APA - Earnings Call - Q3 2025

Executive Summary

• APA delivered adjusted EPS of $0.93, a clear beat versus Wall Street consensus of $0.79, on revenues of $2.12B modestly above consensus of $2.11B; adjusted EBITDAX of $1.35B underscored strong cost execution even as S&P Global EBITDA tracked slightly below consensus ($1.18B vs $1.20B)*.
• Management accelerated cost-reduction milestones, targeting $350M run-rate controllable spend savings by YE 2025 (two years sooner), raised 2025 realized savings to $300M (from $200M), and reduced net debt by ~$431M in the quarter to ~$$4.0B.
• Q4 guidance was raised for U.S. oil production to 123 kbpd and for Egypt gross gas growth; Q4 upstream capital remains ~$440M (unchanged), supporting free cash flow preservation into 2026.
• CFO expects “little to no U.S. taxes” in 2025–2026 following CAMT guidance changes—an incremental free cash flow tailwind and a stock-reaction catalyst, alongside continued Egypt gas outperformance and visible balance sheet deleveraging.

What Went Well and What Went Wrong

• What Went Well

  • Exceeded production guidance in all regions; U.S. oil production reached 121 kbpd on strong Permian execution; adjusted production was 387 mboe/d.
  • Accelerated cost program: “We expect to achieve $350 million in run-rate controllable spend savings by year-end 2025, two years sooner than initially anticipated,” with added $50–$100M targeted by YE 2026.
  • Balance sheet progress: “Reduced net debt by approximately $430 million,” returned $154M to shareholders (dividends and buybacks); FCF was $339M.
  • CFO: “We now expect to owe little to no U.S. taxes in 2025 and 2026,” boosting after-tax cash generation.

• What Went Wrong

  • Derivative mark-to-market: $148M unrealized derivative loss in Q3 weighed on GAAP EPS ($0.57) even as adjusted EPS was strong.
  • Waha basis dislocation led to curtailments (~20 MMcf/d gas and ~1.4 kbpd NGLs), and LOE savings at the corporate level lagged 2025 hopes, with North Sea/Permian initiatives offsetting over time.
  • YoY revenue decline on commodity backdrop: Total revenues fell to $2.12B vs $2.53B in Q3’24; GAAP EPS improved from (-$0.60) to $0.57, but net income margin compression vs Q2’25 reflects price/derivative dynamics.
  • ARO/decommissioning spend increased by $20M for 2025; 2026 after-tax ARO/DCOM cash impact expected to be ~$55M higher YoY, albeit manageable.

Transcript

Operator (participant)

Good day, and thank you for standing by. Welcome to APA Corporation's Third Quarter Financial and Operational Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you'll need to press star 11 on your telephone. You'll then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Stéphane Aka, Managing Director of Investor Relations. Please go ahead.

Stéphane Aka (Managing Director of Investor Relations)

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 Rogers, CFO, will then provide further color on our results and outlook. Steve Riney, President, and Tracy Henderson, Executive Vice President of Exploration, are also on the call and available to answer questions. We will start with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our financial and operational supplement, which can be found on our investor relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax payers. I would 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. With that, I will turn the call over to John.

John Christmann (CEO)

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 two 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 oil performance and continued optimization of infrastructure. On the oil side, our water flood 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-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, two 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-$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 break-evens 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 five 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 will provide formal guidance for 2026 in February. In closing, our third quarter results underscored 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.

Ben Rodgers (EVP and CFO)

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 timeframe, 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 in 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 two ducts 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 pre-tax 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 a third 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 Mexico 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 five 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 Mexico, 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.

Operator (participant)

Thank you. At this time, we'll conduct the question and answer session. As a reminder, to ask a question, you'll need to press Star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press Star 11 again. Please limit yourself to one question and one follow-up. Please stand by while we compile our Q&A roster. Your first question comes from the line of Doug Leggett with Wolfe Research. Your line is now open.

Doug Leggett (Managing Director and Senior Research Analyst)

Thanks. Good morning, guys. The capital guide, I think, puts you below street for next year. I'm curious, John, if you could offer a little bit of color on the flexibility you suggested. We'll see where oil ends up. What's the nature of the flexibility you have? I think a few years ago, when oil prices collapsed, you allowed your Permian production to decline. Sounds like that's not the case this time. Is that a duck manipulation? Is it drilling but not completing? Can you walk us through where the flexibility is against what looks like a kind of sub-$2.2 billion CapEx number now for next year?

John Christmann (CEO)

Yeah. Great question, Doug. I'll just start out with just in general, our mindset going into 2026 is focused on capital discipline. As you point out, we've got flexibility if oil prices move lower. Today, we envision a plan that's going to maintain Permian oil at about $120. While we're growing our BOEs in Egypt, driven by gas, and still funding our Suriname and other exploration, as well as our decom and our ARO. Development CapEx is down 10%. That's mainly in Egypt, mainly in the U.S. Permian, with CapEx in Egypt being flat. I think the other factor is we're going to continue to focus on the cost savings. Clearly. If things soften, as we've mentioned, there is room. We could always decide to drop more rigs in Permian or Egypt if need be. I think we're in a good place with a pretty good range and a pretty good cushion right now on oil price. There is flexibility.

Doug Leggett (Managing Director and Senior Research Analyst)

Okay. I appreciate that. My follow-up is actually on Egypt. I mean, obviously, you continue—it's almost like a beat and raise on your gas guidance. But there is some—I guess there's been some discussions from certainly questions we've been getting about the legacy accelerated cost recovery from when you resigned the contract and what happens to how big a delta that could be on cash flow in 2026 as those legacy costs roll over. I don't know if there's any way, Ben, to—I know it's complicated. There are a lot of moving parts. Is there any way to kind of summarize what the potential delta could be on that in the context of your rising gas production?

Ben Rodgers (EVP and CFO)

Sure. When we modernized the contract about four years ago, we negotiated a recovery of a backlog of costs, and that was around $900 million. Per quarter, we've had the benefit of about $45 million. When that rolls off after the first quarter of next year, that $45 million—let me break it down—is the total number. We do not lose all of that, though, because of the way the PSC works. We only lose about 70% of it, with the other 30% being picked up on the profitable side. That $45 million is actually, on a three-thirds basis, closer to about $30 million. Net to our two-thirds interest, the cash flow impact on a quarterly basis is about $20 million. For next year, again, since we still have it through the first quarter, for three quarters next year, it is roughly $60 million in Egypt.

We think there are a number of different factors that we are working on to offset that, whether it is continued capital efficiencies in Egypt, because we have seen those this year. A lot of the discussion this year has been on the Permian, but Egypt has made great strides on the capital front. There is potential for that to continue next year on the cost side for both capital and LOE. We have expected continued success and performance on the gas side. Then other oil projects too. We should not look past what we have been able to do in the second half of this year on the oil program and the potential for some of that to carry into next year. A number of different factors, Doug, I think, are going to offset that $60 million, have the potential to offset that $60 million free cash flow impact in Egypt.

John Christmann (CEO)

The only thing I'd add, Doug, 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. It shows the success in the modernization process.

Doug Leggett (Managing Director and Senior Research Analyst)

The balance sheet's seen the benefit of that, guys. Thanks very much indeed.

John Christmann (CEO)

Thank you.

Operator (participant)

Thank you. Thank you. Your next question comes in the line of John Freeman with Raymond James. Your line is now open.

John Freeman (Managing Director of Exploration and Production Equity Research)

Good morning. Thank you. I was just following up on Doug's question on 2026 capital. Appreciate all the color y'all are providing on the call. It seems like the other kind of lever y'all have 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.

John Christmann (CEO)

Yeah, John, I think going in, just by nature of the way the program is setting up. 2026 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 2027, as well as timing of the Suriname potential exploration wells that could pop into late next year. In general, 2026 is likely going to be a fairly light year exploration-wise for us.

John Freeman (Managing Director of Exploration and Production Equity Research)

Got it. My other question, obviously, y'all continue to increase the real-time projected savings and also on an accelerated timeline. I just look at how much progress y'all made from the update with Q2 results. I'm just looking for any more that y'all could sort of give 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 Q2. Just any specifics y'all can point to to drive that.

John Christmann (CEO)

Yeah. I'll just say if you step back from where we were in February and you look at the progress. Two places, right? G&A, we've been able to do more than we thought. Obviously, that's something we directly control. The other place has been the capital side, and that's been driven mainly by Permian. To think where we are, we started out in February thinking we'd realize in calendar year 2025, $60 million, and to now know we're at $300 million. Obviously, we set out a three-year target of the $350 million by the end of 2027 to get there by the end of 2025. Very, very proud of the entire organization because we've just been razor-focused on what do we do on the cost side. You're seeing that show up. I'll let Ben provide a little bit of color. We've added by year-end 2026 now another $50 million-$100 million to that. But I'll let Ben jump in and give some more color.

Ben Rodgers (EVP and CFO)

Sure. John, when you think about what we've done this year, as you can see, huge strides made on the capital front, followed by G&A. That's in both what we're capturing this year as well as in that $350 million run rate. Most of that is in capital and in G&A, with some expected on the run rate on LOE. For that incremental $50 million-$100 million, actually, the bulk of that is going to come from G&A and LOE. I think capital is going to contribute some, because capital contributed so much in 2025. As you look to that $50 million-$100 million incremental by the end of next year, a lot of that's going to come on G&A initiatives as well as on the LOE front.

John Freeman (Managing Director of Exploration and Production Equity Research)

Thanks, guys. Well done.

John Christmann (CEO)

Thank you, John.

Operator (participant)

Thank you. Your next question comes to a line of Scott Hanold with RBC Capital Markets. Your line is now open.

Scott Hanold (Managing Director and US E&P Analyst)

Yeah. Thanks. Good morning. I'm interested in Egypt gas. Obviously. It's going well for y'all. I think you're running, if I'm not mistaken, around eight rigs on the gas side. Just with respect to the new terms that you have on the gas pricing, is there any unconstrained level on gas growth? Could you give us some sense of where you think gas production could go here over the next, say, year or two?

John Christmann (CEO)

Yeah. Scott, I mean, if you step back and look where we are, we're actually running 12 rigs in Egypt, and three of them right now are on gas, so instead of eight. Just a quarter of the program. If you look at where we are and you go back, I mean, we signed this contract a year ago. To look at the progress and just see where we are, we've exceeded all of our internal expectations. It's been really the success of the program, the delivery of the wells, and most importantly, the ability to get things tied in and not back out some lower pressure gas. The team has done a phenomenal job. We're going to continue on this trend well into next year. Longer term, it's going to be dictated by the success of the exploration program.

That is something we really—we have been exploring for oil in the Western Desert for three decades. We have now been exploring for gas for really one year and kind of just getting started on the exploration side. A lot of that is going to hinge on our exploration program. We have good momentum. We are going to grow year-over-year on gas. We do have processing capacity that we might need to pipe into depending on where we have success. We are really just getting started, and we are excited long-term about the gas potential.

Scott Hanold (Managing Director and US E&P Analyst)

Yeah. Specifically, I think your agreement on the pricing was basically everything over above a predetermined PDP. 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?

John Christmann (CEO)

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

Scott Hanold (Managing Director and US E&P Analyst)

Got it. 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 what you are thinking as well about some of the deeper potential? There has been a number of Barnett and Woodford being targeted by some of your peers in the Midland. Is there a good amount of overlap with that with y'all?

John Christmann (CEO)

Yeah. I mean, if you step back, I mean, we were drilling Barnett and Woodford wells back as early as 2016, 2017, right? I mean, we've got a good view on that. There is overlap into our positions. The plan at this point, as we've said, when we've done an updated characterization, and Steve can add some color on all the nuances as it becomes a very iterative process. I mean, we are planning to come back to the market first quarter of 2026 with an update. Today, we strongly believe in terms of core development opportunity and development inventory, consistent with what we're drilling today and into the next several years, we can do that well into the early 2030s.

Steve Riney (President)

Yeah. With the significant capital efficiency gains that we've been able to capture this year in the Permian, that's obviously having an iterative effect, as John would say, on the quantum of inventory. It's really requiring us to go back. We came into the year kind of rethinking a bit about our spacing and frac size philosophy. With the efficiency gains, that just causes us to rethink all of that all over again. We're coming through every bit of our inventory. It's not just a case of looking at what's in addition to what we already know. We're also going back and relooking and reexamining everything that we had in inventory to begin with, and also all of the Callon acreage as well and other acreage that we've acquired over the years.

Every single un-drilled landing zone and even new potential landing zones are being reviewed pretty extensively because of the significant efficiency gains. The lower you can drill and complete a well, cost-wise, the more resource you can access. That is a really important aspect of the quantum of inventory. There is a huge amount of work going on around that.

Ben Rodgers (EVP and CFO)

Thank you for that.

Operator (participant)

Thank you. Your next question comes to the line of Michael Scialla with Stephens. Your line is now opened.

Michael Scialla (Managing Director of Industrials and Energy Equity Research)

Good morning. 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. You mentioned you're hedging more. Gas. I just want to get your updated thoughts on potentially hedging oil.

John Christmann (CEO)

Yeah. 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. We're going into 2026 with a disciplined mindset. 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. The last thing you want to be trying to do is accelerate inventory into an oil market like we sit in today. 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. I'll let Ben make a few comments on the gas transport hedges.

Ben Rodgers (EVP and CFO)

Sure. Yeah. Just like we did this year, looking to lock in cash flow associated with Waha to Houston Ship Channel and Waha to NYMEX Henry Hub differential, carried that through into next year. As you know, there is a contango curve on the NYMEX side, but still a pretty wide differential between both Ship Channel and Henry Hub and Waha. Locking that in gives us surety of cash. We have only got a third of it hedged right now. Should that continue to widen, we would make it on the unhedged volumes. Just getting that certainty of a certain amount of cash flow, we thought was prudent. We did it this year. When you compare that to hedging on the oil side and either a flat to backward-dated market.

Just felt like more prudent to capture cash flow for the corporation on the transport side versus on the crude side when we've got a lot more optionality in our portfolio to manage versus locking in any type of oil hedges. Should the opportunity come up on the oil side, we could do that, just more opportunistic on the gas side.

Michael Scialla (Managing Director of Industrials and Energy Equity Research)

Makes sense. Appreciate that detail. I think you said last quarter you're break-even now, and 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 ducks through that, or would you actually drop rigs?

John Christmann (CEO)

I think a lot of it, we've got a lot of flexibility, Mike. It'll just depend on where we found ourselves, right? I mean, if you look at Delaware break-evens, yes, low $50s. Midlands in the mid to low $30s. A lot of that would just hinge on where we found ourselves and what we thought made the most sense. The key message there is lots of flexibility in terms of with the program.

Michael Scialla (Managing Director of Industrials and Energy Equity Research)

You could actually potentially. Is there room for you to move rigs if prices did go there that you would move them over to the Midland and kind of pause on Delaware?

John Christmann (CEO)

Move or drop if needed be, right? Yeah. Move or drop.

Michael Scialla (Managing Director of Industrials and Energy Equity Research)

Gotcha. Thanks, guys.

Operator (participant)

Thank you. Your next question comes to the line of Charles Meade with Johnson Rice. Your line is now open.

Charles Meade (Research Analyst)

Good morning, John. To you and your whole team there.

John Christmann (CEO)

Good morning, Charles.

Charles Meade (Research Analyst)

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. Could you add to the picture about what is available on these 2 million acres? I'm thinking how much of it do you have seismic over, how much are there other more simple things like how much do you have road access to, midstream, that sort of thing, 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?

John Christmann (CEO)

No, it's a great question. I mean, if you look back in the, we've shown that 2 million acres sits kind of across a lot of the desert, and it fits in nicely with our existing footprint. So, we do have access to it. It can be tied into infrastructure for the most part. I would say there is both oil and gas prospectivity. And we're kind of already getting after that. So we're very excited about it. I think there's some low-hanging fruit on that acreage that we're getting after. A lot of it's just going to hinge on, Charles, what we find and where it is, and then what do we need to do to tie it in. Some of it, we might need to build some jumper lines or things to our facilities, but not all of it.

A lot of it is pretty short arms reach away from our existing operation. So it fits nicely. I'd say it's highly prospective, and we're getting after it and look forward to updating in the future. Anything you want to add, Steve?

Steve Riney (President)

Yeah. I think we've actually published a map of that, of the old acreage with the new acreage. On the same map with the infrastructure overlaying that. I think if you—I think that might have been in the second quarter supplement even. If you take a look at that, you'll see two things. Number one is that the acreage is actually—it's not like one big chunk of acreage. It's spread out all over the place. There's some acreage in there that I would say I would kind of classify as just simple step-out type of stuff relative to what we're doing on the acreage right next door. It ranges all the way to some chunks of acreage that is even new play concepts that we're looking at.

The exploration that is going to go through all of that acreage is going to span the full range of types of exploration from kind of lower risk step-out to kind of new concept play opening. The other thing is that you'll see that there is not much of a gap anywhere in that acreage from nearby infrastructure or nearby activity, except for very few places. There is current APA activity going on near all of that acreage.

Charles Meade (Research Analyst)

Got it. Thank you for that color. For the follow-up, still on Egypt gas, on slide three, you guys have a bullet point saying that with the new pricing arrangement, that gas development is at parity with mid-cycle Brent. I wonder if you could just elaborate a little bit more on what the assumptions are there. I mean, what mid-cycle Brent, what your assumption there is, and also what the, what parity means, whether that's an IRR or what else goes into that statement.

Steve Riney (President)

Yeah. What we have is an arrangement. We sell all of the gas that we produce to Egypt. We have a fixed price on this new tranche of gas. We have a fixed price on the old tranche of gas. We have a fixed higher price on the new tranches of gas. The way that that will work is that you end up getting a mix of different prices as you go forward. As the PDP declines on the old price of gas and new volumes come on, you get a rising price as you go through time.

John Christmann (CEO)

Yeah.

Steve Riney (President)

Sorry. Sorry. The mid-cycle. With that price, sorry, on the new volumes, with that new price. Gas is effectively equivalent to a $75-$80 Brent price on oil drilling in Permian, I mean, in Egypt. You can drill for gas that's equivalent at a fixed price that's equivalent to $75-$80 Brent oil on acreage that would be right next door or nearby where we could drill oil wells.

John Christmann (CEO)

We included infrastructure.

Steve Riney (President)

Yeah. We included the potential for new infrastructure requirements in that analysis.

Charles Meade (Research Analyst)

Understood. That is great detail. Thank you.

John Christmann (CEO)

Thank you, Charles.

Operator (participant)

Thank you. Your next question comes on line of David Deckelbaum with TD Cowen. Your line is now open.

David Deckelbaum (Managing Director and Research Analyst)

Thanks for taking the time and for taking my questions. John or Ben, curious when you talk about the program for 2026 and holding 120,000 barrels a day flat with five rigs. Are you assuming any incremental benefits on D&C costs and asset in the context of you guys have made some significant headway? Is there any reason why you can't have a D&C target sort of that rivals the best peers in Delaware for next year?

John Christmann (CEO)

I think we're making great progress. If you look, part of the carry-through into 2026 is the savings that we think are real and the progress we're making. As Ben said, we're going to add another $50 million-$100 million of savings in 2026. Some of that's going to be on capital. 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.

Steve Riney (President)

Yeah. I would say, and I think we said this on the second quarter earnings call, in the Midland Basin, we feel like in many ways we're getting to be pretty close to best in class on the drilling and completion side. In the Delaware Basin, we're probably around peer average. There is still room to go there. Just in terms of reconciling the five rigs to holding volumes flat relative to 2025, 120,000 barrels of oil a day, there are some things that are benefiting us being able to go to five rigs. We're not saying that. We've said in the past that six rigs will hold Permian relatively flat around 120,000. We're not saying that's five now. We still believe that's probably closer to six at this point in time.

There are some things that are benefiting us in 2026 where we've made some good strides recently around base uptime, base volume uptime, kind of reducing the underlying decline rate a bit, which will help as we roll into 2026. There are some facilities where we're facility constrained now. We've brought on wells. The wells are actually constrained a bit in their producibility, and that will resolve itself as we go into 2026. That helps a bit. There is a small reduction in duck count. It's about five. We'll exit 2026 right now, based on current planning, with about five fewer ducks than we enter 2026 with. Not a significant amount, but just being transparent, there is a slight reduction in duck count. With all of that, our development capital in the Permian this year on a like-for-like basis, eliminating stuff that we've sold.

It's about $1.45 billion. Next year, that'll be $1.3 billion. The $1.45 billion actually includes about $200 million of savings that we've talked about that we actually captured in the current year in 2025. There is another $150 million of savings as we roll through 2026. That does benefit from kind of the run rate of what we've done so far. It does have some additional savings planned in there as we go forward. Much of that would probably come in the Delaware Basin versus the Midland Basin, but we still believe there's room to run in the Midland Basin as well. That does include running five rigs instead of—we're down to five rigs today. We had been running six earlier. That includes all of that.

David Deckelbaum (Managing Director and Research Analyst)

I appreciate all the additional color, Steve. My follow-up is just on the North Sea. I think you guys highlighted the tax benefits in particular in 2026. I guess, are you accelerating the ARO activity in the North Sea? What are the, I guess, results or consequences as you see on the production side of that asset over the next couple of years?

Ben Rodgers (EVP and CFO)

Yeah. On the production side, just like we mentioned earlier this year, with little to no investment in the asset, which was expected after all the different changes through the government there, we'll expect production to continue to decline from 2025 into 2026. I think we'd said 15%-20%. That's probably a reasonable assumption from a production standpoint. On the tax side, a lot of that's price dependent, depending on if there's taxable income in the U.K. There will be tax savings because of the increase in the ARO spend that we have next year, again, because the government pays 40% of that ARO. We've talked about that before in terms of the increasing profile when we announced COP last year. That'll increase next year.

Again, the cash flow impact of all ARO and decom spend year-over-year, after-tax cash flow impact is only $55 million. So very manageable. When you look at the total corporate profile from everything else that we have going on there. All in all, there's the taxable net income from the U.K. is price dependent, but there's going to be savings from ARO spend.

Steve Riney (President)

Yeah. To be really clear, we are not accelerating activity in 2026. We've had this plan for quite some time. It is primarily a well abandonment program at Beryl Bravo and initiating a subsea well abandonment program as well that will run for several years. Not an acceleration of any activity.

David Deckelbaum (Managing Director and Research Analyst)

Thank you, guys.

Operator (participant)

Thank you. Your next question comes from the line of Betty Jang with Barclays. Your line is now open.

Betty Jang (Senior Equity Research Analyst)

Good morning. Thank you for taking my question. 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? How should we be thinking about the benefit of these investments?

Ben Rodgers (EVP and CFO)

Sure. For this year, I mentioned in my prepared remarks the $60 million difference between captured savings and our capital guidance. Roughly a third of that was investment in these LOE projects that we started this year. We do expect that to continue into next year as we identify different opportunities. Most of it is around facilities and compression and other items that I have mentioned before. We will continue to invest capital into those projects that will have ongoing LOE savings. It is not a big capital number when you think of. Steve mentioned the $1.45 billion for Permian this year and the $1.3 billion next year. If you are talking $20 million on that $1.3 billion base, it is not a big piece, but it does help us on LOE.

I will say that the teams are working across all different aspects within LOE, not just trying to find ways to lower it through capital investment, but through really all different areas that make up our operating expenses there in the field. That is not also just in the Permian. Clearly, we have done it this year in the North Sea and in Egypt as well. I am not going to outline a per barrel metric for that for the savings, but do expect savings. They will be staggered throughout 2026 and into 2027 as well.

Steve Riney (President)

Yeah. If I could just add a bit to that. Obviously, on LOE for 2025, we did not capture the savings that we had hoped to capture this year at the corporate level. But there is some real success underneath that that I think is worth mentioning. Most of the struggle has actually been in the Permian. That is 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 is going to be targeting LOE primarily, not entirely, but primarily in the Permian Basin. Those are investments that we are going to be beginning this year. There will be more in next year. You will see the benefit of those probably showing up in the second half of next year. I did want to highlight in particular the North Sea significant progress in reducing offshore operating costs this year. That is kind of hidden in what is going on in LOE and some very good progress in Egypt as well without any meaningful amount of capital spend.

Betty Jang (Senior Equity Research Analyst)

Got it. No, that's really helpful color. Thank you. My follow-up is back on the ARO. So the net $50 million delta would imply roughly the headline ARO is up close to $100 million. It does seem a bit higher than where we were thinking for 2026. Can you just speak to how we're tracking on ARO spend just over the next several years? Should we be holding at that level in North Sea beyond 2026?

Ben Rodgers (EVP and CFO)

Yeah. We'll probably wait, Betty, for a multi-year outlook and do that at some point next year, most likely in the first quarter if we do a portfolio update. We've talked about the ramp of the ARO, particularly in the North Sea. We also talked about this year that the Gulf of Mexico was going to be higher than prior years and also higher than what we expect moving forward. The moving pieces for next year are that you see Gulf of Mexico come down pretty significantly back to the kind of $100 million-$120 million range, which is typical for the legacy assets, the non-op assets that we own, as well as the old Fieldwood assets. That normalizes, and I would expect that to stay pretty steady even after 2026.

For the shape of the North Sea, it really—I will just go back to what Steve said originally when we outlined that. Starting in 2025, it was pretty de minimis. It was about $30 million this year. That grows to about $600 million of our after-tax ARO between now and 2030. The other $600 million is between 2031 and ramps down to 2038. We will provide more details potentially about what 2027 and 2028 are. That increase next year, you are right. In the high $100 million range this year, so it would be kind of in the mid to high $200 million range next year. It just should not go without saying that the after-tax impact to us is only $55 million.

Steve Riney (President)

Yeah. I just. Ben commented on an outline of the shape of ARO spend in the North Sea that I talked about on an earlier earnings call. That outline, that shape of spend starting in 2026 and going into the 2030s, that shape has not changed. It's still basically the same. It grows to 2030, peaks around there, and then starts declining. Mostly well abandonment in the first half of that and facility platform and subsea infrastructure in the back half, mostly.

Betty Jang (Senior Equity Research Analyst)

Got it. Got it. And just to confirm, that $55 million already includes the normalization of the lower Gulf of Mexico decommissioning spend?

Ben Rodgers (EVP and CFO)

That's correct.

Betty Jang (Senior Equity Research Analyst)

Got it. Thank you very much.

Ben Rodgers (EVP and CFO)

Thanks, Betty.

Operator (participant)

Thank you. Your next question comes in the line of Paul Chang with Scotiabank. Your line is now open.

Paul Chang (Research Analyst)

Hey, guys. Hey, Ben, you said the U.S. cash tax will be zero for this year and next year. Do you have any rough idea then how that looks like in 2027 to 2030?

Ben Rodgers (EVP and CFO)

Yeah. Right now, Paul, our focus has been for this year. Next year, we've made significant progress on the tax front and have seen some significant savings. I think when you get past 2026, because a lot of the changes this year and next year that we saw, we outlined this quarter, were specific to the corporate alternative minimum tax guidelines that came out and less so with the OBBB impact that we outlined in August. As we get into 2027 and 2028, there's still some guidelines that we'll need for the interpretation of the OBBB. The intention of that was that we get the full benefit of IDCs and bonus depreciation. It should take U.S. taxes pretty close to zero. There's still some work that we're going into that with our tax team.

That is the full intention of the legislation and where we think it could lead past 2026. We think that there are continued benefits. What we have outlined are the benefits for just this year and next year.

Paul Chang (Research Analyst)

Okay. Great. Maybe this is for John. For Alaska, you're saying that next year is going to be pretty minimum spending. How should we look at the program? I mean, you have the SOC I discovery, and you guys seem like you have very big, maybe pretty optimistic on that. What's the game plan, how should we look at it over the next two or three years? When would we see maybe a little bit more data out or more news about what the development may look like if that's one?

John Christmann (CEO)

Yeah. I don't know. It's a good question. 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 SOC I and exploration. Right now, we're doing technical work. The teams are working away, and we're reprocessing the seismic. We've got two 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. We'll come back at some point. 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. It'll 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.

We will update you once we have kind of worked through what are the next steps in terms of appraisal and exploration. We are excited about Alaska.

Paul Chang (Research Analyst)

Okay. We do. Thank you.

Operator (participant)

Thank you. Your next question comes to the line of Leo Mariani with Roth. Your line is now open.

Leo Mariani (Managing Director and Senior Research Analyst)

Yeah. Hi. 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? Also just curious on the decision to bring some ducks on in Alpine High and what seems like a bit of a challenge to Waha market here of late.

John Christmann (CEO)

Yeah. Just two 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. We'll have an update at some point, but do not have anything to announce today on that. The two completions, the two ducks 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. It's about preserving optionality and holding acreage in the future.

Leo Mariani (Managing Director and Senior Research Analyst)

Okay. Yeah. Just on.

Ben Rodgers (EVP and CFO)

As you look at the timing, Leo, real quick, the timing of when we bring those ducks on, you get that flush production. December, January, February, Waha is well above $2. The timing feels right to bring them on. Again, the main reason for doing that, to what John said, is to retain some acreage there. It just seemed you get the flush production, the economics line up, and you get to retain the acreage for optionality.

Leo Mariani (Managing Director and Senior Research Analyst)

Okay. Just on the capital for 2026, just wanted to kind of square everything in the circle here. 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?

Ben Rodgers (EVP and CFO)

That really captures the big items. Because any infrastructure spend would be captured in the development capital. That really captures all of it. The only other piece is the marketing book right now. Is kind of in the low to mid $400 million as we look at next year at Strip. Another very solid year from our marketing book. Again, that's both transport as well as LNG. Other than that, I think we've captured most of the big items.

Leo Mariani (Managing Director and Senior Research Analyst)

Thank you.

Operator (participant)

Thank you. This concludes the question and answer session. I would now like to turn it back to John Christmann for closing remarks.

John Christmann (CEO)

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-$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.

Operator (participant)

Yes. Thank you for your participation in today's conference. This does conclude the program, and you may now disconnect.