APA Corporation

Good day, and thank you for standing by. Welcome to APA Corporation's Second Quarter 2026 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, please press star 11 on your telephone, and you will 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 it over to your first speaker, Stefan Aka, Managing Director, Investor Relations.

Good morning, and thank you for joining us on APA Corporation's second quarter 2026 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO John Chrisman, Ben Rogers, CFO, will share further color on our results and outlook. Steve Reine, 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 interests in Egypt and Egypt taxpayers. 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 in 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. Today I will review our second quarter 2026 results, outline continued progress across our portfolio, and share our updated outlook for the remainder of the year. Last quarter I reviewed the pillars guiding APA's strategy, delivering top-tier operational performance, building and growing a high-quality portfolio, and maintaining financial discipline. Overarching all of this is our long-term strategic commitment to oil and gas. Our second quarter results demonstrate continued momentum consistent with each of these priorities. Operational performance remains strong, costs are declining, both the scale and quality of our portfolio are improving, and we continue to strengthen our balance sheet. At the core of our strategy is a simple objective, doing more with less. This is directly reflected in the quality of our execution during the quarter and the improvement in our forward outlook. It is further reinforced by the ongoing delivery of our cost reduction initiatives. Execution has remained ahead of plan, and we now expect to exit the year with approximately $500 million of annualized run rate savings, up from the $450 million target we established at the beginning of the year. More importantly, these improvements continue to strengthen the underlying economics of the business, reinforcing the progress we've made over the past two years. Turning to the second quarter, across our core Permian and Egypt assets, we met or exceeded production guidance while delivering capital investment below guidance. In the Permian, we have continued to build on the operational momentum established over the past several quarters. Oil production exceeded guidance while capital was in line with plan. Strong execution across drilling, completions, and field operations is reducing the level of capital investment required to sustain current production levels. At the same time, targeted investments to enhance base production reliability and lowering operating costs are delivering measurable results. Based on the progress we've made to date, we remain on track to achieve our expected $3.5 million per month run rate operating cost savings target by year end. Taken together, these efforts are more than offsetting current inflationary pressures while improving the capital efficiency and overall economics of our Permian business. In Egypt, adjusted BOE production was in line with our guidance. reflecting higher gross volumes net of PSC impacts. Gross gas production grew meaningfully during the second quarter as we continue to execute our development strategy. Approximately half of our gas production is now benefiting from the revised pricing agreement, improving the value of every incremental molecule we produce. This underscores the growing value of our gas portfolio and supports a more sustainable cash flow profile for the Egypt business. In Suriname, the Grand Morgue development continues to progress on budget and on schedule toward first oil in mid-2028. Shifting to our exploration portfolio, we also made further strides in building long-term optionality. We recently announced an agreement to acquire Savant Alaska, which secures critical infrastructure adjacent to our eastern north slope position and increases flexibility as we evaluate next steps. This includes a processing facility, a pipeline connection into the Trans-Alaska pipeline system, and supporting field infrastructure we can leverage to appraise and potentially develop this highly prospective resource position. Our upcoming program this winter will comprise an appraisal test to further delineate the sockeye discovery as well as an exploration well targeting a larger separate prospect. In Uruguay, we're pleased to welcome E&I as a strategic partner in OFF6 following a highly competitive process. This partnership underscores the quality of the box prospectivity and our ability to attract top tier partners to progress large-scale exploration opportunities. APA will retain a 60% working interest, with E&I funding a significant portion of the initial exploration well, which we planned to spud in 2027. Turning to capital returns. We continued making progress toward our $3 billion net debt target while returning capital to shareholders through dividends and share repurchases. Our long-term capital allocation framework remains unchanged. Since introducing the framework in late 2021, we have consistently returned at least 60% of free cash flow to shareholders every year while also improving the balance sheet. We expect to achieve this again in 2026. Moving to our full-year outlook, our updated guidance reflects a broader improvement in the capital efficiency and durability of our two core assets. As a reminder, following the Cowan integration, we initially estimated that sustaining Permian oil production around 120,000 barrels per day would require eight rigs and roughly $1.7 billion of capital. Since then, improvements in drilling, completions, and base management has significantly lowered capital intensity. As a result of these structural efficiency gains and our strong operational execution, We now expect to operate four rigs for the remainder of the year, while raising our full-year oil production guidance to 123,000 barrels per day. This is a significant increase relative to our original guidance of 120,000 barrels per day, while our capital budget remains unchanged at $1.3 billion despite certain inflationary pressures. Egypt has followed a similar trajectory, although the drivers have been different. Since signing the revised gas pricing agreement in 2024, we have maintained annual capital at roughly $500 million net to APA while progressively allocating a greater share of this investment towards attractive gas opportunities. Even with this shift, gross oil production has continued along a modest and predictable decline trajectory, while gas production has grown meaningfully. Supported by a refocused exploration program,

and ongoing development activity.

During the quarter, outperformance from recent rich gas discoveries resulted in the deferral of some lower pressure gas volumes at COSR. While this slightly reduces our near-term gas outlook, higher associated liquids offset the impact, resulting in a similar BOE profile as originally anticipated. Accordingly, we now expect full-year gross oil production of approximately 118,000 barrels per day and gross gas production of 535 million cubic feet per day, while maintaining our original BOE production outlook. We expect the impact on free cash flow to be minimal. More importantly, we remain excited about the significant gas potential across our Egypt acreage positions. Our four-year outlook also reflects slightly lower exploration capital, primarily associated with the timing of exploration activity in Block 58. The next exploration well, previously planned to spud late in the fourth quarter of 2026, is now expected in 2027. In closing, I'd characterize the second quarter with one word, momentum. We're sustaining top-tier operational performance across our portfolio, driving stronger production, lower costs, and lower capital intensity. These results reflect the structural improvements we've made over the past two years to become a cost leader and drive higher capital efficiency across our core assets in the Permian and Egypt. We are well on our way to achieving our $3 billion net debt target, which will improve resilience across commodity price cycles and provide greater flexibility for the long term. Taken together, APA is entering its strongest position in several years. With a highly capital-efficient base business, multiple high-quality investment opportunities and exploration, a strengthened balance sheet, and a clear path to organic oil production growth led by Grand Morgue. With that, I'll turn the call over to Ben.

Thank you, John. For the second quarter, APA reported consolidated net income of $747 million, or $2.11 per diluted common share. Consistent with prior periods, these results include items outside of core earnings. The most significant after-tax adjustment was an unrealized gain of $92 million related to our basis hedges. Excluding this and other small items, adjusted net income for the quarter was $669 million or $1.89 per diluted common share. One additional item to note is that deferred tax expense increased during the second quarter, primarily due to higher U.S. income, which accelerated the expected utilization of our U.S. net operating losses. This is a non-cash item that had no impact on second quarter cash flow and only has a minimal impact on our current outlook for full year current tax expense. We generated $738 million of free cash flow during the second quarter and returned $189 million to shareholders through dividends and share repurchases. Underpinning these results was strong execution across production, capital, and operating costs. Some of the cost variance was timing related, particularly in the North Sea where the lifting schedule for our crude oil sales shifted a portion of LOE from late second quarter into early third quarter. However, These results also reflect underlying efficiency gains and cost savings, particularly in the U.S., which have offset inflationary pressures such as global diesel costs. Through the first six months of 2026, we've generated more than $1.2 billion in free cash flow, which is more than we produced during each of the past three years. While higher prices have played a role, we are also benefiting from structural improvements we've made across the business over the past two years. Through sustained cost reductions, capital efficiency gains, and portfolio high grading, we've materially enhanced the cash generating capability of the company. As a result, a greater share of every dollar of revenue is converted into free cash flow, strengthening our capacity to reduce debt, return capital to shareholders, and invest in the long-term future of APA. John covered the operational progress across the business. I will focus on how those improvements are translating into a stronger financial profile, beginning with our updated full year outlook. We now expect to exit the year with $500 million of run rate savings, up from the $450 million target we outlined in February. These higher savings reflect broad-based improvements across the business that are now embedded in our cost structure. While inflation will continue to fluctuate over time, These efficiencies provide a lasting free cash flow tailwind by improving margins, enhancing capital efficiency, and increasing resilience across commodity price cycles. That's exactly what we mean when we say we are doing more with less. Turning to our full year guidance, we now expect lease operating expense of $1.5 billion, $25 million below our prior guidance. This reduction reflects the continued execution of our cost reduction initiatives, with savings primarily in the US and North Sea more than offsetting diesel inflation. This further demonstrates that the efficiency improvements we've implemented over the past two years are delivering durable margin and free cash flow benefits. Shifting now to our gas trading portfolio, which remains a unique source of cash flow and an important competitive advantage for APA. Based on current STRIP, we expect to generate approximately $950 million of pre-tax cash flow in 2026, inclusive of our basis hedges. As a reminder, changes in WAHA pricing have very little impact on APA's consolidated free cash flow because our unhedged transportation portfolio is closely matched by our Permian equity gas production. Higher WAHA prices increase gas production revenue but reduce income from our transportation portfolio by a similar amount, while lower Waha prices have the opposite effect. Taken together, our strong operating performance, structural cost improvements, and differentiated gas trading portfolio position us to generate approximately $2.3 billion of free cash flow this year at current strip pricing. This enables us to continue strengthening the balance sheet while returning meaningful capital to shareholders. Turning to the balance sheet, we repaid $752 million of bond debt during the first half of the year, including $673 million in the second quarter. As we discussed in May, stronger commodity prices prompted us to consider how we should allocate this year's incremental free cash flow. As a result, we will continue returning at least 60% of free cash flow to shareholders every year through dividends and share buybacks, including this year. We also expect to achieve our $3 billion net debt target in 2027 based on current strip pricing. That is well ahead of the three to four year timeframe we outlined when we announced the target last year. In closing, we delivered a very strong second quarter with production above guidance and lower capital and operating costs. The business today is fundamentally stronger than it was just two years ago. In the Permian, we've established a clear cost leadership position that is driving durable free cash flow. In Egypt, we've positioned the asset to generate stable free cash flow with attractive reinvestment rates. Looking ahead, Grand Morgue will provide a differentiated source of high margin oil production while driving free cash flow growth into the next decade. Together with our strong balance sheet, this portfolio positions APA to deliver durable free cash flow and long-term shareholder value. With that, I will turn the call over to the operator for Q&A.

Thank you. At this time, we will conduct the question and answer session. We will allow time for one question as well as one follow-up. As a reminder, to ask a question, you will 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 stand by while we compile the Q&A roster. Our first question comes from Doug Leggett of Wolf. Your line is now open.

Well, thanks. Good morning, everybody. John, this is the first time that you've had a call since you acquired Savant. And I wonder if I could just ask you to maybe offer as much color as you can, because your partner has been pretty open about the potential for a recoverable development north of 400 million barrels. You've now bought a pipeline, which I presume you wouldn't have done if you weren't at least aligned on the possibility of that. So can you share what your current thinking is? Do you have the semblance of a development with Sochi as it stands today, or is it contingent on a successful appraisal program? Any other color you can offer would be great. Thank you.

Well, Doug, I always appreciate you coming in. You know, we are super excited about our position in Alaska. It's now close to 500,000 acres. We're state lands. It's something we entered into in 2023. We've now drilled two successful discoveries with King Street and Sockeye. We were able to test Sockeye. We took a break this last winter to reprocess seismic because there were multiple surveys that needed to be stitched together. So we're very, very excited. We said we've got a high quality sand there. We can now confirm that we did not drill sockeye in the thickest portion. We've got two key wells set up for, you know, for this upcoming winter. We'll start building ice roads late this year and then, you know, spud two wells in 27. One will be an appraisal well, a sockeye hungry horse. And then the second one is an even larger independent prospect, Chinook. They're both similar geology. Obviously, with the appraisal well, you're appraising, you know, the sockeye discovery. And Chinook is, you know, a similar prospect but just much larger. You know, what Savant brings to us, Doug, it is strategic in that, you know, it's positioned right next to us. It obviously has a 25-mile pipeline with 80,000 barrels a day pipeline capacity, but it also brings a large gravel pad. There's 40,000 barrels a day of processing equipment, and it has an airstrip as well as a dock, and so it will be advantageous to us even in the appraisal process. and also, obviously, if we went on to a development. It's early for us to call any development plans at this point, but we're pretty confident we've got a lot to work with up here, and we're very, very excited. I think the thing that we've always talked about that both King Street and Sockeye approved is that we've got higher quality reservoir rock than some of the, you know, plays that are being developed, you know, quite a ways away, you know, to this. And so we're very excited about it. It's state lands. It's oil. The new processing of the seismic was a really, really good call. So we're very, very excited about it, Doug. But, you know, our next step will be to appraise Sockeye, drill Chinook, and then, you know, come back and be in a position to talk more about it at that point.

Okay, I understand. Thanks, John. My follow-up, if I may take advantage of Tracy being on the call or whoever wants to take this, but the E&I deal, ANCAP has given quite a lot of detail on the prospectivity of the whole area. E&I is obviously one of the top, if not the top, global explorer in the last several years. And I guess my question is simply this. There's one well in the deep water, John, Rhea, that you know well. It looks to us that it didn't go deep enough. Can you characterize what the exploration optionality is in Uruguay and what happens beyond the first well?

Well, you know, we've got two blocks. Block six, which we had 100%. We now have 60% in that and we are really, really thrilled to welcome E&I as our partner. It was a very competitive process and, you know, it really speaks to the quality of our position in Uruguay and how, you know, prospective that block is, but also a credit to our exploration team and the work that we've done, you know, now with Suriname bringing in Total and we're less than two years away from, you know, first oil there with Grand Morgue and now bringing E&I into, you know, block six in Uruguay. So we're thrilled to have them here. I'll let Tracy jump in. Obviously the, you know, the one well was too we believe was not drilled deep enough. Our objectives will be much deeper, but I'll let Tracy talk a little bit about the geology and what the concepts are and what we've got there.

Sure. Hi, Doug. I think one of the critical drivers for entry into Uruguay was the recent discoveries on the Namibian side in the Orange Basin in Africa, which really proved source rock on the African side of the margin that before had not been proven. So that's driven our interest and a lot of the industry interest into Uruguay. And, you know, what we're looking at is basically the conjugate margin geology that's worked on both sides of the margin up and down West African Latin America. Now, having proven source rock on the African side, we're looking to step over and test that on the conjugate margin on the Uruguay side. And so really it was that source rock data that drove interest that we're going to test on the Uruguay side. The interesting thing, as you pointed out, there's really only one well in the deep water in Uruguay, and that is the Raya well. And you're correct in your statement that we don't believe it tested nearly deeply enough. It's quite a shallow well relative to where the source rock is. And what has worked on the African side is your reservoirs are very close to source. we're going to be testing the same concept where we see reservoirs very close to source and much deeper than the Raya well tested. So with the exploration well, we'll be looking at that source rock, but also testing deposition, migration, and trap and seal on the site. So it'll be a very, very big well. We've got a really high quality 3D seismic data set over the prospects in block six and block four that we are looking at extending it in block four. But we've seen some terrific prospectivity on the 3D, very large prospects. And as John said, we'll look at testing that in late 2027. Great.

I appreciate the answers, Tracy, and thanks a lot.

Thank you, Doug. Thank you. Our next call comes from John Freeman of Raymond James. Your line is now open. Thank you. Hi, guys.

Good morning, John.

Morning. Last quarter, you know, y'all emphasized maintaining the flexibility between, you know, debt reduction and buybacks, and now given just how strong the balance sheet is, obviously y'all are pretty explicit that the number one priority now, the free cash for the rest of the year is on the buybacks, and kind of reiterating that minimum 60% annual return of free cash for the shareholders, and just given that there was some maybe confusion in the market the prior couple of months, maybe just give you all the opportunity to kind of readdress sort of that framework and how you all think about those allocation priorities going forward.

Sure, John. This has been a good question. And yeah, back in May, and I referenced this in my prepared remarks, what we said was that we were going to take time to evaluate what the right use of the incremental free cash flow between the debt and the equity. And through that process, really where we landed was sticking to the commitment to the 60% because our balance sheet is continuing to strengthen. With the $2.3 billion of free cash flow this year, we expect to have net debt at $3.3 billion by the end of the year. we actually think gross debt actually is going to be pretty close to that as well, which is going to just help with our fixed charges going into 2027. And, you know, having that so close from when we outlined the target in August, and here we are, you know, at the time in May, you're nine months from that, and it, you know, was so close, really just gave us the opportunity to look at, you know, balancing those two different commitments around the equity returns and reaching that $3 billion. But we're in a great position from a balance sheet, lowest debt balance that we've had at Apache in over 15 years. And just wanted to make it clear that we're still committed to the at least 60% return. We've not returned that much in the first half of the year. And so, yes, that implies that You know, we've got quite a bit of share buybacks to do in the second half of the year, and we're going to do that.

That's great. Thanks for that, Ben. And then, you know, y'all raised your cost savings target yet again to the $500 million. Can you kind of clarify, you know, how much of that has actually been captured versus what still needs to be achieved between kind of now and year-end? I know y'all highlighted some projects in the Permian on in the presentation, but just a little bit more clarity on what's captured and what's still left.

Yeah, so I'll actually do it from an annual basis. John, in earlier this year, what we said was we had actually captured $300 million of savings in 2025. And then that set up your run rate exiting 25 of the 350 million. And we said we were going to capture $400 million of savings this year. and that led to a $450 million run rate. As we've gone through the first half of the year, given the execution across our portfolio in Permian, Egypt, and North Sea across LOE and Capital, what we've seen is that that captured amount, which was 400, is actually closer to the high 400s. Call it $475 million. Some of that's being offset with inflation, and we've talked about that. You've got higher diesel costs and a little bit higher service costs across the lower 48 that I think all industry is starting to see. And so that captured amount, putting aside inflation, would have been 475. But when you count that inflation, it's probably closer to 425. But because we're capturing more true savings, that run rate is now higher from the 450 and it is now 500 and it's across all three of the buckets. We're seeing capital efficiencies in the Permian and in Egypt. We're actually through field initiatives across our portfolio, namely in the Permian and the North Sea, we're seeing LOE savings and then GNA continues to trend in the right direction as well. So that incremental 50 of run rate savings as exiting this year is across all three of those buckets. On top of that, you know, we've separated the controllable spend of those three buckets from interest expense savings, but we also now, because, and from my prior comments around gross debt and net debt, we think that annualized interest savings exiting the year is going to be closer to $175 million lower, so $675 million as we exit this year of true costs being lower than they were as we exited 24. And to put that in context, we've outlined $2.3 billion of free cash flow this year. Had we not started this two years ago around controllable spend and really getting after the debt pay down, That $2.3 billion would actually be closer to $1.7 billion. So a testament to the team and all of the hard work that's been done on the costs and enabled us to pay down debt and really position Apache very strongly as we exit this year from a cost standpoint and consider ourselves really a cost leader now.

Perfect. Thanks again. Thank you. Our next question comes from Josh Silverstein of UBS. Your line is now open.

Hey, thanks. Good morning, guys. Ben, you highlighted some of the benefits of the gas trading portfolio and how there's limited free cash flow impacts for the change in Waha prices. And I believe some of this is due to the hedges that you guys have in place for this year. I was hoping, directionally, if you can kind of give us a view into next year. Do you plan on adding some additional basis swaps to kind of have a similar kind of net zero impact and how things may look for you guys next year?

Sure. Good question. You know, actually, since those pipeline positions have been put in place and starting in 2019, 2020, and then the Chenier LNG contract a few years ago, We've not hedged LNG, and we've talked about that, just kind of given the volatility in that. And we like the exposure to the upside of LNG pricing, which has actually helped and benefited us a lot this year. So our hedging program around our gas trading book has been around the basis. And you look back over the past five plus years, almost every year we've had a hedge position in place. And so I would expect that trend to continue to next year. We've not put any places for 27 yet. We do monitor that. And we do like the position that we're in this year because it does provide that unique offset of higher Waha prices that benefits our equity gas production. And it's offset by the loss on the transport side net of hedges. It is unique. It's providing at least investors some stability and understanding of, you know, that free cash flow that's coming from that business. So we've not put any hedges in for next year. We do look at that and we'll update folks through the year if we do.

And then, you know, John, you mentioned you're two years away from the startup of the Grant Moore Group project, and that's clearly a key differentiator for your growth profile into the future. Knowing you have this around the corner, how does this impact the development of the existing asset base and capital allocation strategy? Do you want to hold things steady with the existing production base? How do you think about different options there?

I think, Josh, it's a great question. First of all, things are on track with Grand Morgue. We've said mid-28 first oil. and Total came out and said potentially first or second quarter of 28, so we're going to stick with mid-28. What it's positioned us to where if we can just maintain volumes in our core assets of Permian and Egypt, well, then you've got growth coming through our exploration program and through Suriname. I think a couple of things. The big thing there is the way we structured our joint venture with Total. We're benefiting from a large carry in Suriname today, which has enabled us to continue to fund our programs domestically and internationally with Egypt and Permian. But it's also let us continue to make progress on the balance sheet and deliver on the returns framework while we're funding our such a large-scale capital project. And so it really, really is work to our advantage. And quite frankly, without that, we wouldn't be in the position we're in today. So it's really set us up to run those businesses like we would like to run those. We worked on adding durability and inventory life to Permian, where we can run flat for more than 10 years. which is kind of what we laid out earlier this year. We're obviously exceeding that with volumes and capital efficiency that we continue to have come through. And then obviously gas has changed our picture in Egypt as well. So we've been, you know, growing our BOEs, gross BOEs in Egypt. So, you know, it puts us in a really, really unique place today with our exploration program where we can allocate to the projects and let the projects get the capital they need and we're not having to constrain everything. all along bringing Suriname along. So, you know, it puts us in a really, really good place to continue doing what we're doing. And, you know, we're thrilled to be in the place we're in today.

Thank you.

Our next question comes from Avram Jarom of J.P. Morgan. Your line is now open.

Good morning, John and team. John, I was wondering if you could comment on how you think your sustaining capital requirements in the U.S. are evolving. This year, you guys have highlighted $1.3 billion of domestic capital for 123,000 barrels of oil, but then you did mention how your rig count now is going down to four. and obviously you're generating some efficiencies. So I know you're probably not ready to give us a 2027 guide, but I wanted to see if you thought there's further potential to reduce sustained capital based on efficiency gains.

Yeah, Rune, it's a great question, and we're in a really dynamic period both for us and industry. And if you go back to, you know, Post-close of Cowan, we believed it was eight rigs to hold 120,000 barrels a day flat. As you mentioned, we're now currently at four. We've got to do 123 for this year. And it's been a stair step down as we, one, changed our development philosophy and have really let the cost side drive a lot of things. Today, we're clearly under six. We've been running, you know, we're at four rigs. You know, today we started at five. We dropped down to five last year. You know, we're clearly under six rigs to, you know, to maintain at 120. We've been doing that for the last two years. So it does give us some flexibility in terms of how we think about that. And, you know, we're not ready to dive into 27. You know, we give a little bit of an insight today. Talk a little bit in November, and then obviously in February we'll come out with a plan. But the way the efficiencies have been running through and the team continues to make really, really meaningful progress. And, you know, very proud of that. And, you know, I think the one other thing I'd say is, you know, the number of rigs is not as critical of a number as it used to be because it ultimately boils down to welds you're drilling, feature drilling, and the turn in lines. But... I don't know, Steve, anything you want to add to that?

Yeah, John, just to echo your last comment there, we started this year with a plan of five rigs, and we're clearly going to end up at four and a half rigs. Those four and a half rigs will drill more lateral feet and will complete just as many wells as we planned with five rigs. So we're down to four rigs for the second half of the year. We're actually moderating frack activity in the back half of the year as well in order to meet our capital budget of $1.3 billion. And so it's just, again, to your earlier comments, it's about both the scale and the pace of change and efficiency gains that the team has gotten to. And it's continuing in 26. 25 was obviously a really big year where we started off with this notion that eight rigs would sustain 120. And halfway through the year, we were at six rigs sustaining 120. And I agree with you right now. We've been delivering basically 123,000 barrels of oil a day. And by the end of this year, it'll be for two years straight. And we're doing that clearly with fewer than six rigs. We'll average four and a half this year. Not saying that it's four and a half, But as we do the planning for 2027, we'll talk a bit about it in November and then obviously give the details in February after we've had the full discussions with the board and the full review of the plan.

Appreciate that. And maybe just a little bit of a follow-up on Egypt, where you guys mentioned that you are testing some new play concepts. I wondered if you could elaborate on some of the... exploration type work you're doing in the Western Desert.

Yeah, Rune, we've been in the Western Desert since 1994 and until really late 24, all we focused on was oil and exploring for oil. Obviously, we entered into a new price agreement in November of 24 and We started then to, you know, how do you translate what we know into gas? We knew there were some low-hanging fruit that you saw us get after, you know, last year, but we've really only been exploring now for gas in the Western Desert for, you know, call it 12 to 18 months. So we're stepping out. A lot of it's similar type rock, but you're looking deeper now. You know, the key to think about in Egypt is, you know, we've got 20,000 feet of sand effectively. So the exploration program there is much different than the offshore stuff where you've got your seismic tuned. It's either there or it's not. You know, Egypt, it's the nuances of can we predict, you know, where we've got trap and seal. In a lot of places, you have too much sand. So the program has been very consistent. That's why you see kind of a steady diet of successes as well as some dry holes because at depth it's hard to really differentiate, you know, sand versus pay. But the good thing is when you have your discoveries like we've had, the follow-ons are usually very predictable, and then we can take those and extrapolate into multiple wells. A lot of it is stepping out into deeper parts of the basin. It's stepping into places that we avoided because we thought it might be more gas prone. So it's really putting a new lens on what we've done for 30 years and just thinking about it more from the gas perspective. But we've got a lot of key wells coming up. We've drilled a lot of nice discoveries. So very pleased with the program. But, you know, the key here is it's conventional. It's not unconventional. And, you know, success has been set up, you know, one to two to three to five, you know, type well offsets. And so we've got a lot of concepts that are at play.

Thank you.

Thank you.

Thank you.

Our next question is from Neil Dingman of William Blair. Your line is now open.

Morning, John and team. John, my first question is just a little bit more on your exploration program. Specifically, you've been active in Alaska and Uruguay. I'm just wondering, are those areas where you consider sort of at the front of the potential exploration line, or would you all also consider exploration activity, I don't know, maybe in Block 58 or other blocks in Suriname as well as you know, maybe any other new areas you might see.

Yeah, Neil, I mean, I think the most important thing there is we've stayed committed to exploration. You know, we've tried to allocate approximately 10 to 15% of our capital, you know, to exploration. It's something we stuck with. You know, obviously, you know, going back to 2019 when we spud the first well in Block 58, And then we ran a rig during 2020 during COVID in Block 58. From there, we went into appraisal in Suriname and continued to explore. We recognized in 22, we had what we needed to get to an FID in Suriname and really tasked the team for what else was out there. And it was a very rare window in time where early 23, hardly anybody else was exploring. And so it let us step in to places like Uruguay with even success being announced in Namibia across the conjugate margin was very, very quiet, right? So that was an easy enter into Uruguay for us. You know, we were able to do the deal with Armstrong in Alaska on state lands for what's now a very large position. So, you know, I think the important thing is we were able to kind of build out our portfolio at a time when we knew we had expiration dollars to spend, we were able to attract high-quality people, and it got us kind of ahead, as a lot of folks have started to think about expiration starting last year and now this year. And so, you know, when you look at our portfolio today, you know, you follow on Block 58 success. There is more to do in Block 58. You know, we will be back in there with Total next year, exploring and with looking to either add to the plateau for Grand Morgue or potentially more infrastructure. So we're very excited about Suriname. We're very excited about Alaska as well. I would put both the Block 58 in Alaska at the top because we've de-risked those now with success. We're very, very excited about Uruguay. It is a fantastic-looking area, but it's frontier. We don't have a well deep enough in that basin yet, We need to go see. You've got what Tracy described to Doug a little bit earlier in the Q&A across the conjugate margin in Namibia. We're very, very excited about it. Of course, the team is always looking for other things, but quite frankly, I think we've got a portfolio today that's very, very differentiated, very unique. Quite frankly, we've really de-risked both Suriname Block 58 and and Alaska through already what are successes.

Yeah, I would agree on the deep portfolio and the de-risking. You guys have done a fantastic job. And then just a second question around the Permian natural gas takeaway, maybe for you or Ben, just specifically looking at slide 19 for your presentation last night. Would you all consider adding further FT or I guess maybe ask another way, is your gas takeaway capacity at all limiting potential future oil growth? It doesn't appear to be, but just want to see how you're considering that.

We're in a good spot right now. We do have more capacity than we do equity production, so there's potential room to fill that. But as we look at it right now, we're in a really good spot. It has paid very well dividends over the past five years since it's been in service. It's 2026. The first expiration comes from GCX in 2029, and we'll make the assessment then. We've got extension options on that and PHP, two five-year extension options. That's great optionality as you think about our total U.S. portfolio and what we'd like to do really as we get into the next decade. Do we want to keep that optionality or not? So we're in a really good position right now as we look at that. Thank you, Ben.

Thank you. Our next question is Chris Baker of Evercore ISI. Your line is now open.

You guys, thanks. Just wanted to maybe step back for a second. Some, you know, some great progress in terms of the debt reduction we've seen year to date. Obviously, you know, with the $3 billion target and expecting to end the year at 3.3, you know, it does seem like we're coming up to a point where, you know, you'll be a target. I'm just curious, John, or I don't know, Ben, if you want to take this one. just around the added flexibility that hitting that target provides in terms of, you know, either incremental cash return to shareholders or, you know, if there's other things as you look out at the landscape in terms of exploration and frontier opportunities that kind of rise to the top of your list, we'd love to get a sense just for how you're thinking about that.

You know, first off, Chris, in terms of how we're thinking about things, I think we're in a good place. I mean, 27 will be an increased year. 26 has been light for us in terms of true exploration spend. That'll kick up next year because we've got such a high quality portfolio. The base business is running extremely well and Suriname's coming down the pike quickly. So we're in a really, really good place, which puts us in a nice position. And that's why we've been able to make such progress on the balance sheet and stick with the return framework. So Ben, I'll let you comment more on specifically the $3 billion debt target.

Yeah, I think it's a fair question, Chris. And when you look at, I said in my prepared remarks, we expect at Strip to reach the $3 billion in 2027. I mean, we're a stone's throw away there as we sit here today and at the end of the year. And so, you know, 2027, you reach that. you'll be likely within a year plus from Grand Morgue. That brings not only oil production growth, but growing free cash flow 28, 29, 30 on top of a business with the Permian and Egypt that will continue to sustain that free cash flow generation ability. And so what we can say now is I think that once you hit the 3 billion net debt target, you likely put another one out there to continue to de-lever the business. But that'll be balanced with what we'd like to do on the shareholder side between mix and also just total amount going to shareholders. The good thing is we're going to be very well positioned. We're well positioned because of what we've done on the costs. We're well positioned because of what we've done on the balance sheet. And you've got, you know, Grand Morgan now less than two years away. Next year will be less than one year away. And so it provides us a lot of optionality around that. And we don't have to cannibalize the investment opportunities on the exploration side that John outlined in order to still provide true cash value to our shareholders. So we'll have a lot of options. And as we get closer to that, we'll let folks know where we land.

Great, thanks. And then, you know, obviously a lot of progress as well in terms of capital efficiency in the Permian, getting down to the four and a half rigs obviously is a big move from where you all started after the merger. I'm just curious in terms of how you think about, you know, the biggest potential sources of further improvement there. I guess, where is the team's focus? We'd love to get a sense of where we could see continued progress on that front. Thanks.

Yeah, I think you look at the basin now and you look how long we've been in these plays and the progress you're making, you're at a point now where we've drilled a lot of wells, right, with more than 100 a year. So we're making great, great progress. A lot of the The recent strides have been with really fine-tuning your well designs and your slim hole. You've gone to the simul, trimul, frax, all of those things. I'm going to continue working on the efficiencies and letting folks just continue to work on how do we eliminate steps that cost you money as you work through those. They've got those down now where you look at the per foot numbers you know, you really are benefiting from scale and, you know, the repetitions that we've got. So, you know, I think that's the big thing, you know, some of the opening plays, a lot of what we're doing on the testing side to move the technical locations into economic, you know, there's a lot to learn as you get into some of these other formations and things like the Barnett and others. So I think you'll continue to see progress there, but it's, you're at a point today where it's really more fine-tuning the machine and doing more and more from the repetition standpoint.

Thank you. Our next question is from Bob Brackett of Bernstein Research. Your line is now open.

Good morning. I'd like to return to Uruguay Block 6 The Raya prospect was Cenozoic and was sitting out in sort of record water depth, but it had prograded well out there. You mentioned chasing deeper objectives closer to the reservoir, so that suggests Cretaceous, and that also suggests that you can drill in more palatable water depth. I guess, is that correct thinking? And can you talk about maybe the size of prospects and maybe the chance of success that you're targeting with that first well?

Bob, I'll say a few things. One, it is frontier. The prospects are very, very large. Tracy, I'll let you jump in. They are Cretaceous. I'll let you comment a little further on that.

Correct, John. They are Cretaceous. We're looking at exactly the same age of source rock, for example, as we talked about in Namibia, and very similar, if not exactly the same, reservoir ages that you see on the Namibian side. I think your comment about water depth is, you know, what we're really talking about is drilling deeper, not necessarily pushing into much deeper water. So we're still well inside 3,000 meter, you know, bathymetry in terms of drilling in the water depth. So that's not really a factor in terms of where we're planting the well. It's not in a lot deeper water than the Raya well, but we will be drilling the well significantly deeper into the Cretaceous than the Raya well tested.

Great. Quick follow-up. Would you be potentially testing multiple targets, including Cretaceous and those younger Cenozoic targets with the single well?

I think we've got a lot of work to do, Bob, in terms of, you know, our partner. We've got some very strong views about the prospectivity, which we think is terrific. And we've got multiple options on what we're going to test. So I think we need to wait until we're a little further along with our new partner, E&I, who we're very much looking forward to as We've mentioned previously, I think they're a top-tier explorer and will bring a lot to the table technically. So we are going to engage with them, I think, on final decisions on drilling. But we've got some very good options.

Very good. Thank you.

Thank you. And our next question is from Leo Mariani of Roth. Your line is now open.

Hi, guys. You mentioned this a couple times. I just wanted to clarify. I think you've said in the past that you're going to step up some of your capital commitments in the next couple years with more to do on the exploration side. Are you still going to be committed over the next handful of years to that 60% return of capital, even if we get into a little bit of a weaker oil environment, if you are having to step up some of those capital commitments to some of these longer-term projects?

Yes, Leo. I mean, that's something we've dialed into how we, you know, define that 60%. You won't see us, you know, stepping up beyond what we've really done in the past. It's just it's a step up from where we are this year. And I would characterize this year as more being a lighter year on the exploration spend. So, you know, it's something we've been, we've stuck to, you know, over the last decade. And, you know, we'll continue in the future.

Okay. And just on the exploration side, Like you said, it's going to step up in the next couple of years. Is there kind of like a ballpark target? Is that kind of moving to kind of 15% plus, you think, of capital in the next few years? Just trying to get a sense of how meaningful that can be.

Yeah, it really is going to vary from year to year. I think the takeaway is we kind of just give you a little bit of a preview into 2017. You know, we've got the two wells in Alaska. We've talked about that. We've outlined those. So you're spending about $20 million this year for ice roads in Alaska, you know, those extra two wells. And by the way, we'll firm all this up later this year as we preview 27 in February when we land on it. But, you know, I think a decent assumption for that is kind of $100 to $120 million for those two wells in Alaska. You know, one to two wells in Suriname. So I think those are, you know, you could assume 50 to 75 million a well net to us. And I just want to remind folks that given where we expect to explore in block 58, those exploration dollars are going to be cost recoverable. But we are 50-50 with total on those wells. And so it's a decent proxy there. And, you know, the Uruguay well, it's one well and likely in the back half of next year. and it's offshore, so probably a decent proxy for that is a similar CERNOM well. But we'll outline the terms later on, but we're getting carried for most of that well. It's going to be significantly less than the 60% working interest that we retained there. So you kind of add all that up, Leo, and for next year, you probably have a two-handle on exploration spend. So yeah, it's going to be in that 10% to 15%. You carry that forward, we'll have to see how things go for additional exploration, you know, Alaska, Block 58, et cetera, past 27. But there will be, you know, that increase from this year to next, and then we'll take it from there as we get to the end of the decade.

Okay, thank you. Very helpful.

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

In closing, let me leave you with three key thoughts. First, we are sustaining strong execution across the portfolio with higher production, lower capital intensity, and continued cost reductions. The improvements we have made across the Permian in Egypt are strengthening asset performance. increasing free cash flow resilience, and reinforcing our cost leadership position. Second, we continue to make progress towards our $3 billion net debt target and remain on track to return at least 60% of free cash flow to shareholders in 2026, including significant returns in the second half of this year. Finally, with Grand Morgue less than two years from First Oil, we have a clear path to meaningful production growth. Combined with our exploration opportunities in Suriname, Alaska, and Uruguay, this provides significant future upside and positions APA for strong free cash flow into the next decade. Thank you very much.

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