APA Corporation

Good day, and thank you for standing by. Welcome to the APA Corporation's fourth quarter and full year 2023 results conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Gary Clark, Vice President, Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's fourth quarter and year-end 2023 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO John Christman. Steve Riney, President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Dave Purcell, Executive Vice President of Development, Tracy Henderson, Executive Vice President of Exploration, and Clay Bratches, Executive Vice President of Operations. Our prepared remarks will be about 15 minutes in length, with the remainder of the hour allotted for 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 non-controlling 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. Also, please note that the forward guidance we provided with our fourth quarter results reflects our outlook for APA Corporation on a standalone basis only and does not incorporate pro forma effects of the pending Callen Petroleum acquisition. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. On the call today, I will review our key accomplishments in 2023, comment on fourth quarter performance, and provide an overview of our 2024 plans and objectives. APA has a longstanding strategic framework for managing our business that emphasizes investing capital with a focus on long-term full cycle returns, pursuing moderate sustainable production growth, strengthening the balance sheet to underpin significant cash returns to shareholders, responsibly managing costs, including rightsizing the organization commensurate with lower activity levels, growing inventory both organically through existing play expansion and new area exploration, and more recently building scale and or adding inventory inorganically through acquisitions and such as Callen. We have patiently employed this strategy through periods of considerable price volatility, and our approach going forward will remain unchanged. Looking at APA's results, there were a number of highlights in 2023. The more notable achievements include, on the whole, delivering on all of our production and financial metrics very close to original guidance. Egypt gross oil production lagged expectations for most of the year, but this was offset by continued strong performance from the Permian. Free cash flow generation of nearly $1 billion, 66% of which was returned to shareholders. We repurchased $329 million of common stock and paid $308 million in dividends. Adjusted oil production increased 4% from the fourth quarter 2022 to the fourth quarter of 2023, driven by Midland and Delaware production, which was up in excess of 20% over the same time period. We successfully appraised the Sapakara and Krabdagu discoveries on Block 58 in Suriname, identifying an estimated 700 million barrels of recoverable oil resource. On the ESG front, we now have implemented more than 70% of the projects necessary to achieve our 2022 goal of eliminating 1 million tons of annual CO2 equivalent emissions by the end of this year. Additionally, we replaced or converted more than 2,000 pneumatic devices in the United States during 2023 which aligns with our priority to reduce methane emissions across our operations. And lastly, I want to recognize our operation teams for delivering the lowest recordable incident rate since we began tracking and reporting this metric. We highly value this commitment to safety and excellence, and thank you for your continued diligence on this front. Moving to fourth quarter results, Upstream capital investment of $520 million was slightly above guidance as we spent $27 million on the initial phase of our winter exploration program in Alaska. The U.S. delivered another strong quarter with oil production in line with guidance and up 12% compared to the fourth quarter last year. Throughout 2023, our five-rig drilling program was highly efficient, meeting or exceeding all key performance metrics. Similarly, well connections and well performance were in line with or better than expectations. Our Midland and Delaware Basin teams are driving outstanding results, and we expect that will continue this year. In the North Sea, production for the quarter was below guidance due to unplanned compression downtime at both barrel alpha and 40s during the month of December. And in Egypt, adjusted production exceeded guidance primarily due to higher natural gas production and the positive impact of lower oil prices on volumes within the PSC construct. Gross oil production, however, was lower than expected for a few reasons. For several quarters now, we have been working through some activity delays and scheduling constraints associated with limited available workover rig capacity in Egypt. In addition to routine well maintenance and uphole recompletions, We also utilize work over rigs for completing many of our new drill wells. With the increased size and improving efficiency of our drilling program, the demand for work over rigs to complete new wells has exceeded expectations. This meant the work over rigs were doing fewer re-completions than planned and our work over backlog increased throughout the year. Thus, while production from the new wells was a bit better than expectations, Egypt gross oil volumes fell behind as we could not adequately support the recompletion and workover programs. Compounding this, we also experienced a number of early life failures on new electrical submersible pumps, known as ESPs. During 2023, we had nine new wells impacted by early ESP failures, two of which occurred in the fourth quarter on high-volume wells. We have traced this problem to one manufacturing facility, and the situation is in the process of being remediated. In 2024, we will gear down the Egypt drilling program a bit, which will free up work over rig capacity to reduce the work over and re-completion backlog. I will say more about the effects of this on 2024 activity in a few minutes. Turning now to our 2024 outlook. Given the potential for a flat to lower price environment this year, we have established an activity plan and budget based on $70 WTI and $75 Brent. We continue to diligently manage overhead and operating costs, and we are reducing our total capital investment to less than $2 billion. This includes approximately $100 million of investment for exploration activities and $50 million for feed work and potential long-lead items in Suriname. This year's budget will redirect capital to the Permian Basin, resulting in reduced Egypt drilling program, which I mentioned earlier. The outcome of this investment profile should be relatively flat year-over-year adjusted oil and natural gas production, but lower NGL volumes given our current plans to reject ethane. As in 2023, we expect robust Permian oil production growth to roughly offset production declines in the North Sea, while Egypt adjusted production remains relatively flat. In the US, total volumes will be up about 2% on a BOE basis, despite our current plan to reject ethane for the entirety of 2024. We also project a strong finish to the year with US oil production up more than 10% in the fourth quarter of 24 compared to the fourth quarter of 23. This growth will be driven by the Midland and Delaware basins, where we expect to achieve our goal of returning oil production to pre-COVID levels by year end. In Egypt, we anticipate that our moderated pace of drilling will result in a gross oil production decline However, adjusted production should remain relatively flat year over year, primarily due to lower oil price expectations and the moderating effects of the PSC. And in the North Sea, with our significant reduction in capital investment prompted by the energy profits levy, we anticipate a roughly 20% year over year production decrease. This includes the effect of a lengthy planned maintenance turnaround that will impact both and third quarter volumes. Before closing, I'd like to take a minute to highlight our performance in the Permian and provide some thoughts on our pending acquisition of Callan Petroleum. For several years now, APA's Permian operations have been hitting on all cylinders and exceeding oil production guidance. We have delivered continuous improvement in well productivity and capital efficiency, and we expect this to continue in 2024. Since 2019, we have invested considerable time and technical resources in optimizing our drilling economics in the Permian Basin, and the results have been excellent. Our Midland Basin well productivity has moved up into the top quartile producers as measured by third-party analysts, and we continue to improve Delaware Basin productivity measures each year. The Cowan acquisition we announced in early January will bring scale to our Delaware position and balance to our overall Permian asset base, making it fairly evenly weighted between the Midland and the Delaware upon closing. While Cowan has experienced operational and productivity challenges in the past, more recently they have begun to make good progress towards demonstrating the upside potential of their acreage. By leveraging APA's technical capabilities and work processes across the Cowan acreage, We expect to further build on their progress, most notably in the areas of capital productivity from well spacing, target zone selection, frac design, and drilling completion and infrastructure efficiencies. When we first announced the acquisition, we assigned only $55 million to operational synergies and improvements. However, we are confident that there is substantial upside to this number. While the transaction is accretive on cost synergies alone, The big win-win for shareholders of both companies will be the integration of the assets into a larger Permian platform and the technical optimization, capital allocation, process knowledge, and discipline that APA brings to the table. We look forward to updating our 2024 U.S. guidance upon completion of the transaction. In closing, we are managing the business with a clear and consistent strategy, adhering to our discipline and and delivering on our commitments and financial objectives. In the last three years, we have reduced outstanding bond debt by $3.2 billion and repurchased $2.6 billion or 20% of our shares outstanding. Our Permian Basin and Egypt operations are delivering a high level of free cash flow along with moderate oil growth in aggregate. We have progressed a large scale exploration and appraisal program in Suriname to feed study And we believe this will drive high-margin oil production beginning in the 2028 timeframe. And more recently, we have further expanded our exploration portfolio with large-scale opportunities in Alaska and offshore Uruguay. While the industry may experience some near-term commodity price weakness, we maintain a constructive medium and long-term outlook. Accordingly, we will continue to invest a measured amount of capital into differential, longer-term exploration opportunities. And lastly, we remain fully committed to returning at least 60% of our free cash flow to shareholders through our base dividend and share buybacks. And with that, I will turn the call over to Steve Reine.

Thank you, John, and good morning. For the fourth quarter, under generally accepted accounting principles, APA reported consolidated net income of $1.8 billion, or $5.78 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $1.6 billion increase in net income related to the partial release of the valuation allowance on our deferred tax asset. This was offset by a $167 million after-tax increase in the estimated net remaining decommissioning obligation for the old fieldwood assets in the Gulf of Mexico. Excluding these and other smaller items, adjusted net income for the fourth quarter was $352 million, or $1.15 per share. Free cash flow was $292 million in the quarter. Through dividends and share repurchases, we returned 68% of this amount to shareholders during the quarter. And as John noted, for the full year, we returned 66% of free cash flow. Please refer to APA's published definition of free cash flow for any reconciliation needs. G&A expense for the quarter was $75 million. This was significantly below guidance, mostly due to the decrease in the APA share price and the mark-to-market impact on previously accrued share-based compensation. In the fourth quarter, our Chenier gas sales contract contributed free cash flow and pre-tax net income of $74 million, which was below guidance as LNG margins over Houston Ship Channel narrowed through the quarter. Turning to 2024, John already discussed our capital and production guidance, so I will just touch on a few other items of note. Based on recent strip prices, we currently anticipate our Chenier contract will contribute cash flow of about $100 million for the full year, and third party marketing income related to our gas transport obligations will be roughly break even. In the Gulf of Mexico, our remaining field wood related decommissioning exposure is now $815 million. This is net of remaining security and anticipated future cash flows from the producing properties. These decommissioning costs are estimated to be incurred over the next 10 to 15 years, and in 2024 will amount to around $60 million. Finally, we are preparing for the closing of the Cal-In acquisition with a joint integration team working through plans for day one and beyond. John already indicated our confidence in meeting or exceeding our $55 million goal for annual operational synergies. We are equally focused on the transition of GNA activities and the refinancing of the common debt. At this time, we still expect the sum of the GNA and financing synergies will meet or exceed our goal of $95 million on an annualized basis. A majority of the GNA synergies are expected to be realized on a run rate basis shortly after closing with a small portion requiring a transition period which may take up to a few months. The financing synergies will be realized within a few days of closing with the refinancing of the Calend debt planned and ready to be put into effect. We noted at the time of the acquisition announcement that the assumption of Calend's debt would increase our leverage metrics slightly. This has had no adverse impact on our discussions with the rating agencies, nor on their published outlooks. We continue to target a triple B rating or the equivalent thereof with all three agencies. For this reason, we remain focused on further debt reduction, which will be achieved through the application of cash flow and possible asset divestments. And with that, I will turn the call over to the operator for Q&A.

Thank you. As a reminder, to ask a question, please press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. In the interest of time, we ask that you please limit yourself to one question and one follow-up. Please stand by while we compile the Q&A roster.

Our first question comes from Doug Luggett with Bank of America.

Your line's now open.

Thank you. John, good morning. And Steve, it's always interesting to hear how the operator tackles it, but I'll take that. Good morning, Doug. Good morning, John. Egypt, it sounds like you've identified the issue. Can you give us some idea as to what the point forwards resolution is then? When can you anticipate that? I mean, ESPs should be, it sounds like a really simple issue to solve, but now you've identified it, I mean, why would you not get back on a growth trajectory once this is resolved? I guess that's what I'm really trying to figure out. What do you see as the go-forward outlook? Pick your timeline, three-year, five-year, whatever, and when do you anticipate this turning around?

Yeah, Doug, I'd first start off and say the ESPs was kind of a second factor and kind of piled on. The underlying factor is just the ratio of the workover rigs to the drilling rigs. And these aren't just normal pulling units. These are, you know, good-sized workover rigs. And if you go back historically, we've usually run close to 2 to 3X the workover rigs to the drilling rig count. You know, as we've said, we use these workover rigs to complete new wells. to perform the re-completions and do the workovers. And our ratio really has been just slightly over one. And so, you know, we're ratcheting back, kind of gearing down the rig program. We're still going to run 13 to 15 rigs, so it's not a major reduction. But we want to get the workover count, you know, worked down. We've got a very large asset base there. And it's important that we're getting to the key workovers and the re-completions that underpin those decline rates. You know, there's no reason to keep drilling more wells quicker and piling more ducts into the system right now. It's just not the most efficient use of capital, you know, given the work over rigs. On the sub pumps, you're exactly right. These were the high rate sub pumps that we needed as we brought on, you know, nine big wells last year. There was a problem with the manufacturing. We've identified that and we are in the process of fixing that. So that will get straightened out and is being addressed right now. But it's really more a function of trying to balance the work over rigs and the number of wells we're drilling with the drilling rigs on a go forward basis to kind of get into equilibrium to make sure we're investing the capital wisely and efficiently. and getting the most out of it. So once we work that down, I mean, I'd say today we estimate we've got close to 13,000 barrels a day that's offline that needs to be worked over. We usually run around 5,000 barrels a day, so there's about 8,000 barrels a day there we need to work down, and it's going to take a number of workovers and projects to do that. So we're on it. I think once we get into a good equilibrium point, then we can revisit the rig count at a later date.

And on the medium-term production outlook, can you touch on that?

We're just going to guide the flat, you know, adjusted production, net production for Egypt for now.

Okay, we'll watch that. Gosh, I'm kind of torn as to where to go. I wanted to ask about Callan, but, you know, I don't imagine we're going to get much more from that today. So I would like to ask Tracy maybe about the exploration program. You know, we only have to look back at some of your peers on what exploration did for their portfolios. And it seems to us exploration never gets a look until you've got something to show for it. So characterize for me, please, how you see the risk profile. Alaska specifically, I believe, is near field exploration. You're going to have three wells this quarter, I guess. So I'm assuming you're already halfway through those wells. What are you seeing currently? How would you characterize the risk profile of your backlog?

Yeah, I mean, I'll step in just a few things on Alaska, you know, Doug, and then I'll hand it over to, you know, to Tracy. But, you know, one, it's large, underexplored area. You know, as we put in the supplement today, it's 275,000 acres on state lands. It is highly prospective for what's become a proven play. And Tracy can get into some details and, you know, into that in a minute. We are planning to drill three wells this winter. We are very close to sputting the first well.

So we're not halfway through any of them at this point, but you know, it's it's going to get fun here pretty fast So Tracy, I'll let you talk a little bit more about the program Sure, I'll carry on from what John has mentioned about the exploration program first and then just give a couple of comments I think on your initial question around a little more insight onto the program I guess John said that in Alaska It's a position that sits between Prudhoe Bay and ANWR in the Brookine play. So we've entered into an area where we have analogs there that have worked but are looking and exploring in an area where that particular play has not really been explored for. So we're testing in a region where play has worked in an underexplored region. As you said, we're drilling three wells this season. All of those will spud in Q1. and we'll come back with an update on that once we've completed this season's drilling program. I think in terms of just the portfolio, if you look, we talk a lot about play diversification and portfolio diversification, and I think what you're seeing us build is optionality both in risk with some areas that are more proven, with some areas that are going to be more exploration-based like the Uruguay licenses that we entered last year. So what we're really seeking to do is build a portfolio that will give us play diversity, you know, both in types of plays, onshore, offshore, and with risk. through time, both in near-term optionality like we're seeing in Alaska and longer-term optionality like we're seeing in Uruguay. So more to come on Alaska in the near term later this year.

And Doug, one more thing on your first question. We're limited in Egypt with the number of work over rigs that are in-country. So you're not in the U.S. where you can just go pick up work over rigs and pulling units. You know, we're dealing with a constrained resource there, and so we have to kind of gear around that at this point.

Thank you. One moment for our next question. Our next question comes from Neil Dingman with True Securities. Your line is now open.

Neil, your line's open.

Please check your mute button.

Hello, can you hear me? Yes. Okay, I did. My first question is also on Egypt. Specifically, while I understand, you know, definitely discussed and understand the need for the activity change in the region, John, can you speak a little bit about what you're seeing on the recent well-performance and productivity there versus last year? It seems to still be quite good. We'd love to hear more color on that.

Yes, Neil, the 22 or the 23 program really performed in line as expected. So the new wells were good. We even had, you know, some, what I'll call some really high success in the Berenice area where we had the potential to bring on some high impact wells. We just ran into some challenges on the ESP. So program has been good and the new well program is, you know, is in line. It's all about getting the balance together and just ratcheting back a little bit until we can go faster at a later date.

No, that makes sense. And then a second question just on the permit. I appreciate still not having yet the pro forma calendar. I was wondering, are you able to say anything about just sort of broader decisions if you just simply add the D&C of your activity with theirs? I'm just wondering, maybe it's too early for that. I'm wondering if it is too early for that. Could you maybe instead just talk about the cadence, how we should think about the existing activity there this year?

Yeah, I mean, as we sit today, we're limited on the company-to-company interaction we have. Both companies have integration teams that are set up on the transition side, and so we're working through that. And as you clear certain hurdles, we can start to interact more. But at this point, we're working towards having a very smooth closing and transition. And we really believe that should take place sometime in the second quarter. When you look at our operations, you know, we'll be running six rigs Permian this year. They're running five. And, you know, we'll start out with those 11 rigs. And we're very comfortable, you know, running those 11 rigs and really look forward to being able to integrate the Callen assets into our workflow and our schedules and so forth. But that's going to take a little bit of time. So... As you know, we've been delivering outstanding results, and we're anxious to jump on their Delaware assets in addition to what we're doing in the Delaware and our Midland Basin.

Thank you. One moment for our next question. Our next question comes from Bob Brackett with Bernstein Research. Your line is now open. Bob, your line is open.

I think that's for Bob Brackett.

Yes, Bob. You're good to go.

Excellent. Following up with Alaska, kind of a two-part question around setting expectations of what you're trying to do with this program and when you might be finished. In terms of what you're trying to do, it looks like this is a stratigraphic test more than anything and maybe a VSP to get some seismic control. And it looks like you guys have to kind of be done and off the ice end of April, and therefore you might have some results by then. Is that fair?

Yeah, Doug, as you know, you're limited on the winter window. And, you know, we are getting ready to get started with the first well. And we'll actually have, you know, three rigs, you know, drilling kind of simultaneously pretty quickly. So we do anticipate being able to get three wells down, you know, prior to breakup.

And these are stratigraphic tests? Yes. Yes.

Tracy could say a few words, but you've got good seismic control and they're fully supported. We feel good about them, but it is exploration.

Great. Thanks. Thank you. One moment for our next question.

Our next question comes from Charles Mead with Johnson Rice. Your line is now open.

Good morning, John, to you, Steve, Tracy, and the rest of the APA team there. John, my first question, I want to pick up right where you kind of left off, I think, on one of the first questions about Egypt, saying that more work over rigs is not an option, that you're limited there. Is there a time frame for that? In other words, I understand you might not be able to get one in three months, but maybe in 12 months you could get a couple more work over rigs. So is that a possibility? And then the other aspect of that is, you know, you look at trying to de-bottleneck your system. Is there a possibility that you could bring in some wire line or coil tubing to offload some of the work items on your work over rigs?

Charles, I'd just say, first of all, short term, there's not any real options. And obviously, there are several avenues and things we've explored and been exploring. But getting equipment into a country like Egypt takes time. And so at this point, we don't have any real near term options. And it's something we'd be happy to talk about later if we find a solution. But Right now, we're limited to the 20 work over rigs that we currently have.

Got it. Got it. Appreciate it. And then back to Alaska. I saw, I read that one of your partners there referred to the prospects that you're going to test as PICA lookalikes, and PICA being the Santos development that went FID in 22. So I guess I'm I'm curious, would you agree with that characterization? And for those of us who are just coming up to speed and learning about this, can you offer some details on what, if you agree that the prospects are PICA lookalikes, what that means?

Sure, Tracy. Thanks, Charles. I'll weigh in on that one. Yes, I would agree with that. We're really looking at more play types like Pika and Willow versus Prudhoe Bay, and we're exploring that, and that is part of the Brookian play that we're exploring it for, but we're going to be exploring for it in a younger sequence, but it's absolutely sort of the same geologic model and setup that we expect to see basically just a bit further east than it's been explored for on the other side of Prudhoe Bay. So we would agree with that.

Thank you. One moment for our next question.

Our next question comes from Paul Cheng with Scotiabank. Your line is now open.

Hi, good morning. John and Tracy, I have to apologize first. If we can go back to Alaska, let's assume the program is successful. What's the next step and what kind of infrastructure do you need to put on in order for that to be able to grow? And what is the timeline on that?

Yeah, first of all, Paul, thanks for the question. Yeah, I'll just say we're in the expiration phase at this point. So, you know, we've done a lot of scoping. You know, it's onshore, it's state land, so things can move a little quicker than federal there. You know, you're close to a big pipeline capacity, but, you know, let's work through the expiration phase, you know, see what we find, and then go from there at a later date. So, but we're excited about it.

But can you maybe just share that what type of infrastructure will be needed if it is successful?

Well, a lot of that will hinge on these are three separate tests of similar play concepts. And a lot of that would just hinge on, you know, what we found. So, you know, at this point, we're purely in an expiration phase. And, you know, we'll just have to come back and give you some characterization, you know, if we have the success there that we hope we have.

I see. On EEJ, I'm just curious that, John, is the work over availability issue just happened, something happened in the country and that what used to be available no longer available or that your need for the work over rate have just increased substantially last year. And if that's the case, then is that something that's happening in the rest of us that led to that?

Yeah, I would just say historically, you know, we were running, if you go back to pre-modernization, we were running five drilling rigs and 12 work over rigs. We took the rig count up more than 3x to 15 to 18, and we were only able to take the work over rig count up to 20, so we could only double that when we tripled the drilling set. Initially, it wasn't a major problem because we were trying to get the efficiencies lined out on the drilling side, but as we got the efficiencies lined out on the drilling side, You know, the work-over rigs then are required to complete the drilling wells, and, you know, ultimately we've got to make sure we're managing the base. So it's just a new phenomenon, and it's something that ultimately, longer term, we're going to need more work-over equipment in-country, and there's just not a good short-term fix to that.

Thank you. One moment for our next question. Our next question comes from Neil Mehta with Goldman Sachs. Your line's now open.

Good morning, John and team. First question I had was just on Suriname. Maybe you could step back, John, and big picture talk about where we stand here. And we know we've got that FEED study that you're working through and you're targeting in FID in 2024. But what are you focused on as it relates to Suriname and any updates as it relates to that project?

Now, Neil, first of all, thanks for the question. Secondly, that's exactly where we sit today. We're working with Total. They're in feed study. We've kind of laid a timeline out there that we anticipate an FID before year end, 24, which is this year, which is great news. And then as of right now, we would say first oil in 28. But I can tell you, our partner and us are working hard to try to accelerate those timelines. But the you know, that's where we are at this point. So we remain excited. We do see additional exploration potential in Block 58. Right now, we've kind of got most of the attention on the, you know, moving the first development project forward.

Thanks, John. And then the follow-up, we haven't really talked in Q&A about the U.S. production profile over the course of the year. Just maybe talk about Your Permian plans, it sounds like it's going to be a little bit back half-weighted with strong growth exit to exit. So just any thoughts on Permian oil and navigating the weakness, obviously, in local gas prices there, too?

You know, Neil, we've had a number, a good run of years of really outperformance in the Permian. And, you know, when you're running five to six rigs, which is what we've done, then it becomes very pad-dominated in terms of your timing and your sequences. And yes, we don't have a number of, you know, very many wells coming on early this year. Things are kind of second and third quarter back, you know, weighted with the way the schedule works. And so you'll see strong Permian growth on the oil side. You know, we're anticipating up 10%, you know, Q4 24 over 23. And that's going to, you know, more than offset the decline in the North Sea. So, you know, continues to be the under, you know, underpin our backbone and, you know, We're going to continue to lean on Permian.

Thank you. One moment for our next question. Our next question comes from Arun Jayram with JPMorgan Securities.

Your line is now open.

Good morning, gentlemen. I wanted to first see if you could talk about the payment situation in Egypt. We did see an improvement in the working capital situation in the quarter. But Steve, maybe you could provide an update on where you stand in terms of AR and how the collection trends have been with the Egyptian government.

Yeah, Arun. As you know, we've talked about this a number of times every quarter. We have a We have a very active and constructive working relationship with Egypt, but it does require that ongoing conversation and work of the issue. Fourth quarter, we ended fourth quarter with our lowest quarter end past due receivables for the year from EGPC. And so we continue to make progress. They've come down through the year. They kind of peaked. in early second quarter today we're about 25 to 30 percent below where we were at that peak level so they're still elevated pasty receivables still elevated from egpc but they're they're lower and trending in the right direction have been pretty much through the whole year great to hear and see my follow-up is i wanted to go to if you could go to slide 30 in the deck and just talk about

I want to understand a little bit more about the abandonment costs impacted to cash flow. Your costs incurred for the year were $979 million. Your total upstream capital is $520. Most of the delta is just the ARO. So in 4Q, did you all have an outflow for that $347 million for ARO? And is $60 million... what you mentioned in 2024, maybe a good run rate for the next several years?

So you're talking about the ARO for Fieldwood? Yes, sir. Okay, so that does not go through the capital program there. There's a book liability on the decommissioning obligation there.

And so it doesn't go through the capital program. It doesn't show up as capital expenditure.

Right, but I'm looking at the cost incurred, which were $979 million in the quarter. Were there any outflows associated, or maybe you could quantify the magnitude of outflows with ARO in 2023?

Yeah, maybe we could just take that offline instead of reconciling through the group here. I'll work with Gary to get back in touch with you. We can work through. I just want to make sure we understand the question.

Okay, fair enough. Thanks, Steve.

Thank you. One moment for our next question. Our next question comes from Leo Mariani with Ross MKM.

Your line's now open.

I just wanted to kind of get back to the exploration discussion here. Just wanted to see if you guys could provide a little bit more color on kind of the risk profile in Alaska. I mean, do you see these wells as kind of One in two shots, you know, kind of one in five, just anything you could do to quantify some of the risk profile would be helpful. And then on just block 53 in CERNAM, looks like you relinquished most of that block. Just any update on the thinking there?

Yeah, Leo, I'll jump to CERNAM first. I think, you know, we've been pretty clear that, you know, we see more expiration upside remaining in block 58 versus block 53. And so, you know, it was an easy answer to go ahead and let 53 go. You know, when you look at the risk profile on Alaska, you know, these are 3D and amplitude supported. But you're going to be, this is a step out in an area where there's risk associated with it. So, you know, I'm not going to give you a number on a ratio, but it is exploration. You know, we're taking, you know, we're going to drill three wells today. And they are risky, but they're high reward. So, and I don't know, Tracy, anything you want to add to that?

Yeah, I'll just comment, I think, a little on both pieces, which is, you know, the Block 53 exit. You know, I think we saw, we mentioned on the previous call that, you know, we really saw the prospectivity in Block 58 as being more perspective than what we saw in Block 53. So, you know, what you're seeing with that exit really is the strategic portfolio management and continuous high grading of the portfolio. where we saw more prospectivity both in Block 58 and in other opportunities that we had in front of us. And I would just echo what John said on Alaska. You know, we have a range because these are exploration prospects that have risk associated with them. But clearly what, you know, interested us in the block is that we do see materiality with these prospects that we thought warranted exploration.

Okay, that's helpful. And I just wanted to follow up on some of the comments that you guys made here. I just wanted to make sure I understood this. Did I hear a comment that APA might be adjusting its headcount a little bit downward in response to some of the lower activity levels? I know clearly that once you guys integrate Cal, and I'm sure you'll have to take a fresh look at the whole organization, but did I hear that right, that perhaps you think that maybe you might cut some of the APA headcount here at some point?

I mean, I'll just say, you know, we're always, you know, looking to right-size organization with activity levels. I think the comment in the prepared remarks was if we find ourselves in a much lower price environment, you know, we're always willing to reduce activity and associated staff if we need to do so. But we have gone through an exercise in the North Sea as we're kind of right-sizing for late life. And so we have, you know, gone through some steps there. but we're quite frankly very excited about integrating the Calen assets and, you know, pulling those into the organization. We do see some synergies there, but, you know, activity levels are still going to be strong and relatively close to where we were last year.

Thank you. I'm showing no further questions at this time. I would now like to turn it back to John Chrisman, CEO, for closing remarks.

Yeah, thank you. We have chosen to reduce our capital this year and maintain roughly flat production, given the potential for a lower commodity price environment while still funding our strategic initiatives. We have intentionally directed more capital towards the Permian, which is performing at an extremely high level. And we look forward to integrating the Callen assets into our Permian operations as well. And lastly, we will keep you up to date on our progress in Suriname and our other exploration plays.

Thank you, operator.

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