Prepared remarks
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 speakers' presentation, there will be a question-and-answer session. During the session, please press 11 on your telephone to request the operator. To withdraw your question, please press 11 again. Please be advised that today's conference is being recorded. I would now like to hand it over to your first speaker, Stephane 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 J. Christmann. Ben C. Rodgers, CFO, will share further color on our results and outlook. Stephen J. Riney, President, and Tracey K. 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 the 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 noncontrolling interest in Egypt and Egypt tax barrels. 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 J. Christmann.
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 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 have 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 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 lower operating costs are delivering measurable results. Based on the progress we have 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 GranMorgu 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 are pleased to welcome ENI as a strategic partner in Block 6 following a highly competitive process. This partnership underscores the quality of the block's prospectivity and our ability to attract top-tier partners to progress large-scale exploration opportunities. APA will retain a 60% working interest with ENI funding a significant portion of the initial exploration well, which we plan 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 Callon integration, we initially estimated that sustaining Permian oil production around 120 thousand barrels per day would require eight rigs and roughly $1.7 billion of capital. Since then, improvements in drilling, completions, and base management have 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 thousand barrels per day. This is a significant increase relative to our original guidance of 120 thousand 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 toward 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 Khafre. 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 thousand 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 position. Our full-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 would characterize the second quarter with one word: momentum. We are sustaining top-tier operational performance across our portfolio—driving stronger production, lower costs, and lower capital intensity. These results reflect the structural improvements we 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 in exploration, a strengthened balance sheet, and a clear path to organic oil production growth led by GranMorgu. With that, I will turn the call over to Ben C. Rodgers.
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 noncash 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 with a lifting schedule for our crude oil sales shifting 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 have 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 have made across the business over the past two years. Through sustained cost reductions, capital efficiency gains, and portfolio high-grading, we have 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 is 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 U.S. and the North Sea more than offsetting diesel inflation. This further demonstrates that the efficiency improvements we have 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 pretax 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, and 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, which 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 have established a clear cost leadership position that is driving durable free cash flow. In Egypt, we have positioned the asset to generate stable free cash flow with attractive reinvestment rates. Looking ahead, GranMorgu 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.
Questions and answers
Thank you. At this time, we will conduct a question-and-answer session. We will allow time for one question and one follow-up. As a reminder, to ask a question, you will need to press 11 on your telephone and wait for your name to be announced. To withdraw your question, please press 11 again. Our first question comes from Doug Leggate of Wolfe. Your line is now open.
Thanks. Good morning, everybody. John, this is the first time that you have had a call since you acquired Savant, and I wonder if I could just ask you to 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 have now bought a pipeline, which I presume you would not have done if you were not 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 Sockeye as it stands today, or is it contingent on a successful appraisal program? Any other color you can offer would be great. Thank you.
Doug, we are very excited about our position in Alaska. It is now close to 500 thousand acres on state lands. We entered the position in 2023 and have now drilled two successful discoveries, Kingstreet and Sockeye. We were able to test Sockeye. We took a break this last winter to reprocess seismic because multiple surveys needed to be stitched together, and the new processing was very helpful. We can now confirm that we did not drill Sockeye in the thickest portion of the reservoir. We have two key wells planned for the upcoming winter. We will start building ice roads late this year and then spud two wells in 2027. One will be an appraisal well that will appraise Sockeye and Hungry Horse, and the second is an exploration well targeting a larger independent prospect, Chinook. Both have similar geology; the appraisal well will delineate the Sockeye discovery, and Chinook is a similar but much larger prospect. What Savant brings is strategic infrastructure adjacent to our position: a roughly 25-mile pipeline with 80 thousand-barrel-per-day capacity, a processing facility with about 40 thousand barrels per day of equipment, a gravel pad, an airstrip, and a dock. This is advantageous for appraisal and, obviously, will be helpful if we proceed to development. It is early to call any development plans at this point, but we are confident we have a large opportunity to work with. Both Kingstreet and Sockeye demonstrated higher-quality reservoir rock compared to some plays being developed further away, so we are very encouraged. Our next steps are to appraise Sockeye, drill Chinook, and then be in a position to provide more detail.
Okay. I understand. Thanks, John. My follow-up, if I may take advantage of Ben being on the call, or whoever wants to take this, is about the ENI deal. ANCAP has given quite a lot of detail on the prospectivity of the whole area. ENI is obviously a top global explorer. I guess my question is simply this: there is one well in the deep water, Raya, that looks to us like it did not go deep enough. Can you characterize what the exploration optionality is in Uruguay, and what happens beyond the first well?
We have two blocks in Uruguay. Block 6, where we previously had 100% and will now retain 60% after welcoming ENI, and Block 4 which we are looking at extending. We are thrilled to have ENI as our partner; it was a very competitive process and speaks to the quality of the position in Uruguay and the work our exploration team has done. With the discoveries on the Namibian side in the Orange Basin, source rock has been proven on the African side of the margin, which drives interest into Uruguay on the conjugate margin. Trey, I will let you expand on the geology and concepts we are testing.
Hi, Doug. One of the critical drivers for entry into Uruguay was the recent discoveries on the Namibian side in the Orange Basin, which proved source rock that had not been previously proven. That success on the African side drove our interest in testing the conjugate margin on the Uruguay side. We are looking at conjugate margin geology that has been productive up and down West Africa and Latin America. There is really only one deep-water well in Uruguay, Raya-1, and we believe it did not test deeply enough relative to the source rock. What has worked on the African side is reservoirs very close to source; we will test the same concept where reservoirs are close to source and much deeper than the Raya-1 well tested. The exploration well will look at the source rock and also test deposition, migration, trap, and seal. We have a really high-quality 3D seismic dataset over Block 6 and Block 4, and we have seen strong prospectivity on the 3D with very large prospects. We plan to test in late 2027.
Great. I appreciate the answers. Thanks a lot.
Thank you. Our next call comes from John Freeman of Raymond James. Your line is now open.
Thank you. Hi, guys. Good morning, John. Last quarter, you maintained flexibility between debt reduction and buybacks, and now given how strong the balance sheet is, you're explicit that the number one priority now is buybacks and reiterating the minimum 60% annual return of free cash flow to shareholders. Given some market confusion in recent months, could you readdress that framework and how you think about allocation priorities going forward?
Sure, John. Good question. Back in May, and as I referenced in my prepared remarks, we said we would take time to evaluate the right use of incremental free cash flow between debt and equity. Through that process, we landed on sticking to the commitment to return at least 60% of free cash flow, because our balance sheet is continuing to strengthen. With $2.3 billion of free cash flow expected this year, we expect to have net debt of $3.3 billion by year-end. That is very close to our $3 billion target and will improve our fixed charges heading into 2027. Having that target so close gave us the opportunity to balance those two commitments around equity returns and reaching the $3 billion target. We are in a great position from a balance-sheet perspective—the lowest debt balance at Apache in over 15 years—and we remain committed to at least the 60% return. We have not returned that much in the first half, so that implies significant share buybacks in the second half, and we are going to do that.
That's great. Thanks, Ben. You raised your cost savings target to $500 million. Can you clarify how much of that has actually been captured versus what still needs to be achieved between now and year-end? I know you highlighted some projects in the Permian, but any clarity on what's captured and what's left would be helpful.
Yes. To frame it annually: earlier this year, we said we had captured $300 million of savings in 2025, which set up a $350 million run rate exiting 2025. We said we would capture $400 million of savings in 2026, leading to a $450 million run rate. As we've gone through the first half of 2026, execution across the Permian, Egypt, and North Sea has increased the captured amount from $400 million closer to the high $400 millions—call it $475 million. Some of that is being offset by inflation, such as higher diesel and service costs; if you net out inflation, the captured amount is roughly $475 million, but counting inflation it is closer to $425 million. Because we are capturing more true savings, the run rate exiting the year is now higher than $450 million and is $500 million. Those savings are across capital efficiencies in the Permian and Egypt, LOE savings through field initiatives primarily in the Permian and North Sea, and G&A trend improvements. On top of that, we have separated controllable spend savings from interest expense savings. Given our lower gross and net debt, we now expect annualized interest savings exiting the year to be closer to $175 million lower. So it's $675 million of true cost reduction versus where we exited 2024. To put that in context, we outlined $2.3 billion of free cash flow for 2026—had we not started this cost program two years ago, that would be closer to $1.7 billion. So it's a testament to the team and the work done on costs, enabling us to pay down debt and position APA as a cost leader.
Thank you. Our next question comes from Joshua Silverstein of UBS. Your line is now open.
Hey. Thanks. Good morning, guys. Ben, you highlighted some benefits of the gas trading portfolio and how there is limited free cash flow impact from changes in Waha prices. Some of this is due to hedges you have in place for this year. Directionally, can you give us a view into next year? Do you plan on adding additional basis swaps to have a similar net-zero impact, and how might things look for 2027?
Good question. Since the pipeline positions were put in place starting in 2019–2020 and then the Cheniere LNG contract a few years ago, we have not hedged LNG; we prefer upside to LNG pricing. Our hedging program around the gas trading book has focused on basis. Looking back over the past five-plus years, almost every year we've had a hedge position in place, and we would expect that trend to continue into next year. We have not put any hedges in place for 2027 yet. We monitor the market and will update through the year if we decide to add basis hedges.
Got it. And John, you mentioned GranMorgu is around two years from start-up, which is key to your growth profile. Knowing you have this around the corner, how does this impact development of the existing asset base and capital allocation strategy? Do you want to hold things steady with the existing production base, and how do you think about different options there?
Joshua, things are on track with GranMorgu; we remain focused on mid-2028 first oil. The way we structured the joint venture with Total provides a large carry in Suriname, which has enabled us to fund our domestic and international programs while making progress on the balance sheet and delivering on the returns framework. That carry lets us fund a large-scale capital project without constraining how we run other businesses. We have worked on adding durability and inventory life in the Permian so we can run relatively flat production for more than 10 years, and gas has changed our picture in Egypt as well. Overall, it puts us in a unique position to continue allocating to projects while bringing Suriname along and not having to cannibalize investment opportunities across the portfolio.
Our next question comes from Avram Jayaram of JPMorgan. Your line is now open.
Good morning, John and team. John, could you comment on how you think your sustaining capital requirements in the U.S. are evolving? This year, you highlighted $1.3 billion of domestic capital for a 123 thousand barrels per day oil profile and mentioned operating with four rigs for the remainder of the year. With these efficiency gains, is there further potential to reduce sustaining capital?
Avram, great question. We are in a dynamic period. Post-close of Callon, we believed eight rigs were required to hold roughly 120 thousand barrels per day. Today, we expect to operate four rigs for the remainder of the year and have raised guidance to 123 thousand barrels per day. We've changed our development philosophy and let cost drive many decisions. The number of rigs matters less today because it ultimately comes down to lateral footage drilled and completions throughput. I'm not ready to provide a full 2027 guide today; we'll provide more in November and then in February with the annual plan. But the efficiencies we've achieved give us flexibility, and we continue to drive improvements in drilling, completions, and base management.
I'll echo John's point. We started the year planning five rigs and will end up averaging about 4.5 rigs. Those rigs will drill more lateral feet and we will complete as many wells as originally planned with five rigs. We are moderating frac activity in the back half of the year to stay within the $1.3 billion capital budget. It's about the scale and pace of efficiency gains the team has accomplished. In 2025 we went from an initial view of eight rigs down to six to sustain similar production, and now we're delivering around 123 thousand barrels per day with fewer than six rigs.
Appreciate that. A quick follow-up on Egypt: you mentioned testing new play concepts in the Western Desert. Could you elaborate on the exploration work you're doing there?
In the Western Desert, we've been active for decades but historically focused on oil. After the revised gas pricing agreement in late 2024, we shifted to view the basin through a gas lens. We've been exploring for gas across the Western Desert for about 12 to 18 months, stepping out deeper in the basin. The key in Egypt is conventional play mechanics across long stacked sand sections and predicting trap and seal at depth. We've had a steady program of successes and some dry holes—depth and reservoir identification can be nuanced—but when we hit successful zones, follow-ons can be predictable and repeatable. We have a lot of key wells coming up and are pleased with the program; it's conventional, not unconventional, and success often leads to nearby offsets.
Thank you. Our next question is from Neal Dingmann of William Blair. Your line is now open.
John, a question about exploration: you've been active in Alaska and Uruguay. Are those areas at the front of the exploration line for APA, or would you also consider exploration activity in Block 58 or other blocks in Suriname as top priorities?
Neal, we have stayed committed to exploration and have aimed to allocate approximately 10% to 15% of capital to exploration. After initial activity in Block 58 starting in 2019 and appraisal work in Suriname, we derisked enough to get toward an FID for GranMorgu and then asked the team to find additional opportunities. In early 2023, the exploration landscape was quiet, which allowed us to step into Uruguay and expand our Alaska position. Today, Block 58 and Alaska are at the top because we've derisked them with success. Uruguay is very attractive but still frontier—we need to test deeper objectives. We remain excited about Suriname and Alaska, and the portfolio is differentiated and derisked in parts we've already tested.
A follow-up on Permian natural gas takeaway: looking at your slide, would you consider adding further pipeline capacity, or is gas takeaway capacity at all limiting potential future oil growth?
We are in a good spot on takeaway capacity right now. We have more capacity than equity production, so there is potential room to fill capacity. The infrastructure has paid dividends since it came into service. The first expiration we face is GCX in 2029, and we will evaluate extension options then. We have extension options on PHX and GCX as well, which provides optionality for the US portfolio as we think about the next decade.
Thank you. Our next question is from Chris Baker of Evercore ISI. Your line is now open.
Thanks. You've made great progress on debt reduction year to date. With the $3 billion target and expecting to end the year at $3.3 billion, you're close to target. I'm curious about the added flexibility hitting that target provides for incremental cash return to shareholders or for pursuing exploration and frontier opportunities. How are you thinking about that?
Chris, we are in a good place. 2027 will have increased exploration activity compared with 2026, because we have a high-quality portfolio and Suriname remains on track. The base business is running extremely well, and GranMorgu's progress provides optionality. That combination has allowed us to make strong progress on the balance sheet while sticking to the returns framework and funding exploration opportunities.
When you reach the $3 billion net debt target, you typically consider a subsequent target to continue deleveraging, but it will be balanced with shareholder returns and funding high-return exploration opportunities. We will have many options as we get closer, particularly with GranMorgu producing growth in the next several years. We are well positioned because of cost reductions and balance-sheet improvements, and we won't have to cannibalize exploration investments to provide cash value to shareholders.
Thanks. One follow-up: on Permian capital efficiency, getting down to 4.5 rigs is a big move since the merger. Where do you see the biggest potential sources of further improvement, and where is the team's focus?
We have drilled a lot of wells and are benefiting from scale and repetition. Recent strides include well design optimization and completion innovations such as slim-hole wells and refined frac designs. Ongoing improvement is largely fine-tuning the machine, eliminating unnecessary steps, and continuing to learn as we test technical locations in different formations. Expect continued progress through repetition and incremental improvements.
Our next question is from Bob Brackett of Bernstein Research. Your line is now open.
Good morning. I would like to return to Uruguay and Block 6. The Raya prospect was Cenozoic and in deep water. You mentioned chasing deeper objectives closer to source and perhaps in more palatable water depth. Is that correct? Can you talk about the size of the prospects and the chance of success you're targeting with the first well?
Bob, I'll make a couple of points and let Tracey add technical detail. The plays are frontier but the prospects are very large.
Correct. The objectives are Cretaceous, matching the age of source rock that has been proven on the Namibian side. We plan to drill significantly deeper into the Cretaceous than the Raya-1 well tested. In terms of water depth, we are not planning to drill in much deeper water; the planned water depth remains inside roughly 3,000 meters bathymetry, so water depth is not a limiting factor. We do have multiple options and very good seismic data, but we will finalize drilling decisions in collaboration with ENI, who bring significant technical capability.
Quick follow-up: would you potentially test multiple targets, including Cretaceous and younger Cenozoic targets, with a single well?
We have multiple options on what to test. Final decisions will involve ENI, and we expect to engage with them on the detailed plan. There are good options, and we will decide the well architecture jointly.
Thank you. Our next question is from Leo Mariani of Roth. Your line is now open.
Hi, guys. You mentioned stepping up capital commitments over the next couple of years with more exploration. Are you still committed to the minimum 60% return of free cash flow even if the oil environment weakens and you need to step up capital commitments for long-term projects?
Yes, Leo. We've defined the framework to maintain the commitment and will manage allocations accordingly. You will not see us step beyond what we've historically done. 2026 is a lighter exploration spend year versus what we expect in 2027, but the commitment to return at least 60% remains intact.
On exploration stepping up next year, is there a ballpark target? Would it be moving to 15% plus of capital in the next few years?
It will vary year to year. For 2027, a reasonable proxy: ~$20 million this year for ice roads in Alaska and two wells next winter; roughly $100 million to $120 million for the two wells in Alaska next year. One to two wells in Suriname might be $50 million to $75 million per well net to us. The Uruguay well is offshore and likely similar to a Suriname well. Given cost recovery terms in Block 58 and our carry arrangements, many of those exploration dollars are cost-recoverable and/or carried by partners. For 2027 you could assume exploration spend at a two-handle percentage of total capital—moving toward the 10%–15% range depending on activity levels. We'll firm up details when we provide the 2027 preview in November and finalize the plan in February.
This concludes the question-and-answer session. I would now like to turn it back to John J. Christmann, 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 and Egypt are strengthening asset performance, increasing free cash flow resilience, and reinforcing our cost leadership position. Second, we continue to make progress toward 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 GranMorgu 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 concludes the program. You may now disconnect.