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 speakers' presentation, there will be a question-and-answer session. 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 Christmann. Steve Riney, President and CFO, will then provide further context 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 Bretches, 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've had the opportunity to review our financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website. And please note that our full year 2024 guidance reflects first quarter APA results on a standalone basis, plus three-quarters of APA and Callon combined. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. On the call today, I will 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 U.S., since 2020, we have executed more than $5 billion in acquisitions and over $2.5 billion in 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 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 lease operating expenses. Our primary strategic accomplishments in Egypt are two-fold, both of which drive APA shareholder value and benefit the Egyptian people over the life of the production sharing contract. 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. Recently, we reached an agreement to increase the contractual price for incremental natural gas production in the 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 GranMorgu project final investment decision 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 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 final investment decision on our first development project offshore Suriname in Block 58 with a 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. Cash flow from operations and free cash flow increased 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 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 fourth quarter. 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 8, 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 backlog 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, with a production capacity of 220,000 barrels per day, and a per barrel capital plus operating expense cost of $19 at a 15% internal rate of return 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 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 and 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 Beryl as planned. Earlier this year, the U.K. issued regulations requiring 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 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 31, 2029, well ahead of what would have been an otherwise reasonable time frame. 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 plugging and abandonment 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 to $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 barrels of oil equivalent 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 lease operating expenses, general and administrative expenses, gas processing tax, 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 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 third quarter, 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 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 asset retirement obligations. 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 mostly of 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 the third quarter 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 fourth quarter and 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 final investment decision, 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 fourth quarter outlook to reflect the estimated impact of frac 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 to 25,000 barrel of oil equivalent impact on U.S. 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 Waha 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 Cheniere gas supply contract. 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 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 it comes from the line of Doug Leggate with Wolf Research. Please proceed.

Thank you, everyone. Good morning. There's a lot to discuss this quarter, so I'll focus on two points: Egypt and the oil guidance. First, regarding Egypt, you haven't provided much detail about the gas price beyond mentioning that it's improved. Can you help us understand how this will impact the business? I believe the additional rig costs approximately $25 million net. How should we consider the increase in free cash flow based on your current outlook for the gas price? My second point is about the oil guidance, which has many variables, especially regarding the sale of the Central Basin platform. Could you explain the factors involved in the comparisons of acquisitions and disposals to provide a clear net number? I’ll stop there.

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 in the Western Desert, 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 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, while we've always run oil exploration programs, we found Caser, which is a 3 trillion cubic feet 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.

Yes. So what we mean by incremental gas volumes is as part of the agreement, we've agreed with EGPC what our produced developed product decline looks like for the full development or the full remaining life of the concession. So gas produced developed products, 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, 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 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 still ready for appraisal and development investment. The infrastructure is in place because we do produce a lot of gas today. There is some haulage 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 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. 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 the 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 think about I understand your point about wanting to get to how do 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 help in being able to figure out what this means for free cash flow. We understand the point.

Regarding the second question on Permian oil, we've been operating nine rigs but have reduced this to eight, which is the plan for next year. If we consider our Q3 figures of 143,000 barrels per day for Permian oil and account for the upcoming asset sales of 13,000 barrels a day, we expect to be around 130,000 barrels. We believe we can maintain that level despite a 20% reduction in rig count and similar decreases in production lines and capital expenditures. Overall, our outlook for next year is to sustain around 130,000 barrels a day of oil in the U.S. with eight rigs.

Got it. Thanks, guys. I appreciate the answers.

Thank you. One moment for our next question from John Freeman with Raymond James. Please proceed.

Good morning, guys.

Good morning, John.

I would like some clarification regarding the North Sea. From what you described, it seems that approximately half of the asset retirement obligations could be incurred by the end of 2030. I'm trying to understand the overall capital outflow as you reduce the capital expenditures in the North Sea over the next few years. Additionally, considering the asset retirement obligations, how should I approach the total capital spending in the North Sea over the upcoming decade? I know there's minimal capital spending planned for next year, but any insights on this would be beneficial.

The spending on the Asset Retirement Obligation won't be recorded as capital. Instead, you'll see it reflected in the costs incurred, along with some reconciliations to GAAP versus non-GAAP in our supplement. Specifically, there will be a figure for the North Sea related to the addition to the ARO. For GAAP accounting, the increase in the ARO is categorized as costs incurred, which is somewhat similar to capital spending. Therefore, when we increase the ARO, it won't be classified as capital spending in the CapEx program during the years we incur the ARO. To provide additional insight on the spending patterns, if you combine two numbers on our balance sheet—the gross obligation on the liability side and the deferred tax asset, which reflects a 40% tax savings for every dollar spent on ARO—the net amount is $1.2 billion. With a 40% tax rate, you can estimate that's about a $2 billion liability and an $800 million tax asset. As mentioned, around 50% of the $1.2 billion will be expended by the end of 2030, primarily on wellbore abandonment. This translates to about $100 million per year over six years. However, the spending pattern will increase over time. Next year in 2025, the amount will be significantly less than $100 million, with gradual increases starting in 2026. The first three years are projected to be below $100 million annually, while the last three years will exceed that figure.

That's perfect. I appreciate all the color on that. And then on the lease operating expenses, which you all are indicating a pretty big decline next year, 10% to 15% decline. And you mentioned the drivers, and there's obviously a lot of moving parts with the account synergies, the 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 like a driver of that decline year-over-year, just some way you think about.

Yes, John, we haven't really considered how to separate that out. What we've aimed to do is focus on the stand-alone business for next year and consolidate everything. A significant portion of this, particularly for Callon, is due to the synergies we've achieved. However, a lot also comes from changes in our U.S. portfolio, specifically selling off higher-cost, declining waterflood assets in the Central Basin platform, which tend to have much higher expenses and require substantial water handling. Essentially, you will see a recharacterization of our unconventional Permian Basin operations. I can also assure you that we are diligently exploring ways to exceed our current goals.

Yes. And I would just add, John, we'll provide a lot more detail when we unveil the comprehensive plan in February. At this stage of the year, we aim to outline the capital program and what it signifies for production volume, which is central to the company's direction. There is one chart in the supplement containing multiple elements. You might want to reach out to Gary later today or sometime, and he could walk you through some of the details behind that.

Understood. Thanks, guys.

Thank you, John.

Thank you. 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 the timing. There's a big moving part around your disposals and getting that cash in the door and 3Q percent of free 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 came into the year, 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 out of our control.

Very clear. A quick follow-up on gas curtailment and your latest thoughts around the 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. 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 negative $3 or $3.50.

Thank you, Bob.

Thank you. One moment for our next question from 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 a lease operating expense, but a lot of the general and administrative expenses, and what is that? Or is that in addition to the synergy 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 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.

We mentioned that approximately $90 million of the synergies from the Callon transaction would be linked to general and administrative expenses, while Callon's G&A cost structure was around $110 million annually. Currently, our G&A expenses are stable compared to before the Callon acquisition. I expect some of the G&A synergies to come from exceeding our initial projections. Although we have retained several Callon employees, we have effectively removed the entire Callon G&A. Additionally, there will be some one-time costs in G&A related to the transaction in 2024.

Yes. No, I appreciate that. And then, John, my question for you since you got the Alaska exploration well. And obviously, all those decisions had to be made pre-election. 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.

Yes. I think the main thing there, I'll remind you, Roger, is we've got about 300,000 acres in our position, but it's state lands. So we're in a position where you're fairly close to pipeline, and we're state land. 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 1 of the 2 that we attempted last winter, but we're very excited about it. So it will be early, early next year when we spud, and we have added some capital to start building ice roads and stuff for this winter.

I appreciate that. But one federal roadblock is sometimes more than enough. So I just wanted to check on that.

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 they're actually doing better than us and where that they probably have done the worst?

Yes. 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 acreage 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 million per well in terms of the well cost side, we're anxious on the spacing, and we've got two wells flowing 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 Callon in general.

No, I was just asking that. Is there anything that from a technology or process that Callon you actually find that they are doing well, and then you will be able to adopt their process or technology and enhance your operations?

Yes. I would say on the spacing side, we are thoroughly analyzing the data and how we are approaching the development scenarios, evaluating our design compared to theirs, and considering how to modify our approach for what we believe is a better solution.

Yes. And if I could just add to that. That's what 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 assuming, 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 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 are not in your original synergy target?

No, I can't quantify the benefits at this time. However, we plan to do so in the future. We need to drill, complete, and bring more wells online to gain some historical data. As mentioned previously, we anticipate achieving $250 million in annual cash operating and overhead cost synergies by 2025. We also believe there are significant efficiencies related to capital productivity. We will revisit this in 2025 to provide an update on our progress, which will include insights from our merger with Callon and its impact on our strategies for the rest of our land.

Okay. The second question is on Alaska. John, you guys are going back? Can you tell us that you guys are essentially going back to the same two wells that you suspended in last year’s program, and you’re just going to redo that or that you are targeting a total new prospect?

No, Paul, it's actually going back to the Saki prospect.

Please stand by; we have some technical audio difficulties. Please stand by, ladies and gentlemen. Yes, you are live. So one moment for our next question, please. And it comes from the line of Neal Dingmann with Truist. Please proceed.

Good morning. Thank you for the time, John. I have a question regarding production in the Permian and Egypt, specifically about the target you mentioned for eight Permian and 12 Egyptian rigs. Is the plan still to maintain that level? Do you think it's appropriate for sustaining stable production in both areas? Also, has there been much change to base production in either region? I'm trying to understand how we should approach maintaining flat production.

Yes. We have designed an early look program to sustain Permian oil production around the level I mentioned earlier. In Egypt, the reported production has been declining slightly, with 12 rigs currently in operation—11 focused on oil and one on gas. We are slightly underinvesting in Egypt at this level, but it's close.

Yes. To briefly add to that, we began the year with 18 drilling rigs and finished with 12, even going down to 11 at one point. Reflecting on our earlier comments, we anticipated a slight decline in gross oil volume throughout the year. The first quarter saw 138,000 barrels a day, the second quarter 139,000, and the third quarter was at 137,000, indicating a slight decline which I want to emphasize. This trend is likely to continue into the fourth quarter and into 2022 unless there’s a change in drilling activity. Looking back at 2023, we were in the mid-140s with 18 rigs operating for a considerable period, and maintaining or growing production volume was challenging. As we’ve mentioned before, with 11 rigs, we have achieved a smooth operational cadence that is working effectively. We've increased that to 12 rigs. As for 2025, the 12th rig is focused on gas drilling, with some wells being appraised, some developed, and others being low-risk step-outs or exploratory in nature, as we believe there are promising opportunities available. However, the potential for gas remains uncertain at this stage, although we are optimistic. Additionally, over the past year and a half, we have gained valuable insights into enhancing our waterflood management, with plans in place for 2025. We have yet to fully understand how this can aid in mitigating decline; the key to maintaining production levels in Egypt is to manage decline rather than increasing the number of wells drilled. We are addressing both areas and will see what 2025 brings. If conditions remain stable like in 2024, we will likely follow this pattern of slight decline.

Got it. And then just 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 here, 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 Neal, but we do think that share price is obviously attractive. We've got the proceeds coming in from the asset sales. The majority of that is going to go to debt reduction as we're also working to get debt paid down as well.

Thanks, John.

Thank you. One moment for our next question. And it comes from the line of Arun Jayaram with JPMorgan. Please proceed.

I wanted to go back to Egypt and gas. Steve, you mentioned that over time you can make up, call it, the PDP wedge with incremental volumes where you 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 Caesar field specifically?

Yes, Arun, I'll take that one. Caesar's been on decline. We've gone through some stages of compression. It is the big portion of our gas is Caesar, but we also produce a lot of casing head gas with a lot of the other oil wells. So Caesar 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. 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 of the field. And then obviously, Suriname starting up in 2028, how are you thinking about – thinking about another leg to the stool in terms of the portfolio, obviously, you sold some assets recently. But how are you thinking about just the broader portfolio? And obviously, given the North Sea where it's at, adding another leg to the stool?

Yes. 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 or 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 the portfolio is 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 addition to what are two really nice core positions, both in the Permian and the U.S. and Egypt.

Understood. Plus the exploration in Alaska near...

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 and 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.

Good morning, Charles.

Thank you. I would like to ask about Suriname, specifically regarding the slide in your supplement on slide 11. I appreciate the mockup illustrations that provide insight into the development layout. When you chose to include this, apart from the numbers on the right side of the slide, what key takeaways do you hope to convey to the audience? What should people understand about the GranMorgu?

I believe this project is very real today. We now have visibility on volumes projected for 2028, and I think it’s time to showcase some slides that illustrate this. That’s why we included the image. It offers a view from deepwater in, showing where the FPSO will be situated. This slide from Total highlights Krabdagu, which we’ve discussed regarding its development opportunities. On the other hand, Sapakara represents more of a field. Additionally, along that fairway, there are further exploration prospects and potential tiebacks, which is something we are enthusiastic about. It’s significant and sizeable, but the key is bringing this project to life, as it is very much real today, and we are eager for 2028.

That’s great. That’s it from 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 bit about the kind of activity plan in the U.S., it sounds like you guys are basically kind of pulling back there. Oil is 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?

Yes, Leo, I believe we are experiencing a softer price environment. Our asset base allows us to maintain volumes with eight rigs, and we will focus on improving efficiencies. It's relatively straightforward to mobilize those rigs. As we look toward 2025, I feel positive about our position. Moreover, if we can maintain production in Permian and Egypt, we have Suriname expected to contribute by 2028 at the 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, but I know you're expecting to keep adjusted or 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 in the PSCs for next year. I was hoping you could 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?

In Egypt, we currently have 11 rigs, and as Steve mentioned, we've seen a slight decline in our top-line performance over the last four quarters. With these 11 rigs, our gross oil production is relatively stabilizing. We're also actively pursuing some waterflood projects, which help to slow down production declines. The strong waterflood program could potentially enhance our productivity. On the gas side, while our overall gross gas production is decreasing, we have a one-rig program in place along with some promising prospects that we can develop to improve our infrastructure and bring in new volumes. Additionally, we're planning to drill some larger prospects, which will provide more clarity on our gas operations moving forward once we initiate these projects.

All right. Thanks.

Thank you.

Thank you. Our next question comes from the line of Betty Jiang with Barclays. Please proceed.

Good morning. Thank you for taking my questions. 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 an 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.

I will provide you with another figure. Previously, I mentioned that we have about a $2 billion liability on our balance sheet. According to U.S. GAAP, we need to account for the current cost of abandoning all those assets as if we had to do it today. We project that cost into the future and then discount it based on specific inflation and discount rates. When you take today’s cost, adjust for inflation, and then discount it, you reach $2 billion. The current cost estimate is $2.5 billion, indicating that the inflation rate is lower than our borrowing rate, which we use for a 10 to 15-year timeframe. Additionally, we get a tax benefit from this, with a present value of $800 million, which offsets the $2 billion present value. This results in a $1.2 billion net, reflecting the after-tax present value liability on our balance sheet. To summarize, we have a $2 billion liability and an $800 million deferred tax asset. What was the second part of your question?

Just on the free cash flow calculation, when you think about the organic free cash flow is related to cash return, does this cash outflow gets netted out of that?

Yes, it will. And just I think … Let's remember that while we have discussed the upcoming abandonment activity and its associated costs, we should not overlook that we still have operating assets in the North Sea. These assets continue to generate free cash flow even with a 78% tax rate, and this free cash flow will aid in covering many of those costs in the coming years.

Understood. 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 a weak Waha gas environment. Can you give us a flavor of under the current features, price on Waha spread, would you be able to continue to capture above-normal marketing benefit next year as well?

That will largely depend on what occurs with Waha as we progress through next year. It's not solely about Waha prices, but rather the difference between Waha and Gulf Coast prices relative to transportation costs. For example, if there's a $2.50 spread and a dollar transportation cost, we would make $1.50 on approximately 750 million cubic feet of gas we buy and transport to the Gulf Coast. The situation for 2025 will hinge on what those spreads look like, and as we saw in 2024, they can be highly volatile. For instance, prices can drop significantly over short timeframes, such as during a weekend, potentially going negative, meaning vendors could be paying us to take the gas. We then transport it at our undisclosed costs and sell it on the Gulf Coast, where prices are usually more stable than at Waha.

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

Yes, it would mainly depend on the ship channel or where the pipeline takes you back to.

Okay. Got it. Thank you.

You bet. Thank you, buddy.

Thank you. Our last question comes from Jeoffrey Lambujon with TPH & 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 of questions ago, just around the free cash flow generation that you mentioned. Can you also help us understand what your outlook is for OpEx from that asset as production declines in the next year, or will just kind of help us dominate it along with the ARO dynamic that you already walked through. Thanks.

Yes. We will likely provide more details in the February call. At this time of year, we usually give an overview of the capital program, production volumes, and the overall direction of the company. This is typically influenced by the long-term oil price outlook. On the November call, we will cover the essential points, but we will delve into specific country details and break down revenues, lease operating expenses, and capital expenditures in February. Regarding the North Sea, we are focused on managing day-to-day operations to generate free cash flow. Given the current situation, most capital investments are not economically viable, so we are concentrating on free cash flow and closely examining operating costs. We always prioritize human safety and environmental standards, but we will review our expenditures to ensure we are using funds wisely while focusing on free cash flow for the asset's remaining life. More details will be discussed in February.

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. 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, 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.

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