Operator:

Good day and thank you for standing by. Welcome to APA Corporation's Second Quarter Financial and Operational Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead.

John Christmann :

Good morning, and thank you for joining us. On the call today, I will review APA's second quarter performance, discuss the Callon integration, and review our activity plan and production expectations for the remainder of 2024. Our second quarter results were strong across the board, with higher-than-expected production in all three operational areas. CapEx was lower than expected mostly due to timing of spend. In the U.S., oil volumes of 139,500 barrels per day were up 67% from the first quarter as we incorporated Callon into our operations. Production and costs were significantly better than expected on a BOE basis after adjusting for asset sales and discretionary natural gas and NGL curtailments. Our Permian Basin continues to perform at a high level and we marked our sixth quarter in a row of meeting or exceeding U.S. oil production guidance. On a BOE basis, oil now comprises 46% of our total U.S. production following the Callon transaction. With this increased exposure, APA's cash flow sensitivity to a $5 per barrel change in oil price is approximately $300 million annually. In Egypt, production also exceeded expectations. We saw positive contribution from new wells, improved results from recompletions, and continued strong base production. Base production is particularly benefiting from the implementation of several new water injection projects. We are also beginning to see a decrease in offline oil volumes waiting on workover as we moderate the drilling rig count to free up work over rig resources. Turning to the North Sea, operations were relatively smooth in the second quarter with better than forecast facility runtime driving higher production. Our ongoing focus in the North Sea is right sizing our cost structure for late life operations. In Suriname, our partner Total recently announced that it has secured the FPSO hole for our first offshore development and we remain on track for FID before year end and first oil in 2028. And in Alaska, we are still working through options for the upcoming winter drilling season and look forward to returning to exploration activities. Turning now to the Callon acquisition, note that in last night's release we increased our estimate of annual Callon cost synergies from $225 million to $250 million as we leverage economies of scale of the combined APA and Callon Permian businesses. Steve will speak in more detail about some of the specific initiatives driving these cost reductions. More importantly, we are just beginning to implement drilling unit design and operational changes that we expect will create substantial value on the Callon acreage via improved well performance and capital efficiency. Our preliminary estimate is that we can drill a standardized two-mile lateral for roughly $1 million less than Callon was spending in 2023. We recently spud our first APA designed drilling unit on Callon acreage, the five well Coleman unit in the Midland Basin and should begin to see initial flow-back results in the fourth quarter. Turning now to our activity plans and outlook for the second half of 2024. In yesterday's release we provided guidance for the third and fourth quarters which contained some notable positives. In the U.S. we will average nine to 10 rigs for the remainder of this year consisting of approximately five rigs in the Delaware and four rigs in the Midland. We plan to run three to four frac crews and complete about 90 wells by year end. This sets the stage for strong oil growth in the second half of the year. Accordingly, we are increasing fourth quarter U.S. oil guidance to 150,000 barrels per day which is up 1,500 barrels per day after adjusting for the impact of asset sales closed in June. This represents organic production growth of roughly 8% compared to the second quarter. We also expect an increase in natural gas and NGL production driven primarily by fewer discretionary curtailments than in the first half of the year. In Egypt we expect a continuation of the operational progress that we made in our second quarter. There will be some volume impacts from the rig count decrease but this should be mitigated by strong base production performance and increased workover capacity to remediate wells offline. By year end, we project that backlogged oil production will be closer to more normalized operating levels. On our May call, we said that adjusted production in Egypt would remain relatively flat in 2024, while gross oil production would be flat to slightly down through the remainder of the year. While there are a number of moving parts to the program in Egypt, we see no material variances to our May outlook, and therefore guidance is unchanged. Similarly, our full year production guidance in the North Sea is unchanged, though we now expect a bit larger decrease in third quarter volumes associated with maintenance and turnaround activity at Barrel, and a slightly larger subsequent rebound in the fourth quarter. In closing, second quarter was an excellent quarter operationally, and we continue to execute at a high level in the Permian Basin. We are realizing greater than expected cost savings from the Callon acquisition, and have a clear pathway and plan to improving capital efficiency on those assets. Egypt also had a very good quarter and is beginning to deliver significant capital efficiency improvements. Though our drilling rig count is coming down, continued strength in base production and the return of wells offline will help sustain volumes in the near term. At current strip pricing, the second half of the year is setting up to deliver a substantial increase in free cash flow compared to the first half. And lastly, I am very proud of our teams for delivering these results while remaining on track to achieve our safety and environmental goals for the year. For a detailed review of APA's safety and environmental performance, I encourage you to review our recently published 2024 Sustainability Report, which can be accessed via our website. And with that, I will turn the call over to Steve.

Operator:

[Operator Instructions] Our first question comes from Doug Leggate of Wolfe Research. Your line is now open.

Steve Riney:

Yes, Doug, I'd be careful just using fourth quarter. We're probably going to be a little completion activity in the fourth quarter because a lot of that is -- has been bunch into second quarter and third quarter this year just because of the timing of availability of wells for completion. So I think the easier way to do that would be to look at full year spend, take out the first quarter, which is just APA and then I would probably first adjust that for the exploration spend and then just divide it by three quarters because the quarter was high third quarter is going to be about average-ish and fourth quarter is probably going to be a little low. And then I think you'll get a number of something close to around $700 per quarter.

Steve Riney:

Sorry. If you take out the exploration, you'll probably get something closer to $675 million a quarter of capital spend on basically the U.S. onshore and Egypt. There's not a whole lot of capital activity, as you know, going on in the North Sea.

John Christmann :

Yes, Doug, it's a great question. It's 1 we're working every day. What I would say is if you look at the existing U.S. Permian run rate. We've always said kind of end of the decade with the rig rate we're at. And when we said we're bringing Callon in pretty similar duration I think there's one upside on the Callon is that we can drive the productivity improvements that we think we can then there will be more inventory that comes into play that we did not pay for in our acquisition. So that's something we're currently working on. If you look at where we sit today, we've got a lot of flexibility going into next year. We're going to grow Permian a very strong clip from second quarter to fourth quarter on 9 to 10 rigs, about 8%. And so it gives us a lot of flexibility going into next year pace we want to go. And we've had plenty of inventory that we have visibility on that to carry us to the end of the decade. And we'll keep working that.

Doug Leggate:

Thanks guys. See you next week.

John Freeman :

Good morning, guys. Just kind of following up on some of Doug's questions. I mean, the Permian and Egypt both exceeding guidance and specifically on Egypt, a pretty solid job of getting that turned around. And I'm just trying to make sure that I'm thinking about this right, where you've got you averaged 16 rigs in the first half of the year, you're going to drop down to 11 rigs in the second half of the year. And -- am I kind of reading it right that even at that lower rate cadence in the second half of the year because of all the steps that you all outlined in terms of the improved kind of base production management, catching up on the recompletion, resolving kind of that backlog of oil off-line in the back half of the year. Is that 11 rigs sort of cadence in the second half of the year? I mean, is that like an acceptable number to kind of maintain volumes? Just trying to make sure I understand kind of the moving pieces.

John Freeman:

Great. And then just my follow-up, John, you mentioned that you might -- you'd see the gas volumes on the U.S. side actually grow some, and it had to do with sort of the -- well, one of the drivers was the fact that you had less curtailed gas volumes potentially in 4Q. So in the current guidance, does it assume any curtailments in 4Q? I mean, obviously, you all -- you had some in 2Q, you have even more in 3Q. I'm just trying to get something that's built into that full year guidance?

Steve Riney:

Yes. And just second quarter actuals, the amount that was curtailed, we had 78 million cubic feet per day of gas and 7,6000 barrels of NGLs curtailed during the quarter on an average day, that's nearly 21,000 BOEs per day. Our forecast for third quarter, what we've effectively left out of our guidance is 90 million cubic feet per day of gas and 7,500 barrels of NGLs. That's 22,500 BOEs per day. Those are really large numbers as you might imagine.

Operator:

One moment for our next question, which comes from Neal Dingmann of Truist. Your line is now open.

John Christmann :

Yes. As I said in the prepared remarks that one of the advantages to is we're seeing impacts on the combined business just from the supply chain how we design the wells, we think we can drill a standard 2-mile lateral for about $1 million less than what Callon was spending last year, which is 20%. So we're anxious to see those numbers start to come through. But excited about what we're seeing. And quite frankly, we're just now starting to spud some of the Apache plan pads on the Callon acreage. So excited to see those results, but things are going extremely well on the integration side.

Neal Dingmann:

Great. Great. And then maybe Steve for you. Just a second question on shareholder return. Specifically, your shareholder return continues to be quite active. I think it was down a little bit sequentially in this last quarter. I'm just wondering, can we anticipate a large step-up for many of the year? Or how would you like to think about the program for the remainder '24 to '25?

Operator:

Our next question comes from Charles Meade of Johnson Rice. Your line is now open.

John Christmann :

No, Charles. I mean, we typically wait to talk about property sales. But there's a chance, there's other things that we're looking at that are not core to us in places that we're not putting capital. So you may have some decent intel out there.

Steve Riney:

Yes, Charles. So there's -- yes, we can we can actually curtail quite a bit more than that, a little more than twice that amount. And so what that is, is that's an average for the quarter, but it's in anticipation of there being periods of time where we're where we're curtailing quite a bit of gas and dipping into the rich gas well especially do that when price of negative or significantly negative. When prices are just low, we'll typically just go with the lean gas and not dip into the richer gas. So we do that based on a price basis. We do it -- we have specific prices where we moved from 1 tranche to another. We've got 4 specific tranches of gas going from lean to richer gas that we can shut in different pricing mechanisms. And so I just want to -- I want to make sure that we're really clear about one fact, and that is that the curtailment of gas volumes in the Permian Basin and the Alpine High in particular, is totally independent of our marketing activities because marketing is something that we have to do because we have firm transport on two large pipelines, more pipelines now with Callon. And we have to fulfill those transport obligations. And we do that with purchased gas in the Permian Basin, which we then sell on the Gulf Coast. And we have various access points both in the Permian and on the Gulf Coast to be able to buy and sell that gas. So we don't have a choice of doing that. If we choose not to transport gas, we have to pay the transport fee anyway.

Operator:

Our next question comes from Roger Read of Wells Fargo Securities. Your line is now open.

John Christmann :

Well, I mean, we have a joint venture there. We have a one-third partner with Sinopec, but we never have issues in terms of directionally what we think is the right thing to do and we have full support. And I think the good news is the performance has been strong. The projects are very impactful. And it just shows that getting that workover rig and drilling rig balance into play really gives us a lot more flexibility. I would just say there's -- it would be our choice in terms of adding activity, and there is flexibility to do that. And we're recently over there, met with President Sisi, met with some of his new cabinet members, very impressed with the new minister and excited to work with him, and outlined some frameworks under which we could think about bringing on some other volumes of things. So very constructive meetings, and it's just something we'll factor in as we go into the planning process.

John Christmann :

Yes. I think it's probably more like going through fall camp. There's phases that get ahead early and phases that you're still developing, right? But in terms of the organization and so forth, we've worked through that very quickly with the integration of the assets into the portfolio. We worked through that quickly. Obviously, the piece that's the most exciting is still to come is going to be what can we drive on the productivity improvements and what does that do in terms of inventory locations. So we're just now getting to the first pads and spudding our first Apache plant wells. And obviously, anxious to get on with those results.

Operator:

Our next question comes from Scott Hanold of RBC. Your line is now open.

John Christmann :

Scott, I mean, we've been pretty consistent since this time last year that the -- after we finish the Krabdagu appraisal that we were highly confident we were going to have a project, and we stated we plan to have an FID by year-end '24. And obviously, we remain on track. It's consistent with the message that Total has now put out. I think that is the next step. And once we get to that step, then we can obviously talk a lot more about what that means and all of that, but things are going extremely well. Teams are working very well together, and they are doing their thing. So right now, I'd say we remain on track for year-end FID and first of all by 2028, and they're working hard to accelerate those.

John Christmann :

Today, we feel very comfortable with where we sit. I mean -- and when we talk about inventory, we're talking about long laterals with extremely high PIs. So it's high-quality inventory. As you know, we've got a large acreage footprint in the Permian. We're always working on how we bring more acreage into drillable prospects, but it just takes time as you mark through and you've got a lot of tests along the way. But today, we're very comfortable with our inventory. We know there's a lot more inherently to do there, and we will get to that and improve that as time goes on. I think when it comes to transactions and things, you've got to continue to have a very high bar. We've had one. We've been very patient. We saw a lot of opportunity in Callon, which is why we moved on it. But today, we're very content with where we sit and believe that there will be even more to do than what we have visibility into today.

Bob Brackett :

Good morning. A bit of a follow-up on Suriname. Two interesting things that I interpret from your update. One is you all have gone out and with the partner secured a state-of-the-art slot on FPSO from a leading contractor, that's about the most expensive long lead item I can think of. Does that tell for your conviction in FID or am I overreaching?

Bob Brackett:

And then the second issue is you've disclosed that the field development area is agreed upon for kind of a joint Sapakara Krabdagu development. If I sharpen my crayon and draw a ring fence around Sapakara through Krabdagu I could capture the vast majority of all your discoveries out there, ring-fence that? And then under the PSE cost recover that and have a pretty good cost pool for future work? Am I thinking correctly there?

Bob Brackett:

Good thing. And I'll just throw a last one in, which is to say, you guys increased your acreage in Alaska by 20%, that suggests that you see something interesting there or perhaps the option value of that acreage is pretty low. Is that a good way to think of it?

Bob Brackett:

Thanks for that.

John Christmann :

Yes. I would just say we'll stick to what we said in the script. Clearly, second quarter was strong. Things are going well in Egypt. But at this point, we didn't see any reason to alter our guidance.

John Christmann :

I'd say it just got back from being over there. As I said, I had a good meeting with the President got to meet some of his new cabinet. Things are going well in Egypt. I mean, I think if you step back and look at it, President Sisi has done a really good job of managing a fairly difficult situation. So we've been impressed with that. We have been receiving some payments this year. So all in all, things are going well, and they continue to work through a difficult situation, but we see no reason to be concerned at this point and a lot of positive things on numerous fronts. Steve?

Leo Mariani :

Okay. That's really helpful. And you guys intimated in your comments that there could be some opportunities from additional gas there. I know Egypt has been short gas this summer. It sounds like they're a little desperate to get back at it. Would you anticipate some opportunities and then potentially that could be associated with the price change on some of the gas going forward?

Leo Mariani:

Okay. Thank you.

Scott Gruber :

Yes, good morning. I wanted to come back to the upside on the Callon acreage. So as we think about the productivity improvement potential from up spacing and the completion redesign, will there be a material improvement in 30-day IPs? Or will the improvement to manifest more over time in the six and 12-month cubes? I'm just wondering if the shift in the completion design targets a shallower decline and what that means for the 30-day IP improvement potential versus the longer-term improvement potential.

Scott Gruber:

Okay. Okay. And then just another follow-up on Egypt. So you guys spent about $135 million a quarter, running 16 rigs on average in the first half, and that will drop to 11% in the second half. Roughly how much will the fiber reduction drop Egyptian CapEx in FDU?

Operator:

Our next question comes from Arun Jayaram of JPMorgan Securities LLC. Your line is now open.

Steve Riney:

Yes. So first of all, let me make sure I was clear about the $675 million. That was a number that was -- it was about 2024 capital spending. And I was -- how do you get a -- it was a conversation about how do you get a grip on how much are we actually spending on a run rate basis with the current structure of the company with Callon included as well exploration, excluding exploration activity. And so that's what the $675 million was that's about how much we're spending on average between second, third and fourth quarter of 2024. If you exclude Suriname and Alaska exploration type of activity. As far as -- and so the point being that, that was not an indication that that's what our run rate is going to be going into 2025. Just to be clear about that. I think the best thing that we can do as we normally do is we're in the middle of the planning process right now. The great thing about our portfolio, John mentioned earlier, we've got a huge amount of optionality. It's a complex portfolio actually. And you've got to make a lot of capital allocation decisions with looking view of where you would be allocating capital where the best returns are going to be through other parts and so that's what we typically run our planning process starting in mid-summer through the fall. We have an upcoming conversation with the Board about that plan, a preview of that plan. And we've got a process that we run through. We typically in November, give a high-level view of what 2025 will look like. And then all of the details we typically give in February.

Steve Riney:

Yes. Yes, that's a great quarter, John. A lot of people talk about, well, okay, what's it takes to run flat going into 2025? And we had a little bit of a conversation about that around Egypt. We're running 11 rigs, can you hold flat -- Egypt flat with 11 rigs and we're down to 11 rigs because we had to create the workover capacity to get back at the -- to get us to recompletions and workover backlog, and we're also using that time to do some convert to injection for water injection on a number of these fields. So can 11 rigs hold Egypt flat? Maybe not. It might be a little low, but we were running 18 rigs earlier this year, and running flat in Egypt is much closer to 11 rigs than it is to '18. '18 was clearly more than we needed to be running in Egypt. And as John said, in the Permian, we're running 9 to 10 rigs for the second half of the year, and we're growing 8% from second quarter to fourth quarter. So clearly, the number is below that in terms of how many rigs do you have to run in the Permian to stay flat.

Steve Riney:

Well, I don't know what normalized is anymore after the last several quarters. But in general, market dynamics would tell you that a balanced situation would be that differentials between Waha and Gulf Coast they need to formalized would be that, that should have over time we're basically just making money on the Permian and by buying something slightly below Waha pricing because we've got multiple receipt points and we can take best price, and we typically do, but you're talking about pennies per Mcf. And then on the Gulf Coast side, multiple delivery points where you can sell for pennies maybe above Houston Ship Channel here or there, and you can squeeze a few pennies out on both ends, but on 674 million cubic feet a day, that makes a difference over time. And it just pays for the transport and fuel costs. But in that oil and gas purchase for resale, remember that still includes the Cheniere contract, which, of course, has nothing to do with Waha differentials.

Operator:

Your next question comes from Geoff Jay of Daniel Energy Partners. Your line is now open.

John Christmann :

Yes. So what we've included in the $150 million of annualized synergies excludes the benefit of lower rig rates for frac. Exactly [technical difficulty] have some integrity and [technical difficulty] synergies of a transaction [technical difficulty]. That is excluding any market synergies. So while John talked about $1 million cheaper or lower cost to drill a single well -- that includes the market benefit, but we only took about 70% of that number because 30% of that is the -- some of the market benefits on steel, on rigs, on frac and other things. What is included in the $250 million is about $60 million of annualized run rate for the lower drilling costs on these wells. And what that $60 million is, is basically with 9 to 10 rigs running in the Permian Basin, that's about how many Callon wells we would drill in a given year. And so that's how we got to that number. We're are obviously not drilling 60 wells this year. So we're not -- it's not like we're going to capture a full $60 million of benefit in the calendar year '24. But if we keep running at a similar rate that we're running these days, then we'll probably capture something near that in 2025.

Paul Cheng:

Just one quick one. Alaska, John, can you share with us that what's the drilling trend over there? I mean, how many wells you guys are going to drill whether it's all exploration or is going to be doing some appraisal on the King Street? And what -- how much spending that we may be talking about? Thank you.

Paul Cheng:

Okay, all right. Thank you.

John Christmann :

Thank you, and to wrap up really, just a couple of points here. Number one, we're delivering strong results in the Permian and the Callon integration is going extremely well. Secondly, freeing up the workover rigs in Egypt is letting us do two things, one, implementing some very impactful water flood initiatives. Two, reducing the backlog of wells waiting for workover recompletion and the results of both of those are very visible. And lastly, we are raising full year oil production guidance while seeing a downward bias to our full year capital. And with that, I'll turn it back to the operator. Thank you.

Operator:

Good day, and thank you for standing by. Welcome to the APA Corporation's First Quarter 2024 Financial and Operational Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker for today, Gary Clark, Vice President of Investor Relations. Thank you.

Operator:

[Operator Instructions] Our first question comes from the line of John Freeman of Raymond James. Your line is now open.

Operator:

Our next question comes from the line of Neal Dingmann of Truist Securities.

John Christmann:

Well, I mean, that is the big driver. It needs to compete internally on the oil side. And really, we measure that through Waha. So right now, you've had very, very weak Waha. Obviously, we've got Matterhorn coming on, but we're going to need to see much stronger Waha and it's going to need to compete internally with our oil projects.

John Christmann:

No. I mean I think big picture. We're committed to the 60%, right? We've shown that it's a minimum of 60%. And we will lean into that when we believe there's weakness, which we've historically done, and we'll continue to do in the future. That gives us the other 40% for debt reduction. We do have some non-core asset sales that we're targeting as we do believe we need to make some progress on the debt side with what we brought on with Callon, but you'll see us aggressively approaching both.

David Deckelbaum:

I wanted to ask a couple of questions around the capital program this year and your preliminary thoughts getting into '25 as you further integrate the Callon assets. One, can you just talk about, in this year, how many DUCs you're intending to work down and what you would carry going into next year?

Stephen Riney:

Yes. David, this is Steve. So in terms of the capital program and the treatment of DUCs, what we've done is we've added some frac capital in order to come up to the $2.7 billion of capital that we have in the plan for this year now. We basically just combined the final 3 quarters of Callon's remaining capital program with ours. But then we added some frac capital in the second half of the year because we did see that both of us were building DUCs.

David Deckelbaum:

Appreciate that. If I could make those first 2 questions, I guess, into one and ask another one. I'm just curious if you can share any targets that you might have in mind on proceeds or timing from non-core asset sales?

Stephen Riney:

That's what we're trying to achieve. Yes. I think it's possible, and we're going to certainly give it a try.

Wei Jiang:

I really appreciate the color or the guidance that you have given for 4Q pro forma production for U.S. oil. If we think out to 2025, like Apache is delivering double-digit organic growth in the Permian this year. Do you expect to see continued growth on the combined assets going forward? Just thinking about the overall strategy, like approach from a growth outlook perspective?

John Christmann:

Yes. I mean you've got one factor in Egypt is costs are big picture gas has been declining. So the gross BOEs have been declining because of that, and we've been growing the oil. We're in a place today where we're working to rebalance the workover rigs and the drilling rigs and find a good level in there where we can drive that production base.

Operator:

Our next question comes from the line of Leo Mariani of ROTH MKM.

John Christmann:

Yes, I'd just say we're very confident be it still underway, and we would anticipate an FID by year-end. So it's all moving forward there. And then that's going to dictate timing in terms of drilling we've got till 2026 to start the exploration program. So there's nothing pressing on the '25 side, but we could be back to drilling in '25.

Neil Mehta:

John, I wanted to spend a little bit of time talking about the Callon cost synergies. And specifically on the operational side, you're talking about high-grading the service providers, stuff around casing, surface economics. So can you just spend some time getting us on the ground and giving us a little bit more granularity around some of those cost synergies on the operational side?

Stephen Riney:

Yes. Neil, I'd just add, if you went back to the Permian slide deck that we published in February, we specifically pointed out 3 areas where we felt like Callon was significantly kind of off the mark in terms of where we would want to be on LOE per BOE, workover cost per BOE and downtime percent. And they've -- Callon has a history of a much higher well failure rate including for new wells.

Neil Mehta:

That's a very thorough and helpful explanation. And good look as you bring the asset into the fold.

Paul Cheng:

Steve, I have to apologize. When you talk about dry holes, I sort of missed that. Can you repeat it? I think you're saying that you have a way of in share name on Block 52 that's I think 40-some-odd million. So what's the remaining with the driver expense at 123 -- the second question is that yes, go ahead, please.

Paul Cheng:

I see. And John, on Alaska in King Street discovery, can you share that what's the thickness of the [indiscernible] that you have 2 [indiscernible] do you have any data about permeability or that any information that you can share?

Paul Cheng:

Right. And John, you're saying that you're going to drill the 2 new well for Sockeye and Voodoo. Is that going to be done? Or that is going to be drilled in the next drilling season? Or that you guys have not decided and may get pushed out further?

John Christmann:

Yes. Thank you. In closing, our Permian is performing extremely well, and we have just bolstered it with the addition of Callon and is now approximately 75% of the company. We will be integrating Callon over the next couple of quarters. And by the fourth quarter, you should start to get a good picture of what we can do with the Callon assets.

Operator:

Good day, and thank you for standing by. Welcome to the APA Corporation's Fourth Quarter and Full Year 2023 Results Conference Call. [Operator Instructions]. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Gary Clark, Vice President, Investor Relations. Please go ahead.

John Christmann:

Good morning, and thank you for joining us. On the call today, I will review our key accomplishments in 2023, comment on fourth quarter performance and provide an overview of our 2024 plans and objectives. APA has a long-standing strategic framework for managing our business that emphasizes investing capital with a focus on long-term full-cycle returns, pursuing moderate sustainable production growth, strengthening the balance sheet to underpin significant cash returns to shareholders, responsibly managing costs, including rightsizing the organization commensurate with lower activity levels, growing inventory, both organically through existing play expansion and new area exploration, and more recently, building scale and/or adding inventory inorganically through acquisitions such as Callon. We have patiently employed this strategy through periods of considerable price volatility, and our approach going forward will remain unchanged. Looking at APA's results, there were a number of highlights in 2023. The more notable achievements include on the whole, delivering on all of our production and financial metrics very close to original guidance. Egypt gross oil production lagged expectations for most of the year, but this was offset by continued strong performance from the Permian. Free cash flow generation of nearly $1 billion, 66% of which was returned to shareholders. We repurchased $329 million of common stock and paid $308 million in dividends. Adjusted oil production increased 4% from the fourth quarter 2022 to the fourth quarter of 2023, driven by Midland and Delaware production, which was up in excess of 20% over the same time period. We successfully appraised the Sapakara and Krabdagu discoveries on Block 58 in Suriname, identifying an estimated 700 million barrels of recoverable oil resource. On the ESG front, we now have implemented more than 70% of the projects necessary to achieve our 2022 goal of eliminating 1 million tons of annual CO2 equivalent emissions by the end of this year. Additionally, we replaced or converted more than 2,000 pneumatic devices in the United States during 2023, which aligns with our priority to reduce methane emissions across our operations. And lastly, I want to recognize our operation teams for delivering the lowest recordable incident rate since we began tracking and reporting this metric. We highly value this commitment to safety and excellence, and thank you for your continued diligence on this front. Moving to fourth quarter results. Upstream capital investment of $520 million was slightly above guidance, as we spent $27 million on the initial phase of our winter exploration program in Alaska. The U.S. delivered another strong quarter, with oil production in line with guidance and up 12% compared to the fourth quarter last year. Throughout 2023, our 5-rig drilling program was highly efficient, meeting or exceeding all key performance metrics. Similarly, well connections and well performance were in line with or better than expectations. Our Midland and Delaware Basin teams are driving outstanding results, and we expect that will continue this year. In the North Sea, production for the quarter was below guidance due to unplanned compression downtime at both Beryl Alpha and Forties during the month of December. And in Egypt, adjusted production exceeded guidance, primarily due to higher natural gas production and the positive impact of lower oil prices on volumes within the PSC construct. Gross oil production, however, was lower than expected for a few reasons. For several quarters now, we have been working through some activity delays and scheduling constraints associated with limited available workover rig capacity in Egypt. In addition to routine well maintenance and uphole recompletions, we also utilize workover rigs for completing many of our new drill wells. With the increased size and improving efficiency of our drilling program, the demand for workover rigs to complete new wells has exceeded expectations. This meant the workover rigs were doing fewer recompletions than planned and our workover backlog increased throughout the year. Thus, while production from the new wells was a bit better than expectations, Egypt gross oil volumes fell behind as we could not adequately support the recompletion and workover programs. Compounding this, we also experienced a number of early life failures on new electrical submersible pumps known as ESPs. During 2023, we had 9 new wells impacted by early ESP failures, 2 of which occurred in the fourth quarter on high-volume wells. We have traced this problem to 1 manufacturing facility, and the situation is in the process of being remediated. In 2024, we will gear down the Egypt drilling program a bit, which will free up workover rig capacity to reduce the workover and recompletion backlog. I will say more about the effects of this on 2024 activity in a few minutes. Turning now to our 2024 outlook. Given the potential for a flat to lower price environment this year, we have established an activity plan and budget based on $70 WTI and $75 Brent. We continue to diligently manage overhead and operating costs, and we are reducing our total capital investment to less than $2 billion. This includes approximately $100 million of investment for exploration activities and $50 million for FEED work and potential long-lead items in Suriname. This year's budget will redirect capital to the Permian Basin, resulting in reduced Egypt drilling program, which I mentioned earlier. The outcome of this investment profile should be relatively flat year-over-year adjusted oil and natural gas production, but lower NGL volumes given our current plans to reject ethane. As in 2023, we expect robust Permian oil production growth to roughly offset production declines in the North Sea, while Egypt adjusted production remains relatively flat. In the U.S., total volumes will be up about 2% on a BOE basis despite our current plan to reject ethane for the entirety of 2024. We also project a strong finish to the year, with U.S. oil production up more than 10% in the fourth quarter of '24 compared to the fourth quarter of '23. This growth will be driven by the Midland and Delaware Basins, where we expect to achieve our goal of returning oil production to pre-COVID levels by year-end. In Egypt, we anticipate that our moderated pace of drilling will result in a gross oil production decline. However, adjusted production should remain relatively flat year-over-year, primarily due to lower oil price expectations and the moderating effects of the PSC. And in the North Sea, with our significant reduction in capital investment prompted by the energy profits levy, we anticipate a roughly 20% year-over-year production decrease. This includes the effect of a lengthy planned maintenance turnaround that will impact both second and third quarter volumes. Before closing, I'd like to take a minute to highlight our performance in the Permian and provide some thoughts on our pending acquisition of Callon Petroleum. For several years now, APA's Permian operations have been hitting on all cylinders and exceeding oil production guidance. We have delivered continuous improvement in well productivity and capital efficiency, and we expect this to continue in 2024. Since 2019, we have invested considerable time and technical resources in optimizing our drilling economics in the Permian Basin, and the results have been excellent. Our Midland Basin well productivity has moved up into the top quartile producers as measured by third-party analysts, and we continue to improve Delaware Basin productivity measures each year. The Callon acquisition we announced in early January will bring scale to our Delaware position and balance to our overall Permian asset base, making it fairly evenly weighted between the Midland and the Delaware upon closing. While Callon has experienced operational and productivity challenges in the past, more recently, they have begun to make good progress towards demonstrating the upside potential of their acreage. By leveraging APA's technical capabilities and work processes across the Callon acreage, we expect to further build on their progress, most notably in the areas of capital productivity from well spacing, target zone selection, frac design and drilling, completion and infrastructure efficiencies. When we first announced the acquisition, we assigned only $55 million to operational synergies and improvements. However, we are confident that there is substantial upside to this number. While the transaction is accretive on cost synergies alone, the big win-win for shareholders of both companies will be the integration of the assets into a larger Permian platform and the technical optimization, capital allocation, process knowledge and discipline that APA brings to the table. We look forward to updating our 2024 U.S. guidance upon completion of the transaction. In closing, we are managing the business with a clear and consistent strategy, adhering to our discipline and delivering on our commitments and financial objectives. In the last 3 years, we have reduced outstanding bond debt by $3.2 billion and repurchased $2.6 billion or 20% of our shares outstanding. Our Permian Basin and Egypt operations are delivering a high level of free cash flow, along with moderate oil growth in aggregate. We have progressed a large-scale exploration and appraisal program in Suriname to FEED study, and we believe this will drive high-margin oil production beginning in the 2028 time frame. And more recently, we have further expanded our exploration portfolio with large-scale opportunities in Alaska and offshore Uruguay. While the industry may experience some near-term commodity price weakness, we maintain a constructive medium- and long-term outlook. Accordingly, we will continue to invest a measured amount of capital in the differential longer-term exploration opportunities. And lastly, we remain fully committed to returning at least 60% of our free cash flow to shareholders through our base dividend and share buybacks. And with that, I will turn the call over to Steve Riney.

Operator:

[Operator Instructions]. Our first question comes from Doug Leggate with Bank of America.

John Christmann:

Yes, Doug, I'll first start off and say the ESPs was kind of the second factor and kind of piled on. The underlying factor is just the ratio of the workover rigs to the drilling rigs. And these aren't just normal pulling units. These are good sized workover rigs. And if you go back historically, we've usually run close to 2x to 3x, the workover rigs to the drilling rig count. As we've said, we use these workover rigs to complete new wells, to perform the recompletions and do the workovers. And our ratio really has been just slightly over 1. And so we're ratcheting back, kind of gearing down the rig program. We're still going to run 13 to 15 rigs. So it's not a major reduction, but we want to get the workover count work down. We've got a very large asset base there, and it's important that we're getting to the key workovers and the recompletions that underpin those decline rates. And so there's no reason to keep drilling more wells quicker and piling more ducks into the system right now, it's just not the most efficient use of capital given the workover rigs. On the sub pumps, you're exactly right. These were the high rate sub pumps that we needed as we brought on 9 big wells last year. There was a problem with the manufacturing. We've identified that, and we are in the process of fixing that. So that will get straightened out and is being addressed right now. But it's really more a function of trying to balance the workover rigs and the number of wells we're drilling with the drilling rigs on a go-forward basis to kind of get into equilibrium to make sure we're investing the capital wisely and efficiently and getting the most out of it. So once we work that down, I mean, I'd say today, we estimate we've got close to 13,000 barrels a day that's offline that needs to be worked over. We usually run around 5,000 barrels a day. So there's about 8,000 barrels a day there we need to work down and it's going to take a number of workovers and projects to do that. So we're on it. I think once we get into a good equilibrium point, then we can revisit the rig count at a later date.

John Christmann:

We're just going to guide to flat adjusted production, net production for Egypt for now.

John Christmann:

Yes. I mean I'll stop in, just a few things on Alaska, Doug, and then I'll hand it over to Tracey. But one, it's a large, underexplored area. As we put in the supplement today, it's 275,000 acres on state lands. It is highly prospective for what's become a proven play. And Tracey can get into some details into that in a minute. We are planning to drill 3 wells this winter. We are very close to spudding the first well. So we're not halfway through any of them at this point, but it's going to get fun here pretty fast. So Tracey, I'll let you talk a little bit more about the program.

John Christmann:

And Doug, 1 more thing on your first question. We're limited in Egypt with the number of workover rigs that are in-country. So you're not in the U.S. where you can just go pick up workover rigs and pull in units. We're dealing with a constrained resource there. And so we have to kind of gear around that at this point.

Neal Dingmann:

Hello. Can you hear me?

Neal Dingmann:

My first question is also on Egypt. Specifically, I want to understand -- definitely discuss and understand the need for the activity change in the region. John, can you just speak a little bit about what you're seeing on the recent well performance and productivity there versus last year? It seems to still be quite good. I would love to hear more color on that.

Neal Dingmann:

No, that makes sense. And then the second question just on the Permian. While I appreciate still not having yet the pro forma Callon guidance, are you able to say anything about just sort of broader decisions if you just simply add the D&C of your activity with theirs? Or I'm just wondering, maybe it's too early for that. And if it is too early for that, could you maybe instead just talk about the cadence, how we should think about the existing activity there this year?

Operator:

Our next question comes from Bob Brackett with Bernstein Research.

John Christmann:

Yes, Bob, you're good to go.

John Christmann:

Yes, Bob, as you know, you're limited on the winter window, and we are getting ready to get started with the first well. And we'll actually have 3 rigs drilling kind of simultaneously pretty quickly. So we do anticipate being able to get 3 wells down prior to breakup.

John Christmann:

Yes. You've got -- I mean, Tracey can say a few words, but you've got good seismic control. And they're fully supported. So we feel good about them, but it is exploration.

Charles Meade:

John, to you, Steve, Tracey and the rest of the APA team there. John, my first question, I want to pick up, right, where you kind of left off, I think on 1 of the first questions about Egypt saying that more workover rigs was not -- is not an option that you're limited there. Is that a -- is there a time frame for that? In other words, I understand you might not be able to get 1 in 3 months. But maybe in 12 months, you could get a couple more workover rigs. So is that a possibility? And then the other aspect of that is -- you look at try to debottleneck your system, is there a possibility that you could bring in some wireline or coiled tubing to offload some of the work items on your workover rigs?

Charles Meade:

Got it. Got it. I appreciate it. And then back to Alaska. I saw -- I read that 1 of your partners there referred to the prospects that you're going to test as Pika lookalikes. And Pika being the Santos development that went FID in '22. So I guess I'm -- I'm curious, would you agree with that characterization? And for those of us who are just coming up to speed and learning about this, can you offer some details on what -- if you agree, is a Pika -- that the prospects are Pika lookalikes? What that means?

Operator:

Our next question comes from Paul Cheng with Scotiabank.

John Christmann:

Yes. First of all, Paul, thanks for the question. I'll just say we're in the exploration phase at this point. So we've done a lot of scoping. It's onshore, it's state land, so things can move a little quicker than federal there. You're close to big pipeline capacity. But let's work through the exploration phase, see what we find and then go from there at a later date. So -- but we're excited about it.

John Christmann:

Well, a lot of that will hinge on, these are 3 separate tests of similar play concepts. And a lot of that would just hinge on what we found. So at this point, we're purely in an exploration phase. And we'll just have to come back and give you some characterization if we have the success there that we hope we have.

John Christmann:

Yes. I would just say, historically, we were running -- if you go back to pre-modernization, we are running 5 drilling rigs and 12 workover rigs. We took the rig count up more than 3x to 15 to 18, and we were only able to take the workover rig count up to 20. So we could only double that when we tripled the drilling set. And -- so initially, it wasn't a major problem because we were trying to get the efficiencies lined out on the drilling side. But as we got the efficiencies lined out on the drilling side, the workover rigs they were required to complete the drilling wells. And ultimately, we've got to make sure we're managing the base. So it's just -- it's a new phenomenon. And it's something that ultimately longer term, we're going to need more workover equipment in country. And there's just not a good short-term fix to that.

Neil Mehta:

Yes. First question I had was just on Suriname. Maybe you could step back, John, big picture, talk about where we stand here. And we know we've got the FEED study that you're working through and you're targeting an FID in 2024. But what are you focused on as it relates to Suriname and any updates as it relates to that project?

Neil Mehta:

And then the follow-up, we haven't really talked in Q&A about the U.S. production profile over the course of the year. Just maybe talk about your Permian plans. It sounds like it's going to be a little bit back half weighted with strong growth exit to exit. So just any thoughts on Permian oil and navigating the weakness, obviously, in local gas prices there, too.

Operator:

[Operator Instructions]. Our next question comes from Arun Jayaram with JPMorgan Securities.

Stephen Riney:

Yes, Arun, as you know, we've talked about this a number of times since every quarter. We have a very active and constructive working relationship with Egypt, but it does require that ongoing conversation and work of the issue. Fourth quarter, we ended fourth quarter with our lowest quarter end past due receivables for the year from EGPC. And so we continue to make progress. They've come down through the year. They kind of peaked in early second quarter. Today, we're about 25% to 30% below where we were at that peak level. So they're still elevated, past due receivables still elevated from EGPC, but they're lower and trending in the right direction, have been pretty much through the whole year.

Stephen Riney:

So you're talking about the ARO for Fieldwood?

Stephen Riney:

So that does not go through the capital program there. It's -- there's a booked liability on the decommissioning obligation there. And so it doesn't go through the capital program, that doesn't show up as capital expenditure.

Stephen Riney:

Yes. Can we -- maybe we could just take that offline instead of reconciling through the group here. I'll work with Gary to get back in touch with you. We can work through. I just want to make sure we understand the question.

Operator:

[Operator Instructions]. Our next question comes from Leo Mariani with ROTH MKM.

John Christmann:

Yes, Leo, I'll jump to Suriname first. I think we've been pretty clear that we see more exploration upside remaining in Block 58 versus Block 53. And so it was an easy answer to go ahead and let 53 go. When you look at the risk profile on Alaska, these are 3D and amplitude supported, but you're going to be -- this is a step out in an area where there's risk associated with it. So I'm not going to give you a number on a ratio, but it is exploration. We're taking -- we're going to drill 3 wells. And they are risky, but they're high reward. So -- and I don't know, Tracey, anything you want to add to that?

Leo Mariani:

Okay. That's helpful. And I just wanted to follow up on some of the comments that you guys made here. I just wanted to make sure I understood this. Did I hear a comment that APA might be adjusting its headcount a little bit downward in response to some of the lower activity levels? I know clearly that once you guys integrate Callon, I'm sure you'll have to take a fresh look at the whole organization. But did I hear that right, but perhaps you think that maybe you might cut some of the APA headcount here at some point?

Operator:

Thank you. I'm showing no further questions at this time. I would now like to turn it back to John Christmann, CEO, for closing remarks.

Operator:

This concludes today's conference call. Thank you for participating. You may now disconnect.

Operator:

Good day and thank you for standing by. Welcome to the APA Corporation's Third Quarter 2023 Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today's conference is being recorded. I would now like to hand the conference over to first your speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead.

John Christmann:

Good morning and thank you for joining us. On today's call, we will review third quarter highlights, discuss our outlook for the fourth quarter and provide a high level overview of our capital plan and anticipated production in 2024. For the third quarter in a row, adjusted oil production exceeded the high end of our guidance range; good execution and strong well performance in the Permian are the primary drivers of this trend. We also achieved the high end of our guidance in the North Sea during the quarter, which benefited from the production ramp of the Storr North well. In Egypt, gross oil volumes grew by approximately 4,000 barrels per day, which was a bit below expectations as previously disclosed. On a total company basis, third quarter reported oil volumes were up more than 15% from the same quarter in the prior year, and we are very pleased with this progress. Activity in the U.S. and Egypt remained steady, while we suspended drilling activity around mid-year in the North Sea. Our investment program in the North Sea is now directed towards safety, base production management, and asset maintenance and integrity. In Suriname, we achieved a very important milestone during the third quarter with the completion of a successful appraisal drilling program at Krabdagu on Block 58 and the subsequent announcement by our partner TotalEnergies of plans to proceed with feed work for a 200,000 barrel per day FPSO in the Eastern portion of the block. The planned oil hub is underpinned by an estimated 700 million barrels of recoverable oil resource at Sapakara and Krabdagu and is targeted FID by the end of 2024. Turning now to our outlook. In yesterday's financial and operational supplement, we issued fourth quarter guidance, which anticipates slightly lower production on a BOE basis compared to the third quarter. The primary contributor is in the North Sea, where the temporary shut in at Brae Bravo will result in volume deferrals of about 5,000 barrels of oil equivalent per day. In the U.S., completion timing will lead to a relatively flat quarter consisting of unchanged oil production and a small decline in natural gas. And in Egypt, a combination of higher oil and lower natural gas volumes should deliver BOE growth, but not enough to fully offset the downtime in the North Sea. Let me provide a bit more color on production operations in Egypt. In February, we established a gross oil target of 154,000 barrels per day for the fourth quarter. We now estimate that number will be closer to 150,000 barrels per day, which is up about 5,000 barrels per day from the third quarter. After successfully working through the challenges associated with ramping our rig count from 11 to 18, our drilling program is now performing as planned. However, we have experienced a growing backlog of work over projects over the last two quarters and a corresponding uptick in barrels offline. To address this, we have begun to increase our work over activity, which Dave can discuss further in Q&A. During the fourth quarter, we are opportunistically accelerating the completion of eight Permian wells from January into December and adding a 6th rig in the Delaware Basin. This will result in an increase in our estimated fourth quarter upstream capital to around $500 million and bring full-year upstream capital to just under $2 billion. I should note that these investments will not have a material impact on fourth quarter production. As we typically do at this time of year, I would like to provide a high level overview of our 2024 outlook, which we will follow-up with formal guidance in February. Recall that we entered 2023 with a planned upstream capital budget of $2.0 billion to $2.1 billion. As of today, we expect a similar range in 2024, albeit with some changes in regional allocation. We are targeting low-single-digit oil production growth next year, with expected increases in the Permian and Egypt more than offsetting declines in the North Sea. APA remains committed to returning at least 60% of our free cash flow this calendar year to shareholders. During the first three quarters of the year, we generated $673 million of free cash flow, 65% of which we returned to shareholders via dividends and stock buybacks. This leaves more to do in the fourth quarter, and we will fulfill our minimum 60% commitment for the full-year. One of APA's core principles is to produce oil and gas safely and to reduce the environmental impact of our operations. I am pleased to announce that we recently achieved an important milestone in reducing methane emissions with the conversion of over 2,000 pneumatic devices in the Permian to lower emitting technologies. Our programs to identify and eliminate emissions throughout our global asset base are ongoing, and we continuously seek to expand and improve them. In closing, we are committed to our strategy of maintaining a diversified portfolio and maintaining operational flexibility to respond quickly to commodity price volatility and other externalities. We are demonstrating this today through the reallocation of capital from the North Sea into the Permian and Egypt. We also remain committed to investment in a portfolio of exploration projects which have the potential to drive differentiated future growth and competitive full cycle economics. And with that, I will turn the call over to Steve Riney.

Operator:

Thank you. At this time, we'll conduct a question-and-answer session. [Operator Instructions]. And our first question comes from Doug Leggate with Bank of America. Doug, your line is open. Please go ahead.

John Christmann:

Yes, Doug, it's a good question. We're in the process right now working through the 2024 plan. Clearly, we've got some downtime that we've announced in the North Sea in the fourth quarter, as we do have a compressor that we had to haul onshore. We'll get that back on sometime early next year and then you'll be back at your base decline both for Forties and barrel. Forties is underwater flood, so it's got much lower decline than barrel. But we do not have the rig. We'll continue to focus on maintenance integrity projects and we'll come back early next year with a detailed look when we give out the 2024 plan.

John Christmann:

I think it's early on the --

Doug Leggate:

All right. Thank you. John, my follow-up is in Suriname; I managed to get a red eye to Total's Analyst Day this year and asked Patrick a very specific question about timing. And I wanted to get your perspective on this. What -- my understanding is that the 2028 schedule for first oil assumes a 42-month new build FPSO, but since that announcement, I understand that SBM has been selected with an early hull. In other words, a year earlier on that timeline with some 70% expected to be contracted at the time of FID. I know you're not the operator, but I wonder if you could confirm or offer any color around those points.

Doug Leggate:

Fair enough. Thanks, guys.

Operator:

Standby for our next caller. And that is John Freeman with Raymond James. John, your line is open. Please go ahead.

John Christmann:

John, it's a spot rig, we're picking up. It'll kind of go pad to pad. It will start in the Delaware on some oil pads, but then there's flexibility and we'll come back in February with a little more detail obviously on the 2024 plan and how that would sit.

John Christmann:

Yes, John, it's a great question. Yes. It includes about $150 million of expiration. I think you laid it out pretty accurately. You'll see a full-year without drilling in the North Sea. You'll see an increase in the Permian, relatively stable drilling lines in Egypt, and you will see about $100.5 million in terms of expiration is what we're sketching out at this point. So relatively stable program with continued exploration investment like we've done over the last several years.

Bob Brackett:

Yes. Good morning. You talked about in terms of the Permian; if we think about 12 net completions in 3Q is kind of driving flat production QonQ in 4Q, 20 net completions in 2Q allowed you to grow the following quarter. And it sounds like you've already connected 12 wells in October with 18 coming in the rest of the queue. Does that imply a pretty strong cadence into sort of 1Q of next year in terms of the Permian?

Bob Brackett:

Okay. Quick follow-up, if there is an FID in 2024 around Suriname, does that change that CapEx budget of 2.0 or 2.1 or it's kind of a rounding error?

Operator:

Our next question comes from Neal Dingmann with Truist Securities. Neal, your line is open. Go ahead.

John Christmann:

Yes. Neal, program it will be pretty stable. We're running 18 rigs in Egypt and it is a steady diet of both development and exploration and I anticipate that to be very similar next year. And we do expect to be able to continue to show good growth in Egypt.

John Christmann:

I mean it's really more a function of stability in the Waha pricing. And the wells we've drilled this year have been strong and very competitive. I mean I think at $3 at Waha, they're very, very competitive with Permian oil. So -- but it's really more a function of when we believe we'll have stability there at Waha that you can produce some end of the infrastructure.

Scott Gruber:

Thanks. Can you just coming back to Egypt, you mentioned growth next year. Is that going to be on a year-over-year basis or do you think the exit to exit will be up as well?

Scott Gruber:

Okay. And then, just think about the next few years. You have a project that would be moving forward in Suriname and obviously you have the carry from Total. You still have $1 billion or so of commitment. Can you just speak to whether that impacts your cap allocation across the rest of the portfolio on a multi-year basis?

Operator:

Our next question comes from Roger Read with Wells Fargo Securities. Roger, your line is open. Go ahead.

John Christmann:

There's no doubt Egypt needs more gas production. We're flowing everything we can into the grid, which is where our gas goes. Our program has been focused on oil as we receive 265 per MMBtu there. But short-term there's not anything we could do to increase gas production. But there are some longer-term projects, but we would need to work on a higher gas price there.

Steve Riney:

Yes, on the working capital, this is Steve. So we did have an increase in working capital in the quarter in Egypt, as you will see in the supplement. So the receivables did go up during the quarter, but receivables from EGPC actually went down during the quarter. And if we go back to first quarter of this year, when I think the concern about the payments from EGPC kind of surfaced at that point in time with the first quarter results in May. Since that time, from first quarter -- end of first quarter to the end of the third quarter, EGPC receivables have gone down and so have the past due receivables from EGPC. So I think we're in good shape there. We've made making progress; we've made some good progress. And as John always says, we're in constant contact with the highest level folks in Egypt about managing that receivable balance. So we're making some good progress there. More to go, but we're making good progress. I think the issue with a reason why receivables went up in the third quarter is because we were exporting more cargoes than selling them to third parties. And those third-party receivables have gone up during the quarter because we were -- third-party receivables were low at the end of the second quarter and higher at the end of the third quarter. So those are receivables that are just paid under normal terms from our normal credit worthy and on time paying purchasers of the oil coming out of Egypt in export cargos.

Steve Riney:

Right, right. And you'll see there is a -- at the corporate level, not just in Egypt at the corporate level, there's a meaningful increase in working capital during the quarter. And that also is just seasonal type things. We had some payables in particular a large one around taxes, large cash payment in taxes in the UK that comes in the third quarter. And so a lot of seasonality to working capital movements for the company as a whole.

Michael Furrow:

Hi, good morning. This is Michael Furrow actually filling in for Charles Meade.

Michael Furrow:

Hi, okay, just one question for me regarding Suriname. I know FID is not expected until late 2024 and this might be a bit premature, but when do you think that further exploration could occur within Block 58. And I recognize that Total is the operator here. So maybe a better way to frame it would be when would APA like to further explore Block 58 and maybe if you could even speak on Block 53.

Operator:

Please standby for our next question. And our next question is from Scott Hanold with RBC Capital Markets. Scott, your line is open.

John Christmann:

Alaska fits our exploration strategy and that is trying to build a high quality portfolio. We've got a proven operator, its state lands, very, very prospective acreage and it's something we look forward to sharing more in February. And it's all about a portfolio on the exploration side and having choices to high grade and drill the best things that are going to create the most shareholder value.

John Christmann:

Yes. I mean I think we like to look at both avenues, both the organic and the inorganic. And we stayed committed to an exploration program and you're seeing that pay off in Suriname and longer-term, but I also think you saw us last year bolster some acreage in the Delaware. So it's a diet of both that you're constantly looking at and you've got to continue to focus on adding to the assets as well as what can create value for your shareholders.

John Christmann:

Yes. I mean, I think with where we sit today, five to six rigs, David say, into the decade pretty easily. And that's focused on higher quality, longer laterals and we're always -- we've got a nice footprint that we're always moving inventory from one category of up into the high graded as we continue to test and find ways to make it all work, so.

David Deckelbaum:

Thanks for taking my questions, guys. John, I wanted to just ask, are you able to tell us the $150 million you have earmarked for exploration next year? This I guess to be more pointed about it, how much of that is included for ex-Suriname exploration?

David Deckelbaum:

Appreciate that. Maybe if I could just follow-up on Egypt. You talked about the growth trajectory in the next year and I certainly know that U.S. oil is anticipated growing next year. Can you give a little bit more color just on what's happening with the increased work over activity? What's driving that? And are there any alterations being made that this won't be a drag into next year? Or is this being factored in with greater frequency now that you have this increased rig count?

Dave Pursell:

Yes. And so just to follow-on what John said, we're working on a root cause analysis just to understand, are we seeing a structural change in well failures, we've seen a reduction in ESP run times, but we're doing a broader look at that. And to put some numbers on John's comment, on base level of work over inventory, that typically represents about 5,000 barrels a day of production that's offline at any given time. We've seen that increase to over 10,000 barrels a day, really from the end of the second quarter through today. So we've added a work over rig. We're doing some other things to start working that backlog down over time.

Leo Mariani:

Hey guys just wanted to follow-up briefly on Egypt here. I think you guys maybe added a rig recently. I think you were at 17 earlier in the year, if I sort of got it right. So just curious, is that just because of lower North Sea activity or just kind of reallocating dollars here? And then I guess just in general, obviously there's been significant instability there kind of in that Sinai Peninsula area bordering Israel there with the conflict that's happening right now. I mean, do you guys have any concerns over potential spillover into Egypt and have you been kind of in contact with the Egyptian government regarding them?

Leo Mariani:

Okay. That's helpful. And then, in terms of the $150 million in exploration next year, I don't want to beat a dead horse here, but as you kind of looking at that at a high level in your mind, does that include some dollars in Suriname at this point or is that just sort of kind of still an open ended proposition?

Operator:

And our next question comes from Geoff Jay with Daniel Energy Partners. Go ahead, Geoff.

John Christmann:

There I mean it's really just a continuous program. I mean, we're seeing the benefit of the deliberate approach we've taken. We've been focused on long laterals and really locking the rig lines down and giving the teams time to execute and you're seeing that we've continued to drill long laterals and we're continuing to have good results. It's really just a function of the timing of the completions. In terms of adding the sixth rig, it's really more allocation of capital from the North Sea into the Permian. And -- but we look forward to continuing to deliver strong results. And if you look fourth quarter is a little flattish compared to third quarter. A lot of that's because third quarter is running ahead versus fourth quarter running behind. So we're very, very pleased with the execution level in the U.S.

John Christmann:

Yes. Thank you for participating on our call this morning. I want to leave you with the following thoughts. We've completed a successful appraisal program in Suriname at Sapakara and Krabdagu and will advance a project through the feed process during 2024. In Egypt, gross oil production continues to increase on the success of our drilling program. And lastly, we continue to deliver outstanding results in the Permian, where we've added a sixth rig which will add to the momentum as we enter 2024. We look forward to telling you more about the things in February and thank you for the call.

Operator:

Good day and welcome to the APA Corporation Second Quarter 2023 Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your speaker, Mr. Gary Clark, Vice President of Investor Relations. The floor is your sir.

John Christmann:

Good morning, and thank you for joining us. On today's call, we will review second quarter highlights and discuss our outlook for the rest of the year. APA delivered strong results and made notable progress on a number of fronts during the quarter, most specifically with regard to drilling and completion efficiencies in the US and Egypt. A reduction in year-over-year per unit LOE and G&A costs, working capital improvements in Egypt and the appraisal of Krabdagu in Suriname. We also delivered on our production goals with total adjusted production of 325,000 BOE per day coming in at the high-end of our guidance range. This was driven by good Permian Basin in Egypt oil performance, partially offset by price-related dry gas curtailments in the Permian and unscheduled compressor downtime in the North Sea. Total adjusted oil production of 154,000 barrels per day exceeded our guidance by 4,000 barrels per day, driven mostly by the US. Capital investment during the period was in line with guidance as our average operated drilling rig count remained steady at 17% in Egypt, five in the Permian Basin and one semisubmersible in the North Sea. As previously planned, we released the Ocean Patriot in the North Sea at the end of June. US oil production increased by 6% compared to the first quarter and we are projecting a similar percentage increase in the third quarter. Our steady drilling program in the Permian is delivering substantial efficiencies and oil production increases, which we expect will continue, though the timing and size of pad completions can result in a lumpy production profile. APA's Permian rig activity is directed towards oil development in the Southern Midland Basin, where we currently have two rigs operating and oil-weighted development in the Delaware Basin, where we currently have three rigs operating. As we noted on our last call, we are deferring additional drilling and completion activity at Alpine High until natural gas and NGL prices improve. That said, the most recent wells placed online at Alpine High are performing in line with expectations, and we look forward to returning to work there in the future. Turning now to Egypt. Gross oil production of 141,000 barrels per day was in line with our guidance, drilling efficiencies, new well connections, completions and exploration success were all consistent with our expectations for the quarter. As a result, we are projecting gross oil production will be up 5% in the third quarter to 148,000 barrels per day and we are making good progress toward our fourth quarter guide of 154,000 barrels per day. In the North Sea, second quarter production of 42,000 BOEs per day was well below our guidance due to the previously mentioned compressor downtime. We expect volumes to increase in the third quarter to a range of 46,000 to 48,000 BOE per day, driven by higher operating efficiency and the positive impact of our store North well which went on production in late June. In Suriname, Block 58, we are currently focused on appraising last year's Krabdagu discovery. As previously noted, we have completed testing at Krabdagu 2 and results were consistent with our predrill expectations. At Krabdagu 3, we are in the pressure buildup phase, and data collected thus far is very encouraging. The DD3 semisubmersible rig is still on location and will be released upon completion of operations. We believe that no additional appraisal or exploratory drilling is necessary in the Sapakara and Krabdagu area at this time. Looking ahead to the second half of the year, we expect drilling programs to remain constant in both the US and Egypt. As a steady operational cadence in these areas enables more efficient operations. That said, we have reduced our full year upstream capital investment outlook to reflect previously noted North Sea platform drilling reductions, no additional drilling in Suriname this year and some minor service cost declines. We are also reducing our full year LOE outlook from $1.5 billion to $1.4 billion, which reflects our ongoing success in actively managing these costs down, as well as some price decreases associated with shorter-cycle items such as diesel and chemicals. APA remains committed to returning at least 60% of our free cash flow this calendar year to shareholders. During the first half of the year, we generated $366 million of free cash flow, 94% of which we return to shareholders via dividends and stock buybacks. Since the commencement of our share repurchase program in October of 2021, we have repurchased nearly 20% of total shares outstanding at an average price of just under $34 per share. In closing, we believe the investment case for APA and the E&P industry is strong and that the longer term outlook for hydrocarbon prices is very constructive. APA has a diversified portfolio and the operational flexibility to quickly respond to commodity price volatility and other externalities. We are committed to our shareholder returns framework into allocating capital for the long-term benefit of investors. APA seeks to produce oil and gas safely and to reduce the environmental impact of our operations. Last month, we issued our 2023 sustainability report, which highlights recent achievements on these fronts, as well as our current ESG goals and initiatives. I encourage all of you to review this report, which you can find on our website. And with that, I will turn the call over to Steve Riney.

Q – Doug Leggate:

Good morning guys. I'll take that. Thanks for taking my question.

Q – Doug Leggate:

Yes, it's more exotic than it probably should be, but—good morning, John. So couple of things from me. So I want to ask about Egypt, not about the working capital progress, which is terrific. I think you've addressed that, Steve, with your commentary. But I want to ask about the confidence in the medium-term oil growth trajectory in Egypt. That seems to be the only knock on the quarter is that folks or maybe a lot questioning whether you can actually deliver that. So, how is that progressing? What is the outlook today? And I've got a follow-up, please.

Dave Pursell:

Yes, Doug, as John alluded -- or John said, the gross oil at 145,000 in July gives us confidence. We have a couple other data points. We've had good success on exploration in both the [Indiscernible] Basin. So we have good line of sight on the well stock remaining through the rest of the year that will come online. If you look at expected wells online in the back half of the year, it's significantly higher than the front. So, just some numbers first half of the year, we brought 48 wells online. In the back half of the year, we expect to put over 70 wells online. So more wells, high-quality, good confidence in what those wells look like. So again, our confidence in the back half guidance is very good, very high.

Dave Pursell:

We continue to look at the 2024 plan, and we're too early to give guidance, but we have confidence in the ability to keep the growth engine moving.

John Christmann:

I mean at this point, a couple of things, Doug. Number one, we still have the rig on location, so it's early. Number two, we came into this year with the primary objective being appraising the Krabdagu Fairway. And you had the original discovery well -- if I flip over, it's a totally different set of partners in Block 53, but we -- when we announced the Baja discovery, we said it was a down dip low above that fairway. So yes, it does stretch from there all the way now back to Krabdagu 3. Krabdagu 3 was 14 kilometers from the discovery well. And as we've said, the results are very, very encouraging. We do -- we can confirm its oil, but it's early for me to comment or say anything at this point. We've got a lot of technical work to do. It's a very large fairway and there will be resource in there that you're not going to see from the flow test. So there's just a lot of technical work that we need to do, and we'll come back in due course with information in the relatively near future.

John Freeman:

Hi, guys.

John Freeman:

Yeah. The first topic I wanted to address was on the shareholder returns. You returned the 131% of free cash flow this quarter. Last quarter, you did 81%. So I'd just be curious kind of your thought process and kind of how you'll determine when it's the appropriate time to kind of really lean into to shareholder returns, like you did, obviously, that was more than double the minimum 60% target that you'll have. So just sort of how you all think about when it's an appropriate time to kind of lean into these things.

John Freeman:

Okay. And then my follow-up, just kind of following on to Doug's questions on Egypt. Just sort of what you all identified in terms of the you got the mature natural gas field that's declining so that oil mix as we've seen now for the last three quarters just keeps inching up. It looks like just ballpark that for 2024, like something in that like 65% kind of oil mix would be possible. Just sort of any commentary about how you all see that oil mix sort of continue to evolve as it continues to ramp up.

Operator:

Thank you. One moment for our next question. That will come from the line of Neal Dingmann with Truist Securities. Your line is open.

A – John Christmann:

Neal, it took us a little bit on last year with training programs to kind of get the program where we wanted it. We're there today. So we feel good about that. We've put a lot of training in place I think right now, 17, 18 rigs is a pretty good number. I think it's about all that's in country and from a staffing perspective. So I think we're in a pretty good place. And you're seeing us finally get the results and the efficiencies where we were hoping we'd get to. So we feel like we're in a good place. And right now, that's what I see for the foreseeable future.

A – John Christmann:

Yes. We came into this year really with our programs focused on the longer laterals, a lot of two and three milers. So Dave, I think you've got little more color or some statistics there.

Operator:

Thank you. One moment for our next question. That will come from the line of Scott Gruber with Citigroup. Your line is open.

A – John Christmann:

It's early in terms of numbers. I mean we typically don't start getting into 2024. I can tell you, we're working the 2024 plan and a lot of detail right now that we start getting into reviewing that and so forth in the fall. I would anticipate pretty level activity sets from where we are today. And so if you look at that with the programs we're delivering and the types of laterals we're drilling, I would expect fairly similar increments of growth may be on a little higher base in terms of with the volume that we're growing this year. But it's always lumpy. We're running five rigs with the timing -- so I don't know how the timing will line up year-over-year, fourth quarter over fourth quarter, some of those numbers. But I would expect a very strong continuous program in the US and in Egypt for 2024.

John Christmann:

I mean, I would say right now, the plans would be to take the program and let the program dictate because five rigs, we're working 1.5 frac crews, a pretty good cadence there. It's hard to just add incrementally without going up in stair step function. So I would anticipate that the service side, whatever benefits there would come to free cash flow and the program will be pretty stable. We do try to go in every year with a pretty set framework on the capital side. And so a lot of what's going on this fall will dictate what our service costs will look like for the portions that we will try to lock down for next year. So we'll just have to wait and see how things play out. And clearly, you've had a little bit of softening in some areas right now, but I think everybody is waiting to kind of see what prices do in the back half of the year. to really steer next year's capital.

Charles Meade:

Good morning, John, to you and your whole team there.

Charles Meade:

John, I have to say I'm as I'm sure you guys all are to see all the -- or to learn about all the appraisal results at Krabdagu, but I recognize we're going to have to wait a little bit. So I want to instead ask about Waha. And specifically, what your plans are or what the considerations are for appraisal there? I recognize that you guys said it's in the same deposition system as a Krabdagu. And perhaps as part of talking about your plan for appraisal, can you also address it, is it also one of these shelf slope kind of targets, or has it is -- are you maybe starting to hit the transition into the basin four fans out there?

Tracey Henderson:

Sure. Good morning, Charles. I think great question on the fairway and your initial assessment there about in a system what we've discussed in the past. So what we're describing is a fair way. And as John mentioned in his remarks, something we've defined now that's roughly 25 kilometers from Waha to Krabdagu 3. So you've got a very robust system that's coming through here in a series of slope channels that you call from our original release at Krabdagu 1, which are stacked systems. So correct in your assessment, we're seeing slope channel systems, as John said, we've got more technical work to do. We still got a well on location and a lot of work to integrate going forward.

John Christmann:

You bet.

Roger Read:

Thank you. Good morning.

Roger Read:

John Just like to ask about Egypt and not from an operational standpoint, but it's been more financial, I don't know if I'd call it risk or just it's Egypt being Egypt. But I was just curious how things are going in terms of your ability to from the operations in the country, return capital out of the country as needed or as desired and anything else we should be watching there?

Roger Read:

Okay. I'll take that as a good answer. And then my other question is just as you look at operations in the Permian, what would be the broader description of sort of productivity and efficiency gains you're seeing sort of leaving any service cost inflation or deflation aside, but just what you're seeing in terms of performance on the drilling side, on the completion stages, things like that.

Operator:

Thank you. One moment for our next question. And that will come from the line of Arun Jayaram with JPMorgan Securities. Your line is open.

John Christmann:

Yes. I mean, Arun, first of all, it's -- like we said, we're rigs still on location, and so we've got a lot of technical work to do. But we'll come back at some point with more data. That is exactly what you just mentioned would be the steps you'd take. And we've got a lot of work to do to be in a position to do that. And obviously, we'll be working with our partner in Total. So.

A – JohnChristmann:

The only thing I'd say, and I'm going to defer, we'll let Total handle those relationships, and that's what they're -- they'll be operator, right? I'll just leave it at that. But I mean, I would say we came into this year with the goal to appraise Krabdagu because we said it could impact scope scale. And clearly, we've had a positive result at Krabdagu 3. So that was one of the objectives with the appraisal program and the number three well was designed for a very large step up to better understand potentially what type of resource we could have there. So we've got a lot of technical teams do the work, but that was the objective coming into this year was to help better understand scope and scale.

A – JohnChristmann:

I mean obviously, the nice thing is, is having a diverse portfolio where we've got places to put capital. And we basically program in the North Sea with the Ocean Patriot for six months. You see us in a good position in terms of sustaining and growing the company. So as we look at next year, we'll factor in what makes sense. But right now, more importantly from the North Seas perspective, you'd need to see some stability in the regime to make long-term investments. And right now, we have not seen any stability. And so I would not anticipate us jumping in because prices are up and deciding to put a lot of capital in the North Sea at this point than what we need to do for maintenance and integrity and safety.

Q – Leo Mariani:

Hi, guys. I just wanted to follow-up quickly on Suriname here. So certainly seems as though you guys have found significant oil here, Krabdagu based on the comments you've made. I understand there's more technical work to go. But I'm just curious little bit kind of around the thought process on kind of stopping drilling for the rest of the year. It feels like you've got great momentum there. You found a lot of oil at the end of the day, why get rid of the rig for the last, call it, four or five months of the year, why not sort of building that momentum, drill some of the other exploration targets just given how vast the basin is at this point in time?

Q – Leo Mariani:

Okay. And then just in terms of the US well performance, you guys talked about this a little bit. It sounds like there have been some changes to the completion design potential here with a little bit kind of wider spacing. But it seems like the oil performance there has been a lot more consistent. You guys basically said that it looks like 2023 well performance is a little better than 2022. Just kind of wanted to get a little sense of what do you think the kind of running room here is on kind of the Tier 1 Permian acreage. If you look out handful of years. Do you guys have kind of an estimate on how long you can kind of keep five rigs running and kind of how much inventory you have maybe in terms of kind of rig years or something?

A – John Christmann:

Yes. The other thing I would add is if you look at the evolution of the program, a lot of the stuff we're drilling today that's Tier 1. Two years ago, we had it at Tier 2, Tier 3, right? We've got a nice acreage footprint. And so you're always also looking to see the evolution of the resource. So we've got strong confidence in the U.S. inventory at this program rates.

Q – Jeffrey Lambujon:

Good morning, guys. Appreciate taking my questions. I wanted to ask my first one on US activity. Just wondering if the two Midland and two Delaware quits good to assume as part of that base case of steady activity. And if you could talk about how you think about toggling that in the near term, if at all, whether in terms of inventory comparing the two or any of the factors, I'd imagine the flexibility of the Delaware in terms of proximity of the Alpine High plays into some degree if you can also maybe speak to what you want to see there in the macro or from the wells to add back any sort of capital there?

Q – Jeffrey Lambujon:

Okay. Great. That makes sense. And then maybe just a follow-up on the North Sea. I know it's already a relatively smaller to the budget and getting smaller, just looking to next year with the release of the Ocean Patriot, as you guys highlighted, but can you talk about what sort of operations we should think about there just in terms of steady state going forward and what that means for CapEx? It seems like year-over-year, you could maybe be looking at something like maybe half the spend that was originally budgeted for this year.

Operator:

Thank you. One moment for our next question. And that will come from the line of Paul Cheng with Scotiabank. Your line is open.

John Christmann:

Yeah. So Paul, the -- you get to the 800 million as we've disclosed at Sapakara from the original well, the second well, we had more than 600 million barrels of connected resource. So that's where six of it comes from. And then the original 200 was from the discovery well from the flow test we did there at Krabdagu. So the 800 million number is -- would be a connected resource in place, and it's not a recoverable number, but it also does not include Krabdagu-2 or Krabdagu-3 and the integration work that's going on now that will move forward. So -- and Dave, you might reference just it's really high-quality rock, and it'd be early to talk about actual recovery factors, but you can give some insights there.

Paul Cheng:

Do you have a rough estimate, what's the gas cut in that content there?

Paul Cheng:

Yeah, yeah. What's the gas percentage, or what's the oil percentage either way?

John Christmann:

Yeah. Sapakara was 1,100 GOR, roughly. And the discovery well at Krabdagu had a couple of different ranges from around the high-teens to the high 2000s.

A – Dave Pursell:

Yes, Paul, this is Dave. I don't have that number. It's a relatively small percent of the total work plan. We're happy with the results from our three milers. It's really just a question of where does the acreage footprint allow that to allow us to drill the three milers. You can tell just on the numbers I threw out earlier, most of what we're drilling are two milers. But the team, any time we get a chance to drill three miler, we'll do it and that's just acreage footprint. But from a modeling standpoint is probably best to just assume they're all two milers program.

Q – Umang Choudhary:

Hi. Good morning and thank you for taking my questions.

Q – Umang Choudhary:

My first question is on the $100 million savings from your operating cost management program. You talked about diesel and chemicals driving some things there. Any additional color you can provide in terms of any other buckets, which is driving those savings?

John Christmann:

I mean, I think, in general, you've seen a couple of deals take place in the Permian. They've traded at what we viewed as pretty high valuations. You look obviously focused organically. But you've always got to be on the lookout for things that could make sense. And obviously, that's where we are and what we do. We come in every day to try to make this company more valuable and more attractive. So….

John Christmann:

Yes. Thank you for participating on our call today. I want to close with the following thoughts. Our asset teams are executing at a high level, and we have a high number of quality wells scheduled for the back half of the year which gives us confidence in achieving our full year production guidance. We're progressing in a positive direction in Suriname, and we remain committed to our capital return program. We look forward to keeping you apprised of our progress. Thank you.

Operator:

Good day, and thank you for standing by. Welcome to the APA Conference Call. [Operator Instructions]. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Gary Clark, Vice President of Investor Relations.

John Christmann:

Good morning, and thank you for joining us. On today's call, we will review our first quarter highlights, update our operational progress and comment on our outlook for the remainder of the year. For the last several years, we have been navigating a volatile price environment, and this has been amplified recently with the ups and downs of global oil prices, extreme moves in global LNG pricing and the rapid decline in U.S. natural gas prices. Despite this volatility, we are constructive on long-term prices for oil, natural gas and LNG. Based on this fundamental belief, we plan to invest over the long term for sustainable low single-digit production growth at attractive returns. That said, we cannot ignore price volatility and will, therefore, seek to moderate our investment plans during periods of significant price weakness. We must also be responsive to changing governmental tax and regulatory regimes within our countries of operations. Fortunately, our diversified portfolio provides us optionality, and we maintain the flexibility to adjust our investment plans relatively quickly. In 2023, we have demonstrated this by reducing natural gas directed activity and even curtailing production in response to extreme Waha price dislocations. We also made the decision to reduce spending in the North Sea as the recently enacted energy profits levy has resulted in less competitive return opportunities than in the U.S. and Egypt. So while you should generally expect us to invest at a steady pace for long-term returns and moderate growth, you will also see periods where we respond to external influences by adjusting or redirecting capital activity. Turning now to our first quarter results, which are characterized by strong operational performance and good cost control. APA met or exceeded production guidance in each of our 3 regions. Total adjusted production was 4,000 BOEs per day, above the top end of our guidance range. Adjusted oil production also exceeded expectations, led by performance in the Permian and the North Sea. Capital investment during the period was slightly below guidance, and our average operating drilling rig count remained steady in the quarter with 17 in Egypt, 5 in the Permian Basin and 1 semisubmersible in the North Sea. In the U.S., we connected 17 new wells, and as planned, most of these went online in the back half of the quarter. While timing of well connections can drive production variances, on a quarter-to-quarter basis, we are continuing to see significant benefits from the steady pace of our drilling program. As expected, first quarter oil production declined sequentially from the fourth quarter. However, we remain on track to deliver a significant uptick in the second and third quarters. Permian activity this year will be concentrated primarily on oil development in the Southern Midland Basin and oil-weighted development in the Delaware Basin. At Alpine High, we are currently testing a new 3-well pad at a constrained rate. Beyond this, we are ramping down our planed 2023 lean gas drilling activity in the Permian due to the prevailing weakness in Waha natural gas prices. This will result in an upstream capital reduction of approximately $100 million but should have no material impact on our full year U.S. production guidance. We are pleased with the results at Alpine High and will return when Waha prices improve. In Egypt, gross oil production increased by approximately 1,200 barrels per day compared to the fourth quarter. New well connections, recompletion activity and exploration success were all consistent with our expectations, and we are beginning to see positive contribution from our higher activity pace. For the second quarter, however, we are forecasting that Egypt gross volumes will be roughly unchanged as we have recently experienced some production disruptions, most of which are temporary. Despite this, our full year Egypt production guidance has not changed. Turning now to the North Sea. Our production exceeded expectations in the first quarter, driven by strong facility operating efficiency. We are projecting second quarter average daily production will be in line to slightly below the first quarter as scheduled platform maintenance and expected return to more normalized facility operating efficiency will be mostly offset by contribution from a new well, which was placed online in late March. In Suriname, we continue to progress toward an oil hub development project with activity in the first half of 2023 focused on appraising Krabdagu. We have completed the flow test on the first appraisal well and are currently in the pressure buildup phase. Results of this well thus far are in line with expectations. The second Krabdagu appraisal well is currently drilling and we'll provide more information on next steps in the future. On the ESG front, we delivered another excellent quarter of safety performance and are making good progress toward our longer-term emissions goal of implementing projects to eliminate 1 million tons of CO2 equivalent emissions by year-end 2024. We reduced routine upstream flaring in Egypt by 40% last year, which gave us an excellent start on this goal. In 2023, we plan to further reduce flaring in Egypt and focus on converting diesel combustion for power generation to field gas, which will reduce both cost and net emissions. In closing, APA has the portfolio and the operational flexibility to respond quickly to near-term commodity price volatility, and we are managing our capital activity accordingly. We remain committed to returning a minimum of 60% of our free cash flow to shareholders this year via dividends and share repurchases. Longer term, despite many cross currents, we believe the investment case for APA and the E&P industry is strong, and the outlook for hydrocarbon prices and fundamentals is very constructive. And with that, I will turn the call over to Steve Riney.

Operator:

[Operator Instructions]. Our first question comes from John Freeman of Raymond James.

David Pursell:

Yes, John. This is Dave Pursell. We may have had more than 5 wells planned for the middle of the year. But if you're trying to -- there's some moving parts in the Permian budget, but the effect is, yes, the net $100 million is essentially all the Alpine drilling, completion and facilities capital rounds up to $100 million.

John Christmann:

Well, John, I mean, we did add some more weighted drilling in the Permian with that. That was contemplated. And then you're seeing us drop some of the gas weighted drilling at Alpine. So two effects there.

Doug Leggate:

Sorry, guys, can you hear me now?

Doug Leggate:

All right. Sorry about that. I'm sitting in an airport. I have my new boss in on. I apologize, John. My first question is for Steve, actually. Steve, I wonder if you could just elaborate a little bit on your comments about the increase in receivables in Egypt. There's obviously, I think, some concern events over there, the devaluation and so on might have an impact on your ability to get cash out of the country. So I'm just going to hit that right upfront and ask if you can walk us through what you're seeing currently and whether that working capital build is in fact reversible.

John Christmann:

On Egypt, just a couple of minutes here, Doug. One, we've been in the country for more than -- almost 30 years and we've partnered with Egypt and EGPC and the highest levels of government the whole time. I'd say over that time period, Egypt has been through a number of challenges and successful reforms. The best thing that we can do to help Egypt and our stakeholders is to deliver oil production growth. And that's what we're doing while reducing our emissions. Egypt, like many other places in the world today, is going through a challenging economic time with inflation. This does have some flow-through to us, but not anything that we haven't had to work through in the past. And in fact, there's been more difficult times in the past. Specifically, they are dealing with the after effects of a currency devaluation in January, and we are currently helping our Egyptian National employees through this as we have also done in the past. We maintain very deep and long-standing relationships with our Egyptian stakeholders, both at EGPC and within the government at the highest levels, I'll say. And we are confident that they will work through this. And we are also having very constructive conversations on how to address the receivables over time currently. So we feel good and a long track record here.

Doug Leggate:

Just to be clear, guys, always that balance you talked about in receivables. Are you able to get cash out of the country? Or was that an accumulation of -- basically because it's the highest free cash flowing asset in your portfolio currently? Is this -- are you able to get cash out of the country currently?

Doug Leggate:

Okay. My follow-up is, John, there are a few teasers in the deck about the status of Suriname moving towards potential hub development, I think it was the expression -- and you said you've got the results of at least the first appraisal well at Krabdagu. I wonder if I could ask a question like this. You said the result is in line with expectations. So what were the expectations? And what would you need to move forward by way of resource upside to the more than 800 that you identified in the deck today?

Operator:

Our next question comes from Bob Brackett at Bernstein Research.

John Christmann:

Yes.

John Christmann:

Yes. Bob, I'd say the first thing is, you know we've got a very large asset base area that stretches really from Cairo, almost to be. And we've got a number of fields, and I'll let Dave walk through some of the temporary things and then another minor issue.

Operator:

Our next question comes from Charles Meade at Johnson Rice.

John Christmann:

Yes, Charles, I don't know where you got any ideas on time line because it wouldn't have been from us, but just because Total is operating. I would say the Krabdagu 2 moved on pretty much as expected. We're just in a period now where we're gaining data through the buildup. And so that is the most important information in terms of connected volumes. I will say the Krabdagu 3 well is running a little behind, but that also was a brand-new rig that was brought in the basin. And so there's been some fits and starts on the drilling of the third well. So I wouldn't read too much into that other than it just is taking a little longer than anticipated.

John Christmann:

As we said in the prepared remarks, we're seeing good results on the program there. There's no reason to invest the capital today into this price environment. And so I think we want to see the infrastructure kind of get resolving it through this and feel like we're in a good place because we're making long-term investment decisions here. I'm very pleased with the results but we want a clear pathway on a more constructive price environment for gas.

Charles Meade:

Right. But no -- nothing you're prepared to share about what Waha needs to be for some duration before you decide to put dollars back there?

Operator:

Our next question comes from Paul Cheng at Scotiabank.

John Christmann:

Yes, Paul, I'll let Dave jump in. But it is timing. We said most of the wells came on late in the first quarter in the Permian. And then effectively, your well counts are going to be pretty similar because we're dropping the gas-weighted drilling in the Permian, and we're adding some oil weighting. So it shouldn't have a big impact on the numbers, I wouldn't believe. But Dave, I'll let you...

Paul Cheng:

Okay. And on the second question, the gross production for Egypt, can you just remind us then what is your full year expectation now? And also over the next several years, what kind of budget and what kind of growth rate that you have in mind on the gross production for that?

Paul Cheng:

And what's the risk -- what's the biggest risk that you will not be able to achieve that for this year?

Paul Cheng:

Yes. certainly the first quarter second quarter is definitely, I suppose that is below what you've been looking at. And so you need to step up. And some of the challenge seems it's going to totally go away. So I mean, how big is the cushion when you're talking about 10% year-over-year exit rate?

Paul Cheng:

And do you have a budget that you can share for the next several years, we need to related to Egypt to achieve that plan?

Operator:

Our next question comes from Neal Dingmann at Truist Securities.

John Christmann:

I mean you're cutting out a little bit on the question. So I didn't -- I think I -- it's about capital discipline. I'd say, I think, in general we feel good about where we are. Most of our capital costs are under contract. So it's about cost control and execution. We've made some choices to move some things around and you're seeing the impacts of those. And that's some of the flexibility of the portfolio. But everything is within line and really, we don't plan to drill wells that we wouldn't want to complete. And that's why you see us kind of curtailing the drilling in the gas-weighted programs in the U.S.

John Christmann:

I would just say it's early, right? Everything is still under contract. I think where you'd start to see that as we start looking at, thinking about the '24 pricing and so forth, as you start pricing that in towards the middle of the year into next year. But right now, as you know, the cost structure always lags. And so we haven't seen any real direct softness today.

Arun Jayaram:

Maybe, Steve, I want to ask you a little bit about the working capital build in the quarter in Egypt in the U.S. and just thoughts on the drivers of that. And would you expect that to reverse in 2Q over the balance of the year?

Arun Jayaram:

Great. And just my follow-up, maybe for David. David, in order to hit, call it, the midpoint of the full year oil guide, the business would have to average oil production in the upper 160s for the back half of the year. Just -- it sounds like your 2Q guide is a little conservative. But maybe if you could help us walk through and give us comfort on hitting those levels because the midpoint is 159 for oil.

Arun Jayaram:

No, just full year oil or the component.

Operator:

Our next question comes from Leo Mariani at Ross MKM.

John Christmann:

Yes, you're cutting out for most of your questions. So I think it's -- do we have enough. And I think the answer is, as we've said all along with Krabdagu, we're looking at an oil hub, which incorporates both Sapakara and Krabdagu. And the thing we've been focused on is a scope and scale right. So at this point, it's all I'll say the connected original in place. We put in the documents this morning does not include the appraisal work from Krabdagu yet. So we're making good progress.

John Christmann:

At this point, no update on the Chalk. And on the Alpine wells, we're flowing them back at constrained rates, but we're very pleased with the deliverability and the early results.

Roger Read:

Yes. I guess maybe follow up a little bit on some of the oilfield inflation, deflation issues and broaden it beyond the U.S. to take a look at what the currency issues might portend for the cost structure in Egypt. Or does that not matter given the overall structure of the contract there in terms of the net barrel performance?

Roger Read:

So you wouldn't expect a net reduction given like you said, kind of devaluation issues.

Roger Read:

Okay. And then in the U.S., you mentioned obviously contract structure in place. But I was just curious, are you looking at indexed contracts? When is the next time we should see any potential for an inflection up or down in terms of the next contract rollover as we think about the rigs and the services?

Operator:

Our next question comes from David Deckelbaum at TD Cowen.

Stephen Riney:

No. For quite some time, our is that every molecule of gas we produce in the Permian Basin is sold in the Permian Basin, and our trading organization will take care of both the long-haul transport obligations through purchasing and selling gas, and we'll also take care of the Cheniere contract with purchased gas.

John Christmann:

I would just say we're waiting to see results, right? I mean we're making good progress. As I've said a number of times, we're kind of focused on potential scope and scale of what that first project would look like as there's an incentive for everybody to size upwardly. But we'll know when we get there.

Unidentified Analyst:

There's been much discussion in this earnings season about potential deflation on shale well costs, but I'm curious what you're seeing on the international side. Outside of the increased receivables, what is your view on raw materials and services in Egypt and the North Sea? And how is that trending relative to last year?

David Deckelbaum:

Great. And congratulations on reducing your 2023 CapEx budget. Kind of going back to the Ocean Patriot rig, are the savings from dropping that rig already built into your updated budget you released yesterday? Or have those savings effectively been redirected to the Permian?

Operator:

Our next question comes from Neil Mehta at Goldman Sachs & Co.

John Christmann:

Well, I'll say a few comments and I'll let Steve jump in on the balance sheet. But I'd say, first and foremost, the best flexibility you have is being able to reduce your activity. And you've seen us do that with the lean gas drilling in the U.S. You've seen us do that in the North Sea. So when it's time to stop investing, you need to stop investing. And those are the lessons we've learned. Stay focused on cost and maintain that flexibility to invest in the projects that are going to continue to generate the long-term returns.

Neil Mehta:

Can you remind us where you are in terms of getting to investment grade with all the agencies? And given what you've done with the balance sheet, I feel like you're getting close [indiscernible]. So any perspective on

Operator:

Our next question comes from Jeoffrey Lambujon at TPH & Co.

David Pursell:

Yes. So Jeffrey, good questions. This is Dave. On the 3 miler question first, we tend to like to drill 3 milers where the acreage is set up for that. It's very capital efficient. We've been able to execute those really well, both on the drilling and the completion. So where it's possible, we'll do that. But I think you should think about the majority of our portfolio or 2-mile laterals. So the typical well is going to be a 2-miler. On productivity, we continue to -- the team's work and study and try to squeeze out productivity gains on every pad we get on -- and we continue to have pretty good results with that. So we're -- I don't know how you think about that externally if we've got some -- a pretty good process in place and feel comfortable with it. We've got a good methodical pace of drilling and completions and are pleased with that pace at this point.

David Pursell:

Yes. So inventory, we've consistently said we've got line of sight kind of through the end of the decade. And we keep adding things to it. And that number will move around over time. At the current cadence, I think you could look at the second and third quarter activity pace and roll that through into '24, but we haven't really given guidance yet on '24 on what the capital program and activity would look like. We're assuming that we kind of hold serve on productivity gains. But again, the aspiration is to continue to squeeze more out of each completion.

John Christmann:

Thank you. Before closing the call, I want to leave you with the following thoughts. First, our asset teams are executing well. Safety performance continues to be good, and contributions from our drilling programs are strong. We are managing the portfolio to optimize returns and near-term cash flow and keenly focused on cost control. Second, we continue to make good progress on our appraisal program in Suriname and look forward to sharing more information in the future. Lastly, we remain committed to returning at least 60% of annual free cash flow to investors through dividends and buybacks and believe our stock is a compelling investment. We plan to participate in a number of investor events over the next 2 months and look forward to seeing you. Thank you.

Operator:

Thank you for standing by. Welcome to APA Corporation's Fourth Quarter 2022 Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead.

John Christmann:

Good morning, and thank you for joining us. On the call today, I will review our key accomplishments in 2022, comment on fourth quarter performance, and provide an overview of our 2023 plans and objectives. Ahead of the pandemic, in 2019, we established a pragmatic long-term plan for our business that emphasized returns-focused investment, strengthening the balance sheet, right-sizing the organization and activity levels to deliver moderate sustainable production growth, conservative budgeting, and the selective pursuit of differentiated opportunities for value creation, most notably, exploration. The world oil demand and commodity price dislocations that followed in 2020 and 2021 required some difficult and necessary actions to preserve our business. After a few years of hard work, we have returned to and are delivering on this long-term plan. In 2022, we generated a second highest annual free cash flow in the company's 68-year history, which we allocated primarily to debt reduction and cash returns to our shareholders. We also increased our rig activity to a pace that is now capable of generating sustained production growth in both Egypt and the U.S. Some of the more notable achievements of the past year include free cash flow generation of $2.5 billion, 66% of which was returned to shareholders. The repurchase of $1.4 billion of common stock at an average price of less than $40 per share and the doubling of our annual dividend, a $1.4 billion or 23% reduction in outstanding bond debt, an increase in adjusted oil production from the fourth quarter 2021 to the fourth quarter 2022, which represents our first exit rate to exit rate oil production increase since 2018. The successful integration of our Texas Delaware Basin tuck-in acquisition, which compliments our legacy Delaware position and continues to exceed expectations. And importantly, on Block 58 in Suriname, the flow test of two appraisal wells at Sapakara South, which indicated a combined resource in place of more than 600 million barrels of low GOR oil. At Krabdagu, the discovery well was also successfully flow tested. An appraisal is now underway with two rigs. Additionally, in Block 53, the first oil discovery was made at Baja, which is on trend with Krabdagu. And lastly, on the ESG front, routine upstream flaring in Egypt was reduced by more than 40%. This is a significant step toward our goal of eliminating 1 million tons of annualized CO2 equivalent emissions by the end of 2024. Moving on to fourth quarter results. Following some operational delays in Egypt and unexpected facilities downtime in the North Sea in the first three quarters of the year, we ended 2022 on a strong note. Fourth quarter production and costs were in line with guidance, while CapEx for the period was slightly above expectations due to some small shifts in activity timing. U.S. production exceeded guidance on continued strong performance from our Midland and Delaware Basin oil properties. Oil volumes in Egypt strengthened as we continue to improve drilling efficiencies and project execution and North Sea production benefited from a substantial improvement in facilities runtime. Looking forward to 2023, we will continue to focus on managing costs and driving efficiencies while also taking advantage of the optionality within our portfolio to respond to commodity price movements. Specifically, with regard to the recent and substantial drop in natural gas prices, we are managing the portfolio for cash flow and not production volume. Accordingly, our growth in 2023 will be entirely driven by oil. We are reiterating our capital budget of $2 billion to $2.1 billion, which is consistent with what we indicated back in early November. We believe this appropriately reflects potential inflationary impacts for the coming year and remain confident in our ability to deliver within this range. At this investment level and assuming current strip prices, we anticipate year-over-year adjusted oil growth of more than 10% and BOE growth of 4% to 5%. This is consistent with the preliminary BOE guidance we discussed on our November call. Oil volumes in Egypt and the U.S. will be the primary contributors to growth more than offsetting a decrease in natural gas production in both regions. As we also noted on our November call, we are expecting a sequential decrease in U.S. production from fourth quarter to first quarter. This is primarily driven by our Permian Basin oil well completion cadence. However, natural gas curtailments at Alpine High and liquids volume reductions associated with ethane rejection during the month of January are also significant contributors. Importantly, our Permian oil well completion cadence will accelerate in the second half of February, which should lead to significantly higher U.S. oil production in the second quarter through the fourth quarter. Turning to the North Sea. We anticipate a moderate production rebound this year with three new wells coming online in the first half and shorter scheduled maintenance turnaround times. We plan to release the Ocean Patriot semi-submersible drilling rig around mid-year, following completion of a scheduled drilling campaign in the North Sea. The permanent reallocation of this capital to other areas is being evaluated as a recent tax changes in the UK have made returns less attractive than other investment opportunities within our portfolio. In Suriname, first half 2023 activity is focused on the two appraisal wells drilling at Krabdagu and subsequent flow testing. Following that, another exploration test on Block 58 is also planned. While average oil and gas prices are trending down relative to 2022, APA’s free cash flow this year should be bolstered by our gas sales contract with Cheniere. Steve will provide more detail around the expected impact of this contract in his remarks. We remain fully committed to returning at least 60% of our free cash flow to shareholders through a mix of dividends and share buybacks. Strengthening our balance sheet also remains a priority, and we anticipate that most or all of the free cash flow not returned to shareholders will be used to reduce debt. In closing, while the industry is experiencing considerable short-term oil and gas price volatility, we have a constructive outlook on the long-term supply and demand for hydrocarbons. Over the next several years, our plan is to maintain a relatively constant activity level yet remain flexible to shift capital within the portfolio to the highest value opportunities. Through the cycle, we also plan to continue allocating an appropriate percentage of our capital budget to high-quality differential exploration opportunities. APA’s investment case and portfolio are unique. Within the Permian Basin, we can allocate capital investment to oil or natural gas and generate growth from either or both commodities. Additionally, we hold considerable long-term gas transportation capacity, which our marketing team utilizes to purchase and resale third-party gas for a profit. We have gas sales to Cheniere commencing this summer that will provide long-term access to international index pricing. Our Egypt operations offer exposure to premium Brent oil prices, modernized PSC terms, and an opportunity to generate consistent growth in an area with tremendous potential. And in Suriname, our joint-venture partnership enables the appraisal and potential development of large scale projects on Block 58 with limited capital investment. We believe APA is well positioned to help profitably deliver hydrocarbons that the world needs for the next decade and beyond. We are committed to doing this while reducing carbon intensity and being good environmental stewards. And with that, I will turn the call over to Steve Riney.

Operator:

Thank you. [Operator Instructions] I'll now turn the call over to Mr. Gary Clark.

Operator:

Thank you. [Operator Instructions] And our first question comes from the line of John Freeman with Raymond James. Your line is now open.

John Christmann:

Good morning, John.

John Christmann:

Yes, John, I'd say the program has been pretty constant. We drilled really a multitude of different well types, both on the development side and the exploration side. I think what you're seeing there is the impact from the modernization, there were some things that were not being pursued because of the modernized terms, and we're able to pull some of those forward and prioritize them. So you're running a little higher on the success rate as we get some of that low hanging fruit initially.

John Christmann:

Yes. I would just say today, we've got the two appraisal wells that we're drilling at Krabdagu, and that's going to take a good portion of the first part of the year, and that's where the priority is now. And then we do have one exploration slot that is still being worked and we're still debating with partner on which well that will be, but there are multiple wells identified. It's just a matter of which one. So for now, that is the plan. And obviously, we'll readdress that throughout the year.

John Christmann:

Thank you.

Jeanine Wai:

Hi. Good morning, everyone. Thanks for taking our questions.

Jeanine Wai:

Good morning, John. First question maybe just keeping along with John's on Suriname. The estimate for resource at Sapakara is now over 600 million barrels of oil in place. So I guess our question is, what's the confidence level of that estimate? And how much overall resource is required to get a project to FID, and we know you're doing a ton of appraisal at Krabdagu this year as well?

Jeanine Wai:

Okay. We'll stay tuned for those appraisal results. Maybe moving to the U.S. You mentioned in your prepared remarks that you're managing the portfolio for cash flow and not production and so 23% is driven by oil this year. And so you also curtailed some Alpine High production in January. Can you provide any further color on what the price sensitivity is of natural gas curtailments at Alpine High? Thank you.

Operator:

Thank you. [Operator Instructions] And our next question comes from Charles Meade with Johnson Rice. Your line is now open.

John Christmann:

I mean, Charles, we've prioritized the appraisal at Krabdagu right. And you saw us move from Sapakara with two appraisal wells there, and we're very pleased with those results. And Sapakara 2 kind of came in as we had projected and modeled and obviously anxious for the results at Krabdagu. And so it is fair to say. And its fact, we've prioritized the appraisal program right now.

John Christmann:

Charles, I would just say that clearly, one of the wells is ahead of the second and the second one has been on location spudding any time now. So there will be a lag. And we'll just have to see what we decide to do and work with Total in terms of what we come back with and timing. But we're moving on both of those as quickly as possible, and it's very important information.

Paul Cheng:

Thank you. Good morning, guys.

Paul Cheng:

Two more questions. John, can you remind us that what is Alpine High role in your longer-term portfolio? I think at one point several years ago, you sort of write down edited then gas pipe become a little bit better, and I think you guys go back and sort of having – it seems like it's having a role in the long term. But how should we look at the Alpine High? And also, the second question is that I think you guys have not done any bolt-on acquisitions in the last 12, 18 months. Some of your peers has done so. How should we look at bolt-on acquisition for you guys over the next two or three years? Is that a – could pay a reasonable role or that you will be focusing more effort in exploration in Suriname and also that the activity level in Egypt. Thank you.

Operator:

Thank you. [Operator Instructions] And our next question comes from Doug Leggate with Bank of America. Your line is now open.

John Christmann:

Good morning, Doug.

John Christmann:

Great question, Doug. And there's a lot of work we've done, and we have a lot of confidence in what we put out, but there's also a lot of work left to do. So I will talk about give you a little bit of color on Sapakara and then I'm going to bring Dave in if he wants to add anything, you've really got two areas – you are correct. We are working towards with our partner, potentially a development hub where you would be bringing in both Krabdagu and Sapakara. They are a little different in terms of the makeup and so forth. Sapakara is predominantly one package, really, really high-quality rock when you're talking low GOR oil, 1,100 GOR oil and you're talking 1.3 to 1.5 Darcy rock, one nice blocky sand, you're going to have high recoveries. And that's really all I'll say at this point. You'd want to get into feed study and do more work before we come out with more specifics there. So some of the questions you're asking are things that will come later. And then Krabdagu is – there's three targets there. It is the incremental $200 million that you've referenced there, and we're in the process of appraising that. You've got a range of GORs there depending on the zones. And so the work we're doing to understand those and quantify those is really important to determining potential scale and scope. So all things underway. We prioritize it, which is why you've got two rigs there. And we're anxiously awaiting those as well because it's going to have an impact on scope and scale.

John Christmann:

Well, a bunch of questions in there. So I'll try to answer all of them to the extent I can. One, Sapakara South 2 was an up dip appraisal. So I think that was important in terms of confirming what we confirm there. If you go over to Krabdagu, I'll remind you, Waha in Block 53 was a discovery of a down-dip lobe and the Krabdagu fairway. So there are multiple levels and that's part of what you're driving at. There's also a pretty good chance we're appraising updip at Krabdagu as well, which is always a good thing when you're appraising. We see a lot of potential. I mean if you look at where we are today and the area we're working, we've had great success. There is more beyond just Sapakara and Krabdagu that could also go into a potential hub. And then if you look on the outboard side of the block, you get further out, we've had a working petroleum system, and we found hydrocarbons. The trick has been trap and seal as you get out there. So I do believe we will have an ongoing program in Suriname as there is a lot of prospectivity.

Neal Dingmann:

Good morning, John. Thanks for the time. John, my first question, really just a broader one on shareholder return or specific to maybe capital allocation. The last couple of quarters, you all were pretty adamant about talking about maybe a minimum amount of buyback given still what I certainly agree with a cheap stock price. I'm just wondering, do you all still feel like that? I mean, you have kind of a minimum level that you think about going forward for this year or this quarter? I mean, I'm just wondering from a shareholder or buyback perspective, if you're able to frame anything up?

Neal Dingmann:

No, great point. Okay. And then clearly, just a second question on domestic activity. It's been asked a little bit, but I'm just wondering, you all mentioned having the two Southern Midland Basin, the three Delaware rigs. How fluid is this? Could this change depend on prices, and I'm just – or even more activity in that newer Titus area? Just wanted for plans for remainder that maybe more second half of the year?

Operator:

Thank you. [Operator Instructions] And our next question comes from the line of Roger Read with Wells Fargo. Your line is open.

John Christmann:

Good morning, Roger.

John Christmann:

It's going to be more on the global and TTF or JKM, but I'll let Ben provide any additional details.

Roger Read:

Yes, it makes sense. The follow-up question I have is I understand the reason for reducing investment in gas in the near term. But as you look at your let's call it, guidance goals, expectations to deliver oil volume growth this year. What should we be paying attention to as the risk factors on that things that which I guess could cause you to come in underneath or any of the other issues, as you mentioned, kind of like well cadence, stuff like that?

Operator:

Thank you. And our next question comes from the line of Neil Mehta with Goldman Sachs. Your line is now open.

John Christmann:

Yes, Neil, a good question. I would say we spend a lot of time trying to stay about a year ahead of our programs and so with our contracts and things because that gives us the visibility in terms of the spend. And so today, a lot of what you're seeing is contracts based on the back half of last year pricing. So I think it's a little premature from our perspective to be seeing any softness tied to the commodity price. I think if the price stays where it is today, that is one of the upsides of the plan as you're going to see cost structures follow. They just tend to lag but they will follow the deck. It just takes a little bit of time to play catch-up. So nothing there to really comment on in terms of green shoots or anything at this point.

John Christmann:

Yes. I would just say that it's made the North Sea less competitive relative within our portfolio. And so as we look at that still an asset that we're going to manage for cash flow and we'll get good performance there, and we're going to continue to invest in asset integrity and maintenance and all the things we need to do environmentally, safety like we always will. But longer-term incremental dollars that we have alternatives to put in other places, you're seeing us make that decision just because there's more attractive places to put that. And so it's made the North Sea less competitive on a relative basis within our portfolio. And that's why you're seeing us drop the Ocean Patriot rig later this year.

David Deckelbaum:

Hey, John. Thanks for the time today.

David Deckelbaum:

Just wanted to ask on sort of the future expectations for Egypt growth. I know since the modernization of the PSC and the ramp up to 17 rigs now, the view was that this could be sort of a multiyear growth opportunity. I understand the beginning of this year, production obviously declines and then ramped throughout the year. It seems like a combination of till cadence, but also was curious if there's infrastructure challenges driving some of that production curve. And then what we should expect once we're 10% higher in the fourth quarter of 2023 going into 2024 and beyond there?

David Deckelbaum:

I appreciate that, John. And just my second one, just on Suriname. It sounds like we're obviously waiting for the appraisal results from Krabdagu and the intention to potentially build out a hub there. I guess does that necessarily preclude Sapakara being developed independently? Or would you view this as you kind of need to combine both Sapakara and Krabdagu into one hub system to maximize economics and that Sapakara wouldn't necessarily support a development on its own?

Operator:

Thank you. [Operator Instructions] Our next question comes from the line of Leo Mariani with ROTH. Your line is now open.

John Christmann:

Yes. I would just say, in general, it doesn't really change the abandonment time frames as we model that out today. And really, you look at this year, not much impact from the Ocean Patriot. It was drilling some things that are bigger impact subsea wells that take time to come into play. So it does have an impact, start to see a little bit in 2024 or 2025 and beyond, but it doesn't really drive – I mean we're still looking at early 2030s for both 40s and Barrel. And when we bought the 40s asset, I'll go back and remind you. When we bought that in 2003 from BP, it was scheduled to come out of ground in 2012. And so here we are more than a decade longer 12 – 10 years, 11 years longer. And still looking at close to another decade. So there's still good productivity in life there. We're just going to manage it for cash flow and be very prudent about the future investments.

John Christmann:

I mean the thing I would say is recognize the contract with Cheniere is a separate deal. It's a corporate level deal. We buy gas and ship channel. So it's separate and aside from what our equity gas that we produce. So we sell that in basin at Waha and prices at Waha are going to dictate what we do in basin. So that's the point to make there. In the Chalk, we brought on those three wells. Today, we don't have anything planned in terms of drilling from a working interest perspective. In the Chalk, there may be some non-op wells we participate in, where we've got some non-op interest there that others are drilling. But nothing planned in our budget this year for Chalk drilling.

Arun Jayaram:

Hey, good morning. John, the more recent activities in Suriname have been focused on appraisal activity with, I guess, two rigs now on location at Krabdagu. What are you and the partners' plans in terms of incremental exploration post the evaluation results of Krabdagu with the two rigs.

Arun Jayaram:

Got it. And just maybe one follow-up in the Permian. John, as I think about your 2022 program in the broader Permian including in 4Q – the company didn't place as many wells on the sales as we have thought in terms of our modeling, looking at 4Q, I think you placed one or so wells to sales – what drove that in 2022? Were you building some DUCs and just thoughts on – will that shift a little bit as we think about 2023 because you have a pretty robust production growth outlook from the…

Operator:

Thank you. [Operator Instructions] Next question comes from the line of Jeoffrey Lambujon with Tudor Pickering. Your line is open.

John Christmann:

You bet, Jeff.

John Christmann:

Well, I mean, Jeff, a question. We obviously try to guide to what we believe are numbers with high confidence that we can hit, and we spend a lot of time on that. I do believe there are things at times that – the nice thing about Egypt is there is ability to – with success to bring other things on and get other wells drilled and high grade that schedule as you're moving through the year. But I think we've given a very realistic and good guides for 2023. And I think there's good confidence from the team. I know I sure asked that question and the response I get the response that I'm comfortable to relay.

John Christmann:

Yes. It's all about operational excellence and continuing to try to improve and learn from things as you go. In Egypt, we're drilling in some new areas with the seismic and some of the exploration that we're doing there. And so within those areas, we should see improvement as we drill more wells and things – areas you've drilled before. So you're seeing some of that. And the big thing is across the entire organization, across the asset teams across the functions, everybody is really trying to take all that they integrate it and get better. I mean it's about continuous improvement and execution excellence. And you saw great progress on the safety front. We're going to continue that and continue to focus on the operations. Paying attention to details.

John Christmann:

Yes. Thank you. And before closing today's call, I want to leave you with the following thoughts. First, I want to recognize our entire team for their hard work and dedication to safety, operational excellence and environmental stewardship. APA remains committed to financial and operational discipline. We are focused on leveraging the portfolio to invest in the highest return projects. While activity cadence will impact our first quarter, we are confident in our growth outlook for 2023. Lastly, in Suriname, the JV has accelerated appraisal at Krabdagu, and we look forward to keeping you informed of our progress. I will turn the call back to the operator.

Operator:

Hello, and thank you for standing by. Welcome to APA Corporation's Third Quarter 202 Results Conference Call. [Operator Instructions]. It is now my pleasure to introduce Vice President of Investor Relations, Gary Clark.

John Christmann:

Good morning, and thank you for joining us. On the call today, I will review highlights from the third quarter, provide commentary on our fourth quarter outlook and conclude with an early look at our 2023 plan. APA continues to enjoy a robust free cash flow profile provided by our unhedged exposure to a globally diversified product price mix. With activity in Egypt and the Permian Basin now at levels capable of driving sustainable corporate production growth, our free cash flow is also expected to grow, assuming flat year-over-year oil and gas prices. Turning to the third quarter results. We have had several key highlights. Global production was in line with our guidance range as outperformance in the U.S. offset unplanned facility downtime in the North Sea. Permian Basin assets were strong contributors across the board from the core Midland Basin development program to the newly acquired properties in the Texas Delaware. In Egypt, drilling and recompletion programs are progressing closer to our original plans for the year. New well connections exceeded our revised third quarter guidance and production momentum is picking up into the fourth quarter. The challenges associated with the activity ramp are not totally behind us, but we are making good progress. The North Sea after returning to production from seasonal turnarounds incurred an unusually high amount of unplanned downtime in August and September. Most of these issues have been mitigated and volumes have returned to a more normalized level as reflected in our forward guidance. During the third quarter, we generated more than $600 million of free cash flow, purchased nearly 10 million shares of APA common stock at an average price of $33.85 per share and announced a doubling of our annual dividend rate. In Suriname, we advanced our exploration and appraisal program with the first oil discovery on Block 53 at Baja and a successful flow test of the CrabDagu discovery well in Block 58. And on the ESG front, I am very pleased to announce that we have successfully delivered on our 2022 goal to reduce flaring in Egypt. Today, new projects are reducing routine upstream flaring by 40%, enabling us to compress the gas into sales lines and deliver to Egyptian consumers for cleaner burning affordable fuel. More information on our third quarter results can be found in the operational supplement posted on our website. Turning now to our fourth quarter outlook. Capital investment is projected to be around $450 million, and our full year guidance of $1.725 billion remains unchanged. We expect adjusted production will increase by around 5% from the third quarter, driven primarily by an increase in new well connections and recompletion activity in Egypt and a rebound from planned and unplanned platform maintenance downtime in the North Sea. Given the age of the North Sea facilities, we expect facility run times will generally be lower and more variable than in the past. As a result, we are now providing a production guidance range to accommodate a broader spectrum of potential future outcomes. In Suriname on Block 58, we are currently participating in the drilling of 2 wells, a second appraisal well at Sapakara South and an exploration well at Aware. Results will be provided as they become available. Despite a few challenges during 2022 we will exit the year in a strong position financially and operationally. We are on track to generate around $2.7 billion in free cash flow for the year. Consistent with our 60% capital returns program, we anticipate returning at least $1.6 billion of this in share buybacks and dividends. While there is more to do, we have significantly strengthened our balance sheet, reducing net debt by more than $1.4 billion through the end of the third quarter and production volumes are now trending sustainably higher in the U.S. and Egypt. As we plan for 2023, our objectives remain the same. We will maintain capital discipline, target moderate production growth, work tirelessly to mitigate rising costs and continue to deliver meaningful emissions intensity reductions. Our capital budget next year will be around $2.0 billion to $2.1 billion. This assumes 5 rigs in the Permian Basin and up to 17 rigs in Egypt, while activity in the North Sea and Suriname is projected to remain consistent with 2022 levels. Similar to our approach in 2022, this early view incorporates what we believe is an appropriate view of inflationary impacts on the capital program. The majority of the expected inflation is associated with U.S. rig and frac costs as contracts are renewed at the higher current rates. Inflationary pressures in our international portfolio should be more muted. Despite the planned increase in capital investment in a like-for-like price environment, we estimate APA's free cash flow will grow in 2023. Note, this excludes any uplift from our Cheniere gas supply contract commencing in the second half of the year. Steve will provide more details on this contract, which gives us access to premium natural gas price points in Europe and Asia. Following 3 years of production decline since the beginning of the COVID pandemic, we look forward to returning to growth in 2023. At the corporate level, we are targeting mid-single-digit year-over-year growth, driven primarily by higher oil production across all assets. In the third quarter, our Permian Basin results were particularly strong due to a variety of factors, including good underlying base production and new well performance. The timing and number of new completions and relatively minimal maintenance, midstream and weather-related downtime. As we look into the fourth quarter of 2022, in the first quarter of 2023, we expect Permian production will be flat to down as we experienced a lull in new well connections and reflect the potential for winter weather-related downtime in our outlook. Planning for next year continues and we will have much more detail to provide with our fourth quarter results in February. In closing, we have a constructive outlook on the long-term demand for natural gas and oil. This hasn't changed despite the potential near-term demand impacts of a recession and the ongoing debate over the pace of global decarbonization trends. We continue to plan our business using relatively conservative commodity price scenarios, allocate capital to our highest return projects and target long-term single-digit sustainable production growth. APA will continue to return 60% of free cash flow to shareholders through buybacks and dividends while also continuing to strengthen the balance sheet. Lastly, we remain committed to reducing emissions within our operational footprint, and we will be introducing specific CO2 equivalent emissions intensity goals around this objective in the near future. And with that, I will turn the call over to Steve Riney.

Operator:

[Operator Instructions]. Our first question comes from the line of Doug Leggate with Bank of America.

John Christmann:

No. Doug, the well we're drilling in the kind of the northwest portion of our block is a You will remember Bonboni, it's 25 kilometers west of Bonboni, where we found an active or working hydrocarbon system. It appears that they have a working hydrocarbon system north of us as well. So I think that's all good news. The big thing here will be trap. And -- but Tracy Henderson is here, and I'll let Tracy provide a little bit more color.

Doug Leggate:

I hate to do a kind of Part 1b, but just while we're on the topic of Suriname, do you have any color on Sapakara South at this point as it relates to whether that can help inform an FID in 2023?

Doug Leggate:

My follow-up is for Steve. And I guess, Steve, I'm going to try and layer in a couple of things to this, I guess. But obviously, Cheniere doesn't want to start this contract as soon as -- as early as you would like it to start. I think it was pretty clear given LNG prices. But I guess what I'm really trying to get to is your comments about free cash flow. You said, if I'm not mistaken, that the free cash flow -- the cash flow would be higher next year on a similar price deck, excluding Cheniere, if I heard that correct. But you've also flipped this Waha trading contract or gathering contract to a kind of almost a $300 million run rate on revenues. So when you wrap all that together, it looks to us that the free cash flow could be up even at a substantially lower commodity deck. So can you help me understand if I'm reading that correctly?

Operator:

And our next question comes from the line of John Freeman with Raymond James.

Stephen Riney:

Yes, I'd say that -- and John might have some comments on this as well. But I'd say look at the last 2 quarters, where we've -- especially fourth quarter, we're going to be running basically at what we're planning for, for 2023 preliminarily. Most of that was the same in the third quarter. We did have a bit of time where we didn't have the Ocean Patriot in the North Sea in the third quarter. But on the last 2 quarters, we've been running just a little under or this last quarter and next quarter, we're running a little under $500 million a quarter, and that would give you a $2 billion on an annualized spend rate. And that's -- so that's a preliminary view with maybe a little bit of inflation built into that go into possibly $2.1 billion. And that's just -- that's the preliminary view. We are still early days on the planning process, and I'd just caveat that with that could change. So let's wait and see in February. But I'd characterize it broadly as the bulk of the change in capital spending is because of the change in activity.

John Christmann:

Yes. We're in pretty darn good shape, but we've worked hard to get here in a pretty short time period. And a lot of it is just addressing manpower issues and training -- and so we're in pretty good shape, John. And I think we're close to where we wanted to be, but you're still working through some things there, but we're in pretty good shape.

Neal Dingmann:

First question, a little bit on what Freeman was just asking. John, my first question is on production growth. Specifically, you all, I think, characterized '23 as potentially seen, I think, what you deem this kind of moderate growth. But to me, looking at your '23 domestic and Egyptian activity plans, it seems like production could be even maybe a bit better than moderate? I know you don't have '23 guide yet, but I guess what I'm wondering is how you view sort of next year's contributions incrementally when you think about Egypt versus domestically given to me all the domestic opportunities, including the new play there?

Neal Dingmann:

Okay. Great detail. John. And then secondly, just on shareholder return, I'm just wondering, would you all say you're still leaning in the stock buybacks, I guess what I'm trying to get a sense of that 1.6 buyback plan, what remains year-to-date.

Operator:

And our next question comes from the line of Bob Brackett with Bernstein.

Stephen Riney:

Yes, Bob, that -- so the contract is $140 million a day and the $570 million, I won't recall exactly what day, but it's based on strip pricing for -- and we assumed an 80% TTF, 20% JKM mix, which we have the right to elect and that was versus the same period strip for Houston Ship Channel. And then it has all of the deducts that we get from that contract for liquefaction for shipping, for shrinkage and for regas and things like that.

Stephen Riney:

It would be five months. The -- by contract, the latest that contract can start is August 1. It could start earlier. I'm not holding my breath.

Jeanine Wai:

Maybe we just go to the North Sea here. You mentioned in your prepared remarks, lower and more variable run times, just kind of given the age of the asset. Now we potentially have some higher EPL kind of overhanging here. The current 2023 outlook as it stands today, as you said, the North Sea activity should be consistent with 2022. But we're just wondering what the potential range of outcomes could be there, whether it's related to changes in the regulatory environment or by your choice. And we know it doesn't quite work like sale, but what kind of base decline is the North Sea on.

Jeanine Wai:

Okay. Great. And then maybe turning to the revolver. I think, Steve, you said you consider it to be an asset to utilize and there's attractive opportunities, you'll look to pay it down over time. I guess our question is how much is too much on the revolver? And how does this really factor into your appetite for future bolt-ons?

Operator:

And our next question comes from the line of Charles Meade with Johnson Rice.

John Christmann:

Yes. The thing I would say, if you look at Sapakara South, it was a very, very high-quality discovery. You had 30 meters of pay -- actually 32 meters full to base. Low GOR, around 1,100 and you had really, really high perm 1.3 to 1.5 Darcy rock. At the time of that, we announced a connected volume, which we later updated to more than 400 million barrels. So Sapakara South is really world-class rock. We also said at the time that we believe there was additional resource there that needed to be appraised. And that's exactly what this well is doing. It's moved up dip, and we are appraising and we've got really, really good seismic support. We think the seismic is working. And it could add materially to that Sapakara South discovery.

Stephen Riney:

Yes. Charles, let me -- I'll just run quickly through the similar math that you were going through. We do expect now at recent strip prices that free cash flow this year will be $2.7 billion, as John said. So that would imply a minimum committed returns of $1.6 billion. Year-to-date, we've done $127 million of dividends. We've bought back 26 million shares at $34. So that's $884 million of buyback. And as you said, that's just over $1 billion so far this year. Since inception by the way, that's 15% of the company that we bought back at a little over $31 a share. So at $2.7 billion of free cash flow that would imply for the fourth quarter total returns of $600 million. The dividends will be about $80 million. And so that implies buybacks of $520 million and we've done right around $80 million of that in October. So your math was pretty darn close that with all of that, if you landed right on 60% would be about $440 million of additional share buybacks. Historically, we've delivered those buybacks through 10b5-1 programs and through OMRs. As I said, we use OMRs when we don't have material nonpublic information, we are drilling 2 wells in Suriname. So we do understand that situation and the risk associated with that as John said, we're committed to that program. So you should assume that we have plans in place to make sure that, that will be delivered and -- because it will be delivered by the end of December.

Stephen Riney:

That's correct. We will get to you.

Paul Cheng:

Two questions, please. The first 1 is a little bit of the John, when you're talking about mid-single -- mid-single-digit oil production growth for next year. Is it based on the fourth quarter or based on full year 2022 level? Because if it is based on full year 2022 level, that suggests that your next year oil production may be lower than the fourth quarter level. And with the increased activities -- and is there any reason why that the average production will be lower on the oil growth for next year than the fourth quarter level? That's the first question. And second 1 is very simple. On the Permian, you're saying you're going to run 5 rigs, but do you include anything in the Alpine High. And then what's your view given the current commodity prices between the gas well and oil only weight as well.

Paul Cheng:

John, should we assume you're going to have at least 1 rig at Apline High or is that just not necessarily it may be...

Operator:

And our next question comes from the line of Leo Mariani with MKM Partners.

John Christmann:

I'd just say a lot of it's -- we're coming out of our maintenance turnaround season. And we've had to play catch up in '22 for '20 and '21. The Covid years hit pretty hard there and we were limited on what we could do on the tars. And you've just got aging infrastructure. And when things go down, it takes a little longer to get things back up. But I think we've got a lot of that behind us. And we will be guiding with wider ranges in the future. But right now, we've got good momentum and things are running fairly smooth.

John Christmann:

Yes. I think some of that is just timing of the well connections we had this quarter, and we've got good momentum really across the whole portfolio going into the fourth quarter, we're off to a good start and we had some wells that have come on and things. So we do think Egypt is going to be 1 of the big drivers in '23 and beyond.

David Deckelbaum:

Just wanted to ask if I could. Following up quickly just on North Sea. John, I think your comments were just on the aging infrastructure. Is there sort of a more of an outsized maintenance CapEx spend that goes into North Sea and '23? Is there an imminent need to upgrade facilities? And how does that sort of square with where production would be in the fourth quarter. Are we back to a more sustained level ex downtime heading into next year?

David Deckelbaum:

Appreciate that. And maybe if I could just ask for a little bit more color on the Cheniere contract. I think you all had marked today based on strip pricing. Can you give us a sense on just how those netbacks work? Are the costs that are coming out of those LNG contracts on a fixed or variable basis. And what's a good ballpark to apply on sort of an MMBtu basis for costs relative to where the headline TTF price might be?

Operator:

Our next question is a follow-up from Doug Leggate with Bank of America.

John Christmann:

Yes. I mean, the thing I would say, Doug, is that today, North Sea is a core asset for us. Obviously, you've had some factors out there today that impact the ability to invest future and you have to continually weigh in that. We benefit from the Brent pricing and the high netbacks and the free cash flow. But we also have a portfolio that is dynamic. And so you're always looking to expand your ability to invest in other assets. And as things change, sometimes out of your control, it shrinks some of that. So -- but today, it is core but it's something we're always taking into account as we're laying our future plans.

John Christmann:

Thank you for joining us on our call today. We started the fourth quarter with strong momentum across our global operations, which will carry into 2023. In Suriname, we're drilling an appraisal well at Sapakara South and an exploration well at Aware. We will share results when they are available. We remain on track to deliver on our capital returns framework. We will deliver at least 60% of 2022 free cash flow to our shareholders through dividends and buybacks. Our teams continue to work on our plans for the 2023 program and longer, and we look forward to providing more details to you in February. Operator, I will now turn the call back to you.

Operator:

Ladies and gentlemen, thank you for standing by, and welcome to the APA Corporation's Second Quarter 2021 Results Conference Call. [Operator Instructions]. It is now my pleasure to introduce Vice President of Investor Relations, Gary Clark.

John Christmann:

Good morning, and thank you for joining us. On the call today, I will review our second quarter highlights and discuss key trends and performance in each of our core operational areas. Following that, I will provide some color on the 2022 guidance, which we updated last night in our earnings release and supplement. Over the past few months, fears of economic recession, a new wave of coronavirus outbreaks and concern about potential demand destruction have created substantial volatility in commodity prices and the value of energy equities. However, the pullback in oil prices from the second quarter peak is healthy for both consumers and producers. We continue to have a positive outlook on the long-term fundamentals for natural gas and oil and view APA stock as a compelling value today. As I look at our second quarter results, I see several key highlights. APA generated record free cash flow of $814 million. We repurchased 7 million shares of APA common stock, followed by an additional $6.9 million of share repurchases in July. Gross oil production in Egypt increased by more than 7,000 barrels per day versus the prior quarter, which was our first material quarterly increase in Egypt oil production since 2018. Our 40s field maintenance turnaround in the North Sea was executed safely and on budget. We advanced our program in Suriname with the successful flow test at Krabdagu, and we made excellent progress on upstream flaring reductions in Egypt and are on track to achieve our 40% reduction target by year-end. The second quarter was very good in many ways as our diversified unhedged portfolio benefited from rising oil and gas prices and high margins. However, we have encountered a few challenges. In Egypt, although we delivered strong oil production growth in the quarter, we are experiencing some delays and inefficiencies as we scale our active rig count from 5 to 15. These include supply chain, equipment and infrastructure-related delays, longer-than-expected time to staff and reactivate cold-stacked rigs extended drill times, which are primarily a function of new rig and new crew inefficiencies and increased regional competition for experienced national employees. Well performance in Egypt has been in line with expectations. So these are mostly short-term above-ground challenges. We have identified and are swiftly taking appropriate actions that will bring us back up to pace. In the Austin Chalk, our delineation program has generated mixed results thus far, so we have chosen to pause most of our planned drilling and completion activities. I will talk more about the impact of these items on our second half guidance in a few minutes. Turning now to some of the details of our second quarter results. Our largest spend categories Capital investment, operating costs and G&A were in line or less than expected for the quarter despite a challenging overall supply chain and cost environment. Total adjusted production of 305,000 BOE per day was down compared to the first quarter, primarily driven by our early March Permian Basin minerals divestiture and the impact of high oil prices on our Egypt PSC volumes, the timing of well connections across the portfolio and seasonal maintenance in the North Sea. We continue to expect our global adjusted production volumes will return to a growth path this year as our activity has now reached a level that we have not seen since 2019 prior to the COVID pandemic. In the U.S., we continue to run a steady 2-rig program in the Southern Midland Basin and recently initiated drilling at Alpine High with a third rig. In Egypt, we averaged 12 rigs brought online a number of quality wells and achieved a high drilling success rate. Our strong oil production growth in the quarter was partially offset by a decline in lower margin natural gas production. In the North Sea, we are in the midst of summer turnaround season. We completed the maintenance turnaround at 40s on schedule and on budget and have brought that field back into production. At Beryl, we are wrapping up a platform turnaround and will return to production in the near future. On Block 58 in Suriname, our partner, Total, is drilling the Dikkop exploration prospect which sits roughly 8 kilometers northwest of our Sapakara South discovery. On the adjacent Block 53, we are drilling the Baja exploration prospect with our partners, PETRONAS and CEPSA. On July 29, we closed on an acquisition of properties around our active development areas in the Texas Delaware Basin. This is an attractively valued tuck-in acquisition that comes with PDPs a number of wells in the drilling and completion process and a nice inventory of undrilled locations. It also brings a high-quality drilling rig and experienced crew to continue development in this very tight service environment. There are currently 2 rigs running on the new acreage. One will be released in the fourth quarter and we will retain the other as our fourth U.S. development rig. These assets compete well within our portfolio and integrate nicely into our Permian operations. Turning now to our outlook for the second half of the year, which we included in our financial and operations supplement last night. Our CapEx program of $1.725 billion remains unchanged for the year. Steve will have some comments on a few minor changes in other P&L guidance items. In terms of adjusted production, our new full year guidance range for Egypt is 63,000 to 65,000 BOEs per day, which is down about 7% from prior expectations. More than half of this decrease is a result of fewer wells being drilled and completed due to the operational challenges I spoke of earlier, the remainder is attributable to the PSC impact of higher oil prices. In the U.S., we have a number of moving parts affecting our outlook for the remainder of the year. First, we have removed roughly 8,000 BOEs a day of Austin Chalk production from the second half of the year following the decision to defer most of our near-term drilling and completions. Second, we expect the Texas Delaware Basin acquisition properties will average 12,000 to 14,000 BOEs per day of production for the remaining 5 months of the year. We've also encountered some completion delays on Permian operated and nonoperated wells and recently divested a small package of Permian properties. The net effect of these items is a slight downward revision to our full year 2022 U.S. production guidance. In the U.K. our near-term activity plan and full year 2022 production guidance remains unchanged. Later this month, the Garden 3 development well will commence production, which should generate a significant volume uplift in the fourth quarter. I will note that the new energy profits levy recently became effective in the U.K. This reduces our free cash flow outlook going forward. And while it won't affect our 2022 drilling program, we are evaluating the longer-term impacts of the tax on our planned investment in the U.K. But in general, new taxes are not effective incentives for increased investment. Steve will share more details about the tax impact in his remarks. Turning now to an update on our ESG initiatives. APA's top priorities are reducing GHG emissions throughout our global operations and supporting our employees and the people in the communities where we operate. We have completed several projects across the portfolio, most notably in Egypt that enable us to compress and direct previously flared gas to sales, thereby increasing revenue and improving our emissions profile. This puts us well on our way to achieving our goal of reducing upstream routine flaring in Egypt by 40% by year-end. I'm very pleased with our progress on this and many other fronts, and there is much more to come. Also, in late July, we issued our 2022 sustainability report. I hope you will take a moment to review the report and learn more about our strategy and initiatives to provide affordable, reliable energy to the world while also delivering on rigorous near- and medium-term ESG goals. In closing, APA remains committed to returning 60% of free cash flow through buybacks and dividends as well as strengthening our balance sheet, including paying down debt as it matures. At current strip prices, we expect to generate approximately $3 billion of free cash flow in 2022, of which at least $1.8 billion would be returned to shareholders through dividends and share buybacks. Through July, we have returned just under 50% of this amount. And finally, I would like to extend a personal thank you to John Lowe, APA's Chairman, who recently announced his retirement after serving 9 years on the board. John has been a great friend and colleague. We have benefited greatly from his experience and insights, and we wish him all the best. Lamar McKay has been elected to serve as APA's new Board Chairman, and will formally take over for John in September. Lamar has a wealth of experience that I know will be a tremendous asset to the board room and my leadership team. We are all looking forward to working with him and welcome him into his new role. And with that, I will turn the call over to Steve Riney.

Operator:

[Operator Instructions]. And our first question comes from the line of Doug Leggate with Bank of America.

John Christmann:

Doug, thanks for joining us this morning. First of all, we feel good about our 3-year plan. there's been, as we laid out a couple of challenges, and we take responsibility for those and hit them head on. I think the programs are running well. We've got some work to do in Egypt and we're on it. But if you look at -- we did need to take this year's guidance down a little bit. A lot of that is shifting of Egypt to the right, but the well performance has been good. I think it's premature to look at our '23 and '24, and it would be premature to adjust those forecasts right now. But in general, I think we feel good about the overall delivery over the 3-year period. And I will say we baked in a lot of inflation on the cost side, and we have not had -- we've been able to manage that side really well. So I think in general, it would be early to do anything with the '23 and '24 years.

John Christmann:

No, I would just say today, we go through a process every year in the fall, we're looking at the next 3 years. We will review that. We'll come out with a new 3-year look in February. But in general, we still feel pretty good about the 3-year plan we laid out. And we did pick up some properties in the U.S. The program has been running strong and I think as you look out with the 4 rigs in the Permian, we're going to be just fine in the U.S. and Egypt, we're confident in the well results. We've just got to work through some efficiencies there. So in general, we feel good, Doug, about the 3-year plan and -- but it would be premature right now to do anything. We've got some work to do in the short term, but we're on it, so.

John Christmann:

Yes. No, great question. We did not -- and I'll let Steve comment on the Cheniere contract after I make a few comments on the U.S. rigs. We'll have 4 rigs. We've had 4 rigs running in the U.S., we'll maintain those 4 rigs. You're going to have all 4 of those in the Permian now. 2 in the Southern Midland Basin. We'll have 2 in the Delaware. We've got a rig that we recently moved to Alpine High. Following up the results of our Willow well. We're excited to drill some pads there. So I think it will be positive. So you'll see 2 rigs in that area. The nice thing is having those 4 rigs in the Permian now, we can move them around it based on pads and timing and things. But we do envision 1 of those pretty much stand at Alpine High with the near-term. Steve, anything you want to comment on the Cheniere contract, which is not in those 3-year free cash flow and cash flow numbers?

Doug Leggate:

And that is not in the free cash flow numbers in the 3-year plan, Steve.

Operator:

And our next question comes from the line of John Freeman with Raymond James.

John Christmann:

Well, John, great question. The thing I would say is we typically try to stay about a year ahead of our programs. And so we've been working on 20 -- started working on '23 as soon as the calendar turned. And we continue to do that, and they're starting to get pretty good visibility. The thing I would say about our guidance when we put it out our 3-year guidance, we bumped our capital quite a bit this year, as you'll recall, and took a pretty material increase. Most of that covered where we are today, and that's why you didn't see us have to bump our capital again this quarter. So I think we've got a pretty good handle on things. And I'll just say we built in quite a bit of inflation in '23 and '24 for next -- those next 2 years when we put out that outlook in February. So it's early to come back with hard numbers. for '23 and '24, but I think we've built in a lot of where we sit today on the inflation side.

John Christmann:

Yes. No, John, good question. What we typically do, and you can understand the those rig lines are dynamic. You've got some things that are dependent, some things that are independent in terms of wells and orders. And so because of that, we've typically waited until we're ready to move the rigs to tell you where they are going. Total has the value there drilling the Dikkop prospects right now. That is an exploration well. Clearly, we've got the Gerry De Souza in Block 53, where we're drilling an exploration well. That well will be moving back to Block 58 to Total. And I'll just say you're going to see a mix. There's appraisal to do at Sapakara South. There's also appraisal to do at Krabdagu, and there are also some other exploration wells. So when you see the rigs move, you're going to see probably a combination of exploration and appraisal with the 2 rigs. But I'm not in a position today to tell you which rig is going where with both of them right now.