APA Corporation (NASDAQ:APA) Q4 2023 Earnings Call Transcript

APA Corporation (NASDAQ:APA) Q4 2023 Earnings Call Transcript February 22, 2024

APA Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, and thank you for standing by. Welcome to the APA Corporation’s Fourth Quarter and Full Year 2023 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, Gary Clark, Vice President, Investor Relations. Please go ahead.

Gary Clark: 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 Christmann. 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 Pursell, Executive Vice President of Development; Tracey Henderson, Executive Vice President of Exploration; and Clay Bretches, 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 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.

Also, please note that the forward guidance we provided with our fourth quarter results reflects our outlook for APA Corporation on a stand-alone basis only and does not incorporate pro forma effects of the pending Callon Petroleum acquisition. And with that, I will turn the call over to John.

John Christmann: 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 long-standing 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 such as Callon.

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 5-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 Beryl Alpha and Forties 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 workover rigs for completing many of our new drill wells. With the increased size and improving efficiency of our drilling program, the demand for workover rigs to complete new wells has exceeded expectations. This meant the workover rigs were doing fewer recompletions than planned and our workover 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 9 new wells impacted by early ESP failures, 2 of which occurred in the fourth quarter on high-volume wells. We have traced this problem to 1 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 workover rig capacity to reduce the workover and recompletion 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 U.S., 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 U.S. 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 second 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 Callon 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 Callon 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 Callon 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 Callon 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 delivering on our commitments and financial objectives. In the last 3 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 time frame. 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 in the 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 Riney.

Stephen Riney: 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 Cheniere gas sales contract contributed free cash flow and pretax 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 Cheniere 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 breakeven. In the Gulf of Mexico, our remaining Fieldwood-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 Callon acquisition, with a joint integration team working through plans for day 1 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 G&A activities and the refinancing of the Callon debt. At this time, we still expect the sum of the G&A and financing synergies will meet or exceed our goal of $95 million on an annualized basis. A majority of the G&A 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 Callon debt planned and ready to be put into effect. We noted at the time of the acquisition announcement that the assumption of Callon’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 BBB rating or the equivalent thereof with all 3 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.

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Q&A Session

Operator: [Operator Instructions]. Our first question comes from Doug Leggate with Bank of America.

Doug Leggate: Thank you. John, good morning, and Steve, it’s always interesting to hear how the operator tackles it, but I’ll take that. Egypt, it sounds like you’ve identified the issue. Can you give us some idea as to what the point forward resolution is then? When can you anticipate that? I mean, ESPs should be — sounds like a really simple issue to solve. 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? Take your time line, 3-year, 5-year, whatever, and when do you anticipate this turning around?

John Christmann: Yes, Doug, I’ll first start off and say the ESPs was kind of the 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 good sized workover rigs. And if you go back historically, we’ve usually run close to 2x to 3x, the workover rigs to the drilling rig count. As we’ve said, we use these workover rigs to complete new wells, to perform the recompletions and do the workovers. And our ratio really has been just slightly over 1. And so 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 work down.

We’ve got a very large asset base there, and it’s important that we’re getting to the key workovers and the recompletions that underpin those decline rates. And so there’s no reason to keep drilling more wells quicker and piling more ducks into the system right now, it’s just not the most efficient use of capital given the workover rigs. On the sub pumps, you’re exactly right. These were the high rate sub pumps that we needed as we brought on 9 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 workover 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.

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

John Christmann: We’re just going to guide to flat adjusted production, net production for Egypt for now.

Doug Leggate: Okay. We’ll watch that. Gosh, I’m kind of torn as to where to go. I wanted to ask about Callon, but I don’t imagine we’re going to get much more from that today. So I would like to ask Tracey maybe about the exploration program. 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 outlook until you’ve got something to show for it. So characterized for me, please, how you see the risk profile? Alaska specifically, I believe, is near field exploration, you’re going to have 3 wells this quarter, I guess. So what — I’m assuming you’re already halfway through those wells. What are you seeing currently? How would you characterize the risk profile of your [indiscernible]?

John Christmann: Yes. I mean I’ll stop in, just a few things on Alaska, Doug, and then I’ll hand it over to Tracey. But one, it’s a large, underexplored area. 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 Tracey can get into some details into that in a minute. We are planning to drill 3 wells this winter. We are very close to spudding the first well. So we’re not halfway through any of them at this point, but it’s going to get fun here pretty fast. So Tracey, I’ll let you talk a little bit more about the program.

Tracey Henderson: 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 think as John said, in Alaska, it’s a position that sits between Prudhoe Bay and ANWR in the Brookian plays. 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 under-explored region. As you said, we’re drilling 3 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 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.

John Christmann: And Doug, 1 more thing on your first question. We’re limited in Egypt with the number of workover rigs that are in-country. So you’re not in the U.S. where you can just go pick up workover rigs and pull in units. We’re dealing with a constrained resource there. And so we have to kind of gear around that at this point.

Operator: Our next question comes from Neal Dingmann with Truist Securities. Neal, your line is open. Please check your mute button.

Neal Dingmann: Hello. Can you hear me?

John Christmann: Yes.

Neal Dingmann: My first question is also on Egypt. Specifically, I want to understand — definitely discuss and understand the need for the activity change in the region. John, can you just 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. I would love to hear more color on that.

John Christmann: Yes, Neal, the ’23 program really performed in line as expected. So the new wells were good. We even had some — what I’ll call some really high success in the Barnes 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 in line. So it’s all about getting the balance together and just ratcheting back a little bit until we can go faster at a later date.

Neal Dingmann: No, that makes sense. And then the second question just on the Permian. While I appreciate still not having yet the pro forma Callon guidance, 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? Or I’m just wondering, maybe it’s too early for that. And 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?

John Christmann: Yes. I mean as we sit today, we’re limited on the company, the company interaction we have. We — 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, we’ll be running 6 rigs Permian this year. They’re running 5, and we’ll start out with those 11 rigs, and we’re very comfortable running those 11 rigs and really look forward to being able to integrate the Callon 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.

Operator: Our next question comes from Bob Brackett with Bernstein Research.

Robert Brackett: All right. I think that’s for Bob Brackett?

John Christmann: Yes, Bob, you’re good to go.

Robert Brackett: Excellent. Following up with Alaska, kind of a 2-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?

John Christmann: Yes, Bob, as you know, you’re limited on the winter window, and we are getting ready to get started with the first well. And we’ll actually have 3 rigs drilling kind of simultaneously pretty quickly. So we do anticipate being able to get 3 wells down prior to breakup.

Robert Brackett: And these are stratigraphic tests?

John Christmann: Yes. You’ve got — I mean, Tracey can say a few words, but you’ve got good seismic control. And they’re fully supported. So we feel good about them, but it is exploration.

Operator: Our next question comes from Charles Meade with Johnson Rice.

Charles Meade: John, to you, Steve, Tracey 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 1 of the first questions about Egypt saying that more workover rigs was not — is not an option that you’re limited there. Is that a — is there a time frame for that? In other words, I understand you might not be able to get 1 in 3 months. But maybe in 12 months, you could get a couple more workover rigs. So is that a possibility? And then the other aspect of that is — you look at try to debottleneck your system, is there a possibility that you could bring in some wireline or coiled tubing to offload some of the work items on your workover rigs?

John Christmann: Charles, I’d just say, first of all, short term, there’s not any real options. And obviously, the — 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 just — we’re limited to the 20 workover rigs that we currently have.

Charles Meade: Got it. Got it. I appreciate it. And then back to Alaska. I saw — I read that 1 of your partners there referred to the prospects that you’re going to test as Pika lookalikes. And Pika 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, is a Pika — that the prospects are Pika lookalikes? What that means?

Tracey Henderson: Sure. Tracey. 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.

Operator: Our next question comes from Paul Cheng with Scotiabank.

Paul Cheng: John and Tracey, happy 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 you need to put on in order for that to be able to grow? And what is the time line on that?

John Christmann: Yes. First of all, Paul, thanks for the question. I’ll just say we’re in the exploration phase at this point. So we’ve done a lot of scoping. It’s onshore, it’s state land, so things can move a little quicker than federal there. You’re close to big pipeline capacity. But let’s work through the exploration phase, see what we find and then go from there at a later date. So — but we’re excited about it.

Paul Cheng: But can you maybe share that — what type of infrastructure we’ve been needing if it is successful?

John Christmann: Well, a lot of that will hinge on, these are 3 separate tests of similar play concepts. And a lot of that would just hinge on what we found. So at this point, we’re purely in an exploration phase. And we’ll just have to come back and give you some characterization if we have the success there that we hope we have.

Paul Cheng: I see. On Egypt, I just curious that, John, is the workover availability issue just happen, something happened in the country and that what used to be available no longer available? Or that your own need for the workover rig have just increased substantially last year? And if that’s the case then, is that something that’s happening in the rest of that, that led to that?

John Christmann: Yes. I would just say, historically, we were running — if you go back to pre-modernization, we are running 5 drilling rigs and 12 workover rigs. We took the rig count up more than 3x to 15 to 18, and we were only able to take the workover rig count up to 20. So we could only double that when we tripled the drilling set. And — so 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, the workover rigs they were required to complete the drilling wells. And ultimately, we’ve got to make sure we’re managing the base. So it’s just — it’s a new phenomenon. And it’s something that ultimately longer term, we’re going to need more workover equipment in country. And there’s just not a good short-term fix to that.

Operator: Our next question comes from Neil Mehta with Goldman Sachs.

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

John Christmann: 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 time line 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 time lines. But that’s where we are at this point. So we remain excited. We do see additional exploration potential in Block 58. But right now, we’ve kind of got most of the attention on the move in the first development project forward.

Neil Mehta: 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.

John Christmann: Neil, we’ve had a number a good run of years of really outperformance in the Permian. And when you’re running 5 to 6 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 — very many wells coming on early this year. Things are kind of second and third quarter back weighted with the way the schedule works. And so you’ll see strong Permian growth on the oil side. We’re anticipating up 10%, Q4 ’24 over ’23. And that’s going to more than offset the decline in the North Sea. So continues to be underpin our backbone, and we’re going to continue to lean on Permian.

Operator: [Operator Instructions]. Our next question comes from Arun Jayaram with JPMorgan Securities.

Arun Jayaram: 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 ARO and how the collection trends have been with the Egyptian government?

Stephen Riney: Yes, Arun, as you know, we’ve talked about this a number of times since every quarter. 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% below where we were at that peak level. So they’re still elevated, past due receivables still elevated from EGPC, but they’re lower and trending in the right direction, have been pretty much through the whole year.

Arun Jayaram: Great to hear. And Steve, my follow-up is I wanted to go — 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 cost impact to cash flow. Your costs incurred for the year were $979 million. Your total upstream capital is $520 million. Most of the delta is to ARO. So in 4Q, did you all have an outflow for that, call it, $347 million for ARO? And is $60 million, what you mentioned in 2024, maybe a good run rate for the next several years?

Stephen Riney: So you’re talking about the ARO for Fieldwood?

Arun Jayaram: Yes, sir. Slightly…

Stephen Riney: So that does not go through the capital program there. It’s — there’s a booked liability on the decommissioning obligation there. And so it doesn’t go through the capital program, that doesn’t show up as capital expenditure.

Arun Jayaram: Right. So — but I’m looking at the costs 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?

Stephen Riney: Yes. Can we — 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.

Arun Jayaram: Okay. Fair enough. Thanks, Steve.

Operator: [Operator Instructions]. Our next question comes from Leo Mariani with ROTH MKM.

Leo Mariani: 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 1 in 2 shots, kind of 1 in 5? Just anything you could do to quantify some of the risk profile would be helpful. And then on just Block 53 in Suriname, it looks like you relinquished most of that block. Just any update on the thinking there.

John Christmann: Yes, Leo, I’ll jump to Suriname first. I think we’ve been pretty clear that we see more exploration upside remaining in Block 58 versus Block 53. And so it was an easy answer to go ahead and let 53 go. When you look at the risk profile on Alaska, 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 I’m not going to give you a number on a ratio, but it is exploration. We’re taking — we’re going to drill 3 wells. And they are risky, but they’re high reward. So — and I don’t know, Tracey, anything you want to add to that?