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. 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 yours, sir.

Good morning and thank you for joining us on APA Corporation’s Second Quarter 2023 financial and operational results conference call. We will begin the call with an overview by CEO and President, John Christmann. Steve Riney, Executive Vice President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Dave Pursell, Executive Vice President of Development; Tracey Henderson, Executive Vice President of Exploration; and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be less than 15 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday’s press release, I hope you have had the opportunity to review our financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures today. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today’s call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. I’d like to remind everyone that today’s discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.

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 several fronts during the quarter, most specifically regarding 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 oil performance in Egypt, 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 North well, which went into 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. 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 returned 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 and to 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.

Thanks, John. For the second quarter, under generally accepted accounting principles, APA reported consolidated net income of $381 million or $1.23 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which are mark-to-market appreciation in the value of our Kinetik stock ownership and unrealized gain on Waha basis swaps. Excluding these and other smaller items, adjusted net income for the second quarter was $264 million or $0.85 per diluted common share. Free cash flow, which, for external purposes excludes changes in working capital, was $94 million in the quarter. Through dividends and share repurchases, we returned 131% of this amount to shareholders during the quarter. As John noted, both operational and cost performance were very good during the quarter. Compared to the same quarter last year, total adjusted oil production was up 14%. Adjusted oil mix increased from 44% to 47%, and we held lease operating expenditures nearly flat. G&A expense was $72 million, significantly below our underlying actual run rate cost. This is a result of APA's lower stock price at the quarter end and the mark-to-market impact on previously accrued share-based compensation. Underlying quarterly G&A costs remained stable around $100 million. Switching to forward-looking guidance, oil production is expected to increase significantly in the third quarter in all three of our operating regions. Our full-year guidance implies that oil production will increase again in the fourth quarter in both the US and Egypt. Declines at the mature Qasr gas field in Egypt and at Alpine High, where we have deferred drilling and completion activity, will result in total company natural gas production continuing to decline through the rest of this year. Next, I would like to provide some color related to our changing guidance for profit or loss on our gas transport obligations. As most of you know, we hold just over 670 million cubic feet per day of Permian Basin takeaway capacity, we sell our produced gas in basin, and we manage the transport obligation by purchasing third-party gas in basin for resale on the Gulf Coast. We realized a net trading margin based on the price differentials less the total transport cost. Since the transport cost is mostly fixed, this activity will generate a profit when price differentials are wide and a loss when they are narrow. In the second quarter, this activity generated a net profit of $13 million. As we have all seen, the differential between Waha and Gulf Coast pricing has compressed dramatically since late May. Based on the forward strip, we anticipate these trading activities will result in a small loss in both the third and fourth quarters, and we have adjusted our guidance accordingly. The flip side of this is that we are now getting higher realizations on our gas produced and sold in the Permian Basin. We commenced deliveries under our Cheniere gas supply agreement on August 1. At current strip prices, this contract will generate approximately $120 million of free cash flow for the last five months of 2023 and an estimated $385 million for the full year of 2024. As you know, these cash flows are likely to be volatile from quarter to quarter. As a reminder, these projections are net of all costs, including the cost to acquire and transport the gas to Cheniere. Our complete guidance for both the third quarter and updated full-year 2023 can be found in our financial and operational supplement. Finally, a brief comment on Egypt receivables. We have a long-standing well-functioning relationship with Egypt based on nearly 30 years of working in their country. Like many parts of the world today, they are experiencing some challenging financial times, and we will partner with them through that process just like we have in the past. Since the first quarter earnings call, we have had very constructive conversations with Egypt. As a result of steps already taken, the receivables balance came down in the second quarter, and we are confident further steps will keep us on the right track. In closing, our original full-year production guidance is unchanged, and we have reduced our 2023 budget capital and operating expense in aggregate by about $250 million. Our balance sheet and debt maturity profile are in good shape. This was most recently recognized by Moody's, who returned us to investment grade in June. Since the beginning of 2021, we have significantly improved our capital structure by reducing our outstanding bond debt by $3.2 billion while also returning $2.9 billion to shareholders via share repurchases and dividends. And with that, I will turn the call over to the operator for Q&A.

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

Good morning, Doug.

Yes, it's more exotic than it probably should be, but—good morning, John. So a couple of things from me. 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.

Yes, Doug, the nice thing being early August, we have the luxury of seeing a lot of the wells we've got coming on in the near future. And if you look and you won't see it. But our July volumes have actually averaged 145,000 barrels a day on the oil side were up already in July over the second quarter, and we've got good line of sight on what's coming, and it's going to be a good back half of the year. And I'll let Dave Pursell jump in with a little bit more detail.

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 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.

And what about beyond 2023, Dave?

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.

Great stuff. Thank you for that. John, I apologize, I'm going to have to be predictable. But so Total hoping Analyst Day at the end of September, I think they've a pretty good steer that they're going to have something to say there on Suriname? So, I know you don't want to front-run that, but I do want to ask you about resource scale to the extent you can and what you know today? And I'll frame it like this. When sanctioning in Guyana with similar DORs, the capacity of the development, 600 million barrels, 120,000 barrels a day. From everything we know, especially with Baja and the connectivity there. Tell me why resource of that scale is wildly off the mark?

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 resources 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.

Thank you. One moment for our next question, and that will come from the line of John Freeman with Raymond James. Your line is open.

Hi, guys.

Good morning, John.

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 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.

Yeah, John, this is Steve. If I just—if I step back and take a look at the year, we always plan that the second half free cash flow would be greater than the first half. And that's going to come from production growth. It's going to come from the Cheniere contract. It's going to come from a lower amount of capital spending that we'll have in the second half. And now as we look at the actual prices for the first half and anticipated prices for the second half, price will also be a bit of a factor there. So to address one potential concern that maybe we've done most of our share buybacks in the first half, I'd say the second half—there's still plenty of buybacks to do, plenty of capacity to do that. We've always said the 60% is a minimum. And I think every time period that we would look at, we've exceeded that minimum. We did in that fourth quarter of '21, we did it for the full year of '22 and certainly doing it first half of '23, and I’d just say we did front end, we chose to, obviously, to front-end load the buyback program in 2023. I'd just say that we're very happy with the share prices that we got, especially in the second quarter and we'll see what the second half of the year brings for us.

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—we 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.

John, that's a great point. I mean as costs continue to decline, you're going you will see our oil mix need to rise. And if you go back to this legacy large field, it’s been on decline, and it is declining. And so as costs continue to decline and our programs are in the more oily driven areas, you'll see that mix rise. And so it's early. I don't want to get into '24, but it wouldn't surprise me, and I would probably anticipate that the oil mix will be higher in '24 than it did in '23.

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

Morning, guys. John, can I ask maybe one more in Egypt? Just specifically, given an ample, I'm just wondering, are you seeing ample equipment and personnel there to continue to run the 17 rigs, and if so, given the strong results and your strong balance sheet, any thoughts to boost activity next year?

Neal, it took us a little bit 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 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.

Very good. And then my second for you guys is just on the Southern Midland. Could you speak to now, have you changed or are you walking up the average size, lateral length seems like some of your peers are continuing to get larger wells, larger pads to try to get more efficiencies? So I'm just on the same mindset.

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 a little more color or some statistics there.

Yes. So just on the Permian in general, we continue to walk lateral length higher. If you look at last year, we averaged just over 10,000 feet. This year, we're going to average closer to 10,500 feet for lateral. Again, there's variance. There are some three milers and there's some 1.5. But on average, the program is getting longer. And in 2024, we anticipate the links will continue to inch a little bit longer as well. And I think on the frac side, we've tended to lean to a little bit looser spacing and larger individual frac stage sizes and have had good success with that. And so I don't know that we'll get any bigger, but we're pretty comfortable with where we are on our completion designs at this point.

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

Yes. Good morning. I'm going to peer around the corner a little bit too here to 2024 on the US side; it looks like implied in the full year guidance that your US oil reduction can continuing the decline in 4Q; you're maybe getting to the mid-80s. How should we think about 2024 at this juncture in terms of oil growth in the US?

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 maybe 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.

And if deflation in service costs here in the States, if that turns out to be more material? Do you end up recycling that back into more drilling, or would you kind of keep the program the same in light of that deflation and just reap the benefits in terms of greater free cash?

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.

Thank you. That will come from the line of Charles Meade with Johnson Rice. Your line is open.

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

Good morning, Charles.

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?

I can let Tracey in a second get in a little bit to the geology, but what I'll just tell you first on Waha, it is a discovery that we discovered the discovery well in Block 53, where we have a separate set of partners as opposed to Block 58, it's in Total. We are the operator of Block 53. And so I can't say a lot at this point other than we've got a lot of work to do in terms of does Waha potentially flow into an oil hub in Block 58, or does it make up its own project in Block 53. So at this point, I can't say a lot there other than, obviously, there's a lot of work being done, a lot of different angles looked at. And Tracey, I'll have you chime in a little bit on the geology.

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 fairway. 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 have a well on location and a lot of work to integrate going forward.

Thank you, Tracey, thank you, John. That’s it for me.

You bet.

Thank you. One moment for our next question. And that will come from the line of Roger Read with Wells Fargo. Your line is open.

Thank you. Good morning.

Good morning, Roger.

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?

No. I mean, as Steve mentioned in his prepared remarks, Egypt, in a lot of places around the world right now are going through some difficult times. There is stress in the system. If you look at wheat prices and things, but from a standpoint of our business, it's been pretty much normal course in terms of movements and things like that. And you've seen us working constructively with Egypt to make progress, and you're seeing that.

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.

Yes, Roger, this is Dave. So on the drilling side, we continue to improve our drilling performance. Again, there are any number of metrics, which I won't bore you with. But the drilling team is doing a good job of getting our wells down in a very efficient manner where I think you might be going is on the productivity side. Lateral lengths, as I talked about earlier, getting a little bit longer, and that helps. But on a lateral length adjusted basis, relaxed spacing and bigger fracs have been a benefit to us in getting those lateral length adjusted productivity numbers to continue to improve. And it's always hard to forecast or we're going to keep getting better, but we're happy with the program so far. 2023 looks pretty good compared to 2022. And the team—we have a pretty good or very good subsurface team that continues to try to push the envelope on productivity per foot, and we're striving to continue to move that into 2024.

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, good morning. I wanted to get your thoughts on how the process you think will move once you fully evaluated the Krabdagu 3 results towards the declaration of commerciality and perhaps an FID decision?

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.

Got it. Got it. I mean I just wanted to maybe follow up there. Total has a frame agreement with the subsea provider, John, as you know, and they've raised the scope of the SURF package to over $1 billion from previously to $250 million to $500 million. Anything to read into that in terms of potential boat size at this point?

The only thing I'd say, and I'm going to defer, we'll let Total handle those relationships, and that's what 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.

Great. A quick follow-up on the North Sea. John, oil prices, Brent is now moving eclipse 80. What do you think needs to happen for the North Sea to attract capital next year? And maybe just thoughts on the broader portfolio. If we get in the situation where the Northeast is not competitive, are you just comfortable with, call it, two legs of the stool ex-Suriname at this point?

I mean obviously, the nice thing is, is having a diverse portfolio where we've got places to put capital. And we basically programmed 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 Sea's 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.

Thank you. One moment for our next question. And that will come from the line of Leo Mariani with ROTH MKM. Your line is open.

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 a 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 build that momentum, drill some of the other exploration targets just given how vast the basin is at this point in time?

Yes, Leo, I mean, we've got a large block. We've got a lot of time for other prospect areas and so forth. And I think the key was coming in, there's been a focus on let's get to project and an oil development, and that was what the focus was this year. And there are other prospects in the Krabdagu and Sapakara area. But at this point, we don't think it's necessary to drill those right down so.

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 you think the kind of running room here is on kind of the Tier 1 Permian acreage. If you look out a 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?

Yes. Leo, we've talked about kind of our visibility is kind of through the end of the decade on this run rate in this program and—no change to that. So we're pleased with—we're looking at a 3- to 5-year plan and pretty happy with what we have in there. So stay tuned.

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 rate.

And thank you, one moment for our next question. That will come from the line of Jeffrey Lambujon with TPH. Your line is open.

Good morning, guys. Appreciate you taking my questions. I wanted to ask my first one on US activity. Just wondering if the two Midland and two Delaware splits are 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?

Yes. Jeffrey, just a good question on the Midland versus Delaware split. If you think about the next 18 months or so, two in SMB and three in Delaware Basin makes sense. And then the question on Alpine, it's really about not just gas price, but what gas price does it take for those wells to be competitive versus an oil rig line either in SMB or Delaware. And those are the decisions we'll be looking at as Matterhorn comes online sometime back half of next year.

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

Yes, good morning. Can you just give us a sense of the CapEx outlook for the North Sea? What are your best estimates for how we should think about what may be required in 2024 given the Ocean Patriot release?

Yeah. I mean, I think if we look at the back half of 2023, we've got around $50 million of capital in the North Sea. And that's probably what you'd assume going into—for each half of next year. I'd say so $100 million, give or take, is what it would look like today roughly. I think the biggest thing there is just philosophy change. I mean, we're going to be operating for safety and integrity and managing decline and managing free cash flow. And there's still a lot of life left. I think the important thing is even by pulling the Patriot out, it doesn't really change our timing on when we see abandonment. I think we're still well into the early 2030s. And so we're going to do as good a job with that asset managing it for free cash flow.

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

Thank you. Good morning, guys. John, maybe guiding, but I think at one point that's a number talking about your Suriname so far, the discovery, say, around 800 million barrels. Just wanted to clarify if that is the right number, and that's in pace or are we comparable way and whether—I assume that's not including the Krabdagu-3 latest appraisal. And just want to see, is that the geology that to make what kind of reasonable recoverable weighting pace that we should assume? Any reason that you won't recover more than 50% of the resource in pace? That's the first question.

Yes. 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 the 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.

Yeah. Paul, I think if you can just look at historical recovery factors in big deepwater discoveries to put a range on it, the recovery factors are a function of the field development plans that you have. We're going to have gas injection here. And again, there'll be a lot of pressure maintenance. These are high-quality reservoirs. So I think you'd expect high recovery factors. But at this point, it's way premature to try to put a number on that.

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

Yeah. You're talking about gas cut, Paul?

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

Yeah. I don't have that at the tip of my fingers, but we've put the GORs in the prior press releases on the Sapakara and the Krabdagu discovery, and we've not disclosed anything yet on Krabdagu-2 or 3.

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.

Okay, great. And on Permian, you've done a number of three-mile wells. So just want to see that, is there a number you can share what percent of your inventory backlog that you could do three miles? And what percent of your work program for the next couple of years is going to be in the three miles? Thank you.

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, it's probably best to just assume they're all two-milers in the program.

Thank you. One moment for our next question. And that will come from the line of Umang Choudhary with Goldman Sachs. Your line is open.

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

You bet.

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?

Yes. This is Dave. If you look at it, it's really just across the board. It's a lot of things. And really, it's—the operating team has shown really good cost discipline through the year. We came into the year with some inflationary headwinds, and the team kind of took that as a challenge and really is doing a great job in all the areas, Egypt, North Sea, and the US in trying to keep those costs in check. And so it's—diesel and chemicals are easy to see. But everything else, it's just a lot of little things that add up to material numbers. And then I would echo comments from earlier, excited to see more on Suriname down the road. But separately, would just love your thoughts around the M&A landscape and how does that—how does that compare versus some of your organic opportunities here?

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.

Thank you. I'm showing no further questions in the queue at this time. I would now like to turn the call back over to Mr. John Christmann for any closing remarks.

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.

Thank you all for participating. This concludes today's program. You may now disconnect.