APA Corporation

Good day everyone and thank you for standing by. Welcome to APA Corporation's Third Quarter 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 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 Vice President of Investor Relations, Gary Clark. Please go ahead.

Good morning and thank you for joining us on APA Corporation's Third Quarter 2024 Financial and Operational Results Conference call. We will begin the call with an overview by CEO John Christman. Steve Reine, President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer your questions are Tracy Henderson, Executive Vice President of Exploration and Clay Bratchess, Executive Vice President 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 .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 discussed 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 first quarter APA results on a standalone basis plus three quarters of APA and CalEN 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 third quarter 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 US, 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 rig count today is lower than APA and CalEN 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 cashflow 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 counter cyclical investment in long cycle offshore exploration. The recently announced Grand Morgue 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 cashflow, allowing us to maintain our current capital returns framework. Turning now to the third quarter results and highlights, APA achieved several important milestones during and subsequent to the end of the third quarter. 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 Total Energies. 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. Third quarter results were strong across the board as we exceeded our production guidance while capital and costs were below guidance. Cashflow from operations and free cashflow increase compared to the second quarter, 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 Calon and associated cost synergy capture, cashflow resilience to lower prices in Egypt under the PSC structure, near term organic oil production growth, strong cashflow from our LNG contract and having the optionality to curtail US volumes when Waha pricing is negative while still generating cashflow 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 fourth quarter. Turning now to our key operational areas. US oil volumes have now met or exceeded guidance for the seventh straight quarter. Since closing the Calon 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 Calon and turned our focus to developing the acreage. Our initial wells on acquired Calon acreage are flowing back in the Midland Basin and the early results are encouraging. The first wells on the Delaware Basin on Calon 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 work over rig fleet to reduce backlogged oil volumes associated with delayed re-completions and work overs 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 CERNOM, 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 barrels per day of production capacity, a per BOE capital plus OPEX cost of $19, and a 15% IRR at $60 per barrel. 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 CERNOM development capital out of operating cashflow 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 third quarter, production volumes were in line with guidance as we completed our platform maintenance turnaround at barrel as planned. Earlier this year, the UK 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 40s and barrel, 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 US, Egypt and North Sea will likely be in the range of 2.2 to 2.3 billion dollars 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, GNA, GPT and interest costs to fall by 10 to 15% year over year. In closing, we have made very good progress on our strategic portfolio initiatives in the US, Egypt and Suriname. We had an excellent quarter operationally and achieved all key guidance targets. The Calon integration is complete, most of the cost synergies have been captured and we look forward to demonstrating the potential of the acquired Calon 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 third quarter, under generally accepted accounting principles, APA reported a consolidated net loss of $223 million or 60 cents 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 third quarter 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 barrel 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 well-bore abandonment while the remaining eight years will focus mostly on facility abandonment. We expect barrel 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 Callan acquisition, one of our goals is to liquidate the Callan debt as soon as possible. We made progress on this front in third quarter and will continue to do so in the coming quarters. The Callan 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 fourth quarter in 2024 full year guidance. Our full year capital budget has increased to $2.75 billion, which primarily reflects increases to fourth quarter 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 US production guidance, you'll note that we have adjusted our fourth quarter outlook to reflect the estimated impact of frac activity deferrals and planned production curtailments. With much weaker than expected WHA 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 to 25,000 BOE impact on US production. However, this estimate is subject to considerable volatility depending on how regional gas prices progress through the fourth quarter. As most of you are aware, our income from third-party oil and gas purchased and sold is generally correlated to WHA price differentials. Accordingly, with the persistence of weak pricing into the fourth quarter, we are raising our full year estimate to $500 million, approximately two-thirds of which is attributable to our gas trading activities, and one-third is attributable to the Chenier gas supply contract. And to close, most of our $250 million Carolyn synergy target should be realized by the end of this year. We anticipate reaching full synergy realization through 2025, and we did 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 1-1 on your telephone and wait for your name to be announced. To remove yourself, press star 1-1 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 Doglegged. With Wolf Research, please proceed.

Thanks, guys. Good morning. Well, I've seen 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've obviously, you 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 net, 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. So 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? I'll leave that, thanks.

Yeah, two really good questions, Doug. I'll step in first on Egypt and 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, you know, we've historically always explored for oil. Obviously, the country of Egypt is now in a position where they need gas, and so we've been working on a framework which would bring, you know, 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, you know, on how that is calculated, but you will be able to see it, you know, showing up on our, you know, our income statement on 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 where we've always run oil exploration programs, you know, we found Kasser, which is a 3TCF 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, you know, 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 till, you know, 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, you know, gas compression can bring on more gas volumes, enhanced recovery, step-outs, infield 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. And I would just say, you know, we've got, you know, just to build on what John was saying, we've got five 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 still 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. And I don't know, Tracy, 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've had 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. And it's a great opportunity to grow the inventory and add value to our business in Egypt.

And 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 just 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 see. We'll think about I understand your point about wanting to get to, you know, how we forecast free cash flow. 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 some help in being able to figure out what this means for free cash flow. We understand the point.

And if I can take the second

question, Doug, on the, you know, Permian oil. You know, 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 barrels a day, that's going to put you around 130,000. And, you know, we believe we can maintain that or hold that flat with a rig count that's down about, you know, 20 percent, turning lines that are down 20 percent and cap X, which is in line with that. So we think it's actually pretty strong. But, you know, for next year, you're looking at and this is obviously the preliminary view, as you know, we're looking at about 130,000 barrels a day of oil in the U.S. that we can hold flat with eight rigs.

OK, thanks, guys. I appreciate the answers.

Thank you. One moment for our next question. It's from John Freeman with Raymond and 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 understand. So the way that you laid it out, Steve, of the ARO, 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 you all like ratchet down the cap X in the North Sea over the next several years and then factoring in the ARO is just sort of how I should think about just capital being spent total in the North Sea over these next 10 years. When I know the minimum, it's a minimal spend cap X wise and the North Sea next year, but just any color on that front would be helpful.

Yeah, so the the spend on the ARO won't show up as capital. You'll you'll you'll actually see a number in the. You know, the costs incurred where we we provide some reconciliations to gap versus non gap 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 gap accounting purposes, it's the increase in the ARO is considered costs incurred, which is a gap 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 cap X program as we spend that capital or those dollars in the years in which we incur the ARO. And and John, just to give it maybe a little bit more color on the on the spend patterns. So, as I said, the the if you if you if you were to combine two numbers, because there's a there's a gross 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 percent tax savings for every dollar that you spend on ARO. So there's two numbers on our balance sheet. Those two numbers net to one point two billion dollars. It's you know, with a 40 percent tax rate, you could probably figure out pretty quickly. It's about two billion dollars of liability. It's about a eight hundred million dollar tax asset on the balance sheet. And that one point two billion, as I said, roughly 50 percent of that will be spent between now and the end of 2030. A lot of that is being spent on well, more abandonment. And, you know, so you figure out, you know, you figure, OK, well, that's about 100 million a year for six years. And what I would say is the pattern grows through the through the period of time. So it's going to be, you know, be way less than 100 next year in 2025. It starts kind of ramping up a little bit in 26. 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 all the color on that. And then on the on the .O.E., which, you know, you are indicating a pretty, pretty big decline next year, 10 to 15 percent decline. And, you know, you mentioned the drivers and there's obviously a lot of a lot of moving parts with the account synergies, the non-core permanent investors 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 like a driver of that decline year over year, just some way to think about?

Yeah, I mean, we know 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 Callum 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., you know, selling the higher cost, declining water, flood assets on the central basin platform, which are typically much, much higher cost. We had 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 there's, you know, we're we're working hard on how to do more than what we've laid out at this point.

Yeah, I just said, John. You know, we will provide quite a bit more detail around that when we roll out the detailed plan in February. What we're trying to do, 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 to production volume more than anything else. Kind of the meat of the direction of the of the firm. But there is that that one chart in the supplement. And you and it's got multiple elements in it. You might want to just give Gary a call later today or sometime. And he might take him to 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 bit moving part around your disposals and getting that cash in the door and three percent or three cash flow return came down a bit. Should I think of that as timing versus anything else?

I mean, definitely, it's just timing, Bob. We 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, you know, to get in the market at times. But, you know, in general, yes, it's more just timing that was kind of out of our control.

Very clear. A quick follow up on Gasker Tailman and your latest thoughts are 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 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. Those. That maintenance activity, I believe, is planned to be completed in the next week or so. So I think this is this is a matter of perhaps just days. You know, first of month for December, a couple of days ago was a was a dollar forty. So not not a great price, but but at least better than negative three or three fifty. Very

clear. Thank you.

Thank you, Bob.

Thank you. Our next question comes from the line of Roger Reed with Wells Fargo Securities. Please proceed.

Yeah, thank you. Good morning. I guess I'd like to come back on the lowering of the the cost. I mean, it looks, you know, obviously a piece of it, Eloy, but a lot of the GNA. And what is that or is that in addition to the synergies you anticipated from the Cali merger? I mean, I would think so, given the way it's laid out here. But I just want to understand what was driving some of these opportunities.

I mean, I think, Roger, it's it's clearly synergies on the Cali side, but it's also some of the simplification on our on our business with the asset sales.

Yeah. And the other thing I would just add, you know, in our synergies around the Cali transaction, we we we said that around 90 million of that would be related to GNA. And Cali had a GNA cost structure of around 110 million a year. Our GNA right now is running basically flat with where we were prior to the Cali acquisition. So I think some of the GNA synergies are going to be around, you know, just growing the increasing or exceeding the amount of synergies that we thought. We basically it's not all Cali people because we actually have a number of Cali people here in the company, but we've equivalently eliminated the full Cali GNA. There there were some some one off costs in GNA 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 looks easier to do business in Alaska with the federal government. At this point, just wondering if how you're looking at that, does, you know, it seems good or bad with this particular well, but as you think about the overall Alaska opportunity.

Yeah, I think the main thing there, I'll remind you, Roger, is, you know, we've got about 300,000 acres in our position, but it's state lands. And so, you know, we're in a position where you're fairly close to pipeline and, you know, we're state lands, so you don't really have to bring the federal side in. But, you know, just on a few things. So we feel good about that. We're excited about Alaska. You know, we had a discovery earlier this year on the well that we did get down. And, you know, we're going back to one of the two that we attempted last winter, but we're very excited about it. So it, you know, it'll be early, early next year when we get to the flood 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. Thank you. One moment for our next question that comes from the line of Paul Cheng with Scotiabank. Please proceed. Hi.

Good morning, Tim. Um, John, you guys done the Cowan deal, even though I think Apache probably do better than Cowan. But when you go through that, have you found there's anything that you learn from them saying that, oh, do they actually doing better than us and where that they probably have done the worst?

Yeah, I mean, you know, obviously, Paul, when you when you integrate two companies, you take good and from from both and try to replicate, I think Cowan had some good people that we've integrated in 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, you know, their technical assumptions as well. But I think in general, you've seen us be able to cut costs just from, you know, our supply chain and some of our processes. You know, we've cut almost a million dollars per well. In terms of the well cost side, you know, we're anxious on the spacing and we've got two, two wells flown back, or 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 Cowan in general.

No, yeah, just the

Yeah, sorry, please. No, I was just asking that if there anything that from a technological process that Cowan you actually find that they they are doing well, and then you will be able to adopt this process or technology and then enhance your operation.

Yeah. Yeah, I would say on the spacing side, I mean, we're looking hard into the data and, you know, how they were approaching the development scenarios and how we take how we how we designed it versus how they were and how do you modify that to what we think is a better answer.

Yeah, if I could just add to that, that's where I was going to what I was going to say earlier was that, you know, it'd be really simple just to bring all of that acreage into into the Apache process and just assume well, we're right, we're 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, you know, our fundamental beliefs there as well. And we're doing that. And I think it's worth doing. We will 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 is not in your original synergy target?

No, at this point, I'd say I can't quantify the benefits of that. But, you know, we'll do that in due course. I think we'll, you know, I think we've got to get more wells drilled, completed and online and get some history to those. And, you know, we've talked about it in the past at some point in time in 2025. You know, we have the 250 million of annual cash operational 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. And we've said in the past, we will come back sometime in 2025 with a recap of where we think we are there. And that will include, just like the synergies have included, that will include things that we've learned from the combination with Cowan 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 are essentially going back to the same two wells that you suspend in last year 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, you know, the sockeye

prospect is what we're

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So. So

one moment for our next question, please. And he comes from the line of Neil

Dingman with Truist. Please proceed.

Morning, guys. Thanks for the time, John. My question, maybe just around permanent Egypt production, specifically, you all, you know, the target you talked about for next year, the eight permanent 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? And I'm just wondering when it comes to base production, has that, you know, 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 we designed that, you know, the early look designs program to sustain Permian oil, Neil, around the 130 that I mentioned earlier when with Doug's first question and then in Egypt, you know, it's really our reported production. But the gross has been coming down slightly. If you look at on the oil side, it 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. You know, if you just look back at the when we said that gross oil volume would slightly decline as we go through the year, well, first quarter was 138,000 barrels a day, second quarter was 139, and third quarter was 137. So, you know, 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 fourth quarter and on into 2022. Absent a change in the drilling activity with that. But that's that's if people go back to 2023, you know, we were in the mid one 40s with 18 rigs running for quite some time, and we were kind of struggling to to maintain production volume or to grow it from there. So we've, as we've commented a few times, we've actually 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. You know, the thing I would say about 2025 is that the 12th rig is drilling gas focused wells, and some of those will be appraised, some 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 there are out there. And so, you know, 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 we 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've talked a bit about this already today, but just with shareholder return, I mean, you guys in other periods where the stock has gotten the hit have been very opportunistic coming in pretty aggressively. I'm just wondering, given recent pricing, is that potentially in the cards?

And I think clearly we've got our time periods fastest. We're running ahead, Neo, 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 is we're also working to get debt paid down as well.

Thank you,

John. Thank you. One moment for our next question. And it comes from the line of Arun Jaram 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 obviously in the costier field specifically.

Yeah, Arun, I'll take that one. It's costier has been on decline. We've gone through some stages of compression. It is the big portion of our gas is costier, but we also produce a lot of casing head gas with a lot of the other oil wells. So costier has 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, 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 you know, 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 obviously, you know, 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, you know, strong long term legs to the stool with both permeate our new, you know, kind of our reshaped rework, permeate 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 28 and will be very material. And so if you step back and look at that, and we just maintain, you know, the two large onshore positions, 28 Suriname is going to put in some pretty nice growth relative to, you know, those two assets. So I mean, I think portfolios in pretty good shape, we're always looking to how we improve it. But, you know, I think we've got 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 Caribbean and the US and Egypt.

Understood. Plus the exploration in Alaska near Guam. Absolutely.

And I think that the key there, Arun, is we've stayed committed. You know, we've been spending a small portion of our budget in exploration. I think we've got a wonderful staff and, you know, as I said in the prepared remarks, with successful exploration, you can add real shareholder value in Suriname Block 58 is a perfect example of that. So, you know, 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, you know, 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 Mead with Johnson Rice. Please proceed.

Good morning, John, to you and your whole team there. I wanted to ask a question about Suriname. Thank you. I wanted to ask a question about Suriname. You put this slide in your supplement on slide 11. 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 are you, you know, besides the numbers on the far right side of the slide, what 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 Grammo Group?

Well, I mean, I think it's just given, you know, 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, you know, 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 Crabdagu, it's a fairway, as we've talked about, in terms of the development opportunities that we've appraised there. And looking over at Sopocara, it's more of a field. You know, the thing I would also say along that fairway is there will be, you know, more exploration prospects and potential tiebacks as well. So, you know, 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, you know, 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.

All right, thanks. I just wanted to inquire a little about the kind of activity plan in the US. You know, it sounds like you guys are basically kind of, you know, pulling back there. You know, 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, you know, next year? I mean, obviously, you just bought the Callen asset. You saw some pretty nice organic growth the last couple 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, you know, there as we roll into next year?

Yeah, Leo, I just think we're in a softer price environment. You know, we've got an asset base that we can sustain volumes with eight rigs. You know, we're going to work on efficiencies. It's always easy to pick up those rigs up. But I think with where we're, you know, moving into 2025, it feels like a good place to be, you know, initially. And the nice thing is, like I said, if we can sustain Permian and roughly sustain Egypt, you know, you've got CERNOM coming in the next couple, you know, 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, you know, relatively flat. So, you know, 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 PSEs, you know, 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 next year?

Yeah, I just say if you look in Egypt at 11 rigs, you know, we've, as Steve mentioned, we've been declining slightly at the top line. It's been very, very slight, you know, over the last four quarters. So at 11, that'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, you know, the benefit those have is they flatten your decline. So then it's, you know, 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, you know, 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'll, we've got some bigger prospects to drill, and then we'll see. So, you know, I think the key there is we're getting started with that. And, you know, 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 ARL conversation. So I think the 1.2 billion is on the present value basis. So wondering if you could give the total liability on the absolute basis. And I think the, 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'll give you, 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. US 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 we've got that 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 to 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 as related to cash return, does cash outflow get netted out of that?

Yes, that will.

Let's just remember, we've talked a lot, and I understand why we've talked a lot and focused on the abandonment activity that's ahead of us and the costs associated with that. Let's just remember that we're not going 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, I'm really surprised with how powerful the benefit on the gas marketing side in a 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?

Yes, that's just going to depend a lot on what happens with Waha as we go through next year. It's not absolute Waha prices. It's the differential between Waha and Gulf Coast versus the cost to transport. Fairly simple. If I use fake numbers, if there's a $2.50 spread and there's a $1.50 spread, then you're making $1.50 on nearly 750 million cubic feet a day that we buy and transport to the Gulf Coast. It will all depend on what are those spreads for 2025. As we've experienced here in 2024, they can be extremely volatile. Even over short periods of time, for a weekend, we can find that for a weekend, prices can go negative for three or four days, as much negative as negative $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. We sell that on the Gulf Coast for what would normally be a positive price, a little less volatile pricing on the Gulf Coast than you get on Waha.

It's certainly nice to have that pipeline right now. Just to clarify, the Gulf Coast benchmark, are you looking at Houston Ship or is it a combination of different hubs?

Yes, it would be looking at mainly Ship Channel or depending on where the pipe takes you back to.

Okay, got it. Thank you.

Thank you, Betty. Thank you.

Our last question comes from Jeffrey Lambouillon with TPHM Company. 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 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 and then next year in honor, just to kind of help us dominate along with the ARO dynamic and charting walkthrough? Thanks.

Yes, we'll probably go into more detail on that in the February call. We're just at this point in time where, 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 -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, -to-day operations for free cash flow now. We, 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 assets. 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 Christens, our CEO for Closing Remarks.

Yes, thank you and first 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 high level. We have significantly scaled and streamlined our permanent 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 CERNAN. 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.

And with that ladies and gentlemen we thank you for participating in today's conference. You may now disconnect.