APA Corporation Stock

Good day, and welcome to APA Corporation's Third Quarter 2026 Financial and Operational Results.

[Operator Instructions] Please note this call is being recorded. I would now like to turn the call over to Stephane Aka, Managing Director of Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's Third Quarter 2026 Financial and Operational Results Conference Call.

We will begin the call with an overview by CEO, John Christmann. Ben Rodgers, CFO, will share further color on our results and outlook. Steve Riney, President; and Tracey Henderson, Executive Vice President of Exploration, are also on the call and available to answer questions.

We will start with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you 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'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website.

And with that, I will turn the call over to John.

Good morning, and thank you for joining us. 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 U.S., oil production of 128,000 barrels per day exceeded our guidance through a combination of high uptime, earlier turn-in-lines and robust new well performance. Total U.S. production averaged 294,000 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 206,000 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 64,000 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 U.S. oil production guidance to 124,000 barrels per day, above our initial guidance of 120,000 to 122,000 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 next 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 U.S. 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 one exploration well and an appraisal test of our Sockeye discovery. In Uruguay, we expect to spud our OFF-6 well with Eni in late 2027. 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 upfront 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 and 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'll turn the call over to Ben.

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 and the benefits of structural cost improvements and capital efficiencies achieved over the past 2 years. Building on this performance, higher expected production in the U.S. 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.

We accelerated the pace of capital returns during the quarter, repurchasing 10.5 million shares at an average price of $42.78 for approximately $450 million. Including $87 million of dividends, we returned $537 million to shareholders. Through October, we've repurchased $762 million of shares this year, reducing our outstanding share count by approximately 5% since year-end 2025. 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've 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've increased full year LOE guidance by $25 million, primarily due to higher stock-based compensation expense allocated to LOE. Underlying operating cost performance remains 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 a 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'd like to put our cost reduction progress over the last 2 years into perspective. When we launched this initiative in early 2025, we targeted $350 million in annualized savings by the end of 2027. 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 and 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 target 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 1.5 years after announcing it, positioning us to establish a new target from a stronger financial foundation. Our cost savings progress across operations 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 and 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 Instructions] Our first question comes from Doug Leggate with Wolfe Research.

I wonder if I could touch first on exploration and then specifically in Alaska. I know Tracey is on the call, so I don't 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 deeper target and a shallower formation that you -- that may have helped derisk part of the Chinook target that you're going to drill early next year. I just wonder if you could confirm that or characterize how you see the risk profile of Chinook? That's my first question.

And my follow-up is just, obviously, you're generating an enormous amount of free cash flow. Credit to Steve for being unhedged perhaps. But I wonder where does the ARO, the abandonment liability stack up in the seriatim of priorities for that cash flow between buybacks, debt reduction, and so on? And I'll leave it there.

Thank you, Doug. I'll jump in and then let Tracey add any color to exploration, and then I'll let Ben take the ARO question.

But we're excited about what we have in the Lagniappe play in Alaska. We've 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, really important. Sockeye was the second well, and we drilled it next. It was not our largest feature, but it was the one 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, very important for the whole Lagniappe area. We've got plans next year to appraise Sockeye with the Hungry Horse well and then test a larger separate feature with Chinook.

I'll let Tracey comment a little bit more on Chinook.

Yes. I'll just comment a little bit specifically on your question, Doug, regarding the King Street well and what we had reported previously on that. I think what I would say is it was very encouraging. We saw an 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's encouraging that we see a lot of hydrocarbons in these Alaska wells and some that are roughly in the same stratigraphic zones, but I think it's -- we're basically interpolating a bit too much to say that there's 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 going into Chinook that we feel pretty good about it.

Ben, on the ARO?

Sure. So just on your second question, Doug, yes, we obviously have the ARO liability in the North Sea and the contingent liability in the Gulf of America that we're managing. Hats off to the teams. They've done a great job in the past years in Gulf of America and decommissioning those assets. And we just started decommissioning this year in the North Sea, and that will continue for years to come. When you look at what we've done on the balance sheet, you can see from our maturity profile, we've 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 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's pretty close to $300 million. I would expect the same next year, and dollars in that ZIP code are going to be very manageable for us as we're continuing to execute on those plans. When you look at our leverage stats, we talk a lot about debt to EBITDA. At the end of this year, we're looking at close to 0.4x. But even when you include that liability at the end of this year, it's close to 3/4 turn leverage, and that is significantly different than the past here at Apache. And so we think we're well positioned. We're focused on lowering total liabilities, including the ARO. Those are long term. The team is doing a good job of derisking that, and total debt coming down definitely helps, too.

Our next question comes from John Freeman with Raymond James.

You currently got four rigs running in Midland and one 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 4-2 kind of split next year in the Permian?

You're going to see us, John, like we said, add back. We've been fortunate this year that due to the heavy TIL count in the back half of '25 and the DUCs. We were able to get down to 4 rigs this year. Next year, we will be adding back in. This year, we were kind of in the 85%, 15% ratio of Midland to Delaware. Longer term, it's more 60-40, but you'll see us probably more in the 2/3, 1/3, but we'll give you more specifics in February.

Steve, anything you want to add?

Yes. Just to be clear, right now, we have three rigs running in Midland, one running in Delaware, and right around the beginning of the turn of the year from '26 to '27, we'll be adding two more rigs. But as John said, it's 85-15 for the current year, and over the next few years, we'll be migrating to what is reflected in our economic inventory that we talked about in February, which is 60% Midland Basin and 40% Delaware Basin, we'll eventually get to that type of a ratio.

Got it. And then just following up, Ben, on your comments on the balance sheet. Obviously, leverage is in great shape. You've got the new long-term net debt target of $2 billion. And just want to kind of think about how we should be sort of kind of modeling this because when I look at the kind of the debt stack, there's very little left, obviously, on the '29, those will be gone soon. And then after that, you don't really have any near-term maturities. It's 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'm just trying to think about when you think net debt target, should we just assume that maybe in the near term that outside the '29 that a lot of it is just building cash? Or just sort of how to think about that net debt target?

Sure. So stepping back just on the target itself, in August of last year, we outlined the $3 billion, and we said strip pricing, we'd expect to achieve that in 3 to 4 years. And obviously, over the last 18 months, we've experienced higher than strip pricing, and we're able to achieve that milestone 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's 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 we'll continue to be opportunistic, John, as we look at the debt stack. There's -- it's 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, that's also a benefit to have 17 years average maturity there.

So we'll be balanced and thoughtful on that. Obviously, for our shareholders, it doesn't make a lot of sense to sit on hundreds of millions of dollars of cash for a long period of time. It's meant to be a guiding star as we continue to develop our assets, continue to explore, and return capital to shareholders. So we'll be balanced. We've done a lot of cleanup on the balance sheet so far. And it's 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'll be very thoughtful about that as we think about maturities and refinancing risk, et cetera.

Our next question comes from Arun Jayaram with JPMorgan Securities.

I wanted to see, John, if you could elaborate a little bit more on your Suriname exploration plans for 2027 with Total. Maybe elaborate on what you plan to do with the drill bit outside of outside of GranMorgu.

Sure. Suriname, if you go back to when we announced the Krabdagu appraisal wells at the time that I said that those Krabdagu wells did more than just appraise Krabdagu. They actually derisked an entire exploration fairway and tied it back to our seismic. You'll see in our supplement, Slide 19, we put out a map. It's actually a map that Total has also used and put out. We've outlined kind of four wells over the next 2 years that we'll start back with. They are very similar to what we've done at Krabdagu and Sapakara. So we're very excited about them. I do believe them derisked. I'll also point out that they will be wells that are drilled within the current development area, so they will be cost recoverable under the existing project.

But 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 a second boat or possibly even the ability we're in water depths 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's important that 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 going to be plateau extenders and you'd be more inclined to drill them later in the life cycle. But we're very, very excited. It's something that is relatively derisked, and it's something that both us and our partner are excited to get after because they're definitely going to add more resource.

Got it. And I'll 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 4Q of next year? And how -- and maybe a little bit more around your thoughts around exploration in Uruguay.

Yes, Arun, we have entered into a contract with Noble for the BlackHawk. It's a block now that we'll hold 60% and Eni will hold 40%. They're going to cover most of the well costs.

And I've got Tracey here. So I'll let Tracey high level, talk about kind of what we're going after with Eni in our OFF-6 block in Uruguay.

Sure, John. It is basically deepwater depositional system in the Cretaceous that's 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 a 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've 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.

Our next question comes from Neal Dingmann with William Blair.

John, my first question is on -- for maybe, you, 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 with Cheniere, the contract, and the FT given certainly what looks like to be a volatile commodity market.

Yes, Neal, I'll have Ben jump in on this one.

Sure. So yes, strip pricing from last week, which is -- which we do for every earnings we said it the week before. At strip pricing as we look for next year across LNG, Waha, NYMEX and Houston Ship Channel, that gas trading portfolio is going to generate about $950 million of pretax cash flow. Current prices, they continue to move around. I'd say it's probably in the mid- to high 8s now. So still a significant contributor there. What you see is that this year, obviously, a lot coming from the pipelines. And then LNG, they were more balanced, just kind of given how the curve is next year. The Permian FT portion has shrunk, and that's expected. You've seen a lot of new pipelines, not only be FID-ed recently, but also coming on this year, and that's going to continue into early next year.

So you're seeing Waha strengthen. But 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's done through the conflict in the Middle East. So just stepping back, it's 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're going to be over $3 billion from that book of business for us. So it's differentiated. It goes into our shareholder returns, and we expect that to continue for many years.

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

Neal, 2 good questions. I would say, first in Egypt, they've been a long-term peacemaker over there and have done a really good job in difficult time periods. We've seen that over the last couple of years, starting with Gaza and now what's happening here and now things have moved into the Red Sea. But Egypt has done a great job. We continue to be in very, very close contact with both the Egyptian government and the U.S. Embassy. And obviously, the -- our highest priority is the safety and well-being of our employees over there. But things continue to be something we keep a close eye on, but Egypt has done a really, really admirable job thus far. And I would expect that to continue, but it's something we watch very, very closely.

Steve, anything you want to comment on the workovers?

Yes. Neal, you might remember a few years ago, we had an issue with some mounting workover backlog in Egypt. And we ended up with about 20 workover rigs running in Egypt back then. Since that time, we've concentrated quite a bit of activity around increasing workover rig efficiency and making sure that we're getting after the workover opportunities as quickly as possible. Just recently, we're currently running 23% more jobs per workover rig than we have in the recent past. So we've gotten really quite good at this. At any point in time, we'll be running today between 15 and 20 workover rigs in Egypt. And that backlog has 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.

The last thing I'll add on Egypt there, Neal, is we got current last September on our PDRs, and they've done a really good job of staying current. And so it's been a real good situation. We've been bringing on gas, which has been helping them. They're importing and buying LNG. And so that's been a big deal. And then, of course, they got current with the rest of the industry in June of this year. So I really applaud them for doing a really, really good job in a difficult time period.

Our next question comes from Chris Baker with Evercore.

I wanted to follow up on the '27 outlook. I think, Ben, you mentioned that further efficiency gains are not part of the initial look that you all have outlined today. I'm just curious to the extent that you do see some of those efficiency gains continue and offset some of the cost pressures, we're likely to see that show up in terms of lower capital or perhaps higher volumes?

Sure. Yes, I just -- we've made so much progress over the past 2 years across the company in all 3 buckets that we've talked about on controllable spend with capital, LOE and G&A. On the capital side, a lot of that progress has been in the Permian and concentrated this year in the Midland Basin and the ability to park rigs over DSUs and have them just really work drives lower drilling days and a lot of different efficiencies, and that's even beyond other development design and other changes that the team has implemented, and we've done all of that with higher production. So hats off to the team there.

The main takeaway is, as John and Steve alluded to earlier, higher increase in the Delaware Basin. We've made progress on certain wells there, but we just don't have as many at-bats in the Delaware, and that will increase next year. And we'll 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's upside there. We didn't include that right now. I just want to make sure that we get over there and get some wells down in the Delaware, and we'll update folks as we continue throughout next year.

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

Yes, Chris, this is Steve. So we did announce at the beginning of the year, we had about $100 million of what we call LOE projects. And that's probably doesn't do justice to the projects because they also include benefits in reliability and runtime and uptime. So it actually shows up both in LOE reduction, but also in production efficiency and production resilience as we call it. That $100 million was being spent -- it's primarily -- it's in the Permian Basin. It's 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 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're 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 as much as $100 million, but a meaningful amount of projects. And I would say that, that's 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 of stuff, as you can imagine, would be done in front of the drilling rigs. And so we're not going to go out and do work that we don't need to do because we're not drilling in a certain area.

Our next question comes from Michael Scialla with Stephens.

I wanted to ask about the debt. You're getting your net debt down to 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?

Sure. We're thoughtful across our capital returns and our debt balance. One of the things that we take into consideration is obviously funding our exploration program, but we've got a differentiated free cash flow inflection coming from GranMorgu in '28, and that continues through the end of the decade. And 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 believe that 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 have the different priorities that we're managing across development capital, exploration capital, continuing to get after our decommissioning assets and lower debt is going to really just make Apache stronger over the long term and give us a lot of options as we look even beyond 2028 with additional free cash flow from GranMorgu. So set us up well. We didn't want to plant a flag and say we're done. So continued work there. But it's not going to come at the cost of anything else across the priorities that the company has.

Makes sense. Appreciate that, Ben. I wanted to follow up on Alaska. Looking at the appraisal well you have planned for Sockeye, it strikes me that it's 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'm just thinking about the resource here. I don't want to pin you down on any number, but it looks like obviously a large potential resource. And I'm wondering how you're thinking longer term if you do have success here with the 50% working interest. Are you comfortable maintaining that? Or would you look to bring a partner like you did in Suriname?

Yes, Mike, I mean, when we announced the Sockeye discovery, we said it was a stratigraphic feature that was 25,000 to 30,000 acres. Now clearly, we're stepping out a pretty good distance from that with Hungry Horse, and it is -- I think it's over 6 miles as a crow flies. It's something we're very excited about. It looks fantastic. We did reprocess the seismic data last year. And one thing we did learn is that we did not drill Sockeye initially in the thickest part. That's something that the seismic told us. So we are anxious to appraise it with Hungry Horse. It is a pretty big step-out appraisal well. And then we do have a very large prospect in Chinook that we're also very excited about.

There's tremendous resource up here. We think 50% is a good starting point for us today. With the Savant acquisition that we have on queue, it kind of brings us some starter kit things that we can work with a pipeline, a big gravel pad, there's a dock, there's a runway, a lot of things, and we're going to have a lot of flexibility. But we want to 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.

Next question comes from Charles Meade with Johnson Rice.

Tracey, I want to start by saying circum-Atlantic, that's a new word for me, but I think I understand what it means. John, if I could actually go back to the earlier question around the exploration in Suriname. If I understood you correctly, I think what I inferred from that is that these other prospects that you and Total plan on drilling are similar and maybe similar age and similar settings to Krabdagu as opposed to a different or new kind of play type. And I'm wondering if I'm understanding that correctly. And then also, all other things being equal, which, of course, they're not, but it looks like the most interesting one to drill would be that one to the west of Sapakara, where it looks like you could test 2 different prospects with one wellbore. But I wonder if you could just comment on my interpretation there.

No. I mean I'd say it is exactly similar reservoirs, right, same play, same age rock. Actually, while Sapakara is really one primary zone, Krabdagu actually has multiple targets, and we've been clear on that. We do see multiple targets to the west there of Sapakara. But as I've said, these are very, very similar to what we already understand and are part of the development plan for GranMorgu.

So anything you want to add, Tracey?

No, I think, John, that's spot on. We do see -- as John mentioned, like in Krabdagu, multiple locations where we've got more than one zone that's hydrocarbon bearing. And so I don't think that's going to be uncommon as we continue to drill these out.

Our next question comes from Bob Brackett with Bernstein Research.

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

Bob, I'll just say they're inside the existing bucket, right? So yes, I mean -- but...

Okay. Interesting. The other question I might have is, typically, in a PSC such as this when there's an exploration phase and you'll relinquish parts of the block that you deem nonprospective over time. And I'm thinking back to Bonboni, for example. When you chose these prospects, have you relinquished other parts of the block that you deem nonprospective? Or is there a chance to go out and look at a different system or a play idea?

I mean at this point, we have not relinquished any of 58. In 53, we relinquished everything, except for the little corner that we've got mapped there around Baja. But those are -- we've still got some time and some work to do with Staatsolie in terms of Block 58. I think we'll be able to keep a big piece of this for quite a while. But there are some things in the future where we do have procedures in place that we have to work through with Staatsolie.

Our next question comes from Leo Mariani with ROTH.

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

Yes, Leo, it's a great question. I'll just say it's early. We announced the discovery well, the 2 wells, but Sockeye, we have not come back and started talking about what we would need in an FID case or anything at that point, at this time. So we want to appraise Sockeye first, get Chinook down and then when we're ready to come back and talk about some things, we can give more color and more detail there.

Okay. And then just in the U.S., obviously, you're 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've 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 kind of more competitive?

And then secondly, do you still think there's kind of wood to chop on efficiency gains overall in the Permian?

I mean I think there's definitely wood to chop. We keep staying after it. I think it's more just a function of our portfolio and the prospectivity over time. What we've tried to do is efficiently develop resource. We made great progress in the Midland. We've also made good progress in the Delaware. But when you just look at our inventory longer term, post Callon, we picked up a lot of potential. We've got a lot of shallow zones, a lot that's in our technical inventory bucket to be moved over. And so 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's just kind of the natural progression of our program. But definitely see -- as Ben outlined well, we see room for more efficiencies in the Delaware like we've been able to extract in the Midland.

Our next question comes from the line of Noah Hungness with Wells Fargo.

I just have one quick one here. And it was on your comment there, John, about derisking some of the technical upside locations in the Permian. When we're thinking about your program next year and in a success case, how could we think about the amount of inventory that you guys could derisk in your '27 program?

Yes. No, I mean, we came out in February with a good look at both our -- what we'll call our development inventory and then our technical locations. At some point, we'll come out with another refresh of that. That's something we're constantly working on. We're always testing things. We have what locations as we're consuming inventory in a year. We're also testing things and moving things over. And we'll 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 HBP acreage. So there is a progression there that has taken place this year. There's more taking place now, and we'll come back and update that. We'll figure out the appropriate cadence, but we rolled that all out in February of earlier this year.

This concludes the question-and-answer session. I'd like to turn the call back over to John Christmann, CEO, for closing remarks.

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.

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

Good day, and thank you for standing by. Welcome to APA Corporation's Second Quarter 2026 Financial and Operational Results Conference Call. [Operator Instructions] 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 Christmann. Ben Rodgers, CFO, will share further color on our results and outlook. Steve Riney, President; and Tracey Henderson, Executive Vice President of Exploration, are also on the call and available to answer questions. We will start with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you 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'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 2 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 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're pleased to welcome Eni as a strategic partner in OFF-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 2 core assets. As a reminder, following the Callon integration, we initially estimated that sustaining Permian oil production around 120,000 barrels per day would require 8 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 4 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 Qasr. 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 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'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 2 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'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 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 with 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 6 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 3 years. While higher prices have played a role, we are also benefiting from structural improvements we've made across the business over the past 2 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 U.S. and North Sea, more than offsetting diesel inflation. This further demonstrates that the efficiency improvements we've implemented over the past 2 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 increased gas production revenue, but reduced 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 3- to 4-year time frame 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 2 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, 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.

[Operator Instructions] Our first question comes from Doug Leggate of Wolfe.

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 a -- the semblance of a development with Sockeye as it stands today? Or is it contingent on a successful appraisal program? And any other color you can offer would be great.

Well, Doug, I always appreciate you coming in. 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 2 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 2 key wells set up for this upcoming winter.

We'll start building ice roads late this year and then spud 2 wells in '27. One will be an appraisal well of 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 the Sockeye discovery. And Chinook is a similar prospect, but just much larger.

What Savant brings to us, Doug, it is strategic in that it's positioned right next to us. It obviously has a 25-mile pipeline with 80,000 barrels a day of pipeline capacity, but it also brings a large gravel pad. There's 40,000 barrels a day of processing equipment, and it has an air strip 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 plays that are being developed quite a ways away to this.

And so we're very excited about it. It's state lands. It's oil. The new processing and the seismic was a really, really good call. So we're very, very excited about it, Doug, but our next step will be to appraise Sockeye, drill Chinook and then come back and be in a position to talk more about it at that point.

Okay. I understand. My follow-up. If I may take advantage of Tracey being on the call or whoever wants to take this. But the Eni deal, ANCAP has given quite a lot of detail on the prospectivity of the whole area. Eni is obviously a top -- 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 deepwater, John, Raya, 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, we've got 2 blocks, Block 6, which we had 100%. We now have 60% in that. And we are really, really thrilled to welcome Eni as our partner. It was a very competitive process, and it really speaks to the quality of our position in Uruguay and how prospective that block is. But also a credit to our exploration team and the work that we've done now with Suriname, bringing in Total, and we're less than 2 years away from first oil there with GranMorgu and now bringing Eni into Block 6 in Uruguay. So we're thrilled to have them here. I'll let Tracey jump in. Obviously, the one well was to -- and we believe was not drilled deep enough. Our objectives will be much deeper. But I'll let Tracey talk a little bit about the geology and what the concepts are and what we've got there.

Sure. 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 what we're looking at is basically the conjugate margin geology that's worked on both sides of the margin up and down West Africa and 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 deepwater 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 will be a very, very big well. We've got a really high-quality 3D seismic data set over the prospects in Block 6 and Block 4, though we are looking at extending it in Block 4. But we see some terrific prospectivity on the 3D, very large prospects. And as John said, we'll look at testing that in late 2027.

Our next call comes from John Freeman of Raymond James.

Last quarter, you all emphasized maintaining the flexibility between debt reduction and buybacks. And now given just how strong the balance sheet is, obviously, you all are pretty explicit that the #1 priority now that 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 flow to 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 is Ben. Good question. And yes, 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 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 having that so close from when we outlined the target in August and here we are at the time in May, you're 9 months from that and it was so close, really just gave us the opportunity to look at balancing those 2 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 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. And then you all raised your cost savings target yet again to the $500 million. Can you kind of clarify how much of that has actually been captured versus what still needs to be achieved between kind of now and year-end? I know you all highlighted some projects in the Permian in the presentation, but just a little bit more clarity on what's captured and what's still left.

Yes. So I'll actually do it from an annual basis, John. And 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 million is actually closer to the high $400 million, 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 million. But when you account that inflation, it's probably closer to $425 million. But because we're capturing more true savings, that run rate is now higher from the $450 million, and it is now $500 million and it's across all 3 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 savings. And then G&A continues to trend in the right direction as well. So that incremental $50 million of run rate savings exiting this year is across all 3 of those buckets.

On top of that, we've separated the controllable spend of those 3 buckets from interest expense savings. But we also now because -- and from our 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 2 years ago around controllable spend and really getting after the debt paydown, 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.

Our next question comes from Josh Silverstein of UBS.

Ben, you highlighted some of the benefits of the gas trading portfolio and how there's limited free cash flow impacts from 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 costs to kind of have a similar kind of net zero impact? And how things may look for you guys next year?

Sure. Good question. Actually, since we've -- since those pipeline positions have been put in place and starting in 2019, 2020 and then the Cheniere 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 5-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 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.

Got it. And then, John, you've mentioned you're 2 years away from the start-up of the GranMorgu project, and it's clearly a key differentiator for your growth profile into the future. Knowing you have this around the quarter -- 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, but how do you think about different options there?

Yes. I mean, I think, Josh, it's a great question. And first of all, things are on track with GranMorgu. 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 we can just maintain volumes on our core assets of Permian and Egypt, well, then you've got growth coming, right, through our exploration program and through Suriname. I think a couple of things. So the big thing here 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 led us continue to make progress on the balance sheet and deliver on the returns framework while we're funding such a large-scale capital project.

And so it really, really has worked 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 growing our BOEs -- gross BOEs in Egypt. So 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 it puts us in a really, really good place to continue doing what we're doing, and we're thrilled to be in the place we're in today.

Our next question comes from Arun Jayaram of JPMorgan.

John, I was wondering if you could comment on how you think your sustaining requirement -- 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 4. 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 sustaining capital based on efficiency gains.

Yes, Arun, it's a great question, and we're in a really dynamic period, both for us and industry. And if you go back to post close of Callon, we believed it was 8 rigs to hold 120,000 barrels a day flat. As you mentioned, we're now currently at 4. We've guided to 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 6. We've been running -- we're at 4 rigs today. We started at 5. We dropped down to 5 last year. We're clearly under 6 rigs to maintain at 120. We've been doing that for the last 2 years. So it does give us some flexibility in terms of how we think about that. And I'm not ready to dive into '27. We'll 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 very proud of that.

And I think the one other thing I'd say is the number of rigs is not as critical of a number as it used to be because it ultimately boils down to wells you're drilling, feet you're drilling and the turn-in lines. But I don't know, Steve, anything you want to add to that.

Yes, John, I'll just -- just to echo your last comment there, we started the year -- this year with a plan of 5 rigs, and we're clearly going to end up at 4.5 rigs. Those 4.5 rigs will drill more lateral feet and we'll complete just as many wells as we planned with 5 rigs. And so we're down to 4 rigs for the second half of the year. We're actually moderating frac 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 the -- 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 8 rigs would sustain 120 and halfway through the year, we were at 6 rigs, sustaining 120.

And I agree with you, right now, we're -- we've been delivering basically 123,000 barrels of oil a day. And by the end of this year, it will be for 2 years straight. And we're doing that clearly with fewer than 6 rigs. We'll average 4.5 this year. Not saying that it's 4.5, 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. Wondered if you could elaborate on some of the exploration type work you're doing in the Western Desert.

Yes. Arun, 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. We started then to -- how do you translate what we know into gas. We knew there were some low-hanging fruit that you saw us get after last year. But we've really only been exploring now for gas in the Western Desert for, 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.

The key to think about in Egypt is 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. Egypt, it's the nuances of can we predict 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 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.

And so 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 the key here is it's conventional, it's not unconventional. And success has been set up 1 to 2 to 3 to 5 type well offsets. And so we've got a lot of concepts that are at play.

Our next question is from Neal Dingmann of William Blair.

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

Yes, Neal. I mean, I think the most important thing there is we've stayed committed to exploration. We've tried to allocate approximately 10% to 15% of our capital to exploration. It's something we stuck with. Obviously, going back to 2019 when we spud the first well on Block 58. And then we ran a rig during 2020 during COVID in Block 58. From there, we went into appraisal in Suriname and continue 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. 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 entry into Uruguay for us.

We were able to do the deal with Armstrong in Alaska on state lands for what's now a very large position. So I think the important thing is we were able to kind of build out our portfolio at a time when we knew we had exploration 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 exploration starting last year and now this year. And so when you look at our portfolio today, you follow on Block 58 success. There is more to do in Block 58. We will be back in there with Total next year exploring. And we're looking to either add to the plateau for GranMorgu 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 and Alaska at the top because we've derisked 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. So we need to go see. You've got what Tracey described to Doug a little bit earlier in the Q&A across the conjugate margin in Namibia. But -- so we're very, very excited about it. And 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. And quite frankly, we've really derisked both Suriname, Block 58 and Alaska through already what our successes.

Yes, I would agree on the deep portfolio and the derisking. 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 -- of 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 5 years since it's been in service. And we're -- 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 5-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 it's -- we're in a really good position right now as we look at that.

Our next question is Chris Baker of Evercore ISI.

Just wanted to maybe step back for a second, some great progress in terms of the debt reduction we've seen year-to-date. Obviously, with the $3 billion target and expecting to end the year at $3.3 billion, it does seem like we're coming up to a point where you'll be at 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 either incremental cash return to shareholders or 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, would love to get a sense just for how you're thinking about that.

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 will kick up next year because we've got such a high-quality portfolio. The base business is running extremely well, and Suriname is 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 returns framework.

So Ben, I'll let you comment more on specifically the $3 billion debt target.

Yes, 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 2027, you reach that. You'll be likely within a year plus from GranMorgu. 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 delever the business. But that will be balanced with what we'd like to do with -- on the shareholder side is 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 GranMorgu now less than 2 years away. Next year would be less than 1 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. And then obviously, a lot of progress as well in terms of capital efficiency in the Permian, getting down to the 4.5 rigs. Obviously, it's a big move from where you all started after the merger. I'm just curious, in terms of how you think about the biggest potential sources of further improvement there. I guess where is the team's focus? Would love to get a sense of where we could see continued progress on that front.

Yes. 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 recent strides have been with really fine-tuning your well designs and your slim hole, you've gone to the simul, trimul fracs, all of those things.

So 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. But I mean, they've got those down now where you look at the per foot numbers. You really are benefiting from scale and the repetitions that we've got. So I think that's the big thing.

Some of the opening plays, a lot of what we're doing on the testing side to move the technical locations into economic. 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.

Our next question is from Bob Brackett of Bernstein Research.

I'd like to return to Uruguay Block 6. The Raya prospect was Cenozoic and was sitting out at 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?

Yes. Bob, I'll say a few things. One, it is frontier. The prospects are very, very large.

Tracey, I'll let you jump in. They are Cretaceous. I'll let you comment a little further on that.

Correct, John. They are Cretaceous. So 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 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 bathymetry in terms of drilling in the water depth. So that's not really a factor in terms of where we're planning 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. A 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 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, Eni, who we're very much looking forward to as we've mentioned previously. I think they're top-tier explorer and we'll 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.

And our next question is from Leo Mariani of ROTH.

I just wanted -- you mentioned this a couple of 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 of 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 kind of 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 the -- how we define that 60%. You won't see us 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 it's something we've been -- we've stuck to over the last decade, and we'll continue in the future.

Okay. And just on the exploration side, like you said, you're 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.

Yes, 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 '27. We've got the 2 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, those extra 2 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 I think a decent assumption for that is kind of $100 million to $120 million for those 2 wells in Alaska, 1 to 2 wells in Suriname. So I think those are -- you could assume $50 million 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 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 Suriname 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 from next year, your -- you probably have a 2 handle on exploration spend. So yes, 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, Alaska, Block 58, et cetera, past '27. But there will be that increase from this year to next, and then we'll take it from there as we get to the end of the decade.

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

In closing, let me leave you with 3 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 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 GranMorgu less than 2 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.

Good morning, ladies and gentlemen. Welcome, and thank you for attending the Annual Meeting of Shareholders of APA Corporation. It's 10:00, and the meeting is called to order. My name is Lamar McKay, Chair of APA's Board of Directors. On your screen, you will see today's agenda and the rules of conduct for the meeting. I would first like to thank the members of the Board for their service and commitment. And on behalf of the Board, I'd like to thank the employees of the company for their dedication and many accomplishments this past year.

The nominees for election to the Board of Directors today are: Annell Bay, John Christmann, Juliet Ellis, Ken Fisher, Charles Hooper, Chansoo Joung, Peter Ragauss, Dave Stover, Anya Weaving and myself, Lamar McKay.

I'll now turn the meeting over to John Christmann, APA's Chief Executive Officer.

Thanks, Lamar. Officers available today are Steve Riney, President; Ben Rodgers, Executive Vice President and Chief Financial Officer; and Kim Warnica, Executive Vice President, Chief Legal Officer and Corporate Secretary.

I appoint Ms. Warnica, as Parliamentarian and as Secretary of the meeting.

Ms. Warnica was notice of the meeting duly and properly mailed and is the inspector of election present?

Yes. The proxy statement and notice of the annual meeting were mailed to shareholders on April 9, 2026. We have an affidavit to that effect from BetaNXT and samples of the items mailed.

Also, a certified list of the shareholders of record as of the close of business on the record date, March 23, 2026, has been available at the company's headquarters for the past 10 days.

As of the record date, there were 353,400,414 shares of common stock outstanding and eligible to vote at this meeting. A quorum is present a meeting may proceed with business.

Amanda Wood with BetaNXT has been appointed as the inspector of election to receive the proxies, judge the qualifications of voters, collect and count the votes, report the results of the ballots and perform any other duties that may be required.

The minutes of the last annual meeting of shareholders held May 22, 2025, are available for inspection. Reading of these minutes will be waived. The company did not receive timely notice of any other director nominations by a shareholder as required under our bylaws. Therefore, the nominations are closed.

The first item of business for this year's meeting is the election of directors. The directors elected at this meeting will serve for a period of 1 year starting today and ending on the date of the annual meeting in 2027. The nominees were named earlier, and I hereby declare them duly nominated.

The second item of business is ratification of Ernst & Young LLP as APA's independent auditor for fiscal year 2026.

The third item of business is an advisory nonbinding vote to approve the compensation of APA's named executive officers.

The fourth and final item of business is approval of an amendment to APA's 2016 Omnibus Compensation Plan.

Each of these items was described in the proxy statement provided to all shareholders. The polls are now open.

[Voting]

Any shareholder who has not yet voted or wishes to change their vote, may do so by returning to the e-mail with the meeting link, clicking on the vote button and following the instructions. Shareholders who have sent in proxies or voted via telephone or Internet and do not want to change their vote, do not need to take any further action.

The next item on the agenda is the preliminary report of the inspector of election. Any ballots collected before the polls closed but not reflected in the preliminary report will be reflected in the final report of the inspector of election.

The polls are now closed. Ms. Warnica, do you have the results?

Yes. The inspector of elections has reported the following results. Each nominee for the office of director has been elected. The ratification of EY as APA's independent auditor for fiscal year 2026 has been approved. The compensation of APA's named executive officers as disclosed in the proxy statement has been approved. And the amendment to APA's 2016 Omnibus Compensation Plan has been approved.

I hereby declare that all matters submitted for a vote of the shareholders have been approved. With no other business to come before the meeting, the formal meeting is adjourned.

Good day, and thank you for standing by. Welcome to the APA Corporation's First Quarter 2026 Financial and Operation Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Stephane Aka, Managing Director of Investor Relations. Sir, please go ahead.

Good morning, and thank you for joining us on APA Corporation's First Quarter 2026 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John Christmann. Ben Rodgers, CFO, will share further color on our results and outlook. Steve Riney, President; and Tracey Henderson, Executive Vice President of Exploration, are also on the call and available to answer questions.

We will start with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you 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'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. Today, I will review our first quarter 2026 results, highlight our execution against APA's strategic priorities and share our outlook for the remainder of the year. I want to first acknowledge the ongoing events in the Middle East. The escalation in geopolitical tensions and the human impact of the conflict are deeply concerning. Our thoughts are with those affected. Our teams in Egypt continue to operate safely and without disruption.

We remain in close coordination with our partners and government stakeholders. We have a long track record of operating in the country, and our priority remains the safety of our people and the reliability of our operations. The increased volatility in global energy markets reinforces the importance of a sound long-term strategy. At APA, our strategy is very clear. We will deliver top-tier operational performance across our assets.

We will build and grow a high-quality portfolio, and we will maintain financial discipline. These principles have guided our strategic direction and capital allocation priorities over the last several years and continue to shape our path forward. Our operational focus has never been stronger. In the Permian, we've significantly improved capital efficiency while delivering resilient oil production volumes, all with fewer rigs and lower capital intensity.

Our improving execution is driving cost leadership across key operational categories with great momentum and clear visibility to further progress ahead. In Egypt, we've strengthened base production reliability through targeted waterflood investments, a more efficient workover program and increased uptime, all of which have helped moderate effective base decline rates. At the same time, we're expanding our gas development activity to build a more durable total production foundation.

Across the broader portfolio, we've continued to high-grade our key assets and build long-term optionality. First, in the Permian, we've repositioned the asset base to be entirely unconventional, establishing more than a decade of economic inventory with meaningful upside. Second, in Egypt, we've enhanced the value of our assets through improved fiscal terms and a more gas-weighted activity mix. Third, in Suriname, we're advancing a world-class development toward first oil.

And finally, we're building future growth opportunities through exploration. With respect to financial discipline, we've streamlined our corporate overhead to drive sustainable structural efficiencies. This lower cost base, combined with disciplined capital allocation across our high-graded portfolio supports more steady free cash flow generation through commodity cycles. Alongside our highly profitable gas trading business, this positions us to deliver meaningful shareholder returns while accelerating progress towards the $3 billion net debt target we set just 9 months ago.

Together, these actions demonstrate consistent execution of our strategy, which is to drive strong operational performance, position the portfolio to deliver long-term value and maintain balance sheet strength. Turning to the specifics of our first quarter performance, I'd like to highlight several notable achievements. Across the portfolio, our teams executed exceptionally well and delivered capital spend and operating costs below guidance despite inflationary pressures.

In the Permian, operational efficiencies and improved uptime drove oil production above guidance, while gas volumes were curtailed due to weak Waha pricing. In Egypt, continued success in the gas program, including on our newly acquired acreage is underpinning the delivery of our ambitious 2026 targets. Longer term, we remain excited about the extensive prospectivity of the Western Desert.

Robust asset performance, complemented by favorable commodity prices generated nearly $0.5 billion in free cash flow during the quarter. Ben will discuss the steps we're taking to further strengthen our balance sheet in the current price environment. Looking ahead, we are carrying significant operational momentum into the balance of the year. In the U.S., we are raising our full year oil production outlook to 122,000 barrels per day, reflecting our confidence in continued strong performance.

In Egypt, despite gross production volumes above previous expectations, our adjusted volume guidance has been lowered to reflect the PSC impacts of higher commodity prices. We remain focused on capital discipline and cost management with no change to our upstream capital or LOE guidance. In closing, our first quarter results reflect continued execution across our Permian and Egypt assets.

In the current higher commodity price environment, we are prioritizing free cash flow generation over incremental activity and maintaining a sustained focus on cost reductions to drive long-term value. We remain rigorous in our capital allocation across our foundational assets in the Permian and Egypt, which are poised to deliver consistent production volumes for the next several years, providing a stable and durable base for free cash flow generation.

Organic high-margin oil production growth is expected to come from Suriname GranMorgu, which remains on track for 2028 first oil. This is a clear differentiator relative to our peers, representing a significant free cash flow growth engine for the long term. We remain committed to our capital returns framework with a clear path to further debt reduction and share repurchases, supported by our current free cash flow outlook. I will now turn the call over to Ben.

Thank you, John. For the first quarter, under generally accepted accounting principles, APA reported consolidated net income of $446 million or $1.26 per diluted common share. Consistent with prior periods, these results include items that are outside of core earnings. The most significant after-tax item impacting adjusted earnings was $37 million of unrealized derivative instrument losses. Excluding this and other small items, adjusted net income for the first quarter was $489 million or $1.38 per diluted share.

APA generated $477 million of free cash flow in the first quarter, of which $88 million was returned to shareholders. John already covered key elements of our outlook for the rest of the year, so I'll focus on a few additional items. For the second quarter, our outlook for U.S. BOEs assumes continued natural gas curtailments through the end of the second quarter, driven by the current forward strip for Waha gas pricing.

No price-related curtailments are assumed in our U.S. BOE production guidance for the second half of the year. For Egypt adjusted total production, about two-thirds of the second quarter decline from the first quarter is related to higher Brent prices. As a reminder, while higher prices increased profitability, they reduce adjusted volumes under the PSC cost recovery mechanism, an accounting impact rather than a change in underlying gross production volumes.

The remainder reflects the successful recovery of backlog costs from our 2021 PSC modernization, which was completed in the first quarter. As John mentioned, our full year upstream capital guidance remains unchanged at $2.1 billion. We expect to incur approximately 55% of this spending in the first half of the year, largely driven by the cadence of activity in the U.S.

We anticipate most of our Permian turn-in lines to occur in the second and third quarters, sustaining oil production volumes through the second half of the year. We've also updated our guidance for current taxes to reflect higher pricing assumptions relative to our prior outlook. We now expect 2026 U.S. and U.K. current tax expense to be approximately $230 million, nearly all of which is in the U.K., where we are subject to a 78% effective tax rate.

Looking at our oil and gas trading portfolio, based on current strip pricing, we expect these activities to generate approximately $1.1 billion of pretax cash flow in 2026. This is inclusive of commodity hedges and reflects significantly wider Waha basis and higher LNG prices since our last update. Turning now to the balance sheet. We ended the first quarter with approximately $4.1 billion in net debt compared to $4 billion at the end of 2025.

This slight increase is attributable to a large use of working capital, almost all of which was driven by 2 factors: first, an increase in total company receivables due to the significant rise in oil prices late in the quarter. Second, the payout of incentive compensation accrued throughout 2025, consistent with our usual practice. As outlined on Page 8 of our supplement, we've repaid $634 million of near-term bond maturities year-to-date, including $555 million in April.

Combined with the deleveraging steps taken in 2025, this results in interest savings of more than $60 million versus last year. Compared to 2024, we now expect annual interest expense to be approximately $150 million lower on a run rate basis at the end of 2026. With no debt maturities until December of 2029, we have significant financial flexibility to manage our decommissioning liabilities in a deliberate and efficient manner while maintaining our broader capital allocation priorities.

Moving now to our cost reduction initiatives, where we're continuing to make progress across capital, LOE and G&A. We remain on track to achieve our $450 million target for cumulative run rate savings by the end of 2026, which is reflected in our current guidance. Building on the significant strides made last year on capital and operational efficiencies, our focus this year will span all 3 categories with the same discipline and focus that enabled the results we delivered in 2025.

Including the previously noted interest savings, we expect run rate cash costs to be $600 million lower exiting this year compared to 2024. While commodity prices have been volatile since the start of the conflict, the strength of our execution and contributions from our gas trading portfolio position us to generate significant free cash flow this year. Currently, as outlined on Slide 9 of our supplement, we expect to generate approximately $2.2 billion of free cash flow for the full year.

This level of cash generation meaningfully advances our progress toward achieving our $3 billion net debt target in the near term while supporting shareholder returns. In closing, these results mark another quarter of consistent, predictable performance across our asset base, underscoring the disciplined execution we've demonstrated for more than a year.

We remain well positioned to deliver significant free cash flow this year and beyond, supported by continued execution and structural cost improvements. We will continue to allocate capital with rigor, balancing shareholder returns, balance sheet strength and investments in future growth through exploration. With that, I will turn the call over to the operator for Q&A.

[Operator Instructions] Our first question will come from the line of Doug Leggate with Wolfe Research.

I guess, Ben, maybe for you first. The big -- the gas trading number is pretty meaningful. I think if I go back maybe, I don't know, about 6 or 9 months ago, you talked about a $300 million kind of run rate. But now we've got Hugh Brinson and a bunch of things going on in Midland coming online. But with what you know today, given what's happened with TTF, what would you say your line of sight is, what does it look like beyond 2026?

And what tools do you have to maybe protect some of that? That's my first question. My second question, if I may, is, John, it's probably for you, but just a quick one on Alaska exploration. My understanding is you've been waiting on the seismic. My understanding is you've now got the seismic. I'm just wondering what that informs for your views on the existing discoveries and what your running room is for the upcoming drilling program. I'll leave it there.

Sure. Thanks, Doug. So when you look at the marketing book, the $1.1 billion this year, a lot of that is coming from the pipeline transport side, about $300 million is coming from LNG for the year -- for the remainder of the year. And the bulk of the pipeline transport really is kind of through the summer where we see very wide basis differentials.

To your point, that starts to compress at least per the curve, given GCX expansion, the Blackcomb pipeline and Hugh Brinson coming online kind of all in the second half of the year. So we watch that, and we'll see how the basis trades given the different dynamics with gas production in the basin, higher GORs, a lot deeper targets being drilled with more gas cut than other wells. And so we monitor that.

Basis does, at least per the curve, continue to tighten into '27. But the good thing is that with the elevated LNG prices this year, that does carry through into next year. And at current strip, we're just above $400 million of expected pretax cash flow in 2027 at strip for both basis and TTF. So still another good year expected next year.

We'll monitor that. We have hedges on just the basis for this year. We do look at other options to hedge 2027, both on the LNG and the basis side. We've not done any of that, but we monitor that daily. And if we find the right opportunity, we'll look to lock some of that in. But even next year at around $400 million, it's still looking to be another good year for us.

And Doug, on the Alaska question, yes, we took the -- this winter off to reprocess the seismic. And if you go back, when we drilled Sockeye, we said we went to Sockeye not because it was our biggest prospect because it's where we had the best seismic picture. Taking the results from Sockeye and King Street and integrating those into the new reprocessed seismic was really, really the right thing to do.

We -- us and our partners are all thrilled that we took that pause. It now looks like we did not drill Sockeye even in the thickest place. And we will be coming back this winter with a 2-well program. We're in the process of assuming operations, but you'll see us come back with an exploration well and an appraisal well. And we're very, very excited about Alaska.

Our next question will come from the line of John Freeman with Raymond James.

The first question, obviously, it was nice to see you'll be able to take advantage of the macro backdrop and retire all those near-term maturities. And obviously, buybacks sort of took a pause. When I sort of think about like the rest of the year, should we assume, given that the next maturity is not till 2029 and those aren't callable yet, should we just assume the majority of the free cash flow goes toward buybacks?

I know Ben mentioned maybe the decommissioning obligations. I wasn't sure if that meant that maybe some of those get accelerated. Just any color on -- obviously, it's a high-class problem, but just usage of the free cash flow.

No, John, it's a great question and a good observation. I mean I'd start out and say we're living in unprecedented times. We remain committed to our 60% returns framework that we initially outlined in the fourth quarter of 2021. Since the inception of that framework, we've actually returned 71% of our free cash flow to shareholders.

And there have been times when we leaned in on the equity side and times when we leaned in on the balance sheet side. We also, 9 months ago, outlined a net debt target of $3 billion. And that's something that's also a priority for us. The beauty of today is we've got commodity exposure to both WTI Brent pricing, LNG and the basis in Waha.

So it puts us in a position where rolling forward, we do have a very robust free cash flow outlook for the remainder of the year. The thing I would say, John, is while we've made progress on the balance sheet, we're going to continue to be very, very thoughtful about how we deploy that. We like where the valuation is, but we also want to be thoughtful. Anything you want to add to that, Ben?

Sure. I think to just reiterate, given the current price environment and the opportunity we have to improve the balance sheet, we took some of those steps through April. We think the responsible thing to do is just evaluate how we deploy our free cash flow for the remainder of the year.

We are committed to our framework, as John said, and really starting from fourth quarter '21 when we put the framework in place cumulatively through the year-end '25, we've returned more than 75% to shareholders through dividend and buybacks and $3.2 billion of that was in buybacks. Also on the debt side, since year-end '21, we've reduced debt by $3.6 billion.

So being only 2 months into the conflict, we've seen immense volatility, not just the past couple of days, but really over the past 2 months, we're going to be patient, recognize that really the responsible thing to do is evaluate how we deploy the significant amount of free cash flow that we expect to generate this year.

To John's point and to be clear, this is not a view on our valuation of our equity. It's just solely how we would deploy the free cash flow for the remainder of the year. We will pay down debt. We'll pay our dividend, and we'll buy back shares. It's really the mix is what we're evaluating. At these prices, that's the right thing to do.

I'd just end with, it's a great position to be in where we've got an increasing free cash flow picture, and we're going to be thoughtful on how to deploy it.

Just one other thing. John, you mentioned that with all the free cash flow, maybe we want to look at the decommissioning activity. I do want to point out, we raised guidance on decommissioning spend this year by $20 million. And I want to be really clear; that's not an increase in cost of planned activity. That's actually all increase in planned activity. There are some more platform wells in the Gulf of America that we just want to go ahead and get after, and we'll do that this year.

Appreciate all that color. And then I'm just going to shift to Egypt. Obviously, that resource base gives you a lot of flexibility between gas and oil. And I think the current program is close to 50% of the activity is kind of gas focused. And I appreciate the fact that you'll get like a $4.25 gas price, which is obviously quite attractive. But is there a certain level in that kind of where the oil price is relative to that gas price you're getting that would potentially cause you all to think about any sort of a shift in the allocation of activity in Egypt, whether it's currently or next year?

Yes. John, I'd say, first of all, when you look at where we geared and negotiated the increased gas price, we geared it towards a $75 to $80 Brent price, inclusive of infrastructure investment. And we've been fortunate that we've been able to get a lot of our new gas discoveries on without a lot of infrastructure spend. There have been some lines that we've laid and some things there. So we're in a position today where it still is very, very attractive.

I think also with the new acreage that we brought on last year, we've got new wells to drill that we want to drill there. So you're going to continue to see -- right now, the program is about 50-50. They need gas. If you look at what we're providing for them right now, they're saving about 2 LNG cargoes a month on the gas side. So we're in a pretty good place, and we want to monitor how things play out over time.

Yes. I would just add to that. As John said, we are basically splitting rig counts 50-50 between gas and oil. And on a mid-cycle price environment, we are agnostic, basically between gas and oil. And no, we're not in a mid-cycle price environment as we speak but -- and certainly much more volatile than a mid-cycle situation. But we feel like this is the right split at this point in time. And I'd just remind people that while we're getting an average of $4.25 for gas, the actual marginal price on new gas is higher than that.

Our next question is going to come from the line of Chris Baker with Evercore ISI.

First question for John. Clearly, a lot of great progress on the cost saving front, some good first quarter numbers around LOE and other costs. You mentioned inflationary pressures, I'm presuming in the Permian, but any additional color you can add in terms of what you all are seeing there? It seems like it's still a good quarterly result.

No. I think the teams are doing a really, really good job. We came into the year in Permian with higher power costs that we outlined, I think you're seeing diesel on the rise here, not just here but also globally as well. But doing a good job. We came into the year with most of our contracts and services under contract.

So we're in a pretty good place there. You have seen a little bit on tubulars. Power, diesel would be the main items. But I think in general, our teams have been able to do a pretty good job, which is why we didn't raise the cost on the outlook due to those inflationary pressures.

That's great. And the second question, just maybe for you or Ben. As you guys think about some pretty significant progress towards the $3 billion debt target, can you just help us think about how that -- what that unlocks in terms of strategic priorities or how are you thinking about the opportunity that provides you all in terms of cash returns, buyback, dividends or other sort of longer cycle investments.

Sure. So yes, last year, when we outlined the $3 billion net debt target, recall that we said that at mid-cycle prices, we'd expect to get there in 3 to 4 years. If we were below those mid-cycle prices, it may take towards the end of the decade. If we were above, we said it'd take 1 to 2 years to get there. So it's in the crosshairs of what we see now of being achievable here in the near term. I think once we achieve that, we'll look at the different priorities that we have.

Clearly, we've got a strong debt maturity runway here with no maturities due until really the end of the decade. That allows us a lot of flexibility to prudently manage our ARO and decommissioning. We've got exploration on the horizon. So we will continue to invest in the future. Last year and this year, exploration spend was less than $75 million. This year's guidance is still at the $70 million, and that's just $20 million for ice roads in Alaska and another $50 million for exploration in Suriname.

But when you get into '27, additional exploration in Suriname and the actual wells being drilled in Alaska, we'll see some more exploration spend, and that number will tick up next year. So we'll balance all of those priorities. If we reach the net debt target in the near term, we'll reevaluate at that time and likely set another target below that, but balance all the different things that we've mentioned.

Our next question will come from the line of Neal Dingmann with William Blair.

My first question is just on Suriname. Well, I know that first oil production you guys talked about from GranMorgu project in Block 58 is scheduled for mid-'28. I know you also mentioned there's various other exploration projects either also in Block 58 or 53. Is there anything that you would talk about here in the near term?

Yes. I think both us and our partner are excited about the additional exploration we have in Block 58. And Neal, if you remember back when we announced the appraisal wells at Krabdagu, I said those not only appraised Krabdagu, but they derisked an entire exploration play from a seismic perspective. So we've got a number of prospects. And the plan is when we get the rigs out there to start drilling some exploration wells that at a minimum could extend plateau or potentially even look for incremental infrastructure. So we are very, very excited about getting back to exploring in Suriname.

Very good. And then second question, just on Egypt. Specifically, I'm just wondering how many -- I think you might have said, but how many workover rigs are you currently running? And would you all consider boosting the workover count here similar to what -- to take advantage of the higher oil prices similar to what some of the domestic guys have done with their workover count?

Yes. I mean I think when you look at where we are in Egypt, we're in a pretty darn good place. We've been investing in the secondary projects, waterflood performance. We've been able to maintain a pretty flat profile for several quarters. So in pretty good shape. So Steve, anything you want to add?

Yes. I don't know the exact count of workover rigs today; it's somewhere in the mid- to high teens as it has been for quite some time. It got higher than that for a while. But -- because remember, we use workover rigs for completing new drilling wells as well as for workover activity.

Our next question will come from the line of Kevin MacCurdy with Pickering Energy Partners.

I just wanted to touch on oil realization. The international oil realizations were quite good in the first quarter. I realize that we're in a very volatile environment right now. But is there any kind of outlook you can provide for the second quarter and maybe the back half of the year for Egypt and North Sea realizations relative to Brent?

Sure. So really on both of our commodity -- our oil commodities, Brent and WTI, the current market is giving a premium for spot prices on that. We do get dated Brent for our North Sea oil as well as our Egypt cargoes that we sell. That dated Brent differential to the price that you see on the screen has varied pretty widely in the first quarter, really March and then in the second quarter. It's kind of $8 to $10 in the second quarter, compresses through the year.

So based on current strip, it's about a $5 to $10 premium for dated Brent versus the futures Brent that you see on the screen. Similar on WTI. There's a couple of factors that go into getting the forward price to a spot price. I won't go through the specific details on that. But when you put those factors together, it's about a $2 to $5 premium on WTI that producers are getting to realize for the barrels that we're selling in Midland as well.

[Operator Instructions] And our next question will come from the line of Leo Mariani with ROTH.

Yes. I wanted to follow up with you guys on LOE. Certainly, it looks like your LOE has kind of come in below guide the last couple of quarters. Can you just provide some color around the drivers there? And you mentioned inflationary pressures on the call. Do you see some of that maybe rolling through LOE the rest of the year as well?

Sure. So in the first quarter, coming in below guidance on LOE was really cost savings in the U.S. There was a little bit of timing in there as well. As we look for the full year and keeping guidance at $15.25 for the full year, we do see inflationary pressures mainly on diesel in Egypt, diesel usage and the higher price for diesel pushing up Egypt LOE. Those are offset from other savings that we're realizing currently and expect to continue to realize through the rest of the year, predominantly in the U.S.

And we've talked about the $100 million of spend that we're going to have this year on LOE uptime projects in the Permian. Those are going according to plan. And when you bake in the savings from that as well as additional work that the field is doing in the U.S. is offsetting any inflationary pressures that we have in Egypt. So full year is unchanged right now.

Okay. Appreciate that. I wanted to shift back over to Egypt. I think for at least about a year or so, you guys have kind of talked about sort of a modest decline in Egypt gross oil volumes. Looking at like the last several quarters of 2025, you guys actually did not see a decline. The number did tick down a little bit in 1Q on gross oil. Just trying to get a sense, are we still in a position where you think for the rest of the year, there's a modest decline on gross Egypt oil? Or I think you guys have been doing a good job, maybe, able to stabilize that a little more?

Yes. I think that both of those things are true, actually. But what's going on with gross oil in Egypt is that I do believe, and we've been saying this for a number of years now that over the long term, we are on a slight decline. We've gone now 4 quarters in a row, if I adjust for the small concession that we exited earlier this year. We did 4 quarters in a row where we were right around 121,000 barrels a day, flat for 4 quarters.

A little bit of noise from quarter-to-quarter, but basically flat at 121,000. What you're going to see for the next 3 quarters on gross oil, and I'm not going into '27 yet, so just the remaining quarters of this year, you're going to see something closer to flat around 118,000 barrels of oil a day. So about a 2.5% to 3% decline from the prior 4 quarters on average. And that's kind of reflective of a slight decline from year-to-year.

And so I think we're on that. It's just that when you look from quarter-to-quarter, you can have -- we're drilling some very, very nice gas wells, as you know, in Egypt. Well, some of those are rich in gas and they come with condensate, which counts as oil volumes. And so some of the success on the gas side is actually helping with the oil decline rate. The one other thing I would just note on that is that we have been talking about a slight decline in oil volumes for about 3 or 4 years now in terms of a slight annual decline rate.

That was -- we started that back when we were running basically 12 rigs drilling for oil. Today, we're running 12 rigs, half of which are drilling for oil prospects, the other for gas. And so -- and we're still talking about a slight decline rate year-to-year. So I think that speaks to the oil that comes with some of the gas volumes, but also just more efficiency on the oil drilling side as well.

That's super helpful. And then just on Egypt oil. Obviously, that seems more strategic these days given energy security issues. It doesn't really intersect with the Persian Gulf or the Strait of Hormuz. Is that potentially a consideration where you might say, hey, maybe we should do a little bit more in Egypt oil in the coming years, particularly if prices are supportive?

Today, we're in a good place with what we're executing on the projects. We've got the new acreage that we're drilling some prospects on. I think some results there. We do have oil and gas prospects there. More of the success of the program could drive what we do there. But right now, they need both commodities, and we're doing what we can on both fronts.

Yes. I'd just echo that ending comment by John in that he noted earlier that Egypt is importing LNG now. And if you look at it from an energy security perspective for the country of Egypt, they're just as interested in gas as they are in oil because they can import both oil or refined products, which they do.

And I'm showing no further questions at this time. And I would like to hand the conference back over to John Christmann for closing remarks.

Thank you. In closing, we delivered an excellent first quarter with continued execution across our asset base, driving strong operational and financial performance. In this current price environment, our focus remains on free cash flow generation through disciplined capital allocation and continued cost reductions.

We continue to make significant progress toward our $3 billion net debt target, and we'll continue to balance further debt reduction and meaningful capital returns to shareholders through the cycle. Finally, we are well positioned to sustain production volumes across the Permian and Egypt over the next several years, providing a durable foundation for free cash flow generation.

Suriname GranMorgu remains on track for first oil in mid-2028 and is expected to drive meaningful organic oil production and free cash flow growth over the longer term. And with that, I will turn the call back over to the operator. Thank you.

This concludes today's conference call. Thank you for participating, and you may now disconnect. Everyone, have a great day.

Good day and thank you for standing by. Welcome to the APA Corporation Fourth Quarter and Full Year 2025 Financial and Operational Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your speaker today, Stephane Aka, Managing Director of Investor Relations. Please go ahead.

Good morning and thank you for joining us on APA Corporation's Fourth Quarter and Full Year 2025 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John Christmann. Steve Riney, President, will then provide an update on our Permian inventory; and Ben Rodgers, CFO, will share further color on our results and outlook. Tracey Henderson, Executive Vice President of Exploration, is also on the call and available to answer questions.

We will start the call 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 interests in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss 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. On today's call, I will review our full year 2025 results, outline our continued progress across key strategic initiatives and discuss our outlook and plans for 2026. 2025 was a highly successful year for APA, defined by continued progress against our strategic priorities and strong execution across our asset base. We entered the year with a clear objective to materially reduce our overall cost structure, part of which was to make significant further strides in terms of operational excellence. We set a goal to reduce our controllable spend by $350 million on a run rate basis by the end of 2027 without compromising safety, asset integrity or our commitment to exploration.

Through the dedication of our employees and strong leadership alignment, we exceeded this target over a significantly shorter time frame and have line of sight to exiting 2026 at a $450 million run rate. Ben will provide more details on this topic. During the year, we also met or exceeded oil production guidance in the Permian every quarter in 2025 on a lower-than-planned capital budget. In addition, we also made significant progress on a comprehensive assessment of our Permian Basin inventory, incorporating our improved cost structure. This effort confirmed the depth and quality of our drilling opportunities and validated substantial upside potential. Additionally, it increased our confidence in sustaining long-term oil production while delivering competitive capital efficiency. Steve will provide further color on our Permian inventory position shortly.

Moving to Egypt. Our focused activity under the new gas pricing framework drove meaningful production growth, establishing the foundation for a sustained multiyear strategic focus. On the oil side, strong reservoir management through targeted waterflood activity has helped stabilize gross volumes over the past 3 quarters. In Suriname, our partner, Total, continues to execute at a high level as we advance toward a mid-2028 first oil date. On the exploration front, our Sockeye discovery in Alaska further confirmed the prospectivity of our approximately 325,000 acre position, providing a strong basis for future exploration and appraisal activity. In summary, the disciplined execution across our asset base and strong delivery of our cost reduction initiatives drove more than $1 billion in free cash flow generation in 2025, of which we returned approximately $640 million to shareholders. We also significantly strengthened our balance sheet, ending the year with less than $4 billion in net debt.

Turning to 2026. Our strategic priorities are clear and our capital plan is disciplined. We will sustain operational momentum, further reduce our cost structure, continue strengthening our balance sheet and invest in the future through exploration. In the United States, our $1.3 billion capital program is designed to maintain relatively flat oil production year-over-year at approximately 120,000 to 122,000 barrels per day, despite significant weather-related downtime in the first quarter. This represents an improvement relative to our preliminary outlook discussed in November, reflecting continued gains in operational and capital efficiency. In Egypt, we will invest approximately $500 million to slightly grow BOE production year-over-year. As our activity becomes increasingly gas weighted, gross oil production is expected to decline slightly, while gross gas volumes continue on a growth trajectory year-over-year.

After just 1 year of focused successful gas drilling, we now have visibility into a runway of new development inventory and near-field exploration opportunities. This has laid the foundation to support continued growth and we expect to deliver approximately 540 million to 550 million cubic feet per day this year. This volume outlook includes a minor impact from our withdrawal from a small noncore concession, which Ben will address shortly. Under our new pricing framework, increased gas production strengthens free cash flow and further establishes Egypt as a key value driver within our portfolio. For the GranMorgu development in Suriname, we will allocate approximately $230 million in capital. On the exploration front, we are investing approximately $70 million to advance high-impact opportunities across our portfolio. This includes a return to exploration drilling in Suriname Block 58 in the fourth quarter and planning and readiness spend ahead of an active first quarter 2027 drilling season in Alaska.

In aggregate, our total portfolio spend is $2.1 billion, roughly 10% lower than last year. This plan is operationally manageable and preserves flexibility to scale activity in response to commodity price movements. In closing, the progress we delivered in 2025 reflects a fundamental transformation of APA's base business over the past several years. We have high-graded the portfolio, significantly reduced our cost structure, strengthened the balance sheet and further advanced our exploration efforts, resulting in a more focused, resilient and capital-efficient company. These actions have translated into stronger free cash flow generation and a structurally more competitive asset base in both the Permian and Egypt. In the Permian, we have enhanced returns through disciplined capital allocation and significant efficiency gains while building depth and durability in our inventory, which is expected to sustain oil production and deliver competitive capital efficiency for the next decade.

In Egypt, we continue to strengthen asset durability through both commercial and operational initiatives. This includes a focused gas strategy supported by an improved pricing framework that complements our established oil base. Our high-quality development and near-field exploration program is expected to drive gas growth and support a strong long-term outlook. Together, the strength of these base businesses form the foundation for sustained free cash flow generation for the next several years. Starting in 2028, the addition of Suriname will provide a meaningful step change and continued growth in free cash flow through at least the early 2030s.

I will now turn it over to Steve, who will provide more details on our Permian inventory.

Thank you, John. The Permian Basin is Apache's foundational asset. It's our largest source of both production and free cash flow and it consistently attracts the largest amount of capital. One of our strategic objectives is to build and grow a high-quality portfolio of assets. In the Permian, we have made great progress on this over the past 2 years. That progress can be summarized in 3 key efforts: portfolio actions, cost structure improvements and refining our development approach.

So let's take a quick look at each of these 3 key efforts. Throughout my remarks, I will reference slides from our financial and operational supplement, which is available on our website. In terms of portfolio actions, we have high-graded our Permian asset base, leveraging scale and localized knowledge to maximize economic inventory. This was enabled through the Callon acquisition and exits from noncore assets like the conventional Central Basin Platform and our fragmented position in New Mexico. We now hold approximately 450,000 net acres across the Midland and Texas Delaware basins with more than 95% of that acreage held by production. Our position is now concentrated in a few key areas, presenting 2 primary benefits. It enables economies of scale in our operations and provides significant flexibility in the pacing of activity.

Turning to our progress on the cost side. Our momentum has been evident over the last several quarters. Beginning in 2024, the successful delivery of Callon synergies significantly lowered breakeven oil prices from what Callon experienced in 2023. In 2025, we made further strides in drilling, completions, equipping and facilities costs on a per-lateral-foot basis. As shown on Page 11 of our supplement, our current drilling and completion costs average $595 per foot in the Midland Basin and $750 per foot in the Delaware Basin. These costs reflect a mix of landing zone depths and compare very favorably to both public and private peers. We have also significantly reduced facilities costs as we have moved to more brownfield expansions. Finally, our development approach has historically involved wider well spacing with larger completions. That approach drove very strong per well productivity.

However, as our cost structure improved, it enabled us to drill more wells on tighter or denser spacing and to moderate completion intensity. This translated to more economic inventory, greater recoverable reserves and a higher overall net asset value. There is a reinforcing mechanism at play here as well. Lower cost enables more dense development, increasing density accesses economies of scale and economies of scale reduce costs even further. Taken together, these 3 efforts, portfolio actions, cost structure improvements and a refined development approach have significantly improved both the quantum and the quality of our economic drillable inventory. Importantly, these are not temporal improvements resulting from macro drivers. These are sustainable improvements and we expect to see more in the future.

Before I dive into the details of Permian inventory, let me share our perspective on how we classify locations. Every location or opportunity in our Permian portfolio falls into 1 of 3 categories: economic inventory, technical upside and prospective leads. The first category is what we call economic inventory. On Page 12 of the supplement, you will find a skyline plot of how we currently view Permian economic inventory. This includes only operated locations expected to generate at least a 10% rate of return. At this point in the characterization process, there are 2 factors driving a naturally conservative outcome. First, this is entirely based on our current cost structure, assuming no future efficiency gains or technology improvements. Secondly, there has to be a high level of confidence in the production forecast, where further appraisal or delineation is required, we reduce location counts oftentimes to 0 until they are further derisked.

We currently carry around 1,700 locations in economic inventory, which is a baseline that we will continue to refine and build upon. We are confident this will continue to improve both in quantity and in quality through advances in resource understanding, technology and capital and operational efficiencies. We refer to the second category of locations as technical upside. Technical upside represents locations in established or emerging Permian Basin plays that we believe will be the next subset of locations to progress to economic inventory. As you'll see on Page 13 of the supplement, we believe there is significant technical upside potential. Continued delineation success and ongoing efficiency gains remain key drivers for advancing these locations into economic inventory. Approximately 2/3 of our technical upside today is in the Delaware Basin with the vast majority in shallow landing zones, the Avalon and the First and Second Bone Springs.

There has been significant activity in these zones in the Northern Texas Delaware and we have recently drilled 2 First Bone Spring wells in Ward County. While there hasn't been much industry activity that far south, early performance is promising. Therefore, we are planning a 4-well appraisal test later this year. Opportunities like this are largely unrepresented in our economic inventory but this appraisal could advance a full year of drilling activity from technical upside into economic inventory. The best part of having this much upside in the shallow zones is this should be some of the lowest cost development in the Delaware Basin. With less geologic complexity and a longer track record of development, our subsurface understanding is much more advanced in the Midland Basin. Despite this, we continue to see technical upside through spacing refinement and further delineation of both established and emerging zones with roughly half of this technical upside residing in the deeper benches.

For example, there has been extensive industry activity in the Barnett in Western Midland County and most of our DSUs there carry locations in economic inventory. By comparison, in areas like Upton County, there has been very little Barnett activity. As a result, the vast majority of our DSUs carry Barnett locations only as technical upside. In our view, this reflects a need for further appraisal, not a lack of prospectivity. In aggregate, we have roughly 1,700 additional locations within our technical upside. The boundary between economic inventory and technical upside is not a function of economics but a technical maturity. As these opportunities advance, we expect many to compete favorably with the economic inventory illustrated in the skyline plot on Page 12.

It is equally important to understand we have not attempted to characterize all potential locations in the first 2 categories. The third category, prospective leads are those which we have not yet characterized at all. These opportunities are not currently included in our technical upside. They carry subsurface or completion-related risk and have limited or no historical development. As the basin continues to mature, some of these leads may underpin future upside. In closing, as we see things today, we are confident we can sustain oil production volumes at today's levels for at least the next 10 years and we see meaningful potential to extend that further. The scale of the technical upside characterized in actual location counts is at least as large as the economic inventory we are presenting today.

We believe the future will bring more locations from technical upside into economic inventory and locations will continue to move to the left on the skyline plot with improving economics and lower breakeven prices. Our progress in 2025 demonstrated our standing as a leading operator in the Permian Basin. We improved capital efficiency, strengthened the depth and quality of our inventory and increased confidence in long-term performance. Our Permian position is anchored by a long runway of inventory with a sustainably improved cost structure and a competitive development approach. All of this is underpinned by a cored-up asset base that is largely held by production. The Permian is well positioned to underpin robust free cash flow generation for the company for the next decade and beyond.

I will now turn the call over to Ben.

Thank you, Steve. For the fourth quarter, under generally accepted accounting principles, APA reported consolidated net income of $279 million or $0.79 per diluted common share. Consistent with prior periods, these results include items that are outside of core earnings. The most significant after-tax items impacting adjusted earnings include $36 million of noncash impairments and $29 million for unrealized losses on hedges, offset by a $47 million gain on our decommissioning contingency. Excluding these and other small items, adjusted net income for the fourth quarter was $324 million or $0.91 per diluted share.

APA generated $425 million of free cash flow in the fourth quarter, of which $154 million was returned to shareholders. For the full year, free cash flow was more than $1 billion, and APA returned 63% to shareholders through both common dividends and share repurchases. Permian oil production significantly exceeded our fourth quarter guidance, primarily driven by incremental completion activity, improved runtime and milder-than-normal weather. In the first quarter of 2026, we have already experienced 3,000 barrels per day of weather-related downtime, which is reflected in our guidance. In Egypt, gross gas production of 501 million cubic feet per day was below guidance due to unplanned temporary pipeline disruptions late in the quarter. This was remediated and operations have since resumed to normal. LOE came in below guidance, driven by progress across our portfolio from ongoing cost-saving initiatives, namely in the North Sea and Permian.

Net debt ended the year just below $4 billion, down approximately $1.4 billion from year-end 2024 through a combination of free cash flow generation, asset sales and payments from Egypt. This progress brings us closer to our long-term net debt target of $3 billion. Additionally, interest expense was approximately $80 million lower compared to 2024. Wrapping up 2025, our proved reserves increased approximately 9% year-over-year, surpassing 1 billion barrels of oil equivalent and our all-in reserve replacement ratio exceeded 160% for the year. The team's execution in the Permian and in Egypt enabled us to grow reserves despite a 13% year-over-year decline in SEC oil prices, underscoring the quality of our inventory and the capital efficiency of our development program.

Turning to our cost reduction initiatives. 2025 marked a year of remarkable progress across the entire company. We captured over $300 million of savings and exited the year at a $350 million run rate, achieving our original target 2 years ahead of schedule. This reduction in controllable spend improved margins, expanded free cash flow and strengthened the resilience of our base business. For 2026, as outlined on Page 7 of the supplement, we expect controllable spend to decline by another $200 million. Only half of this reduction is incremental savings with the remainder driven by lower Permian activity relative to 2025. All of this is incorporated in our annual guidance for capital, G&A and LOE. Each category is below 2025 levels with the exception of LOE.

While we expect operating expense savings to continue through the year, they are being offset by various market-related headwinds, primarily in the Permian and North Sea. We will work throughout the year to mitigate these pressures but at this point, we expect 2026 LOE to be slightly above 2025. The progress achieved in 2025, combined with the additional savings we expect to capture in 2026, positions us for a structurally lower spend profile as we move into 2027. By year-end 2026, we now estimate our run rate savings will reach $450 million. These savings are sustainable and position us to be a cost leader as we continue to drive efficiency and long-term value creation.

Turning to our outlook for 2026. John already outlined our high-level capital investment plans and expected production trajectory. So I will focus on a few additional items. Starting with the Permian, 2026 development capital is expected to be around $1.2 billion. In addition, we plan to invest approximately $100 million for base capital projects aimed at structurally reducing LOE and improving uptime. These projects offer attractive 6- to 24-month paybacks and enhance the durability of the asset with LOE benefits starting in the back half of 2026 and building into 2027. As a result, total Permian capital will be approximately $1.3 billion for 2026.

Moving to Egypt. We recently elected to withdraw from a small noncore concession as part of our ongoing portfolio high-grading efforts. These assets fall outside of the merged concession area established in 2021 and do not benefit from the new gas pricing framework. While the concession did not generate free cash flow, our exit will reduce oil and gas production volumes. The quantified impact is detailed on Page 16 of our supplement. Shifting to decommissioning and asset retirement obligations, we expect combined gross spend to increase to approximately $280 million in 2026. This reflects lower spending in the Gulf of America offset by higher planned activity in the North Sea. As a reminder, all North Sea decommissioning expenditures receive a 40% tax benefit. After incorporating these tax impacts, we expect net spend for 2026 to be approximately $225 million.

Shifting now to our oil and gas trading portfolio, which continues to be a meaningful contributor to free cash flow. Based on current strip pricing, we expect these activities to generate approximately $650 million of pretax income in 2026. From 2020 through the end of this year, we expect to have generated nearly $2 billion in cumulative pretax income from our trading activities, underscoring the scale, consistency and value of this business within our portfolio. In closing, 2025 was a strong year for APA. We significantly exceeded our cost savings targets, generated over $1 billion of free cash flow, reduced net debt by more than $1.4 billion and continued to high-grade our portfolio. Our focus remains on disciplined capital allocation, further cost efficiencies, continued balance sheet improvement and advancing our high-return development program and exploration opportunities.

With that, I will now turn the call over to the operator for Q&A.

Our first question comes from the line of Doug Leggate with Wolfe Research.

John, or maybe this one is for Ben. But I'm trying to understand this Permian CapEx guidance, the $1.2 billion -- $1.3 billion total, $1.2 billion. I wonder, can you offer any color on the impact of this $100 million? What was the nature of that spend? How does it show up in the payback you talked about? Any kind of color on the LOE, for example, impact would be appreciated. And then my follow-up, John, if I may, hit exploration. There's been a number, it looks like EGPC has been announcing a series of recent gas discoveries, a quick-hit stuff, if you like. But you've also put new exploration numbers in the budget for this year, presumably Alaska and Suriname. I wonder if you could offer any color on what the program looks like in those 3 areas. And specifically, I believe there's a potential game-changer target in Alaska. If you could speak to the prospectivity around that as well, that would be great.

Yes. Thank you, Doug. What I'll do first is just address the exploration, maybe have Tracey chime in and then I'll have Ben come back on the LOE and the capital question.

In general, we've got $70 million in the budget this year. $20 million of that is really prep work in Alaska for ice roads. There's another $50 million that's late in the year for predominantly Suriname as we will be returning to exploration in Block 58 with the well. The exact spud date is not yet set but we expect it to be late fourth quarter. So that's how that $70 million breaks out. Clearly, we're also active in Egypt. And just to spend a couple of seconds there. What you've seen with the progress in Egypt, last year when we -- or November of '24 when we updated our new price mechanism, it really shifted a gear for us and let us start focusing on gas in the Western Desert of Egypt. You saw last year with the progress in terms of what we're able to do in growing our gas volumes. We went after some low-hanging fruits, some things we knew were there.

But now we're really starting to work the exploration inventory and I'm very, very excited about what's coming in Egypt. We've got some pretty key wells that we'll be drilling. Those are some of the things you referenced. EGPC has been announcing some of the smaller things. But we're excited about that. And I can let Tracey talk about Alaska. But in general, we're prepping for a big winter, likely 2 wells in early '27, likely an appraisal at Sockeye. We're still in the process of getting back the seismic that we're having reprocessed. So that's still coming in. But you'll likely see us drilling an exploration well and an appraisal well in early winter of '27 in Alaska.

So Tracey, you can comment a little bit just on the geology there.

Sure. We've got a really robust and diverse prospect inventory on the block. And as John said, we're focused right now on reprocessing the new seismic data and maturing that entire inventory. We've had success in the bottom set play at Tumbleweed and in the top set play at Sockeye. And so we're going to be focusing really in the near term on maturing a lot of what we see as analogous prospects to the Sockeye discovery and that will be a focus for the near term and the next drilling season. And as John said, we'll be looking to appraise the Sockeye discovery as well. So we've got a lot going on in the background, getting ready for the next season in terms of defining the inventory and next steps.

Yes. And just to clarify, we'll start building ice roads this winter for the late '26, early '27 Alaska drilling season. So Ben, I'll go back to you now on the Permian capital and the $100 million we're spending.

Sure. So Doug, we started spending some capital last year. We talked about in August and November on some of these LOE projects. As we did that, we identified some additional opportunities going into 2026. A lot of it is around compression and facilities consolidation. There's some artificial lift dollars in there as well. But -- so it's a lot of different projects spread throughout the basin. And the way to think about it is, as you get to the back part of '26, we expect that our LOE will come down by somewhere around $3.5-plus million per month. And so when you annualize that number, you're kind of in the $40 million to $50 million of ongoing savings in LOE. So spending that $100 million gets you $40 million to $50 million of savings, which is pretty much in line with the kind of 1- to 2-year payback.

Ben, just to be clear, that -- so presumably, that's like rented equipment becoming capital equipment or something of that nature, is my understanding of that right?

That's a portion of it. But it really -- it spans across a lot of different pieces in the basin. Steve, I don't know if you want to add some color.

Yes. I just -- I wanted to add some color to the LOE investments because really, they have 3 purposes. Obviously, one is just -- it's $100 million of capital investment that will drive down costs. And actually, we -- our estimate is that we'll exit '26 on a monthly LOE run rate that's $3 million to $3.5 million lower than it otherwise would be. So that's just the cost side, just investing to reduce cost. But we're also investing in things that will increase the reliability and the resilience of production volume. As John said, we had an amazing fourth quarter on uptime. And we've been looking at what are all the various sources of downtime that we have and we experience and some of it is related just to the reliability and resilience of facilities and equipment.

And so there are some investments that could be made there that could improve uptime for the future, maybe not as good as fourth quarter but maybe better than what we've experienced in the past. And then thirdly, there are some opportunities on the inventory side. I'm sure we'll talk about inventory in a bit, Permian inventory. But there are some -- actually some high LOE areas where if we can invest in some of the facilities, we can drive down LOE. That moves some of -- maybe some of the high breakeven inventory that you see on that inventory skyline plot to the left, it also will serve to bring in some of the technical inventory onto that skyline plot. So there's lots of purposes for that LOE investment.

And last thing there, Doug, yes, some of that would be rental equipment that Callon had that we will be investing in. So -- but thank you.

Our next question comes from the line of John Freeman with Raymond James.

The first question, you all had a huge beat on U.S. oil volumes and you all cited a few different items that drove that improved runtime, incremental completion activity and a more moderate weather. This may be difficult to answer but if you sort of went back and I guess, did like a postmortem, you looked at your original guidance versus the big beat, can you sort of flesh out a little bit for us sort of the impact that each of those had, like the improved run time versus a few incremental completions versus the moderate weather? Just trying to flesh that out a little more.

Yes. I mean, John, I'll take a cut at it and then have Steve add some detail if we need to. But I mean, first of all, you look at fourth quarter, first quarter are historically our periods when you've got the most weather impact. And fourth quarter was almost flawless in terms of no downtime. So that in itself is something we typically will bake in. Fourth quarter, there was virtually no weather. Obviously, that changed in January and we've had a lot of weather in the first quarter. So when you look at fourth quarter versus first quarter, that is a big chunk of it. Secondly, we were able to bring some TILs earlier into the year and some of those just cleaned up a little quicker than we expected them to. And that's going to drive a pretty big portion of it just because we had wells cleaning up, you had forecasted downtime. In fact, we were able to give the workover rigs both holidays off both Christmas and Thanksgiving because their run times were so good fourth quarter.

Yes. We don't have -- I don't have exact numbers on any of that, John. But I would just say roughly 1/3 each, 3 big impacts, virtually no weather downtime in the fourth quarter, the TILs and then the actual improvement in underlying run time was just phenomenal during the fourth quarter. So I would just say 1/3 each probably.

Great. That's helpful. And then my follow-up, looking at Slide 11, we also -- the really good progress on the D&C per foot down 30%. And then sort of looking at your development plan on Slide 14 and I don't quite have everything I probably need on there to back in this exactly but it just looks like back of the envelope, the D&C per foot looks like it's continued to go lower on your '26 program. Would it be possible to maybe get sort of just rough breakdown of those 130 completions in the Permian between Midland and Delaware and then just sort of a rough idea of kind of what you all are baking into the plan on like a D&C per foot basis?

Yes. We're not prepared to do that on this call. You can maybe have a follow-up call with Stephane and Ben and the team after this, John. What I would just say is that we made huge progress on drilling and completion costs in 2025. At the end of the year, especially in 2025, if you looked at some of the shallow wells that we were drilling in both basins, we actually got to a point where in the Midland Basin, we were under $500 a lateral foot. And in the Delaware Basin, we were under $700 a foot. So we are continuing to make progress. We're not -- certainly not done with that. And the drillers, I know are anxious to get after other opportunities here in 2026. So we believe that will continue to improve. There is a mix effect on all of that. But I think that when you do go through the math, you'll find that it's pretty in line with what we've been doing as we went through '25 and ended 2025. But I'll let you guys do that offline in a separate call.

Our next question comes from the line of Neal Dingmann with William Blair.

John, for you or Steve, just wondering, could you talk a little bit about just Permian inventory, how the potential sensitivity is, especially around some of your gassy assets?

Yes. I mean, if you look today, what we looked at was really the oil inventory. So you're not going to have any of our pure gas location counts in there. Those will be separate. And Steve, you can jump in a little bit on.

Yes. Just to kind of -- I don't know, just maybe a bit of an overview on inventory, in general. As we said, economic inventory, I'd say the cutoff that we have between economic inventory and technical upside is probably, I would say and you probably imagine this to be true for us, we err maybe a bit on the conservative side. But 1,700 gross locations in economic inventory. What do we mean by economic inventory? We have -- it's got to have a very high confidence in terms of being able to draw a type curve for it. And we have that confidence either from our own experience or offset operators that have good analogs to what we're going to be drilling. The economics include all drilling, completion, equipping and facilities costs and it's actually burdened with central facilities, which some people don't do. They just stop at pad level facilities but we include the gathering system, saltwater disposal, we include central tank batteries and it has to have a 10% rate of return to make it into economic inventory.

The technical upside inventory is, as I said in my prepared remarks, it's stuff that, it's the next best opportunity for bringing stuff through appraisal and development into the economic inventory bucket. And I don't want people walking away from the call thinking, okay, this is kind of like pie in the sky stuff. Actually, it's not at all. 40% to 50% of our entire technical upside inventory is shallow Delaware Basin. So it's the Avalon and First and Second Bone Springs. And in my prepared remarks, I talked about there were 2 wells that we drilled that had pretty promising results. Well, if we drilled those 2 wells today at our current cost structure for drilling wells, those wells would be breaking even at $41 WTI. And so this is stuff that falls right into the good end of the skyline plot.

That's all -- every bit of that stuff is in technical upside, not in inventory. And so we're going to be drilling a 4-well spacing test later this year in that area. And those are the types of things that we're going to be doing to move technical upside into economic inventory. We actually have several appraisal tests or spacing tests going on, both in the Delaware Basin and in the Midland Basin this year for that very purpose, moving quantum of inventory out of technical upside into economic inventory.

Great detail, Steve. And then just a second one just on Suriname is, I just want to make sure I think this is the case. Is 100% of that $230 million in suggested capital for the year strictly focused on the GranMorgu? Or are you assuming any other parts of -- to be spent in any other maybe parts of Block 58 or 52?

No. The $230 million there is for GranMorgu and then the exploration capital would be covered in the exploration side.

Our next question comes from the line of Bob Brackett with Bernstein Research.

If we could talk about Egypt and the 7.5 million acres you have there, much of that -- some of that acreage is well connected with existing gas pipelines but there's a whole lot of territory fairly far from gas pipelines that could hide some fairly large leads or prospects. Can you talk to your exploration philosophy for gas out there? Is it fishing from the pier? Or is there some appetite to step out to some of the more distant opportunities?

No, Bob. I mean, I think the big thing to think about there is we've been in the Western Desert for 30 years. We've shot multiple versions of 3D seismic as we learned to try to see deeper searching for oil. We started out drilling the big bumps on the oil side, 4-way closures to the 3-way, migrated to the strat traps -- and really November of '24, we enter into a new gas price environment and it lets us start that process over on the gas side. So as I mentioned, we went after some things we knew were close, that we could tie in. And now the exploration team is stepping back and really looking in the pockets that are deeper where we knew there was gas and we stayed away from. We've also added 2 million acres last year of new acreage. So we're stepping back and doing a regional look. And Tracey can comment a little bit on that but we're taking a regional approach on the gas side. And that's what I'm excited about is, it's bringing a lot of structures into play that historically, we knew were gas, we steered away from.

Yes. Thanks, John. No, I think as John said, we put a lot of effort in the last year of going back and building a better regional picture, too, with look backs over what we've been exploring for, for the last few decades. And as John said, we've got a lot of areas that we've historically avoided because we knew that they were going to be gas prone. So we've reprocessed seismic data. We stood up teams to really focus on this specifically and are currently building out more of an inventory of what we see as our longer-term gas portfolio of some of which of those wells we will start to see this year. So I think we've got -- we're in a really good place on that.

Our next question comes from the line of Michael Scialla with Stephens.

I wanted to follow up on the Permian inventory. Stephen, I think you said in your prepared remarks that if the test, I think you were referring to on the Bone Spring, were to be successful, that could replace a year's worth of drilling inventory. Is that essentially saying this 4-well spacing test in the Bone Spring could add like -- could move 130 locations from the technical to the economic inventory. Is that the correct read?

Yes, that's a correct read. And that's just for the First Bone Spring. As I said just a few minutes ago, actually, 40% to 50% of our 1,700 technical upside locations are in the Avalon, First or Second Bone Springs in Delaware Basin, mostly in Ward and Reeves County and a bit in Southern Winkler County. And that test in the First Bone Spring won't prove up all of that but we will prove up concepts related to all of that because we believe, at least, in some places, that's one big tank. So yes, it can prove up just in the First Bone Springs in that area up to another year worth of drilling but there's a lot more at play there.

Got you. And then I wanted to follow up on Suriname. The $230 million of development, is all that going toward the FPSO? Or is there actually development drilling that's going to take place? I know you said you've got some exploration drilling you plan on late '26 but is there any development drilling in that $230 million number? Or is that separate?

It's everything, Mike and we will be starting the drilling. Those rigs coming on late next year, early '27. So there could -- some of that would fall in on the drilling side, too. But the whole $230 million is for the GranMorgu development project. But yes, it's on the FPSO, the umbilicals, a little bit of everything and we will start drilling development wells.

So you're contemplating 2 rigs running kind of late in the year there, 1 exploration and 1 development?

There will be multiple rigs, yes.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Yes. So could you give us a sense of in the $1.3 billion spending in the Permian, how much of that is going to run these various tests to look at the technical upside? And is that something that you plan on having sort of working into the budget in '27, '28 and beyond? Or will there be a point where we see a little bit of drop-off in Permian spend because you've kind of done most of that work?

No, Scott. I mean, we've got a steady diet. I mean last year we -- we're flowing back now a 4-well Barnett test. So you should just envision in that $1.2 billion, we've got a steady diet of testing that we're doing, both delineation and appraisal. And that's going to continue. I mean that's the nature of the basin, right? So we've got the development piece that you're drilling off of those results but you're going to constantly be drilling wells in that technical category that can move things up. So a pretty steady diet. We've got several we did last year, the last several years and several more this year. We've got a pad we're flowing back and there's more Barnett we'll drill later this year.

Okay. Okay. Understood. And could you talk about Uruguay a little bit? It doesn't look like there's any exploration spend there? I know you're looking to farm down part of that right now. But like what is sort of the path? What are the next steps there? And when could we potentially start seeing some activity?

Yes. I mean our next step in Uruguay, we have had a data room open. There's been a lot of interest from the industry. We are looking to farm down. So at some point, we'll have something to say about that. And then we'd be looking at a well. It's probably likely '27, but could be -- there's a chance it could be late this year but it's likely '27.

Our next question comes from the line of Josh Silverstein with UBS.

The FT capacity and the trading benefit continues to be a positive driver for you guys and clearly still a big beneficiary of wide spreads in 2026. Can you talk about how you see this trending next year in '27 as 4-plus Bcf a day of new Permian pipeline capacity comes online? Does that $650 million start to come down? And then maybe do you offset any of that with some higher of your own volumes, so there's kind of no net reduction there?

Sure. Yes. So this year is $650 million. You look at next year, it does come down just based on strip. There is quite a lot of takeaway coming online late this year, a little bit next year. We'll kind of see what happens to Waha. This is a trend that we've seen over the last really 7 years of deep discounts and then you get an increase when the pipelines come on as they fill up and then it gets challenged again. So we'll see what industry activity and things do to continue to push gas production in the basin and where that lands. Some people say it will fill up pretty quick and others are skeptical. And that's just going to be driven on types of wells that are drilled, GORs, the amount that's flaring now that can be put on the pipes, et cetera.

So it does come down next year. It's still positive actually for 2 years out for us, kind of through '28. And then our extension options on those begin in '29. And so we'll look at the market at that time and figure out what to do. But as you look for the next 3 years, it's positive for us across that and the LNG book. And to your point, if those spreads do compress and that is through Waha strengthening, then yes, we do get better prices than on our equity gas. And it doesn't fully offset that because we have a little bit more capacity than our production but it does mitigate that drop on the marketing side because you're making more on your equity gas that you're producing.

Yes. Maybe just sticking on the financial front, the balance sheet improvement efforts have been really good, now down to $4 billion at year-end '25. You still have the $3 billion kind of long-term target there. Is the goal to stick with that 60-plus percent of free cash flow going to shareholders until you meet that target? Is there any sort of flex to this? Or do you want to make sure you're hitting that target this year?

Yes. I mean we think that 60% is competitive. We've exceeded it every year since we outlined that in 2021. We've exceeded the 60%. And we think that, that's a prudent level right now. We also are using portions of our free cash flow to invest in exploration. I think a lot of our peers don't have the exploration portfolio that we have. We're thinking about that longer term as well. And so that 60% takes that into account as well as balance sheet management and managing our ARO and decommissioning spend. And so we're managing all of that. The $3 billion target we put out, recall that was kind of at a mid-cycle price of $70. We'd get there in kind of 3 to 4 years.

Prices go higher than that, we can get there potentially by the '27, '28 time frame and if they're lower, then it'll be end of the decade. The point is that we've made a lot of progress through cost savings, capital efficiency, execution in the field and all of that pulled together has increased free cash flow last year. You look at '25 free cash flow compared to '24 free cash flow, it was up over 20% with lower prices. And so that's just a testament to what the team has done. And we used a lot of that to return to shareholders but we also paid down a lot of debt. So just -- we've got flexibility in our program, as outlined with the Permian inventory and Egypt gas. When you take all that together, we still feel pretty good about reaching that $3 billion kind of at current prices in the next couple of years.

Our next question comes from the line of Leo Mariani with ROTH.

I just wanted to follow up a little bit on the Permian inventory. Just wanted to make sure I sort of understood it from a definition perspective here. When you guys kind of talk about a 10% or greater rate of return, is that like a field level sort of pretax return? Just wanted to make sure I sort of understood that. Does that not include like any kind of corporate burden or anything for G&A?

It doesn't include a corporate burden, but it does include full field cost burden. And it is before tax and after tax, we probably won't be paying tax for quite some time.

Okay. That's helpful. And just wanted to follow up on Egypt. You guys spoke about this and I was hoping that you could give us a little bit of a quantification. You did speak about how Egypt's gross oil was going to decline in 2026. Is there kind of a rough ballpark percentage on that in terms of the decline you're going to see?

So, Leo, I mean, if you look at it, we've been able to, with the waterfloods, hold oil volumes flat for the last 3 quarters. So we're still prioritizing oil. We've just shifted the gas rigs up to 50% from -- we started last year at 25%. So we're just going to be drilling more gas wells on a relative basis. And so as a result, we're going to forecast gross BOEs, gross gas or gross oil to slightly decline. But we've had a pretty good track record of being able to sustain that through the waterflood projects.

Well and also quite a few of the gas fields are rich gas, have condensate with them and so that shows up as oil volume as well.

And some of the new exploration acreage also is prospective for oil as well. So -- but it's just how we steered gross oil.

I would now like to turn the call back over to John Christmann, CEO, for closing remarks.

Thank you. In closing, let me leave you with the following thoughts. 2025 was an excellent year for APA, reflecting strong execution and meaningful progress towards cost leadership. We delivered substantial cost reductions ahead of schedule, generated over $1 billion of free cash flow and significantly strengthened the balance sheet. At the same time, we sustained Permian oil production on lower capital, grew gas volumes in Egypt and continue to advance the GranMorgu development in Suriname.

With a structurally lower cost base and a stronger balance sheet, we are well positioned to unlock the full value of our high-quality Permian inventory and expect to deliver sustainable production and competitive returns for the next decade and beyond. With a strong foundation, disciplined capital allocation and a clear line of sight to incremental free cash flow from Suriname beginning in 2028, we are very well positioned going forward.

With that, I will turn the call back to the operator. Thank you.

Thank you. This concludes today's conference. Thank you for your participation. You may now disconnect.

Good day, and thank you for standing by. Welcome to APA Corporation's Third Quarter Financial and Operational Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, [ Stephane Aka ], Managing Director of Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's Third Quarter 2025 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John Christmann. Ben Rodgers, CFO, will then provide further color on our results and outlook. Steve Riney, President; and Tracey Henderson, Executive Vice President of Exploration, are also on the call and available to answer questions. We will start with prepared remarks and allocate the remainder of time to Q&A.

In conjunction with yesterday's press release, I hope you've had the opportunity to review our financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude noncontrolling interest in Egypt and Egypt tax barrels.

I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website.

And with that, I will turn the call over to John.

Good morning, and thank you for joining us. On today's call, I will review our third quarter results, outline our continued progress across key strategic initiatives and discuss our outlook for the fourth quarter and our preliminary plans for 2026. This year's macro environment has remained challenging, characterized by heightened volatility and uncertainty in commodity prices, largely driven by shifting trade policies and geopolitical tensions. While these external factors have created headwinds for the industry, they also underscore the progress that we've made at APA over the past 2 years.

At the core of these efforts is a strong focus on lowering our controllable spend, which is delivering meaningful and sustainable improvements in our cost structure. Additionally, through disciplined capital allocation, a reshaped and more resilient portfolio and a sharper operational focus, we've built a stronger, more adaptable organization, one that can perform through cycles and respond quickly to changing market conditions. Our strategy is working, and the benefits are increasingly evident across both our operations and financial performance. With a stronger foundation in place, APA is well positioned to navigate any oil price environment for 2026.

Turning to the third quarter. Results were once again very strong across the board. We have exceeded our production guidance in each of our operating areas, while capital investment and operating costs were below guidance. In the Permian, continued strong operational execution resulted in oil production above guidance, while capital investment and operating costs were in line with expectations. Moving to Egypt. In addition to the significant acreage award we previously discussed, we also received substantial payments during the third quarter, nearly eliminating our past due receivables. This progress reflects the strength of our partnership with the Egyptian government.

Operationally, once again, gross BOEs grew sequentially in Egypt, underpinned by the ongoing success of our gas program. This reflects both strong well performance and continued optimization of infrastructure. On the oil side, our waterflood and recompletions programs are moderating our base decline and flattening our near-term gross oil production. In the North Sea, our continued focus on operating efficiency and cost management drove higher production and lower costs compared to our guidance. We remain focused on optimizing our late-life operations and are preparing to decommission our assets in a safe, efficient and environmentally responsible manner. Finally, in Suriname, progress at GranMorgu continues at pace and first oil remains on track for mid-2028. Moving to our outlook for the fourth quarter.

In the Permian, following another strong quarter of operational execution, we are raising our guidance for oil production while maintaining our outlook for capital spend. On the gas side, with the recent dislocation in Waha pricing, we are adjusting our guidance to reflect temporary curtailments in the field. Although this slightly reduces our BOE volumes, the impact to free cash flow will be minimal. In Egypt, we are slightly increasing our fourth quarter production estimates in line with the ongoing momentum from our gas program. We are also drilling several high-potential exploration wells, including on our newly acquired acreage. The Western Desert presents a vast and highly prospective opportunity set. And although we are early in our gas exploration program, success here could be impactful for our portfolio.

Turning now to our cost reduction initiatives. Our commitment to reducing every aspect of our controllable spend has been evident all year, and I want to recognize the diligence of our teams and the strong alignment among leaders across the organization. Through their collective efforts, we've made significant changes to our operations and driven meaningful improvements in both capital and operational efficiency. We are now on track to realize $300 million in savings this year and are also positioned to reach our run rate savings target of $350 million by the end of 2025, 2 full years ahead of the original goal of year-end 2027.

Looking ahead, we see significant opportunity to build on this momentum, driving additional efficiency gains and further simplifying how we work. Through these efforts, we aim to deliver an additional $50 million to $100 million in combined run rate savings across G&A, capital and LOE by the end of next year. Moving to our preliminary plans for 2026. With the recent volatility in oil prices, we are evaluating multiple capital allocation scenarios with a focus on free cash flow generation. While we have significantly improved our cost structure and reduced breakevens across our asset base in the last 18 months, we believe a flexible approach to capital investment is warranted in the current price environment.

In the Permian, at our current pace of 5 rigs, we expect to deliver consistent year-over-year oil production of approximately 120,000 barrels per day, with capital investment of around $1.3 billion. However, if oil prices move lower, we have the operational flexibility to moderate activity to reduce capital further with minimal expected impact on 2026 oil volumes. In Egypt, we plan to maintain consistent activity levels and capital spend with a similar allocation between oil and gas drilling as this year. This would allow us to grow gas volumes on a gross basis year-over-year, gross oil production will remain on a modest decline. We will continue to monitor commodity prices over the coming months, and we'll provide formal guidance for 2026 in February.

In closing, our third quarter results underscored the strong operational performance and consistent execution across all operating areas. Through the rigorous focus of our teams, we are driving significant cost savings ahead of schedule and increasing our targets for the future. As we head into 2026, we will remain disciplined in our capital allocation and continue prioritizing free cash flow generation.

With that, I will turn it over to Ben.

Thank you, John. For the third quarter, under generally accepted accounting principles, APA reported consolidated net income of $205 million or $0.57 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was $148 million unrealized loss on derivatives. Excluding this and other smaller items, adjusted net income for the third quarter was $332 million or $0.93 per share. LOE came in below guidance, largely due to ongoing cost savings, primarily in the North Sea. G&A was in line with guidance despite a larger-than-expected impact from mark-to-market adjustments related to stock compensation. On an underlying basis, G&A was approximately $15 million below guidance. We continue to progress multiple initiatives across all categories of G&A and expect this momentum to carry into 2026.

Current income tax expense was lower than anticipated, primarily due to a change in our projected 2025 corporate alternative minimum tax. New guidelines issued by the U.S. Treasury late in the quarter clarified the treatment of net operating losses and depreciation deductions under the minimum tax framework. As a result, we now expect to owe little to no U.S. taxes in 2025 and 2026. Overall, this was an excellent quarter during which APA generated $339 million of free cash flow and returned $154 million to investors through dividends and share buybacks. During the quarter, net debt was reduced by approximately $430 million through a combination of free cash flow generation and payments from Egypt.

This balance sheet progress has enabled us to realize net financing cost savings, excluding gains on the extinguishment of debt of $75 million so far in 2025 when compared to the same period in 2024. We ended the quarter with $475 million in cash, providing financial flexibility as we enter 2026. This gives us the ability to opportunistically repurchase debt, address upcoming maturities and thoughtfully manage the timing and execution of our decommissioning and asset retirement obligations.

Turning now to our cost reduction initiatives. John already covered our progress to date and outlined the targets we've set for 2026. So I'll focus on the key movements in our 2025 guidance for controllable spend items relative to the $300 million of savings we expect to achieve this year. While these savings are reflected in our guidance for LOE and G&A, there are a few offsetting effects within capital. Since issuing our initial 2025 capital guidance in February, our teams have identified and implemented an additional $210 million in cost reduction opportunities, primarily in the Permian. Over the same time frame, our capital budget has been reduced by $150 million. This results in a $60 million difference between the change in our full year capital guidance and the change in capital cost savings since the beginning of the year.

The largest portion of this variance is attributable to capital investments and LOE reduction initiatives. As highlighted last quarter, we identified several high-impact projects aimed at sustainably lowering future Permian operating costs, such as building saltwater disposal systems, consolidating field compression and other facility optimization projects. Capital is being directed toward these efforts, which are expected to generate strong returns with short payback periods and position us for structural operating cost improvements in 2026 and beyond. Another component of this difference is activity related, which primarily relates to the completion of 2 DUCs at Alpine High this quarter.

Shifting to our oil and gas trading portfolio, which has been a meaningful and relatively steady contributor to free cash flow generation this year. Based on current strip pricing, we expect $630 million in pretax income from our trading activities for 2025. To enhance cash flow certainty heading into next year, we have added to our 2026 hedge positions. Currently, about 1/3 of next year's gas transport position is hedged, locking in roughly $140 million of cash flow.

Turning to our asset retirement and decommissioning obligations. Our goal is to reduce these liabilities through a prudent approach that balances operational efficiency with financial discipline. As an example, during the third quarter, we identified a well at one of the fields in the Gulf of America that required decommissioning. Rather than mobilizing a vessel for a single well and returning later to complete the remaining work, we chose to decommission the entire field of 5 wells in a single campaign. This enabled us to capture meaningful operational efficiencies and reduce the total cost that would have been incurred over time.

We have identified similar opportunities to execute during the fourth quarter, which led us to increase our full year 2025 ARO and decommissioning spend guidance by $20 million. Going forward, we will continue to pursue similar initiatives, proactively managing these liabilities in a way that is both operationally efficient and financially sound. For 2026, we expect our combined ARO and decommissioning spend to increase, reflecting a decline in spending in the Gulf of America, offset by higher planned activity in the North Sea. As a reminder, APA receives a 40% tax benefit on all decommissioning spend incurred in the North Sea. Therefore, on an after-tax basis, our total spend will increase year-over-year by roughly $55 million.

In closing, as we enter 2026, our priorities remain centered on disciplined capital allocation, further cost reductions and continuing to strengthen the balance sheet. Our development capital, inclusive of approximately $250 million for Suriname development is expected to be 10% lower than 2025, reflecting improved capital efficiency across our portfolio. This preliminary plan positions APA to sustain Permian oil production, deliver continued gas growth in Egypt and advance the world-class opportunity we're developing in Suriname Block 58. Together with our ongoing focus on reducing controllable spend, these actions further strengthen our foundation for durable free cash flow generation and long-term value creation.

With that, I will turn the call back to the operator for Q&A.

[Operator Instructions] Your first question comes from the line of Doug Leggate with Wolfe Research.

So the capital guide is, I think, puts you below Street for next year. But I'm curious, John, if you could offer a little bit of color on the flexibility you suggested. I mean we'll see if oil -- where oil ends up, but what's the nature of the flexibility you have? Because I think a few years ago, when oil prices collapsed, you allowed your Permian production to decline.

It sounds like that's not the case this time. So is that a DUC manipulation? Is it drilling but not completing? Or can you walk us through where the flexibility is against what looks like a kind of sub-$2.2 billion CapEx number now for next year?

Yes. Great question, Doug. I'll just start out with just in general, our mindset going into '26 is focused on capital discipline. So -- and as you point out, we've got flexibility if oil prices move lower. Today, we envision a plan that's going to maintain Permian oil at about 120,000 while we're growing our BOEs in Egypt, driven by gas and still funding our Suriname and other exploration as well as our decom and our ARO. Development CapEx is down 10%. It's mainly in Egypt with CapEx -- or mainly in the U.S. Permian with CapEx in Egypt being flat. So I think the other factor is we're going to continue to focus on the cost savings.

Clearly, if things soften, as we've mentioned, there is room. We could always decide to drop more rigs in Permian or Egypt if need be. But I think we're in a good place with a pretty good range and a pretty good cushion right now on oil price. So -- but there is flexibility.

Okay. I appreciate that. My follow-up is actually on Egypt. I mean, obviously, you continue -- it's almost like a beat and raise on your gas guidance. But there is some -- I guess there's been some discussions from certainly questions we've been getting about the legacy accelerated cost recovery from when you re-signed the contract. And what happens to -- how big a delta that could be on cash flow in 2026 as those legacy costs roll over?

So I don't know if there's any way, Ben, to -- I know it's complicated. There are a lot of moving parts, but is there any way to kind of summarize what the potential delta could be on that in the context of your rising gas production?

Sure. So when we modernized the contract about 4 years ago, we negotiated a recovery of a backlog of costs, and that was around $900 million. So per quarter, we've had the benefit of about $45 million. When that rolls off after the first quarter of next year, that $45 million, let me break it down, is the total number. We don't lose all of that, though, because of the way the PSC works. We only lose about 70% of it with the other 30% being picked up on the profit oil side. So that $45 million is actually on a 3/3 basis closer to about $30 million. So net to our 2/3 interest, the cash flow impact on a quarterly basis is about $20 million. So for next year, again, since we still have it through the first quarter, so for 3 quarters next year, it's roughly $60 million in Egypt.

But we think with -- there's a number of different factors that we're working on to offset that, whether it's continued capital efficiencies in Egypt because we have seen those this year. A lot of the discussion this year has been on the Permian, but Egypt has made great strides on the capital front. So there's potential for that to continue next year on the cost side for both capital and LOE. We've got expected continued success and performance on the gas side.

And then other oil projects, too. We shouldn't look past what we've been able to do in the second half of this year on the oil program and the potential for some of that to carry next year. So a number of different factors, Doug, I think, are going to offset that $60 million -- had the potential to offset that $60 million free cash flow impact in Egypt.

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

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

Your next question comes from the line of John Freeman with Raymond James.

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

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

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

Yes. I'll just say if you step back from where we were in February and you look at the progress, 2 places, right? G&A, we've been able to do more than we thought. Obviously, that's something we directly control. But the other place has been the capital side, and that's been driven mainly by Permian. So to think where we are, we started out in February, thinking we'd realized in calendar year '25, $60 million. And to now know we're at $300 million. And obviously, we set out a 3-year target of the $350 million by the end of '27 to get there by the end of '25.

Very, very proud of the entire organization because we've just been razor-focused on what do we do on the cost side, and you're seeing that show up. But I'll let Ben provide a little bit of color. We've added by year-end '26 now another $50 million to $100 million to that. But I'll let Ben jump in and give some more color.

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

Your next question comes from the line of Scott Hanold with RBC Capital Markets.

I'm interested in Egypt gas. Obviously, it's going well for you all. And I think you're running, if I'm not mistaken, around 8 rigs on the gas side. And just -- with respect to the new terms that you have on the gas pricing, is there any unconstrained level on gas growth? And could you give us some sense of where you think gas production could go here over the next, say, year or 2?

Yes, Scott, I mean, if you step back and look where we are, we're actually running 12 rigs in Egypt and 3 of them right now are on gas, so -- instead of 8. So just 1/4 of the program. But if you look at where we are and you go back, I mean, we signed this contract a year ago. And so to look at the progress and just see where we are, we've exceeded all of our internal expectations, and it's been really the success of the program, the delivery of the wells. And most importantly, the ability to get things tied in and not back out some lower pressure gas.

So the team has done a phenomenal job. We're going to continue on this trend well into next year. Longer term, it's going to be dictated by the success of the exploration program, and that's something we really -- we've been exploring for oil in the Western Desert for 3 decades. We've now been exploring for gas for really 1 year and kind of just getting started on the exploration side.

So a lot of that's going to hinge on our exploration program. But we've got good momentum. We're going to grow year-over-year on gas. And we do have processing capacity that we might need to pipe into depending on where we have success. But we're really just getting started, and we're excited long term about the gas potential.

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

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

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

Yes. I mean if you step back, I mean, we were drilling Barnett and Woodford wells back as early as 2016, 2017, right? So I mean, we've got a good view on that. There is overlap into our positions. The plan at this point, as we've said, when we've done an updated characterization and Steve can add some color on all the nuances as we -- it becomes a very iterative process.

But I mean, we are planning to come back to the market first quarter of '26 with an update. But today, we strongly believe in terms of core development opportunity and development inventory, consistent with what we're drilling today and into the next several years, we can do that well into the early 2030s.

Yes. With the significant capital efficiency gains that we've been able to capture this year in the Permian. That's obviously having an iterative effect, as John would say, on the quantum of inventory, and it's really requiring us to go back and -- we came into the year kind of rethinking a bit about our spacing and frac size philosophy. And with the efficiency gains that just causes us to rethink all of that all over again. And so we're coming through every bit of our inventory.

So it's not just a case of looking at what's in addition to what we already know. We're also going back and relooking and reexamining everything that we had in inventory to begin with and also all of the Callon acreage as well and other acreage that we've acquired over the years. So every single undrilled landing zone and even new potential landing zones are being reviewed pretty extensively because of the significant efficiency gains. The lower you can drill and complete a well cost-wise, the more resource you can access. And that's a really important aspect of the quantum of inventory. So there's a huge amount of work going on around that.

Your next question comes from the line of Michael Scialla with Stephens.

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

Yes. I just think, Mike, going in with all the progress we've made on the cost structure and clearly, we've got a WTI price that's been sitting around $60, it's prudent to be cautious. And so we're going into '26 with a disciplined mindset. And like always, we've set ourselves up with the improvements in the controllable spend and the cost structure and the balance sheet, we're in a really, really good place.

And the last thing you want to be trying to do is accelerate inventory into an oil market like we sit in today. So in terms of the hedging, not really hedging gas, Ben can jump in at some of the transport and locking in some of those gains there, but I'll let Ben make a few comments on the gas transport hedges.

Sure. Yes. So we -- just like we did this year, looking to lock in cash flow associated with the Waha to Houston Ship Channel and Waha to NYMEX, Henry Hub differential, carried that through into next year. As you know, there's a contango curve on the NYMEX side, but still a pretty wide differential between both Ship Channel and Henry Hub and Waha. And so locking that in gives us surety of cash. We've only got 1/3 of it hedged right now. So should that continue to widen, we would make it on the unhedged volumes. But just getting that certainty of a certain amount of cash flow is -- we thought was prudent. We did it this year.

And when you compare that to hedging on the oil side and either a flat to backwardated market, just felt like more prudent to capture cash flow for the corporation on the transport side versus on the crude side when we've got a lot more optionality in our portfolio to manage versus locking in any type of oil hedges. But should the opportunity come up on the oil side, we could do that just more opportunistic on the gas side.

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

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

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

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

Your next question comes from the line of Charles Meade with Johnson Rice.

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

No, it's a great question. I mean if you look back in the -- we've shown that 2 million acres sits kind of across a lot of the desert and it fits in nicely with our existing footprint. So we do have access to it. It can be tied into infrastructure for the most part. I would say there is both oil and gas prospectivity, and we're kind of already getting after that. So we're very excited about it. I think there's some low-hanging fruit on that acreage that we're getting after.

A lot of it is just going to hinge on, Charles, what we find and where it is and then what do we need to do to tie it in. Some of it we might need to build some jumper lines or things to our facilities, but not all of it. A lot of it is pretty short, arm's reach away from our existing operations. So it fits nicely. I'd say it's highly prospective, and we're getting after it and look forward to updating in the future.

Anything you want to add, Steve?

Yes. I think we've actually published a map of that, of the old acreage with the new acreage on the same map with the infrastructure overlaying that. And I think if you -- I think that might have been in the second quarter supplement even.

So if you take a look at that, you'll see that 2 things. Number one is that the acreage is actually -- it's not like one big chunk of acreage. It's spread out all over the place. And there's some acreage in there that I would say -- I would kind of classify that as just a simple step-out type of stuff relative to what we're doing on the acreage right next door. And then the -- and it ranges all the way to some chunks of acreage that is even new play concepts that we're looking at.

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

Got it. And then for the follow-up, still on Egypt gas. On Slide 3, you guys have a bullet point saying that with the new pricing arrangement that gas development is at parity with mid-cycle Brent. I wonder if you could just elaborate a little bit more on what the assumptions are there? I mean what mid-cycle Brent -- what your assumption there is and also what the -- what parity means, whether that's IRR or what else goes into that statement?

Yes. So what we have is an arrangement. We sell all of our -- the gas that we produced to Egypt, and we have a fixed price on this new tranche of gas. We have a fixed price on the old tranche of gas. We have a fixed higher price on the new tranches of gas. And the way that, that will work is that you end up getting a mix of different of price as you go forward as the PDP declines on the old price of gas and new volumes come on, you get a rising price as you go through time.

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

We included infrastructure.

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

Your next question comes from the line of David Deckelbaum with TD Cowen.

John or Ben, curious when you talk about the program for '26 and holding 120,000 barrels a day flat with 5 rigs. Are you still -- are you assuming any incremental benefits on D&C costs? And I ask that in the context of you guys have made some significant headway. Is there any reason why you can't have a D&C target sort of that rivals the best peers in the Delaware for next year?

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

Yes. I would say, and I think we said this on the second quarter earnings call. In the Midland Basin, we feel like in many ways, we're getting to be pretty close to best-in-class on the drilling and completion side. In the Delaware Basin, we're probably around peer average. And so there's still room to go there. So just in terms of reconciling the 5 rigs holding volumes flat relative to 2025, 120,000 barrels of oil a day. There are some things that are benefiting us being able to go to 5 rigs. We're not saying that we've said in the past that 6 rigs will hold Permian relatively flat around 120,000. We're not saying that's 5 now. We still believe that's probably closer to 6 at this point in time. But there are some things that are benefiting us in 2026, where we've made some good strides recently around base uptime, base volume uptime kind of reducing the underlying decline rate a bit, which will help as we roll into 2026.

There are some facilities where we're facility constrained now. So we brought on wells. The wells are actually constrained a bit in their producibility and that will resolve itself as we go into 2026. That helps a bit. There is a small reduction in DUC count. It's about 5. So we'll exit '26 right now based on current planning with about 5 less DUCs, fewer DUCs than we enter '26 with, not a significant amount, but just being transparent, there is a slight reduction in DUC count.

And with all of that, our development capital in the Permian this year on a like-for-like basis, eliminating stuff that we've sold is about $1.45 billion. Next year, that will be $1.3 billion. The $1.45 billion actually includes about $200 million of savings that we've talked about that we actually captured in the current year in 2025. And so there's another $150 million of savings as we roll through 2026. That does -- it benefits from kind of the run rate of what we've done so far. It does have some additional savings planned in there as we go forward. Much of that would probably come in the Delaware Basin versus the Midland Basin, but we still believe there's room to run in the Midland Basin as well. And that does include running 5 rigs instead of -- and we're down to 5 rigs today, but we had been running 6 earlier. So that includes all of that.

I appreciate all the additional color, Steve. My follow-up is just on the North Sea. I think you guys highlighted the tax benefits, in particular, in '26. I guess as you -- are you accelerating the ARO activity in the North Sea? And what are the, I guess, results or consequences as you see on the production side of that asset over the next couple of years?

Yes. So on the production side, just like we mentioned earlier this year with little to no investment in the asset, which was expected after all the different changes through the government there, we'll expect production to continue to decline from '25 into '26. I think we'd said 15% to 20%. And so that's probably a reasonable assumption from a production standpoint.

But on the tax side, a lot of that's price dependent depending on if there's taxable income in the U.K., but there will be tax savings because of the increase in the ARO spend that we have next year, again, because the government pays 40% of that ARO. And so we've talked about that before in terms of the increasing profile when we announced COP last year. And so that will increase next year.

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

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

Your next question comes from the line of Betty Jiang with Barclays.

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

Sure. So for this year, I mentioned in my prepared remarks, the $60 million difference between captured savings and our capital guidance. Roughly 1/3 of that was investment in these LOE projects that we started this year. We do expect that to continue into next year as we identified different opportunities. And again, most of it's around facilities and compression and other items that I've mentioned before. And we will continue to invest capital into those projects that will have ongoing LOE savings.

So it's not a big capital number when you think of -- Steve mentioned the $1.45 billion for Permian this year and the $1.3 billion next year. If you're talking $20 million on that $1.3 billion base, it's not a big piece, but it does help us on LOE. I will say that the teams are working across all different aspects within LOE, not just trying to find ways to lower it through capital investment, but through really all different areas that make up our operating expenses there in the field. And that's not also just in the Permian.

Clearly, we've done it this year in the North Sea and in Egypt as well. So there's -- not going to outline a per barrel metric for that for the savings, but do expect savings, and they'll be staggered throughout '26 and into '27 as well.

Yes. If I could just add a bit to that. Obviously, on LOE for 2025, we didn't capture the savings that we had hoped to capture this year at the corporate level. But there's some real success underneath that, that I think is worth mentioning. Most of the struggle has actually been in the Permian, and that's where most of the investment that Ben is talking about around consolidating compression and rationalizing that and around produced water disposal wells and things like that. That's going to be targeting LOE primarily, not entirely, but primarily in the Permian Basin.

And those are investments that we're going to be beginning this year. There will be more in next year, and you'll see the benefit of those probably showing up in the second half of next year. But I did want to highlight, in particular, the North Sea, significant progress in reducing offshore operating costs this year, and that's kind of hidden in what's going on in LOE and some very good progress in Egypt as well without any meaningful amount of capital spend.

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

Yes. So for -- we'll probably wait, Betty, for a multiyear outlook and do that at some point next year, most likely in the first quarter if we do a portfolio update. We've talked about the ramp of the ARO, particularly in the North Sea. And so -- and we also talked about this year that the Gulf of America was going to be higher than prior years and also higher than what we expect moving forward. So the moving pieces for next year is that you see Gulf of America come down pretty significantly back to the kind of $100 million, $120 million range, which is typical for the legacy assets that -- the nonop assets that we own as well as the old Fieldwood assets. So that normalizes, and I would expect that to stay pretty steady even after '26.

And then for the shape of the North Sea, it really -- I'll just go back to what Steve said originally when we outlined that. Starting in '25, it was pretty de minimis. It was about $30 million this year. But that gross to about $600 million of our after-tax ARO is between now and 2030. And then the other $600 million is between 2031 and ramps down to 2038. So we'll provide more details potentially about what '27 and '28 are, but that increase next year, you're right. So about -- in the high 100s this year. So it would be kind of in the mid- to high 200s next year, but it just shouldn't go without saying that the after-tax impact to us is only $55 million.

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

Got it. Just -- and just to confirm, that $55 million already includes the normalization of the lower Gulf of -- GoA decommissioning spend?

That's correct.

Your next question comes from the line of Paul Cheng with Scotiabank.

Ben, you said the cash tax -- U.S. cash tax will be 0 for this year and next year. Do you have any rough idea then how that look like in 2027 to 2030?

Yes. Right now, Paul, our focus has been for this year and next year. We've made significant progress on the tax front and have seen some significant savings. I think with -- when you get past 2026 because a lot of the changes this year and next year that we saw we outlined this quarter were specific to the corporate alternative minimum tax guidelines that came out and less so with the OBBB impact that we outlined in August. As we get into '27 and '28, there's still some guidelines that we'll need for the interpretation of the OBBB.

But again, the intention of that was that we get the full benefit of IDCs and bonus depreciation. And so it should take U.S. taxes pretty close to 0. There's still some work that we're going into that with our tax team, but that's the full intention of the legislation and where we think it could lead past '26. So we think that there's continued benefits, but what we've outlined are the benefits for just this year and next year.

Okay. Great. And maybe this is for John. For Alaska, you're saying that next year is going to be pretty minimum spending. So how should we look at the program and you have the Sockeye discovery and you guys seems like you have very big -- maybe pretty optimistic on that. So what's the game plan that how should we look at over the next 2 or 3 years? And when that we will see maybe a little bit more data out or the -- more news about what the development may look like if there's one?

Yes. No, it's a good question. And what we said, Paul, was we're in the process right now literally of reprocessing multiple surveys to come back with what is the next steps in terms of appraisal at Sockeye and exploration. So right now, we're doing technical work. The teams are working away, and we're reprocessing the seismic. We've got 2 really nice discoveries, and we're kind of stitching together a lot of the seismic surveys so we can come back with the next steps.

So we'll come back at some point. But right now, we just said actually next year, there won't be any winter drilling this year. Obviously, we'd be getting ready for that now, but it will likely be next winter, which is why late next year, we're likely to be building some ice roads as we bring a rig back. But we'll update you once we've kind of worked through what are the next steps in terms of appraisal and exploration, but we are excited about Alaska.

Your next question comes from the line of Leo Mariani with ROTH.

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

Yes. So just 2 things, Leo. Number one, in Uruguay, we actually have a data room open. We've been showing that externally. There's been a lot of industry interest in our Uruguay program. And so we'll have an update at some point, but don't have anything to announce today on that.

And then the 2 completions, the 2 DUCs we completed at Alpine were purely acreage retention. There were wells we drilled. We needed to go ahead and complete those. We've actually got a better Waha price now. So the economics look really good. But it's about preserving optionality and holding acreage in the future.

Yes. Just as you look at the timing, Leo, real quick, the timing of when we bring those DUCs on, you get that flush production December, January, February, Waha is well above $2. And so the timing feels right to bring them on. But again, the main reason for doing that to what John said is to retain some acreage there. So it just seemed -- you get the flush production, the economics line up and you get to retain the acreage for optionality.

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

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

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

Thank you. Our strong results year-to-date have been underpinned by remarkable performance across our entire business. This underscores confidence in our plan and creates positive momentum going into 2026. The capture of meaningful cost savings has improved our free cash flow profile, enhanced our investment opportunities and added inventory to our portfolio.

Our efforts to rigorously improve our cost structure will continue, and we are now targeting an additional $50 million to $100 million in run rate savings by the end of 2026. We continue to benefit from our diversified portfolio with a step change in capital efficiency in the Permian, strong momentum with Egypt gas and the GranMorgu project in Suriname progressing on schedule. Lastly, we remain very optimistic on the impact our exploration portfolio can have on our future.

With that, I will turn the call back over to the operator, and thank you very much for joining us today.

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