan 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 years ago, a well followed industry analyst group noted that Apache's wells have 30% more EUR than industry average. And that was just a couple 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 wells are delivering as we planned. Some are over plan, some are under plan, as that's always the case. But importantly, some of these ones that are under plan were actually learning from those and improving. It's not just because they can't be improved, it's because there's 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 Gar 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 completions in the GAR area also actually significantly outpaced our facility logistics. And the facility just wasn't completely ready for that. 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 have been producing for the last few months. If you looked at the production of those wells, 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 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 de risked those 24 turn in lines. The facility is being worked on as we speak, being de bottlenecked 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 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 called mega fracs at the time. And there's some doubts or concerns out there about 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 had delays in delivering power to the facility and we have electric compression there. So 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 two 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 de risked quite more a drilling in that area.

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

Doug, think if you looked at us today, six rigs and if you adjust our numbers for the New Mexico sale this year, we're in the low one twenty range. So, I would say going into 26 right now, six 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 six rigs range, Ben.

Yeah, think Doug, just if you annualize second quarter through fourth quarter of this year, that'll 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'll 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. So I'm going to turn it back as someone else jump on. But thanks so much.

Thank you. Our next question comes from Michael Cialla with Stephens. Your line is open.

Good morning, everybody. Total pushed back on their second quarter call on the possibility they were ahead of schedule Suriname and you're sticking with the first oil in mid twenty eight. But is it fair to say that the fact you're increasing the budget for Grand Morgue milestone payments reflects that the project's 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 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 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 twenty six, twenty seven winter? I guess Yep. Want to get, you know, a progress report there and what what you're looking at with the reprocessing.

Mike, if you step back two years ago when our partner originally spud three wells, three prospects on the block there. The only one that got down, we ran into a short winter and they had some drilling challenges with the equipment. The only weld we TD ed was King Street and it was a successful discovery in the Brookie and play. What King Street told us is that you can 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 prioritize Sockeye this year was it had the highest quality seismic data. And what we were hoping to prove the sockeye is one oil to high quality sands. We did both of those, you know, 25 feet of net pay. It's amplitude supported over 25 to 30,000 acres, really high quality sand, and it's all oil. So, you know, and then the flow test confirm 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 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 Sockeye 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 they're going to be working. But yes, it's likely '26 before we move a rig back out there. Tracy, anything you want to say?

No, John, I think you covered it. I think the most exciting thing is John mentioned was that we proved the play concept moving from the Pecan Willow discoveries to the block on the other side of Prudhoe Bay, which was a really big story. I think we've just really been bolstered by the success that we've seen at Sockeye as well that further demonstrates a working hydrocarbon system with really good reservoir quality and an oil charge.

Thank you. Our next question comes from Betty Jiang with Barclays. Your line is open.

Good morning. 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 UK this year, the team's 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's 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.

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'll increase pretty steadily from '25 and kind of peak in the 02/1930, 2031 context and then decline from there into 02/1938. 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 twelve 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. Thank you, Ben. 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 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 twenty four-twenty five and at this activity set with the oil investment that we're doing, with about two thirds of the activity on oil and one third on gas, it'll 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 think that trend can continue next year and that implies a modest free cash flow increase year on year as well.

Thank you. Our next question comes from Paul Cheng with Scotiabank. Your line is open.

Hi. Good morning, guys. Don't know if for John or for Steve. Just curious then, I mean, as you move to doing more gas, from an organizational capability standpoint as well as the equipment availability in Yijing, how big is the program you can do? If we set aside, say, capital constraint, just looking at organizational capability, where's the constraint?

Can we do the program? Because it seems like you're so attractive on those development. Can you do it faster? Do you have that capability? And also, yes, the market equipment can support it.

Paul, it's great question. I'll jump in here, 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. You know, we developed in the early 2000s a field costar came on about $750,000,000 a day, three 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 three decades. We've now been looking for gas for nine months. And so with the new acreage and the seismic, it's just 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 set this up in terms of what can we do in Egypt on the gas side. But it's a very, very gas prone basin.

APA (APA) Q2 2025 Earnings Call Transcript

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