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. To ask a question during the session, you will need to press star one, one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one, one again. 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 Christman. 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 Purcell, 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 had an 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. The full disclaimer is located with the supplemental information on our website. With that, I'll turn the call over to John. Good morning. 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 U.S. 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 and 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 U.S. Capital investment during the period was in line with guidance, as our average operated drilling rig count remained steady at 17 in Egypt, 5 in the Permian Basin, and 1 semi-submersible in the North Sea. As previously planned, we released the Ocean Patriot in the North Sea at the end of June. U.S. 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 toward 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 Al pine 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, recompletions, 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 46,000-48,000 BOE per day, driven by higher operating efficiency and the positive impact of our Storr 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 pre-drill expectations. At Krabdagu-3, we are in the pressure buildup phase, and data collected thus far is very encouraging. The DDIII semi-submersible 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 U.S. 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 returned to shareholders via dividends and stock buybacks. Since the commencement of our share repurchase program in October 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. 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've 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 remain 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 U.S. 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 realize 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 1st. At current strip prices, this contract will generate approximately $120 million of free cash flow for the last 5 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 second quarter. We are confident further steps will keep this on the right track. In closing, our original full-year production guidance is unchanged. We have reduced our 2023 budget, CapEx, and OpEx 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. With that, I will turn the call over to the operator for Q&A. Thank you. As a reminder, to ask a question, please press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Due to time restraints, we ask that you please limit yourself to one question and one follow-up question. Please stand by while we compile the Q&A roster. Our first question will come from the line of Doug Leggate with Bank of America. Gosh, good morning, guys. I'll, I'll, I'll take that, but, thanks for. Good morning, Doug. Yeah. Yeah, I, I, I, yeah, it's more exotic than it probably should be, but, morning, John. Couple of things from me. I wanna ask about Egypt, not about the working capital progress, which is terrific. I think you've addressed that, Steve, with your, your commentary, but I wanna ask about the confidence in the medium-term oil growth trajectory in Egypt. That, that seems to be the only knock on the quarter, is that, you know, folks are maybe a little questioning whether you can actually deliver that. How is that progressing? What is the outlook today? I've got a follow-up, please. Yeah, Doug, it, you know, the nice thing about being early August, you know, we have the luxury of seeing a lot of the wells we've got coming on in the near future. If you look and you won't see it, but our July, our July volumes have actually averaged 145,000 barrels a day on the oil side, so we're up already in July over the second quarter, and we've got good line of sight on what's coming, and it's gonna be a good back half of the year. I'll, I'll let Dave Purcell, you know, jump in with a little bit more detail. Yeah, Doug, as John alluded or John said, the gross oil at 145 in July gives us confidence. We have a couple other data points. We've had good success on exploration in both the Matruh and the Abu Gharadig basins, 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. Just some numbers. First half of the year, we brought 48 wells online. Back half of the year, we expect to put over 70 wells online. More wells, high quality, good confidence in what those wells look like. Again, our confidence in the back half guidance is very good, very high. What about beyond 2023, Dave? Yeah, we, we continue to, to look at, at the, at the 2024 plan. We're, we're, you know, too early to give guidance, but we have confidence in the ability to, to keep the growth engine moving. Great stuff. Thank you for that. John, I, I apologize, I'm gonna have to be predictable. Total is having its analyst day at the end of September. I think they've given a pretty good steer that they're gonna have something to say there on Suriname. I know you don't want to front-run that, but I, I do wanna ask you about resource scale to the extent you can and what you know today. I'll, I'll frame it like this: When Liza Two was sanctioned in Guyana with similar GORs, the capacity of the development, 600 million barrels, 220,000 barrels a day, from everything we know, especially with Baja and the connectivity there- Tell me why resource of that scale is, is wildly off the mark? I mean, at this point, well, a couple of things, Doug. Number 1, we still have the rig on location, so it's, it's early. You know, number 2, we, we came into this year with the primary objective being appraising the Krabdagu fairway. You know, you had the original discovery well. If I flip over, it's a totally different set of partners in Block 53, but we had... You know, when we announced the Baja discovery, we said it was a down dip low above that fairway. Yes, it does stretch from there all the way now back to Krabdagu-3. Krabdagu-3 was, was 14 kilometers from the discovery well. You know, as we've said, the results are very, very encouraging. It, we do-- we can confirm it's 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 gonna see from the flow test. There's just a lot of technical work that we need to do, and, and we'll come back in due course with, you know, information in the relatively near future. Thank you. One moment for our next question. That will come from the line of John Freeman with Raymond James. Your line is open. Hi, guys. Good morning, John. Yeah. The, the first topic I wanted to address was on the, the shareholder returns. You know, you returned the, the 131% of free cash flow this quarter. Last quarter, you did 81%. I'd just be curious, kind of your thought process and kind of how you all 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, you know, 60% target that you all have. Just sort of how you all think about when it's, when it's appropriate time to kind of lean into these things. Yeah, John, this is Steve. You know, if I, if I step back and take a look at the year, you know, we, we always plan that the second half free cash flow would be greater than the first half. You know, that's gonna, that's gonna come from production growth, it's gonna come from the Cheniere contract, it's gonna come from a lower amount of capital spending that we'll have in the second half. Now as we look at that actual prices for the first half and anticipated prices for the second half, price will also be a, a benefactor there. You know, to, to address one potential concern that, you know, maybe we've, we've done most of our share buybacks in the first half, I'd say the second half, there's still plenty, 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, we've exceeded that minimum. We did in that fourth quarter of 2021, we did it for the full year of 2022, and certainly doing it first half of 2023. I'd just say, you know, we, we did front-end, we, we chose to, obviously, obviously, to front-end load the, 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. You know, we're, we'll, we'll see what, what the second half of the year brings for us. Okay. My follow-up, just, kind of following on to, Doug's questions on, on Egypt. Just sort of what y'all, y'all identified in terms of the, you got the mature natural gas field that's, that's declining. So that, that oil mix, as we've seen now for the last, you know, three quarters, just keeps inching up. It, it looks like, just ballpark, that for 2024, like something in that, like 65% kind of oil mix would be, would be possible. Just sort of any commentary about how you all see that, that oil mix sort of, continue to evolve as it's, it's continuing to ramp up? John, that's a great point. I mean, as Qasr continues to decline, you know, you will see our oil mix in Egypt rise. If you go back, Qasr is a legacy, large field, three Ts. It's been on decline, and it is declining. As Qasr continues to decline and our, our programs are in the more oily, driven, you know, areas, you'll see that mix rise. It's early. I don't want to get into 2024, but it wouldn't surprise me, and I would probably anticipate that the oil mix will be higher in 2024 than it is in 2023. Thank you. One moment for our next question. That will come from the line of Neal Dingman with Truist Securities. Your line is open. Hi, morning, guys. John, could I ask maybe one more on Egypt, just specifically, you know, I'm just wondering, are you seeing ample equipment and personnel there to continue to run the 17 rigs? You know, if so, given the strong results and your strong balance sheet, any thoughts to boost activity next year? You know, Neal, it took us a little bit of time last year with training programs to kind of get the program where we wanted it. We're there today, we feel good about that. We've put a lot of training in place. I think right now, you know, 17, 18 rigs is a pretty good number. I think it's about all that's in country and from a staffing perspective. I think we're in a pretty good place, and you're seeing us finally get you know, the results and efficiencies where we were hoping we'd get to. We feel like we're in a good place, and right now, that's what I see for the foreseeable future. Very good. Then my, 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 go to larger wells, larger pads to try to get more efficiencies. I'm just wondering if you're on the same mindset. Yeah, we came into this year, you know, really with our programs focused on the longer laterals, a lot of two and three milers. Dave, I think you've got a little more color or some statistics there. Yeah. Just on the, the Permian in general, we continue to walk lateral length, higher. If, if you look at last year, we averaged just over 10,000 feet. This year, we're gonna average closer to 10,500 feet, foot per lateral. Again, there's variance. There's some three milers, and there's some one and a half, but on average, the program's getting longer. In 2024, we anticipate the, the lengths will continue to inch a little bit, longer as well. I think on the frack size, we've tended to lean to a little bit looser spacing and larger individual frack stage size, and have had good success with that. I don't know that we'll get any bigger, but we've, we've, 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 gonna peer around the, the corner a little bit too here. In the 2024 on the U.S. side, you know, it looks like, you know, implied in the, the full year guidance that your U.S. oil production can continue to, to climb in 4Q, you maybe get into the mid-80s. How should we think about 2024 at this juncture in terms of oil growth in the U.S.? It's early in terms of numbers. I mean, we, 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, you know, we start getting into reviewing that and so forth in the fall. I would anticipate, you know, pretty level activity sets from where we are today. So if you look at that, you know, with the programs we're, we're delivering and the, the types of laterals we're drilling, you know, I would expect fairly, you know, similar increments of growth, maybe on a little higher base in terms of, you know, the, with the volume that we're growing this year. You you know, it's always lumpy when you're running 5 rigs with the timing, and so I don't know how the timing will line up, you know, year-over-year, fourth quarter over fourth quarter, some of those numbers. I would expect a, a very strong continuous program in the U.S. and in Egypt for 2024. If, if deflation, you know, and service costs, here in the States, if that turns out to be more material, do you end up, you know, recycling that back into, into more drilling? Would you kinda keep the program the same, even in light of that deflation and, and just, you know, reap the benefits in terms of greater free cash? I mean, I, I would say right now, the, the, the plans would be to, you know, take the program and let the program dictate, because, you know, 5 rigs, we're, we're working with 1.5 frack crews. We're in a pretty good cadence there. You know, it's, it's hard to just add, you know, incrementally without going up in stairstep function. I would anticipate that the, the service side, whatever benefits there, would come to free cash flow, and the program will be pretty stable. You know, we do try to go in every year with a pretty set framework on the capital side, and so we... You know, a lot of what's going on this fall will dictate what our service costs will look like, you know, for the portions that we will try to lock down for next year. You know, we'll just have to wait to see how things play out. You know, clearly, you've had a little bit of softening in some areas right now, but I think everybody's waiting to kind of see what prices do the back half of the year to really steer next year's capital. Thank you. One moment for our next question. 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, I'm eager to, 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 gonna have to wait a little bit. I want to instead ask about Baja, 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 depositional system as, as the Krabdagu, and perhaps as part of talking about your plan for appraisal, can you also address it, is, is it also one of these shelf slope kind of targets, or, or is, are you maybe starting to hit the transition into the basin for fans out there I, I can let, Tracey in a second, get in a little bit to the geology, but what I, what I'll just tell you first on, you know, Baja, it, it is a discovery that we, you know, discovered. The discovery well is in Block 53, where we have a, you know, a separate set of, partners as opposed to, Block 58, where it's us and TotalEnergies. We are the operator of Block 53. So I can't say a lot at this point other than, you know, we've got a lot of work to do in terms of, does Baja potentially flow into, you know, an oil hub in Block 58, or does it make up, its own project in Block 53? At this point, you know, I can't say a lot there other than obviously, there's a lot of work being done and a lot of different angles looked at. Tracey, I'll have you chime in a little bit on the geology. Sure. Morning, Charles. I think great question on the fairway. Your, your initial assessment there about, you know, being slope channel systems are what we've discussed in the past. What we're, you know, describing as a fairway, and as John mentioned in his remarks, you know, something we've defined now that's roughly, you know, 25 kilometers, from Baja to Krabdagu-3. You've got a very, you know, robust system that's coming through here in a series of slope channels that, you know, you can tell from our original, release at Krabdagu-1, which are stacked systems. Correct in your assessment, we're seeing slope channel systems. As John said, we've got more technical work to do. We've still got 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. That will come from the line of Roger Read with Wells Fargo. Your line is open. Yeah, thank you. Good morning. Good morning, Roger. Morning, John. Just like to, to ask about Egypt and not from an operational standpoint, but, you know, 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 fund 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, you know, Steve mentioned in his prepared remarks, that, Egypt and a lot of places around the world right now are going through some difficult times. There, there is, you know, stress in the system as you look at wheat prices and things. From a standpoint of our business, you know, it's been pretty much normal course in terms of, you know, movements and things like that. You've seen us, you know, working constructively with Egypt to make progress, and, you know, you're seeing that, so. Okay. I'll take that as a good answer. Then, my other question is just, as you look at operations in the Permian, what would be the, the broader description of sort of productivity and efficiency gains you're seeing, you know, sort of leaving any service cost, inflation or deflation aside, but just what you're seeing in terms of performance on, you know, the drilling side, on the completion stages, things like that? Yeah, Roger, this is Dave. On the drilling side, we continue to improve our drilling performance. You know, again, there's any number of metrics, which I won't bore you with, but the drilling team's doing a good job of getting our wells down in a very efficient and manner. Where I think you might be going is on the productivity side. You know, 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. You know, it's always hard to forecast, are we gonna keep getting better? But we're happy with the program so far. 2023 looks pretty good compared to 2022. You know, the team, we have a, a, a pretty good or very good subsurface team that continues to try to push the envelope on productivity per foot, and we're, we're, we're striving to continue to move that into 2024. Thank you. One moment for our next question. That will come from the line of Arun Jayaram with J.P. Morgan Securities. Your line is open. John, good morning. I wanted to get your thoughts on, you know, how the process you think will move, you know, once you've fully evaluated the Krabdagu-3 results towards, the declaration of commerciality and perhaps an FID decision. Yeah, I mean, Arun, first of all, it's like we said, we're rig's still on location, and so we've got a lot of technical work to do, but, you know, we'll come back at some point with more data. That is exactly what you just mentioned, would be the steps you'd take. You know, 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 and, you know, TotalEnergies, so. Got it. Got it. I mean, I just wanted to maybe follow up there. You know, TotalEnergies 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, you know, previously it was $250 million-$500 million. Anything to read into that in terms of potential boat size at this point? You know, the only thing I'd say, and, and I'm gonna, you know, defer, we'll let Total handle those, you know, relationships, and that's what they're-- They'll be operator, right? I'll just leave it at that. I mean, I, I would say we came into this year with the goal to appraise Krabdagu because we said it could impact scope, scale. You know, clearly, we've had a, you know, a positive result at Krabdagu-3. Yeah, that was one of the objectives with, with the appraisal program, and, and the, you know, the number 3 well was designed for a very large step out to better understand, you know, potentially what type of resource we could have there. Gotta let the technical teams do the work, but, you know, 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, you know, eclipsed 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 a situation where the, the North Sea is just not competitive, are you just comfortable with, call it, 2 legs of the stool, ex Suriname at this point? I mean, yeah, obviously, the nice thing is, is having a diverse portfolio where we've got, you know, places to put capital. You know, we basically ran a program in the North Sea with the Ocean Patriot for six months. You know, you see us in a good position in terms of sustaining and growing the company. As we look at next year, you know, we'll, we'll factor in what makes sense. You know, right now, more, more importantly, from the North Sea's perspective, you know, you'd need to see some stability in the regime to make long-term investments. Right now, we have not seen any stability. I, you know, I would not anticipate us jumping in because prices are up and, and deciding to put a lot of capital in the North Sea at this point, other than what we need to do for maintenance and integrity and safety. Thank you. One moment for our next question. That will come from the line of Leo Mariani with Roth MKM. Your line is open. Hi, guys. Just wanted to follow up quickly on Suriname here. Certainly seems as though you guys have found, you know, significant oil here, you know, 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, you know, for the rest of the year. I mean, it feels like you've got great momentum there. You found a lot of oil at the end of the day. You know, why get rid of the rig for the last, you know, call it four or five months of the year? Why not sort of build on that momentum, drill some of the other exploration targets, just given how, you know, vast, you know, the basin is at this point in time? Yeah, Leo, I mean, we've got a large block. We've got a lot of time, you know, for other prospect areas and so forth. I think the key was coming in. You know, there's been a focus on let's, let's get to a project and an oil development, and that was what the focus was this year. You know, there are other prospects in the Krabdagu and Sapakara area, but at this point, we, we don't, you know, think it's necessary to drill those right now, so. Okay. Just, you know, in terms of the, the U.S. well performance, you guys talked about this a little bit. You know, it sounds like there have been some changes to the, the completion design, potentially here with, you know, a little bit kind of, you know, wider spacing. It seems like the, the oil performance there has been a lot more consistent. You guys basically said that it looks like 2023 well performance is, is a little better than, than 2022. Just kinda wanted to get a little sense of, you know, what do you think the kind of running room here is on, on kinda the tier one, you know, Permian acreage? If you look out, you know, a handful of years, do you guys have kind of an estimate on, you know, how long you can kinda keep 5 rigs running and, and kinda how much, you know, inventory you have, maybe in terms of kinda rig years or something? Yeah, Leo, we've, we've talked about kinda our visibility is kinda through the end of the decade on, on, on this run rate and this program, and no change to that. We're, we're pleased with... You know, we're looking at a three to five-year plan and pretty happy with what we have in there, so stay tuned. Yeah, the other, 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 one. two years ago, we had it at tier two, tier three, right? We've got a nice acreage footprint, and so you're always also looking to, to see the evolution of the, of the resource. You know, we've got strong confidence in the, in the U.S. inventory at these, you know, at this program rates. Thank you. One moment for our next question, and that will come from the line of Jeffrey Lambujon with TPH&Co.. Your line is open. Morning, guys. Appreciate you taking my questions. Wanted to ask my first one on U.S. activity. Just wondering if the 2 Midland and 3 Delaware splits, good to assume as part of that base case of steady activity. If you talk about, you know, how you think about toggling that in the near term, if at all, whether in terms of, you know, inventory comparing the two or, or any other factors. I'd imagine the flexibility of, of the Delaware, in terms of proximity to the Alpine High, plays into it to some degree. If you could also maybe speak to what you want to see there on the macro or from the wells to add back any sort of capital there. Yeah, Jeffrey, just good question on the Midland versus Delaware split. You know, you know, again, as you know, rigs are fungible. We could, you know, there's no magic a Delaware rig could move over to the Southern Midland Basin. But if you think about, you know, the next 18 months or so, you know, 2 in SMB and 3 in Delaware Basin tends to make 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, you know, those are the decisions we'll be looking at as, as, you know, Matterhorn comes online sometime, you know, back half of next year. Okay, great. That makes sense. Then maybe just a quick follow-up on the, the North Sea. I know it's already a, a relatively small part of the budget and, and getting smaller, just looking to next year with the release of the Ocean Patriot, as you, as you guys highlighted. 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, for CapEx? It seems like year-over-year, you could maybe be looking at something like, you know, maybe half the spend that was originally budgeted for, for this year. 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. That's probably what you'd assume going into, you know, for each half of next year, I'd say. $100 million, give or take, is what it would look at like today, roughly. I think the biggest thing there is just philosophy change. I mean, we're gonna be operating for safety and integrity and managing decline and managing free cash flow. You know, 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, you know, our timing on when we see abandonment. I think we're still well into the early 2030s. You know, we're gonna 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, I-- maybe I got it wrong, but I think at one point that the number talking about your Suri name so far, the discovery, say, around 800 million barrels. Just want to clarify if that is the right number, and that's in-place or recoverable way, and whether I assume that's not including the Krabdagu-3 latest appraisal? Just want to see, is that, the geologies that to make what kind of reasonable, recoverable way it is in place, that we should assume any reason that it, it won't recover more than 50% of the resource in place? That's the first question. Yeah. Paul, the, you know, you get to the 800, as we've disclosed, at Sapakara. You know, from the original well, and the second well, we had more than 600 million barrels of connected resource. You know, 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. The 800 number is would be a connected resource in place, and it, it's not a recoverable number, but it also does not include Krabdagu-2 or Krab. You know, Krabdagu-3 and the integration work that's going on now that, you know, will, will come forward. Dave, you might reference just, you know, 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, I think if you, you can just look at historical recovery factors in, in big deep water discoveries to put a range on it. You know, the recovery factors are a function of, you know, the field development plans that you have. We're gonna have gas injection here and, you know, again, there'll be a lot of pressure maintenance. You know, these, these are, are high-quality reservoirs, so I think you'd expect, you know, high recovery factors. At this point, it's way premature to try to put a put a number on that. I think, do you have a rough estimate what's the gas cut in that 800 million barrel? Yeah. You, 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, 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 Krabdagu-3. Yeah. Sapakara was 1,100 GOR, roughly, and the discovery well at Krabdagu had two different ranges from around, you know, the high teens to, you know, the high 2,000s. Okay, great. On Permian, you've drilling a number of 3-mile wells, so just want to see that, is there a number you can share, what% of your inventory backlog that you could do 3 miles, and what% of your work program for the next 2 years is going to be in the 3 miles? Thank you. Y- yeah, Paul, this is Dave. I, I don't have that number. It's a relatively small% of the total work plan. We're, we're happy with the results from our 3-milers. It's really just a question of where does the acreage footprint, you know, allow that to allow us to drill the 3-milers. We've-- you can tell just by the numbers I threw out earlier, you know, most of what we're drilling are, are 2-milers. The team, you know, anytime we get a chance to drill a 3-miler, we'll do it, and that's just acreage footprint. From a, from a modeling standpoint, it's, it's probably best to just assume they're all 2-milers in the program. Thank you. As a reminder, if you would like to ask a question, please press star one, one. One moment for our next question. That will come from the line of Umang Chowdhury with Goldman Sachs. Your line is open. Hi, good morning, and thank you for taking my questions. You bet. My, my first question is on, on the $100 million savings, from your operating cost management program. You talked about diesel and chemicals driving some savings there. Any additional color you can provide, in terms of, any other buckets which is driving, those, those savings? Yeah, 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, you know, 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 U.S., and trying to keep those costs in check. So it's, you know, diesel and chemicals are easy to see, but everything else, it's just a lot of little things that add up to material numbers. Thank you. Then, would echo comments from earlier, excited to see more on Suriname down the road. 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, I think in, in general, you've, you've seen a, a couple of deals take place in the Permian. They've traded at what we viewed as pretty high valuations. Yeah, you look, obviously, we've been focused organically, but, you know, you've, you've always gotta be on the lookout for things that could make sense. You know, and, and obviously, that's, that's, 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. 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 Christman 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. 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. 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.