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F500-2020-465-Apache

The oil and gas exploration and production company operates in the U.S., Egypt, and the U.K. and has exploration activities offshore of Suriname.

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APA, best known through its Apache subsidiary, is an independent energy company specializing in the exploration, development, and production of oil and natural gas. Operating primarily in the Permian Basin, as well as in Egypt, the North Sea, and Suriname, APA focuses on delivering reliable and affordable energy to meet global demand. The company is committed to sustainable practices and leverages advanced technologies, including artificial intelligence, to enhance operational efficiency and reduce environmental impact.

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APA (APA): Company Profile, Stock Price, News, Rankings

legacy

for standing by, and welcome to the APA Corporation's Fourth Quarter twenty twenty four Financial and Operational Results. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Ben Rogers, Senior Vice President of Finance and Treasurer.

Good morning, and thank you for joining us on APA Corporation's fourth quarter and year end twenty twenty four 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. Also on the call and available to answer questions are Tracy Henderson, Executive Vice President of Exploration and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be about twenty minutes in length with the remainder of the hour allotted for Q and 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 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. And with that, I'll turn the call over to John.

Good morning, and thank you for joining us. On the call today, I will review our 2024 accomplishments, share highlights of our fourth quarter performance and provide an overview of our 2025 plan and other key long term objectives. Over the last several years, APA has been strategically reshaped in numerous ways. We have enhanced the quality and sustainability of the portfolio in our core areas of the Permian Basin and the Western Desert Of Egypt, while also building long term optionality through a differentiated exploration strategy. Throughout this process, we have been strengthening the balance sheet and prudently allocating capital to prioritize returns.

2024 was a year of notable further progress on all of these fronts. In the Permian, we continued to strategically refine our position with the acquisition of Cowen and the sale of non core assets. In Egypt, we signed a new gas price agreement creating the potential for significant additional drilling opportunities with returns on par with oil. In Suriname, we reached a final investment decision for our first oil development. Lastly, we achieved a BBB- rating from S and P and are now investment grade with all three rating agencies.

With the significant portfolio changes in the Permian Basin during 2024, our U. S. Business is now almost entirely comprised of unconventional assets. This strategic shift has solidified the Permian as the cornerstone of our asset base, driving over 75% of our current adjusted production and providing a more predictable and steady business model. As seen in our supplement released yesterday, APA scale in the Permian now stands out, rivaling and surpassing many of our U.

S. Independent shale peers. In Egypt, we successfully returned to more normalized workover and recompletion backlogs, while also improving our PDP decline through waterflood activities. These efforts have provided a much more predictable oil production profile, increasing the overall efficiency and longevity of our operations. In Suriname, we reached a significant milestone when our partner Total announced FID on the Grand Morgu project.

With a capacity of 220,000 barrels of oil per day and first oil expected in 2028. As you will recall, based on the joint venture agreement we have with Total, our capital spending exposure for the project will be very manageable. 2024 also highlighted the value of our gas trading activities, where we realized an annual net gain of nearly $500,000,000 At current strip prices, we believe 2025 will be a similarly strong year. Lastly, we continue to deliver on our capital return framework. In 2024, we returned 71% of free cash flow through $353,000,000 in dividends and $246,000,000 in share repurchases.

This includes $100,000,000 of repurchases executed during the fourth quarter at a price just under $22 per share. We continue to believe our shares offer a compelling value and we will be inclined to lean into the buyback program at such prices. Moving now to a few highlights from the fourth quarter. We delivered production volumes above guidance in all three of our operating regions it did so on a capital program that came in lower than guidance, primarily due to ongoing well cost reductions in the Permian Basin. These factors were the main drivers in delivering $420,000,000 of free cash flow during the quarter.

In November, we added a rig in Egypt to initiate a gas focused drilling program. We are very pleased with the early results and now expect year over year gas production to increase for the first time in over a decade. Finally, on December 31, we closed on the sale of our non core conventional properties in the Permian Basin. Let me now turn to the progress we have made with Cowen. We acquired Cowen primarily to add scale and inventory to our existing Delaware footprint.

We also anticipated capturing meaningful synergies, most of which we achieved on a sustainable basis by the end of twenty twenty four. As we took over operations, our focus was on addressing the capital and operating efficiencies required to deliver industry competitive returns. By increasing lateral length while reducing total well costs, we are able to lower breakeven oil prices in 2024 to $61 per barrel compared to Cowen's twenty twenty three breakeven of $78 per barrel. We are looking forward to further improvements in 2025 and beyond. In the Midland Basin, in Northern Howard County, our early results have significantly outperformed expectations.

We plan to return to this area with tighter well spacing on future pads, which will increase inventory counts and capture more resource than we originally anticipated. This has a positive read through to offset legacy APA acreage as well and we will revisit these opportunities in the future. Moving on to our 2025 plan. Our 2024 achievements helped lay the foundation for an efficient activity set and more predictable production profile in 2025 and beyond. We expect to run an eight rig program in the Permian and a 12 rig program in Egypt.

This activity set results in a combined development capital budget of $2,200,000,000 to $2,300,000,000 and reflects more than a 20% year over year reduction in development capital in the Permian when adjusting for Cowen's first quarter twenty twenty four spend. Adding $200,000,000 for Suriname development and $100,000,000 for exploration capital, primarily in Alaska, we expect our total capital budget to be $2,500,000,000 to $2,600,000,000 With this lower development capital budget, we expect to deliver higher total adjusted production in 2025 compared to 2024. While this includes the benefit of no planned gas curtailments, it also underscores the progress we are making on capital efficiency through the integration of Cowen and the stabilization of Egypt volumes. Lastly, I want to touch on the cost reduction initiatives we announced in our earnings release yesterday. In the fourth quarter, we launched an effort to analyze cost saving opportunities across three core areas that drive the majority of our annual controllable spend: capital, LOE and overhead.

We are focused on identifying opportunities to streamline the business, improve the way we operate and control our costs. The first step in simplifying the organization was announced in January when we reduced our corporate officer count by over one third. Earlier this month, we initiated additional overhead decreases as part of a broader streamlining effort across the organization. These initial reductions coupled with the targeted savings in capital, LOE and additional overhead spend are expected to generate at least $350,000,000 in annualized savings by year end 2027. These efforts will drive free cash flow expansion over the next several years.

In closing, APA made significant continued progress in 2024 to streamline our portfolio and establish a core asset base that can underpin a sustainable activity set and predictable production profile from the Permian and Egypt for the long term. In the short to medium term, we will work to reduce our controllable spend. This is our path to meaningful free cash flow growth in the 2025 to 2027 timeframe, ahead of Suriname First Oil in 2028, which will underpin a further step change in free cash flow into the next decade. We believe that this cash flow growth profile, coupled with our high quality exploration portfolio is differentiated for many of our peers and will drive growth in long term shareholder value. And with that, I will turn the call over to Steve.

Thank you, John. For the fourth quarter under generally accepted accounting principles, APA reported consolidated net income of $354,000,000 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 $224,000,000 U. S. Deferred tax benefit related to the write off of APA's investment in our UK subsidiaries and a $190,000,000 increase in our net liability on the former Fieldwood properties.

Excluding these and other smaller items, adjusted net income for the fourth quarter was $290,000,000 or $0.79 per share. Fourth quarter DD and A expense was higher than guidance, primarily due to accelerated depreciation at Alpine High. With negative Waha gas prices for the second and third quarters of twenty twenty four, SEC reserve guidelines required that substantially all of the Alpine High reserves be written off. As a result, one third of the Alpine High carrying value was depreciated in the fourth quarter and there will be a similar impact in the first quarter of twenty twenty five. Fourth quarter lease operating expense also came in slightly higher than guidance, largely due to an extra North Sea cargo lifting in the quarter.

The timing of North Sea cargo liftings has no impact on reported production, but it does affect the recognition of both sales revenue and LOE. APA generated $420,000,000 of free cash flow in the fourth quarter, the highest of any quarter in 2024. Through dividends and share repurchases, we returned 46% of this amount to shareholders in the quarter. For the full year, we generated $841,000,000 in free cash flow, of which we returned 71% to shareholders. Please refer to APA's published definition of free cash flow for any reconciliation needs.

In 2024, we made significant progress strengthening our balance sheet and are close to returning to pre Calend debt levels only nine months after closing the acquisition. Recognizing the lower net debt levels and increased scale achieved last year, S and P upgraded our credit rating to BBB- in October. Our ultimate objective is to achieve BBB or better ratings one notch above our current ratings at all three rating agencies. Wrapping up commentary on 2024, let me address the 190,000,000 increase in the net contingent liability for the Fieldwood properties. This increase does not reflect any change in the anticipated cost to plug in abandoned wells or to remove facilities and seafloor infrastructure.

In 2021, as a result of the Fieldwood bankruptcy ruling, an independent third party was required to own and manage the assets. In this capacity, the third party operates the producing assets and maintains and monitors the non producing assets awaiting abandonment. We believe the third party's cash costs for these activities remain too high. Until we take actions to directly reduce these costs, the resultant reduction in future net cash flows increases the contingent liability on our balance sheet. With a large portion of the security utilized, we are now free to explore all avenues to manage these assets and to enable a more prudent cost management system.

We expect resolution to this later this year. Turning to our 2025 outlook, let me provide a few more details with respect to our guidance for the year. Starting with our capital spending cadence, you should expect our spending to be front half weighted primarily due to the timing of Suriname capital calls and our exploration activities in Alaska. Despite a planned steady activity level, Permian is also first half weighted primarily due to the timing of facilities spend in the basin. Looking at production, 2024 oil volumes for The U.

S. Adjusted for the effects of asset sales and the first quarter Cowan production were 128,000 barrels of oil per day. With the eight rig program planned in the Permian for 2025, U. S. Oil volumes should be in the 125,000 to 127,000 barrels per day range.

Total U. S. Volumes should increase mid single digits as we do not anticipate any price related production curtailments this year. In Egypt, adjusted production is expected to grow slightly year over year with a modest decline in gross volumes. On the gas front, we initiated drilling activity in the fourth quarter and have seen very encouraging results.

As John indicated, we now expect gross gas production to grow year over year. Our average realized gas price is expected to increase from $2.96 per Mcf in the fourth quarter to at least $3.15 per Mcf in the first quarter. Average realized price will continue to grow through the year with the full year average expected in the $3.4 to $3.5 range. As we look beyond 2025, success in the gas program will determine our ability to continue growing gas production and will highlight any need for additional infrastructure investment. Moving to lease operating expense.

For The U. S, we expect operated LOE per BOE in the Permian to be about 20% lower than 2024. This step change in operating efficiency reflects the progress we have made streamlining our U. S. Portfolio and harvesting synergies from the acquisition of Cowen.

The return of curtailed gas volumes also contributes to the improvement in our per unit LOE. In terms of our guidance related to G and A, it may appear that overhead costs are increasing significantly in 2025. Total overhead costs are in fact going down, but it is difficult to see that comparing 2024 actual G and A expense to 2025 guidance. Recall that overhead costs are allocated to multiple areas including capital investment, exploration, LOE and G and A. The relationship between G and A expense and total overhead costs is impacted most significantly by allocation methodology and the mark to market impact for long term incentive compensation.

These items are causing G and A expense to increase despite our plans to decrease overhead costs by at least $25,000,000 in 2025. '20 '20 '4 was a strong year for our third party gas trading business and 2025 is shaping up to perform at a similar level. This year, the Waha basis spread remains advantageous and we have seen appreciation in international LNG prices benefiting APA through our Cheniere gas supply contract. Given current strip prices, we anticipate generating a combined net gain of $600,000,000 for 2025. Lastly, I would like to end with some additional color around our cost reduction initiatives.

We are targeting $350,000,000 in annualized cost savings by the end of twenty twenty seven. Our goal is not just to capture some quick hit opportunities to lower costs, although that is certainly a near term focus. Our goal is to right size our entire cost structure to achieve a long term purposeful and sustainable outcome. In the near term, this will naturally focus on efforts, which are simply a matter of choice and discretion. Much of this is in our overhead cost structure and in day to day field operating practices.

In the intermediate term, it will address our capital cost structure for things like drilling and completions and facilities as well as operating practices such as life of field resource management and field automation. For the longer term, it will address more deeply ingrained structures like IT systems and infrastructure and accounting applications and procedures. This is why we have set longer term targets out to 2027. Some of these things are happening quickly and others will take more time and effort. In 2025, our objective is to achieve run rate savings of $100,000,000 to $125,000,000 by the end of this year.

At this point, we anticipate an in year capture of around $60,000,000 of actual savings, which is something we hope to improve upon as we go through the year. Our cost reduction targets are an important effort for the entire organization and are therefore included in both our short term and long term incentive compensation programs. Already this year, we have made good progress on restructuring our organization, starting with the reduction in our officer count that John mentioned. This was followed by a greater than 10% reduction in our global overhead structure in February. The combined annual run rate savings with these two simplification steps is approximately $35,000,000 per year of salaries and benefits.

In closing, the ongoing enhancement in the quality and sustainability of our core portfolio combined with the rightsizing of our cost structure will lay a foundation for growing free cash flow over the next three years. Suriname First Oil in 2028 will then carry that free cash flow growth into the next decade. Over that same time period, free cash flow per share increases even more significantly as a result of the share buybacks built into our capital returns framework. And with that, I will turn the call over to the operator for Q and A.

Certainly. Our first question comes from the line of Doug Leggate from Wolfe Research. Your question please.

Thanks. Good morning everybody. John and Steve, look, I think looking at your share performance, whether we take twenty five year to date, a '24 or a '23, something is clearly not clicking in terms of the $420,000,000 of free cash flow in the fourth quarter, the $600,000,000 of gas trading, the cost cutting all adds up to big numbers, but yet your share price continues to frankly get decimated relative to your peer group. It seems to us at least that there was a crisis of confidence in the guidance that is persistently getting missed. And I'd like to ask you, what confidence do you have through these cost cutting measures that that control over your guidance and visibility is going to get better?

Doug, I appreciate you jumping on. I appreciate the question. I think if you step back, number one, if you look at what we're doing on the cost structure side and you look at the portfolio over the last several years, we've really transformed our two anchor assets, Permian and Egypt into two businesses that we believe now have sustainable and durable inventory and the future with them, right? So, and if you look back over the last seven, eight quarters, we've actually done pretty well on hitting targets on the guidance. As far as the cost reductions, you go back to middle of last year as we're always focused on the cost structure and what can we do to generate more free cash flow.

Now that we've got two businesses that quite frankly, we don't feel like you need to grow with Surname now coming on in 2028. We started looking at how do we moderate and put some sustainability and predictability in those, which is why you saw us ratchet the capital down in the back half of the year. We've now got programs in Egypt, the 12 rigs in Permian with eight that we feel like we can deliver and it's all about cost structure. And so we started stepping back and looking at that hard and took a very deliberate approach starting at the top of the organization. I think we've laid out $350,000,000 over the next three years.

We're getting after it. We've already got $35,000,000 of it kind of already identified and captured. And so I feel really confident that we set meaningful targets that we will deliver. And I think we've got the asset base in a place today where it will also deliver.

I know it's a tricky one to answer, John, but we're all going to have to watch what happens. But my follow on is, and you know you and I and Steve have talked about this often, but if I could kind of replay back to you a couple of things you said in your opening remarks about you believe your stock is compelling value, you're going to return 60% of your free cash flow to shareholders. Your yield is almost 5%. Your capital structure is getting close to 45% debt. I don't really care too much about the rating agencies say about it.

Your equity holders are they're what's left after net debt. Why are you continuing to buy prioritized share buybacks when you can easily confirm transfer of value from debt to equity by paying down your debt? Because you've been buying back shares for three years and your share price is down 57%?

Yes. I would say, Doug, we've also I mean, you look at the returns framework, we've also been buying back debt. And I think we've made meaningful progress on both fronts. And I think with the framework that we have in place today, we will make progress on both fronts, both on the share side and the debt side, Steve.

Yes. Doug, I'd just state the same thing. We're working both sides of that. And you have a $40 price target on us. And with that kind of potential appreciation, buying back shares is leveraging to our current shareholder base and a number of our shareholder base actually support the buyback pretty heavily.

Yes. I got to defend myself very quickly. Let me just say one thing and I'll pass it on. That assumes a normalized discount rate, Steve, which you're not going to get with this capital structure given the volatility in your business. So if you don't fix the capital structure, your discount rate is not going to normalize.

That's kind of the thesis. But I'll leave it there. I appreciate you answering the questions. I know it's not easy, but thanks for your time.

Thank you. Our next question comes from the line of Charles Meade from Johnson Rice. Your question please.

Good morning, John and Steve and the rest of the APA team there.

John, I want to ask a couple of questions about what's going on with the asset base. And I guess the first one would be, can you give us an update on what's going on in Alaska, specifically with the Sockeye exploration well, where you are in the progress, what you've seen and particularly how that kind of I guess interacts or have it in reference to the activity you guys did in the last drilling season?

Yes. What I would say Charles is I think the big difference is the operations are going extremely well and going very smoothly. We are not in a position yet to comment on anything as we're not into the pay zones yet, but I can tell you things are on track and things are going extremely well operationally and it's been very smooth from that standpoint. So obviously, we're anxious to see the results and they'll be forthcoming. So far so good.

Got it. So just stay tuned there. And then, John, going back to some of your prepared comments about the Permian, specifically Howard County, I think you said that you guys have seen you're seeing better productivity in some zones and you're looking at some future downspacing. My understanding of Howard County, of course, it varies as you go from West to East, but that the zones you have are good, but there's not as much stack potential up and down the column and that in general the spacing needs to be wider in Howard to get the same kind of EURs. But I wonder if you could talk about where in Howard County, what more specifically you're seeing with these with the higher productivity, whether it's just related to longer laterals and perhaps if this is a different zone up or down the column that where you're seeing these positive results?

Charles, what I would just say is, as you're starting to press the northern boundaries, and we did space these a little wider, and quite frankly, the results have been fantastic. So we're excited about that. I don't want to comment too much, but I mean, we've got some offset acreage. So there's some other ramifications there, but we're very pleased with the results. They've been fantastic.

And like I said, we will be coming back. And fortunately, we're going to be able to space the wells on tighter spacing, but we'll come back with that, right. But we're very, very excited about the potential up there.

Okay. Well, stay tuned on that too. Thanks, John.

Thank you. And our next question comes from the line of Scott Hanold from RBC. Your question please.

Yes, thanks. If we could stick with the Permian for a minute. Could you talk to a couple of things? One, I guess in your presentation, Deck, you talked about delineating some zones there. Can you just give us a sense of exactly what you're looking at and how much capital you're allocating to that this year?

And secondarily, just in your Permian guidance, it does seem a little softer than sort of initial indications during the third quarter conference call. Just help me square the circle on that.

Scott, I would just say in Permian now we've got eight rigs, they're lined out pretty well. That's why we will come back. There are some areas. As always is the case, you're testing new zones and landing zones because we're always trying to build future inventory. So those the tests up in Howard County were two of those later last year and we've always sprinkle a few of those in.

In terms of the overall guide with Permian, we were looking high level. As you looked at last year, you're coming off of us and Cowen combined running 11 rigs. We ran those. We started to drop down in the third quarter and you've seen us now level off at eight rigs. So

Yes, Scott, if I could maybe give a little bit more detail. And John was right. We weren't typically in the third quarter results. We give directional guidance. We weren't trying to give guidance for 2025 for the Permian, but I understand why some people may have taken it that way.

What we were basically saying is that 2025 wasn't since we had already come down to eight rigs by that time, 2025 was not going to look like the fourth quarter. It was going to look more like the third quarter, but we were just kind of we were trying to give some directional view on that as opposed to precise guidance. But if I think it for you to be able to understand what's going on in our Permian assets, you kind of have to understand the pattern of activity and the volumes associated with that. And John talked about it. In the first half, we were running 11 rigs and we were turning in line on average 17 wells per month.

Some of that included a little bit of DUC activity and some of it was drilling complete. In June, we started dropping rigs. We dropped one in June, we dropped one in July. Pretty quickly, we were down to eight rigs. And by the time we got to the end of the year, we'd finished the DUC population and we'd gotten down to where we were turning in line 11 wells per month.

And so what the we came into the fourth quarter at a really at a peak of production volume. And if I talk about numbers that are that exclude our Central Basin platform that we sold on December 31, we peaked at production in The U. S. At 140,000 barrels of oil a day in October. And then we began declining.

We averaged 134,000 barrels for the quarter. And the exit rate in December, rather balanced between those two numbers was $128,000,000 we exited that. So that's the $134,000,000 average, which was the average for the fourth quarter. So the 128 was where we entered the first quarter. We've had some weather, some uncharacteristic amount of weather downtime so far in the quarter that brings us down to we believe our first quarter is probably going to average $125,000,000 to $127,000,000 With that though, I think what we've gotten to is we've gotten to a base of production volume with the eight rigs running for the most part since about September that we're at a base production volume that we believe is sustainable through the year.

And that's why our average guidance for the year for the full year is 125,000 to 127,000 barrels a day as well. So hopefully that gives a little bit more of the color behind why that's the case.

Yes. No, I appreciate that. That's good color. I mean, a lot of tough questions you guys are answering today, but I think you guys know what you need to do. Let me turn my second question to Egypt.

Obviously, the gas opportunity is encouraging. And can you give us a sense of when you look at your I think it's 12 rigs you're going to be running this year there. How do you balance those between oil and gas drilling? And is that going to change? And maybe a little color around what kind of infrastructure do you need to support the growth that could occur over the next couple of years in gas?

Scott, we had to cut out when you said how do you balance I'm assuming how do you balance the rig count? And then at the tail end, I heard you reference infrastructure. Can you just reframe that real quickly to make sure we answer the right question? Yes.

I'm sorry if it went out. Yes, the question was, how do you balance your 12 rig activity this year between oil and gas drilling? And what kind of infrastructure do you need to add to really get a lot more gas growth going forward if the returns are pretty strong under the new contract?

Yes. I'll step back. And number one, we're off to a really good start. And with the 12 rigs, we mentioned we picked up a rig in November. We dedicated that to gas and we kind of went after some things that we knew were lower risk that were high gas yields with also some liquid, some condensate.

And so we've been able to drill a couple of really good wells. We've been able to bring them into infrastructure, which is why we're running pretty strong on the gas side. We are because they're high pressure. We have backed out some lower pressure gas in some areas because of the infrastructure requirements right now. But it's got us very confident in the gas program.

And what you're likely to see us do is shift another rig or two to gas this year. So we'll probably maintain the 12 rigs, but we could run two to three rigs on the gas program. And quite frankly, we're anxious to get to some of the exploration targets as well. But the first thing to do is let's go ahead and go after some of the targets that we know we could get online, get those flowing through. And that's why you're seeing the kind of our average gas price starting to creep up as we're bringing on some of that new strong gas.

So the nice thing, you step back across the 5,000,000 acres. We've got good infrastructure. At times we've delivered, this is the first time in a dozen years really where we've been able to start to flatten or bring our gas curve up. So there is infrastructure, but it's going to depend on what we find and how successful the program is as to where we need to eliminate the, what I'll call bottlenecks or capacity or find ways to pipe the gas into areas where we can treat it or if we do have to build new infrastructure. So but in general, a good backbone of infrastructure, very promising results.

And quite frankly, we found a lot of gas in the Western Desert when we were looking for oil. So I'm really anxious to see as we start looking into some of the areas that we avoided because we knew they were gas rich, just what the capability would be.

Thank you. And our next question comes from the line of Leo Marinari from Roth. Your question please.

Hi. I wanted to follow-up a little bit more on Egypt. Just wanted to get a sense of what the receivable situation is these days. Have you started to see a little bit more substantial pay down of that? And what's the kind of outlook for that in 2025 in terms of getting some of your cash out?

Yes, Leo, we were just in Cairo and we're fortunate enough for the Egypt show. I did a keynote there and we were able I was actually able to meet with the President. So, if you go back and look over the last two years, the past due balances has been moving within a pretty tight band due to timing. And so when you step back and look at it, they've been pretty much staying current on what they owe when the past due has not been really growing or shrinking. But we do have reason to believe that we'll make some progress on that.

They're committed to making some progress on that. And so I think we should see some progress made this year.

Yes. And Leo, if I could just add one thing to that. Some in our supplement, we have a number of non GAAP reconciliations in the back and some people tend to look at those for working capital movements. It's not a pure working capital movement analysis, but it's somewhat it's characteristic of working capital movements. And if you look at the Egypt portion of that non GAAP reconciliation, you might believe there was a big increase in receivables in the quarter.

That is not correct. Receivables were basically flat in the quarter. What happened was we had an increase in drilling long leads. So it's just inventory for the drilling program. That's the working capital movement in Egypt.

over to the purchased oil and gas sales here. You guys are guiding to $600,000,000 in 2025. You obviously referenced strip prices. I was hoping maybe you could kind of give a little bit of breakdown there in terms of roughly how much is from the Cheniere contract versus how much is kind of from your domestic gas optimization business?

Yes, no problem. So if we look at 2024, the actuals, if I round up maybe slightly, the pipelines, the trading of gas around the pipelines from Permian Basin to the Gulf Coast was about $330,000,000 and the LNG contract was about $170,000,000 for a total of $500,000,000 for $24,000,000 pretty similar ratio for $25,000,000 at this point according to strip prices and there's lots of strip prices you've got to watch in all of that obviously. The $600,000,000 breaks down to about $400,000,000 on the gas trading around the pipeline contracts and about 200,000,000 on the Cheniere LNG contract.

Thank you. And our next question comes from the line of Betty Jiang from Barclays. Your question please.

Hello. Good morning. I want to go back and talk about the cost cutting initiative because that's really a big part of the free cash flow expansion for the next few years. Just wondering, is there anything structurally changing how the organization is being run or the milestones that's being set? Could you just give us a bit of comfort around your ability to hit on these targets?

Like how much the breakdown between capital cost savings versus operating G and A savings? And maybe just give us a bit more color on how you are thinking about executing on those targets?

Yes. I'd say, Betty, if you step back and you look at our three buckets, the biggest buckets obviously going to be the capital, the next one is going to be the LOE and then the next one is going to be the G and A. And when you look at immediate impact that you can address, it's kind of in the reverse order with you can address the G and A first and foremost. And so there's a lot of confidence in those numbers. We've already gotten off to a pretty darn good start.

As we mentioned in early January, we reduced the officer count by one third. We followed that on here recently with some of the support staff as well. So I think the G and A piece is one that we're getting on to. And then some of the other ones take more time as you really get into how are we running the business, how are we leveraging synergies and how are you driving the cost out. And some of that's with changes in technology and things that are taking place as you're seeing across corporate America today, was this data and infrastructure and software.

We spend a lot of money on those types of things. And so, I mean, it takes a little bit of longer on some of those. And then the efficiencies on the capital program are the ones that also take a little bit of time. But we're dead set on the benchmarking side and what do we need to do to drive us up into top quartile on the cost performance.

Yes. And Betty, if I could just add a few things to that. Where did the $350,000,000 target come from? I would emphasize it's at least $350,000,000 And as John alluded to, it did come from some fairly rigorous both internal and external benchmarking efforts. So we didn't just make the number up.

It's actually got some science behind it and we do believe it is something that we should be able to attain at least. But some of that is going to take longer than just a year and that's why we've set this up as a three year program. We are not at this point providing a breakdown of that between capital and LOE and G and A. But as John said, by the time we get to the end of the three year period, most of it's going to come from capital. And then LOE and G and A will probably be competing for second and third, probably somewhat similar amounts.

We do believe that the $350,000,000 is probably on the conservative end, but we're going to be talking about this pretty much every quarter now for the next three years as we go through this process. So there's still a lot to unfold here and we'll give more and more detail as we go through quarter after quarter, especially during 2025.

That's great. I'll look forward to that those metrics. My follow-up will be on the inventory duration that you see in the Permian as you start fully incorporating the Cowen assets. What is your current assessment of your years of inventory life in both the Delaware and Midland today? Like how many years you have a similar quality development if you continue at the current eight rig pace?

Yes. Betty, if we look at that today, we're confident we can see through 2029 right into the next decade. And I think the track record and quite frankly, there's still a lot of stuff to characterize that we're working through. So we're confident that each year we tend to add more locations than we drill. And that's something that we're working on and you're starting to see a lot of the stuff results come in on Cowen, which have been good.

And so we're confident that we'll continue to add to that as is always the case. But we've got really, really good visibility to the end of this decade with the program that we're running today.

APA (APA) Q4 2024 Earnings Call Transcript

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