Good day, and thank you for standing by. Welcome to the APA Corporation's Fourth Quarter and Full Year 2023 Results Conference Call. 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 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.

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 have now 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. 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 to 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 December. 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 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 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's 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. 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 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 timeframe. 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. 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.

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 the 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.

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

Thank you. John, good morning, and Steve, it's always insightful to hear how the operator approaches it, but I'll address that. Egypt, it seems you've pinpointed the issue. Can you provide us with an idea of what the resolution looks like moving forward? When do you expect this to happen? It appears that ESPs should be a relatively straightforward issue to resolve now that it's been identified. I'm curious as to why you wouldn't expect to return to a growth path once this is addressed. What do you envision as the outlook from here? Take your timeline, whether it's three years, five years, or so, and when do you foresee a turnaround?

Yes, Doug, I'll first start off and say the ESPs were 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. These aren't just normal pulling units. These are good-sized workover rigs. 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, perform the recompletions, and do the workovers. Our ratio really has been just slightly over 1. 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 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 recompletions that underpin those decline rates. 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 are in the process of fixing that. It's really more a function of trying to balance the workover rigs and the number of wells we're drilling to kind of get into equilibrium to ensure we're investing the capital wisely and efficiently. 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. We're on it. I think once we get into a good equilibrium point, 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 to flat adjusted production, net production for Egypt for now.

Okay, we'll keep an eye on that. I'm a bit uncertain about where to start. I wanted to inquire about Callon, but I don't expect we'll have much more to discuss on that today. Instead, I'd like to ask Tracey about the exploration program. Looking at some of your industry peers, it's clear that exploration can significantly impact their portfolios. It seems that exploration doesn't get much attention until there are results to present. Could you describe how you view the risk profile? Specifically regarding Alaska, I understand it's near field exploration, and you're set to drill three wells this quarter. Assuming you're already partway through those wells, what are your current observations? How would you describe the risk profile of your exploration efforts?

Yes. I mean I'll stop in, just a few things on Alaska, Doug, and then I'll hand it over to Tracey. 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 has become a proven play. 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.

Sure, I'll continue from what John has said about the exploration program. To provide some additional comments regarding your initial question about gaining more insight into the program, as John mentioned, in Alaska, we are situated between Prudhoe Bay and ANWR in the Brookian plays. We have entered an area where we have successful analogs but are exploring a region that hasn't been thoroughly examined. We're testing in an area where the play has been effective but remains underexplored. As you noted, we are drilling three wells this season, all of which will begin in the first quarter, and we will provide an update once this season's drilling program is completed. In terms of our portfolio, we frequently discuss play and portfolio diversification. What we are developing is optionality in terms of risk, with some areas being more established and others more exploration-driven, such as the Uruguay licenses we entered last year. Our goal is to create a portfolio that offers play diversity across different types of plays, both onshore and offshore, and risk over time, featuring both near-term options like those in Alaska and longer-term possibilities like those in Uruguay. More updates will follow regarding Alaska later this year.

And Doug, one 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. We have to kind of gear around that at this point.

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

Hello. Can you hear me?

Yes.

My first question is on Egypt. I want to understand the need for the activity change in the region. John, can you speak about what you're seeing regarding recent well performance and productivity there compared to last year? It seems to still be quite good, and I would love to hear more about it.

Yes, Neal, the 2023 program performed as expected. The new wells have shown good results, especially in the Barnes area, where we were able to bring on some impactful wells. We did encounter some challenges with the ESP. Overall, the program has been successful, and the new well program is aligned with our goals. It’s important for us to find the right balance and adjust our pace slightly for now so we can accelerate later on.

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. 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?

Yes. As we sit today, we're limited on the company interaction we have. Both companies have integration teams that are set up on the transition side, and so we're working through that. 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. We really believe that should take place sometime in the second quarter. When you look at our operations, we'll be running 6 rigs in the Permian this year. They're running 5, and we'll start out with those 11 rigs, and we're very comfortable running those 11 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. We're 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.

Our next question comes from Bob Brackett with Bernstein Research.

All right. I think that's for Bob Brackett?

Yes, Bob, you're good to go.

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?

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

And these are stratigraphic tests?

Yes. You've got good seismic control. And they're fully supported. We feel good about them, but it is exploration.

Our next question comes from Charles Meade with Johnson Rice.

John, I want to follow up on what you mentioned about Egypt, specifically regarding the use of additional workover rigs. Is there a potential timeline for acquiring more rigs? I understand that getting one in the next three months might not be feasible, but could you possibly add a couple in the next year? Additionally, as you work on optimizing your system, could you consider bringing in some wireline or coiled tubing to help manage the workload on your workover rigs?

Charles, I'd just say, first of all, short term, there's not any real options. 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. Right now, we're just limited to the 20 workover rigs that we currently have.

I understand. Thank you. Now, regarding Alaska, I noticed that one of your partners referred to the prospects you plan to test as similar to Pika, which is the Santos development that reached FID in 2022. I'm curious if you agree with that description. For those of us who are new to this, could you provide some details on what it means for the prospects to be similar to Pika?

Sure. Tracey. Thanks, Charles. I would agree with that. We're really looking at more play types like Pika and Willow versus Prudhoe Bay. We're exploring that, and that is part of the Brookian play that we're exploring. 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 just a bit further east than it's been explored for on the other side of Prudhoe Bay. So we would agree with that.

Our next question comes from Paul Cheng with Scotiabank.

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 do you need to put in order for that to grow? And what is the time line on that?

Yes. First of all, Paul, thanks for the question. I'll say we're currently in the exploration phase. We've conducted a lot of initial assessments. It's onshore and state land, so the process can move a bit faster than federal land. Additionally, there is significant pipeline capacity nearby. However, let's focus on the exploration phase, evaluate what we discover, and then plan our next steps. We are excited about the potential.

But can you maybe share what type of infrastructure we might need if it is successful?

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

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 has 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?

Historically, we operated five drilling rigs and twelve workover rigs before modernization. We increased the drilling rig count to between fifteen and eighteen, while we were only able to raise the workover rig count to twenty, effectively doubling it alongside the tripling of the drilling rigs. Initially, this wasn't a significant issue because we focused on improving efficiencies in drilling. However, as we streamlined operations on the drilling side, the workover rigs became necessary to finish the drilled wells. We need to manage the base effectively. This is a new situation, and in the long run, we will require more workover equipment in the country, as there isn't a short-term solution to this problem.

Our next question comes from Neil Mehta with Goldman Sachs.

Yes. First question I had was just on Suriname. Maybe you could step back, John, big picture, talk about where we stand here. 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?

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. 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. 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.

And then a 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.

Neil, we've had a number of good run years of really outperformance in the Permian. 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. Yes, we don't have many wells coming on early this year. Things are kind of second and third-quarter back-weighted with the way the schedule works. You'll see strong Permian growth on the oil side. We're anticipating up 10%, Q4 '24 over '23. That's going to more than offset the decline in the North Sea. It continues to be underpin our backbone, and we're going to continue to lean on Permian.

Our next question comes from Arun Jayaram with JPMorgan Securities.

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?

Yes, Arun. As you know, we've talked about this a number of times every quarter. We have a very active and constructive working relationship with Egypt, but it does require that ongoing conversation and work. In the fourth quarter, we ended with our lowest quarter-end past-due receivables for the year from EGPC. We continue to make progress. They've come down through the year and peaked in early second quarter. Today, we're about 25% to 30% below where we were at that peak level. They're still elevated, past-due receivables from EGPC but are lower and trending in the right direction, having been pretty much through the whole year.

Great to hear. Steve, my follow-up is about Slide 30 in the deck. I want to understand more about the impact of abandonment costs on cash flow. Your costs incurred for the year were $979 million, and your total upstream capital is $520 million. Most of the difference is related to ARO. In the fourth quarter, did you have an outflow of about $347 million for ARO? Is the $60 million you mentioned for 2024 a reasonable run rate for the next several years?

Yes, let's discuss this later instead of going over it in the group. I will coordinate with Gary to follow up with you. We want to ensure we fully understand your question.

Okay. Fair enough. Thanks, Steve.

Our next question comes from Leo Mariani with ROTH MKM. Did you have an outflow of about $347 million for ARO in the fourth quarter? Is the $60 million you mentioned for 2024 a reasonable estimate for the following years? Yes, maybe we can discuss that later instead of going through it here. I'll collaborate with Gary to get back to you, and we can sort it out. I just want to ensure we fully grasp the question. Okay, understood. Thanks, Steve.

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.

Yes, Leo, I'll start with Suriname. We've indicated that we see greater exploration potential in Block 58 compared to Block 53, which made it a straightforward decision to let go of Block 53. Regarding the risk profile in Alaska, the data is supported by 3D and amplitude analysis, but it involves stepping into a riskier area. I can't provide a specific ratio, but this is about exploration. We are drilling three wells that carry risks, yet they also offer high rewards. Tracey, do you have anything to add?

Yes, I'll just comment on a little both pieces, which is the Block 53 exit. We mentioned on the previous call that we really saw the prospectivity in Block 58 as being more prospective than what we saw in Block 53. So what you're seeing with that exit really is 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. I would just echo what John said on Alaska. We have a range because these are exploration prospects that have risk associated with them. But clearly, what interested us in the block is that we see materiality with these prospects that 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 Callon, I'm sure you'll have to take a fresh look at the whole organization. But did I hear that right, but perhaps you think that you might cut some of the APA headcount here at some point?

I mean, I'll just say we're always looking to rightsize the organization with activity levels. I think the comment in the prepared remarks was that we find ourselves in a much lower price environment. We always want to reduce activity and associated staff if we need to do so. We've gone through an exercise in the North Sea as we're kind of rightsizing for late life. We've gone through some steps there. Quite frankly, we're very excited about integrating the Callon assets and pulling those into the organization. We do see some synergies there, but 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 Christmann, CEO, for closing remarks.

Yes. 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. We look forward to integrating the Callon assets into our Permian operations as well. 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.