Good day. Thank you for standing by. Welcome to the APA Corporation's First Quarter 2025 Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Ben Rodgers, Senior Vice President of Finance and Treasurer. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's First Quarter 2025 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO, John Christmann. Steve Riney, President and CFO, will then provide further color on our results and outlook. Tracey Henderson, Executive Vice President of Exploration, is also on the call and available to answer questions. We will start with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you've 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 noncontrolling interest in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. Today, I will provide an overview of our first quarter results, share an update on our cost reduction initiatives and provide details on how significant improvements in operating performance are allowing us to protect our free cash flow outlook despite the current commodity price volatility. We delivered strong first quarter results with in-line production and lower capital investment relative to guidance. In the Permian, oil production was within our guidance range despite a 1,000 barrel per day larger impact from third-party and weather-related downtime that was anticipated when we gave guidance. Capital came in below guidance largely due to significant improvements in drilling performance. In Egypt, we are highly encouraged by the prospectivity for natural gas. First quarter gas production exceeded guidance due to outperformance from our recent development program, along with continued efforts to optimize existing infrastructure. Despite shifting activity to gas, oil drilling is progressing well, and we continue to see positive results from our waterflood implementation programs, where we see additional running room with very favorable returns. In the North Sea, volumes were ahead of guidance, primarily driven by strong operational efficiency at Beryl. On the exploration front, we announced our second discovery, Sockeye-2, in the Brookian Play across our 325,000-acre footprint. The King Street-1 discovery in 2024 initially confirmed a working hydrocarbon system approximately 90 miles east of the Pikka development with high-quality pay in two separate hydrocarbon zones. Earlier this year, the Sockeye-2 well encountered 25 feet of net oil pay with an API oil gravity of approximately 28 degrees and a GOR of 720 across one consistent sand package, with seismic amplitude supporting the stratigraphic feature across 25,000 to 30,000 acres. We subsequently conducted a flow test that confirmed anticipated rock properties much better than regional…

Thank you, John. I will begin my remarks with an overview of our first quarter results and then provide further commentary on our cost reduction initiatives and our updated plans for the rest of this year. For the first quarter, under generally accepted accounting principles, APA reported consolidated net income of $347 million or $0.96 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $111 million after-tax gain on the extinguishment of debt and a $76 million charge to increase our deferred tax liability in the UK due to the most recent increase in the energy profits levy. Excluding these and other smaller items, adjusted net income for the first quarter was $385 million or $1.06 per share. Let me start my comments on first quarter highlights with a couple of items from Egypt. I want to specifically recognize the significant progress that the Egyptian government has made towards normalizing our past due receivables. APA generated $126 million of free cash flow in the first quarter, but this does not include the progress we made on past due balances during the quarter, and that progress has now continued into the second quarter. Today, our past due balances in Egypt are the lowest they have been since the end of 2022. Also in Egypt, gas development is going very well, and increasing production volumes have led to an average realized gas price of $3.19 in the quarter, exceeding our guidance of $3.15. This is up from our fourth quarter average of $2.97. The combined benefit of substantial recent progress on payments and the new gas pricing agreement have been critical factors in a decision to maintain our planned activity levels in Egypt, albeit with a shift to…

[Operator Instructions] Our first question will be coming from John Freeman of Raymond James. John, your line is open.

Thanks. I wanted to dig in a little bit more to the cost savings that you all achieved already on the controllable spend. So the original guide that you all gave last quarter of getting down that $3.7 billion or $350 million run rate savings by the year-end '27. Given the fact that you've basically doubled what you thought you were going to achieve this year, do we just think of it as that original sort of time line you all showed last quarter, it just got pulled forward, but you're not necessarily increasing the absolute target, like the $350 million run rate savings by year-end '27 is being achieved quicker, but is there any thought of that number potentially moving higher?

Yes, John, you're exactly right. I mean at this point, we're way ahead of schedule. Obviously, now we've gone from 125 at year-end on a run rate basis to 225. So we're well on our way. I do anticipate that number will get raised at a later date. But today, that's -- we're going to leave that intact and keep working our away. The other thing of note is, if you look at in-year savings, we've gone from $60 million in-year to now $130 million in-year. So we're making really, really good progress. And I do anticipate at some point in the future, you'll see that 350 number go up. But today, we're going to leave it intact.

Understood. And then my follow-up question, in the Permian, where you've talked about being able to now go from what used to be eight rigs needed to hold US production flat, you can now do with six rigs -- I'm sorry, with 6.5 rigs. Would you all plan to go down to six rigs is -- do I think of it as that's slightly left in all -- you basically can't hold production flat at that level? Or do you think that at some point later this year, you're going to have additional efficiency gains and that 6.5 now becomes six to hold production flat? Just a little more color on that.

Yeah. That's exactly where we are. We came into the year with eight rigs. Today, we think we can hold the 125,000 to 127,000 barrels a day in the Permian flat with 6.5, but we're seeing signs of further efficiencies, which is why we're confident we can go ahead and drop two rigs and on down to six, which we believe we will hold it flat. And quite frankly, we think can do so well into 2026.

That's great. Thanks, John. Appreciate it.

Thank you.

And our next question will be coming from Doug Leggate of Wolfe Research. Your line is open, Doug.

Thank you guys. Sorry, John, to pound on this topic, the other John just asked about. But I'm just wondering, when we think about the pace of cost delivery that you're now -- especially the capital side of it. What had you originally assumed when gave us the 350 in terms of rig cadence? I guess, the $800,000 per well that you talked about, I mean, were those in your original 350 numbers, or is this a moving target? I'm trying to get a feel for who you're not willing to give us a new number today. What was embedded in that original target versus what you've done so far as quickly as you've done it?

Yeah. I mean I'd say we set aggressive targets, the 125 that we plan to capture by year-end, we set some aggressive targets, and you saw that in the LOE numbers. Obviously, the overhead was a piece. We said the capital was the biggest piece, but we thought that would come later and it's coming earlier. So we knew we could drive cost down. So I would say those savings were in that 350. But they're just coming faster. And we think there's more to do.

Okay. So my follow-up is, I wanted to take advantage of Tracey being on the call and ask her a question about Alaska. I know it's very early days, but you've got a couple of wells now that -- they're fairly well apart and some pretty good analogs if you look at Pikka flow rates from [indiscernible], when it was eventually tested, those wells, as I understand were fractured, yours was not. So can you offer any insight as to what you're thinking in terms of resource size? And if I can add a Part B, this is a bit of an obtuse one. I think there's a concern that, okay, here we go, we've got another major capital development that Apache has 50% of. How would you plan on funding it? Would you ever consider monetizing part of Suriname to fund Alaska?

Well, Doug, if you step back, we've got a 300, and I'll let Tracey chime in, in a couple of minutes, but we've got 325,000 acres estate lands. With the King Street discovery last year, it did two things. It proved we had high-quality reservoir sands, 90 miles east of Pikka. We went back to Sockeye this year, because we had the best seismic image over there. It is not the largest feature by any means, but it was the one we felt pretty confident would test geologic, geophysical model and as well as the whole acreage position. Obviously, it came in, but I'd say the surprise in there was the quality of the reservoir sands, which are actually better than expected. So it's a material discovery. It's high-quality oil, low GOR, 720, but it's one continuous package of sand, 20% porosity. But the big kicker in here is the permeability. It was 100 to 125 millidarcies, which is quite a bit better than the developments that are taking place. I think the thing you look at now, a big portion of our acreage -- we are in the process of reprocessing that seismic. And quite frankly, the largest prospect sits on the area we are reprocessing. So we're not going to be going at this hard on the capital side. We're going to be really smart about how we appraise and quite frankly, what we would drill next on the exploration side. But if you look at timing on your second Part B question, you look at timing on Suriname. You're going to have Suriname coming on well before you'd have meaningful capital spend here. So Tracey, you can jump in on the reservoir quality a little bit more about it geologically.

Sure, John. Thanks. One of the things we're most encouraged by really is the reservoir quality, as John mentioned, and where we know we have something to work with. Our permeabilities are easily two times to four times better than analog fields to the west. And that's critical for how we go about developing fields. So our focus right now is on reprocessing the data, as John said, but also developing an appraisal strategy, which will include things like number of wells, development scenarios. You saw in the press release, the well flowed 2,700 barrels a day un-stimulated, and that was limited by tubulars. So we'll be looking at things like potential for waterflood, which is a possibility given the reservoir quality that we have, horizontal wells. Those will all be things that we need to think about and what development scenarios will look like. So we've got a lot to do to frame the path forward. And the appraisal program will be what will ultimately inform how we -- what we will come out with in terms of size of the resource here. And so we've got a lot of work to do, but we are very excited. One of the limiting factors that we have really is winter access, so we really need to be measured in how we plan our activities. And the work we're going to be focused on in the near term is going to be seismic reprocessing and looking at appraisal strategies. And we need to do that work, so we understand how we want to appraise and look at development scenarios going forward.

I'll give everyone a giggle here when I would think your partner, Bill Armstrong, has described the overlooked areas on the -- that booking plays the next Guyana. So we're watching with a lot of interest. We'll see. Anyway, thanks very much indeed guys. I appreciate the answers.

Thank you, Doug.

Thank you. And our next question will be coming from Scott Gruber of Citigroup. Your line is open, Scott.

Yes. Good morning. I wanted to come back to the asset sale. As part of the motivation to sell the New Mexico position beyond the non-op aspect, there's been -- part of the motivation there where you're seeing across the rest of the Permian portfolio, it's been about a year since the Callon closed, you altered the development program there. So is that acreage surprising of the positive? Or are the drilling efficiencies making legacy acreage even more attractive? Maybe it's both? Just some color there.

Yes. If you step back on the New Mexico assets, what we had remaining in Mexico is good rock, but it's very small. It's less than 5% of our production. It's less than 5% of -- our acreage is scattered. Some of it was non-op for us. It was a package that we didn't have to sell, but we put in the market. It was highly contested. And so a lot of interest, and quite frankly, we felt like because of the price, it made sense to transact. We feel like we got full price. Obviously, Permian Resources is happy with it as well, but we think it's a good transaction especially for us, and the proceeds are going to predominantly go to debt paydown. Ben, anything you want to add?

Yes. I'll just say we -- outside of the strategic reasons for getting out of New Mexico, you think about value here, and as John said, a very competitive process. And when you look at it a bunch of different valuation ways to look at it, but kind of in the mid- to high 5s on an EBITDA multiple, really good value for us. We'll use the proceeds to pay down debt and focus on the Texas side of the basin.

Yes. I'd just add to that, that this is an area that really got sparing capital allocated to it for the last several years. And it's one that just didn't compete with the core other Permian Basin assets that we have in the Delaware and in the Southern Midland Basin for capital.

Yes. So I was curious whether the rest of the portfolio is getting better. And maybe turning to the LOE side of things. You mentioned the need to take some longer-term initiatives to address some of the inflation there in compression and water. Just some more color on those initiatives, whether there's CapEx associated and what kind of time line should we think about to see the benefit?

Yes. If I could just maybe step back a bit on Permian LOE. We -- coming into the year, we set a plan that perhaps was a bit ambitious with some embedded savings already built into it. And those are materializing a little bit slower than we had hoped. And -- in addition to that, as I mentioned in my prepared remarks, we are seeing some inflationary pressures, too, and compression costs and water disposal in particular, ones where we're seeing those. And so we're going to get there on LOE in the Permian. It might take a little bit longer. We're looking at all options that -- some might involve some capital investment, some probably did not. Some of them might be just commercial negotiations and getting after the embedded cost structure, both in our assets historical and in the Callon assets as well. But we certainly believe at this point, just like G&A and the CapEx, it's going to be -- LOE is going to be a meaningful part of the $350 million of cost savings that we've targeted for the next three years. We're just going to take a little bit more time to get there. We'll be getting there later this year and into 2026.

Got it. Appreciate the color. Thank you.

Thank you.

One moment for our next question. Our next question will be coming from Arun Jayaram of JPMorgan Securities. Your line is open.

Yes. Good morning. I wanted to go through your plans to kind of evolve or migrate your completion design in the Permian. I know when you guys announced the Callon merger, John, Steve, one of the first steps that you did was to maybe relax spacing in your DSUs. So I wanted to see if you could elaborate on maybe the decision to move to tighter spacing. Is this in the Delaware? And maybe just give us some thoughts around that decision?

I think, Arun, it's just overall in the basin. I mean we did relax spacing with the wider spacing and larger fracs on the Callon side. I would say over time, though, as we look in areas, we're starting to move more a little tighter spacing with smaller fracs and areas. So I think it's more of the of the evolution basin. And as we look at it today, a lot of the areas where we're focusing our capital, we are drilling on tighter spacing than what we have historically. And with the well cost coming down and smaller fracs, we can more efficiently develop the resource. But I'll let Steve jump in on a few points as well.

Yes. This is the type of thing that comes up every time we get questions associated with our Permian inventory. And we haven't come to the market for quite some time with a transparent view and a thorough view of our inventory in the Permian, and we are working on that. We've talked about that in the past. We're deep in the process of characterizing everything that we've gotten with the Callon acquisition. We're also characterizing some remaining legacy Apache inventory that we haven't gotten to yet. And all of that inventory, the quantum of inventory is increasing with what we're planning to do on the density side. And that is actually turning out now to be a bit of shooting at a moving target on the density side because every time we get cost reductions, it naturally will increase the density, the economic density of drilling in the Permian. And every time you increase the density of the wells, you're increasing not just the well count in the in the drilling unit, but also the EUR drilling unit. And so the more you drive down costs, what we've achieved on the $800,000 per well in the first quarter of this year, the more you do that, the more you're going back and saying, well, this further increases the density possibility of drilling in the Permian. And that's what we're looking at. And we will -- what we've said in the past and we will do this, we will come out probably later this year or early next year with a more thorough view of all of our inventory. But just recognize for everybody is that -- that is a moving target as you drive costs down, things that were uneconomic or marginally economic before become economic in that process.

Great. I know investors would welcome that type of analysis, Steve, so look forward to that. Maybe one for Ben. It looks like the proceeds from the New Mexico asset sale will be targeted towards debt reduction. So maybe looking for some color, Ben, how you think about repurchasing debt? I think some of your debt is trading at 25% discount to par. But you obviously have some other items such as repaying the term loan or taking out debt as it matures. So where is your head at in terms of using asset sales proceeds in terms of the debt stack?

Sure. No. So we paid off Callon term loan in the first quarter with a mix of cash we had on hand and some revolver borrowings. So the revolver balance that you see at the end of the quarter, which was a mix of revolver borrowings and commercial paper was a result of fully paying off the Callon term loans. So that's good, had some interest expense savings on that. When we look really for the rest of the year and through our maturity profile through 2030, that's where a lot of our focus is going to be. We do recognize that there's some debt that's trading below par, and that's inclusive of that time period, even between now and end of 2030. And so we'll with -- pay down the revolver and have a bunch of liquidity, we've got a lot of different options that we can look at. We think of it in a lot of different ways. One way is on a yield basis. So to your point, with those bonds trading below par, that yield is higher than the cost of us to borrow on the revolver. So we'll be opportunistic as we go through the year and have a lot of tools because of the liquidity pickup from paying down the revolver.

Great. Thanks a lot.

And our next question will be coming from Betty Jiang of Barclays. Your line is open, Betty.

Hi, good morning. Thank you for taking my question. I think it will be really helpful to get some color reconciling, back on the cost optimization, the $130 million average saving for the year to the $225 million run rate expected for year-end 2025. What's driving that increase in run rate over the course of the year? So specifically, I'm wondering, if you're already seeing a $0.8 million saving on the Permian well cost to date, are you assuming that's going to double from here?

Yeah. So good question, Betty. We increased the 60 realized this year by $70 million to capture $130 million. To get to the run rate to the $225 million, that's just expecting that as we get into 2026, a lot of the capital savings that we have by running just six rigs and additional progress we'll make on overhead. And then to Steve's point, on the LOE side, we'll make some progress on LOE this year, but really expect a lot of that to come in 2026 and 2027. And so that's what's implied in that run rate of $225 million is that a continued acceleration of capturing those cost savings, again, by reduced activity in the Permian while still holding production flat and then continuing to capture savings with overhead and pickup in LOE.

The $800,000 of savings per well is delivering the majority of that increase to $225,000 run rate at the end of the year.

And the other factor is -- back half of the year, anything we capture now will be full year for 2026. And so the captured in year number now going from 60 to 130, you're actually at a higher run rate on an annualized basis going forward. And so it's really what's captured inside this year versus what the run rate on the overall program will be going into next year.

Got it. That's helpful. It seems like it's more driven by the overhead and LOE. Maybe my follow-up is just on the LOE front. Could you give some specific example on what you're expecting to see on the LOE side to offset the inflationary pressure that you have seen to date?

Yeah, there are going to be a lot of things that we're going to be looking at, everywhere from the basic day-to-day route optimizations of pumpers, all the way to the contracting of produced water disposal and compression we have contracts for things like that that come due throughout the year and throughout the years. And every time one of those comes available, you have the opportunity to renegotiate. So a lot of this stuff is going to be internally focused on how we work, work operating practices, how we work out in the field, how we manage day-to-day activity and then other aspects of it will be externally focused negotiating with vendors, everything from chemicals to all other forms of services.

Great. Appreciate the color.

Thank you. And our next question will be coming from Paul Cheng of Scotiabank. Your line is open, Paul.

Hey, guys. Good morning.

Good morning, Paul.

John, wondering that, I mean, you're saying that why now in Egypt, the gas development is actually very attractive or comparable to the oil. And so should we assume that you have oil price line further from here that you will be making -- you're going to shift more of the rig the gas? On the other hand, your oil price rise above the current level, you're going to ship back more into oil? And also that for Alpine High, what kind of gas/oil ratio will make you saying that -- I mean, now that we will be able to move some of the capital back to Alpine High? That's the first question.

Paul, I mean, if you look at Egypt, we came into the year running one rig. Obviously, we've been ratcheting that up as Brent crude oil has softened. So it puts us in a nice position. And we've also had capacity in the infrastructure to be able to add shift. And as we said, we should see volumes north of 500 by year-end. So it does give us optionality in Egypt, but you have to work kind of within the constraints of what we have in terms of facilities and inventory. And the oil still works nicely because of the cost recovery mechanisms in the PSC in Egypt. But those are at par kind of a mid-cycle Brent prices. So with crude softening, definitely a tilt to the gas side in Egypt. And I'll let Steve comment on the US gas.

Well, and I would just add on Egypt. On the oil side, there's been some concern expressed that while shifting more towards gas means less oil production, actually, most of the gas in the Western Desert of Egypt is very rich gas and comes with a lot of condensate. So we've been on what we've called a slight decline in oil -- gross oil volumes in Egypt and between the condensate that's coming with the gas program and also the improvements coming from waterflood programs in stemming base decline, I would still characterize oil volume decline as being on a very slight decline. And it's on the -- as we look at the outlook for gross oil volume in Egypt, I would say it's on the slightest of declines as we go through second through fourth quarters.

Steve, on Alpine High, can I ask that on -- in Egypt, I think for oil, you sort of like need to workover rig for one drilling rig. In the gas side, is this still a similar ratio? Or that -- yes, I'm less? Because I think part of the issue last year or the last couple of years is that you don't have -- you can't find enough of the workover rig there for you to increase the drilling rate?

Yes. We're still running a similar number of workover rigs today as we were before. But you got to remember on the gas side, part of the gas comes from [indiscernible], and part of it is associated gas with the oil wells -- oil production. And all of this incremental new gas that's coming on, I certainly hope we're not going to be spending a lot of time and effort and money on workovers on those wells. These are brand-new wells, should be producing for quite some time. And typically, maintenance on gas wells tends to be a little less intensive than on oil wells. On Alpine High, Alpine High is -- obviously a lot of gas there and very economic gas at certain types of prices. But we run economics on Alpine High and decide whether we're going to drill there or not based on Waha pricing because the transport activity is completely separate from that, and we purchase gas and sell it on the Gulf Coast. And so the money that we make on the gas trading, what we call gas trading, is completely independent of Alpine High. Alpine High has to stand economically, and drilling in Alpine High has to stand economically on Waha pricing and a perceived forward view of Waha pricing. Obviously, with pipelines being built, the occasional pipeline maintenance shutdown, things like that, Waha is still extremely volatile right now. And we've seen -- even this year, we've seen Waha pricing to a point where we have actually curtailed volumes, and we thought that that would not be the case coming into this year. With all of that, when we're at a position where we believe Waha pricing is adequate to support economic drilling in Alpine High that is as good or better than drilling for oil in the Permian Basin, then we'll shift the rig from oil-focused drilling to gas-focused drilling, or we'll add another rig for Alpine High, one or the other.

I see. A final -- a second one, hopefully, real quick. John, at what oil price that you would say the [indiscernible] is here or we are in the red mine and so you would take a more drastic cut in the capital program as well as allow the oil production to drop from -- trying to hold it flat? Is there a number that you have in mind?

Obviously, we'll keep an eye on things, and we've set ourselves up when we're positioned if need be to respond. But I think you'd have to see WTI get down into the very low 50s at this point. And obviously, the first step would likely be dropping a couple of rigs in the Permian and a frac crew. Maybe in Egypt, but we're -- we'll watch things, and we're in a really, really good place right now. And quite frankly, with the activity set that's running and the progress we're making on the cost structure, that number is going lower every day.

Great. Thank you.

And our next question comes from Leo Mariani of ROTH. Your line is open Leo.

Hi. I wanted to just touch base on the buyback here. Obviously, oil prices have softened quite a bit. You did significant buyback, $100 million or so in the first quarter. Just kind of at that $60 level, do you guys see the buyback being a little bit more limited with more focus on debt paydown? You obviously elected to sell an asset in this market. It seemed like you certainly wanted to deliver on some debt paydown goals this year in light of the weaker macro. So can you just talk about how the buyback kind of plays into your thinking at this oil price or even a little lower?

Yes, I'll let Ben jump in just a second. But in general, Leo, we sold the asset because we were opportunistic on the price. I mean it wasn't something that we felt like we had to do, but we put it in the market and got numbers that we thought were fantastic, and so we transacted. We're in the process of transacting. It does let us take the revolver down, and Ben can talk about those, but I think it puts us in a position where we can also still be very opportunistic if -- on the buyback if need be.

Yes, just a quick follow-up. We set the 60% return to shareholders within our framework. We've exceeded that every year. And so -- as we go through the year, as John said, we'll have -- we'll be opportunistic around that. And with our zero revolver balance, we'll look at both the debt side and being opportunistic on the equity side as well.

Okay. I just wanted to follow up a little bit on Egypt oil volumes. Steve, you basically said it's going to be a very, very slight decline there on gross oil volumes, if I heard you right. Certainly, just looking at first quarter, they were down, I would say, a little bit more than kind of slight decline. Maybe there were some timing issues or sort of an anomaly there. But I'm just trying to kind of get a sense, should those gross volumes continue to decline off of 1Q levels? Or is there maybe something anomalous there in 1Q?

There was a bit of unexpected downtime in 1Q, but I think that you can expect continued slight decline through the quarters on gross oil.

Thank you.

And our next question will be coming from Oliver Huang of TPH & Company. Oliver, your line is open.

Good morning, John and team. And thanks for taking the questions.

Hi, Oliver.

For my first question, I just wanted to ask about breakevens. As we think about the revised program with some of the cost outs from the savings initiatives you all have accelerated, what sort of oil price are you all now looking at in terms of covering your CapEx and base dividend with internally generated free cash flow?

Yes. Oliver, if you look at where we sit today and when you factor in the savings we've got planned at the 350 annual run rate, we can fund Ceron, the exploration program, the DCOM, run 6 rigs in the rigs in the Permian, 12 Egypt and still pay dividend at $50 WTI with very reasonable assumptions on the marketing side. So making really, really good progress. And those are -- we're funding some programs that actually are going to provide longer-term growth.

Makes sense. Thanks for that response. And I just had a follow-up question to Arun's earlier question. Just really trying to better understand the progression of the denser well space -- well spacings you all talked about in the prepared remarks. I understand there are many variables, as Steve mentioned earlier, with shooting at a moving target analog. But just -- is there any way to quantify how this is transitioning from, say, 2024 to 2025 and how this might look going forward into 2026 or if there's a better way just kind of understand what percentage of the program this year is seeing that denser spacing design?

Yes. I mean, if you look today, a great percentage of it is. And part of it is we did a lot of work last year, and then we prepurchased a lot of our tubulars and materials and things. And we're running with slimmer casing. And so you've got to set these programs up and let them run a little bit, but we're -- it moved a lot of the program in a lot of the areas we're drilling, and seeing really, really good results. And so we'll continue to tweak that. But it's a dynamic process, and we're going to continue to look to optimize as we go forward. But a greater percentage, especially in the areas where we're focused right now, you're seeing a little tighter spacing than what we've done historically and also some smaller fracs.

Perfect. Thanks for the time guys.

And I'm showing -- and I'm showing no further questions at this time. I would now like to turn the call back to John Christmann, CEO, for closing remarks.

Yes. Thank you. In closing, let me leave you with the following thoughts. We are making significant strides in drilling efficiencies in the Permian, and we are on track to deliver our full year production volumes at a lower capital budget. We have reduced average well cost by $800,000 per well from the 2024 levels, and this is on top of the $1 million savings we had achieved on the Callon properties. And we believe these cost savings to be structural and sustainable. In Egypt, we are very encouraged with strong performance from the gas program, where we are shifting an increasing proportion of the activity for this year. We have visibility to increasing average gas realizations in line with this outlook, with fourth quarter expected to average $3.80 per Mcf. Finally, our overhead cost reductions are proceeding ahead of schedule, and we are well on the way to delivering our targets for 2025 and beyond. This will sustainably improve our cost structure and long-term free cash flow generation. With that, I will turn the call back to the operator.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.