Apache Aktie

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 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. 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 three 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 confirm 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, strengthen 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 in 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 three key efforts. Portfolio actions, cost structure improvements, and refining our development approach.

So let's take a quick look at each of these three 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 two primary benefits. It enables economies of scale in our operations and provide 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 averaged $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 three 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 one of three 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 two 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 reduced location counts oftentimes to zero 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 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 two 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 as 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 two 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, strengthen 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 run time 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 continue 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.

[Operator Instructions] Our first question comes from the line of Doug Leggate with Wolf 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 to $1.2 billion. I wonder, can you offer any color on the impact of this $100 million? What's 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 three 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 a 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 and with the progress in Egypt, last year, when we -- or November 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. 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 winner. Likely two 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 in the next drilling season. And as John said, we'll be looking to appraise the Suriname 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 LOW 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 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 three 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 costs. 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 experienced and some of it is related, just 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 actual -- 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 some of the technical inventory onto that skyline plot. So there's lots of purposes for that LOE investment.

And last thing there. 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 run time, incremental completion activity and more moderate weather. This may be difficult to answer, but if you sort of went back and I guess, like a post 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 have Steve add some detail if we need to. But I mean, first of all, you look at fourth quarter, first quarter are historically are 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 where 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 the 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, three 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 130 each, probably.

Great. That's helpful. And then my follow-up, looking at Slide 11, we also show 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 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 the 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. The 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 fit. So we are continuing to make progress. We're not -- we're 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 when you 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 off-line in a separate call.

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

Sorry, guys, to the delight. Can you hear me?

Yes.

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 not maybe a bit of an overview on inventory. Yes, sorry. A bit of an overview on the 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 are 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 ped 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 -- 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 two wells that we drilled that had pretty promising results. Well, if we drilled those two 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 -- 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. I just want to make sure I think this is the case. Is the 100% of that $230 million in suggested capital for the year strictly focused on the GranMorgu? Or are you assuming any other parts of -- would it be spent in any of the 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 can 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 needs or prospects.

Can you talk to your exploration philosophy for gas out there? Is it efficient from the peer? 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, the 4-way closures to the 3-way migrated to the strat traps. And really, November 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 that 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, 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 lookbacks over what we've been exploring 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 inventories, 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 a 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'll 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 a development drilling that's going to take place? I know you've got some exploration drilling 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 is for the GranMorgu development project. But yes, that's -- it's on the FPSO, the umbilicals, a little bit of everything, and we will start drilling development wells.

So you're contemplating two rigs running kind of late in the year there, exploration...

There will be multiple rigs, yes.

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

Yes. 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 sets to look at the technical upside? And is that something that you plan on having sort of working into the budget in 2020 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're flowing back now a 4-well Barnett test. So you should just envision in that one. Two, 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 path we're flowing back, and there's more Barnett we'll drill later this year.

Okay. Okay. Understood. And could you talk about your growing a little bit. It doesn't look like there's any exploration spend there you look initially farm down part of that right now. But like what is sort of the path? What are the next steps there? And what could be to start seeing some activity?

Yes. I mean our next step in Uruguay, we have had a data room open. There have 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 it 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 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 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's $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.

Got it. 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. And 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 they're lower, then it will 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 the Egypt Gas, 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 I just wanted to follow up on Egypt. You guys spoke about this. I mean, you could give us a little bit of a quantification, you did speak about how Egypt 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?

Well, 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. Our 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 perspective for oil as well. So -- but it's just how we steered gross oil.

Thank you. 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 Grand Margo 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, it -- 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, you 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...

Move or drop if needed to 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 arms 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 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. Is -- 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 non-op 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 grows 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 that'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.

Good day, and thank you for standing by. Welcome to the APA Corporation's Second Quarter 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 ], Director of Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's Second 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 in 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 provide an overview of our second quarter results, share an update on our cost reduction initiatives and provide color on our outlook for the second half of the year. Overall, this was an excellent quarter for APA, showcasing strong operational and financial performance, continued capital returns to shareholders and significant debt reduction.

I want to first acknowledge the strides we continue to make in strengthening the balance sheet and improving our capital structure. We reduced net debt by more than $850 million during the quarter and returned approximately $140 million to shareholders through our dividends and buybacks. We remain firmly committed to shareholder returns and balance sheet strengthening through debt reduction. Ben will provide more color on this topic shortly.

Turning specifically to second quarter operational performance. Production volumes across the portfolio generally exceeded guidance [ were ] remaining on plan for company-wide capital investment. In the Permian, oil production exceeded guidance, primarily driven by faster turn in lines enabled by efficient field execution. Capital investment came in slightly above guidance, largely due to the ongoing capture of efficiency gains across drilling and completions. Put simply, we are delivering more activity with fewer rigs and frac crews. Last quarter, we noted that these efficiency gains would allow us to keep Permian oil production flat with 6.5 rigs instead of 8. As a result of further progress, we are currently delivering flat go-forward oil production with 6 drilling rigs.

Our continued improvement in drilling performance is evident. Our D&C cost per foot are now among the lowest in the Midland Basin and in line with offset peers in the Delaware Basin. Our teams are committed to finding new ways to further improve efficiencies across the basin. In Egypt, we again exceeded our quarterly gas production guidance, driven by the strong performance of our recent discoveries and our ability to continue increasing utilization of existing infrastructure. Oil production declined modestly following our decision to shift rig activity toward increased gas development due to improved gas realizations. However, gross BOEs were consistent quarter-over-quarter. Reported volumes also exceeded guidance, but adjusted production was slightly lower than guidance due to the impacts of higher oil prices and lower operating costs on our allocated volumes under the production sharing contract.

Our capital efficiency in Egypt is benefiting from small refinements across our drilling and infrastructure programs, which collectively result in meaningful time and cost savings. For example, on the drilling side, on average, we are delivering wells more than 2 days faster compared to last year. Lastly, North Sea production was ahead of guidance, a testament to the continued optimization of field operations and maximizing run time as we manage these late life assets. Our focus remains on safety, operating efficiency and cost management as we prepare for decommissioning.

Turning now to our cost reduction initiatives. At the start of the year, we set forth some important goals for reducing controllable spend over the next 3 years. I just outlined some of the significant capital efficiency improvements we are making in the Permian and Egypt. Ben will provide further details on other cost initiatives which have also advanced considerably since our last update.

We now anticipate capturing at least $200 million in savings in 2025, up from our prior estimate of $130 million, and plan to exit the year at an impressive $300 million annual savings run rate. We are now on a path to achieve our $350 million run rate target sometime in 2026 versus year-end 2027. Moving forward, over the next 2 years, we see considerable opportunities to further streamline our business and simplify the way we operate. Given the magnitude of these opportunities, it is clear we have upside to our 3-year goal. As we began implementing these initiatives, we will address the scale of that upside in the future.

Looking ahead to the second half of 2025. Our supplement released last night outlined our expected Permian activity and production for the third and fourth quarters, adjusted to reflect the recent asset sale that closed in mid-June. With continued efficiency gains, we are delivering our planned number of turn in lines and expected production volumes, and we now expect to exit the year with a higher DUC inventory than originally planned. We'll continue to optimize our drilling and completion cadence through the second half of the year to ensure we deliver our revised capital guidance and set 2026 up for success.

As an additional benefit, these efficiency gains enable incremental resource development. As previously noted, we are moving toward denser well spacing with smaller frac sizes. While this may result in lower average well productivity, our new development patterns should deliver increased EURs at the spacing unit level and lower breakeven prices per barrel of oil. In turn, this expands economic inventory counts and increases both overall oil recovery and net asset value. This is a fantastic outcome.

In Egypt, underscoring our long-term strategic commitment and the ongoing success of our development program, we have recently secured presidential approval for the award of approximately 2 million net prospective acres in the Western Desert. This represents a greater than 35% increase in our acreage position and meaningfully enhances our already substantial footprint in the region. This acreage benefits from extensive 3D seismic coverage and considerable overlap with our existing operations, presenting compelling prospectivity for both oil and gas. We are currently in the final steps of the administrative process and plan to initiate drilling activity before the end of 2025.

We expect to maintain current activity allocations, with around 1/3 of our turn-in lines expected to be gas focused for the remainder of the year. Based on our year-to-date performance, we are once again raising our guidance for gross gas volumes for the next 2 quarters. This also increases our outlook for price realizations, as a higher share of volumes will now be subject to the new price negotiated under last year's revised gas sales agreement.

On the oil side, we expect production to stabilize for the remainder of 2025 and hold relatively flat to second quarter levels as our workovers, recompletions and waterflood programs help mitigate base decline. Combined with the success in the gas program, Egypt is now poised for 2025 growth in both BOE volumes and free cash flow relative to our expectations at the beginning of the year.

In Suriname, the GranMorgu development continues to advance towards first oil in mid-2028. I would like to commend our partner, Total, on their execution of the project since announcing FID last fall. Manufacturing of the top sides for the FPSO is currently ongoing, and Total was able to secure drilling contracts at very attractive rates earlier this year. We have updated our full year capital guidance to $275 million to reflect additional milestone and progress payments expected later this year. This just reflects a simple rephasing of spend patterns, and total anticipated project costs remain unchanged.

Lastly, we announced a discovery and successful flow test at Sockeye-2 in Alaska earlier this spring. As a reminder, the Sockeye prospect is amplitude supported across 25,000 to 30,000 acres and the discovery well encountered approximately 25 feet of net oil pay in 1 blocky sand. The subsequent flow test validated rock properties much better than regional analogs now under development. Given the size and extensive prospectivity of the block, the next best step is to reprocess 3D seismic data across the majority of our acreage position. This will allow us to tie multiple surveys together to refine our technical understanding and provide regional context. This is a key step for both better characterizing additional exploration prospects and for optimizing an appraisal program for Sockeye as well as helping to prioritize between the two. Given the timing of the seismic reprocessing and subsequent technical data integration, we anticipate drilling activity will resume during the 2026 to 2027 winter season.

In closing, I will leave you with the following: First, our operational and financial performance for the first half of the year was outstanding. This success is due to the collective efforts of our teams and strong alignment among all leaders in the organization. Our momentum is palpable and sets us up extremely well for the remainder of the year and into 2026.

Second, our cost reductions initiatives are progressing very well, and we are on the path to achieving significant and lasting improvements to our cost structure. On the capital side, we are capturing efficiency gains through structural improvements to our operations. This is allowing us to deliver our planned Permian oil production volumes at a reduced rig count and to grow BOE volumes in Egypt at lower capital. Our operating costs are also trending lower in both Egypt and the North Sea, and we continue to capture significant overhead cost savings through our ongoing simplification efforts.

Third, our progress in Suriname and our success in Alaska further underscores the value of our diverse portfolio of high-quality exploration opportunities which represent material catalysts for the future of the company. Finally, we are committed to our capital returns framework, which allows us to further strengthen our balance sheet while maintaining a competitive payout to shareholders.

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

Thank you, John. For the second quarter, under generally accepted accounting principles, APA reported consolidated net income of $603 million or $1.67 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $219 million after-tax gain on the New Mexico divestiture that closed in June and a $106 million unrealized after-tax gain on derivatives. Excluding these and other smaller items, adjusted net income for the second quarter was $313 million or $0.87 per share.

LOE came in below guidance, primarily driven by cost savings realized in our international assets. G&A was also lower due to continued progress in simplifying our organizational structure. While the majority of the variance stems from these structural improvements, both LOE and G&A were modestly impacted by timing-related shifts in spend, which are expected to land in the second half of this year.

APA generated $134 million of free cash flow during the second quarter, all of which was returned to shareholders through our base dividend and share repurchases. Our free cash flow is expected to be second half weighted, driven by Permian capital timing and continued growth in Egypt gas volumes and price realizations. During the quarter, we also made significant progress on debt reduction. We eliminated outstandings on our revolver and reduced net debt by over $850 million, a decrease of more than 15%. This was driven by proceeds from the New Mexico asset sale and positive working capital inflows primarily associated with payments from Egypt. In total, for the second quarter, nearly $1 billion was returned to investors through dividends, buybacks and debt reduction.

I'd like to take a moment to step back and highlight the meaningful progress we've made over the past several years under our capital returns framework. Since emerging from the COVID downturn at the end of 2020, APA has strengthened its balance sheet by reducing net debt by more than $4 billion. During that same period, we've returned over $4 billion to shareholders through our base dividend and share repurchase programs. This underscores our disciplined approach to capital allocation and our ability to consistently navigate commodity cycles while delivering long-term value.

Looking ahead, we plan to continue this balanced capital return strategy. To reinforce our focus on financial strength, we are establishing a long-term net debt target of $3 billion. While we remain committed to returning 60% of our free cash flow to shareholders, providing a debt target reflects our confidence in the durability of our cash flows, the resilience of our asset base and our goal of maintaining an investment-grade credit profile through the cycle. Maintaining low leverage enhances financial flexibility, reduces volatility and positions APA for sustainable success. This approach is not new. It's a continuation of the principles that have guided us, allowing us to fortify the balance sheet while delivering strong shareholder returns.

Moving now to our controllable spend reduction initiatives, where we continue to significantly exceed the targets established earlier this year. This accelerated momentum demonstrates our relentless focus on managing every aspect of our controllable spend across G&A, LOE and capital. Importantly, these increased targets do not represent a stopping point. Instead, they serve as key milestones in our consistent pursuit of operational excellence and our ongoing drive to reduce our cost structure.

Slide 4 of our supplement provides further detail between the various categories of cost savings that we expect to capture this year. While the changes in LOE and G&A savings can be reconciled with the movement in our guidance ranges for those items, our capital savings are partially offset by additional activity in the Permian. With the efficiency gains we've achieved, we're on pace to end the year with approximately 25% more drilled uncompleted wells than previously planned, while remaining within our capital guidance range, which will provide operational flexibility as we head into 2026.

On the LOE front, costs are trending lower across our international assets. In Egypt, reductions to date have come from two of our larger categories, optimizing equipment use and reducing our diesel consumption through recently completed power projects. Moving forward, we expect to further reduce diesel usage as we progress additional power projects into next year.

In the North Sea, we have been streamlining vendors and optimizing the size of our offshore organization as we manage late life operations. Furthermore, while maintaining our commitment to safety, we've shifted the scope of our maintenance activities to accommodate shorter, more focused pit stops versus extended platform turnarounds. In the Permian, while we expect the bulk of our LOE savings to become evident in 2026, we are already seeing early signs of improvement this year. Additionally, we are progressing multiple projects in the back half of this year that will deliver meaningful benefits in 2026 and beyond. These projects include, but are not limited to, utilizing owned and operated saltwater disposal facilities that will reduce reliance on third-party providers, consolidating field compression to larger centralized compression stations and reducing our workover fleet based on improved workover rig efficiencies. Across our entire operated asset base, we have moved decision-making authority closer to operations, which enables field personnel to swiftly identify and implement cost savings without compromising safety or performance. This has gained traction, unlocking a steady stream of small-scale opportunities that collectively drive meaningful financial impact.

Turning to overhead. Our initial focus was on executing quick win opportunities primarily through selective cost-cutting decisions. We implemented the bulk of those near-term actions, which drove the additional $35 million in realized savings since our last update. Looking ahead, we're advancing several work streams to rethink and reshape broader organizational processes and workflows with a focus on streamlining the business. These efforts, along with other simplification initiatives, are expected to deliver further savings in 2026 and beyond.

With all of these initiatives gaining traction across the organization, we're confident in reaching our $350 million run rate savings target within 2026, a significant change from our prior time line of end of 2027. We also see meaningful upside beyond that original target, which we will quantify at a later date. What's clear is that the entire organization is aligned and committed. In just 6 months, we've made real strides toward positioning APA as a cost leader. The focus is relentless, and the results speak volumes.

Shifting to our oil and gas trading portfolio. At current strip pricing, our full year guidance reflects $650 million in pretax income from our trading operations, a $75 million increase from our May update. This is a key value driver for us, and the forward curve for 2026 shows favorable LNG pricing and spreads, reinforcing these activities as a meaningful differentiator for APA.

I will close by discussing several changes to our U.S. and U.K. tax estimates. Following passage of the One Big Beautiful Bill Act, we expect to benefit from two changes to the U.S. tax code, the first being 100% bonus depreciation for taxable income, which is effective as of January 20 of this year. The second being the ability to deduct intangible drilling costs for corporate alternative minimum tax, which comes into effect at the beginning of 2026.

For 2025, we expect a significant reduction in our U.S. current tax expense, driven by bonus depreciation changes and the recently passed legislation, changes in 2024 tax estimates and other smaller items. This reduction is largely offset by an increase in U.K. current tax expense, where higher revenues and lower operating costs have increased our taxable income. Starting in 2026, at current strip prices, we do not expect our U.K. operations to generate meaningful taxable income. Combined with the expected benefits from the One Big Beautiful Bill, our total U.S. and U.K. current tax expense will be significantly lower compared to this year.

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

[Operator Instructions] Our first question comes from John Freeman with Raymond James.

Congratulations on the continued progress on the cost savings initiatives. Along those lines with the new $3 billion long-term net debt target that Ben outlined, do you all have a time line for achieving that target? And maybe if you could provide some details on the planned and whether or not divestitures might be used as a tool to kind of accelerate that time line or possibly exceed kind of that debt target kind of on the heels of what you did with the recent New Mexico sale?

Sure, John. When we outlined that target, we thought it was responsible really to commit to the specific target and not really a date which could move around and ostensibly be artificial. There's a lot of macro volatility and regulatory shifts that could just distort short-term move in optics in that. So we just thought that putting a target out there was more prudent.

Now that being said, at what we think is mid-cycle pricing, which is pretty close to what we have seen last year and this year, we'll achieve that target likely by close to the end of this decade, so call it in the next 4 plus or minus years. If prices are higher, then that can be accelerated, and we might be able to achieve that earlier, call it, in a couple of years. And if prices for that entire time period are below, then it could take a little bit longer, call it, 5 years. But we expect to do that just through our organic free cash flow generation and really a commitment of that 40% that's not being returned to equity being directed towards getting our net debt down.

And it's just going to provide a lot of flexibility. That still includes us managing our ARO and decommissioning spend, and we're getting that liability managed. It allows us to invest in the future for exploration and other projects that we see necessary to continue to help the future of Apache. And so we didn't want to put a specific time on it. We just feel very confident in the durability of our cash flows that we'll be able to achieve it, like I said, call it, in the next 3 to 5 years.

And then shifting gears and looking at kind of what you have outlined on Slide 11 with Egypt, given the impact of the recent gas pricing agreements, the consistent outperformance on the production side, along with the recent award of the additional 2 million acres in Egypt. When you sort of look out to next year, would this sort of indicate that there might be a shift to a larger percentage of the total CapEx budget being allocated to Egypt?

Yes. John, if you just step back and look big picture at Egypt, I'll just give -- it is a big award, and I'll give a little bit of context. We've been in the Western Desert now for over 3 decades. And for those first 3 decades, we spent the majority of that time looking for oil. Along the way, we found some gas and some material gas, feel like costs are over 3 Tcf. And then a lot of associated gas and some rich gas. And so we spent 3 decades looking for oil and trying to really stay away from gas. If you look at the Western Desert, you've got 15,000 to 18,000 feet of stack pay. It's all sand, it's high quality. We knew, drilling deeper, you would find it.

So if you go back, what changed for Egypt is they went from an exporter of LNG to an importer of LNG. And with the change in the new minister last summer, early on, we set a goal in place to -- let's put a new gas price in place that would incentivize us to get after drilling. And we also had our eye on some acreage that is prospective for both oil and gas. So we've worked through that direct award. We've gotten after the program, and Steve can talk a little bit about the impact we're having on the gas program. And then I'll let Tracey talk about what she sees is longer-term upside for gas in the Western Desert, which we think [indiscernible] perspective.

Yes. Thanks, John. As John said, historically, we've been -- we've done what we could for the last 30 years to avoid gas, but we have encountered gas. Sometimes in large enough quantities that was worth developing, sometimes rich enough with enough associated liquids that it was worth developing. But sometimes we left it either undeveloped or underdeveloped simply because the gas price that prevailed at the time wasn't economic enough to deliver -- to develop the asset when we had more oil opportunities. And in 9 months now, we've focused on going back after those opportunities, mostly things that we left undeveloped or underdeveloped, and the results have been quite striking where there are more known opportunities to go. So there is more to do in that space.

And the good thing is that through that, we're actually derisking what I would call kind of minor step-out type of, if you want to call it, exploration, the step-out opportunities beyond what we know is there, we're de-risking those, and there's quite a bit of those for the near-term future as well. And so the obvious question is, well, how long can this type of performance run and actually potentially for quite some time. But at the same time, we're also stepping back, and Tracey's team is looking at, well, let's just step back and look at the whole regional geology around this 7.5 million acre position that we have now and what's the potential for even larger scale gas opportunities. And I'll let Tracey talk about that.

Sure. Good morning, John. So with the new acreage additions, we're going to be really well positioned to both expand our existing proven place for both oil and gas and test and new concepts to add inventory. So for example, in the western portion of our acreage, in the [ Fugar Shushan ] region, we've had some recent success by drilling deeper to the [ Paleozoic ] and have encountered some really good discoveries for gas. So we're really building on that success there by extending the [ Paleozoic ] plays both to the west and to the south into the direct award acreage, where we believe we have mature gas prone source rocks in the [ Paleozoic ]. So we see that deep play continuing, and we think we've got a lot of running room because that's a very underexplored play in a mature area.

And in the AG Basin, which was in the Southern Central portion of our acreage, this is one area where we previously focused and only limited ourselves to oil prospectivity and the shallower Cretaceous targets. And now this is a big area for us for big gas and a big focus. So we're quite excited about this because this is an area that's a proven basin. But it's been underexplored because we've been avoiding drilling for gas. So the gas pump portions of this basin, we think we have a lot of running room in.

The last area that I'll touch on is the acreage to the east, which will allow us to expand our oil plays as well. So we picked up a block there with only 8 wells drilled in it. So it's very underexplored for a very sizable area. And we see evidence on seismic that some of our proven Cretaceous plays in the Western Desert expand into this area. So we've got some new play tests there as well. So we're really encouraged by what we're seeing on 3D seismic, and we'll be testing some of those later this year.

So we're in a really good position to both leverage what we know in the desert and test some new concepts. And I'm really optimistic on what we're going to be able to deliver in Egypt for the exploration program.

If I could just wrap that up. I mean, we're operating now in a 7.5 million acres in what's obviously a hydrocarbon-rich basin. And with the new gas price agreement, we can actually operate in a way where we don't have to avoid certain types of hydrocarbons. So we can just pursue the best prospects and were really almost indifferent over time to whether it's oil or gas.

Our next question comes from Doug Leggate with Wolfe Research.

Thanks everyone. John, this is starting to look a lot like a turnaround, so congrats on the quarter. But there's a lot of things to dig into. I'm going to pick two, if I may. And it's the one sore point perhaps for the market, which is there's still no visibility on inventory in the Permian. So you haven't commented on that in quite some time. So I wonder if you could address that and the associated run rate capital we should expect for that maintenance of the new production level that you highlighted in your comments?

Yes, Doug, I'll jump in. And the first thing I'll say is we're always culturally looking for how do we continuously improve and drive innovation. And if you look at the impact you're seeing on the capital efficiency today in the Permian, those are results that are really a credit to both the technical teams and the field staff for really focusing on operations excellence over the last two years. We've continued to build a lot of momentum. You're seeing those results come in. And quite frankly, there's a lot of upside and more we still see to bring forward.

In my prepared remarks, I outlined how our Permian development strategy is evolving in a lot of areas now where we're drilling more wells per section with smaller fracs, and it's really a function of getting the cost down and being able to drive the capital efficiencies. And where we are, we're in the process of characterizing all of our inventory and all of the upside zones in the Permian. I have seen what I'd call the core inventory. And where we historically would have said to the end of the decade, I can tell you today, looking at what I would call core development inventory, we're now well into the 2030s with run rate in terms of existing pace in time. And there's a lot more we're still working on.

It's a very iterative process. The teams have been working hard on it, and we should be in a position, either late this year or early next year, to give some more color on that. But it's progressing. I'm excited about the impact we're seeing. And Steve can get into some of the results. But if you look at some of the pads we're drilling today, we've gone back into overfill areas and are having fantastic results. So very excited. We will be at the Permian on our existing portfolio for a long time.

Yes, John, just -- if people will indulge me a bit with a bit of time. I think if you just step back, capital efficiency changes everything in our industry, and that's always been true in our industry. And that lower cost leads to the ability to access more resource. And all you have to do is look at the history of the Permian conventional to see that, where as costs came down, people went from 40-acre spacing to 20-acre spacing to 10-acre spacing, increasing well density and even promoting resource from uneconomic to economic status.

In the unconventional space in Permian, that increasing well density also enables, as you alluded to, lowering frac intensity, which then further compounds the lower cost structure that you have on a per well basis. And so for us, capital efficiency has really led to here recently to a step function change in our capital efficiency and is leading to pretty meaningful changes in our development patterns. And I don't use the term step function change very lightly either because I think that's an adequate descriptor of what we've done over the last several quarters. We're increasing well count. We're decreasing frac intensity, as you alluded to.

That generally lowers average well productivity, yes. But at the DSU level, the drilling spacing unit level, we're increasing total resource access and lowering breakeven oil prices. We talked about in Callon, in 2023, Callon had a $78 WTI oil breakeven price. In 2024, we lowered that to $61. Currently, in the Permian, we are running on average in the low 40s across the entire Permian in terms of a WTI breakeven oil price. In Midland Basin, we're running in the high 30s. And in the Delaware Basin, we're in the low 50s. And most of that Delaware Basin stuff is Callon. And so Callon has come down in 2023 from a $78 breakeven oil price to low 50s at this point. All of this is increasing net asset value and increasing inventory duration, as you alluded to. And while I say average well productivity is lower, I think it's a focus on average well productivity is actually not the right metric. You really have to focus on the spacing unit because wells in a spacing unit are interdependent. And it's the spacing unit that actually matters. Just a couple of years ago, a well-followed industry analyst group noted that Apache have -- Apache's wells have 30% more EUR than industry average. And it was just a couple of years ago, and these were highly productive wells.

But at today's cost structure that we have, that development pattern with the wider spacing and larger fracs would actually leave a pretty meaningful amount of economic resource behind. And so today, our development patterns, as you said, much tighter, smaller fracs, they're lower EUR per well, lower productivity per well, but more inventory, more resource, more NAV, lower breakeven oil price. And so if you look at some of our most recent wells using new development patterns, these are delivering -- these wells are delivering as we planned. Some are over plan, some are under plan, that's always the case. But importantly, some of these ones that are under plan, we're actually learning from those and improving. It's not just because they can't be improved. It's because there are things that we're learning and improving along the way.

And I think some really important context that might not be visible to the market, especially related to some of these recent wells that we've been drilling is that there's been some temporary constraints or curtailments on the productivity, impacting perceived well producibility. A few examples of that in the Delaware Basin at the [ Gar ] facility, as we noted in the fourth quarter, we're actually curtailing production on those intentionally because of the low oil price that wasn't going to last very long. It was because of some pipeline maintenance that was going on at a really low price at Waha. And so we intentionally curtailed production for a while.

Drilling and completion in the [ Gar ] area also actually significantly outpaced our facility logistics, and the facility just wasn't completely ready for that. That was -- that's been fixed since then. Also in the Delaware Basin, there's a facility called [ Wild Jenny ]. We currently have 14 producers into the [ Wild Jenny ] facility and have been producing for the last few months. If you looked at the production of those wells, you say, well, that's not really very exciting. But again, facility logistics, drilling and completions going faster than facilities have also constrained those wells' productivity for the last few months. We actually like the underlying performance, and we think the rock quality of those wells are actually really good.

We've got 24 more turn-in lines into the [ Wild Jenny ] facility by the end of this year. And the production from those wells, even though it might -- on paper might not look all that great, the production from those have actually derisked those 24 turn-in lines. The facility is being worked on as we speak, being debottlenecked and being completed, actually. And we expect that all 38 of those wells will flow unconstrained or nearly unconstrained by the end of this year.

And perhaps most importantly, in the Midland Basin in the [ wildfire ] area, we've got the [ Silver Belly ] facility. And the [ wildfire ] is the area where we're going back in and drilling what we call overfills, which is we're drilling shallower zones where we, in prior years developed on the wider spacing with what we called mega fracs at the time. And there's some doubts or concerns out there about, well, what are these wells going to produce with those mega fracs down below them, they've been producing for a few years. Well, at the [ Silver Billy ] facility, we had delays in delivering power to the facility, and we have electric compression there. So those -- that actually constrained early production from those wells as well. The wells were ready, but the facility wasn't completely ready. That power is now online. The electric compression is up and running and the performance of those wells have actually improved significantly.

So the point to all of this is that it's a bit hazardous looking at either comparing well productivity today to 2 years ago when we were developing at a much different pattern. It's also a bit hazardous looking at short-term production from new wells when there might be constraints or other reasons at facilities. We look at the [ wildfire ] production and the wells that are online today and we actually believe that that's derisked quite a bit more drilling in that area.

Gosh. Very thorough answer, Steve. I appreciate that. I wonder if I could just put a bow on it. What is the sustaining capital in the Permian production? What is the spending run rate into '26?

Doug, I think if you looked at us today, 6 rigs -- and if you adjust our numbers for the New Mexico sale this year, we're in the low 120 range. So I would say, going into '26 right now, 6 rigs, 120. And I think you need to look at a capital number, back half of this year will be lighter than that. So you're probably more in the 6 rigs range. Ben?

Yes. I think, Doug, just -- if you annualize second quarter through fourth quarter of this year, that will give you a decent proxy for next year, which is lower than '25 full year as expected with the cost savings initiatives, and we think there's even upside to that. But just from where we sit right now, if you annualize our second quarter through fourth quarter spend this year, that will give you a decent proxy for what to look at for next year on U.S. capital.

All right. Guys, I had five more questions, but you've taken a long time for this one, so I'm going to turn it back to someone else.

Our next question comes from Michael Scialla with Stephens.

Good morning, everybody. I know Total pushed back on their second quarter call and the possibility they were ahead of schedule on Suriname and you're sticking with first oil in mid-'28, but is it fair to say that the fact you're increasing the budget for GranMorgu milestone payments reflects that the project's moving more quickly at least than you anticipated?

Mike, what I'd say is, first of all, I really want to complement Total. I mean they stepped in, we FID'd this thing last fall, and they have gotten after it and they're really validating that we picked the right partner for Suriname. What I would say is overall project is moving as scheduled. What's actually moved from early next year payments to this year, you're seeing some milestones on some of the things like the FPSO moving a little quicker, but nothing that's going to change the overall project at this point or increase the overall cost. So it's just some of the noise, I'd call it, between a calendar year of what's getting paid because as you complete certain aspects of the infrastructure and things, those are due. So no real change at this point, but things are progressing very, very well.

Okay. Sounds good. I wanted to ask on Alaska. You gave a little bit of detail on that. I guess, on the technical work that's being done there, did I hear you correctly that it's just seismic reprocessing for a while and no drilling until the '26-'27 winter? I guess I wanted to get a progress report there and what you're looking at with the reprocessing.

Mike, if you step back 2 years ago and our partner originally spud 3 wells, 3 prospects on the block there. And the only 1 that got down, we ran into a shortened winter and they had some drilling challenges with the equipment. The only well we TD'd was King Street, and it was a successful discovery in the Brookian play. What King Street told us is that you can move 90 miles from any of the offset development, and we had a really high-quality sand.

So when we looked at this year's program, we wanted to go in and drill 1 well. The well we elected to drill was Sockeye, it is not the largest prospect. But the reason we prioritize Sockeye this year was it had the highest quality seismic data. And what we were hoping to prove is Sockeye is 1 oil to high-quality sands. We did both of those, 25 feet of net pay. It's amplitude supported over 25,000 to 30,000 acres, really high-quality sand, and it's all oil. So -- and then the flow test confirmed the Perm is much better than what's being developed. So we're very, very happy.

When you step back, as I said, Sockeye was not the biggest prospect. We've got a bunch of different seismic surveys. And so with the success we've now had on both the east and the west side of the block, the next step is really, let's reprocess the seismic, put all these together because, quite frankly, where we place the next exploration well and then the timing and the plan on how we appraise Sockeye are important and a better picture across the whole block from a regional perspective is what's key right now. And it takes a little bit of time. And so there's a lot of data to integrate. It won't be just the seismic the technical teams are doing, they are going to be working. But yes, it's likely winter of '26 before we move a rig back out there. And Tracey, anything you want to say?

John, I think you covered it. I think the most exciting thing, as John mentioned, was that we proved the play concept moving from the Pikka and Willow discoveries to the block on the other side of [ Prudo Bay ], which was a really big story. And I think we've just really been bolstered by the success that we've seen at Sockeye as well that further demonstrates a working hydrocarbon system with really good reservoir quality and an oil charge.

Our next question comes from Betty Jiang with Barclays.

It's great to see North Sea taxes coming down so much in -- next year. Could you help us just impact what exactly is driving that drop? Does it mean the ARO spend is going up in a meaningful way next year? And if you could just remind us what's the general trajectory of that decommissioning activity over the next few years?

Sure. Really, I'll just step back when you look at the U.K., this year, the team has done a really great job with the asset, as you can tell in the first half. We've gotten production higher than expected, and we've been -- and the team has been cutting a lot of costs there. And that's increased taxable income for this year.

But when you step back and consolidate everything, that means that free cash flow for that asset is also up at some point with production continuing to decline without investment in the asset in the future, it will be at a tax loss position and that at strip pricing and current investment levels, we think that, that's likely going to happen in 2026. Until then, we'll continue to manage productivity and cost on that asset and the profitability of that asset. But at some point, it will get to a tax loss position just inherently through the asset standing alone from regardless of the ARO spend. And so then you put ARO on there, it will increase next year compared to this year as we start to do more planning and decommission certain assets in the North Sea.

What Steve said, I think a few quarters ago about the shape of that is it will increase pretty steadily from '25 and kind of peak in the 2030-2031 context and then decline from there into 2038. So all the while, the team is focused on safety and really managing those assets for profitability. The tax regime there has been challenging. But for us, we expect at some point, likely in the next, call it, 12 months or so, some point next year. There won't be taxable income there, and so we won't be paying cash taxes on that asset.

Got it. That's helpful color. My follow-up is on the free cash flow profile of the Egypt business. Just given the gas price improvement that you're seeing, the cost saving initiative that's being implemented now. Maybe one way of looking at the Egypt business is how much free cash flow do you think that business can generate on a sustainable basis?

Sure. I think when you step back this year and you look at the beginning of the year, where we were, we had some expectations for what we were going to do on the gas side, and we've clearly exceeded a lot of that this year. And with the increased gas production as well as the step change in the gas price, which you've seen quarter-on-quarter delivery, free cash flow for that asset net is up, and that includes the modest decline in oil that you'll see just year-on-year, '24, '25. And at this activity set with the oil -- with the oil investment that we're doing with about 2/3 of the activity on oil and 1/3 on gas, it will likely decline next year as well. But that's going to be more than offset by gas production and the gas price. And so BOEs, we expect will continue to grow and they'll grow this year. And think that, that trend can continue next year, and that implies a modest free cash flow increase year-on-year as well.

Our next question comes from Paul Cheng with Scotiabank.

I don't know -- Ben. I don't know it's for John or for Steve. Just curious that, I mean, as you move to doing more gas, from an organizational capability standpoint as well as the equipment availability in Egypt, how big is the program you can do? I mean, if we set aside, say, the capital constraint, just looking at organizational capability, where is the constraint? Can we do the program? I mean, because -- it seems like you're so attractive on those developments. Can you do it faster? Do you have that capability? And also, if the market equipment can support it?

Paul, it's a great question. I'll jump in here, and then Steve can add if need be. But from an organizational standpoint, we've got the capacity. And if you step back and look at the Western Desert in the supplement, we put a picture in there that shows a lot of the infrastructure. We developed in the early 2000s of [ field Caser ], came on about $750 million a day, 3 Tcf.

So when you step back, I mean, I think the biggest thing for us is characterizing on the exploration side. I mean, we've historically been focused on oil for 3 decades. We've now been looking for gas for 9 months. And so with the new acreage and the seismic, it's just -- it's letting the team have time to work up some of the larger exploration prospects and prioritizing those and drilling some of those are going to be the keys to setting us up in terms of what can we do in Egypt on the gas side. But it's a very, very gas-prone basin. There's a lot of potential. I think it's just going to take a little bit of time for us to work the entire 7.5 million acres.

And John, just curious on...

Yes, John, I'd just add on the -- on the gas processing side, if you look at field infrastructure on the gas processing side, we've got a significant amount of [ olage ] there. We've got -- we produce about around 500 million cubic feet a day today. We've actually got plant processing capacity of about 800 million cubic feet a day. And the limitation for us is really in the field around gathering and transport to the facilities. And in new areas, it's a need for trunk lines, and that's kind of fairly simple. In the producing areas, the legacy producing areas, we're dealing with pressure regimes as you're dealing with older legacy production that's lower pressure with the new gas discoveries and gas production volume that comes in at higher pressure, and that's a bit more complex in dealing with that.

We've been working through those limitations actually extremely effectively. But more infrastructure eventually will be needed if we have the exploration success that we actually anticipate we have for the long term. We'll need to develop low pressure and high pressure systems. We will need compression. And there are some other actually other existing or anticipated facilities in the area, third-party facilities where we're actually having conversations already with some of these third parties about could we get access to your capacity, which would lead to additional capacity much more easily available to us and a lot less capital and in some cases, readily available actually today. And I think in the longer term, exploration, as you mentioned, is going to determine the way forward around cost -- I mean, around growth.

Okay. Steve, just curious, in the past, when you're developing oil, you have said you need about 2 workover rigs for 1 drilling rig. And that become a bottleneck because you just could not find enough of the workover rig. That's why you scale back in your program in oil. In gas, based on your experience that, what's that ratio?

Yes. In gas, it's not going to share the same ratio. And actually, we don't necessarily -- that ratio doesn't stay constant even on the oil side because we -- I think you were probably talking about the situation that we had a year or so ago, a couple of years ago when we were running -- at 1 point, we were running as many as 21 drilling rigs, and I think we had about 20 or 21 workover rigs running at the same time. And the issue on the oil side is that a lot of the oil wells have to be completed by a workover rig, and the drilling rig is not actually equipped to do that. We've actually moved to today, we can do more, not all, but more of the completions with the drilling rig. And because we're drilling more gas wells, you don't need as many workover rigs to handle the completions also.

Yes. And the other factor that comes into play there is the deliverability of the gas wells and the targets. We've been looking for oil for 30 years, and gas, we've just started. So you'll have bigger targets relative. But -- so not a major problem on the workover rig count at this point.

Great. Final question. Steve, when you're talking about an upside to the 350, where you think that is the biggest source of that upside?

Sure. I'll start and hand it over to Steve. I'll start on the G&A or overhead part. We've made a lot of progress there. As I said in my prepared remarks, there have been some kind of quick wins that we've done. Right now, we've got a lot of simplification efforts ongoing in some of our larger corporate groups. And when you take all of those together, it's about 7 different projects we're working on right now. It's about 1/3 of our total overhead. And so we'll work through that. The focus there is streamlining processes and making sure that we're being efficient with the use of technology. There's potential for AI to help out in that, and we're evaluating that. And the -- and it's also just making sure that everyone is being efficient with time and doing things that actually add value.

So we're starting with those 7 groups, but that doesn't cover the whole organization. So you move into next year, the following year, there will be other groups that will be going through the simplification efforts. And we think that as we do that and streamline everything with a company that has manageable activity in front of it, that there's going to be upside to the overhead savings that we have and we've already captured this year. I'll turn it over to Steve to talk about additional -- on capital and LOE.

Yes. On the capital side, I think in the Midland Basin, we believe on a drilling and completion basis, we're actually competitive today with some of the best in the industry. And that doesn't mean that there's not opportunity for continued improvement because our competitors continue to improve as well. So obviously, we'll keep pushing for improvement there.

In the Delaware Basin, drilling and completions, we've improved quite a bit, but we're running at about industry average now that Delaware Basin is not as homogeneous as the Midland Basin is. So it's not necessarily comparable across the entire basin. But we do -- and we do think we're very good in some areas, but we do think there's also areas where we can continue to improve. I think across the entire basin, things like more use of simul frac, more drill-out optimization, which we've made some good strides there, drill out post completion, that is -- and we've accomplished quite a bit in the Midland Basin, particularly because of the pressure regime that we find in the Midland Basin, which is much lower than what we find in the Delaware Basin.

But some of the things that we've done in the Midland Basin, can we transition or translate some of those in some form into the Delaware Basin, things like changes in casing programs, casing designs, drilling fluids, bottom hole assemblies and things like that, that we might be able to get into the Delaware Basin as well that have been instrumental in getting to improved rate of penetration in the Midland Basin and lowering total well costs.

I'd say also on the facilities side, we've probably -- we're moving away from greenfield type of facility construction, which we've done quite a bit of in the past. We're moving more towards brownfield activities, which will be less expensive. We've reduced facility spend on the magnitude of $50 million or a bit more from '24 to '25. We still had some greenfield activity even in '25. As we move into '26 and beyond, I think we're going to be predominantly brownfield type of facilities activity. And I think that there's an opportunity for further facilities capital spend reduction as well.

On the LOE side, I'll start with the obvious, and that is we've actually made little to no progress on the dollar side of LOE year-to-date in '25. So it's not contributing a whole lot to our improvement in costs so far this year. We're making progress today, not necessarily visible with the second quarter results, but we are making progress. And actually, second quarter was above our guide for LOE, but it was below first quarter LOE. And actually, the month of July has been the lowest month of LOE in the Permian that we've experienced to date this year. So we are making progress.

Short term, I think we're benefiting from a move of accountability around certain types of costs out to the field, closer to where costs are incurred, and we're working more closely with vendors. We're seeing reductions coming in contract labor. We're seeing reductions in chemical usage. We anticipate more coming up in -- and we've done this in the past, too, just ESP to pump conversions using less power, more tankless batteries. We're seeing workover rig rationalization in the Permian due to the efficiency gains in our workover activities.

I think longer term, there's some very high-return capital investment opportunities that will lower LOE, things around water disposal. Because water disposal hits us in 2 ways, actually, which is obviously the cost of third-party water disposal. But also as many operators are experiencing in the Permian today, we're getting water takeaway constraints from time to time, and actually, it results in curtailing production volume. And so when you have control over your own water disposal, it benefits you in both ways, compression, in the field compression, we need to go to a larger scale, more centralized, therefore, more efficient and more reliable compression systems.

And just overall, continuing to improve the leverage of technology around recognizing and addressing issues in the field more timely so the production volume, which might be constrained or offline, gets back online quicker and you do it in a more targeted basis instead of the old-fashioned way of someone visiting every site every day and just getting ahead of some of those things in the field and being more preventative instead of reactive. So I think there's quite a bit of opportunity on the LOE side. And I didn't mention, but good LOE reduction activities going on in Egypt and North Sea as well.

Our next question comes from David Deckelbaum with TD Cowen.

I wanted to follow up -- I appreciate it. I was hoping for a little bit more detail on the additional Egyptian acreage and the award there. Just to confirm, one, that -- is there any performance that APA needs to perform in terms of activity levels, et cetera, to earn into this award? Or should we just view this as a concession because you've been a solid operator in the area? And then how do you all think about the incremental acreage from an infrastructure perspective? It looks like aerially, that things are well tied in. But I guess as we think about over the next couple of years, is this an area that you're going to have to add additional infrastructure capital to?

Yes. It's something we integrate in. Some of the acreage we've had in the past, some of it we haven't. There is a bonus we pay that gets netted off of our past due receivables. And there are a number of wells we'll drill which get rolled into the program. So in general, you should think of it as just adding to our existing program on our merged concession, which is how this acreage gets rolled in and gets treated. It becomes car really just part on the infrastructure side of both the oil and gas programs with success in areas we'll need to build out and add on. But as you see from the map in the supplement, we've got quite a good backbone across the desert. And so it's something that we will look to add to and build on with success. So -- but just think of it as adding to our going concern. Egypt, we've gone up from 5.5 million acres now to 7.5. Activity levels today are going to stay the same. But we'll be drilling on this acreage in the fourth quarter.

Appreciate that, John. And then just for my follow-up, as you think about this new long-term net debt target of $3 billion, which appears like you're going to achieve in relatively short order, especially with the benefits of taxation next year, when you get there, how do you think about capital from beyond that in terms of free cash, just given the fact that you have a fairly robust exploration portfolio relative to returns of capital?

Yes. I mean, if you -- I mean I'll step back and then let Ben jump in, but we've tried to be really smart, right? I mean, when you look at what we did in Suriname when we brought in a partner, we banked on the fact that to really get value for this block, we needed to FID a project. And we structured the agreement accordingly. So as you're now going through development scenario, Total is carrying a large portion of our capital, and it enables us to stick to our returns framework without having to sell a lot of assets or do other things. And so we've tried to be really smart and think longer term about the balance sheet and think about how do you fund these types of projects in the future.

Yes. And we made it a net debt target. From time to time, we'll have cash on the balance sheet. I think that provides a lot of flexibility. To your point, just organically expect to get there in the foreseeable future. But when you have different priorities like John mentioned, whether it's exploration and investing in in the future or decommissioning assets, which we know is coming in the coming years and it has been. We've been decommissioning for quite a few years now. It really helps us to manage that risk and deliver returns. It's the responsible way to do it without eroding shareholder value.

And so really provides flexibility. And just stepping back, 1 comment you mentioned on the taxes. The One Big Beautiful Bill, the intent of that was -- that legislation really was for the favorable tax treatment for industries like ours that are highly capital-intensive for tax treatment for intangible drilling costs to be beneficial. And so when we look at that, we think it's durable and will continue for years as long as that legislation is intact, and that provides a lot of tailwinds for the industry and definitely for Apache.

And so that helps when you think about shareholder returns and when you think about deleveraging, there's a lot of positive momentum for that. And we'll be flexible with how we deploy that capital, but focused on shareholder value, that net debt target once we do achieve that we'll step back and reevaluate. But believe that the durability of our cash flows and a lot of other momentum that we have, we'll be able to get there as well as invest in the future and return capital to shareholders.

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

Thank you. Our strong second quarter results reflect the hard work of our entire organization, and specifically, the integration of the technical teams in the field and the execution across everywhere. We built strong momentum for the back half of the year and well into 2026. We are outpacing our expectations on capital efficiency gains and cost reduction initiatives while continuing to make progress on net debt reduction and shareholder returns. We have bolstered our core assets with a step change in capital efficiency in the Permian and the direct award of 2 million acres in Egypt, along with the early success of the gas program.

The GranMorgu project in Suriname is progressing on schedule, and we remain very optimistic on the impact of our exploration portfolio [ that what ] it can have on the corporation. With that, I will turn the call back over to the operator, and thank you very much for joining us today.

This concludes today's conference call. Thank you for participating. You may now disconnect.