Good day, everyone, and thank you for standing by. Welcome to APA Corporation's Q3 2024 Financial and Operational Results. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To participate, you will need to press star one one on your telephone. You will then hear a message advising that your hand is raised. To withdraw your questions, simply press star one one again. Please be advised that today's conference is being recorded. Now, I will pass the call over to the VP of Investor Relations, Gary Clark. Please go ahead. Good morning, and thank you for joining us on APA Corporation's Q3 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 your questions are Tracey Henderson, EVP of Exploration, and Clay Bretches, EVP of Operations. Our prepared remarks will be less than 20 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 bbl. 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, and please note that our full- year 2024 guidance reflects Q1 APA results on a standalone basis, plus 3/4 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 discuss our key strategic accomplishments in the core areas of the portfolio, review Q3 highlights and results, and outline our preliminary capital production and cost outlook for 2025. Over the past several years, APA has delivered a number of strategic initiatives designed to enhance the portfolio and create shareholder value. In the U.S., since 2020, we have executed more than $5 billion of acquisitions and over $2.5 billion of divestitures, effectively transforming our asset base into an unconventional pure-play Permian operation. This activity has three primary benefits. First, it has added scale to our unconventional Permian position, increasing unconventional acreage by more than 40% and enabling us to roughly double our unconventional production. Second, it has increased drilling inventory, and extended inventory duration, as the return today is lower than APA and Callon on a standalone basis, and third, it rationalized our portfolio by eliminating assets that did not compete for capital and significantly reduces per unit LOE. Our primary strategic accomplishments in Egypt are twofold, both of which drive APA shareholder value and benefit the Egyptian people over the life of the PSC. In late 2021, we modernized and extended our PSC terms, paving the way for more efficient capital allocation, more operational flexibility, and greater free cash flow generation, and we recently reached an agreement to increase the contractual price for incremental natural gas production in-country, making gas exploration and development more economically competitive with oil development. Shifting to Suriname, we are now seeing the culmination of our strategic efforts that began more than 10 years ago when we made a countercyclical investment in long-cycle offshore exploration. The recently announced Gran Morgu Project FID gives us visibility into strong future oil production growth at the most attractive economics in our entire portfolio. Importantly, we believe this project can easily be funded over the next few years through operating cash flow, allowing us to maintain our current capital returns framework. Turning now to the Q3 results and highlights, APA achieved several important milestones during and subsequent to the end of the Q3. We announced the sale of a package of non-core Permian properties for $950 million, which is expected to close in December. We reached FID on our first development project offshore Suriname in Block 58 with our partner and operator TotalEnergies. We signed an agreement in Egypt that increases our contractual natural gas price on incremental volumes, and we received a credit rating upgrade from Standard & Poor's, thus achieving investment-grade status at all three major rating agencies. Q3 results were strong across the board as we exceeded our production guidance while capital and costs were below guidance. Cash flow from operations and free cash flow increased compared to the Q2 despite weaker WTI oil prices and significantly lower Waha gas prices. This resilience results from some unique attributes of the APA portfolio, as well as some recent specific initiatives. These include the successful integration of Callon and associated cost synergy capture, cash flow resilience to lower prices in Egypt under the PSC structure, near-term organic oil production growth, strong cash flow from our LNG contract, and having the optionality to curtail U.S. volumes when Waha pricing is negative while still generating cash flow from gas trading, the real value of which lies in the preservation of resource for a better price environment. We expect all of these will continue to generate positive financial impacts in the Q4. Turning now to our key operational areas, U.S. oil volumes have now met or exceeded guidance for the seventh straight quarter. Since closing the Callon acquisition on April 1st, we have reduced our Permian rig count from 11 down to eight, which we believe is an appropriate pace given the prevailing commodity price environment. We have successfully integrated Callon and turned our focus to developing the acreage. Our initial wells on acquired Callon acreage are flowing back in the Midland Basin, and the early results are encouraging. The first wells in the Delaware Basin on Callon acreage will follow later this quarter. In Egypt, operations are running to plan, and gross oil production is tracking accordingly. The reduction in our drilling program has enabled the workover rig fleet to reduce backlogged oil volumes associated with delayed recompletions and workovers to more normalized levels. Pursuant to the terms of the new gas price agreement, we recently added one drilling rig, bringing our total rig count to 12. Moving on to Suriname, we recently achieved an important milestone with the announcement of the final investment decision on our first offshore development in Block 58. The operator, Total, summarized the project as having a $10.5 billion gross cost, 220,000 bbl per day of production capacity, a per BOE capital plus OpEx cost of $19, and a 15% IRR at $60 per bbl. These are very good returns, and APA's economics will be further enhanced by the capital carry provision we negotiated in 2019 when we brought Total in as a partner. We plan to fund Suriname development capital out of operating cash flow for the next few years until production commences in 2028. As previously noted, we see significant opportunity for additional exploration in Block 58 that could extend the production plateau and enhance the economics of our first FPSO or potentially support additional development projects in the future. Switching now to the North Sea, during the Q3, production volumes were in line with guidance as we completed our platform maintenance turnaround at Beryl as planned. Earlier this year, the U.K. issued regulations which will require substantial new emissions control investments on facilities that will operate beyond 2029. After six months of evaluation, we have concluded that the investment required to comply with these regulations at Forties and Beryl, coupled with the onerous financial impact of the Energy Profits Levy, makes production of hydrocarbons beyond the year 2029 uneconomic. As a result, we have made the decision to cease all production in the North Sea by December 31st, 2029, well ahead of what would have been an otherwise reasonable timeframe. Steve will provide further details on the revised schedule and financial statement impacts of this change in a few minutes. In the wrap-up operations, we have finalized plans to resume exploration drilling on our extensive state lease position in Alaska, where we will test the Sockeye prospect during the first half of 2025. Turning now to our preliminary activity plan and outlook for 2025, we currently expect to run an eight-rig program in the Permian Basin and a 12-rig program in Egypt. In the North Sea, we will have a very limited capital program focused primarily on maintaining asset safety and integrity and a small amount of initial P&A work in preparation for long-term asset abandonment. Our 2025 capital budget for the U.S., Egypt, and North Sea will likely be in the range of $2.2 billion-$2.3 billion, with an additional $200 million allocated to Suriname development activity and $100 million for exploration, primarily Alaska. This capital program should broadly sustain production volumes in the Permian and Egypt on an adjusted BOE basis, while North Sea production will be down approximately 20% year-over-year. I would also like to highlight the significant cost reductions we are targeting in 2025. In aggregate, we expect per unit LOE, G&A, GPT, and interest costs to fall by 10%-15% year-over-year. In closing, we have made very good progress on our strategic portfolio initiatives in the U.S., Egypt, and Suriname. We had an excellent quarter operationally and achieved all key guidance targets. The Callon integration is complete, most of the cost synergies have been captured, and we look forward to demonstrating the potential of the acquired Callon acreage. Egypt is running at a much more efficient operational cadence, and we have the opportunity to unlock incremental value and assist the country with its natural gas needs following the negotiation of a new price framework. Under our current price outlook, we will seek to generally sustain volumes in the Permian and Egypt for the foreseeable future while rigorously managing costs and increasing the free cash flow that these regions generate. Longer term, a successful exploration program can add tremendous value and fuel future growth, as evidenced by Suriname Block 58. And with that, I will turn the call over to Steve. Thank you, John. For the Q3, under generally accepted accounting principles, APA reported a consolidated net loss of $223 million, or $0.60 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $571 million after-tax impairment of North Sea assets and non-core Permian assets held for sale. Excluding these and other smaller items, adjusted net income for the Q3 was $370 million, or $1 per share. John noted in his remarks that we have revised the expected timetable for cessation of production and abandonment of our assets in the North Sea. This decision had three primary impacts this quarter. The previously mentioned after-tax asset impairment, of which $325 million was related to the North Sea, a 17 million bbl of oil equivalent write-down of reserves that we no longer expect to produce, and a $116 million increase in the net after-tax present value of abandonment obligations on our balance sheet. We now carry an after-tax present value liability of $1.2 billion for all of our North Sea ARO. We are planning to incur this liability between now and 2038. Approximately half of this liability will be incurred between now and the end of 2030. While there will be some overlap, the next five years will consist of mostly wellbore abandonment, while the remaining eight years will focus mostly on facility abandonment. We expect Beryl Bravo will be the first facility to cease production, likely in late 2027 or early 2028. Moving over to Egypt, we continue to make good progress on past due receivables, and during the quarter, both total and past due receivables decreased. When payments on past due receivables are made, there is a counterintuitive impact on our stated free cash flow for the quarter because of the way we define free cash flow for the purposes of our 60% cash returns framework. If you have questions about how to model these cash flows, please work with Gary and his team. Debt reduction is a continuing area of focus at APA. While total debt increased with the Callon acquisition, one of our goals is to liquidate the Callon debt as soon as possible. We made progress on this front in Q3 and will continue to do so in the coming quarters. The Callon deal brought increased scale in the Permian, which, coupled with our commitment to return to pre-acquisition debt levels, was a significant factor in our recent credit rating upgrade by S&P. To close, I would like to provide a bit of color on some of our changes in our Q4 and 2024 full-year guidance. Our full-year capital budget has increased to $2.75 billion, which primarily reflects increases to Q4 spend on development capital in Suriname following the October project FID, our recent decision to drill another exploration well in Alaska this winter, and the addition of a 12th rig in Egypt. These items, which were previously not contemplated in our guidance, were partially offset by the reduction of one rig in the Permian Basin. Turning to our U.S. production guidance, you'll note that we have adjusted our Q4 outlook to reflect the estimated impact of frack activity deferrals and planned production curtailments. With much weaker than expected Waha pricing this quarter, we decided to curtail gas from our Alpine High area, as we typically do. We also decided to curtail some high-volume, high-GOR oil wells, which will generate higher revenue under a more constructive future gas price. We currently project this will have a 20,000-25,000 BOE impact on U.S. production. However, this estimate is subject to considerable volatility depending on how regional gas prices progress through the Q4. As most of you are aware, our income from third-party oil and gas purchased and sold is generally correlated to Waha price differentials. Accordingly, with the persistence of weak pricing into the Q4, we are raising our full-year estimate to $500 million, approximately 2/3 of which is attributable to our gas trading activities and 1/3 is attributable to the Cheniere gas supply contract, and to close, most of our $250 million Callon synergy target should be realized by the end of this year. We anticipate reaching full synergy realization through 2025, and we do not plan continued reporting on these efforts from this point forward, and with that, I will turn the call over to the operator for Q&A. Thank you so much, and as a reminder, to ask a question, simply press star one one on your telephone and wait for your name to be announced. To remove yourself, press star one one again. We do ask you to keep your questions to one and one follow-up. One moment for our first question, and it comes from the line of Doug Leggett with Wolfe Research. Please proceed. Thanks, guys. Good morning. Well, Steve, there's a lot this quarter, so I'm going to hit two. One is Egypt, and one is the oil guide. So first of all, in Egypt, you obviously haven't given any color whatsoever around the gas price, other than the fact that you got better pricing. So to what extent can you help us frame the impact of this? I guess it costs you about, I don't know, $25 million, $25 million net for that additional rig. How do we think about the incremental free cash flow based on your current visibility on that gas price? That's my first one. My second one is clearly the oil guide has got a lot of moving parts, not least the sale of the Central Basin Platform. Can you just walk through the moving parts on the apples-for-apples acquisition versus disposals to get us to kind of net number just to make sure that the street is looking at it on an apples-for-apples basis? And I'll leave it there. Thanks. Yeah. Two really good questions, Doug. I'll step in first on Egypt, then let Steve follow up, and then we can come back to the Permian and the oil guide. But if you step back in Egypt and the Western Desert, we've historically always explored for oil. Obviously, the country of Egypt is now in a position where they need gas. S o we've been working on a framework which would bring gas exploration wells up to parity with oil wells. It is on incremental volumes. We're not in a position to get into a lot of detail on how that is calculated, but you will be able to see it showing up on our income statement going forward. We've allocated one rig. We've got a lot of low-hanging fruit, as you know. If you step back and look at the Western Desert, well, we've always run oil exploration programs. We found Qasr, which was a 3 TCF field back in the early 2000s. So there's tremendous potential for gas in Egypt. We've got a lot of low-hanging fruit. This will be on incremental gas volumes, and it's going to put our exploration program on par with an oil program. Yeah. So what we mean by incremental gas volumes is, as part of the agreement, we've agreed with EGPC what our PDP decline looks like for the full development or the full remaining life of the concession. So gas, PDPs, a decline curve. And for every quarter, we'll look at how much gas was produced, and any gas over that decline curve in that quarter gets the new price. It doesn't have to be from new wells. It doesn't have to be from new fields. So gas compression can bring on more gas volumes, enhanced recovery, step-outs, in-field step-outs, and infill, things like that all qualify for incremental gas volume. As John said, we've priced it to where we're indifferent economically drilling an oil well or drilling a gas well and as part of that agreement, we agreed to add one rig. As we've said, we have already done that. I would just say we've got just to build on what John was saying, we've got 5 million acres of hydrocarbon-rich resource here. There's been, as John said, no gas-focused exploration. So we believe that there's quite a bit of prospectivity. We've actually got some previously discovered gas-focused resource. Some of that may need some appraisal, but there's quite a bit that's ready for appraisal and development investment. Infrastructure is in place because we do produce a lot of gas today. There is some ullage in that infrastructure and to the extent that we might need it in the future, any further build-out of infrastructure was contemplated in the price that we negotiated. I don't know, Tracey, if you want to talk about maybe a little bit about prospectivity for gas in Egypt. Sure, Steve. As John and Steve said, we've really focused our exploration program on oil. So gas is really underexplored relative to oil, but we see significant potential. We have a good understanding of the geology and the source rocks having been there for two decades, and we know the areas that are more gas-prone and the basins that are more gas-prone. So we do have a known inventory of low-risk resource potential with material volumes. And in addition, we will be testing some exploration gas prospects and concepts to continue to grow that inventory over time. So we see a lot of potential in those opportunities, and we're excited to have a gas-focused program. It's a great opportunity to grow the inventory and add value to our business in Egypt. Yeah. Doug, just to wrap that point up, that question. So we're not going to share specifics about a gas price agreement with Egypt. We're not going to do that at this point in time at their request. You will start to see this show up in results. We'll think about. I understand your point about wanting to get to how do we forecast free cash flow if I don't know a price. We'll start thinking about how between now and February, when we give a final plan for 2025 and possibly beyond, we'll give some help in being able to figure out what this means for free cash flow. We understand the point. If I can take the second question, Doug, on the Permian oil, we've been running nine rigs. We've scaled back. We're at eight rigs, and that's what we plan to run for next year. If you take our Q3 numbers, which we just put out, 143 on the oil side for Permian, and you subtract the upcoming asset sales of 13,000 bbl a day, that's going to put you around 130,000. We believe we can maintain that or hold that flat with a rig count that's down about 20%, turning lines that are down 20%, and CapEx, which is in line with that. We think it's actually pretty strong. For next year, you're looking at, and this is obviously the preliminary view, as you know, we're looking at about 130,000 bbl a day of oil in the U.S. that we can hold flat with eight rigs. Got it. Thanks, guys. I appreciate the answers. Thank you. One moment for our next question. It's from John Freeman with Raymond James. Please proceed. Good morning, guys. Good morning, John. The first topic, just a little bit more info on the North Sea. So just want to make sure that I'm understanding. So the way that you laid it out, Steve, of the ARO, you said about half would potentially be spent between now and the end of 2030. And I guess I'm just trying to understand in terms of just outflow of capital as y'all ratchet down the CapEx in the North Sea over the next several years, and then factoring the AROs, just sort of how I should think about just capital being spent total in the North Sea over these next handful of years. I mean, I know it's a minimal spend CapEx-wise in the North Sea next year, but just any color on that front would be helpful. Yeah. So the spend on the ARO won't show up as capital. You'll actually see a number in the costs incurred. We provide some reconciliations to GAAP versus non-GAAP reconciliations in our supplement and you'll see a number in there for the North Sea for the addition to the ARO. So from a GAAP accounting purposes, the increase in the ARO is considered costs incurred, which is a GAAP kind of equivalent or somewhat equivalent to capital spending. So it shows up when you add to the ARO, and it doesn't show up as capital spending in the CapEx program as we spend that capital or those dollars in the years in which we incur the ARO. John, just to give it maybe a little bit more color on the spend patterns. So as I said, if you were to combine two numbers, because there's a gross obligation on the liability side on our balance sheet, and then there's a deferred tax asset because there's a 40% tax savings for every dollar that you spend on ARO. So there's two numbers on our balance sheet. Those two numbers net to $1.2 billion. And with a 40% tax rate, you could probably figure out pretty quickly it's about $2 billion of liability. It's about a $800 million tax asset on the balance sheet. And that $1.2 billion, as I said, roughly 50% of that will be spent between now and the end of 2030. A lot of that is being spent on wellbore abandonment. And so you figure out, you figure, okay, well, that's about 100 million a year for six years. What I would say is the pattern grows through the period of time. So it's going to be way less than $100 million next year. In 2025, it starts kind of ramping up a little bit in 2026. The first three years are below $100 million a year. The last three years are above $100 million a year. That's perfect. I appreciate all the color on that. And then on the LOE, which y'all are indicating a pretty big decline next year, 10%-15% decline. And you mentioned the drivers, and there's obviously a lot of moving parts with the Callon synergy, the other non-core Permian divestitures or curtailed volumes. Is there any way to give maybe just sort of a rough kind of idea of just ballpark, like the magnitude of each of those from a driver of that decline year-over-year, just some way to think about? Yeah. I mean, John, we really haven't thought about how to break that out. I mean, what we've tried to do is just look at the standalone business next year as you're going into that and roll everything up. Obviously, a big chunk of that is on the Callon side is the synergies we've been able to drive out. But a lot of it comes to just the change in the portfolio changes that we've made in the U.S., selling the higher cost, declining water flood assets on the Central Basin Platform, which are typically much, much higher cost. We handle a lot of water. So it's really a recharacterization of our unconventional Permian Basin business is what you're going to see. And I can also tell you we're working hard on how to do more than what we've laid out at this point. Yeah, and I'd just add, John, we'll provide quite a bit more detail around that when we roll out the detailed plan in February. What we always try to do at this point in time in the year is just kind of give a shape to the capital program and what that means to production volume more than anything else, kind of the meat of the direction of the firm. But there is that one chart in the supplement, and it's got multiple elements in it. You might want to just give Gary a call later today or sometime, and he might be able to take you through some of the details behind that. Understood. Thanks, guys. Thank you. Thank you, John. Our next question comes from the line of Bob Brackett with Bernstein Research. Please proceed. Good morning. I had a question around the cadence of the cash return strategy and kind of the timing. There's a big moving part around your disposals and getting that cash in the door and Q3% of free cash flow return came down a bit. Should I think of that as timing versus anything else? Yeah. I mean, definitely, it's just timing, Bob. We came into the year. We're running a little bit ahead. And then you look at Q3, we've had a lot of material things that were in the works that can sometimes prevent you from being able to get in the market at times. But in general, yes, it's more just timing that was kind of out of our control. Very clear. Quick follow-up on gas curtailment and your latest thoughts or on-the-ground intelligence around Matterhorn. Matterhorn feels slow, but it's coming. Is that your expectation that we'll get some takeaway out of the Permian, realizations will improve, and that's when the curtailment ends? And what's your latest that you hear happening in the basin? Yeah. I believe most of the price extremes, if you want to call them that right now, are not related to Matterhorn but are related to some downtime on other pipelines coming out of the Permian and to the Gulf Coast, and I think that's impacting the pricing extremes as we see them today. That maintenance activity, I believe, is planned to be completed in the next week or so. So I think this is a matter of perhaps just days. First of month for December a couple of days ago was $1.40. So not a great price, but at least better than - $3 or $3.50. Very clear. Thank you. Thank you, Bob. Thank you. Our next question comes from the line of Roger Read with Wells Fargo Securities. Please proceed. Yeah. Thank you. Good morning. I guess I'd like to come back on the lowering of the cost. I mean, it looks obviously a piece of it LOE, but a lot of it G&A, and what is that, or is that in addition to the synergies you anticipated from the Callon merger? I mean, I would think so given the way it's laid out here, but I just wanted to understand what was driving some of these opportunities. I mean, I think, Roger, it's clearly synergies on the Callon side, but it's also some of the simplification on our business with the asset sales. Yeah. And the other thing I would just add, in our synergies around the Callon transaction, we said that around $90 million of that would be related to G&A, and Callon had a G&A cost structure of around $110 million a year. Our G&A right now is running basically flat with where we were prior to the Callon acquisition. So I think some of the G&A synergies are going to be around just growing, increasing, or exceeding the amount of synergies that we thought. It's not all Callon people because we actually have a number of Callon people here in the company, but we've equivalently eliminated the full Callon G&A. There were some one-off costs in G&A in 2024 around the transaction as well. Yeah. No, I appreciate that. And then, John, my question for you since you've got the Alaska exploration well, and obviously all those decisions had to be made pre-election, but in terms of regulatory outlook, certainly it looks easier to do business in Alaska with the federal government at this point. Just wondering how you're looking at that. Assume good or bad with this particular well, but as you think about the overall Alaska opportunity. Yeah. I think the main thing there, and I'll remind you, Roger, is we've got about 300,000 acres in our possession, but it's state lands. And so we're in a position where you're fairly close to pipeline, and we're state lands. So you don't really have to bring the federal side in, but just on a few things. So we feel good about that. We're excited about Alaska. We had a discovery earlier this year on the well that we did get down and we're going back to one of the two that we attempted last winter, but we're very excited about it. So it'll be early, early next year when we spud, and we have added some capital. We'll start building ice roads and stuff for this winter. Yeah. Appreciate that. But one federal roadblock is sometimes more than enough. So I just wanted to check on that. Thanks. Yep. Thank you. One moment for our next question that comes from the line of Paul Cheng with Scotiabank. Please proceed. Hi. Good morning, team. John, you guys done the Callon deal, even though I think Apache probably do better than Callon. But when you go through that, have you found there's anything that you learned from them saying that, "Oh, they're actually doing better than us," and where that they probably have done the worst? Yeah. I mean, obviously, Paul, when you integrate two companies, you take good from both and try to replicate. I think Callon had some good people that we've integrated into the organization. Obviously, they've got some good acres that we're excited to get after as well. And then we've been digging into a lot of their technical assumptions as well. But I think in general, you've seen us be able to cut costs just from our supply chain and some of our processes. We've cut almost $1,000,000 per well in terms of the well cost side. We're anxious on the spacing, and we've got two wells flown back. We're actually four now, but two we've got pretty good results on in the Midland Basin. And we're seeing some pretty good uplift on those two. So we're pretty excited about Callon in general. [crosstalk] Go ahead, Paul. Please. No, I was just asking that, is there anything that from a technology or process that Callon, you actually found that they are doing well, and then you will be able to adopt their process or technology and enhance your operation? Yeah. Yeah. I would say on the spacing side, I mean, we're looking hard into the data and how they were approaching the development scenarios and how we take how we designed it versus how they were and how do you modify that to what we think is a better answer. Yeah. And if I could just add to that, that's where I was going to say earlier was that it'd be really simple just to bring all of that acreage into the Apache process and just assume, "Well, we're right. We've got everything figured out, and we're going to do it exactly the way we do everything else." Instead, I think it's always a good idea to just step back and think, "Okay, well, do they have any aspects of spacing and fracking and landing zones and what's in communication, what's not in communication?" So it's good just to take the opportunity to step back and question what we believe and our fundamental beliefs there as well and we're doing that. And I think it's worth doing. We'll come to some conclusions in due course, but it's worth asking ourselves those questions. Steve, can you quantify what's the benefit? Because I assume those are not in your original synergy target. No. At this point, I'd say I can't quantify the benefits of that, but we'll do that in due course. I think we've got to get more wells drilled, completed, and online, and get some history to those. And we've talked about it in the past. At some point in time in 2025, we have the $250 million of annual cash operating and overhead-type cost synergies, but we do believe that there are some meaningful synergies around the capital productivity or capital efficiency, whichever you want to call it. W e've said in the past, we will come back sometime in 2025 with a recap of where we think we are there. That will include, just like the synergies have included, that will include things that we've learned from the combination with Callon and how that helps even the Apache approach to the rest of our acreage as well. Okay. The second question is on Alaska. John, you guys are going back, and can you tell us that you guys essentially going back to the same two wells that you suspend in last year's program, and you're just going to redo that, or that you are targeting a totally new prospect? No, Paul. It's actually going back to the Sockeye prospect is what. Please stand by. We have some technical audio difficulties. Please stand by, ladies and gentlemen. Please continue to stand by, ladies and gentlemen. Thank you. Thank you for continuing to standing by. One moment, please. And you may continue. Thank you for standing by. Okay. Yes, you are live. We're back up. Apologize. We had an internet disconnect, but we're back, so. So one moment for our next question, please, and it comes from the line of Neal Dingmann with Truist. Please proceed. Good morning, guys. Thanks for the time, John. My question, maybe just around Permian Egypt production specifically, the target you talked about for next year, the eight Permian and 12 Egyptian rigs. I'm just wondering, is that, again, kind of the plan to maintain? You think that's about appropriate to maintain stable production in both those areas? I'm just wondering, when it comes to base production, has that changed much in either area? So I'm trying to get a sense of how we should think about sort of maintaining the flat production. Yeah. We've designed that. The early look designs are programmed to sustain Permian oil, Neal, around the 130 that I mentioned earlier with Doug's first question and then in Egypt, it's really our reported production, but the gross has been coming down slightly. If you look at it on the oil side, with 11 right now, you've got 12 rigs, 11 to the oil program, one to the gas is what we've got in there. At 11, we're slightly under-investing in Egypt, but it's close. Yeah. If I can just add to that briefly, I mean, we started the year with, as people know, we started the year with 18 drilling rigs. We ended the year with 12. We went down to 11 at one point in time. If you just look back at the when we said that gross oil volume would slightly decline as we go through the year, well, Q1 was 138,000 bbl a day. Q2 was 139,000 bbl a day and Q3 was 137, 000 bbl a day. So we're on a slight decline. I would emphasize the slight aspect of that. And I think that that's probably going to just continue into Q4 and on into 2022, absent a change in the drilling activity. But that's if people go back to 2023, we were in the mid-140s with 18 rigs running for quite some time, and we were kind of struggling to maintain production volume or to grow it from there. So as we've commented a few times, with 11 rigs, we've achieved kind of a nice, very smooth operational cadence that's working really well. We have increased that to 12. The thing I would say about 2025 is that the 12th rig is drilling gas-focused wells, and some of those will be appraisal. Some of them will be development wells. Some will be low-risk appraisal type of step-outs. Some of them will be exploration, looking for bigger, better prospects, which we believe they are out there and so the potential for gas, I would say, is unknown at this point in time. We're certainly optimistic. We believe there's good prospectivity, but the potential is still a bit unknown. The other thing I would say is that in the last, I would say, last year and a half, we've learned a lot about what we can be doing around improving our focus on water flood management, and we've got a lot of plans in 2025 for working that, and I think the potential for that, we have yet to really see what that can do on a decline mitigation basis. The best way to maintain production volumes in a country like Egypt is to mitigate decline, not to be trying to drill too many wells, so we're working on both fronts, and we'll see what 2025 brings, but if everything is kind of equal with 2024, we'll probably just continue on this pattern of just slight decline. Got it and then just a second, you talked a bit about this already today, but just with share return, I mean, you guys in other periods where the stock has gotten hit have been very opportunistic, coming in pretty aggressively. I'm just wondering, given recent pricing, is that potentially in the cards? Well, I think clearly we've got our time periods fastest. We're running ahead, Neal, but we do think the share price is obviously attractive. We've got the proceeds coming in from the asset sales. The majority of that's going to go to debt reduction as we're also working to get debt paid down as well. Thank you, John. Thank you. One moment for our next question. And he comes from the line of Arun Jayaram with JP Morgan. Please proceed. Yeah. I wanted to go back to Egypt and gas. Steve, you mentioned that over time that you can make up, called the PDP wedge, with incremental volumes where you'd get the higher gas price. I was wondering if you could help us think about what the PDP decline rate looks like for gas in Egypt and the Qasr field specifically. Yeah. Arun, I'll take that one. Qasr's been on decline. We've gone through some stages of compression. It is the big portion of our gas is Qasr, but we also produce a lot of casing head gas with a lot of the other oil wells. So Qasr's been in the double- digits there and obviously, we'll have to see with the new program, can we fill the overall gas decline? But I think we've got an opportunity to add some incremental volumes that could be pretty material. Understood. And then just maybe a follow-up, John, with the North Sea now in kind of a late cycle stage in terms of the life cycle of that development, the field. And then obviously, Suriname starting up in 2028. How are you thinking about another leg to the stool in terms of the portfolio? Obviously, sold some assets recently, but how are you thinking about just the broader portfolio? And And obviously, given the North Sea where it's at, adding another leg to the stool? Yeah. I mean, I think if you step back, we've got what we believe are two really strong long-term legs of the stool with both Permian and kind of our reshaped and reworked Permian unconventional business. We think we can hold that flat at a very efficient rig count for the foreseeable future. Egypt is a large asset. We've been there now for over three decades. We see a lot of running room in Egypt as well. Suriname will start to come on in 2028 and will be very material. And so if you step back and look at that and we just maintain the two large onshore positions, 2028, Suriname's going to put in some pretty nice growth relative to those two assets. So I mean, I think portfolio's in pretty good shape. We're always looking to how we improve it. But I think we've got with Suriname stepping in and coming on in 2028, it's going to be a nice add to what are two really nice core positions, both in the Permian and the U.S. and Egypt. Understood, p lus the exploration in Alaska and Uruguay. Absolutely. And I think the key there, Arun, is we've stayed committed. We've been spending a small portion of our budget in exploration. I think we've got a wonderful staff and as I said in the prepared remarks, with successful exploration, you can add real shareholder value. Suriname Block 58 is a perfect example of that. So we've got a nice portfolio. We're excited about it. We'll continue to fund a little bit, but we also know where we make our real money is in our core assets and driving our free cash flow from Permian and Egypt. Great. Thanks a lot, John. Thank you so much. One moment for our next question that comes from the line of Charles Meade with Johnson Rice. Please proceed. Good morning, John, to you and your whole team there. I wanted to ask a question about. Good morning, Charles. Yeah. Thank you. I wanted to ask a question about Suriname. And you put this slide in your supplement on Slide 11. And I like these kind of mock-up cartoons that give a sense of the development layout. But when you guys decided to include this, what, besides the numbers on the far right side of the slide, do you really hope people take away from this when they see this? And what's the so what you want people to get about the GranMorgu? I mean, I think it's just given it's a real project today, right? So I mean, we've got visibility now to volumes in 2028. And so I think it's time that you put some slides out there that bring it to life. And that's why we put the picture out there. You can see this is kind of looking from deep water in. You'll see where the FPSO will be placed. This is a Total slide. You see with Krabdagu, it's a fairway, as we've talked about, in terms of the development opportunities that we've appraised there. And looking over at Sapakara, it's more of a field. The thing I would also say along that fairway is there will be more exploration prospects and potential tiebacks as well. So it's something we're excited about. It's material. It's large. But I think it's just bringing this project to life because it's real today and we're looking forward to 2028. That's great. That's it for me. Thank you, John. You bet, Charles. Thank you. Thank you so much. One moment for our next question that comes from the line of Leo Mariani with Roth. Please proceed. Hi, thanks. Just wanted to inquire a little about the kind of activity plan in the U.S. It sounds like you guys are basically kind of pulling back there. Oil's roughly at $70. You guys are kind of citing a softer oil outlook. Just kind of curious, are you expecting kind of oil prices to be lower next year? I mean, obviously, you just bought the Callon asset. You saw some pretty nice organic growth the last couple of quarters on a combined basis, and now you're kind of choosing to pull back. Can you just provide a little bit more color on sort of the thinking there as we roll into next year? Yeah. Leo, I just think we're in a softer price environment. We've got an asset base that we can sustain volumes with eight rigs. We're going to work on efficiencies. It's always easy to pick those rigs up, but I think with where we're moving into 2025, it feels like a good place to be initially. And the nice thing is, like I said, if we can sustain Permian and roughly sustain Egypt, you've got Suriname coming in the next 2028 from an overall corporate level. Okay, and then maybe just jumping over to Egypt here, so I think you guys made a comment there on the call that you expect that we could see some very modest declines on Egyptian gross oil. I know you're expecting to kind of keep adjusted or sort of net production on oil relatively flat, so maybe you're expecting to get a slightly higher share of that oil. I don't know if that's just related to expectations for lower prices and the PSCs for next year. I was hoping you could kind of address that quickly, and then also just on Egypt gas, you got the gas rig going. What's your expectation there on gas production in Egypt for next year? Can that start to flatten out maybe in the second half? Do you see any growth in Egypt gas as we get towards the end of the year or next year? Yeah. I'd just say if you look in Egypt at 11 rigs, as Steve mentioned, we've been declining slightly at the top line. It's been very, very slight over the last four quarters. So at 11, it's about where we probably are on the gross oil side. We're actually getting after some of the water flood projects as well, which the benefit those have is they flatten your decline. So then with a strong water flood program, then you can improve that. And then on the gas side, our overall gross gas is declining. But with this program, and we've got a one-rig program laid out and some nice quick prospects to get after that we can get the infrastructure, we'll bring new volumes on, and then we've got some bigger prospects to drill, and then we'll see. So I think the key there is we're getting started with that. After we get some prospects down, we'll have a better clue of scale on the gas side in the future. All right. Thanks. Thank you. Thank you. Our next question comes from the line of Betty Jiang with Barclays. Please proceed. Hello. Good morning. Thank you for taking my question. I want to go back to the North Sea ARO conversation. So I think the $1.2 billion is on a present value basis. So wondering if you could give the total liability on the absolute basis. And I think as we think about the cash outflow related to this, does your free cash flow calculation include this outflow as you think about the capacity for cash returns in any given year? Thanks. Yeah. So I've already given you two numbers. I'll give you a third number as well. So again, the two numbers I've given are that we've got about a $2 billion liability on our balance sheet. U.S. GAAP requires that we take what we think the current cost is of abandoning all of those assets as if we had to abandon them today. We inflate that into the future, and then we discount that back at prescribed inflation and discount rates. So when you take the cost today, inflate them, and then discount them back, you get $2 billion. The today cost estimate is $2.5 billion. So obviously, the inflation rate is lower than the discount rate that we have to use for that, which is our borrowing rate for that 10-15-year timeframe. Then there's the tax benefit of all of that. The present value of that tax benefit is $800 million. So that's offsetting the $2 billion present value and getting to the $1.2 billion net, which is a net after-tax present value liability on our balance sheet today. Two different numbers on the balance sheet, $2 billion liability, $800 million deferred tax asset. What was the second part of the question? Just on the free cash flow calculation, when you think about the organic free cash flow that's related to cash return, does this cash outflow get netted out of that? Yes, that will. And I think. Appreciate it. Let's just remember, we've talked a lot, and I understand why we've talked a lot and kind of focused on the abandonment activity that's ahead of us and the costs associated with that. Let's just not forget that we still have operating assets in the North Sea. Those continue to generate free cash flow even after a 78% tax rate. And that free cash flow will help us pay for a lot of those costs here in the next several years. Thank you for that. My follow-up is on the gas marketing piece. This year, really surprised with how powerful the benefit on the gas marketing side in the weak Waha gas environment. Can you give us a flavor of, under the current futures price on Waha spread, would you be able to continue to capture above-normal marketing benefit next year as well? Yeah. That's just going to depend a lot on what happens with Waha as we go through next year. And it's not absolute Waha prices. It's the differential between Waha and Gulf Coast versus the cost to transport. Fairly simple. If there's a $2, if I use fake numbers, if there's a $2.50 spread and there's a $1 cost to transport, then you're making a $1.50 on nearly 750 million cu ft a day that we buy and transport to the Gulf Coast. And it'll all depend on what are those spreads for 2025. And as we've experienced here in 2024, they can be extremely volatile. Even over short periods of time, like for a weekend, we can find that for a weekend, prices can go negative for three or four days, as much negative as - $5, which means when we're purchasing gas over the weekend, people are paying us $5 to take gas, and then we transport it for our transport costs, which we can't disclose, but you could probably figure out what it is, and we sell that on the Gulf Coast for what would normally be a positive price, a little less volatile pricing on Gulf Coast than you get at Waha. Certainly nice to have that pipeline right now. Just to clarify, the Gulf Coast benchmark, are you looking at Houston Ship or it's a combination of different hubs? Yeah. It would be looking at mainly Ship Channel or depending on where the pipe takes you back to. Okay. Got it. Thank you. You bet. Thank you, Betty. Thank you. Our last question comes from Jeoffrey Lambujon with TPH & Co. Please proceed. Good morning, guys. And thanks for squeezing me in here. Really just a quick follow-up to your commentary on the North Sea. A couple of questions ago just around the free cash generation that you mentioned. Can you also help us understand what your outlook is for OpEx from that asset as production declines into next year and onward just to kind of help us tie that in along with the ARO dynamic that you already walked through? Thanks. Yeah. We'll probably go into more detail on that in the February call. We're just not at this point in time, like we say, we normally at this time of year give a view to the capital program and production volumes and the general overall direction of the company. And that, as we've highlighted with this conversation, is generally dominated by the longer-term oil price outlook. So that's all we really typically look to accomplish on the November call. We'll give more details around country-by-country specifics and the line items between revenues and LOE and breakdown of capital and things like that in February. I can tell you, though, that the North Sea is a because of the situation we're in in the North Sea, and we talk about it openly that we're in the business now managing operations, day-to-day operations for free cash flow now. Practically any type of capital investment is not economic under the current situation, and so we manage that for free cash flow, and we will look hard at operating costs, and we are looking hard at operating costs. We never do so in a way that sacrifices or puts at risk either human safety or the environment, but there's a lot of stuff that we spend money on that could be looked at and examined just to make sure that we're spending properly in an environment where we're just focused on free cash flow for the remaining life of the asset, so we'll get into more detail of that in the February call. All right. Thank you. Thank you. And with that, I will close the Q&A session for today and turn it back to John Christmann, our CEO, for closing remarks. Yes. Thank you. F irst of all, I want to apologize for the internet disconnect that we had during Paul's question. But in closing, as we've outlined, we've made great progress on the portfolio, and the assets are performing at a very, very high level. We have significantly scaled and streamlined our Permian unconventional position. We're adding a potentially very valuable gas program in Egypt and now have a clear timeline to significant production and cash flow in Suriname. Going into 2025, we are looking at a potentially softer oil price environment and are focused on sustaining our core business, reducing costs, and generating free cash flow. We provided an early look at a plan of eight rigs in the Permian and 12 rigs in Egypt, which should broadly sustain oil volumes at reduced capital levels. We will continue to work this plan and look forward to coming back to you in February with a lot more details. Thank you for joining us. With that, ladies and gentlemen, we thank you for participating in today's conference. You may now disconnect.