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Operator: Good day and thank you for standing by. Welcome to the APA Corporation’s First Quarter 2024 Financial and Operational Results Conference Call. At this time all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. Each person is limited to one question and one follow up. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your first speaker for today, Gary Clark, Vice President of Investor Relations. Thank you.

Gary Clark: Good morning, and thank you for joining us on APA Corporation’s first quarter 2024 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 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 have had the opportunity to review our financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.com.

Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today’s call are adjusted to exclude 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.

Please note that the first quarter 2024 results reflect APA Corp. only as the Callon acquisition was subsequently closed on April 1st. Accordingly, our full year 2024 guidance reflects first quarter APA results on a standalone basis, plus three quarters of APA and Callon combined. 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 first quarter performance, discuss the compelling opportunities we are seeing after the closing of the Callon acquisition and review our activity plan and production expectations for the remainder of 2024. During the first quarter, upstream capital investment of $568 million was below guidance due primarily to the deferral of some planned facility leasehold and exploration spend. We continue to deliver excellent results in the Permian Basin with the first quarter marking our fifth consecutive quarter of meeting or exceeding U.S. oil production guidance. U.S. oil volumes were up an impressive 16% compared to the first quarter of 2023, and we expect organic growth to continue through the year as we integrate talent.

On the natural gas side, we chose to curtail a substantial amount of production at Alpine High, primarily in March in response to extreme Waha basis differentials. This dynamic has continued into the second quarter. In Egypt, gross production was in line with our expectations, while adjusted volumes were just shy of guidance due to the PSC impact of higher than planned oil prices. As discussed previously, we are in the process of rebalancing our drilling rig to workover rig ratio in Egypt to further optimize capital efficiency. In the first quarter, we averaged 17 drilling rigs and 21 workover rigs. While the workover rig count will remain flat, we will reduce the drilling rig count over the next three quarters, allowing workover rigs to be redirected.

The amount of oil production temporarily off-line and waiting on workover remained at around 12,000 barrels per day during the quarter, we expect to make progress on this as the drilling rig count comes down and freeze up workover resources. The challenges we experienced in the fourth quarter 2023 with faulty new electrical submersible pumps have now been fully remediated through vendor change out and design modifications. Turning to the North Sea. First quarter production was impacted by a decrease in average facility run time at Barrel in March. As a reminder, this type of downtime tends to occur more frequently and is less predictable when managing late-life assets like those we have in the North Sea. On the exploration front, we recently concluded our three-well Alaska exploration drilling program.

As a reminder, our 275,000 acre position lies on state lands, roughly 70 to 90 miles east of analogous industry discoveries. Our King Street #1 well confirmed a working petroleum system on our acreage, discovering oil in two separate zones. The other two wells, Sockeye #1 and Voodoo #1, were unable to reach their target objectives in the allotted seasonal time window due to a number of weather and operational delays. We are currently analyzing all of the data and we’ll come back later with more commentary on next steps in Alaska. Lastly, in Suriname, we are progressing the FEED study on our first development project, which we hope to FID before the end of the year. Turning now to the Callon acquisition, which closed on April 1, we are one month into the integration process and are making very good progress.

As anticipated, we are finding tremendous opportunities to reduce costs, improve efficiencies, leverage economies of scale and create value by applying our operational expertise and unconventional development workflows to the Callon acreage. Accordingly, we have increased our estimate of annual cost synergies by 50% from $150 million to $225 million. Steve will comment further on the timing and nature of these synergies in his remarks. The most exciting and compelling value capture opportunity we see with Callon still lies ahead. That will come from capital efficiency improvements which will enhance overall development economics and potentially expand the development inventory that form the basis of our transaction value. For the remainder of 2024, we will be revising most of Callon’s operational practices and workflows.

This includes everything from contracting and logistics, to well planning and design, drilling and completions, facility construction and many aspects of daily operations. At a high level, you will see wider well spacing, fewer discrete landing zones and larger fracture stimulations. Improvements in capital efficiency will manifest in fewer wells to deliver the same amount of incremental production volumes. While it will take some time to realize the full benefit of these changes, the implementation has already begun. In the meantime, we are modifying many aspects of Callon’s previous 2024 plan to capture as much near-term benefit as possible. Turning now to our activity plans and outlook for 2024, in yesterday’s release, we provided guidance for the second quarter and full year 2024, along with our expected oil production rates for the fourth quarter.

In the U.S., we have been running 11 rigs in the Permian since April 1. We expect to average approximately 10 for the remainder of this year as we actively manage changes to the combined rig fleet. You will see the rig count change as we drop some rigs when their term ends and pick up other rigs more suitable for the planned drilling program. Similarly, we will be making a number of adjustments to our combined frac schedule. In terms of oil volumes, we noted in our first quarter materials that we expect U.S. oil production in the fourth quarter to be around 152,000 barrels per day which represents an 11% growth rate from our second quarter guide of 137,000 barrels per day. Switching now to Egypt, in February, we commented that adjusted production would remain relatively flat in 2024.

Today, we anticipate adjusted production will decrease slightly as a function of the PSC impacts of higher-than-planned oil prices. And in the North Sea, production guidance for the full year is unchanged with an expected dip mostly in the third quarter as we conduct scheduled platform maintenance. In closing, we continue to manage our business with a clear and consistent strategy and deliver on our capital return commitments and financial objectives. The Callon acquisition is complete and the path to value creation is clear and well underway. Post Callon, our Permian Basin unconventional acreage footprint has increased by approximately 45% and our Permian Basin oil production has increased by more than 65%. The Permian Basin will represent an estimated 73% of APA’s total company adjusted production in the second quarter and will approximate 75% of our upstream capital this year.

Notably, our oil production weighting in the U.S. will increase to a projected 46% in the second quarter from 39% on a stand-alone basis in the first quarter. Finally, Steve will discuss our priorities around debt reduction, but I want to emphasize that our shareholder return framework has not changed, and we will continue to return at least 60% of our free cash flow via dividends and share repurchases. And with that, I will turn the call over to Steve Riney.

Steve Riney: Thank you, John. And good morning. For the first quarter, under generally accepted accounting principles, APA reported consolidated net income of $132 million or $0.44 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $52 million after-tax addition to the provision for costs associated with Gulf of Mexico abandonment liabilities. Excluding this and other smaller items, adjusted net income for the fourth quarter was $237 million or $0.78 per share. The resulting adjusted earnings for the quarter include some significant exploration dry hole expenses. Specifically, we took a $59 million charge for the two exploration wells in Alaska, which were unable to reach their targets.

Additionally, we wrote off the remaining $42 million we were carrying for the Bonboni exploration well in Suriname, which was drilled in 2021 and as we now have no active plans for further exploration in the Northern portion of Block 58. The total after-tax impact of these items on adjusted earnings was $88 million or $0.29 per share. In the first quarter, we returned $176 million through dividends and share repurchases. As John indicated, we remain committed to returning a minimum 60% of free cash flow to shareholders. We are also cognizant of the need to strengthen the balance sheet, and we are looking at non-core asset sales as a source of debt reduction, in addition to the 40% of free cash flow not designated for shareholder return. Our priorities for debt reduction will be the three-year term loan we used to refinance the Callon debt and the revolver.

Finally, we incurred roughly $20 million of costs associated with the Callon transaction in the first quarter and expect to incur an additional $90 million of such costs. The vast majority of which will be in the second quarter for professional services, departing Callon employees and other closing costs. Now let me turn to progress on the Callon integration. One month into the process, we are on track to realize more cost savings than originally projected. As John noted, we have revised our annual synergies from $150 million up to $225 million. Recall, we put expected synergies into three categories: overhead, cost of capital and operational. Annual overhead synergies have been revised up from $55 million to $70 million. This is moving quickly, and we will capture approximately 75% of this on a run rate basis by the end of the second quarter.

We expect by year-end, nearly all of these synergies will be realized and our go-forward G&A run rate will be around $110 million per quarter. Expected annual cost of capital synergies are unchanged at $40 million. The initial refinancing of the Callon debt realized a portion of these synergies and they will be fully realized when the debt is termed out or paid off. We are seeing the greatest amount of opportunity in operational synergies. Our original estimate for this category was $55 million, which we have revised upward $215 million. We are making extremely good progress in this area, some of the more impactful items that we are working on include recontracting of frac services in rig high-grading artificial lift optimization, which will lower LOE and reduce downtime, supply chain synergies for casing and tubing, sand, chemicals and other items, compression fleet optimization and economies of scale and well design improvements that eliminate extra casing strings and reduced drilling days.

Further down the road, we see additional potential in areas like gas marketing and transportation and water handling, disposal and recycling. To reiterate, these cost synergy estimates do not include capital productivity effects associated with improvements in well type curves and economics through well spacing, landing zone optimization and frac size. Turning to our 2024 outlook. John has already discussed our activity plans and production guidance. So I will just touch on a few other items of note. Other than reflecting the Callon acquisition and our outlook, the most material change to guidance is associated with gas pricing in the Permian and its impact on expected near-term production and third-party gas marketing activities. As most of you are aware, Waha experienced severe basis differentials in March and April, we expect this will continue through much of May.

As a result, we have continued to curtail gas into the second quarter and our 2Q guidance now reflects an estimated impact on the quarter of 50 million cubic feet per day of gas and 5,000 barrels per day of NGLs related to the weakness at Waha Hub. Our income from third-party oil and gas purchased and sold, including the Cheniere gas supply contract is expected to be around $230 million for the full year, which is up significantly from our original guidance of $100 million. You will also see that we have removed DD&A from our guidance at this time. We are still working on the Callon purchase price allocation and aligning our reserve booking practices. We will reinstate D&A guidance with the second quarter results. Finally, as a reminder, APA will be subject to the U.S. alternative minimum tax starting in 2024.

We incurred no AMT in the first quarter and do not expect to in the second quarter. Based on current strip prices, we will likely incur these costs in the second half of the year. And with that, I will turn the call over to the operator for Q&A.

Operator: Thank you. We’ll now, at this time conduct our question-and-answer session. [Operator Instructions] Our first question comes from the line of John Freeman of Raymond James. Your line is now open.

John Freeman: Good morning, guys.

John Christmann: Good morning, John.

John Freeman: The first question I had, just to make sure that I understand sort of the moving parts in Egypt. So last quarter, had about 13,000 that was off-line. I think normally, I think you all cited that, that would be closer to probably 8,000 – I’m sorry, 5,000 would normally be offline. So you’ve worked it down a little bit, and I see how the rigs keep coming down, the workover rig level stays level. But I think historically, John, you all said that used to be sort of 2 to 3 times the number of workover rigs to drilling rigs. So even as the rig cadence kind of goes down the rest of the year, you still stay kind of well below that level. So maybe just help me understand how you can kind of – you get that backlog or what’s off-line worked down despite still being a good bit below that historical ratio? Like maybe why that historical ratio maybe doesn’t apply anymore? Or just any additional color there?

John Christmann: No, it’s a great question. And as you acknowledge, historically, we have run a higher ratio of workover rigs or drilling rigs. Today, we’re going to average 13 to 15 on the drilling rig side this year, and we’re going to run right at 20 workover rigs. So it’s going to take a little bit more time to kind of chisel away at that, but we’re on it. It’s coming down a little bit. There’s also things we’re doing with the drilling rigs to be able to complete some wells, which will also help some of that pressure. So it’s just going to take a little bit longer, which is why you’ll see a gradual move down on that number.

John Freeman: Got it. And then just shifting gears, nice to see the 50% increase in the Callon synergies and obviously making a lot of progress on the cost side. You all put out previously a presentation just sort of showing all Permian results relative to legacy Callon results. And I guess in four – it won’t be until 4Q, and we get to see basically wells that you all kind of started design drill completed from the get-go show up in the numbers, and you mentioned some of the things that could drive to the better well productivity wider spacing, et cetera. Just to be clear, you all guidance just assumes legacy Callon well results, right? Like it doesn’t assume any uplift. Is that correct in your current guidance?

John Christmann: Yes. Today, the guidance is what’s in front of us, right? And it’s going to – obviously, Callon’s drilled a lot of wells. We’re immediately making changes on the completion side to the extent we can. But there are more wells drilled per section that we would drill. There are more landing zones. And so we’re going to have to pump similar-sized fracs in terms of sand loads, I think the big thing will be changing is the fluid volumes will go up, but we’re doing things with – it’s kind of a work in progress, right? We start with what Callon has and we modify what we can and what we think is going to be impactful. And then by the time you get to the fourth quarter, you’ll start to see how we plan things and what will be full Apache workflow on that.

Just a little color in terms of where the rig count sits and things today, we’re running 11 rigs, there’s four in the Delaware, there’s actually seven in the Midland. We’ve actually moved one of the Callon rigs to some Apache acreage that was ready and kind of plan like we want to drill it. So we’ve accelerated some there. So it’s going to be in flux as we work through this. But yes, we’re anxious to get to fully Apache planned workflow and execution. And it’s going to be a kind of a transition over the next two quarters until we get their fourth quarter.

John Freeman: Thanks, John.

John Christmann: You bet. Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Neal Dingmann of Truist Securities. Your line is now open.

Neal Dingmann: Good morning, John. Thanks for taking my question. I just had a quick one first on the Permian gas play. It’s interesting the acreage and the potential returns there. I’m just wondering what would it take for you to bring some of that back? Is it just strictly it needs to compete against your now more oily play given that Callon and the larger footprint?

John Christmann: Well, I mean, that is the big driver. It needs to compete internally on the oil side. And really, we measure that through Waha. So right now, you’ve had very, very weak Waha. Obviously, we’ve got Matterhorn coming on, but we’re going to need to see much stronger Waha and it’s going to need to compete internally with our oil projects.

Neal Dingmann: No, that totally makes sense. And then just, again, maybe last one for you, Steve, just when it comes to shareholder return, you guys have continued and maybe sometime towards the end of the year, stepped a bit more into the buybacks and all. I’m just wondering, will that plan change or should we just think sort of more of the same when it comes to shareholder return?

John Christmann: No. I mean I think big picture, we’re committed to the 60%, right? We’ve shown that it’s a minimum of 60%. And we will lean into that when we believe there’s weakness, which we’ve historically done, and we’ll continue to do in the future. That gives us the other 40% for debt reduction. We do have some non-core asset sales that we’re targeting as we do believe we need to make some progress on the debt side with what we brought on with Callon, but you’ll see us aggressively approaching both.

Neal Dingmann: Very good. Thanks, John.

John Christmann: You bet. Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of David Deckelbaum of TD Cowen. Your line is now open.

David Deckelbaum: Thanks for the time guys. I wanted to ask a couple of questions around the capital program this year and your preliminary thoughts getting into 2025 as you further integrate the Callon assets. One, can you just talk about, in this year, how many DUCs you’re intending to work down and what you would carry going into next year? And as a follow-up to that, if we think about the combined company this year, should we be assuming improved capital efficiencies into next year that would sort of have you on this glide path of combined companies spending in and around $3 billion a year.

Steve Riney: Yes. David, this is Steve. So in terms of the capital program and the treatment of DUCs, what we’ve done is we’ve added some frac capital in order to come up to the $2.7 billion of capital that we have in the plan for this year now. We basically just combined the final three quarters of Callon’s remaining capital program with ours. But then we added some frac capital in the second half of the year because we did see that both of us were building DUCs. Now I think it’s probably best that we not get into numbers at this point simply because the program is still, I’d say, very much in flux as you go out towards the back half of the year. We’re working our way through it. As John said, we are changing a lot of the activity.

There’s hardly any activity that’s going on the Callon acreage later this year that we’re not changing from the Callon plan. And so you can imagine after four weeks that, that’s still a bit in flux. And so maybe we can share some – a bit more clarity on things like that with the second quarter earnings call in August. I think that would be better just so we can be through a bit of this, and we can solidify the remaining plan for the year. But just as a general statement, we don’t believe that it’s good capital efficiency in general to be carrying a lot of DUCs. There are some value to having some DUCs and there’s some just basic need because of the logistics of matching up frac schedules with drilling schedules, but we don’t believe in the capital efficiency of having a tremendous amount of DUC inventory.

John Christmann: And the only thing I would add is, obviously, we believe the capital productivity will improve on the Callon portion especially as we go to our modifications and our workflows back half of the year. So combined companies going to improve and we’re seeing that productivity on the Apache side right now, and we’ll get the Callon assets there towards the back half of the year.

David Deckelbaum: Appreciate that. If I could make those first two questions, I guess, into one and ask another one. I’m just curious if you can share any targets that you might have in mind on proceeds or timing from non-core asset sales?

Steve Riney: No, we don’t have any specific targets in mind. But what we recognize that even after the progress that we made in 2021 and 2022 on debt, for Apache Corp. we knew that we needed to make more progress. And we didn’t make as much as we might have wanted to during the intervening time, and we just feel like we need to get on with that and get debt down. And now that we’ve added some debt through the Callon acquisition, we’re going to just try to focus on that this year. We think it’s a good time to be doing that. The market seems to be strong for some of these non-core assets and we’ll see if we can get some of those off and get some good prices, and they will be focused on debt reduction. We’re optimistic about that.

We think that it’s a good time to be doing it. Ultimately, the – sorry, ultimately, the target is to get debt to a point where we are kind of a solid BBB type of rating on our debt so that you’re not kind of dancing around the edge of investment grade and non-investment grade. And we slid into non-investment grade in 2020 with the massive downturn in oil price and we haven’t been able to climb back out of that, even though we’re – we have the metrics of a lot of investment-grade companies. We’re still not investment grade with everybody. We’ve gotten there with two, but not all three.

David Deckelbaum: And do you think there’s a path to getting there within the next couple of years?

Steve Riney: That’s what we’re trying to achieve. Yes. I think it’s possible, and we’re going to certainly give it a try.

David Deckelbaum: Good luck, guys. Thank you.

John Christmann: Thank you.

Operator: Thank you for your question. [Operator Instructions] Our next question comes from the line of Betty Jiang of Barclays. Your line is now open.

Betty Jiang: Good morning. Thank you for taking my question. I really appreciate the color or the guidance that you have given for 4Q pro forma production for U.S. oil. If we think out to 2025, like Apache is delivering double-digit organic growth in the Permian this year. Do you expect to see continued growth on the combined assets going forward? Like just thinking about the overall strategy, like approach from a growth outlook perspective? Thanks.

John Christmann: Yes. Betty, what I’ll say is, as post the Callon merger, our Permian now makes up roughly 75% of the company. And we’ve been executing at a high rate on the Apache side. We’re anxious to provide those workflows on the Callon side. We have added a little bit of capital, which is going to work down some of the DUCs in the fourth quarter of this year. So I mean, it’s early to comment on 2025, but it’s going to give us a lot of strong momentum as we exit 2024 with a very strong fourth quarter. So we’re very anxious to demonstrate that, and we’re very confident in what we can deliver from the Permian.

Betty Jiang: All right. Maybe shifting…

Steve Riney: Sorry, Betty. I was just going to add one thing to that. One of the reasons why we added the frac capacity in the second half of this year, number one is frac is pretty inexpensive these days. So it’s a good time to be doing that. But also just – with the scale of the operation now that we have in the Permian Basin, as John said, 75% of our company now, with that kind of scale and the amount of activity that we’re carrying on we ought to be able to plan activity to where we don’t have these big lulls a big rush of completions and turn-in lines and then a big wall of activity, and we ought to be able to plan it maintaining capital efficiency, but plan it in a way that creates a bit smoother profile to production volume.

And that’s one of the things that we’re trying to achieve as we bring this frac capacity into the back half of this year is to get a little more smoothness to that because we were – we felt like we may have been setting ourselves up for yet another downturn in first quarter on volume, a little bit of a lull or a flat spot, and we don’t need to be doing that, and we can do better than that.

Betty Jiang: Great. I appreciate that color. Thanks. Shifting gear to Egypt a similar question. This year, seeing that growth of Egypt volume is down a little bit, but a lot of that related to the workover rig shortage. If we look out post the PSC contract renegotiation, there was an expectation of Egypt growing single-digit range. Do you expect to go back to that type of profile. When do you think that asset will be ready to do that?

John Christmann: Yes. I mean you’ve got one factor in Egypt is costs are big picture gas has been declining. So the gross BOEs have been declining because of that, and we’ve been growing the oil we’re in a place today where we’re working to rebalance the workover rigs and the drilling rigs and find a good level in there where we can drive that production base. So, we’ll monitor that over the year and come back later this year with projections in terms of what we’ll do next year. And quite frankly, how Egypt continues to compete with what we’re doing in the Permian, will play into that as well.

Betty Jiang: Great. Thank you for that.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.

Leo Mariani: I wanted to follow up a little bit here on Egypt. I wanted to just kind of get a sense from you folks what the situation is with the receivables there in country. I saw that Egypt recently got an IMF loan a little bit ago. I’m not sure if that’s kind of improved the state of financial well-being there. So maybe you could just kind of speak to that? And then also, could you speak a little bit to kind of your expectations for gross Egyptian oil volumes? I know you talked a lot about sort of net, but it looks like growth has come down in the last few quarters. How do you expect growth trajectory on the gross volumes to trade over the next couple of quarters?

Steve Riney: Okay. Yes. So sorry, this is Steve. Yes, on receivables. So as we’ve always said, we worked very closely with the Egyptian government on things like that. We’ve received two payments during the first quarter of this year. But despite that receivables, especially with oil price and all receivables increased slightly in the first quarter of 2024 we kind of made good progress through 2023, bringing it down most quarters. It increased slightly in the first quarter of 2024, but it’s still below the average of where we were last year. But more importantly, I think you hit on the point, I think Egypt is on a very good path right now. They’ve floated their currency; they devalued it and floated it. And with that, they had to raise interest rates to control inflation.

But with that, their bonds are up and the ratings outlook is improving. The IMF loan, as you talked about, they increased their loan program from $3 billion to $8 billion. They’ve gotten a significant amount of investment coming in from other Gulf states mostly around some real estate opportunities. And they’ve got pledges now from both the World Bank and from the EU to offer support as well. So I think all of the signs for Egypt are pointing up now. That doesn’t mean that it’s going to be an easy ride. It’s not going to be a quick ride, but things are certainly improving. Liquidity is improving. It’s just a big positive step in the right direction, and that’s going to help as we go forward. And we have had indications from the Egyptian government that we will get a large payment in the second quarter of this year.

So we’re – will be – and will actually be in Egypt visiting with them around that same time. So that’s where we are on the receivables. It hasn’t changed a whole lot in the first quarter, but certainly all of the signs of things going on in Egypt are pointing up and improving. In terms of gross volume, we haven’t declined for two quarters in a row. We’ve actually – and if you look back to 2023, gross oil volume was pretty flat for a while and then rose. We’re declining now from fourth quarter to first quarter. A lot of that is around completion timing. We actually completed 27 new wells in the third quarter last year, 26 in the fourth quarter. And then we completed 17 in the first quarter of this year. So that’s not necessarily a surprise that volume – oil volume might be declining a bit in this quarter.

We’ll see where we go going forward. We are continuing to reduce the drilling rig count. So that is going to have an effect on the number of wells that will be available for completion. But we’ll see as we go quarter-to-quarter through the year on gross oil volume. And then as we approach year-end, and as John said in the prior question, we’ve got to work through this issue of the balancing of workover rigs and workover capacity with our drilling capacity because it’s not a very efficient use of capital to be drilling new wells when workover is so much more capital productive than drilling new wells. Nothing wrong with drilling new wells, but workover is cheap and normally returns quite a bit of production volume to – on the line.

So you got to make sure you have the capacity to stay on top of the workover program. And we’ve got a lot of ideas on how we can work through that. Ultimately, there is longer term, the possibility you could bring more workover rigs into the country, but there are a lot of other things that we can try to work through before we get to that. So we’ve got a lot to do in 2024 to get things balanced properly and functioning properly between drilling new wells and working over and working our way through that backlog. And then as we roll into 2025, we’ll give a better view to where Egypt is going.

Leo Mariani: All right. That was very helpful, very good explanation there. And I guess just maybe turning to Suriname very quickly here. Just wanted to kind of get a better sense of kind of where things stand. I know you’re still working towards FID kind of what’s your confidence level with your partner on achieving that later this year. And it sounds like there’s still no drilling happening in 2024, but does Apache anticipate some drilling there in 2025?

John Christmann: Yes, I’d just say we’re very confident, FEED is still underway, and we would anticipate an FID by year end. So it’s all moving forward there. And then that’s going to dictate timing in terms of drilling. We’ve got till 2026 to start the exploration program. So there’s nothing pressing on the 2025 side, but we could be back to drilling in 2025.

Leo Mariani: Okay. Thank you.

John Christmann: You bet. Thank you, Leo.

Operator: Thank you for your question. Please standby for our last question. Our last question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Neil Mehta: Good morning, team. John, I wanted to spend a little bit of time talking about the Callon cost synergies. And specifically on the operational side, you’re talking about high-grading the service providers, stuff around casing, surface economics. So can you just spend some time getting us on the ground and giving us a little bit more granularity around some of those cost synergies on the operational side?

John Christmann: Yes, I’ll jump in, and I’ll let Steve add a little bit more color. But in general, we’re changing the program. So you’re going to see fewer wells per section, fewer landing zones, larger fracs in general. The other thing is when you look at the well count in terms of how they complete their wells, Callon was putting a third of their new wells on ESPs and 30% on gas lift. We’ve been running outside of Alpine High, about 3% ESP and 60% gas lift. So that’s the other place in terms of just how we’re equipping the wells, how we’re flowing the wells and producing the wells and then obviously, the power then that is needed to drive those sub pumps is another big factor. I’ll also say that they turnkey a lot of their stuff.

I mean they turnkeyed a lot of their frac operations and we’re going to self source and do a lot of stuff there. So there’s a lot of low-hanging fruit on the operations side. So those are some of the big ticket items. And we’ve already seen a lot of that, which is why you’ve seen us increase a lot on the operational side.

Steve Riney: Yes. And Neil, I’d just add, if you went back to the Permian slide deck that we published in February, we specifically pointed out three areas where we felt like Callon was significantly kind of off the mark in terms of where we would want to be on LOE per BOE, workover cost per BOE and downtime percent. And they’ve – Callon has a history of a much higher well failure rate and including for new wells. They have a higher rate of ESP failures than we do. And many of those are around – we feel around their equipping choices, and we’re already making some changes on a proactive basis in that – even on some of the wells that they’ve already drilled and completed and equipped. There was a lot of inefficiency around compression and the use of their compression fleet, and we’re making across a larger set of operations, we can make more economies of scale around compression optimization and even on the rate negotiations for compression costs.

As John pointed out, they have a tendency to use a lot of ESPs for which they purchase power. That’s very expensive and a big contributor to their LOE per BOE. They use a lot of contract labor, a lot of our supply chain aspects of using APA rates around services and around product using volume discounts that we get across the larger operations and just reducing overall usage. They had a very high water handling and disposal costs, which we believe we can do much better at. They had a high rate of rental, rentals of ESPs, rental of compressions where we think we can do better at that as well. On the capital side, we’ll use more technology to drill to use – to decrease average drilling days on wells. We’ll get better rig rates. We’ll do a better job of rig moves because we’re not moving rigs across the basin between the Delaware and the Midland Basin.

We will use spudder rigs generally for a lot of the wells that we drill. They did not have a practice of doing that normally. Frac rates will get better at proppant costs; again more supply chain type of stuff. And then on facilities, we – they typically have built facilities spec. We typically try to modularize that. We will typically go to multiphase flowing through a single line. They like to use test separators and meter three products in three different lines. So we think there’s just – and there’s just a whole bunch more of stuff that we’re going to be looking at and doing to reduce LOE per BOE and downtime and the work over costs.

Neil Mehta: That’s a very thorough and helpful explanation. Thank you team and good look as you bring the asset into the fold.

Steve Riney: Thanks Neil.

Operator: Thank you for your question. We will be taking one more question. Please stand-by. We now have a question from Paul Cheng of Scotiabank.

Paul Cheng: Hey guys. Good morning.

John Christmann: Good morning, Paul.

Paul Cheng: Good morning, John. Steve, I have to apologize. When you talk about dry hole, I sort of missed that. Can you repeat it? I think you’re saying that you have a way of in share name on B52 that’s I think $40-some-odd million. So what’s the remaining with the driver expense at 123 [ph]. The second question is that yes, go ahead, please.

John Christmann: Well, I’ll jump in. The – there’s one dry hole in Suriname, which was related to Bonboni up in the north. It was one that we held and weighted because we didn’t know how the North would factor in on the future exploration side. And so that’s why we took that one now. And then we went ahead in Alaska and rolled off the two wells that we failed to reach TD on simply because the decision was made that it would be easier to go back and redrill those prospects with brand-new wells. And so that’s what the dry hole expenses were for.

Paul Cheng: I see. And John, on Alaska in King Street discovery, can you share that what’s the thickness of the case one that you have interpolated that do you have any data about the permeability or that any information that you can share?

John Christmann: Well, it’s very preliminary, Paul. But we’re excited about both. I mean these are not shallow wells in the Brookian play to high-quality oils – we were also very pleased with the early data, but we need to get the rock data back into the lab and analyze that and go through all that before we really share anything. I think one of the big read-throughs on King Street though, it was the smallest and the most risky of the three prospects, even though it’s the one we got down all the way, but there is a very positive read through in the Upper Zone at King Street for the big target in Voodoo, so it’s very exciting. And if anything, it has us feeling even better about the program and the acreage going forward. I mean we’ve moved 70 miles to 90 miles east of working hydrocarbon system.

Truly wildcat area, and now we’ve proven petroleum system. We’ve proven oil, and there’s also very high-quality sand there. So a lot to get pretty excited about going forward in Alaska.

Paul Cheng: Right. And John, you’re saying that you’re going to redrill the two new well for Sockeye and Voodoo is that going to be done? Or that is going to be drilled in the next drilling season? Or that you guys have not decided may get pushed out further?

John Christmann: I’ll just say, it’s highly likely that we redrill both prospects – but it’s – we’ve got to work through the partners, and we don’t have to make decisions yet on the 2025 drilling program. So we’re – it’s something we’ll be working through with the partners over the next several weeks. But at this point, it’s something that could be done in 2025. It doesn’t have to be done in 2025, but we’ll be working through the partners with that.

Paul Cheng: Okay. Thank you.

John Christmann: You bet. ]

Operator: Thank you. This does conclude our question-and-answer session. I would now like to turn the call back over to John Christmann for closing remarks.

John Christmann: Yes. Thank you. In closing, our Permian is performing extremely well, and we have just bolstered it with the addition of Callon and is now approximately 75% of the company. We will be integrating Callon over the next couple of quarters. And by the fourth quarter, you should start to get a good picture of what we can do with the Callon assets. We have pulled from some frac capital into the second half of the year which should really give us strong momentum as we head into 2025. On the cost synergy side, we have increased our expectation by 50%, and we’ll capture most of these by year-end and we believe there is even more to do beyond that. And lastly, we’d like to make more progress on debt reduction by the end of the year while also meeting our 60% shareholder return commitment. Thank you very much for joining us today.

Operator: Thank you. This does conclude today’s conference. You may now disconnect.