Welcome to the Fourth Quarter 2024 ConocoPhillips Earnings Conference Call. My name is Liz, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. During the question-and-answer session, if you have a question, please press star one-one on your touch-tone phone. I will now turn the call over to Phil Gresh, Vice President, Investor Relations. Sir, you may begin. Thank you, Liz, and welcome everyone to our fourth quarter 2024 earnings conference call. On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO, Bill Bullock, Executive Vice President and Chief Financial Officer, Andy O'Brien, Senior Vice President of Strategy, Commercial, Sustainability, and Technology, Nick Olds, Executive Vice President, Lower 48, and Kirk Johnson, Senior Vice President of Global Operations. I also wanted to formally welcome Guy Baber, the former Vice President of Investor Relations for Marathon Oil, who has joined the Investor Relations team here at ConocoPhillips. Ryan and Bill will kick off the call with opening remarks, after which the team will be available for questions. For the Q&A, we'll be taking one question per caller. A few quick reminders. First, along with today's release, we published supplemental financial materials and a slide presentation, which you can find on the Investor Relations website. Second, during this call, we will make forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's press release and in our periodic SEC filings. We'll be making some non-GAAP financial metric references. Reconciliations to the nearest corresponding GAAP measure can be found in the release and then on our website. With that, let me turn it over to Ryan. Thanks, Phil, and let me extend my welcome to everybody for joining our fourth quarter 2024 earnings conference call. 2024 was certainly another strong year for ConocoPhillips. We executed well operationally and, on a standalone basis, delivered 4% production growth year-over-year, which was above the high end of our full-year guidance range. We showed strong performance across the entire portfolio, delivering 5% growth in the Lower 48 and 3% growth in Alaska and international on the same basis, and we delivered a 123% preliminary organic reserve replacement ratio in 2024. Our three-year average is now 131%. We also enhanced the portfolio. We closed the acquisition of Marathon in late November, which added high-quality, low-cost-to-supply inventory to our portfolio, and we remain confident that we will deliver more than $1 billion of run-rate synergies by the end of 2025, over half of which is included in our capital guidance. In Alaska, we opportunistically exercised our preferential rights to acquire additional working interests at attractive valuations in Kuparuk River and Prudhoe Bay units. We progressed our global LNG strategy through additional regasification and sales agreements into Europe and Asia. And as we announced this morning, we're making solid progress on our planned $2 billion of asset sales. We have agreements in place to sell non-core Lower 48 assets for approximately $600 million before customary adjustments in the first half of 2025. We continue to deliver on our returns-focused value proposition. We generated a trailing 12-month return on capital employed of 14%, or 15% on a cash-adjusted basis. We returned $9.1 billion of capital to our shareholders, representing 45% of our CFO, consistent with our long-term track record and well above our 30% commitment. Now, looking ahead to 2025, we remain confident in the plan that we outlined in our third quarter call to deliver low single-digit production growth for $12.9 billion of CapEx. In the Lower 48, on a pro forma basis, we plan to reduce capital spending by over 15% year-over-year while still delivering low single-digit production growth. This is primarily due to expected material synergy capture associated with the acquisition of Marathon and significant drilling and completion efficiency gains. We also expect to grow production in Alaska and Canada, and we are doing all of this while continuing to invest in differentiated, high-return, longer-cycle projects. Now, on these projects, we're making steady progress across the board. We expect 2025 to be the peak year of our long-cycle spending at around $3 billion, followed by a steady stream of project startups from 2026- 2029. Once these projects are all online, we expect $3.5 billion of incremental CFO from NFE, Port Arthur, NFS, and Willow, all combined at $70 WTI, $10 TTF, and $4 Henry Hub. And that leads to roughly $6 billion of incremental annual sustaining free cash flow relative to 2025. Shifting to shareholder distributions, this morning we announced a target to return $10 billion back to shareholders this year, assuming current commodity prices. This consists of $4 billion of ordinary dividends and $6 billion in buybacks, positioning us to execute on our objective to retire the equivalent of the shares issued for the Marathon transaction within two to three years, even with lower WTI prices than at the time of the announcement. So, in conclusion, once again, I'm proud of the accomplishments of the entire organization. Our portfolio is well positioned to generate competitive returns and cash flow for decades to come. Now, let me turn the call over to Bill to cover our fourth quarter performance and 2025 guidance in more detail. Thanks, Ryan. In the fourth quarter, we generated $1.98 per share in adjusted earnings. Now, we had a number of special items in the quarter. The two largest were related to the Marathon acquisition. First, we recorded over $400 million of transaction and integration-related expenses. Now, this was mostly offset by over $400 million of tax benefits resulting from utilization of certain foreign tax credits associated with the Marathon acquisition. Both of these items were largely non-cash in the quarter, and the one-time cash benefit will show up as a working capital tailwind in the first quarter of this year, and it is in addition to the NOLs associated with the Marathon acquisition that we expect to recognize over the next few years. The transaction-related costs will gradually flow through working capital during 2025 as we achieve our promised synergies. Shifting to fourth quarter operations, we produced 2,183,000 barrels of oil equivalent per day. This included one month of production from the acquired Marathon assets, which added 126,000 barrels per day to the quarter. Excluding Marathon's production, we achieved 8% underlying growth year-over-year. This is above the high end of our guidance range. Now, inclusive of one month of Marathon, Lower 48 produced 1,308,000 barrels of oil equivalent per day, and by basin, we produced 833,000 in the Permian, 296,000 in Eagle Ford, and 151,000 in the Bakken. Moving to cash flows, fourth quarter CFO was over $5.4 billion, and this included over $250 million of AP LNG distributions. Operating working capital was a $1 billion headwind in the quarter, primarily due to normal changes in accounts receivable and accounts payable. Capital expenditures were $3.3 billion, which included approximately $400 million for spending related to acquisitions that was not premised in guidance. We returned more than $2.8 billion to shareholders, including just under $2 billion in buybacks and $900 million in ordinary dividends in the quarter. We also completed a series of strategic debt transactions following the acquisition of Marathon. Now, these transactions simplified our capital structure, extended the weighted average maturity of our portfolio, lowered our weighted average coupon rate, and reduced near-term maturities. We ended the year with cash and short-term investments of $6.4 billion and had $1.1 billion in long-term liquid investments. Turning to guidance, we forecast 2025 production to be in the range of 2.34-2.38 million barrels of oil equivalent per day. This takes into account 20,000 barrels per day of planned turnarounds. Turnarounds are expected to be highest in the second quarter, with a tri-annual turnaround at Ekofisk in Norway, a turnaround at Qatar, and maintenance in Australia. Then, in the third quarter, we will have turnarounds in Alaska. For the first quarter, we expect production to also be in a range of 2.34-2.38 million barrels of oil equivalent per day. This guidance reflects a 20,000 per day impact on the full quarter from January weather events. We expect a minimal first quarter impact from turnarounds, and that's similar to the fourth quarter. For capital spending, our full-year guidance is approximately $12.9 billion. On slide eight of the presentation material, we provide a pro forma bridge from 2024 to 2025 with some of the key year-over-year variables. In the Lower 48, we expect to reduce spending by approximately $1.4 billion. For long-cycle projects, we expect to see a $400 million increase in spending to roughly $3 billion in 2025, inclusive of capitalized interest of about $400 million. Finally, in Alaska and international, we expect to see a $200 million increase in spending driven by our growth opportunities in Canada and Alaska. Shifting to cost guidance, we expect full-year adjusted operating costs to be in the range of $10.9-$11.1 billion. Full-year cash exploration expenses are expected to be $300 million, and full-year DD&A expense is expected to be in the range of $11.3-$11.5 billion. Full-year adjusted corporate segment net loss guidance is approximately $1.1 billion. We expect our effective corporate tax rate to be in the 36%-37% range at strip pricing, excluding any one-time items, with an effective cash tax rate in the 35%-36% range. Finally, on cash flows, we expect full-year AP LNG distributions to be about $1 billion, with about $200 million in the first quarter. So, to wrap up, ConocoPhillips had a strong year in 2024. We executed well operationally. We're continuing to deliver on our strategic initiatives across our deep, durable, and diverse portfolio, and we remain highly competitive on our shareholder distributions. That concludes our prepared remarks. I'll turn it back over to the operator to start the Q&A. Thank you. We will now begin the question-and-answer session. In the interest of time, we ask that you limit yourself to one question. If you have a question, please press star one one on your touchtone phone. If you wish to be removed from the queue, please press star one one again. If you're using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star 11 on your touchtone phone. Our first question comes from the line of Arun Jayaram, with JP Morgan. Yeah. Good morning. Good afternoon. Ryan, you outlined the 10% increase in cash return to $10 billion. I'm sure the company scrutinized its approach to cash return in 2025, just given commodity price volatility and obviously the recent close of Marathon. But I wanted to see if we could get some insights on what drove your ultimate decision in terms of 2025 to give a quantum of cash return, and how should we think about potential flex in cash return, either higher or lower, given potential commodity price changes? Yeah. Thanks, Arun. I think when we set the new strategy for the company way back in 2016, certainly delivering a lot of our significant amount of our cash back to the shareholder. And I think that that's something that's important to the company, important to demonstrate we can continue to do that. And I think it's represented in what we kind of set as our target for 2025. I think as we looked at it, we obviously took a look at the forward curve and where things are developing in 2025. We take our own view. We have lots of commodity markets that drive our CFOs. We We go through the course of the year. But I think despite the recent downdrafts in the WTI here over the last month, we felt pretty comfortable at $10 billion. Look, I remind people we have a lot of torque to the upside on commodity prices. Look at our past behavior over the number of years. We've been sharing that with our shareholders. A reminder, if you look at the whole company, a good rule of thumb is about $400 million for every dollar of WTI movement. So, obviously, if we get $5 or $10 of uplift, that's pretty significant cash flow to the company. And we typically share that with our shareholders as well. On the downside, look, we've got a strong balance sheet. We ended the year with over, I think, $7.5 billion of cash and long-term investments. So we've got a lot of flexibility there. And then, as we announced in our prepared remarks, we're on track to dispose of about $2 billion of non-core assets, which gives us a lot of flexibility as we go into 2025. So, putting all that together, we felt like $10 billion was a good place to start. And we'll do like everybody, watch the volatility of the market and the commodity price, but feel pretty good about where we started the year. Our next question comes from the line of Pedro Lopez with Evercore ISI. Hi. Good morning. It's not Pedro, but it's Steve. Oh, hey, Steven. We need to change the name. Sorry about that. Yeah. Oh, no worries. Trying a new look, so I was wondering, Ryan, if we could dig in. Fits you well. Dig in a little bit on some of the long-cycle CapEx, if we could, and the outlook. Just wondering if you could kind of hit on some of the moving parts around Alaska, Qatar, thoughts on Port Arthur Phase Two. And are we right in kind of assuming that your equity outlays on major projects are peaking in 2025, or is that a misplaced view? Thanks. Hey, Steve. It's Andy, maybe I can get that one started. There's a few bits to the question. Maybe I'll start with Port Arthur Phase Two, and then I'll get to the long-cycle capital. So, on Port Arthur Phase Two, this is a great project. It's underpinned by a premier developer and a premier EPC company. It's also positive to see a company like Aramco showing an interest in being part of that project. But as we've said before, we took an equity stake in Phase One for unique reasons, which included getting the project off the ground. And it came with options on other phases and other projects. So, we're very keen to see Phase Two get completed. There's going to be cost sharing across the common facilities of the two projects. So, it's only in our interest to see Phase Two go. But I think it's fair to say our primary focus is on building out our offtake and regas capacity for 10- 15 MTPA. So, maybe that sort of gives you the background on our thinking on Port Arthur Phase Two. Then, moving to the major project capital and the pace of decline on the $3 billion. As we said in our prepared remarks, our capital guidance for the year is $12.9 billion. And that includes the $3 billion of long-cycle project spend, of which there's $400 million of capitalized interest. And as we said, 2025 is expected to be the peak spend as we undertake the biggest winter construction season in Willow. So, if you look past 2025, we are going to see the major project spend step down each year. At the same time, we'll start to see the projects coming online, delivering on our expected cash flow and free cash flow improvements, and the first one of those will be NFE in 2026. Now, that will be followed by Port Arthur, then NFS, and then we'll have Willow in 2029, so there'll be a steady drumbeat of these projects coming on, but I think the key point I want you to take away is that, yeah, absolutely, we see this year as the peak spend in these projects. And I would add, Steve, and then we tried to say that in our opening remarks, look, this is coming. And there's going to be a steady beat of project startups, as Andy described, and kind of a $70 WTI, $10 TTF, $4 Henry Hub kind of price deck. That results in $3.5 billion or more of CFO, but more importantly, over $6 billion of free cash flow coming relative to our 2025 starting point. So, all that's starting to materialize and is out there. And these are great projects, low-cost supply, competitive in the portfolio, and lead to the long-term growth and development of the company, which we're quite excited about. Our next question comes from Doug Leggett with Wolfe Research. Good morning, everybody. Ryan, nothing short of spectacular performance in the Lower 48. And my question is that when you laid out the 10-year plan, you talked about low single-digit growth. And I think you're up 10% year-over-year, 4% sequentially in the third and fourth quarter. And I have to imagine it's productivity gains, it's efficiencies, it's all the things that you talked about. My question is, do you accept that production growth on a go-forward basis, or do you trim activity levels and reduce your capital? I'm just trying to understand what the philosophy is as to how you respond to the extraordinary delivery you've had in your portfolio. Yeah. Thanks, Doug. A huge shout-out to Nick and his team. They're thinking delivering some amazing efficiencies with the horizontals, the larger well pads, and just the frac and drilling efficiencies that we experience are really good. I know it's a little dry. I guess production growth is a bit of an outcome from our plans. But I think the way we kind of look at it is we think about planning cycle year-over-year. And we got the great addition of the Marathon assets, which gave us another 2 plus billion barrels of resource sub $40 cost of supply. So, we get to integrate that into our plans, and we build significant scale and scope, primarily Bakken in the Eagle Ford, but additional scope in the Permian as well. So, if we step back a minute, what we look at is trying to keep driving the efficiency that Nick's team is delivering for the company. So, if you think about it, do you want to lay down some extra frac spreads? Well, all that does is end up building more pads than we need to build. And you go the opposite way and say, well, why don't we cut out a couple of rig lines? And that just creates a problem on the frac spread where we got to take frac holidays, and we shut frac crews down for three or four months just to keep the whole thing balanced. So, we're trying to operate within this efficient operating window. And the Marathon transaction just gave us the opportunity to reset optimized plateaus across both the Bakken and the Eagle Ford. So, we kind of approach it that way. We try to set a reasonable scope going into the year that doesn't allow us to whipsaw the organization both up or down, and then we try to take a look at what kind of production growth comes out of that, so it truly is an output for the plans, trying to keep driving that efficiency. I remind people back in 2022, we thought we'd be adding two, three, four rig lines a year to get the kind of growth that we're seeing. We haven't added a single rig line over this timeframe, so it's all driven around the efficiency. I think the point you're getting at is, when, in a macro that's growing maybe one, 1.5%, is the growth too much? I think we do try to take a look at that at the end of the day, but it's really trying to drive for capital, efficiency, and returns on the capital that we're getting. And we just don't want to upset that efficient machine one way or the other. Our next question comes from Lloyd Byrne with Jefferies. Hey, good afternoon, Ryan, Bill, team. I really appreciate your comments on cash flow and CapEx. It looks to us as though consensus is embedding almost flat capital and no production growth into the future. So, I think that's important. I know you answered some of it. Can we go back and go through what you would think is a theoretical maintenance capital number as you look out? And I'm also thinking about how efficient you've been in replacing dollars per proved developed in the U.S. Hi, it's Andy. Yeah, I can take that one. And I think you started it off for me that thinking of sustaining capital, it is a bit philosophical because it does require being in a sustaining world. So, maybe I'll try and sort of translate on it a couple of different ways for you. So, if you were to take our 2025 capital of $12.9 billion, as we've just cleared, that includes $3 billion of pre-productive capital. And we're still growing the underlying business, low single digits. So, if you then were to normalize that out sort of in round numbers, you'd get to about $9 billion in the current commodity price environment if we were trying to just stay flat. Now, back at our investor meeting in 2022, we gave a different data point, which was to say we could basically our sustaining capital would be $6 billion, but that was in a sustaining world at a $40 price. Now, the company's changed a lot since then. We've grown with the acquisitions and our organic growth. So, if you were to add Marathon or organic growth, the Surmont acquisition, we'd be closer to about $7.5 billion on an apples-to-apples in a $40 world right now. But it is, as I said, this is kind of hypothetical. You've got to be in sort of a sustaining world before you really contemplate doing these kinds of things. But if you're trying to model it, so hopefully that's given you a couple of different ways to sort of triangulate on the same answer. Our next question comes from the line of Betty Jiang with Barclays. Good afternoon. Thank you for taking my question. Maybe just want to add a bit more color on the Lower 48, maybe from the CapEx side. In the slide, I show the $1.4 billion reduction in the Permian CapEx. Marathon synergy accounted for $500 million of that reduction. But could you just give a bit more color on what are the other drivers? How much of it is efficiency gains that's lowering well costs, and how much of it is development optimization that's perhaps driving a lower overall activity level? And then just if I step back for a bit, if you maintain at this CapEx level, does that mean you would be able to deliver the same low single-digit growth that you outlined before because of all the synergies and optimization that you're seeing with Marathon? Thanks. Good morning, Betty. This is Nick. Let me walk you through the few key components related to that $1.4 billion that you mentioned. It's really around the operational improvements that Ryan was mentioning. It's that meaningful synergy capture of the $500 million that we talked about, and there's modest deflation as well. If I first start with the operational improvement, this is a well-established and demonstrated track record the last two and a half years. The team continues to do more with less, and just hats off to the team that are calling in today. We demonstrated this in 2024. With similar rig and frac activity counts, we delivered 15% more scope. That means more feet drilled, more stages per day, but most importantly, it's more wells online. You're seeing that through the bottom line production as we look in Q3 and Q4. Now, we're going to apply the same model, those operating efficiencies, in a level loaded steady state development program to the Marathon assets. So, we see those efficiency improvements coming forward. And that is a key component of the material synergy capture of the $500 million. Now, within the synergies itself, in addition to those efficiencies, you've got items like moving on to common contracts, designs around facilities, different well programs, mud programs that are also in there. Now, in addition to shifting to our steady state development program, and if you recall, Heritage Marathon were typically very front-end weighted with their activity, then ramped down Q3, Q4. We're moving to that over time. But we're also moving our legacy positions in Eagle Ford and Bakken to an optimum plateau. And we'll reassess this as we integrate those assets. So, that's another big driver. So, you can think about you got the efficiencies, you got material synergy capture, you got activity optimization. And then we expect modest deflation in 2025 as well, around $200 million. So, all that gets you to the $1.4 billion. Now, related to production and continuing on with that, we've kind of demonstrated over the last two and a half years that flat activity, we can grow the Lower 48 business. The teams have continued to drive operating efficiencies. And we do see that for years to come at flat activity. Our next question comes from the line of Devin McDermott with Morgan Stanley. Hey, good morning. Thanks for taking my question. I wanted to circle back to Alaska. Willow is a big portion of the major capital project spending, and we're in the peak construction season right now. So, I was hoping you can give us a bit of an update on some of the near-term milestones and remind us of the cadence for spending on that project over the next few years. And maybe just stepping back, Alaska has gotten a lot of attention from the Trump administration so far and even had its own executive order. So, more broadly, could you remind us how you're thinking about the Western North Slope opportunity set and whether or not the policy environment creates more of an opportunity to move forward with some of this over the next few years? Thanks. Yeah, good morning, Devin. This is Kirk. Yeah, there's a few things certainly in there to unpack. I'll start with Willow, as you did, and certainly happy to report that the progress we made here last year, certainly inclusive of fourth quarter and even just this last month here in 2025, allows me to say we're really on trend with the progress that we've been making. You've been hearing from me report out simply that that project team there in Alaska just continues to hit all the key milestones that we've laid out certainly since taking FID back in late 2023. When I think about certainly the work that was underway in fourth quarter and even just this last month in January, the initial mobilization of our winter construction season, certainly that you point out as our largest for the project, has really gone quite well. So, we got a quick and early start. We got some cold weather. Ice road construction activities are, dare I say, modestly ahead of plan, which is really nice for us. It puts us in a position of taking full advantage of the full winter season, knowing that we may certainly have a little bit of weather in front of us. And again, to the note of this is the largest winter construction season, we're in a great position of building on all the activity that we accomplished here last year. Again, this is a peak year of ice road construction. It's from those ice roads that we're building gravel roads, gravel pads. It allows us to, from those ice roads, build our pipeline networks. And then we've got a few unique activities as well here planned this winter season. Think bridge construction as well as some horizontal directional drills for pipeline crossing. So, again, lots to do. And then you even go into the operation modules that you heard me speak about last year. We floated those, barged those up to Alaska, landed those, and onshored those during the ice-free season. And those are. I've got report outs just this last month that those are moving across into the Willow development area. So, again, some really good progress. We landed our contracts. Engineering's on track. That puts us in a great position for full fabrication across the entirety of this year. So, all that culminates, again, Devin, into this peak year of spend, which is why we're guiding to an expectation of project capital being roughly $500 million more than we spent in 2024. Then last, I might just help you all a little bit as well. We're thinking about all of that spend then manifesting in probably close to a third of our total annual spend expectation here in 2025 showing up in the first three to four months of this year. And then so nationally, then we expect the capital this year to stair-step down into second, third, and fourth quarter. And then you'd expect the same trend from us when we think about the total project spend, the balance of what we've guided on for the first couple of years post-FID. That'll continue to stair-step down with very little, if any, spend in 2029, which is when we're expecting first oil. So, again, great progress here. Look forward to continued hitting of milestones for our Willow project here in 2025. Then lastly, yes, there's certainly been quite a bit of press out there around NPRA. I would probably back up just a little bit to say, first and foremost, I think it's important for me to emphasize that the ruling that came out on NPRA here from the prior administration doesn't affect any of the activities that we're doing up there, whether it's in Kuparuk, Western North Slope, or even Willow. But we did take issue, as did the state and certainly other stakeholders, with that ruling. So we were pleased to see that President Trump and that administration issued an executive order to, in essence, reverse what came about here late last year. We recognize that's going to take a little bit of time here this year. But yes, we're looking forward to partnering with the Department of the Interior and especially with the state of Alaska. Fundamentally, we believe that continued exploration west of Willow, it's the right thing to do for energy. It's the right thing to do for the state of Alaska and its stakeholders. And clearly, we're in a really good position. We're putting ourselves in a position to continue exploring west of Willow as that's enabled for us. So, again, some good news out there for us in Alaska. Our next question comes from the line of Neil Mehta with Goldman Sachs. Good morning, Ryan and team, or good afternoon. I just love your perspective on slide four, specifically around reserve replacement. There's been some discussion about how investors should interpret this number. And it's one where you appear to do pretty well on over the last couple of years. So, just your thoughts on where you've been able to drive that reserve replacement, any geographies in particular that you want to call out, and how we should interpret the statistic. Yeah, good morning, Neil. This is Andy. We agree that we still think that reserves and reserve replacements is a really important metric to measure us and to measure oil and gas companies by. So, yeah, we're really pleased that we're delivering yet another strong organic reserve replacement ratio this year, as we said in the prepared remarks, that's 123%. A bit of color I can add to that. We're doing that while growing our annual production and also in an environment where prices fell, which that part results in downward revisions due to market factors. So, we're particularly pleased that given that, we're still having above 100% reserve replacements. Now, specifically to where it's coming from, again, particularly pleased here in terms of the balance we have. Our Lower 48 organic reserve replacement ratio, excluding market factors, was over 100% again. We were able to make the first initial booking on the NFS project, and then now that we have ownership of complete ownership of Surmont, we're progressing Surmont development plans with new pads, so we were able to do some bookings there. They're kind of, I'd say, the three big levers that I'd point to. You'll see more detail when we publish the K, so that's how we got to 123% organic, and then with the additions from the Marathon acquisition and the additional working in Alaska, the total reserve replacement ratio was 244%. So when you put all that together, we're showing for 2024 reserves of $7.8 billion BOE. That's up a billion from last year, and our RTP is improving from 10 years to 10.7 years. And then one other little thing I'd add is that given the Marathon transaction close so late in the year, the bookings we've got for Marathon primarily represent the proved developed reserves with minimal pod bookings. So, the teams right now are working through integrated pro forma five-year plans. And once that's finalized, we'd actually expect to make an additional pod booking later this year. So, again, yeah, another very healthy year and a good sort of good milestone for us in terms of achieving greater than 100% again. Our next question comes from Ryan Todd with Piper Sandler. Good, thanks. Maybe one on divestiture. You've announced $600 million of asset sales relative to a target of $2 billion. Can you maybe talk about that program ongoing, going forward, the market and appetite for the divestiture efforts and within that, maybe the ongoing discussions around the Port Arthur equity sell down? Sure. This is Andy. I'm happy to take that one. So, as you said, we've had activities well underway on multiple fronts now with disposition candidates. As we announced today, we signed PSAs for about $600 million. That's non-core Permian assets. And we expect those to close in the first half of the year. We've actually reflected this in our guidance. So, that's part of what's in our guidance this year. We've also got activity progressing well on other fronts. So, we'd actually expect the majority of the $2 billion to be achieved in 2025. So, we're really pleased with the progress we're making there. You specifically asked about Port Arthur phase one. We've talked about this one a number of times in the past. As we've said before, we took equity in phase one for unique reasons, which included getting the project off the ground. And it came with options and other phases of projects for us. So, it was a unique reason why we invested in that project. But the project is now well into execution. And we don't necessarily need to be an equity owner forever in that project. But we can be patient. We don't need to rush anything here in that the project is using project financing to fund construction now. So, another way to look at that is that we're continuing to de-risk the project every day without additional capital contribution. So, it's an asset we look at. We've had inbounds on that asset. And it's one that we'll consider over time. But we feel very confident about the $2 billion target we put out there. And we feel good about achieving that this year. Our next question comes from the line of Bob Brackett with Bernstein. Good morning. Some of your peers have talked about opportunities in U.S. data center power demand, either supplying feedstock gas or, in fact, setting up power demand via CCGTs. And your strategy clearly has been a more global LNG approach. Can you talk about comparing and contrasting those strategies and maybe highlight anything interesting you might be doing on the domestic power demand side? Yeah, thanks, Bob. Like a lot of people, been studying it. We're also getting inbounds on the power side, like a lot of people, primarily because we obviously have a lot of natural gas and we're producing. We have a commercial power desk. So, we buy and sell power all over the U.S. We have a large land position throughout the U.S. So, there's some natural advantages that we have in that space. And we're looking at them and trying to assess some of those inbounds. It's another way to potentially monetize a lot of gas that maybe would get a lower Waha kind of wellhead price. You talked about our main sort of thrust is in the LNG space. The way I would describe that is we're bullish gas volumes in North America, but we're bearish price. So, it's a great way to take advantage of those molecules and move them to higher valued markets through that LNG channel, which we've described to everybody. But the power requirements are going to be going up. Certainly, these hyperscalers, data centers are going to need opportunities for fast and cheap power. So, we sit in an area in the Permian Basin that kind of fits a lot of those kinds of attributes. So, we're looking at it. Can it scale to a really big business in the company? I don't know. But we're looking at those opportunities. But it's first and foremost got to fit our framework. And we've talked about what our financial framework is. And power is no different. It's got to be competitive for capital. But certainly, it looks like some growth opportunities potentially coming. And we're assessing some of those opportunities right now. Our next question comes from the line of Scott Hanold with RBC Capital Markets. Yeah, hey, thanks. I was wondering if you could all provide your perspective on, there's been a number of initiatives coming out of the White House, and how do you all see that impact the way you all do business and the industry as well? And if you could give your point of view or perspective on the potential for tariffs and how that may impact your outlook. Yeah, Scott, I can maybe start, let Andy follow up with a few more specifics. Like we were kind of following it closely like everybody else. It certainly upsets the market. The market will find its own rebalance point if these go on for a long period of time. It does look like they're a negotiating opportunity for this administration to do some things that they want with both our southern neighbor and our northern neighbor. So, it will have some impact in the market. We've done some looking relative to our portfolio. And it's got kind of pluses and minuses, as you might expect. So, I can let Andy maybe give you a flavor or a feel for those specific impacts to the company. Thanks, Ryan. Morning, Scott. Yeah, as Ryan said, it's something that we obviously we've been looking at closely. And no surprise, our primary exposure to the tariffs that were announced last week would have been the sales of our Surmont liquids into the U.S. We sell around half of our Surmont liquids into the U.S. on a mix of pipeline and rail. But the remainder is actually transported to the Canadian West Coast or sold in the local Alberta market. So, if tariffs were to be implemented, it's pretty difficult to say exactly who's going to carry the burden where. The refiners in the Midwest and the Rockies have less options for substitutes versus, say, the Gulf Coast or the West Coast refiners. Maybe just thinking about our other asset in Canada, the Montney, very quickly. We don't actually sell any liquids or gas into the U.S. from the Montney. We're actually pretty naturally hedged on gas between Montney and Surmont. If you come up above Canada and think about ConocoPhillips as a total, this is where our diversified portfolio really comes into play to provide some mitigation. If we were to see tariffs, we'd likely see strengthening differentials for Bakken, for ANS, and possibly even the Permian. Lots of moving parts. I'm probably just scratching on the surface of the implications. If tariffs were implemented, we'd also see movements in foreign exchange rates that we'd have to factor in. There'd be an awful lot for us to work through. Ultimately, I'd draw you back to what we're focused on is what we can control. That's producing the lowest cost supply volumes, then optimizing value with our commercial organization. As Ryan said right at the very beginning, we hope to see that we don't get in a situation of having tariffs, but we're also doing the work to make sure that we're prepared if they were to come into play. Our next question comes from the line of Neal Dingmann with Truist Securities. Morning, thanks for the time. Ryan, just a very broad question around M&A specifically. While realizing it's fairly dry on Marathon, I'm just wondering, when you look at the landscape out there today, would you characterize M&A opportunities that fit your requirements as better or worse than you saw this time last year? I just don't know kind of how many opportunities you foresee out there. We've said it in the past, Neil, that consolidation is going to continue in this business. I don't quite know when companies make strategic decisions to change the direction that they're going and create some opportunity out there. The landscape is certainly changing. There's probably less of the high-quality names out there just on balance as we look over the transactions that have preceded us and what we've done over the last three to four years as well. But that doesn't say consolidation needs to go. But I go back to sort of our kind of three big tenets in this space is, look, first and foremost, it has to fit our financial framework, our view of mid-cycle prices going forward. We have to find a way to make the assets better if they were in our portfolio. And it needs to make our company better, our 10-year plan better. So, those are pretty high hurdles. And we had a unique opportunity when Marathon decided to do something different strategically for their company. We weren't out looking. But obviously, we pay close attention to everything that's going on in the business. And we take a view of these companies. Certainly, that landscape is starting to shrink a little bit of real quality sort of opportunities that are out there. Our next question comes from the line of Leo Mariani with Roth MKM. I wanted to just dive a little bit more into the divestiture that you disclosed here, the $600 million. Sounds like that's going to close in the first half of the year. Sounds like it's basically all kind of non-core Permian. But can you provide a volume number associated with that in terms of roughly how much production is being sold and just any thoughts on commodity mix? Is that kind of a standard Permian mix with a little bit more than half of that being oil? Yeah. I can take that question. Yeah, the production from the assets would have been about 15,000 barrels a day last year. The assets are essentially non-core Southern Delaware. So, that pretty much gives you sort of the typical mix of what they are. Our next question comes from the line of Paul Cheng with Scotiabank. Hey, guys. Good morning. Ryan, now you have a little bit more than two months under your belt with the Marathon asset. Can you give us some idea of what's the running room in those assets in terms of the tier one inventory backlog, if there's anything that you can share? And can you break it down by basin, particularly in Eagle Ford and Bakken, that really is quite mature over there. And also, what is your game plan for Equatorial Guinea? Is there any differences compared to what Marathon has been communicating to the street before they've been acquired? Thank you. Yeah, thanks, Paul. Maybe I can take the Equatorial Guinea, and Nick can provide some color on the Marathon assets that were acquired, but at EDG, we're certainly pretty pleased with the CFO and the contracts that were established by Marathon that we've walked into at EDG. We really haven't changed the plans at all that Marathon was walking into. We look forward to a couple more infill wells that are going on. I think the rig has been sourced, and they're about ready to spud, so we'll be bringing it and getting our feet under the ground with EDG. I'd say short and medium term, no real changes to what Marathon was doing at EDG. The bigger question is the same thing. I think Marathon was grappling with what's the long-term potential in the area that can flow through the LNG plant and be marketed. But we're trying to grow our LNG. And this fits well within the portfolio and what we're trying to do longer term for the company. Maybe I can let Nick address your inventory question for Marathon. Yeah, Paul, you're right. We've got a couple of months under the belt and look forward to the future months as well. Yeah, as far as the inventory quality, it's unchanged. We don't see anything from the acquisition case. We've got 2,000 competitive well locations, as Ryan mentioned, around that $40 per barrel cost of supply. Roughly about half of that is in Eagle Ford. And then you can kind of think the remaining is split between Bakken and Delaware. So, highly competitive out there. We're looking at the current well performance as well. Eagle Ford looks very strong. If you look at both our Heritage COP and Heritage Marathon on a barrel of oil per foot or even on a barrel of equivalent per foot and compare that to prior years from 2022 to 2023, really strong performance in last year's assets. And we're seeing, as we drill these wells, they're meeting type curve expectations in Eagle Ford and Bakken as well. A couple of other things along the synergy lines when we combine these assets. If you look up in the Bakken, as we trade experience on our combined acreage for long laterals, we're seeing more opportunities for increased long laterals in the Bakken, as an example. So, the teams are just working to optimize and improve that combined inventory. Our next question comes from the line of Charles Meade with Johnson Rice. Good morning, Ryan. To you and the Conoco team there. I wanted to go back to Alaska. You guys highlighted the startup of the Nuna project, which I believe was kind of mid-December. I wondered if you could put the startup of that project in the context of your overall called 180,000 barrels of oil a day. I know you guys said it was 29 wells, but can you tell us, is that going to be of a magnitude that we're going to be able to observe the effect of that in your 1Q and 2Q volumes in 2025? Yeah, good morning, Charles. This is Kirk. I can take that one. Yeah, I appreciate the question on the Alaska-based business because certainly, that business continues to chart a course of really sustaining production here with some really modest growth in the next couple of years. And I think it really highlights the amount of investment opportunities that still exist for us in that business, with Nuna being a prime example of that. So, again, maybe just a little bit about Nuna. And you pointed some of this out. This is a project in which we have built out a new pad, the first one in roughly a decade. And it shows the great work that the teams are doing and exploring and appraising new targets and taking advantage of the infrastructure that we have up there. First oil was in December. That came on after drilling and completing and bringing on a couple of wells. We do have plans of eight more wells here this year in 2025. And all of that, as you point out, has actually come on the heels, if you will, of having drilled over 10 wells from existing gravel. So, again, it shows the pragmatism that the team has really deployed of ensuring that we understand what these targets are, we de-risk those before we actually put new gravel out there. We are, in fact, expecting that production to enable us to more than offset decline as we look at Alaska's production profile for the next year. And then we have a number of other targets that exist out there for us. And you've heard me speak to some of these before. In Kuparuk, in addition to Nuna, we have Coyote. Coyote is a really interesting parallel to Willow. And then in WNS and our Alpine asset, we've got Narwhal and Minke. And so, these Brooki an topsets put us in a really nice position of using these wells to advance technology, to advance certainly our capital efficiency, knowing that some of these are a great analog or a parallel to Willow, which gives us, again, that much more of an opportunity as we stand up a couple of rigs for Willow in 2027. So, really pleased with how that's taken shape for us on our base business in Alaska. Our next question comes from the line of Josh Silverstein with UBS. Yeah, thanks, guys. Just wanted to get an update on the LNG contracting environment. Curious if there's been any shift in thinking around the need for new LNG in Europe, potentially due to Russia-Ukraine ceasefire or anything that the current administration is doing to kind of push more LNG projects here in the Gulf Coast to send potentially over there. Thanks. Yeah, good morning. This is Andy. In terms of what's going on in the LNG space, I'd just say it's more continuation. There's nothing I'd say that's particularly new. We look at sort of the situation with Europe. We're heavily dependent on LNG. You've seen the Russia-Ukraine deal for the pipeline gas that came to an end. That's one and a half BCF capacity that is no longer available. You've just seen what's going on with the TTF pricing right now in terms of the cold winter that they're seeing in Europe and just sort of how the inventories are being drawn down. So, I would say that in terms of the need for LNG, nothing's really changed. And in terms of the way that we're looking at it, sort of our strategy remains unchanged. We're really looking at how we can build out offtake for the 10-15 MTPA. And as you've seen in the past, we're building out regas capacity in Europe. And we're also looking for sales into Asia. So, I'd kind of just say that really sort of we're right on track with our strategy. And I think it's sort of things are playing out as we expected them to. Our last question will come from the line of Alastair Syme with Citi. Thanks, Ryan, Bill, and team. Another White House question for you. I mean, the president's made some noises about wanting higher levels of U.S. domestic production. And I get your points about running the Lower 48 business for optimal efficiency. But is there anything that would incentivize you to go faster in that business? Not really. I think we're just trying to drive the efficiencies, Alastair. I think the message that I've had for the transition team and for the people that are looking at it is that I'd say we are drilling, drill, baby, drilling. I think we have to build. We have to build a lot of infrastructure. So, I think a lot of our focus and attention right now is on permitting reform, trying to make sure we can build out the infrastructure both for the power kinds of opportunities that are going to be out there and then, obviously, the gas lines that come with it. And then just faster movement within the regulatory and the permitting environment for wherever you sit on federal lands, whether it's New Mexico, North Dakota, Gulf of Mexico, Alaska, just getting more timely drilling approvals, rights of ways, easements, and all those permits. They just had slowed down under the prior administration, and there's a real opportunity to get back to kind of normal business, if you will, to what we've had in years past, and that just adds to the overall efficiency of the system and should lead to a more sustained plateau or growth in our production coming out of the Lower 48 in terms of liquids and certainly the growing amount of gas volumes that are coming as well, so, it just creates a better environment for investment and more efficient operations. Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.