APA Corporation (APA) — Q3 2025 Earnings Call Transcript

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

Good morning, and thank you for joining us. On today's call, I will review our third quarter results, outline our continued progress across key strategic initiatives and discuss our outlook for the fourth quarter and our preliminary plans for 2026. This year's macro environment has remained challenging, characterized by heightened volatility and uncertainty in commodity prices, largely driven by shifting trade policies and geopolitical tensions. While these external factors have created headwinds for the industry, they also underscore the progress that we've made at APA over the past 2 years. At the core of these efforts is a strong focus on lowering our controllable spend, which is delivering meaningful and sustainable improvements in our cost structure. Additionally, through disciplined capital allocation, a reshaped and more resilient portfolio and a sharper operational focus, we've built a stronger, more adaptable organization, one that can perform through cycles and respond quickly to changing market conditions. Our strategy is working, and the benefits are increasingly evident across both our operations and financial performance. With a stronger foundation in place, APA is well positioned to navigate any oil price environment for 2026. Turning to the third quarter. Results were once again very strong across the board. We have exceeded our production guidance in each of our operating areas, while capital investment and operating costs were below guidance. In the Permian, continued strong operational execution resulted in oil production above guidance, while capital investment and operating costs were in line with expectations. Moving to Egypt. In addition to the significant acreage award we previously discussed, we also received substantial payments during the third quarter, nearly eliminating our past due receivables. This progress reflects the strength of our partnership with the Egyptian government. Operationally, once again, gross BOEs grew sequentially in Egypt, underpinned by the ongoing success of our gas program. This reflects both strong well performance and continued optimization of infrastructure. On the oil side, our waterflood and recompletions programs are moderating our base decline and flattening our near-term gross oil production. In the North Sea, our continued focus on operating efficiency and cost management drove higher production and lower costs compared to our guidance. We remain focused on optimizing our late-life operations and are preparing to decommission our assets in a safe, efficient and environmentally responsible manner. Finally, in Suriname, progress at GranMorgu continues at pace and first oil remains on track for mid-2028. Moving to our outlook for the fourth quarter. In the Permian, following another strong quarter of operational execution, we are raising our guidance for oil production while maintaining our outlook for capital spend. On the gas side, with the recent dislocation in Waha pricing, we are adjusting our guidance to reflect temporary curtailments in the field. Although this slightly reduces our BOE volumes, the impact to free cash flow will be minimal. In Egypt, we are slightly increasing our fourth quarter production estimates in line with the ongoing momentum from our gas program. We are also drilling several high-potential exploration wells, including on our newly acquired acreage. The Western Desert presents a vast and highly prospective opportunity set. And although we are early in our gas exploration program, success here could be impactful for our portfolio. Turning now to our cost reduction initiatives. Our commitment to reducing every aspect of our controllable spend has been evident all year, and I want to recognize the diligence of our teams and the strong alignment among leaders across the organization. Through their collective efforts, we've made significant changes to our operations and driven meaningful improvements in both capital and operational efficiency. We are now on track to realize $300 million in savings this year and are also positioned to reach our run rate savings target of $350 million by the end of 2025, 2 full years ahead of the original goal of year-end 2027. Looking ahead, we see significant opportunity to build on this momentum, driving additional efficiency gains and further simplifying how we work. Through these efforts, we aim to deliver an additional $50 million to $100 million in combined run rate savings across G&A, capital and LOE by the end of next year. Moving to our preliminary plans for 2026. With the recent volatility in oil prices, we are evaluating multiple capital allocation scenarios with a focus on free cash flow generation. While we have significantly improved our cost structure and reduced breakevens across our asset base in the last 18 months, we believe a flexible approach to capital investment is warranted in the current price environment. In the Permian, at our current pace of 5 rigs, we expect to deliver consistent year-over-year oil production of approximately 120,000 barrels per day, with capital investment of around $1.3 billion. However, if oil prices move lower, we have the operational flexibility to moderate activity to reduce capital further with minimal expected impact on 2026 oil volumes. In Egypt, we plan to maintain consistent activity levels and capital spend with a similar allocation between oil and gas drilling as this year. This would allow us to grow gas volumes on a gross basis year-over-year, gross oil production will remain on a modest decline. We will continue to monitor commodity prices over the coming months, and we'll provide formal guidance for 2026 in February. In closing, our third quarter results underscored the strong operational performance and consistent execution across all operating areas. Through the rigorous focus of our teams, we are driving significant cost savings ahead of schedule and increasing our targets for the future. As we head into 2026, we will remain disciplined in our capital allocation and continue prioritizing free cash flow generation. With that, I will turn it over to Ben.

Thank you, John. For the third quarter, under generally accepted accounting principles, APA reported consolidated net income of $205 million or $0.57 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $148 million unrealized loss on derivatives. Excluding this and other smaller items, adjusted net income for the third quarter was $332 million or $0.93 per share. LOE came in below guidance, largely due to ongoing cost savings, primarily in the North Sea. G&A was in line with guidance despite a larger-than-expected impact from mark-to-market adjustments related to stock compensation. On an underlying basis, G&A was approximately $15 million below guidance. We continue to progress multiple initiatives across all categories of G&A and expect this momentum to carry into 2026. Current income tax expense was lower than anticipated, primarily due to a change in our projected 2025 corporate alternative minimum tax. New guidelines issued by the U.S. Treasury late in the quarter clarified the treatment of net operating losses and depreciation deductions under the minimum tax framework. As a result, we now expect to owe little to no U.S. taxes in 2025 and 2026. Overall, this was an excellent quarter during which APA generated $339 million of free cash flow and returned $154 million to investors through dividends and share buybacks. During the quarter, net debt was reduced by approximately $430 million through a combination of free cash flow generation and payments from Egypt. This balance sheet progress has enabled us to realize net financing cost savings, excluding gains on the extinguishment of debt of $75 million so far in 2025 when compared to the same period in 2024. We ended the quarter with $475 million in cash, providing financial flexibility as we enter 2026. This gives us the ability to opportunistically repurchase debt, address upcoming maturities and thoughtfully manage the timing and execution of our decommissioning and asset retirement obligations. Turning now to our cost reduction initiatives. John already covered our progress to date and outlined the targets we've set for 2026. So I'll focus on the key movements in our 2025 guidance for controllable spend items relative to the $300 million of savings we expect to achieve this year. While these savings are reflected in our guidance for LOE and G&A, there are a few offsetting effects within capital. Since issuing our initial 2025 capital guidance in February, our teams have identified and implemented an additional $210 million in cost reduction opportunities, primarily in the Permian. Over the same time frame, our capital budget has been reduced by $150 million. This results in a $60 million difference between the change in our full year capital guidance and the change in capital cost savings since the beginning of the year. The largest portion of this variance is attributable to capital investments and LOE reduction initiatives. As highlighted last quarter, we identified several high-impact projects aimed at sustainably lowering future Permian operating costs, such as building saltwater disposal systems, consolidating field compression and other facility optimization projects. Capital is being directed toward these efforts, which are expected to generate strong returns with short payback periods and position us for structural operating cost improvements in 2026 and beyond. Another component of this difference is activity related, which primarily relates to the completion of 2 DUCs at Alpine High this quarter. Shifting to our oil and gas trading portfolio, which has been a meaningful and relatively steady contributor to free cash flow generation this year. Based on current strip pricing, we expect $630 million in pretax income from our trading activities for 2025. To enhance cash flow certainty heading into next year, we have added to our 2026 hedge positions. Currently, about 1/3 of next year's gas transport position is hedged, locking in roughly $140 million of cash flow. Turning to our asset retirement and decommissioning obligations. Our goal is to reduce these liabilities through a prudent approach that balances operational efficiency with financial discipline. As an example, during the third quarter, we identified a well at one of the fields in the Gulf of America that required decommissioning. Rather than mobilizing a vessel for a single well and returning later to complete the remaining work, we chose to decommission the entire field of 5 wells in a single campaign. This enabled us to capture meaningful operational efficiencies and reduce the total cost that would have been incurred over time. We have identified similar opportunities to execute during the fourth quarter, which led us to increase our full year 2025 ARO and decommissioning spend guidance by $20 million. Going forward, we will continue to pursue similar initiatives, proactively managing these liabilities in a way that is both operationally efficient and financially sound. For 2026, we expect our combined ARO and decommissioning spend to increase, reflecting a decline in spending in the Gulf of America, offset by higher planned activity in the North Sea. As a reminder, APA receives a 40% tax benefit on all decommissioning spend incurred in the North Sea. Therefore, on an after-tax basis, our total spend will increase year-over-year by roughly $55 million. In closing, as we enter 2026, our priorities remain centered on disciplined capital allocation, further cost reductions and continuing to strengthen the balance sheet. Our development capital, inclusive of approximately $250 million for Suriname development is expected to be 10% lower than 2025, reflecting improved capital efficiency across our portfolio. This preliminary plan positions APA to sustain Permian oil production, deliver continued gas growth in Egypt and advance the world-class opportunity we're developing in Suriname Block 58. Together with our ongoing focus on reducing controllable spend, these actions further strengthen our foundation for durable free cash flow generation and long-term value creation. With that, I will turn the call back to the operator for Q&A.

So the capital guidance appears to fall short of market expectations for next year. However, John, could you provide some insight into the flexibility you mentioned? We'll see how oil prices fluctuate, but what kind of flexibility do you have? A few years ago, when oil prices dropped, you allowed your Permian production to decrease. It seems that’s not the case this time. Is it related to managing drilled but uncompleted wells? Is it about drilling without completion? Can you explain where this flexibility lies regarding the projected sub-$2.2 billion capital expenditure for next year?

Yes, that's a great question, Doug. To begin with, our approach for 2026 is centered around maintaining strict capital discipline. As you noted, we have some flexibility if oil prices decrease. Currently, we plan to keep our Permian oil production at around 120,000 while also increasing our BOEs in Egypt, primarily driven by gas, and continuing to invest in Suriname and various exploration efforts, along with our decommissioning and asset retirement obligations. Development capital expenditures are down by 10%, mostly due to Egypt, while expenditures in the U.S. Permian remain stable. We're also committed to identifying cost-saving opportunities. If market conditions worsen, we can adjust our operations, like reducing the number of active rigs in Permian or Egypt if necessary. Overall, we are in a strong position with a good range and cushion concerning current oil prices, and there is room for flexibility.

I appreciate that. My follow-up is on Egypt. You seem to consistently exceed your gas guidance. However, there have been discussions and questions regarding the legacy accelerated cost recovery from when you re-signed the contract. I'm curious about how significant the impact might be on cash flow in 2026 as these legacy costs phase out. Ben, is there any way to summarize the potential impact on that in relation to your increasing gas production?

Sure. When we updated the contract about four years ago, we arranged for the recovery of a backlog of costs amounting to approximately $900 million. This has provided us with about $45 million each quarter. After the first quarter of next year, we will see that $45 million decrease, but we won't lose the entire amount since the contract structure absorbs part of it. Specifically, we will retain around 30% of it on the profit oil side, making our effective amount closer to about $30 million on a 3/3 basis. For our two-thirds interest, this translates to a cash flow impact of about $20 million each quarter. Therefore, for the next year, considering we still have it until the first quarter, we anticipate roughly $60 million in Egypt for three quarters. However, we believe various factors will help offset this, including ongoing capital efficiencies in Egypt, which have already shown improvement this year. While much of the focus has been on the Permian, we've made significant progress with capital management in Egypt. There is potential for that trend to continue next year regarding both capital expenses and lease operating expenses. Additionally, we expect continued success in gas production and other oil projects. It's important not to overlook what we've achieved in the second half of this year with our oil program and the potential for that momentum to carry into next year. Overall, there are several factors that may offset the $60 million cash flow impact in Egypt.

Yes. And the only thing I'd add, Doug, if you step back and think about it, removing that backlog now is a good thing financially. We've got our past dues down, lowest they've been. It really underscores the investment environment we have in Egypt, just how good things are because we've been able to capture basically the PDRs and the backlog now and shows the success in the modernization process.

And the balance sheet has seen the benefit of that, guys.

I was just following up on Doug's question on 2026 capital. I appreciate all the color you all are providing on the call. It seems like the other kind of lever you all got depending on commodity prices on the budget would be the exploration capital. And unless I missed it, I didn't hear any sort of commentary on that. Just how we should think about that relative to the $65 million you're spending this year?

Yes, John, I think going in, just by nature of the way the program is setting up, '26 is going to be a pretty light year exploration-wise for us. We could get into building some ice roads in Alaska late next winter as you prep for what would be really more in '27 as well as timing of the Suriname potential exploration wells that could pop into late next year. But in general, '26 is likely going to be a fairly light year exploration-wise for us.

Got it. And then my other question, obviously, you all continue to increase the realized and projected savings and also an accelerated timeline. And when I just look at how much progress you all made from the update with 2Q results, I'm just looking for any more specifics on just to see that big of an improvement, both on the realized savings as well as the sort of run rate targets for that much to happen since 2Q. Just any specifics you all can point to, to drive that?

Yes. I'll just say if you step back from where we were in February and you look at the progress, 2 places, right? G&A, we've been able to do more than we thought. Obviously, that's something we directly control. But the other place has been the capital side, and that's been driven mainly by Permian. So to think where we are, we started out in February, thinking we'd realized in calendar year '25, $60 million. And to now know we're at $300 million. And obviously, we set out a 3-year target of the $350 million by the end of '27 to get there by the end of '25. Very, very proud of the entire organization because we've just been razor-focused on what do we do on the cost side, and you're seeing that show up. But I'll let Ben provide a little bit of color. We've added by year-end '26 now another $50 million to $100 million to that. But I'll let Ben jump in and give some more color.

Sure. So John, when you consider what we've accomplished this year, it's clear we've made significant progress on the capital front, along with general and administrative expenses. This pertains to both our current achievements and the projected $350 million run rate. Most of that will come from capital and G&A, with some expected from the run rate on lease operating expenses. For the additional $50 million to $100 million, a large portion will come from G&A and lease operating expenses. While capital will also contribute, given its substantial impact in 2025, much of the upcoming incremental amount by the end of next year will primarily stem from G&A initiatives and lease operating expenses.

I'm interested in Egypt gas. Clearly, things are going well for you. I believe you are operating around 8 rigs in the gas segment. Regarding the new terms for gas pricing, is there any limit on gas growth? Could you provide an estimate of where you think gas production might reach in the next year or two?

Yes, Scott. If you take a step back and see where we stand, we are currently operating 12 rigs in Egypt, with 3 of them focused on gas instead of 8, which means we are utilizing just a quarter of the program. Reflecting on our progress since we signed this contract a year ago, we have surpassed all internal expectations, contributing significantly to the success of the program and the effective delivery of wells. Importantly, we have been able to integrate operations without reducing lower pressure gas. The team has performed exceptionally well, and we plan to maintain this momentum into next year. Long-term growth will depend on the success of our exploration efforts, particularly since we have been searching for oil in the Western Desert for three decades and have only just begun exploring for gas over the past year. Our outlook heavily relies on the results of our exploration program. However, we are gaining momentum and anticipate year-over-year growth in gas production. Additionally, we have processing capacity that we may need to utilize based on where we find success. We are truly just beginning, and we are enthusiastic about the long-term potential for gas.

Yes. But specifically, I think your agreement on the pricing is basically everything over above a predetermined PDP. And I'm just kind of curious, is there any upper limit to that? Or is it all premium priced over and above that going forward?

Everything that we bring on new gas gets new gas price. And so I mean, even if we were just to hold gas flat, our gas price is going to grow as that the old PDP decline curve kicks in. So we're sitting in a good place price-wise. And quite frankly, we're excited about the inventory, but we just need to drill some exploration wells.

Got it. And then if I could turn to a question on the Permian. I think you all are working on a potential inventory update assessment, hopefully, by early next year. Can you give us a sense of like what are you thinking as well about some of the deeper potential? There's been a number of like Barnett and Woodford being targeted by some of your peers in the Midland. Is there a good amount of overlap with that with you all?

Yes, if you take a step back, we started drilling Barnett and Woodford wells as early as 2016 and 2017, so we have a solid understanding of that. There is some overlap with our positions. Our current plan is to return to the market in the first quarter of 2026 with an update after we have completed an updated assessment. This process involves many nuances, and Steve can provide additional insights. We are confident in our core development opportunities and inventory, consistent with our current drilling activities, and we expect to continue this well into the early 2030s.

Yes. This year, we've achieved notable gains in capital efficiency in the Permian, which is positively impacting our inventory levels. As a result, we are reevaluating our spacing and frac size strategies. The efficiency improvements prompt us to reassess everything in our inventory, not just what's new, but also our existing holdings and the Callon acreage along with other properties we've acquired over the years. Every undrilled landing zone and potential new zones are being thoroughly reviewed due to these significant efficiency gains. A lower cost of drilling and completing a well allows us to access more resources, which is crucial for our inventory levels. There is extensive work happening around this.

John, it sounds like you're fairly cautious on the oil macro like a lot of your peers. I want to get your thoughts on the dynamics there. And you mentioned you're hedging more gas. I just want to get your updated thoughts on potentially hedging oil.

Yes. I just think, Mike, going in with all the progress we've made on the cost structure and clearly, we've got a WTI price that's been sitting around $60, it's prudent to be cautious. And so we're going into '26 with a disciplined mindset. And like always, we've set ourselves up with the improvements in the controllable spend and the cost structure and the balance sheet, we're in a really, really good place. And the last thing you want to be trying to do is accelerate inventory into an oil market like we sit in today. So in terms of the hedging, not really hedging gas, Ben can jump in at some of the transport and locking in some of those gains there, but I'll let Ben make a few comments on the gas transport hedges.

Sure. We are looking to secure cash flow from the Waha to Houston Ship Channel and Waha to NYMEX, Henry Hub differentials and plan to carry that into next year. There's a contango curve on the NYMEX side, but a significant differential remains between the Ship Channel, Henry Hub, and Waha. By locking this in, we ensure a reliable cash flow. Currently, we're only hedged for one-third of it. If the differential continues to widen, we would benefit from the unhedged volumes. We believe it's wise to secure a certain amount of cash flow, which we did this year. Compared to hedging in the oil market, which is either flat or backwardated, it seemed more sensible to secure cash flow on the transport side rather than locking in oil hedges, as we have more flexibility in managing our portfolio. However, if the right opportunity arises in the oil market, we could act on that more opportunistically while focusing on gas.

Makes sense. Appreciate that detail. I think you said last quarter, you breakeven now in the Delaware is kind of in the low 50s. Is that where you would kind of pull the trigger and pull back on Permian activity? What would that look like? Would you just build DUCs through that? Or would you actually drop rigs?

I think we have a lot of flexibility, Mike. It will depend on our situation. If we look at Delaware breakevens, they are in the low 50s, while Midland is in the mid- to low 30s. So, it really depends on where we are and what we believe makes the most sense. The main point is that we have a lot of flexibility with the program.

So you could potentially move rigs if prices went in that direction and pause on the other side.

Move or drop if needed to be, right? Yes, move or drop.

I want to go back to Egypt, if I may. The 2 million acres that you guys picked up most recently, I think I heard you say in your prepared comments, you're actually drilling some exploratory wells on that new position. But could you add to the picture about what's available on these 2 million acres? And I'm thinking how much of it do you have seismic over? How much of their other more simple things like how much do you have road access to midstream, that sort of thing? And all with an aim of when that's going to start to be able to work into your capital budget and delivering for you guys?

No, it's a great question. If you look back, we've shown that 2 million acres spans a lot of the desert and fits well with our existing footprint. We have access to it, and it can mostly be connected to our infrastructure. There is both oil and gas potential, and we're already pursuing it. We're very excited about it. I believe there is some easy-to-reach opportunity on that acreage that we're targeting. A lot of it will depend on what we discover and where it's located, as well as what needs to be done to connect it. Some areas may require us to build jumper lines or other connections to our facilities, but not all. Much of it is relatively close to our existing operations, so it integrates well. I would say it's highly promising, and we're actively working on it, looking forward to providing updates in the future. Steve, do you have anything to add?

Yes, we have actually created a map that shows both the old acreage and the new acreage, including the infrastructure. This might have been in the second quarter supplement. If you look at that map, you'll notice two key points. First, the acreage is not concentrated in one large area; instead, it is distributed across various locations. Some of this acreage can be classified as a straightforward step-out from what we are developing next door, while there are also areas indicating new exploration opportunities. Our exploration efforts across this acreage will encompass a wide range of activities, from lower-risk step-outs to new concept developments. Additionally, there is minimal gap in access to infrastructure or nearby activity throughout most of this acreage, except for a few areas where current Apache operations are located nearby.

Got it. For the follow-up on Egypt gas, on Slide 3 you mentioned that with the new pricing arrangement, gas development is aligned with mid-cycle Brent. Could you please elaborate on the assumptions involved? Specifically, what your mid-cycle Brent assumption is and what you mean by parity, whether that refers to internal rate of return or other factors that contribute to that statement?

We have an arrangement where we sell all the gas we produce to Egypt at a fixed price for both the new and old gas tranches. The new tranches have a higher fixed price, and as the production declines on the old price of gas, the price will gradually increase with the new volumes. Essentially, the new gas pricing is equivalent to a $75 to $80 Brent price for oil drilling in Egypt. This means we can drill for gas at a fixed price comparable to $75 to $80 Brent oil on land that is close to where we could drill for oil wells.

John or Ben, I am curious about your program for 2026 and maintaining a production level of 120,000 barrels a day with five rigs. Are you anticipating any additional benefits regarding drilling and completion costs, considering the significant progress you have made? Is there any reason you couldn't set a drilling and completion target that competes with the best peers in the Delaware for the upcoming year?

And I think we're making great progress. And if you look, part of the carry-through into '26 is the savings that we think are real in the progress we're making. So as Ben said, we're going to add another $50 million to $100 million of savings in '26. Some of that's going to be on capital. But I'll let Steve jump in a little bit in terms of the progress we're making on the capital side and where we think we sit.

Yes. I believe we mentioned this during the second quarter earnings call. In the Midland Basin, we feel we are approaching best-in-class performance in terms of drilling and completion. In the Delaware Basin, we are likely around the average compared to our peers, indicating there is still room for improvement. When considering the five rigs maintaining volumes steady in relation to 2025, which is 120,000 barrels of oil a day, there are factors that support our ability to operate five rigs. While we previously indicated that six rigs would keep Permian production relatively flat around 120,000 barrels, we are currently not asserting that five rigs will achieve the same. We now believe that six rigs is likely necessary. However, we’ve made considerable progress recently concerning base uptime and volume uptime, which has helped reduce the underlying decline rate slightly, benefiting our transition into 2026. There are facilities currently constrained, and while we have recently brought on new wells, their production capacity is somewhat limited; this should improve as we move into 2026. Additionally, there will be a minor reduction in our DUC (drilled but uncompleted) count, approximately five fewer by the end of 2026 compared to the beginning. Our development capital for the Permian this year, adjusted to exclude sales, is about $1.45 billion. Next year, that is projected to drop to $1.3 billion. The $1.45 billion figure includes roughly $200 million in savings we have realized in 2025, with another $150 million in savings expected as we progress through 2026. This projection is influenced by the savings we have achieved thus far and involves additional planned reductions moving forward. Most of these savings will likely come from the Delaware Basin, though we remain optimistic about further advancements in the Midland Basin as well. This budget also accounts for the reduction to five rigs, down from six previously operated.

I appreciate all the additional information, Steve. My follow-up question is about the North Sea. You mentioned the tax benefits, particularly for 2026. Are you accelerating the ARO activity in the North Sea? What do you see as the results or impacts on the production side of that asset in the coming years?

Yes. Regarding production, as we mentioned earlier this year, with minimal investment in the asset and considering the various government changes, we anticipate production to continue declining from 2025 into 2026, likely by 15% to 20%. This seems like a reasonable estimate from a production perspective. On the tax front, much of that depends on whether there is taxable income in the U.K., but we do expect tax savings due to the increase in our ARO spending next year, which is benefitted by the government covering 40% of that ARO. We discussed this increase when we announced our COP last year, and it will continue to grow next year. However, the after-tax cash flow impact from all ARO and decommissioning spending year-over-year is only $55 million, which is manageable within our overall corporate profile. So, while the taxable net income from the U.K. is dependent on prices, there will be savings from ARO expenditures.

Yes. To be clear, we are not accelerating activity in 2026. This plan has been in place for quite some time and primarily involves a well abandonment program at Beryl Bravo, as well as starting a subsea well abandonment program that will continue for several years. Therefore, there is no acceleration of any activity.

I want to ask about non-D&C CapEx. Ben, you talked about repurposing some of the CapEx savings this year into infrastructure investment and LOE reduction initiatives. Are there other opportunities along that line? And how should we be thinking about the benefit of these investments?

For this year, I mentioned the $60 million difference between captured savings and our capital guidance. About one-third of that was invested in the LOE projects we began this year. We expect this trend to continue next year as we discover new opportunities. Most of the investment relates to facilities, compression, and other areas I previously mentioned. We will keep investing capital in these projects, which will result in ongoing LOE savings. When considering the total capital amounts—$1.45 billion for the Permian this year and $1.3 billion next year—$20 million on the $1.3 billion base is a relatively small portion, but it will contribute to our LOE efforts. Our teams are addressing LOE from multiple angles, not only by finding ways to reduce it through capital investment but also by examining all components of our operating expenses in the field. This work is not limited to the Permian; we have made similar progress this year in the North Sea and Egypt. While I can't provide a specific per barrel savings metric, we do anticipate savings that will be staggered throughout 2026 and into 2027.

Yes. If I could just add a bit to that. Obviously, on LOE for 2025, we didn't capture the savings that we had hoped to capture this year at the corporate level. But there's some real success underneath that, that I think is worth mentioning. Most of the struggle has actually been in the Permian, and that's where most of the investment that Ben is talking about around consolidating compression and rationalizing that and around produced water disposal wells and things like that. That's going to be targeting LOE primarily, not entirely, but primarily in the Permian Basin. And those are investments that we're going to be beginning this year. There will be more in next year, and you'll see the benefit of those probably showing up in the second half of next year. But I did want to highlight, in particular, the North Sea, significant progress in reducing offshore operating costs this year, and that's kind of hidden in what's going on in LOE and some very good progress in Egypt as well without any meaningful amount of capital spend.

Got it. No, that's really helpful information. My follow-up is regarding the ARO. The net $50 million difference suggests that the headline ARO is up close to $100 million, which appears to be higher than our previous expectations for 2026. Can you provide some insight into how we are progressing on ARO spending over the next few years? Should we maintain that spending level in the North Sea beyond 2026?

Yes. We will likely wait until next year, probably in the first quarter, to provide a multiyear outlook and do a portfolio update. We have mentioned the increase in the Asset Retirement Obligation (ARO), especially in the North Sea. Additionally, we indicated that the Gulf of America is expected to perform better this year compared to previous years, and that trend is expected to continue into the future. For next year, we anticipate the Gulf of America will decrease significantly to around $100 million to $120 million, which is typical for our legacy non-operated assets as well as the older Fieldwood assets. This should stabilize and remain steady even after 2026. Regarding the North Sea, as previously mentioned by Steve, the impact in 2025 will be minimal, approximately $30 million this year. However, it will grow to about $600 million of our after-tax ARO from now until 2030. An additional $600 million will be allocated between 2031 and gradually decrease until 2038. We will offer further details on 2027 and 2028 potentially, and you are correct that next year’s increase should be in the mid- to high 200s, with the after-tax impact for us being only $55 million.

Yes. Ben mentioned some details about the projected ARO spending in the North Sea that I discussed during a previous earnings call. The outline for spending starting in 2026 and extending into the 2030s remains consistent. It will increase until it peaks around 2030, after which it will begin to decline. The primary focus will be on well abandonment in the first half and on facility platform and subsea infrastructure in the latter half.

Got it. Just to confirm, does the $55 million already include the normalization of the lower Gulf of Goa decommissioning spend?

That's correct.

Ben, you mentioned that the U.S. cash tax will be zero for this year and next year. Do you have any rough estimates for what that might look like from 2027 to 2030?

Yes. Currently, Paul, our focus has been on this year and next year. We've made significant progress regarding taxes and achieved notable savings. Looking beyond 2026, many of the changes we've highlighted this quarter are related to the corporate alternative minimum tax guidelines and less about the OBBB impact we discussed in August. As we approach 2027 and 2028, we will need further guidance on interpreting the OBBB. However, the goal is to fully benefit from IDCs and bonus depreciation, which should bring U.S. taxes close to zero. We are working closely with our tax team on this, but that is the expected outcome of the legislation, and we believe it could yield ongoing benefits after 2026. For now, we have outlined the benefits expected for this year and next year.

Yes. No, it's a good question. And what we said, Paul, was we're in the process right now literally of reprocessing multiple surveys to come back with what is the next steps in terms of appraisal at Sockeye and exploration. So right now, we're doing technical work. The teams are working away, and we're reprocessing the seismic. We've got 2 really nice discoveries, and we're kind of stitching together a lot of the seismic surveys so we can come back with the next steps. So we'll come back at some point. But right now, we just said actually next year, there won't be any winter drilling this year. Obviously, we'd be getting ready for that now, but it will likely be next winter, which is why late next year, we're likely to be building some ice roads as we bring a rig back. But we'll update you once we've kind of worked through what are the next steps in terms of appraisal and exploration, but we are excited about Alaska.

Just on the exploration front, it sounds like not a lot of capital next year. Can you give us kind of an update on Uruguay? And then also just curious on the decision to bring some DUCs on in Alpine High and what seems like a bit of a challenged to Waha market here of late.

Yes. So just 2 things, Leo. Number one, in Uruguay, we actually have a data room open. We've been showing that externally. There's been a lot of industry interest in our Uruguay program. And so we'll have an update at some point, but don't have anything to announce today on that. And then the 2 completions, the 2 DUCs we completed at Alpine were purely acreage retention. There were wells we drilled. We needed to go ahead and complete those. We've actually got a better Waha price now. So the economics look really good. But it's about preserving optionality and holding acreage in the future.

Yes, regarding the timing of bringing those DUCs online, we see a spike in production in December, January, and February, with Waha prices well above $2. Therefore, the timing appears optimal. However, the primary reason for this action, as mentioned by John, is to retain some acreage. With the increased production and favorable economics, this approach allows us to keep our options open for the future.

Okay. And just on the capital for '26, I just wanted to kind of square everything in the circle here. So it sounds like development CapEx down 10% year-over-year, exploration CapEx down a little bit. ARO spend, you talked about up kind of $55 million after tax. Is there anything else like infrastructure or anything like that, that might kind of be a final moving part? And just any kind of thoughts on changes for that next year?

That really summarizes the key points. Any spending on infrastructure will be included in the development capital. Additionally, our marketing book is currently in the low to mid-400s as we look at the upcoming year. This indicates another strong year for our marketing book, which includes both transport and LNG. Overall, I believe we have addressed most of the major items.

Thank you. Our strong results year-to-date have been underpinned by remarkable performance across our entire business. This underscores confidence in our plan and creates positive momentum going into 2026. The capture of meaningful cost savings has improved our free cash flow profile, enhanced our investment opportunities and added inventory to our portfolio. Our efforts to rigorously improve our cost structure will continue, and we are now targeting an additional $50 million to $100 million in run rate savings by the end of 2026. We continue to benefit from our diversified portfolio with a step change in capital efficiency in the Permian, strong momentum with Egypt gas and the GranMorgu project in Suriname progressing on schedule. Lastly, we remain very optimistic on the impact our exploration portfolio can have on our future. With that, I will turn the call back over to the operator, and thank you very much for joining us today.