APA Corporation (APA) Q3 2026 Earnings Call Transcript

Operator: Good day, and welcome to APA Corporation's Third Quarter 26 Financial and Operational Results. At this time, participants are in a listen-only mode. After the speakers' presentation, there will be a question and answer session. To ask a question, you will need to press *11 on your touch tone telephone. Please note this call is being recorded. I would like to turn the call over to Stephane Aka, managing director of Investor Relations. Please go ahead.

Stephane Aka: Good morning, and thank you for joining us on APA Corporation's Third Quarter 26 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 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 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. And with that, I will turn the call over to John.

John J. Christmann: Good morning. And thank you for joining us. Today, I will review our third quarter results discuss our fourth quarter outlook, and outline our preliminary plans for 2027. APA's strategy is anchored by 3 priorities. Delivering top tier operational performance, building a high quality portfolio, and maintaining financial discipline. Together with our long term commitment to oil and gas, these core principles guide our investments, operations, and capital returns framework. By honing these priorities over the past 2 years, we are continuing to strengthen our operating capabilities resulting in another quarter of excellent performance. More efficient development programs a structurally lower cost base, and higher commodity prices are driving stronger free cash flow. In addition, the carry agreement under our joint venture in Suriname further enhances our financial flexibility allowing us to fund only 10% of GranMorgu's development capital while retaining our 40% working interest and significant exposure to the project's future cash flows. This has enabled us to advance this world class opportunity while reducing debt, returning cash to shareholders, and building the long term future of the company. Turning to the third quarter, we delivered strong performance across our core assets. U. S. Oil production again exceeded guidance, Egypt sustained gross BOE production and GranMorgu continues to progress toward first oil in mid-2028. Capital investment in the Permian and Egypt as well as total operating costs were in line with guidance. We generated approximately $700 million in free cash flow and returned over $500 million to shareholders through dividends and buybacks. We also took additional steps to strengthen the balance sheet which Ben will discuss shortly. In the US, oil production of 128 thousand barrels per day exceeded our guidance through a combination of high uptime earlier turn-in-lines, and robust new well performance. Total US production averaged 294 thousand BOEs per day also above guidance. Our focus remains on improving capital productivity through continued drilling and completion efficiency gains and maintaining reliable base production. In Egypt, gross production was relatively flat quarter over quarter at 206 thousand BOEs per day. Gross gas production of 542 million cubic feet per day exceeded our guidance, driven by strong well performance and more resilient base production. Average gas realizations increased to $4.34 per Mcf from $4.23 in the second quarter. Adjusted production was approximately 64 thousand BOEs per day, slightly below guidance due to PSC impacts primarily from higher oil prices. In Suriname, our partner Total continues to advance GranMorgu on budget and on schedule for first oil in mid-2028. Third quarter development capital was approximately $40 million which was below our guidance. A portion of capital shifted into the fourth quarter primarily due to the timing of equipment deliveries and rig upgrades. But our full year outlook remains unchanged. Shifting to our fourth quarter and updated full year outlook. In the Permian, drilling and completion efficiency gains continue to improve capital productivity. These improvements have driven an increase in full year US oil production guidance to 124 thousand barrels per day above our initial guidance of 120 thousand to 122 thousand barrels per day. Faster drilling cycle times are also enabling us to accelerate some frac activity into the fourth quarter resulting in a modest increase in 2026 capital spending that will support a smoother production profile entering 2027. Fourth quarter oil production is expected to moderate with the timing of turn-in-lines during the year and reflecting seasonal weather impacts. In Egypt, we expect gross BOE production to increase slightly for the fourth quarter and full year. Across the portfolio, our priorities remain operational execution, continued cost management, and strong free cash flow generation as we close out 2026. Looking ahead to 2027, we will continue generating significant free cash flow from our core producing assets while advancing GranMorgu towards First Oil. The strength of our core business provides the financial flexibility to further enhance the balance sheet and return capital to shareholders while pursuing several high impact exploration opportunities. Our preliminary estimate for upstream capital year is approximately $2.5 billion. Exploration and GranMorgu development account for roughly 60% of the increase from 2026, with the remainder driven by Permian activity and modest inflation. We expect this investment program to result in similar US and Egypt production year over year. In the Permian, activity will increase relative to 2026, with a greater percentage in the Delaware Basin while Egypt activity and capital allocation across oil and gas will remain consistent with 2026. GranMorgu investment will increase as development drilling begins. On the exploration side, capital investment will return to our targeted range of 10% to 15% of annual upstream capital. These investments across our differentiated portfolio could establish new sources of long term production free cash flow, and substantial value for shareholders beyond our existing development assets. In Suriname, 2 exploration wells are planned with our partner Total targeting additional resource potential to extend GranMorgu's production plateau or even support a second development. In Alaska, this winter's program includes 1 exploration well and an appraisal test of our Sockeye discovery. In Uruguay, we expect to spud our Offshore Block 6 well with ENI in late 2 thousand 27. We will provide a more detailed outlook in February. In closing, our third quarter results demonstrate continued execution across the portfolio. Our Permian and Egypt businesses are delivering reliable performance and significant free cash flow enhanced by a structurally lower cost base and improved capital efficiency. This foundation, combined with our advantageous joint venture in Suriname, puts APA in a unique strategic position. Our carry agreement with Total significantly reduces our up front capital outlay for GranMorgu while preserving our ownership interest and full share of future profit allocations. As a result, we are able to advance a material high impact exploration program while reducing debt and returning significant capital to shareholders. Few companies have the financial flexibility to fund world class growth opportunities of this scale while strengthening their balance sheet delivering significant shareholder returns. We are accomplishing all of these priorities simultaneously. With GranMorgu less than 2 years from First Oil, and a transformational increase in free cash flow on the horizon. With that, I will turn the call over to Ben.

Ben C. Rodgers: Thank you, John. For the third quarter, APA reported net income attributable to common stock of $698 million or $2 per diluted common share. Consistent with prior periods, these results include items outside of core earnings, The largest after tax adjustment was an unrealized derivative gain of $17 million Excluding this and other smaller items, adjusted net income was $676 million or $1.94 per diluted common share. We generated $699 million of free cash flow. Bringing our year to date total to more than $1.9 billion. These results reflect strong execution across our core assets the benefits of structural cost improvements and capital efficiencies achieved over the past 2 years. Building on this performance, higher expected production in The US and Egypt, and stronger commodity prices have increased our 2026 free cash flow outlook to $2.9 billion. up $600 million from August. This supports significant returns to shareholders and continued debt reduction through year end. Accelerated the pace of capital returns during the quarter, repurchasing 10.5 million shares at an average price of $42.78. approximately $450 million. Including $87 million of dividends, we returned $537 million to shareholders. Through October, we have repurchased $762 million of shares this year. Reducing our outstanding share count by approximately 5% since year end 25. At current strip pricing, we expect approximately $650 million of additional share repurchases by year end. Together with dividends, these repurchases are consistent with our commitment to return at least 60% of annual free cash flow to shareholders. We also retired approximately $450 million of debt during the third quarter, opportunistically repurchasing bonds across near term and longer dated maturities. We ended the quarter with total debt of $3.3 billion and net debt of $3.2 billion Our debt reduction since year end 2024 has lowered annualized interest expense by more than $180 million compared with 2024. G&A expense for the quarter was $112 million including $56 million of stock based compensation, primarily due to the increase in our share price. Turning to capital. Third quarter upstream investment was $466 million approximately $30 million below guidance mostly due to GranMorgu spending that shifted into the fourth quarter. For our 2026 capital outlook, we have increased full year upstream capital guidance by $30 million to $2.1 billion reflecting the additional Permian activity John mentioned. Separately, we have reduced full year ARO spending by $15 million reflecting the deferral of certain North Sea activities as we optimize the program. This partially offsets the cash flow impact of the higher upstream capital spending. We have increased full year LOE guidance by $25 million primarily due to higher stock based compensation expense allocated to LOE. Underlying operating cost performance remained strong, with savings across our asset base absorbing $40 million of higher diesel costs in Egypt this year. Moving to our gas trading portfolio, which has been a significant cash flow contributor for several years and represents differentiated financial advantage for APA. While contributions will vary with market conditions, we expect the portfolio to continue generating substantial free cash flow. At current strip pricing and inclusive of basis hedges, we expect approximately $1.1 billion in pretax cash flow this year and $950 million next year. As we close out the year, I would like to put our cost reduction progress over the last 2 years into perspective. When we launched this initiative in early 25, we targeted $350 million in annualized savings by the end of 27. We achieved that milestone 2 years ahead of schedule, and subsequently increased our target to $500 million. Which we expect to reach by the end of this year. Combined with the $180 million in annualized interest savings already in place, reaching our year end target would bring total annualized savings to approximately $680 million compared with our cost structure as we exited 2024. For context, that is equivalent to roughly 80% of APA's total free cash flow in 2024. These improvements span our entire business, from greater capital efficiency and lower operating costs to a simpler, more efficient organization. The result is a structurally lower cost base that improves investment returns and supports more resilient free cash flow through commodity cycles. Our employees deserve tremendous credit for these results. Their commitment to finding better ways to operate has translated directly into tangible value for shareholders. Looking ahead to 2027, our focus is on sustaining these gains and driving further reductions as we navigate industry wide inflationary pressures. On capital, our preliminary outlook for the Permian program John described already incorporates mid single digit cost inflation. We are pursuing additional efficiencies from increased Delaware Basin activity other initiatives that could help offset those pressures. These potential capital savings are not reflected in our outlook. On operating costs, projects implemented in both Egypt and the Permian are already lowering LOE. With more savings to come in 2027. In Egypt, we are expanding power projects to reduce diesel consumption and operating costs. In the Permian, we will benefit from a full year of savings from projects implemented this year, alongside new initiatives to drive further reductions. Strong free cash flow and continued cost discipline also position us to take the next step in strengthening our balance sheet. We are approaching our $3 billion net debt target and expect to achieve it in the near future. Looking beyond this milestone, we are establishing a new net debt of $2 billion Further debt reduction will lower interest expense and fixed cash obligations. Supporting free cash flow through commodity cycles. It also preserves flexibility to fund future developments from exploration success while continuing to return at least 60% of annual free cash flow to shareholders. In closing, our financial progress this year is translating into meaningful shareholder value. With $2.9 billion of expected free cash flow, we are funding significant share repurchases while strengthening our balance sheet. We expect to achieve our $3 billion net debt target about a year and a half after announcing it. Positioning us to establish a new target from a stronger financial foundation. Our cost savings progress across and overhead has been central to these results. Sustaining these gains and building on them remains a priority as we look ahead. Over the next 5 years, we see a compelling opportunity to grow free cash flow per share through sustained cost discipline, lower interest expense, GranMorgu start up, continued share repurchases. Importantly, this growth does not depend on additional exploration success which would provide further upside. With that, I will turn the call over to the operator for Q&A.

Operator: Thank you. If your question has been answered and you would like to 1 question and a follow-up. Our first question comes from Doug Leggate with Wolfe Research. Your line is open.

Doug Leggate: Thanks, fellas. I wonder if I could touch first on exploration and then specifically in Alaska. I know Tracey's on the call, so I do not know if you want to defer to her maybe. But my question is specifically related to the King Street well that you drilled some time ago. And my understanding is there was a there was a deeper target and a shallower formation that you. That may have helped derisk part of the Chinook target that you are gonna drill early next year. I just wonder if you could confirm that or characterize the, you know, how you see the risk profile of Chinook. that is my first question. My follow-up is just that, obviously, you are generating an enormous amount of free cash flow Credit to Steve for being unhedged perhaps. I wonder where does the ARO the abandonment liability stack up in the of priorities for that cash flow between buybacks, debt reduction, and so on. I will leave it there. Thank you.

John J. Christmann: Thank you, Doug. I will jump in and then let Tracey add any color to, exploration, and then I will let Ben take the ARO question. But, no. We are excited about what we have in the Nanushuk play in Alaska. You know, we really derisked the play with 2 discoveries. King Street was the first that really confirmed a working petroleum system and high quality reservoir, and that was really important. Sockeye was the second well, and we drilled it next. It was not our largest feature, but it was the 1 that we had the best seismic data over at the time. And what Sockeye did was really tie our interpretations, to the seismic and the geologic model to the actual well results. And so both of those wells are very important for the whole Nanushuk area. We have got plans next year to appraise Sockeye with the Hungry Horse well. And Then Test A Larger Separate Feature With Chinook. I will let Tracey comment a little bit more on Chinook.

Tracey K. Henderson: Yeah. Morning. I will just comment a little bit specifically on your question, Doug, regarding the King Street well and what we have reported previously on that. I think what I would say is it was very encouraging. You know, we saw accumulation at depth that we reported. And as you mentioned, some shallower things that looked encouraging as well. I think we really need to get the well down at Chinook. I would say it is encouraging that we see a lot of hydrocarbons in these Alaska wells and some that are roughly, you know, in the same stratigraphic zones, but it. it is. I think it is, you know, we are basically interpolating a bit too much to say that there is a direct connection or derisking of Chinook based on the seismic from what we see. But it is encouraging to see hydrocarbons in those age equivalent zones that gives us some confidence that, you know, going into Chinook that we feel pretty good about it.

Ben C. Rodgers: Ben, on the ARO. Sure. So just on your second question, Doug. Yes, you know, we obviously have the ARO liability in the North Sea and the contingent liability in the Gulf of Mexico that we are managing You know, hats off to the teams. They have done a great job in the past years, and Gulf of Mexico, in decommissioning those assets, and we just started decommissioning, this year in the North Sea. That will continue, for years to come. When you look at what we have done on the balance sheet, you can see, from our maturity profile, we have got less than $200 million due in the next 9 years. And, that gives us flexibility not only from a shareholder return and funding exploration and other items, but also allows us flexibility to, you know, flex up or down based on commodity cycles, for how we decommission those assets with that being really the only liability we have to manage. This year, it is pretty close to $300 million I would expect the same next year, and dollars in that ZIP code are gonna be very manageable for us, as we are continuing to execute on those plans. When you look at our leverage stats, you know, we talk a lot about debt to EBITDA. At the end of this year, we are looking at close to 0.4x. But even when you include that liability, at the end of this year, it is close to 0.75x turn leverage and that is significantly different than the past here at Apache. And so we think we are well positioned. We are focused on lowering total liabilities, including the ARO. Those are long term. The team's doing a good job of derisking that. And, total debt coming down definitely helps too. Great opportunity to clean up. I appreciate the answers, guys. Thank you.

Operator: Thank you. Our next question comes from John Freeman with Raymond James. Your line is open.

John Freeman: Yes. Thank you. You currently have 4 rigs running in Midland, 1 in Delaware. John, you mentioned that the plan is for Delaware activity to increase next year. So I assume we should take that sixth rig that gets added and assume that goes to the Delaware next year, so kind of a 2, kind of split next year in the Permian?

John J. Christmann: Yeah. You are going to see us, John, like we said, go, you know, add back. We have been fortunate this year that you know, due to the heavy TIL count in the back half of 25, in the DUCs. We were able to get down to 4 rigs this year. Next year, we will be, you know, adding back in You know, this year, we were kind of in the 85/15% ratio of Midland to Delaware. Longer term, it is more 60/40. But you will see us probably more on the you know, 2 thirds, 1 third. But we will give you more specifics in February. Steve, anything you wanna add?

Stephen J. Riney: Yeah. Just to be clear right now, we have 3 rigs running in Midland, 1 running in and right around the beginning of the turn of the year from 2026 to 2027, we will be adding 2 more rigs. But as John said, it is it is 85/15 for the current year And over the next few years, we will be migrating to what is what is reflected in our economic inventory that we talked about in February. Which is 60% Midland Basin, 40% Delaware Basin, we will eventually get to that type of a ratio.

John Freeman: Got it. Thanks for that clarification. And then just following up, Ben, on your comments on the balance sheet. Obviously, leverage is in great shape. You have got the new long term net debt of $2 billion And just want to kind of think about how we should be sort of modeling this because when I look at the common debt stack, there is very little left, obviously, on the 2029s. Those will. Those will be gone soon. And then, you know, after that, they do not really have any near term maturities. it is pretty low coupon, and none of that is really able to get called at par at least for a number of years. And so I am just trying to think about when you think net debt target, should we just assume that maybe in the near term that outside of the 2029s, but a lot of it is just building cash? Or just sort of how to think about that net debt target?

Ben C. Rodgers: Sure. Sure. So, you know, stepping back, just on the target itself, in August of last year, we outlined the $3 billion, and we said, you know, strip pricing, we would expect to achieve that in 3 to 4 years. And obviously, over the last 18 months, we have experienced higher than strip pricing, and we are able to achieve that here, likely by the end of this year. So, when you look at this new $2 billion target similar timing at mid cycle pricing, it is likely by the end of the decade. And if higher prices play out, then, again, we could achieve that in a much shorter time period. So, you know, we will we will continue to be opportunistic, John, as we look at the debt stack. You know, there is. it is a pretty strong benefit that we have that $2.8 billion of debt is past the 2040 time frame. There are some other 2030 bonds, that we could potentially go after. A lot of that longer dated debt just given the current interest rate environment is trading below par, so you get a little bit additional deleveraging. But definitely recognize that is also a benefit to have you know, 17 years average maturity there. So we will be balanced and thoughtful on that. Obviously, for our shareholders, it does not make a lot of sense to sit on, you know, hundreds of millions of dollars of cash for a long period of time. it is meant to be a guiding star as we continue to develop our assets, continue to explore and return capital to shareholders. So we will be balanced We have done a lot of cleanup on the balance sheet so far. And it is really just meant to be a guiding star for us as we continue in the next few years. And, from an actual what bonds we go after, we will be very thoughtful about that as we think about maturities. And, refinancing risk, etcetera. Great. Guys. Appreciate it.

John J. Christmann: Thank you, John.

Operator: Thank you. Our next question comes from Arun Jayaram JPMorgan Securities. Your line is open.

Avram Jawram: Yes. Good morning, gentlemen. Wanted to see, John, if you could elaborate a little bit more on your Suriname exploration plans for 2027, you know, with Total. Maybe elaborate on what you plan to do with the drill bit. Outside of GranMorgu.

John J. Christmann: Sure. You know, Suriname, if you go back to when we announced the Crabdagu appraisal wells, at the time, you know, I said that, those Crabdagu wells did more than just appraise Crabdagu. They actually derisked an entire exploration fairway and tied it back to our seismic You will see in our supplement, you know, Slide 19, we put out a map. it is actually a map that Total's also used and put out We have outlined kind of 4 wells over the next 2 years, that we will start back with. They are very similar to what we have done at Crabdagu and Sapakara, so we are very excited about them. I do believe them to be derisked. I will also point out that they will be wells that are drilled within the current development area, so they will be cost recoverable, you know, under the, existing project. But, you know, most importantly, they provide the potential at a minimum to extend the plateau but we also believe, you move on these early, because you want to understand the materiality and the potential for possible additional infrastructure, either, you know, a second boat or possibly even the ability. We are in water depth where you could set some fixed structures and get creative on what you might be able to do with the infrastructure. So I think it is important that, you know, you get after them early because it gives you some clues on what you might be able to do with it. Versus if they were only gonna be plateau and you would be more inclined to drill them later in the you know, in the life cycle. But we are very, very excited. it is something that is relatively derisked. And it is something that both us and our partner are excited to get after because they are they are definitely gonna add more resource. Got it.

Avram Jawram: And they will stay with the exploration theme. I know you and your partner Eni, in Uruguay have contracted a deepwater floater to drill that well with Noble in the fourth quarter. Could you talk a little bit about the prospect that you plan to drill in Q4 Of Next Year? And, you know, how And Maybe A Little Bit More Around Your Thoughts Around Exploration In Uruguay.

John J. Christmann: Yeah. Yeah. Arun, we have entered into a contract with Noble for the. it is Black Hawk. it is a block now that we do not hold 60% and an ENI will hold 40%. They are gonna cover most of the well costs And I have got Tracey here, so I will let Tracey high level talk about kind of what we are going after with ENI in, our Offshore Block 6 block in Uruguay.

Tracey K. Henderson: Sure, John. It is a basically deepwater depositional system in Cretaceous that is worked in multiple places around the Cretaceous margin, on the Atlantic margins, most notably Namibia, which is our analog for this and the conjugate margin. So it is a really petroleum systems test on the Latin American side for what has worked on the African margin. The prospect itself, as I said, is very much like a lot of the deepwater Cretaceous turbidite depositional systems that we have seen that have worked in large scale in other parts around the circum Atlantic. So big well, but we are excited to get it down and very happy to have ENI in as a partner. Great. Thank you.

Operator: Thank you. Our next question comes from Neal Dingmann with William Blair. Your line is open.

Neal Dingmann: John, my first question is on for maybe you or Steve on the gas trading, specifically Could you speak to what we might expect next year with what I would call your 3 buckets there, which are the contract and the Feet, given certainly what looks like to be a volatile commodity market? Yes.

John J. Christmann: I will have Ben jump in on this 1.

Ben C. Rodgers: Sure. So, yeah, it is strip pricing. From last week, which we do for every earnings. We set it the week before. At strip pricing, as we look for next year across LNG, you know, Waha, NYMEX, and Houston Ship Channel, that gas trading portfolio is gonna generate about $950 million of pretax cash flow. You know, current prices, they continue to move around. I would say it is probably in the mid- to high 800s now. So still a significant contributor there. What you see is that, you know, this year, obviously, a lot coming from the pipelines And then and then LNG, they were more balanced, just kinda given how the curve is next year. The Permian Feet portion has shrunk, and that is expected. You have seen a lot of new pipelines not only been FID would recently, but also coming on this year, and that is going to continue into early next year. So you are seeing Waha Strengthen. But, you know, The Gulf Coast prices are still pretty low compared to global LNG prices. So still expect that to continue next year just given some of the global infrastructure damage, that is done through the, conflict. The Middle East. So, you know, just stepping back, it is it is been a very, very differentiated source of cash flow for us. If you look through this year alone, that business has generated $2.5 billion So you look at adding next year, you are gonna be over $3 billion from that book of business for us. So it is differentiated. It goes into our shareholder returns. And we expect that to continue for many years.

Neal Dingmann: Perfect. And then my second question just Egypt. John, I guess given what is going on in The Middle East, it appears you have been spared and does not seem like there is been any issues there. So again, I guess first question, you know, do you think that will continue to be the case? And then, you know, secondly, just maybe talk about workover activity there. It seems like you have been able to keep production very stable. Just if you could address that.

John J. Christmann: No, Neal. 2 good questions. I would say first in Egypt, You know, they have been a long term peacemaker over there and have done a really good job in difficult time periods. We have seen that over the last couple of years starting with Gaza, now what is happening here, and now, you know, things have moved into the Red Sea. But Egypt's done a great job. We continue to be in very, very close with both the Egyptian government and the US embassy. And, obviously, our highest priority is the safety and well-being of our employees over there. But things continue to be, you know, something we keep a close eye on, but Egypt's done a really, really admirable job, you know, thus far. And I would expect that to continue But, it is something we watch very, very closely. Steve, anything you wanna comment on the workovers?

Stephen J. Riney: Yeah. Neal, you might remember a few years ago, we had a. We had an issue with some mounting work over backlog in Egypt, and, we ended up with about 20 workover rigs running in Egypt back then. Since that time, we have we have concentrated quite a bit of activity around increasing workover rig efficiency and making sure that we are getting after the work over opportunities as quickly as possible. Just recently, you know, we are we are we are currently running 23% more jobs per workover rig than we have in the recent past. So we have gotten really quite good at this. At any point in time, we will be running today between 15 and 20 workover rigs in Egypt, and, that backlog is been worked down to a pretty small number now. So workover activity in Egypt is a really important part of what we call base resilience, which is just keeping the base running as efficiently, and as effectively as possible. Yeah.

John J. Christmann: Thank you all. The last thing I will add on Egypt there, Neal, is, you know, we got current last September on our PDRs. They have done a really good job of staying current. And, so you know, it is it is been a real good situation. We have been bringing on gas, which has been helping them. You know, they are importing and buying LNG, and so that is been a big deal. And then of course, they got current with the rest of the industry in June of this year. So you know, I really applaud them for doing a really, really good job in a difficult time period. Great point. Thanks again, John.

Operator: Thank you. Our next question comes from Chris Baker with Evercore ISI. Your line is open.

Chris Baker: Hey, Good morning. Wanted to follow-up on the 2027 outlook. I think, Ben, you mentioned that further efficiency gains are not part of the initial look that you all have outlined today. I am just curious to the extent that you do see some of those efficiency gains continue and offset some of the cost pressures. We are likely to see that show up in terms of lower capital or perhaps higher volumes?

Ben C. Rodgers: Sure. Yeah. I just you know, we have made so much progress over the past 2 years, across the company in all 3 buckets, that we have talked about on controllable spend with capital, LOE and G and A. On the capital side, a lot of that progress has been in the Permian. And, you know, it concentrated this year in the Midland Basin. And the ability to park rigs over DSUs have them just really work drives, you know, lower drilling days and a lot of different efficiencies. And that is even beyond you know, other development design and other changes that the team has implemented. And we have done all of that with higher production. So hats off to the team there. The main takeaway is John and Steve alluded to earlier, higher increase in the Delaware Basin. We have we have made progress on certain wells there, but we just do not have as many at bats in the Delaware. That will increase next year. And we will see how many of those learnings from the Midland Basin can be carried over to the Delaware Basin, from an efficiency standpoint. On both drilling and completions. And even through to equipping and facilities. So we think that there is upside there. We did not include that right now just wanna make sure that we get over there and get some wells down in the Delaware, and we will update folks as we continue, throughout next year.

Chris Baker: Great. And then just as a follow-up you mentioned some projects around driving continued cost savings in LOE. I am just curious in terms of any split you can offer you know, what you have locked in with projects this year versus new initiatives that could potentially show up as further benefits for 2027?

Stephen J. Riney: Yeah, Chris. This is Steve. So, we did announce beginning of the year we had about a $100 million of what we call LOE projects. And that is probably does not do justice to the projects because they also include benefits in reliability and runtime and up time. So it actually shows up both in LOE reduction, but also in production and production resilience as we call it. That 100 million was being spent. it is primarily. it is in the Permian Basin. it is primarily around things like ESP conversion to gas lift, more efficient gas treatment primarily through larger scale gas treatment and facility consolidation type of projects. So these are these are brownfield types of projects. That $100 million worth of projects we said would save about $40 million of LOE on a run rate basis We are delivering those projects on time and as expected in terms of the anticipated results. There will be, more of those projects The budget for 2027 does include some. Not a not a. Not as much as a 100 million but a meaningful amount of projects. And I would say that is still a preliminary budget for 2027. There are things that we can do even beyond 2027 on the facility side. Most of it is. Most of the type stuff, as you can imagine, would be done in front of the drilling rigs. And so we. We are not gonna not gonna go out and do work that we do not need to do because we are not drilling in a certain area. Great. Makes sense. Thank you.

Operator: Thank you. Our next question comes from Michael Scialla with Stephane. Your line is open.

Michael Scialla: Good morning. Wanted to ask about the debt you. You are getting your net debt down your target of 3 billion. Ben, you mentioned the low leverage. Can you talk about the decision to lower that net debt target further to $2 billion rather than changing your free cash flow framework?

Ben C. Rodgers: Sure. You know, we are we are thoughtful across our capital returns and our debt balance. You know, 1 of the things that we take into consideration is obviously, funding our exploration program, but we have got a differentiated free cash flow inflection coming from Graham Morgu in 2028. And that continues. Through the end of the decade. And, you know, we look at that and understand we need to continue to delever the balance sheet so that we can be more opportunistic in debt funding, potential growth opportunities and, and believe that you know, instead of being defensive on our debt balance now, we can be more on the offensive as opportunities arise, and that will be accretive to shareholders over the long term. So we take that into consideration, but just realize we need to continue to pay down debt as we, we have the different priorities that we are managing across development capital, exploration capital, continuing to get after our decommissioning assets, and lower debt is gonna really just make Apache stronger over the long term and give us a lot of options as we look, even beyond 2028. Additional free cash flow from GranMorgu. So, set us up well. We did not wanna plant a flag and say we are done. So, continued work there, but it is not gonna come, at the cost of anything else across the priorities that the company has. Makes sense. Appreciate that, Ben.

Michael Scialla: Wanted to follow-up on Alaska. Looking at the appraisal well you have planned for Sockeye, it strikes me that it is pretty good distance away from the discovery well. I think like 8 miles. That seems like a pretty large step out, and you mentioned that Chinook is potentially larger than Sockeye. So I am just thinking about the resource here. I do not wanna pin you down on any number, but it looks like, obviously, large potential resource. And I am wondering how you are thinking longer term if you do have success here with the 50% working interest. Are you comfort comfortable maintaining that, or would you look to bring in a partner like you did in Suriname?

John J. Christmann: Yeah, Mike. I mean, that, you know, when we announced the 25 thousand to 30 thousand acres. Now, clearly, we are stepping out a pretty good distance from that, with Hungry Horse, and it is. I think it is over 6 miles you know, as a crow flies. it is something we are very excited about. It looks fantastic. We did you know, reprocess the seismic data last year. And 1 thing we did learn is that we did not drill sockeye initially in the thickest part. that is something that the seismic told us. So we are anxious to, you know, to appraise it with Hungry Horse. It is a pretty big step out appraisal well. And then we do have, you know, a very large prospect in Chinook that we are also very excited about. You know, there is tremendous resource up here. We think 50% is a good starting point for us today. You know, with the Savant acquisition, that we have on queue, it kinda brings us some starter kit things that we can work with, a pipeline, a big gravel pad. there is a dock. there is a runway. A lot of things, and we are gonna have a lot of flexibility. But, you know, we wanna get these 2 wells down. And come back after that. But I think we like having the 50% where we sit today. Is a good place for us to be. Very good. Thanks, John. You bet.

Operator: Thank you. Our next question comes from Charles Meade with Johnson Rice. Your line is open.

Charles Meade: Yes, good morning, John, to you and your whole team there. And, Tracey, I want to start by saying circum Atlantic, that. that is a new word for me, but I think I understand think I understand what it means. John, if I could ask you to go back to the earlier question around the exploration in Suriname. If I understood you correctly, I think what I think I inferred from that is that these other prospects that you and Total Planner Drilling are similar in maybe similar age and similar settings to a Crabdagu as opposed to a, you know, a different or new kind of play type and I want. I am wondering if I am understanding that correctly. And then also, all other things being equal, which, of course, they are not, but it looks like the most interesting 1 to drill would be that 1 to the west of Sapkara where it looks like you could test 2 different, prospects with 1 wellbore, but I wonder if you could just comment on my interpretation there.

John J. Christmann: No. I mean, I would say, you know, you are. It is exactly similar reservoirs. Right? Same play. Same age rock. Actually, while, Sapakara is really 1 primary zone, Crab Dagu actually has multiple targets, and we have we have been clear on that. We do see multiple targets to the west there of Sapakara. But as I have said, these are very, very similar. You know, to what we already understand and are part of the development plan you know, for GranMorgu. So anything you wanna add, Tracey?

Tracey K. Henderson: No. I think that, John, that is spot on. We do see with. You know, as John mentioned, like in Crabdagu, multiple locations where we have got, more than 1 zone, that is hydro bearing. And so I do not think that is gonna be uncommon as we continue to drill these out.

Charles Meade: Great. that is it for me. Thank you. Thank you, Charles.

Operator: Thank you. Our next question comes from Bob Brackett with Bernstein Research. Your line is open.

Bob Brackett: Good morning and staying with the theme of Suriname. You mentioned, interestingly, on the Q&A that the prospects you are targeting are ring fenced within the development license. Does that mean that if you did pursue a second development that development could access the cost oil pool from the existing operations and therefore be fairly capital efficient?

John J. Christmann: Bob, I will just say they are inside the existing bucket. Right? So. Yes. I mean. Okay. Interesting.

Bob Brackett: The other question I might have is typically, in a PSC such as this 1, there is an exploration phase, and you will relinquish parts of the block that you deem nonperspective over time. So I am thinking back to, for example, When you chose these prospects, have you relinquished other parts of the block that you have deemed nonprospective? Or is there a chance to go out and look at a different system or a play idea?

John J. Christmann: I mean, at this point, we have not relinquished any of Block 58. In 2053, we are. you know, we have everything Except for the little corner that we have got mapped there. Around Baja. But those are. You know, we have still got some time and some work to do with Staatsolie in terms of Block 58. You know, I think we will be able to keep a big piece of this for quite a while. You know, but there are some things in the future where we do have procedures in place that we have to work through with Staatsolie. Very clear. Thank you. You bet.

Operator: Thank you. Thank you. Our next question comes from Leo Mariani with Roth. Your line is open.

Leo Mariani: I wanted to follow-up quickly here on Alaska. Obviously, you got some wells drilling over the winter. Wanted to kind of get a sense of, like, is there sort of a minimum success case terms of maybe a couple hundred barrels or something like that you need to kind of be comfortable with? To proceed with development? Anything you can kinda do to help us out would be great there.

John J. Christmann: Yeah, Leo. it is a great question. I will just say it is early. You know, we announced the discovery well. The 2 wells, but Sockeye. We have not come back and started talking about you know, what we would need in an FID case. Or anything at know, at that point at this time. So we want to appraise Sockeye first, get Chinook down, and then when we are ready to come back and talk about some things we can, you know, we can give more color and more detail there. Okay.

Leo Mariani: And then just in the in the US, doing a little bit more shifting of activity towards the Delaware. It sounds like next year. Just trying to get a sense, is some of that just driven by the fact that you have had such strong gains on efficiency in the Midland that you believe you can probably replicate some of that in the Delaware, which maybe makes it you know, kinda more competitive. And then secondly, do you still think there is kinda wood to chop on efficiency gains overall in the Permian?

John J. Christmann: I mean, I think there is definitely wood to chop. We keep staying after it. I think it is more just the function of our portfolio and the prospectivity over time. You know, what we have tried to do is efficiently develop resource. We made great progress in the Mid,. We have also made good progress in the Delaware. But when you just look at our inventory longer term, you know, post call, and we picked up a lot of potential. We have got a lot of shallow zones. A lot that is in our, you know, our technical, inventory bucket to be moved over. And so, you know, our natural progression with what our acreage footprint today is would be more of a 60/40 split and you just see us shifting slightly to that. So it is just kind of a natural progression of our program. But definitely see it is been, you know, outlined well. We see room for more efficiencies in the Delaware like we have been able to extract in the Midland. Okay. Thanks.

Operator: Thank you. Our next question comes from the line of Noel Hughes with Wells Fargo. Your line is open.

Analyst: Morning. I just have 1 quick 1 here, and it was on your comment there, John, about the derisking some of the technical upside locations in the Permian. When thinking about your program next year and a success case, how could we think about the amount of inventory that you guys could derisk in your 2027 program?

John J. Christmann: Yeah. No. I mean, we came out in February with you know, a good look at both our what we will call, our development inventory and then our technical locations. At some point, we will come out with another refresh of that. Is that something we are constantly working on? We are always testing things. We have test locations as we are consuming inventory in a year. We are also testing things and moving things over, and we will come back at some point and give an update and a fresh look on that But we are constantly appraising and industry is also appraising. We have a lot of HPP acreage So there is a progression there that, you know, has taken place this year. there is more taking place now, and we will come back and update that you know, we will figure out the appropriate cadence but we rolled that all out in February of this year. Thanks for the color.

Operator: Thank you. This concludes the question and answer session. I would like to turn the call back over to John J. Christmann, CEO, for closing remarks.

John J. Christmann: Thank you. In closing, I will leave you with the following thoughts. First, we continue to deliver strong operational and financial performance. Supporting substantial shareholder returns and debt reduction in 2026. Second, improving capital efficiency and ongoing cost savings are enhancing the long term durability of our core assets in the Permian and Egypt. Lastly, with GranMorgu less than 2 years from start up, we have a clear path to a step change in production and free cash flow through the end of the decade and beyond. Combined with our world class exploration portfolio, we are very well positioned to deliver differentiated long term shareholder value. Thank you.

Operator: Thank you for your participation. You may now disconnect. Good day.