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. 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 first speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead. Good morning, and thank you for joining us on APA Corporation's Second Quarter 2024 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO John Christmann. Stephen Riney, President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are 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. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website. Please note that the Callon acquisition closed on April 1. Accordingly, our full year 2024 guidance reflects first quarter APA results on a standalone basis, plus three quarters of APA and Callon combined. With that, I will turn the call over to John. 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 workover 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 hull for our first offshore development, and we remain on track for FID before year-end and first oil in 2028. 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-$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 2-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 5-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 9-10 rigs for the remainder of this year, consisting of approximately 5 rigs in the Delaware and 4 rigs in the Midland. We plan to run 3-4 frack 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 Beryl, 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. Thank you, John. For the second quarter, under generally accepted accounting principles, APA reported consolidated net income of $541 million or $1.46 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which were a $216 million after-tax gain on divestitures and $98 million of after-tax charges for transaction, reorganization, and separation costs, mostly associated with the Callon acquisition. Excluding these and other smaller items, adjusted net income for the second quarter was $434 million or $1.17 per share. During the first half of the year, we generated roughly $200 million of free cash flow and returned $311 million to shareholders, nearly half of which consisted of share repurchases. That's a lot compared to the $200 million of free cash flow, but we liked buying at those share prices, and we anticipate free cash flow will be much higher in the second half of the year. That said, the balance sheet remains an important priority, and I will talk about plans for further debt reduction in a few minutes. Now let me turn to progress on the Callon integration. As John noted, we increased our estimate of annual synergies to $250 million. Since we announced the Callon acquisition, we have categorized synergies into three buckets: overhead, cost of capital, and operational. We are now increasing our estimate of expected annual overhead synergies to $90 million. Most of this was captured by the end of the second quarter on a run rate basis, and the remainder will be done by year-end. At this time, we anticipate that our quarterly core G&A run rate as we enter next year, will be approximately $110 million. With that, we will have eliminated about 75% of Callon overhead cost, so no material further synergies are likely. Our cost of capital synergy estimate of $40 million annually assume terming out Callon's $2 billion debt at APA's lower long-term cost of borrowing. At the closing, we used cash from the revolver and a $1.5 billion three-year term loan to refinance this debt. Instead of terming this debt out, our current intention is to use asset sales and free cash flow to simply pay off the loan before the end of its three-year term. This would represent a significant step forward in the goal to strengthen the balance sheet and to fully realize these synergies. Lastly, we are increasing our operational synergies to $120 million annually, approximately 60% of which is associated with capital savings and 40% attributable to LOE. To reiterate, these cost synergies do not include capital productivity benefits associated with uplifting type curves and improving well economics through spacing, landing zone optimization, and frack size. We believe this will be a source of material long-term value accretion. Turning to our 2024 outlook, John has already discussed our activity plans and production guidance, so I will just add a few items of note. We now expect that our original full-year capital guidance of $2.7 billion may start trending down a bit. A number of factors could contribute to this, including further synergy capture from the Callon combination, lower service costs, improving capital efficiency, and potential minor reductions in the planned activity set, mostly in the U.S. For purposes of third quarter U.S. BOE production guidance, we are estimating further Permian gas curtailments of 90 million cubic feet per day. This would also result in the curtailment of 7,500 barrels per day of NGLs. As most of you are aware, our income from third-party oil and gas purchased and sold can change significantly from quarter- to- quarter. This is primarily driven by the volatility in differentials between Waha and Gulf Coast gas pricing, regardless of the absolute pricing levels. It's important to note that APA's gas marketing and transportation activities are generally more profitable when Waha gas price differentials are wider. For example, the Waha differential was very wide in the second quarter. While Gulf Coast gas prices averaged around $1.65, Waha gas prices averaged closer to -$0.34. Because of the nearly $2 differential, income from our third-party marketing and transportation activities was well above expectations. At current strip gas pricing, we expect a similar dynamic in the third quarter. Accordingly, we are raising our full year estimate of income from third-party oil and gas purchased and sold by $120 million to around $350 million. Approximately half of the full year estimate is attributable to the Cheniere gas supply contract, and half is attributable to our marketing and transportation activities. Lastly, APA is now subject to the U.S. Alternative Minimum Tax, and accordingly, we are introducing new guidance for current U.S. tax accruals of $95 million for the year. With that, I will turn the call over to the operator for Q&A. Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for your name to be announced. To withdraw the question, please press star one one again. You may ask one question and one follow-up question. Please stand by while we compile the Q&A roster. Our first question comes from Doug Leggate of Wolfe Research. Your line is now open. Hey, guys. I'm still getting used to the new moniker, so bear with me. Thanks for having me on. Welcome back into the fray, Doug. Thanks, John. So I guess there's so many things on the quarter that I could go after, so I'm gonna just try a couple. But Steve, it looks to us that your CapEx run rate, exit, call it fourth quarter, looks like you're gonna be around $600 million, which would be about a 10% decline year-over-year, if that held into 2025. Is the objective after you grow, you know, you've got the momentum from Callon, is the objective to hold that flat, in which case, should we be thinking something around $2.4-$2.5 billion for next year? Yeah, Doug, I'd be careful just using fourth quarter. We're probably gonna be a little on completion activity in the fourth quarter because a lot of that has been bunched 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, you know, full year spend, take out the first quarter, which is just APA.... And then, you know, 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 gonna be about average-ish, and fourth quarter is probably gonna be a little low. And then I think you'll get a number of something close to around 700 per quarter. Okay. All right. That's really helpful, guys, and then I'll get a chance to- Sorry, sorry, Doug. If you, if you take out the exploration, you'll probably get something closer to 675 a quarter—675 million a quarter of capital spend on, basically, the U.S. onshore and, and Egypt. There's not a whole lot of capital activity, as you know, going on in the North Sea. Okay. That's what I was trying to get run rate, so that's really helpful. John, I wonder if you've not wanted to be drawn on inventory depth since the Callon deal, but I'm guessing you're getting your hands around that now. So when you look at the drilling pace, I guess you're gonna be at 9 rigs in the second half, what are you thinking with the up spacing and so on? What are you thinking about your inventory depth looks like now in the lower 48? And I'll leave it there. Yeah, Doug, it's a great question. It's one we're, you know, we're working every day. What I would say is, if you look at the existing, you know, 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, and is that if 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, you know, pay for in our acquisition. So that's something we're currently working on. You know, if you look at where we sit today, we've got a lot of flexibility going into next year. We're gonna grow Permian a very strong clip from second quarter to fourth quarter, you know, on 9-10 rigs, about 8%. So it gives us a lot of flexibility, you know, going into next year pace we wanna go. We've had plenty of, you know, inventory that we have visibility on now to carry us to the end of the decade, and, you know, we'll keep working that. Yeah, and just- Okay. Just a bit to add on, Doug, to what John just said, just to enhance that a bit. You know, when we were working on the acquisition, of course, we were looking at a lot of outside service providers that look at inventory counts, and most of them probably would have said that Callon had more running room, more inventory, more years of inventory than we did. Based on our analysis, as John said, which is a fairly conservative view of the world, we said, "Now, it's probably more similar to ours in duration." And, you know, as John indicated, the more we can get capital efficiency, capital productivity into the right place on the Callon acreage, the more that inventory quantum could grow back to what some of the other people thought it was, which is something that would extend beyond the end of this decade. Got it. Thanks, guys. I'll see you next week. Thank you. One moment for our next question. Our next question comes from John Freeman of Raymond James. Your line is now open. Good morning, guys. Good morning, John. Just to kind of follow up on some of Doug's questions. I mean, the Permian and Egypt both, you know, exceeding guidance and, you know, specifically on Egypt, you know, pretty solid job of getting that turned around. And I'm just trying to make sure that, you know, I'm thinking about this right, where you've got, you know, you average 16 rigs in the first half of the year, you're gonna drop down to 11 rigs in the second half of the year. Am I kind of reading it right, that even at that lower rig 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 recompletions, you know, resolving kind of that backlog of oil offline, 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 kinda maintain volumes? Just trying to make sure I understand kind of what's the moving pieces. No, it's a great question, John, and you know, you're on the right track. I'd say that you know, the benefit we've had by dropping the rigs is it's been able to free up the workover rig time, which is critical because we have a lot of recompletions. And really, we also have a lot of CTIs, which are conversion to injection projects that we've been able to get to. And so, you know, when we were running you know, 20 workover rigs and 18 drilling rigs, there was not much slack. By ratcheting that back, it's freed up the time, and it's letting us get to some very meaningful you know, projects that are making a huge impact. Is 11 rigs? You know, this year we kinda guided to flat to slightly down. Is 11 the right number? It's early to tell on that front, but, you know, just having gotten back from Egypt, there's also a lot of other projects that we're talking to Egypt about. You know, for example, some gas drilling and other things too, which could be pretty impactful as well. So, you know, there's lots of flexibility there, and, you know, we'll be working through that as, we work through our planning cycle. ... Great. And then just, my follow-up, John, you mentioned that, you might, you'd see the, 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'd have less curtailed gas volumes, potentially in four Q. So in the, the current guidance, does it assume any curtailments in four Q? I I mean, obviously, y'all, you had some in two Q, you have even more in three Q. I'm just trying to get a sense of what's built into that full year guidance. Today, 4Q, you know, fourth quarter does not have any curtailments built in. But obviously, we had to up the, you know, the third quarter with September, with where Waha sits. Yeah, and just, you know, second quarter actuals, the amount that was curtailed, we had 78 million cubic feet per day of gas and 7,600 barrels of NGLs curtailed during the quarter on an average day. You know, 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. Appreciate it, guys. Nice quarter. Thank you, John. One moment for our next question, which comes from Neal Dingmann of Truist. Your line is now open. Morning, guys. Nice update. John, maybe sticking with on the Permian or the Callon, specifically, the Callon acreage development. Really just wondering here, you all have talked about, I think, pretty openly, potentially up spacing a little bit. I'm just wondering, besides potentially future up spacing, is there any sort of material other changes, either on the completion or other side going forward you could see, potentially doing on this point? Yeah, as I said in the prepared remarks, Neal, that, you know, one of the advantages, too, is we're seeing impacts on the combined business, just from the supply chain, how we design the wells. You know, we think we can drill a standard two-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, you know, excited about what we're seeing. And quite frankly, we're just now starting to spud some of the Apache planned pads on the Callon acres. So, you know, excited to see those results, but things are going extremely well on the integration side. Yeah- Look forward to it, and then... Go ahead, Steve. Yeah, the only thing I would add to that on the, on the completion side, you know, with the Callon-drilled wells or Callon spud wells, since they were spaced quite a bit tighter than we would space them, we haven't really changed the proppant loading much on those. We did on a few, but not many. But we significantly increased the fluid loading on those, on those fracs. As we get to our wells, the ones that we drill, obviously, the both proppant and fluid loading will be quite a bit larger. Great. Great. And then maybe, Steve, for you, just a second question on shareholder return. Specifically, your shareholder return continues to be quite active. You know, I think it was down a little bit sequentially in this last quarter. I'm just wondering, can we anticipate, you know, a large step up for remainder of the year? Or how would you like to think about, think us, think about the program for remainder of 2024 into 2025? I tend to think of that on a, on an annual basis, a calendar year basis. We've got at least 60% of free cash flow through dividends and through share buybacks, both with April first acquisition using shares, the outlook of dividends and for free cash flow is quite a bit, but the framework doesn't change. 60% at a minimum. We're obviously way ahead of that in the first half of the year. And you know, we'll, we'll see what the second half brings. We, I think we've demonstrated in the past that we're not afraid to go over, well over the 60% framework. But let's, you know, we also recognize there's continued need for balance sheet strengthening after the... So we'll balance that on a, you know, quarter by quarter, really day by day, basis. We'll see where we are at, as we go from one year to the next. Very good. Thank you. Our next question comes from Charles Meade of Johnson Rice. Your line is now open. Good morning, John and Steve and the rest of the APA team there. Good morning, Charles. Yeah. Thank you. I'm wondering, you kind of maybe you didn't surprise the whole market, but you surprised a few people, at least, with these last couple of asset sales. And I'm curious if you can share or you might want to share what is next. And I guess I'm thinking most prominently about the Central Basin Platform, which is an asset or an area that we don't really talk about much anymore, and it doesn't seem like you guys are deploying capital there. No, Charles, I mean, you know, we typically wait to talk about property sales. But you know, there's a chance there's other things that we're looking at that are not core to us and places that we're not putting capital. So, you know, you may have some decent intel out there. ... Fair enough. Thank you, John. And then I have a question about the shut-ins and the marketing in the Permian. As I think about how I would manage that, you know, the production, given that you have that valuable firm transport to the coast, I would, I guess I'm surmising that that 90 million a day and 7,500 barrels of NGLs, is that essentially all of your dry gas and some of your liquids-rich gas? Or is, or are you, you know, is there more that you could curtail if that basis got wider? Yeah, Charles, so there, there's yeah, we can actually curtail quite a bit more than that, a little more than twice that amount. 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. We'll especially do that when prices go negative or significantly negative. When prices are just low, we'll typically just go with lean gas and not dip into the richer gas. So we do that based on a price basis. We have specific prices. We move from one tranche to another. We've got four specific tranches of gas going from lean to richer gas that we can shut in different pricing mechanisms. And so I just wanna, I wanna make sure that we're really clear about one fact, and that is that the curtailment of gas volumes in the Permian Basin and in 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. We don't have a choice of doing that. If we choose not to transport gas, we have to pay the transport fee anyway. It's a nice piece of business to have. Thanks for that detail, Steve. Thank you. Our next question comes from Roger Read of Wells Fargo Securities. Your line is now open. Hey, good morning. Good morning, Roger. Yeah, I'd like to maybe follow up on some of your discussions on Egypt, just to understand, like, where is the decision coming from on the switch from drilling to workovers? Is that, you know, all the partners? Is that your decision? Is it Egypt's decision? And then how should we think about that maybe reversing as we exit 2024 into 2025, to the extent you can offer any sort of guidance that way? Well, I mean, you know, we have a joint venture there. We have a one-third partner with Sinopec, but, you know, 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, you know, it just shows that getting that workover rig and drilling rig, you know, balance into play really gives us a lot more flexibility. I would just say there's, you know, it would be, you know, our choice in terms of adding activity, and there is flexibility to do that. And, you know, we were recently over there, you know, 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, you know, outlined some frameworks under which we could, you know, 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, you know, the planning process. Okay, appreciate that. And then just to come back around on the Callon integration, understand the, you know, the changes and the synergies and all. But if you were to just give us an idea, you know, in the old, baseball terms or football game quarters or whatever, as you think about the integration and the understanding of, you know, what Callon really brings to the Apache family, like, are we, we early, we mid, we-- are we late in, in the process of really kind of understanding all that? Yeah, I think it, 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, you know, 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've worked through that quickly. You know, obviously, the piece that's the most exciting and still to come is gonna be, what can we drive on the productivity improvements and what does that do in terms of inventory and location? So, you know, we're just now getting to the first pads, and spudding our first Apache planned wells and, you know, obviously anxious to get on with those results. Yeah, anyone want to add to it? Yeah, I'd characterize it using the baseball analogy. I think, you know, going through the synergies and going through the headcount and all of that, getting the organization integrated, that's kind of the pregame warm-up. You know, as John said, we've just drilled our first well out there on Callon acreage. So, you know, I would say that we're, you know, we're at bat the first inning, and we haven't taken the first pitch yet, so it's just starting. The game is just beginning. I appreciate that. Thank you. Thank you. Our next question comes from Scott Hanold of RBC. Your line is now open. Thanks. I was wondering if we could pivot to Suriname and, you know, what are your high-level thoughts on, on how you look at activity, maybe spending in 2025? I know it may be a bit early and, your partner has a upcoming analyst day, and that we're gonna get more color there. But, you know, what is your understanding at this point? Yeah, Scott, I mean, we've been pretty consistent since this time last year that, you know, the, after we finished the Krabdagu appraisal, that, we were highly confident we were gonna have a project. And we stated we, you know, plan to have an FID by year-end 2024, and obviously, we remain on track. It's consistent with the message that Total's now put out. I think that is the next step, and, you know, once we get to that step, then we can obviously talk a lot more about what that means and, and all of that. But, things are going extremely well. Teams are working very well together, and they are doing their thing. You know, right now, I'd say we remain on track for year-end FID and first oil by 2028, and they're working hard to accelerate those. Okay, understood. And, you know, my follow-up question is, you know, back to, you know, kind of the Permian inventory runway. You know, you talked about being, you know, confident through the end of the decade at this point in time. You know, do you all think that's a strong enough position? And so what I'm trying to get to is, like, what is your appetite for further consolidation? Do you feel comfortable with that position now, or are there other opportunities there for you? You know, today, we feel very comfortable with where we sit. I mean, and when we talk about inventory, we're talking about long laterals with, you know, extremely high, you know, 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, you know, more acreage into drillable prospects, but it just takes time as you march through, and you've got a lot of tests along the way. But today, we're very comfortable with our inventory. You know, we know there's a lot more inherently to do there, and we will get to that and prove that as time goes on. I think when it comes to, you know, transactions and things, you've got to continue to have a very high bar. You know, we've had one. We've been very patient. You know, we saw a lot of opportunity in Callon, which is why we moved on it. But today, you know, we're very content with where we sit and believe that there will be even more to do than what we, you know, have visibility into today. Thanks. Thank you. One moment for our next question. Our next question comes from Bob Brackett of Bernstein Research. Your line is now open. 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 a FPSO from a leading contractor. That's about the most expensive long lead item I can think of. Does that tell of your conviction in an FID, or am I overreaching? Bob, I think we've been really confident we'd have a project, right? So, but we still need to get to FID. So, you know, it just tells you the seriousness and the timeline that, you know, that they're looking to accelerate. But it's... You know, they did declare commerciality earlier this year. You know, we just got a lot of work, technical work it takes to get to an FID decision. But, you know, we've said year-end, and I wouldn't change that now, but just know we're trying to accelerate that. 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 PFC, cost recover that and have a pretty good cost pool for future work. Am I thinking correctly there? I would just say when we, you know, when we talk about Sapakara, you know, it's pretty much the defined field as we have it defined today. When we talked about appraising Krabdagu, we talked about appraising a fairway and, seismically driven, right? And so, and if you go back to the comments when we announced the Krabdagu appraisal wells, we said that, not only did it confirm and appraise Krabdagu, but it obviously de-risked a lot of other prospects. So, you know, at this point, let's, you know, the next step will be a, an FID, and we need to get there. But, you know, you're, you're definitely, you know, starting to think about things, you know, directionally in the right way. ... Good, thanks. 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? I would just say we're, you know, we're excited about Alaska. The King Street discovery is, you know, it's proof of concept. It proves the play that we're chasing sits, you know, 80-90 miles, you know, east of where it's been proven. So, you know, we're in a good area. We said it was a high-quality discovery, oil, high-quality sands. So, you know, we all are anxious to get back and continue exploring in Alaska, you know, in the near future. Thanks for that. Thank you. Thank you. Our next question comes from Leo Mariani from ROTH. Your line is now open. Yeah, guys, wanted to quickly follow up here on, on Egypt. So I know you reiterated your comments from May, where you thought that gross, gross oil would be flat to slightly down in Egypt. Certainly noticed that gross oil in the second quarter was up a little bit, you know, versus the, the first quarter. Just trying to get a sense, I know that the rig count is coming down a little bit in the second half, but do you think you can maybe hold that second quarter gross oil run rate in Egypt? Or do you think it's more likely that it comes down by the end of the year with some of the, the lower rig activity? Yeah, I would just say we'll stick to what we said in the script, Leo. It clearly, second quarter, you know, second quarter was strong. Things are going well in Egypt, but at this point, we didn't see any reason to, you know, to alter our guidance. Okay, any update on the receivable situation there in Egypt that you guys can share? Yeah, I'd say I just got back from, you know, from being over there. As I said, had a good meeting with the president, got to meet, you know, some of his new cabinet. You know, things are going well in Egypt. I mean, I think if you step back and look at it, you know, President Sisi has done a really good job of managing a fairly difficult situation, so, we've been impressed with that. You know, we have been receiving some payments this year, so, you know, all in all, things are going well, and they continue to, you know, work through a difficult situation. But, you know, we see no reason to be concerned at this point and, a lot of positive things on numerous fronts. Steve? Yeah, I know. The only thing I would add to that, John, is that, you know, the new Minister of Petroleum has a set of priorities, and high on that list of priorities is to get the oil companies paid off. You know, he, we sat down and discussed all of that with him as well, and that he's serious about his list of priorities. He's one of. He's anxious to get started on this. Okay, now that's really helpful. You guys intimated in your comments that there could be some opportunities for some additional gas there. I know Egypt's 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, you know, that could be associated with a price change on some of the gas going forward? Yeah, I would just say, you know, historically, we have explored for oil in the Western Desert. And, you know, we've mainly focused on oil. We, we do produce a lot of gas. You know, we had a very large discovery in Qasr a couple of decades ago. You know, there is gas in the Western Desert, and we've had some conversations about what it would take to, you know, maybe go after some gas projects that could be helpful to the country. So it's something that, you know, we're discussing with them, but it's early and, you know, obviously, you know, you'd, you'd probably look at something that made more economic sense at a higher price for future, you know, gas exploration. But, it's, it's early, but definitely something, that could, could come into play in the future. Okay, thank you. Thank you. Our next question comes from Scott Gruber of Citigroup. Your line is now open. 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 upspacing and the completion redesign, will there be a material improvement in 30-day IPs, or will the improvement manifest more over time in the 6- and 12-month cumulatives? 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, you know, the longer-term cumulative improvement potential. Yeah, Scott, we just need to get some down, but I mean, obviously, with the changes we'd be looking at, we're pumping a lot more fluid. I think you could see increases there, but also, you know, with a little wider spacing, you should see better longer-term performance. So, you know, we just need to get some wells down and talk from, you know, delivered results at this point, so which we're getting on to and anxious to demonstrate. 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'll drop to 11 in the second half. Roughly, you know, how much will the 5-rig reduction drop Egyptian CapEx net to you? ... Yeah, I don't have that number to hand. It should be relatively proportional, but we're running 20 workover rigs, and some of that work is capital as well, and that doesn't change. So, you could probably get with Gary. He could give you some data on that. Okay. Okay, just curious. Okay, I'll follow up. Thank you. Thank you. Our next question comes from Arun Jayaram of JP Morgan Securities LLC. Your line is now open. Good morning. John and Steve, I wanted to get your thoughts on how should we start thinking about spending in 2025? You mentioned maybe a run rate of $675 per quarter, you know, heading into next year. I was wondering, as we think about some of your exploration activities in Alaska, as well as assuming an FID at Suriname, I was wondering if you could maybe help us think about, you know, maybe a placeholder for CapEx for areas outside of your base D&C program. Yeah. So, first of all, let me make sure I was clear about the $675. That was a number that, you know, there was, it was about 2024 capital spending, and that was how do you get a grip on how much are we actually spending on a run rate basis, you know, on with the current structure of the company, with Callon included as well, ex-exploration, excluding exploration activity. And so that's what the $675 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... So the point being that that was not an indication that that's what our run rate's gonna be going into 2025, just to be clear about that. I think that, you know, I think the best thing that we can do, as we normally do, is, you know, 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 a forward-looking view of where you want to be allocating capital, where the best returns are gonna be through the portfolio. So that's why we typically run our planning process starting in midsummer through the fall. We have an upcoming conversation with the board about that plan, a preview of that plan. And, you know, 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. Okay, great. Yeah, the other thing I was gonna say, Arun, if you looked at what Steve was saying on the 675, Permian's actually growing at about 8% the back half of this year. So there's a lot of room in terms of, moderating, if we choose, you know, to what is the right plan going into next year, and that's a lot of what we'll put into the decision-making process. Yeah, that-- yeah, that's a great point, John. You know, a lot of people talk about: Well, okay, what's it take 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, you know, we're down to 11 rigs because we had to create the workover capacity to get at the 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? You know, maybe, maybe not. It might be a little low, but you know, 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 you know, 9-10 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. Great. Just my follow-up, this year's, you know, financials are obviously benefiting from, you know, weak Waha prices and your ability to arbitrage that along the Gulf Coast. Steve, how do you think about maybe a more normalized earnings picture for that midstream, call it, piece, when you have Matterhorn on and maybe some other pipes? So just wanting to think about how you think about kind of the normalized earnings potential there. Well, I don't know what normalized is anymore after the last several quarters, but, you know, in general, you know, market dynamics would tell you that a balanced situation would be that differentials between Waha and Gulf Coast normalized would be that that should, over time, we're basically just making money on the Permian end 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. 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. Okay, thanks a lot. Thank you. Your next question comes from Geoff Jay of Daniel Energy Partners. Your line is now open. Hey, guys. Just wanted to get some clarification on the D&C savings you guys talked about. I mean, kind of $100 a foot per Callon 2-mile. I guess those are like $72 million of the, of the total synergy. Just wondering, kind of, you know, if you can give me any more granularity about, granularity about what's in there, and are there any service cost deflation numbers in that figure? Thanks. Yeah. So, so what we've included in the $150 million of annualized synergies excludes the benefit of lower rig rates, or frack like that. We have some integrity and, like the synergies of a trend is... 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, on steel, on rigs, on frack, and other things. What is, what is included in the $250 million, is about $60 million of annualized run rate, for, for the lower drilling costs on these wells. What that $60 million is, is basically, with, with 9-10 rigs running in the Permian Basin, that's about how many Callon wells we would drill in a given year. So that's, that's how we got to that number. We're obviously not drilling 60 wells this year, so we're not, it's not like we're gonna capture a full $60 million of, of benefit in calendar year 2024. 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. Excellent. Thanks. That's very helpful. Thank you. Our next question comes from Paul Cheng of Scotiabank. Your line is now open. Hey, guys, good morning. Just one quick good morning. Just one real quick one. Alaska. John, can you share with us that, what's the drilling plan over there? I mean, how many wells you guys going to drill, whether it's all exploration or it's going to be doing some appraisal on the King Street, and what, how much spending that, we may be talking about? Thank you. Yeah, Paul, it's early. I mean, we're working through plans with the partner. So at this point, no update on Alaska, specifically for plans, other than that, we will be doing some more drilling up there. Okay. All right. Will do. Thank you. Yeah. Thank you. This concludes the question and answer session. I would now like to turn it back to John Christmann, CEO, for closing remarks. Thank you. And to wrap up, really just a couple 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 or 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. Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.