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 speaker's presentation, there will be a question-and-answer session. Each person is limited to one question and one follow-up. To ask a question during the session, you will hear an automated message advising that your hand is raised. To withdraw your question, please press star one one again. 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. 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 1. 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. 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 Callon. 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 work over 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 offline 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 frees up workover resources. The challenges we experienced in the fourth quarter of 2023 with faulty new electrical submersible pumps have now been fully remediated through vendor changeout and design modifications. Turning to the North Sea, first quarter production was impacted by a decrease in average facility runtime at Beryl 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 70-90 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 1st. 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 1st. 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'll be making a number of adjustments to our combined frack 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. 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 standalone 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. With that, I will turn the call over to 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 resultant 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, 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 cents 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 turned out or paid off. We're seeing the greatest amount of opportunity in operational synergies. Our original estimate for this category was $55 million, which we have revised upward to $115 million. We are making extremely good progress in this area. Some of the more impactful items that we are working on include recontracting of frack services and 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 reduce 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 frack 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 in 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 the Callon purchase price allocation and aligning our reserve booking practices. We will reinstate DD&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. With that, I will turn the call over to the operator for Q&A. Thank you. We will now, at this time, conduct our question-and-answer session. As a reminder, all participants are limited to one question and one follow-up. To ask a question, you will need to press star one, one on your telephone and wait for your name to be announced. To withdraw your question, please press star one, one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of John Freeman of Raymond James. Raymond James, I apologize. Your line is now open. Good morning, guys. Good morning, John! Yeah, the first question I had, just to make sure that I understand, sort of the moving parts in, in Egypt. So, so last quarter, y'all had about 13,000 that was offline. I think normally, I think y'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, you know, keep coming down, the workover rig level stays level. But I think historically, John, y'all said that y'all used to be sort of 2-3x 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. Maybe just help me understand how you can kind of, you get that backlog or what's offline 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. No, it's a great question, and, you know, as you acknowledge, historically, we have run a higher ratio of workover rigs or drilling rigs. You know, today, we're gonna average 13-15 on the drilling rig side this year, and we're gonna run right at 20 workover rigs. So it's gonna 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, you know, with some of that pressure. So it's just gonna take a little bit longer, which is why you'll see a gradual move down on that number. Got it. And then just shifting gears, you know, nice to see the 50% increase in the Callon synergies, and obviously making a lot of progress on the cost side. Y'all had put out previously a presentation just sort of showing y'all's Permian results relative to legacy Callon results. And you know, I guess in four-- it won't be till 4Q, and we get to see, you know, basically wells that y'all kind of started, you know, design, drill, completed from the get-go, show up in your numbers. And you mentioned some of the things that could drive you to the better well productivity, wider spacing, et cetera. Just to be clear, y'all's guidance just assumes legacy Callon well results, right? Like, it doesn't assume any uplift. Is that correct, in our current guidance? Yeah. Today, the guidance is what's in front of us, right? And, it's gonna... You know, 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 than we would drill. There are more landing zones, and so, you know, we're gonna have to pump similar-sized fracs, in terms of sand loads. I think the big thing we'll be changing is the fluid volumes will go up, but we're doing things, you know, 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 gonna be impactful. And then, by the time you get to the fourth quarter, you'll start to see, you know, how we plan things and what will be, you know, 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, you know, kind of planned, like we want to drill it, so we've accelerated some there. So it's gonna be in flux as we work through this. But yeah, we're anxious to get to fully Apache planned workflow and execution. And it's gonna be a kind of a transition over the next two quarters till we get there, fourth quarter. Thanks, John. You bet. Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Neal Dingmann of Truist Securities. Your line is now open. Morning, John. Thanks for taking my question. I just had a quick one first on the Permian Gas play. You know, 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, you know, your now more oily play, given the Callon and the larger footprint? Well, I mean, that is the big, you know, the big driver. It needs to compete internally on the oil side. And really, we measure that through Waha. So, you know, right now, you've had very, very weak Waha. Obviously, we've got Matterhorn coming on, but, you know, we're gonna need to see much stronger Waha, and it's gonna need to compete internally with our oil projects. No, that, that totally makes sense. And then just again, well, maybe last one for, 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? 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, you know, which we've historically done and will 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 know, you'll see us aggressively approaching both. Very good. Thanks, John. You bet. Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of David Deckelbaum of TD Cowen. Your line is now open. Thanks for the time, guys. I wanted to ask a couple 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 then 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? Yeah. David, this is Steve. So, you know, in terms of the capital program and the treatment of DUCs, you know, what we've done is we've added some frack capital. In order to come up to the $2.7 billion of capital that we have in the plan for this year now, you know, we basically just combined the final three quarters of Callon's remaining capital program with ours. But then we added some frack 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. We, as John said, are changing a lot of the activity. There's hardly any activity that's going on 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. You know, there are some value to having some DUCs, and there's some just basic need because of the logistics of matching up frack schedules with drilling schedules, but we don't believe in the capital efficiency of having a tremendous amount of DUC inventory. 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 workforce back half the year. So the combined company is going to improve, and we're, you know, 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. 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 the non-core asset sales? No, we don't have any specific targets in mind. But you know 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. 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 gonna 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 that. And did the- 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 you know, 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 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. You think there's a path to getting there within the next couple of years? That's what we're trying to achieve. Yes, and I think it's possible, and we're gonna certainly give it a try. Good luck, guys. Thank you. Thank you. Thank you for your question. As a reminder, to ask a question, please press star one, one on your telephone. To remove yourself from the queue, press star one, one again. Please stand by for our next question. Our next question comes from the line of Betty Jiang of Barclays. Your line is now open. Good morning. Thank you for taking my question. I really appreciate the color of, 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 us 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. Yeah, Betty, you know, what I'll say is, post the Callon merger, you know, our Permian now makes up roughly 75% of the company, and we've been, you know, 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 gonna, you know, work down some of the DUCs in the fourth quarter of this year and give us a lot of strong momentum, as we exit 2024 with a very strong fourth quarter. So, you know, we're very anxious to demonstrate that, and we're, you know, very confident in what we can deliver from the Permian. Right. Maybe, shifting- Sorry. Sorry, Betty. I was just gonna add one thing to that. One of the reasons why we added the frack capacity in the second half of this year, you know, number one, is frack 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, 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 turning lines, and then a big lull 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 frack 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, you know, 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. We can do better than that. Great. No, I appreciate that color. Thanks. Maybe shifting gear to Egypt, a similar question. Now, this year, we've seen that gross 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, a 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? Yeah, I mean, you've got one factor in Egypt is, you know, costs are big picture, gas has been declining, so the, you know, the gross BOEs have been declining because of that, and we've been growing the oil. You know, 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, you know, drive that production base. So, you know, we'll monitor that over the year and come back later, you know, 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. Great. Thank you for that. Mm-hmm. Thank you. Please stand by for our next question. Our next question comes from the line of Leo Mariani of Roth MKM. Your line is now open. I wanted to follow up a little bit here on Egypt. Wanted to just kinda 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, you know, 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 talk a lot about sort of net, but it looks like gross has come down the last few quarters. How do you expect growth trajectory on the gross volumes to trade over the next couple quarters here? Okay, yes. So sorry, this is Steve. Leo, yeah, on receivables. So, as we've always said, we work 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 had kinda 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, and you hit on the point, I think Egypt's on a very good path right now. They've floated their currency, they devalued it and floated it. And with that, you know, 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 gonna be an easy ride, and it's not gonna 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 gonna 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'll be, and we'll 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, you know, 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, you know, 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, 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 gonna have an effect on, on the number of wells that'll be available for completion. But we'll see as we go quarter to quarter through the year on gross oil volume. You know, and then as we approach year-end, and as John said in the prior question, you know, we've got to work through this issue of the balancing of workover rigs and workover capacity with our drilling capacity, and 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 onto 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. All right. That was very helpful, very, you know, very good explanation there. And I guess just maybe turning to Suriname, you know, very quickly here. Just wanted to kind of get a better sense of kind, you know, where things stand. I know you're still working towards FID. Kind of what's your confidence level with your partner on achieving that, you know, later this year? And it sounds like there's still no drilling happening in 2024, but does Apache anticipate some drilling there in 2025? Yeah, I'd just say we're, we're, you know, we're very confident. Feed's still underway, and we would anticipate an FID by year-end. So, you know, it, it, it's all moving forward there. And then, you know, that's gonna 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 I— you know, we, we could be back to drilling in 2025. Okay, thank you. You bet. Thank you, Leo. Thank you for your question. Please stand by for our last question. Our last question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open. Good morning, team. John, I want 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 a 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? Yeah, I'll jump in, and I'll let Steve, you know, add a little bit more color. But in general, you know, we're changing the program. So, you know, you're gonna see fewer wells per section, fewer landing zones, you know, larger fracs, you know, 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. You know, we've been running outside of Alpine High, about 3% ESPs and 60% gas lift. So, you know, 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, you know, is another big factor. I'll also say that. You know, they turnkeyed a lot of their stuff. I mean, they turnkeyed a lot of their, you know, their frack operations. And, you know, we're gonna self-source and do a lot of stuff there. So there's a lot of low-hanging fruit on the operations side. You know, so those are the, some of the big-ticket items, and we've already seen, you know, a lot of that, which is why you've seen us increase a lot on the operational side. Yeah, 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 wanna be on LOE per BOE, workover costs per BOE, and downtime%. And those, 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, you know, 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. They, as John pointed out, 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 the 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, they, we can do, we can do better at that as well. On the capital side, we'll use more technology 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'll use super-spec rigs generally for a lot of the wells that we drill. They did not have a practice of doing that normally. Frack rates, we'll get better at. Proppant costs, again, more supply chain type of stuff. And then on facilities, we, they, they typically built facilities spec. We typically try to modularize that. We will typically go to multi-phase flowing through a single line. They like to use test separators and meter, you know, three products in three different lines. So we think there's just a, there's just... And there's just a whole bunch more of stuff that we're gonna be looking at and doing to reduce LOE per BOE and downtime and the workover costs. That's a very thorough and helpful explanation. Thank you, team, and good luck as you bring the asset into the fold. Thanks, Neil. Thank you for your question. We'll be taking one more question. Please stand by. We now have a question from Paul Chang of Scotiabank. Hey, guys. Good morning. Good morning, Paul. Good morning, John. Steve, I have to apologize. When you talked about dry holes, I sort of missed that. Can you repeat it? I think you're saying that you have a write-off in Suriname on Block 52. That's, I think $40-somewhat million. So what's the remaining with the dry hole expense at $123? The second- Yeah ... question is that, yeah, go ahead, please. 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, you know, waited 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 wrote 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, you know, with brand-new wells. And so that's what the dry hole expenses were for. I see. And John, on Alaska, in King Street discovery, can you share that, what's the thickness of the pay zone? That you have two intervals that, how thick are they, and that, do you have any data about the permeability or that, any information that you can share? Well, it's very preliminary, Paul, but you know, we're excited about both. I mean, these are not shallow wells in the Brookian Play, two 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, you know, it's very exciting, and if anything, it has us feeling even better about, you know, the program and the acreage going forward. I mean, we've moved 70-90 miles east of working hydrocarbon system, truly wildcat area, and now we've proven a petroleum system, we've proven oil, and there's also, you know, very high-quality sand there. So, a lot to get pretty excited about going forward in Alaska. 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 this going to be drilled in the next drilling season, or that you guys have not decided and may get pushed out further? I'll just say it's highly likely that we redrill both prospects. But it's something we've got to work through the partners and, you know, we don't have to make decisions yet on the 2025 drilling program. It's something we'll be working through with the partners over the next several weeks. But at this point, that's something that could be done in 25. It doesn't have to be done in 25, but we'll be working through the partners with that. Okay, thank you. You bet. 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. Yes, thank you. In closing, our Permian is performing extremely well, and we've just bolstered it with the addition of Callon, and it 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 frack 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. 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. Thank you. This does conclude today's conference. You may now disconnect.