APA Corporation (APA) — Q2 2025 Earnings Call Transcript

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 two. 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 underscore 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 a $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.

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 take a moment to view the situation in Egypt from a broader perspective, it's a significant award, and I'll provide some context. We've been operating in the Western Desert for over 30 years. During the first three decades, our main focus was on searching for oil, while we also discovered some gas, totaling over 3 Tcf, along with associated and rich gas. Our emphasis was on oil, intentionally avoiding gas. In the Western Desert, there are 15,000 to 18,000 feet of stacked pay, comprising all high-quality sand. We recognized that deeper drilling would yield results. The shift for Egypt occurred when it transitioned from being an LNG exporter to an importer. Following the change in the new minister last summer, we aimed to establish a new gas price that would encourage us to pursue drilling. We have also been eyeing acreage that holds potential for both oil and gas. We've made progress with the direct award and have initiated our program. Steve can elaborate on the impact we are seeing on the gas program, and then I'll hand it over to Tracey to discuss her outlook on the long-term potential for gas in the Western Desert, which we believe shows great promise.

Yes, thanks, John. As John mentioned, historically, we've taken steps over the last 30 years to avoid gas, but we've encountered it in significant quantities that were worth developing at times, especially when it had valuable associated liquids. However, there were instances where we either left gas resources undeveloped or underdeveloped due to prevailing gas prices not being economically viable compared to more abundant oil opportunities. For the past nine months, we've concentrated on revisiting those opportunities, mainly those we previously left undeveloped or underdeveloped, and we've seen impressive results. There are additional known opportunities available. Furthermore, we are reducing risks associated with exploratory efforts beyond our immediate knowledge, and there are plenty of those in the near future. Naturally, the question arises about how long we can sustain this performance, and we are optimistic about its duration. At the same time, we’re also taking a step back to examine the overall regional geology surrounding our 7.5 million acre position to explore the potential for even larger-scale gas opportunities, and I will let Tracey elaborate on 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 avoiding drilling for gas. So the gas 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 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 are really almost indifferent over time to whether it's oil or gas.

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 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, if you could give me a moment. Looking at the bigger picture, capital efficiency is transformative for our industry. Lower costs enable greater access to resources. A prime example is the history of the Permian basin, where as costs decreased, drilling density increased significantly, moving from 40-acre to 20-acre and even down to 10-acre spacing. This increased well density transitioned resources from non-economic to economic. In the unconventional sector of the Permian, greater well density also allows for reduced hydraulic fracturing intensity, which further enhances the cost structure on a per well basis. Recently, capital efficiency has led to a significant improvement in our operations, demonstrating a major change in efficiency levels, which is reflected in our development strategies. We are increasing the number of wells while reducing fracturing intensity. While this generally lowers average well productivity, it is essential to consider the drilling spacing unit level where we are actually enhancing total resource access and reducing breakeven oil prices. For example, in 2023, Callon's breakeven oil price was $78 per barrel of WTI, which we lowered to $61 for 2024. Currently, we are averaging in the low 40s for breakeven oil prices across the entire Permian and seeing even lower numbers in specific areas, like the high 30s in the Midland Basin. Callon has reduced its breakeven price from $78 to the low 50s this year. This focus on efficiency is increasing our net asset value and extending our inventory duration. While average well productivity may seem lower, concentrating on average productivity isn’t the best approach; the spacing unit is what counts since wells influence each other within it. Just a couple of years back, an analyst group noted that Apache's wells had 30% more estimated ultimate recovery than the industry average. Given today's cost structures, the previous wider spacing and larger fracks would leave many resources unrecovered. Hence, our current development patterns involve tighter spacing and smaller fracs, resulting in lower EUR per well but also more inventory, more resources, and reduced breakeven costs. We've seen that many of our recent wells are performing as expected or even exceeding expectations, while some are underperforming. However, we are learning from these underperforming wells and making improvements. It's important to understand that there have been temporary constraints affecting perceived productivity, particularly in the Delaware Basin due to intentional production curtailments amid low oil prices and ongoing pipeline maintenance. We intentionally managed production rates during the past few months at the GOR facility. In addition, drilling in the GOR area outpaced facility logistics, leading to some constraints. At the Wild Jenny facility, we have 14 producing wells, but recent facility logistics have limited their productivity. We remain optimistic about performance and expect that 24 additional wells should come online by year-end, which will help alleviate these constraints. The Silverbelly facility in the Midland Basin faced delays in power delivery affecting our early well production, but with that issue resolved, we expect improved performance. In summary, analyzing well productivity over different time frames and comparing present wells to those from years past can be misleading, especially when factoring in current facility constraints. We are confident that our recent progress, particularly in the Wildfire area, has reduced risks associated with future drilling efforts.

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, if you evaluate our current situation, we have 6 rigs, and if you adjust our figures for the New Mexico sale this year, we're around the low 120 range. Therefore, looking ahead to 2026, we have 6 rigs and are at 120. It's important to note that our capital expenditure for the second half of this year will be lower. So, you can expect we're likely to stay around 6 rigs. Ben?

Yes. I think, Doug, if you annualize the spending from the second quarter through the fourth quarter of this year, that will provide a good estimate for next year, which will be lower than the full year of '25 as anticipated due to the cost-saving initiatives, and we believe there may be further potential for improvement. But from our current perspective, annualizing our spending from the second quarter through the fourth quarter this year will give you a solid basis for what to expect for U.S. capital next year.

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 look back two years ago when our partner drilled three wells in that area, the only well that reached total depth was King Street, which turned out to be a successful discovery in the Brookian play. King Street demonstrated that we could move 90 miles away from the existing developments and still find high-quality sand. This year, we decided to drill one well, which was Sockeye. Although it is not the largest prospect, we chose to prioritize Sockeye because it had the best seismic data. Our goal with Sockeye was to confirm oil presence and high-quality sands, which we successfully achieved with 25 feet of net pay, supported by 25,000 to 30,000 acres of excellent quality sand, all of which is oil. The flow test showed that the permeability is significantly better than what is currently being developed, so we are extremely pleased. While Sockeye wasn't the biggest prospect, we have a variety of seismic surveys, and with our success on both sides of the block, the next major step is to reprocess the seismic data and integrate everything. It's crucial for us to plan the location of the next exploration well and the timeline for appraising Say. This will provide a better overall understanding of the block from a regional perspective, which is crucial right now. Integrating all this data will take some time. The technical teams will be actively working on this. It’s likely that we won’t move a rig back out there until the winter of ‘26. Tracey, do you have anything to add?

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.

It's great to see North Sea taxes coming down so much 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?

Certainly. Let's take a step back and review the situation in the U.K. this year. The team has performed exceptionally well with the asset. In the first half, our production has exceeded expectations, and the team has implemented significant cost reductions, which has resulted in an increase in taxable income for this year. However, when we look at the bigger picture, this also means that free cash flow for the asset is rising. Eventually, if production continues to decline without further investment, we anticipate that it will reach a tax loss situation, with this happening likely in 2026 based on current investment levels and pricing. Until that time, we will keep managing productivity and costs effectively to maintain profitability. However, it’s inevitable that the asset will encounter a tax loss position purely due to its operational dynamics, independent of the Asset Retirement Obligation spend. Next year, the ARO spending will rise compared to this year as we begin planning and decommissioning certain assets in the North Sea. A few quarters back, Steve mentioned that ARO costs would steadily increase from 2025, peaking around 2030 or 2031, before declining toward 2038. Throughout this process, the team remains committed to safety and ensuring the profitability of these assets. The tax environment has been difficult, but we expect that in the next 12 months or so, there will be no taxable income from that asset, meaning we won't have to pay cash taxes.

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 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.

I’m not certain if this is directed at John or Steve. I'm just wondering, as you expand your gas operations in terms of organizational capabilities and equipment availability, what is the scale of the program that can be implemented? If we disregard capital limitations and focus solely on organizational capabilities, where do you see the constraints? Is it feasible for you to execute the program? It appears that you have appealing opportunities for development. Can you accelerate this process? Do you possess the necessary capabilities, and can the market equipment accommodate this?

Paul, that's a great question. I'll start, and then Steve can add if needed. From an organizational perspective, we have the capacity. If you take a look at the Western Desert in the supplement, there’s a picture that illustrates a lot of the infrastructure. We developed a field called Caser in the early 2000s, which produced about 750 million a day, totaling 3 Tcf. The key for us now is to focus on exploration. Historically, we have concentrated on oil for 30 years, and now we have been exploring for gas for 9 months. With the new acreage and the seismic data, we are allowing the team time to evaluate some of the larger exploration opportunities and prioritize and drill some of these, which will be essential for our progress in Egypt's gas sector. The basin is highly conducive to gas, with significant potential, but it will take time for us to thoroughly explore the entire 7.5 million acres.

Yes. Another factor to consider is the deliverability of the gas wells and the targets. We have been searching for oil for 30 years, and we have just begun our focus on gas. Consequently, the targets will be larger in comparison. However, the workover rig count is not currently a major issue.

And John, just curious on...

Yes. In gas, the ratio will differ. On the oil side, this ratio doesn't remain constant either. You might be referencing the scenario from a year or two ago when we operated as many as 21 drilling rigs alongside about 20 or 21 workover rigs. The challenge with oil wells is that many must be completed using a workover rig, as drilling rigs aren't designed for that. Currently, we have increased our ability to handle more completions with drilling rigs, although not all. Moreover, since we are drilling more gas wells, fewer workover rigs are necessary for completions.

Yes. Another factor to consider is the deliverability of the gas wells and the targets. We have been searching for oil for 30 years, and we have just begun with gas. Therefore, the targets will be larger in comparison. However, this is not a significant issue regarding the workover rig count at this time.

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 begin and then pass it over to Steve. I'll discuss the general and administrative expenses. We have made significant progress in this area. As I mentioned earlier, we've achieved some quick wins. Currently, we are executing numerous simplification efforts in several of our larger corporate departments. In total, we are working on about seven different projects, which account for roughly one-third of our total overhead. Our main goal is to streamline processes and ensure we are using technology efficiently. There is an opportunity for AI to assist in this, and we are currently assessing that potential. Additionally, we are focusing on ensuring that everyone is using their time efficiently and engaging in activities that genuinely add value. While we are beginning with these seven groups, this is just the starting point, and in the coming years, other groups will also undergo similar simplification efforts. We believe that as we make these improvements in a company with manageable activities ahead, there will be additional opportunities for overhead savings, which we have already started to capture this year. Now, I will turn it over to Steve to provide more information on capital and lease operating expenses.

Yes. In the Midland Basin, we believe our drilling and completion processes are currently competitive with the industry's best, although there’s room for improvement as our competitors are also advancing. In the Delaware Basin, we've made significant improvements in drilling and completions but are currently averaging at the industry level. The Delaware Basin is less uniform than the Midland Basin, making comparisons difficult across the area. While we excel in specific regions, there are still areas for enhancement. We are focusing on techniques such as increased simul-frac usage and optimized drillout procedures, particularly in the Midland Basin, where lower pressure contributes to our success. We are shifting away from greenfield facility construction, which we have heavily pursued, towards more cost-effective brownfield activities. We plan to reduce facility spending by around $50 million from 2024 to 2025, although there will still be some greenfield efforts in 2025. Moving into 2026 and beyond, we expect our activities to predominantly involve brownfield facilities, with further opportunities for cutting capital expenditures. Regarding lease operating expenses (LOE), we have seen little to no progress in reducing dollar amounts in 2025, which has not significantly contributed to cost improvements thus far. While our second quarter results were above our expectations for LOE, they were lower than in the first quarter. However, July marked our lowest LOE month in the Permian this year, indicating we are making advancements. We are benefitting from increased accountability for certain costs in the field and closer collaboration with vendors, leading to reductions in contract labor and chemical use. We are also seeing efficiencies from ESP to pump conversions that use less power and more tankless batteries, along with rationalization of workover rigs. In terms of long-term investments, we see high-return opportunities to lower LOE, especially around water disposal, which impacts us financially and operationally as we face takeaway constraints that can limit production. Controlling our own water disposal can mitigate these issues. Additionally, we need to enhance field compression systems to be larger, more centralized, and efficient. Ongoing improvements in technology will help us address issues more quickly, allowing us to restore production volumes that are constrained or offline. Overall, there are significant opportunities for LOE improvements, and we are also seeing effective reduction activities in Egypt and the North Sea.

I wanted to follow up and appreciate your insights. I was hoping for more detail regarding the additional Egyptian acreage and the award associated with it. Could you confirm whether APA needs to meet any performance requirements in terms of activity levels to qualify for this award, or is it simply a concession due to your solid operations in the area? Additionally, how do you perceive the incremental acreage in relation to infrastructure? Aerially, it appears well integrated, but considering the next couple of years, will you need to invest in additional infrastructure capital in this area?

Yes, we integrate this into our operations. Some of the acreage is new to us, while some we have had before. We pay a bonus that is deducted from our overdue receivables. We will also drill several wells that will be included in this program. Overall, consider this as an enhancement to our existing efforts and our combined concession. This acreage will play a role in the infrastructure of both our oil and gas initiatives. With successful ventures, we will need to expand and develop further. As shown in the map provided in the supplement, we have established a strong foundation across the desert. We plan to build upon this with future successes. Our operations in Egypt have increased from 5.5 million acres to 7.5 million. Current activity levels will remain steady, but we will 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 will take a step back and let Ben contribute, but we have made strategic decisions. For instance, in Suriname, we recognized the necessity of finalizing a project to maximize the value of the block, so we structured our agreement with this in mind. As we move forward with development, Total is shouldering a significant share of our capital, allowing us to maintain our returns framework without needing to divest many assets or take alternative actions. We've aimed to be very strategic and consider the long-term implications for our balance sheet and how to finance similar projects in the future.

We have occasionally set a net debt target while maintaining cash on our balance sheet, which provides significant flexibility. We expect to reach that target organically in the near future. However, priorities can shift, as John noted, whether it involves exploration, future investments, or managing decommissioning assets that are on the horizon. We've been decommissioning for several years, which aids in risk management and delivering returns responsibly without diminishing shareholder value. Regarding taxes, the intention behind the legislation known as One Big Beautiful Bill was to offer favorable tax treatment for capital-intensive industries like ours, particularly concerning intangible drilling costs. We believe this favorable treatment will persist as long as the legislation remains in effect, providing positive momentum for both the industry and Apache. As we consider shareholder returns and deleveraging, we see a lot of positive developments. We will be flexible in our capital deployment while prioritizing shareholder value. Once we achieve our net debt target, we will reassess our position, but we are confident in the durability of our cash flows and the positive momentum we have to 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 about 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.