APA Corporation (APA) — Q1 2025 Earnings Call Transcript

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 than 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 analogs, including an average permeability of 100 to 125 millidarcies and a 20% porosity. Technical evaluation is underway to determine next steps for both the exploration and appraisal programs. I will turn now to our cost reduction initiatives, where we are making significant strides. Commensurate with our simplified portfolio, we are committed to sustainably reducing our controllable spend across capital, LOE, and overhead. Our overall progress on these initiatives has been impressive, giving us the confidence to increase both our 2025 targets for realized savings to $130 million and the annualized run rate savings by the end of the year to $225 million. Of note, capital efficiencies are being captured much faster than we expected. Permian drilling efficiencies are the largest driver of capital savings. We are also making good progress on both completions and facilities. Overall, our objective is to achieve top quartile operational performance in the Permian, and we are confident we're on track to deliver that. In Egypt, we are also seeing savings in drilling costs driven by continued refinement of our operating practices. Moving to LOE. In the Permian, while we continue pursuing near-term opportunities to reduce certain operating costs, we are experiencing upward pressure on other cost areas in the short term. Material savings will come from structural changes to how we operate, including items such as water handling, compression, and power procurement. We see opportunities for substantial long-term reductions in these costs, but achieving them will require extended execution timeframes. On the international front, we have lowered Egypt operating costs through efforts like accelerating diesel reduction projects and optimizing equipment rentals, and in the North Sea, rationalized offshore activity as we transition to late life operations. On the G&A front, we are accelerating the capture of cost reductions, which is also contributing to our increased savings targets for 2025. These savings not only come from streamlining our organization, but are also realized in multiple areas of discretionary third-party spend. This momentum is expected to continue through the year and is proving to be sustainable as we simplify how we manage our assets. As we continue to right-size our organizational structure and work processes to better align with our current portfolio, we're further refining our operating model and leadership structure. Among other things, I would like to personally congratulate Ben Rodgers on being named Chief Financial Officer, effective next week. Many of you on the call have had the opportunity to interact with Ben over the past few years, and I am eager to work more closely with him as the new head of our finance pillar with a continued focus on managing our cost structure. In the same spirit, I would like to thank Steve and acknowledge his invaluable contributions and thought leadership over financial and strategic matters through the years. I look forward to his continued contributions as he brings the same rigor and focus to our operations and development organizations, where his impact has already made a difference since his promotion to President last year. Before discussing our updated 2025 outlook, let me comment on the asset sale we announced in our press release yesterday. Subsequent to the first quarter, we signed an agreement to monetize our New Mexico Permian properties for $608 million. These assets, which contributed approximately 5,000 barrels per day of oil production during the first quarter, represent less than 5% of both our Permian oil production and unconventional acreage position. We intend to allocate most of the proceeds from this divestiture toward debt reduction. This sale fits with the continued streamlining of our portfolio and reflects a full exit from New Mexico, allowing us to focus solely on the Texas side of the basin. The transaction is expected to close late in the second quarter. In keeping with prior practice, our forward guidance at this time continues to include these assets and will be adjusted post-close. Turning now to our revised outlook for the remainder of the year. Let me start by emphasizing the rapidly improving drilling efficiency we are seeing in the Permian. As we progress the integration of Callon, we have reduced activity to eight drilling rigs late last year to sustain flat oil volumes in the Permian. Given the confidence in operating efficiency gains, we can now hold oil volumes sustainably flat beyond 2025 with 6.5 rigs. Anticipating continual efficiency improvements, we are in the process of reducing to 6 rigs by the end of this quarter, and will reduce activity further if oil prices continue to deteriorate. We are also adjusting our frac fleets and completion schedule to better align with the lower rig count going forward. This will result in several wells for 2025 being turned in line later than originally planned, but we still expect to deliver oil volumes within our guidance range of 125,000 to 127,000 barrels per day. The combination of changes in completion timing and significant capital efficiency gains in the Permian is driving the bulk of our $150 million reduction in development capital guidance for the year. In Egypt, with the success of the gas program and the softness of oil prices, we have shifted rig activity to be approximately one-third gas focused. Our second quarter guidance contemplates continued growth to 470 million cubic feet per day gross gas volumes, and we anticipate ongoing strong performance in the second half of the year. Commensurate with this outlook, we expect our average realized gas price to continue to increase through the fourth quarter and into next year. This highlights how Egypt enhances the diversity of our portfolio and our capital allocation optionality. The new gas price agreement has brought gas-focused development into economic parity with oil drilling at mid-cycle Brent prices, making gas opportunities at today's oil strip more attractive on a relative basis. In addition, the production sharing contract in Egypt provides downside protection through the cost recovery mechanism, a natural hedge against lower Brent oil pricing. In closing, we are making substantial progress on our cost initiatives, particularly in Permian well costs and our overhead cost structure. This has allowed us to more than double our controllable spend savings targets for the year and reduce the capital intensity required to sustain longer-term production volumes. Together, these protect free cash flow in a volatile oil price environment. We will continue to balance the goals of sustaining and growing our business with returns to shareholders and further balance sheet strengthening. Our focus on cost reductions and capital efficiency for the near term will underpin free cash flow through 2027, ahead of Suriname first oil in 2028, which will significantly accelerate further growth. We believe that the resulting free cash flow growth profile, coupled with our high-quality exploration portfolio, is differentiated from many of our peers and will drive growth in long-term shareholder value.

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 latest 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 more gas-focused drilling. First quarter upstream capital came in quite a bit below guidance despite some accelerated spending in Suriname. This was a direct result of the outstanding operational results delivered by our Permian drilling teams, where drilling efficiencies have seen step change improvements compared to 2024. Let me now turn to progress on our cost reduction efforts. As a reminder, our efforts to rationalize our cost structure began almost a year ago, with a primary objective to drive sustainable cost savings for the long term. When we spoke about these initiatives on the February earnings call, we did not provide a breakdown of targeted savings between the various cost categories. We knew that overhead would be the largest initial contributor because that was the logical first target. However, we expected capital would be the largest contributor in the long term. Given the progress achieved through Permian drilling efficiencies, savings on capital will now provide the vast majority of our controllable spend reductions this year. Since the beginning of the year, we have captured an impressive $800,000 in cost savings per well in the Permian, and we still see additional room for improvement going forward. We have made significant improvements, including slim hole drilling, modifying casing stream designs, and utilizing fit-for-purpose directional tools that have considerably shortened our drilling durations. Looking ahead to the rest of the year, we see additional improvements that are expected to drive further momentum into 2026. Completions and facilities costs also represent large reduction opportunities for us, and we are beginning to see progress. As we continue to optimize economic resource recovery, several development patterns will shift toward a combination of denser well spacing per DSU with smaller fracs, leading to additional drilling cost savings due to fewer rig moves, as well as lower completion costs due to the smaller frac loading. On the facility side, through 2023 and 2024 and into 2025, we built a number of new facilities in areas where drilling activity was going to be growing. For the remainder of this year and into 2026, we will be much more dependent on brownfield modifications instead of new builds, resulting in additional capital savings relative to the recent past. On LOE, as John mentioned, our original targets contemplated an aggregate level of cost reduction that is proving challenging to achieve. While we are making good progress in some areas, we are also seeing some underlying pressure in others. This includes items like compression and water disposal, where we have experienced some inflationary pressures. As a result, we expect more meaningful progress on LOE savings will likely come later this year and beyond. Finally, on overhead costs, while our initial focus centered primarily on headcount rationalization, we are now also looking to streamline some of our more complex workflows. In particular, we are eliminating lower-value activities, standardizing and simplifying routine work processes, expanding the use of more efficient technologies, and broadening leadership spans of control. While some of these efforts will take more time to implement, we are progressing faster than previously anticipated, which is also contributing to our increased 2025 savings targets. Moving now to our outlook for this year. John touched on a number of topics related to our forward outlook, so I will comment on a few other items. The progress we have made on reducing controllable spending capital and overhead more than doubles our expected realized cost savings in 2025 despite increases in LOE. We've updated our guidance to reflect these changes while purposefully segregating activity reductions, deferrals, and other items, excluding them from our accounting for savings on controllable spend. While these types of items will support free cash flow in 2025, we want to clearly distinguish sustainable reductions from timing-related differences for the year. Please refer to our supplement for further details. In Egypt, with over a third of this year's activity geared towards gas, we expect gross gas volumes to continue growing from first quarter levels. Despite some planned downtime due to plant maintenance, we expect gross gas volumes in the fourth quarter to be the highest of the year, and we anticipate exiting the year around 500 million cubic feet per day. Gas price realizations will steadily increase in line with this trajectory from approximately $3.40 in the second quarter to $3.80 in the fourth quarter, putting us at the upper end of our prior guidance of $3.40 to $3.50 per Mcf for the full year. Turning now to US gas marketing, a part of our business that has proven particularly profitable for us over the last few years. As a reminder, APA sells all Permian gas production in-basin and holds approximately 750 million Btus a day of firm capacity on various gas pipelines. Every day, we buy gas at Waha and transport that gas to the Gulf Coast, where it is sold at various price points. Based on current Waha differentials, this is a very profitable activity. Income generated from our firm capacity contracts, along with our LNG sales contract with Cheniere, is reflected in our guidance and financials as purchased oil and gas sales and costs. APA has entered into basis swap agreements for the second through fourth quarters of 2025 on roughly two-thirds of our firm transport capacity. Including actual profits in the first quarter, this locked in approximately $450 million of income for the year. Our 2025 guidance for income from third-party oil and gas marketing has been updated to $575 million, inclusive of these basis hedges. Lastly, I would like to quickly touch on some changes we have made to our upstream capital and free cash flow definitions around the treatment of ARO and leasehold acquisitions. Previously, cash ARO expense and leasehold acquisitions were included in our definition of upstream capital. Starting in 2025, we have removed both ARO and leasehold from upstream capital and are now including these as individual line items in our reconciliation to free cash flow. Note that these changes have no impact on how we report free cash flow, and we have provided the new definitions, along with a reconciliation of the changes in our supplement. Please reach out to our IR team if you require any clarification. And with that, I will turn the call over to the operator for Q&A.

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 timeline 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 way. 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. For my follow-up question regarding the Permian, you've mentioned that you can now maintain US production with 6.5 rigs instead of the previous eight. Are you planning to reduce the number of rigs to six, which might mean you can't hold production flat at that level? Or do you anticipate achieving further efficiency improvements later this year so that 6.5 rigs could become sufficient to maintain production? I would appreciate some additional clarification 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.

Thank you. I apologize, John, for pressing further on this topic that the other John just mentioned. I'm curious about the pace of cost delivery, especially on the capital side. What were your initial assumptions regarding rig cadence when you provided the 350 estimate? Regarding the $800,000 per well figure you mentioned, was that part of your original 350 estimates, or is that something that has changed? I’m trying to understand what was included in that initial target compared to what you have achieved so far.

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.

I wanted to take the opportunity to ask Tracey a question about Alaska. Although it's still early, you've got a couple of wells that are quite distant from each other, and there are some strong analogs if you consider the flow rates from the Pikka wells. Can you provide any insight into your thoughts regarding the resource size? Additionally, there seems to be a concern about another major capital development where Apache has a 50% stake. How do you plan to fund it? Would you ever think about monetizing part of Suriname to finance the Alaska project?

If you take a step back, we have a 325,000-acre estate. The King Street discovery last year achieved two things. It confirmed that we have high-quality reservoir sands located 90 miles east of Pikka. We returned to Sockeye this year because we obtained the best seismic image there. While it's not the largest feature, we felt confident it would test both the geological and geophysical models as well as the entire acreage. It proved successful, and the surprising factor was the quality of the reservoir sands, which exceeded our expectations. It's a significant discovery with high-quality oil and a low gas-to-oil ratio of 720. The sand forms one continuous package with a porosity of 20%. The standout factor is the permeability, which ranged from 100 to 125 millidarcies, significantly better than ongoing developments. A significant portion of our acreage is currently being reprocessed for seismic data, and notably, the largest prospect is in this area. Therefore, we won't aggressively pursue capital spending; instead, we will be strategic in our appraisal and exploration drilling. Regarding your second question about timing, Suriname will come online well before we see any substantial capital expenditure in Alaska.

Sure, John. Thanks. One of the things we're most encouraged by is the reservoir quality, as John mentioned, and we know we have something to work with. Our permeabilities are easily two to four times better than similar fields to the west, which is critical for our field development. Right now, our focus is on reprocessing the data, as John said, and developing an appraisal strategy that will include factors like the number of wells and different development scenarios. In the press release, you saw that the well flowed 2,700 barrels a day un-stimulated, and that was limited by tubulars. We'll be exploring options such as the potential for a waterflood, given the quality of the reservoir, and horizontal wells. These are all considerations we need to make regarding our development scenarios. There is a lot of work ahead to define our future path. The appraisal program will ultimately inform us about the resource size here, so we have plenty to accomplish, but we are very excited. One limitation we face is winter access, meaning we need to be strategic in planning our activities. Our near-term focus will be on seismic reprocessing and developing appraisal strategies to understand how we want to approach development going forward.

I'll give everyone a giggle here when I would think your partner, Bill Armstrong, has described the overlooked areas on 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.

Yes, good morning. I wanted to revisit the asset sale. One of the reasons for selling the New Mexico position, in addition to its non-operational nature, is related to the other parts of the Permian portfolio. It's been about a year since Callon made changes to its development program. Is the performance of that acreage unexpectedly positive? Or are the drilling efficiencies making older acreage more appealing? Perhaps it's a combination of both? I'd appreciate your thoughts on this.

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, the buyer 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. Outside of the strategic reasons for exiting New Mexico, we see significant value here, and as John mentioned, it was a highly competitive process. Evaluating it from various valuation perspectives, it sits in the mid- to high 5s on an EBITDA multiple, which represents great value for us. We plan to use the proceeds to reduce debt and concentrate on our operations in Texas.

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 timeline should we think about to see the benefit?

Yes. To provide some context on Permian LOE, we entered the year with a plan that we realized may have been a bit ambitious, as it included some savings that are now taking longer to materialize than we anticipated. Additionally, as I highlighted earlier, we are facing inflationary pressures, particularly regarding compression costs and water disposal. We are committed to achieving our LOE targets in the Permian, though it may take a bit longer. We are exploring various options, some of which may require capital investment, while others might involve commercial negotiations to address the embedded cost structure in both our assets and the Callon assets. We are confident that, similar to G&A and CapEx, LOE will play a significant role in the $350 million of targeted cost savings over the next three years. However, reaching those targets will take additional time, with progress expected later this year and into 2026.

Got it. Appreciate the color. Thank you.

Thank you.

Yes. Good morning. I wanted to go through your plans to 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 a little tighter spacing with smaller fracs in areas. So I think it's more 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 a common topic whenever we discuss our Permian inventory. We haven't been open with the market about our inventory there for a while, but we are working on it. We've mentioned this before and are currently deep into understanding the inventory we acquired from Callon. We're also evaluating some leftover legacy Apache inventory that we haven't addressed yet. The amount of inventory is increasing with our plans for higher well density. However, this is becoming a bit unpredictable because every time we achieve cost reductions, it naturally enhances the economic viability of drilling in the Permian. Increasing the density of wells not only raises the number of wells in each drilling unit but also boosts the estimated ultimate recovery per drilling unit. The more we reduce costs—like the $800,000 per well we accomplished in the first quarter—the more it expands the feasibility of drilling density in the Permian. This is what we are currently focusing on. As we've stated before, we plan to provide a more comprehensive view of our inventory later this year or early next year. It's important to understand that as we lower costs, what was once uneconomical or marginally viable can become economically feasible.

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 a 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 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.

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.

The other factor is that in the second half of the year, anything we capture now will contribute fully to 2026. So, as we increase the captured in-year number from 60 to 130, you will see a higher annualized run rate going forward. It's really about what is captured this year compared to the overall program's run rate heading 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 examples 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, how we operate 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.

Hey, guys. Good morning.

Good morning, Paul.

John, could you explain why gas development in Egypt is currently more appealing or comparable to oil? Should we expect that if oil prices increase, you will allocate more rigs to gas, and if oil prices rise above current levels, you would revert to oil? Additionally, for Alpine High, what gas/oil ratio would prompt you to redirect some capital back to that area? That's my 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.

I would like to add a point about Egypt. There have been concerns that the shift towards gas may result in lower oil production. However, most of the gas in the Western Desert of Egypt is rich in condensate. We have experienced a slight decline in gross oil volumes in Egypt, but with the condensate associated with the gas program and improvements from waterflood programs helping to stabilize base decline, I would describe the decrease in oil volumes as very minimal as we progress through the second to fourth quarters.

Steve, regarding Alpine High, could you clarify if in Egypt for oil you need one workover rig for each drilling rig? Is the same ratio still applicable for gas, or is it lower? I believe one of the challenges in the past couple of years has been the difficulty in finding enough workover rigs to boost the drilling rate.

Yes. We are currently operating a similar number of workover rigs as we did previously. However, it’s important to note that the gas production comes from both dry wells and associated gas from oil wells. I hope we won’t need to invest much time, effort, or money in workovers for the new wells we are bringing online since these should be productive for a while. Generally, maintaining gas wells requires less effort compared to oil wells. In Alpine High, there is a significant amount of economic gas available depending on certain price points. Our decision to drill in Alpine High is driven by Waha pricing, as the transportation logistics are separate, and we engage in gas trading on the Gulf Coast. The revenue from gas trading is independent of Alpine High; it must be economically viable, and drilling there must be justified based on Waha pricing and anticipated trends. Waha pricing can be quite unpredictable, impacted by pipeline construction and maintenance. This year, we faced situations where we had to reduce our output due to Waha pricing not meeting expectations. We will transition our drilling efforts from oil to gas in Alpine High or add a new rig there when we believe the Waha pricing can support economically viable drilling that is on par with or better than oil drilling in the Permian Basin.

I have a quick follow-up question. John, what oil price would indicate that we are operating at a loss and would prompt you to make significant cuts in the capital program or allow oil production to decline instead of maintaining it? Is there a specific number you're considering? We will monitor the situation closely and are prepared to take action if necessary. However, it seems that we'd need to see WTI prices fall to the very low 50s for that to happen. Initially, this would likely mean reducing the number of rigs in the Permian and potentially a frac crew, and possibly seeing changes in Egypt. We are in a strong position right now, and with the ongoing activities and improvements in our cost structure, we expect those numbers to decline further every day.

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 speak in just a moment. Generally, we sold the asset because we took advantage of a favorable price. It was not a necessity, but we listed it and received excellent offers, which led to the transaction. We are currently in the process of finalizing that transaction. This will allow us to reduce our revolving credit, and Ben can provide more details on that. I believe it places us in a position where we can still be very strategic regarding buybacks if necessary.

Yes, just a quick follow-up. We have established a 60% return to shareholders within our framework and have exceeded that every year. As we progress through the year, we will be opportunistic in our approach. With our zero revolver balance, we will explore opportunities on both the debt side and 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.

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 cuts 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. Looking at our current position and considering the planned savings at the 350 annual run rate, we can support our exploration and development program, operate 6 rigs in the Permian, and 12 in Egypt, while also paying dividends at $50 WTI, with reasonable marketing assumptions. We are making significant progress, and we are investing in programs that will contribute to long-term growth.

Thank you for the response. I have a follow-up to Arun's earlier question. I'm trying to better understand the development of the denser well spacing that was mentioned in the prepared remarks. I know there are many variables involved, as Steve mentioned earlier with the analogy of a moving target. However, is there any way to quantify the transition from 2024 to 2025 and what this might look like moving into 2026? Alternatively, is there a better way to understand what percentage of this year's program is utilizing the denser spacing design?

Yes, currently a significant percentage of our operations is focused on this. We undertook substantial preparations last year, including pre-purchasing tubulars and materials. We're using slimmer casing, and while we need to allow these programs to run their course, we've made considerable progress in the areas where we're drilling, with very positive results. We will keep refining our approach, acknowledging that it is a dynamic process, and we aim to optimize as we move ahead. Particularly in the areas we’re concentrating on right now, we are implementing tighter spacing compared to our historical practices and utilizing smaller fracs.

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.