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F500-2020-465-Apache

The oil and gas exploration and production company operates in the U.S., Egypt, and the U.K. and has exploration activities offshore of Suriname.

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Wal-Mart stayed on top as its sales crept closer to half-a-trillion dollars. Apple moved into the top five. And UnitedHealth Group continued its steady climb. 

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APA, best known through its Apache subsidiary, is an independent energy company specializing in the exploration, development, and production of oil and natural gas. Operating primarily in the Permian Basin, as well as in Egypt, the North Sea, and Suriname, APA focuses on delivering reliable and affordable energy to meet global demand. The company is committed to sustainable practices and leverages advanced technologies, including artificial intelligence, to enhance operational efficiency and reduce environmental impact.

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Q3 2024

APA (APA): Company Profile, Stock Price, News, Rankings

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Good day, everyone, and thank you for standing by. Welcome to APA Corporation's Third Quarter 20 24 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 Q3 2024 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John Christmann Steve Riney, President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer your questions are 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 and A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our financial and operational supplement, which can be found on our Investor Relations website at investor.

Apacorp.com. Please note that we may discuss certain non GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non controlling interest in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward looking estimates and assumptions based on our current views and reasonable expectations.

However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website. And please note that our full year 2024 guidance reflects Q1 APA results on a standalone basis, plus 3 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 Q3 highlights and results and outline our preliminary capital production and cost outlook for 2025. Over the past several years, APA has delivered a number of strategic initiatives designed to enhance the portfolio and create shareholder value. In the U. S, since 2020, we have executed more than $5,000,000,000 of acquisitions and over $2,500,000,000 of divestitures, effectively transforming our asset base into an unconventional pure play Permian operation.

This activity has 3 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. 2nd, it has increased drilling inventory and extended inventory duration as the rig count today is lower than APA and Cowen on a standalone basis. And third, it rationalized our portfolio by eliminating assets that did not compete for capital and significantly reduces per unit LOE. Our primary strategic accomplishments in Egypt are twofold, both of which drive APA shareholder value and benefit the Egyptian people over the life of the PSC.

In late 2021, we modernized and extended our PSC terms, paving the way for more efficient capital allocation, more operational flexibility and greater free cash flow generation. And we recently reached an agreement to increase the contractual price for incremental natural gas production in country, making gas exploration and development more economically competitive with oil development. Shifting to Suriname, we are now seeing the culmination of our strategic efforts that began more than 10 years ago when we made a countercyclical investment in long cycle offshore exploration. The recently announced Grand Mourgeou Project FID gives us visibility into strong future oil production growth at the most attractive economics in our entire portfolio. Importantly, we believe this project can easily be funded over the next few years through operating cash flow allowing us to maintain our current capital returns framework.

Turning now to the Q3 results and highlights. APA achieved several important milestones during and subsequent to the end of Q3. We announced the sale of a package of non core Permian properties for $950,000,000 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 and Poor's, thus achieving investment grade status at all 3 major rating agencies.

3rd 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 2nd 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 Q4. Turning now to our key operational areas. U.

S. Oil volumes have now met or exceeded guidance for the 7th straight quarter. Since closing the Cowen acquisition on April 1, 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 Cowen and turned our focus to developing the acreage. Our initial wells on acquired Cowen Acreage are flowing back in the Midland Basin and the early results are encouraging.

The first wells in the Delaware Basin on Cowen 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 1 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 $10,500,000,000 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 further enhanced by the capital carry provision we negotiated in 2019 when we brought Total in as a partner. We plan to fund Suriname development capital out of operating cash flow for the next few years until production commences in 2028. As previously noted, we see significant opportunity for additional exploration in Block 58 that could extend the production plateau and enhance the economics of our first FPSO or potentially support additional development projects in the future.

Switching now to the North Sea. During the Q3, production volumes were in line with guidance as we completed our platform maintenance turnaround at Barrell as planned. Earlier this year, the U. K. Issued regulations which will require substantial new emissions control investments on facilities that will operate beyond 2029.

After 6 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 31, 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 twenty twenty five. Turning now to our preliminary activity plan and outlook for 2025.

We currently expect to run an 8 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 and A work in preparation for long term asset abandonment. Our 2025 capital budget for the U. S, Egypt and North Sea will likely be in the range of $2,200,000,000 to $2,300,000,000 with an additional $200,000,000 allocated to Suriname development activity and $100,000,000 for exploration, primarily Alaska. This capital program should broadly sustain production volumes in the Permian and Egypt on an adjusted BOE basis, while North Sea production will be down approximately 20% year over year.

I would also like to highlight the significant cost reductions we are targeting in 2025. In aggregate, we expect per unit LOE, G and A, 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 U. S, Egypt and Suriname. We had an excellent quarter operationally and achieved all key guidance targets.

The Callon integration is complete, most of the cost synergies have been captured, and we look forward to demonstrating the potential of the acquired Callon acreage. Egypt is running at a much more efficient operational cadence, and we have the opportunity to unlock incremental value and assist the country with its natural gas needs following the negotiation of a new price framework. Under our current price outlook, we will seek to generally sustain volumes in the Permian and Egypt for the foreseeable future, while rigorously managing costs and increasing the free cash flow that these regions generate. Longer term, a successful exploration program can add tremendous value and fuel future growth as evidenced by Suriname Block 58. And with that, I will turn the call over to Steve.

Thank you, John. For the Q3, under generally accepted accounting principles, APA reported a consolidated net loss of $223,000,000 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 $571,000,000 after tax impairment of North Sea assets and non core Permian assets held for sale. Excluding these and other smaller items, adjusted net income for the Q3 was $370,000,000 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 3 primary impacts this quarter. Previously mentioned after tax asset impairment of which $325,000,000 was related to the North Sea, a $17,000,000 barrel of oil equivalent write down of reserves that we no longer expect to produce and a $116,000,000 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 $1,200,000,000 for all of our North Sea ARO. We are planning to incur this liability between now and 2,038.

Approximately half of this liability will be incurred between now and the end of 2,030. While there will be some overlap, the next 5 years will consist of mostly wellbore abandonment, while the remaining 8 years will focus mostly on facility abandonment. We expect Barrow Bravo will be the 1st facility to cease production likely in late 2027 or early 2028. Moving over to Egypt, we continue to make good progress on past due receivables and during the quarter both total and past due receivables decreased. When payments on past due receivables are made, there is a counterintuitive impact on our stated free cash flow for the quarter because of the way we define free cash flow for the purposes of our 60% cash returns framework.

If you have questions about how to model these cash flows, please work with Gary and his team. Debt reduction is a continuing area of focus at APA. While total debt increased with the Callon acquisition, one of our goals is to liquidate the Callon debt as soon as possible. We made progress on this front in Q3 and will continue to do so in the coming quarters. The Callon deal brought increased scale in the Permian, which coupled with our commitment to return to pre acquisition debt levels was a significant factor in our recent credit rating upgrade by S and P.

To close, I would like to provide a bit of color on some of our changes in our 4th quarter and 2024 full year guidance. Our full year capital budget has increased to $2,750,000,000 which primarily reflects increases to 4th 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 1 rig in the Permian Basin. Turning to our U. S.

Production guidance, you'll note that we have adjusted our 4th 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 BOE impact on U. S.

Production. However, this estimate is subject to considerable volatility depending on how regional gas prices progress through the Q4. As most of you are aware, our income from 3rd party oil and gas purchased and sold is generally correlated to Waha price differentials. Accordingly, with the persistence of weak pricing into the 4th quarter, we are raising our full year estimate to $500,000,000 approximately 2 thirds of which is attributable to our gas trading activities and 1 third is attributable to the Cheniere gas supply contract. And to close, most of our $250,000,000 Cowen synergy target should be realized by the end of this year.

We anticipate reaching full synergy realization through 2025 and we do not plan continued reporting on these efforts from this point forward. And with that, I will turn the call over to the operator for Q and A.

Thank you so much. And it comes from the line of Doug Leggate with Wolfe Research. Please proceed.

Thanks guys. Good morning. Gosh, Steve, there's a lot this quarter. So I'm going to hit 2. 1 is Egypt and 1 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, dollars 25,000,000 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

versus disposals to get us to kind of net number just to

is looking at on an apples for apples basis?

Yes. 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, 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 on going forward. We've allocated 1 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 Kosser, which is a 3 Tcf field back in the early 2000s. So there's tremendous potential for gas in Egypt. We've got a lot of low hanging fruit. This will be on incremental gas volumes and it's going to put our exploration program on par with an oil program.

Yes. So what we mean by incremental gas volumes is as part of the agreement, we've agreed with EGPC what our PDP decline looks like for the full development or the full remaining life of the concession. So gas, PDPs, a decline curve and for every quarter, we'll look at how much gas was produced and any gas over that decline curve in that quarter gets the new price. It doesn't have to be from new wells. It doesn't have to be from new fields.

So gas compression can bring on more gas volumes, enhanced recovery, step outs, 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 1 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 5,000,000 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 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 allege 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.

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

2 decades. And prone. So we do have a known inventory of low risk resource potential with material volumes. And in addition, we will be testing some exploration gas prospects and concepts to continue to grow that inventory over time. So we see a lot of potential in those opportunities and we're excited to have a gas focused program.

It's a great opportunity to grow the inventory and add value to our business in Egypt.

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 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 how do we forecast free cash flow, but I don't know a price.

We'll start thinking about how between now February when we give a final plan for 2020 5 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.

And if I can take the second question, Doug, on the Permian oil, we've been running 9 rigs. We've scaled back. We're at 8 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. Dollars And we believe we can maintain that or hold that flat with a rig count that's down about 20% turn in lines that are down 20% and CapEx, which is in line with that.

So we think it's actually pretty strong. But 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 8 rigs.

Got it. Thanks guys. I appreciate the answers.

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

topic, just a little bit more info on the North Sea. So I just want to make sure that I understand. So the way that you laid it out Steve of the ARO, you said about half would potentially be spent between now and the end of 2,030. And I guess I'm just trying to understand in terms of just outflow of capital as you all like ratchet down the CapEx in the North Sea over the next several years and then factoring the AROs, just sort of how I should think about just capital being spent total in the North Sea over these next handful of years? When I know the minimal it's a minimal spend CapEx wise in the North Sea next year, but just any color on that front would be helpful.

Yes. So the spend on the ARO won't show up as capital. You'll actually see a number in the costs incurred where we provide some reconciliations to GAAP versus non GAAP reconciliations in our supplement. And you'll see a number in there for the North Sea for the addition to the ARO. So from a GAAP accounting purposes, the increase in the ARO is considered costs incurred, which is a GAAP kind of equivalent or somewhat equivalent to capital spending.

So it shows up when you add to the ARO and it doesn't show up as capital spending in the CapEx program as we spend that capital or those dollars in the years in which we incur the ARO. And John, just to give maybe a little bit more color on the spend patterns. So as I said, if you were to combine two numbers, because there's a gross obligation on the liability side on our balance sheet and then there's a deferred tax asset, because there's a 40% tax savings for every dollar that you spend on ARO. So there's two numbers on our balance sheet. Those two numbers net to $1,200,000,000 It's with a 40% tax rate, you could probably figure out pretty quickly, it's about $2,000,000,000 of liability.

It's about $800,000,000 tax asset on the balance sheet. And that $1,200,000,000 as I said, roughly 50% of that will be spent between now and the end of 2,030. A lot of that is being spent on wellbore abandonment. And so you figure out, you figure, okay, well, that's about $100,000,000 a year for 6 years. And what I would say is the pattern grows through the period of time.

So it's going to be way less than $100,000,000 next year in 2025, starts kind of ramping up a little bit in 2026. The first three years are below $100,000,000 a year, the last 3 years are above $100,000,000 a year.

That's perfect. I appreciate all the color on that. And then on the LOE, 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 Cowen 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 to think about?

Yes. I mean, we Joe, 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 Calum side is the synergies we've been able to drive out. But a lot of it comes to just the change in the portfolio changes that we've made in the U.

S, selling the higher cost, declining waterflood assets on the Central Basin platform, which are typically much, much higher cost. We handle a lot of water. So it's really a re characterization of our unconventional Permian Basin business is what you're going to see. And I can also tell you there's we're working hard on how to do more than what we've laid out at this point.

Yes. And I'd just add, John, we will provide quite a bit more detail around that when we roll out the detailed plan in February. What we're trying to what we always try to do at this point in time in the year is just kind of give a shape to the capital program and what that means to production volume more than anything else, kind of the meat of the direction of the firm. But there is that one chart in the supplement and it's got multiple elements in it. You might want to just give Gary a call later today or sometime and he might take you be able to take you through some of the details behind that.

Our next question comes from the line of Bob Brackett with Bernstein Research. Please proceed.

Good morning. I had a question around the cadence of the cash return strategy and kind of the timing. There's a big moving part around your disposals and getting that cash in the door and 3Q percent of free cash flow return came down a bit. Should I think of that as a timing versus anything else?

I mean, definitely, it's just timing, Bob. We came into the year, we're running a little bit ahead and then you look at Q3, we've had a lot of material things that were in the works that can sometimes prevent you from being able to get in the market at times. But in general, yes, it's more just timing that was kind of out of our control.

Very clear. A quick follow-up on gas curtailment 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?

Yes, 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 a matter of perhaps just days. 1st 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 Very clear.

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

Yes. Thank you. Good morning. I guess I'd like to come back on the lowering of the cost. I mean, it looks obviously a piece of it LOE, but a lot of it G and A.

And what is that or is that in addition to the synergies you anticipated from the Callon merger? I mean, I would think so given the way it's laid out here, but I just wanted to understand what was driving some of these opportunities.

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

Yes. And the other thing I would just add, in our synergies around the Callon transaction, we said that around $90,000,000 of that would be related to G and A and Callon had a G and A cost structure of around $110,000,000 a year. Our G and A right now is running basically flat with where we were prior to the Callon acquisition. So I think some of the G and A synergies are going to be around just growing the increasing or exceeding the amount of synergies that we thought would basically it's not all Callon people because we actually have a number of Callon people here in the company, but we've equivalently eliminated the full Callon G and A. There were some one off costs in G and A in 2024 around the transaction as well.

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. But in terms of regulatory outlook, certainly it looks easier to do business in Alaska with the federal government at this point. Just wondering if 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, and I'll remind you, Roger, is we've got about 300,000 acres in our position, but it's state lands. And so we're in a position where you're fairly close to pipeline and we're state lands. So you don't really have to bring the federal side in, but just on a few things. So we feel good about that.

We're excited about Alaska. We had a discovery earlier this year on the well that we did get down and we're going back to 1 of 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 and 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.

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 Cowen deal even though I think Apache probably do better than Cowen. But when you go through that, have you found there's anything that you learned from them saying that, oh, they actually doing better than us and where that they probably have done the worse?

Yes. I mean, obviously, Paul, when you integrate 2 companies, you take good and from both and try to replicate. I think Cowen has 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 sort of our processes. We've cut almost $1,000,000 per well in terms of the well cost side. We're anxious on the spacing and we've got 2 wells flown back or actually 4 now, but 2 we've got pretty good results on in the Midland Basin and we're seeing some pretty good uplift on those 2. So we're pretty excited about Cowen in general.

No, I was just asking that, is there anything that from a technology or process that current you actually found that they are doing well and then you will be able to adopt their process or technology and then enhance your operation?

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

Yes. And if I could just add to that, that's where I was going to say earlier was that it'd be really simple just to bring all of that acreage into the Apache process and just assume, well, we're right, we'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 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 is not in your original synergy target?

No. At this point, I'd say I can't quantify the benefits of that, but we'll do that in due course. I think we've got to get more wells drilled, completed and online and get some history to those. And we've talked about it in the past at some point in time in 2025. We have the $250,000,000 of annual cash operating 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 Cowen and how that helps even the Apache approach to the rest of our acreage as well.

Okay. The second question is on Alaska. John, you guys are going back. And can you tell us that you guys essentially going back to the same 2 wells that you suspend in last year program and you're just going to redo that or that you are targeting a total renewal prospect?

No, Paul. It's actually going back to the sockeye prospect is what We're back up. I apologize. We had an Internet disconnect, but we're back.

APA (APA) Q3 2024 Earnings Call Transcript

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