Thank you for standing by, and welcome to the APA Corporation's fourth quarter 2024 financial and operational results. At this time, all participants are in listen-only mode. After this speaker's presentation, there will be a question-and-answer session. To ask a question during this session, you'll need to press star one one on your telephone. If your question has been answered and you'd like to remove yourself from the queue, simply press star one one again. As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Ben Rodgers, Senior Vice President of Finance and Treasurer. Please go ahead, sir. Good morning, and thank you for joining us on APA Corporation's Fourth Quarter and Year-End 2024 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 20 minutes in length, with the remainder of the hour allotted for 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 non-controlling interest in Egypt and Egypt taxpayers. 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 and 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 Callon 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 triple B minus rating from S&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's 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 water flood 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 GranMorgu 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 million. 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 million in dividends and $246 million in share repurchases. This includes $100 million 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 and 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 million 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 31st, 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 Callon. We acquired Callon 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 2024. 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 cost, we were able to lower break-even oil prices in 2024 to $61 per barrel, compared to Callon's 2023 break-even 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 $2.2 billion-$2.3 billion and reflects more than a 20% year-over-year reduction in development capital in the Permian when adjusting for Callon's first quarter 2024 spend. Adding $200 million for Suriname development and $100 million for exploration capital, primarily in Alaska, we expect our total capital budget to be $2.5 billion-$2.6 billion. 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 Callon 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 million 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 from 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 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 $224 million U.S. deferred tax benefit related to the write-off of APA's investment in our U.K. subsidiaries and a $190 million 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 million, or $0.79 per share. Fourth quarter DD&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 2024, 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 2025. 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 million 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 million 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-Callon debt levels only nine months after closing the acquisition. Recognizing the lower net debt levels and increased scale achieved last year, S&P upgraded our credit rating to triple B minus in October. Our ultimate objective is to achieve triple B or better ratings, one notch above our current ratings at all three rating agencies. Wrapping up commentary on 2024, let me address the $190 million increase in the net contingent liability for the Fieldwood properties. This increase does not reflect any change in the anticipated cost to plug and abandon 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 facility 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 Callon 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 125,000-127,000 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 $3.40-$3.50 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 Callon. The return of curtailed gas volumes also contributes to the improvement in our per unit LOE. In terms of our guidance related to G&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&A expense to 2025 guidance. Recall that overhead costs are allocated to multiple areas, including capital investment, exploration, LOE, and G&A. The relationship between G&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&A expense to increase despite our plans to decrease overhead costs by at least $25 million in 2025. 2024 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 million for 2025. Lastly, I would like to end with some additional color around our cost reduction initiatives. We are targeting $350 million in annualized cost savings by the end of 2027. 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 million-$125 million by the end of this year. At this point, we anticipate an in-year capture of around $60 million 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 million per year of salaries and benefits. In closing, the ongoing enhancement in the quality and sustainability of our core portfolio, combined with a right-sizing 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&A. Certainly. And ladies and gentlemen, we'd ask that you please limit yourself to one question and one follow-up. You may get back in the queue as time allows. And one moment for our first question. Our first question comes from the line of Doug Leggett from Wolfe Research. Your question, please. Oh, thanks. Good morning, everybody. John and Steve, look, I think looking at your share performance, whether we take a 2025 year to date, a 2024, or a 2023, something's clearly not clicking in terms of the $420 million of free cash flow in the fourth quarter, the $600 million of gas trading, the cost cutting. It 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's 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 a future with them. 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 the 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 Suriname 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 million over the next three years. We're getting after it. We've already got 35 of it kind of already identified and captured, and so I feel really confident that we set meaningful targets, that we will deliver. I think we've got the asset base in a place today where it will also deliver. Yeah. 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, 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%. 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. Yeah. Doug, I'd just say 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. Yeah. 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. 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. Good morning, Charles. John, I want to ask a couple of questions about what's going on with the asset base. 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? Where you are on the progress, what you've seen, and particularly how that, I guess, interacts or have it in reference to the activity you guys did in the last drilling season? Yeah. 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 stacked potential up and down the column, and that in general, the spacing needs to be wider in Howard to get to the same kind of EURs. But I wonder if you could talk about where in Howard County, what more specifically you're seeing 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 where you're seeing these positive results. Yeah. Charles, what I would just say is 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. 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. You bet, Charles. Thank you. And our next question comes from the line of Scott Hanold from RBC. Your question, please. Yeah. 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, Doug, 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 that are 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 the tests up in Howard County, we're two of those later last year, and we've always sprinkled 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 were coming off of us and Callon 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. Yeah. 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 trying to give some directional view on that as opposed to precise guidance. But I think 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. 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 we came into the fourth quarter really at a peak of production volume. And if I talk about numbers that exclude our Central Basin platform that we sold on December 31st, we peaked at production in the U.S. at 140,000 barrels of oil a day in October. Then we began declining. We averaged 134 for the quarter. The exit rate in December, rather balanced between those two numbers, was 128. We exited at that. That's the 134 average, which was the average for the fourth quarter. The 128 was where we entered the first quarter. We've had some weather, kind of 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 125-127. 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. That's why our average guidance for the year, for the full year, is 125,000-127,000 barrels a day as well. Hopefully, that gives a little bit more of the color behind why that's the case. Yeah. 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 you 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? Yeah. Yeah. I'm sorry if I went out. Yeah. 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 drilled going forward if the returns are pretty strong under the new contract? Yeah. Yeah. I'll step back. Number one, we're off to a really good start. With the 12 rigs, we mentioned we picked up a rig in November. We dedicated that to gas. We kind of went after some things that we knew were lower risk, that were high gas yields, with also some liquids, some condensate. So we've been able to drill a couple of really good wells. We've been able to bring them into the 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. 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 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 million 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. 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. In general, a good backbone of infrastructure. Very promising results. Quite frankly, we found a lot of gas in the Western Desert when we were looking for oil. 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. Appreciate it. Thank you. You bet. Thank you. And our next question comes from the line of Leo Mariani 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 paydown of that? And what's the kind of outlook for that in 2025 in terms of getting some of your cash out? Yeah. Leo, we were just in Cairo, and we're fortunate enough for the Egypt show. I did a keynote there, and I was actually able to meet with the president. So if you go back and look over the last two years, the past due balance 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, and 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. Yeah. And Leo, if I could just add one thing to that. 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 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. Okay. Appreciate that. Wanted to jump over to the purchased oil and gas sales here. You guys are guiding to $600 million 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. Yeah. No problem. So if we look at 2024, the actuals, if I round up maybe slightly, the trading of gas around the pipelines from Permian Basin to the Gulf Coast was about $330 million, and the LNG contract was about $170 million for a total of $500 million for 2024. Pretty similar ratio for 2025 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 million breaks down to about $400 million on the gas trading around the pipeline contracts and about $200 million on the Cheniere LNG contract. Okay. Thank you. Thank you. Our next question comes from the line of Betty Jiang from Barclays. Your question, please? Hello. Good morning. I wanted to go back and talk about the cost-cutting initiative because that's really a big part of the free cash flow extension story for the next few years. Just wondering, is there anything structurally changed in how the organization is being run or the milestones that's being set to 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&A savings, and maybe just give us a bit more color on how you are thinking about executing on those targets? Yeah. I'd say, Betty, if you step back and you look at our three buckets, the biggest bucket's obviously going to be the capital. The next one's going to be the LOE, and then the next one's going to be the G&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&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&A piece is one that we're getting onto. 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 with just 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 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. Yeah. And Betty, if I could just add a few things to that. Where did the $350 million target come from? I would emphasize it's at least $350 million. 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&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&A will probably be competing for second and third, probably somewhat similar amounts. We do believe that the $350 million 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 those metrics. My follow-up will be on the inventory duration that you see in the Permian as you start fully incorporating the Callon assets. What is your current assessment of your years of inventory life in both the Delaware and Midland today? How many years do you have of similar quality development if you continue at the current 8-rig pace? Yeah. Betty, if we looked 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 Callon, 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. Yeah. And again, if I could just add a bit to that, the reason why John alluded to 2029 is on the free cash flow per share chart that we provided in the supplement. And basically, what we've got embedded in the assumptions underneath that growing free cash flow per share is that Permian roughly holds flat through that time period. And we're very confident we can do that and probably beyond 2029. We still have a lot of work to do on the Callon acreage and, for that matter, on our own acreage and getting fully characterized all of the acreage that we have and all of the potential landing zones. And we know that the market is wanting to hear more about that. We're working on that, still kind of fully digesting the Callon acquisition in that regard. We'll come back probably later this year with a more detailed look at our full view of what our portfolio looks like and inventory looks like in the Permian and how long that will last. We're confident, certainly, it'll last beyond the range of that free cash flow chart. Great. Look forward to that. Thank you. Thank you. And as a reminder, ladies and gentlemen, if you do have a question at this time, please press star one one on your telephone. And our next question comes from the line of Bertrand Donnes from Truist. Your question, please. Hey, morning, guys. Just following up on slide four, assuming you keep the 60% shareholder return program in place, which I believe is the plan, it looks like this could result in your purchasing a substantial portion of the shares. Just want to understand how we should think about that level of growing free cash flow versus probably the natural desire to maybe increase activity a little bit or look externally to grow through acquisition. Just how do you balance those two? Thanks. Yeah. So maybe I'd just take this opportunity to go through a number of the underlying assumptions on that free cash flow per share chart because I think they're important. It does assume that we capture and sustain $350 million of cost reductions. And frankly, 2025 and through to 2027, free cash flow per share is driven primarily through that $350 million of cost reductions. It is after-tax cost reductions. And then, obviously, 2028 begins surrounding Block 58 production volumes. And as I indicated, Permian volumes are held relatively flat through that five-year time frame. Egypt, though, is actually on decline, similar to what we've seen in 2024 and similar to what we're giving guidance to for 2025. Actually, it does not include the Egypt production volumes in that. Do not include any of what we're seeing on the gas side right now because that's kind of pretty fresh data. It includes all ARO and DCOM spend. It includes exploration spend. As it's clear on the chart, we assume $300 million per year annually for the third-party trading activity and the Cheniere contract. We do stay, and we build into that chart. Built into that is the 60% capital returns framework. To get to the answer on your question, the underlying assumptions in there are that in that five-year period, we would pay down $2.2 billion of debt. That's the term loan that's existing now, anything on the revolver. It includes bond debt that is maturing during that time frame. It would include $1.7 billion in dividends during that time frame. It would include share buybacks of around 52 million shares. We have a price expectation that's underlying in that chart that says we trade at a constant, a fixed multiple of free cash flow. With the free cash flow increasing over time, those 52 million shares are bought back at an average price over the five years of $33.65. That's about $1.75 billion of share buybacks during the five-year period. That's helpful. I guess more to the question is if you're staring down this kind of free cash flow and if you don't see a price response in the shares, do you continue to buy back shares or do you shift your strategy towards either production growth or external growth through acquisition? I mean, today, you're going to continue to buy back stock as we believe in the asset base and you look at what's coming on in the free cash flow. So I think you continue to invest in yourself under those circumstances. Understood. And then just shifting gears, I appreciate the ARO disclosure for about $100 million this year. Just wondering if you could walk us through how that changes over time, maybe ARO and decommissioning costs over the next few years just directionally, if that's all you can share. Thanks. Yeah. The $100 million of ARO this year is broken down. It's about $40 million in legacy Gulf of Mexico abandonment. It's about $30 million of North Sea, and it's about $30 million of onshore US. That's the $100 million. In addition to that, we'll spend about $70 million this year on Fieldwood DCOM. Other than the North Sea, I expect most of those to stay relatively flat. They will spike from time to time just based on activities. The North Sea will grow over time. We've talked about the profile of that. We talked about that extensively on the third quarter call. The North Sea will grow, and others will stay relatively flat here for the next four or five years. Thanks, guys. Thank you. And our next question comes from the line of David Deckelbaum from TD Cowen. Your question, please. Thanks for taking my questions, guys. I just wanted to follow up just on that. I appreciate it. I just wanted to follow up just for clarification on the Egypt gas agreement. Just to confirm, this pertains to new drilling activity and I'm just wanting to get a sense of the comparative economics that you see relative to oil opportunities there and how long the duration of this contract is for. Now it is on new gas, and it's set up, David, to where it's on par, right? We put gas on par with oil. That's why we're comfortable shifting the rigs. Quite frankly, Egypt's short gas. We've been on decline on the gas side. It truly is a win-win. You're seeing that impact. It puts gas on par with oil. It's on an incremental gas above an agreed decline curve. You're seeing the impacts of that new gas come into our weighted average price. Yeah. And I'll just add to that that when we say it's on par with oil, that's on a full-cycle basis. So it does have built into it, into that price, it has built into it the anticipated costs of any infrastructure build-out that we might need to do if we were to be meaningfully successful on the gas exploration program. I guess it's still like, I guess my follow-up is just to confirm. I know in the past, we've looked at sort of logistical constraints in Egypt around kind of getting beyond the current rig counts. So should we think of this overall as the top-line rig count and that you'll just be allocating between gas and oil opportunities here? I mean, I don't think so. I think we're in a good place today where we've been able to work the workover projects and recompletions down to kind of a steady state. With the 12 rigs we're running today and the 20 workover rigs, we're in a pretty darn good place. That's not the constraint here would be top-line rig count. It's really just going to be getting to the opportunities and initially what we can do with the infrastructure, right? So what we need to do is do exactly what we're doing, bring on the low-hanging fruit, which we're going after. And then we need to get some of the nicer prospects drilled, which would give us some clues into what we want to do on the infrastructure in the future. Thanks, John. Thank you. And our final question for today comes from the line of Neil Mehta from Goldman Sachs. Your question, please. Yeah. Good morning, John and team. Just want to spend some time on Suriname. I guess this year is more about securing some long lead-time items and recognizing the operator probably has a little bit more color here. But what are you focused on, John, in terms of the milestones at that development for 2025 specifically? No, I mean, I think we're off to a good start. As we said, capital first quarter is a little heavy just because of some of the long leads that we've already purchased, some of the things with the FPSO and things. So we're tracking things well. Total is doing a fantastic job. We're digging in on the development plan and those things and continuing to look at the block's future potential in terms of exploration and those things. So in general, it's going to be a year of good progress, and I'd say Total is off to a really good start and doing an excellent job. And then, John, on the Permian, you've talked about a pretty flattish profile in terms of the production here. Is there a scenario where you could accelerate production in that time horizon? Do you feel like you have the inventory depth to do it, or do you want to run this business at plateau? I mean, Neil, there's no doubt. I mean, if you look at what we were doing last year with 11 rigs, it was at a much, much higher rate, and we feel like ratcheting down, running this at eight, we can run it relatively flat, which is the plan for more than just 2025, and so it puts us in a pretty good spot, and that's why we've kind of ratcheted down to this level. Clearly, there's inventory that you could ramp up, but quite frankly, we want to get in here and get into execution mode and deliver where we can drive some of the cost efficiencies out of the cost curve and really improve the free cash flow while running it flat. Yeah. If I could just add a bit to that. The thing that we talked about last year, probably on the third quarter call, was that strategically, we have a differentiated strategy around exploration. And with that type of a strategy and the investment that it requires, you don't need to be growing the base production volume in the Permian or in Egypt. If you're successful on the exploration side, the exploration provides the growth for the future. We just have this period of time, 2025-2027 now, that seems to be if we're producing flat from our core foundational portfolio, then our free cash flow is going to be flat for three years. That's part of the impetus around the cost initiative was to get that free cash flow per share moving up during that timeframe as opposed to just waiting for Suriname growth to come across the hill in 2028. Yeah. That makes sense. And then driving your share count down in the process. Thanks, guys. Thank you. Thank you. This does conclude the question and answer session of today's program. I'd like to hand the program back to John Christmann, our CEO, for any further remarks. Yeah. Thank you. Over the last several years, we have transformed the portfolio by building sustainability and duration in our two foundational assets, the Permian and Egypt. This will be complemented by our world-class development in Suriname, with first oil expected in 2028. We have set meaningful cost reduction targets. We are confident we can deliver and see the potential to exceed these targets over time. This puts us on a path for substantial free cash flow growth in both the near and long term. With that, I will turn it back to the operator. Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.