Welcome to the Q4 2022 ConocoPhillips Earnings Conference Call. My name is Michelle, 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. Yes, thank you, operator, and welcome to everyone joining us for our Fourth Quarter 2022 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, Dominic Macklon, Executive Vice President of Strategy, Sustainability, and Technology, Nick Olds, Executive Vice President, Lower 48, Andy O'Brien, Senior Vice President of Global Operations, and Tim Leach, Advisor to the CEO. Ryan and Bill will kick off the call with opening remarks, after which the team will be available for your questions. A few quick reminders. First, along with today's release, we published supplemental financial materials and a presentation which you can find on our investor relations website. Second, during this call, we'll be making forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release and in our periodic SEC filings. Finally, we will make reference to some non-GAAP financial measures. Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website. With that, I will turn the call over to Ryan. Thanks, Phil, thank you to everyone for joining our Fourth Quarter 2022 Earnings Conference Call. As we sit here today, there are a number of crosscurrents in the global economy. While the energy sector is not immune to potential macro headwinds, our fundamental outlook remains constructive. On the demand side, we think that growth will continue in 2023, aided by a normalization in China mobility following the loosening of COVID restrictions. On the supply side, we believe the continued producer discipline and the expected impacts of Russian oil and product sanctions are likely to keep balances tight. While commodity prices are currently not as high as they averaged in 2022, we see duration to this upcycle. Stepping back, we remain steadfast in our view that a successful energy transition must meet society's fundamental need for secure, reliable, and affordable energy while also progressing toward a lower carbon future. While we all recognize the challenges that global energy policymakers face to achieve the goals of the Paris Agreement, it is clear that doing so requires an all-of-the-above approach. This can be done by enacting policies that encourage the development of lower emission energy sources and oil and gas resources. These policies should include efforts aimed at fiscal stability, streamlining of the permitting process, increased transparency on timelines, and supporting critical infrastructure. These are not just necessary for the oil and gas industry, but also for nuclear, hydrogen, and renewables, all of which will be necessary to deliver on the energy transition. At the end of the day, it's critical for our Administration to remember that North American energy production is a stabilizing force for both global energy security and meeting energy transition demand. Meeting that demand will require investments in medium and long cycle projects in addition to short cycle U.S. shale. This is why you see ConocoPhillips leaning a bit further across our deep and diversified portfolio in 2023. Whether it's the Lower 48, where we achieved record production in 2022, or our diversified global portfolio, ConocoPhillips is well-positioned to meet the world's long-term energy needs while also reducing our own emissions footprint. Shifting to our 2022 performance, ConocoPhillips showed continuous strong execution across our triple mandate. We generated a trailing 12-month Return on Capital Employed of 27%, the highest since the spin. We delivered on our plan to return $15 billion of capital to our shareholders, which represented 53% of our CFO, well in excess of our greater than 30% annual through-the-cycle commitment. We further advanced our net zero operational emissions ambition with a new medium-term methane intensity target consistent with our recent commitment to joining OGMP 2.0. Looking ahead, ConocoPhillips is well positioned to further deliver on our triple mandate in 2023 with a well-balanced capital allocation strategy. This morning, we announced a plan to return $11 billion of capital to shareholders, which represents about 50% of our forecasted CFO at $80 WTI. The other half of our cash flow will be dedicated to reinvesting in the business. From a portfolio perspective, our deep and well-diversified asset base is well-positioned to generate solid cash flow growth for decades to come. This is further evidenced by our organic reserve replacement ratio of 177% in 2022. We're also enthusiastic about our new LNG opportunities we are participating in in Qatar and the United States, which are highly complementary to our existing LNG business. We look forward to providing you a comprehensive update about our long-term strategy and our financial outlook at our upcoming analyst and investor meeting on April 12 at the New York Stock Exchange. Let me turn the call over to Bill to cover our fourth quarter performance and 2023 guidance in a bit more detail. Thanks, Ryan. Starting with fourth quarter results, we generated $2.71 in adjusted earnings per share. Fourth quarter production was 1,758,000 barrels of oil equivalent per day, which included a 27,000 barrel a day negative impact from weather in the Lower 48. Lower 48 production averaged 997,000, including 671 from the Permian, 214 from the Eagle Ford, and 96,000 from the Bakken. Moving to cash flow. Fourth quarter CFO was $6.5 billion, excluding working capital at an average WTI price of $83 per barrel. AP LNG distributions were $639 million, and fourth quarter capital expenditures were $2.5 billion, including $2.1 billion of base capital and $300 million for acquisitions and North Field East payments. On capital allocation, we returned $5.1 billion to shareholders through ordinary dividends, VROC payments, and share buybacks, while also reducing gross debt by $400 million. Full year CFO was $28.5 billion, excluding working capital at an average WTI price of $94 per barrel in 2022. Full year AP LNG distributions were $2.2 billion, full year total CapEx was $10.2 billion, with base CapEx achieving our guidance of $8.1 billion and $2.1 billion of acquisitions in North Field East payments. Full year return of capital was $15 billion, while $3.4 billion went to debt reduction, with cash and short-term investments ending the year at $9.5 billion. Turning to 2023 guidance. We forecast full year production will be in a range of 1.76 million-1.8 million barrels of oil equivalent per day, which represents 1%-4% of organic growth. Our first quarter production guidance range is 1.72 million-1.76 million, which includes 35,000 of planned maintenance, primarily in Qatar and the Lower 48. Our full year planned maintenance is expected to be similar to 2022. On capital spending, we expect a range of $10.7 billion-$11.3 billion, which I will discuss in more detail in a moment. We expect operating costs of $8.2 billion, DD&A of $8.1 billion, and corporate segment net loss of $900 million. For 2023 cash flow, we forecast $22 billion in CFO at $80 barrel WTI, $85 Brent, and $3.25 Henry Hub at current strip prices for regional differentials. Included in our cash flow forecast is $1.9 billion in APLNG distributions, with $600 million expected in the first quarter. Regarding CapEx, we provide a waterfall in our prepared materials bridging 2022 actual spending to 2023 guidance. Starting with base capital spending, we forecast an increase from $8.1 billion in 2022 to a range of $9.1 billion-$9.3 billion in 2023. The remaining $1.6 billion-$2.0 billion is allocated to longer-term projects. Of this amount, $1.5 billion-$1.6 billion is for LNG projects, which includes Port Arthur, North Field East and North Field South. For Port Arthur specifically, after factoring in expected project financing, we forecast that ConocoPhillips net investment will be just under $2 billion over the five-year investment period. More than half of this capital investment will be in 2023. For Willow, we're guiding to $100 million-$400 million of incremental spending with the higher end of this range, assuming that the project is sanctioned this year. We're happy with our strong 2022 results, which would not be possible without the hard work and dedication of our talented workforce. We are well positioned to balance investing in our deep and diversified portfolio this year, while also continuing to return capital to our shareholders. That concludes our prepared remarks. I'll now turn the call back over to Phil. Great. Thanks, Bill. As a reminder, just before we go to the Q&A, we ask that you please keep it to one question and a follow-up. With that, Michelle, we're ready to turn over to you for Q&A. Thank you. We will now begin the question-and-answer session. If you have a question, please press star one one on your touch tone phone. If you wish to be re-removed from the queue, please press star one one again. If you are 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 one one on your touch tone telephone. Okay. Our first question will come from Neil Mehta with Goldman Sachs. Your line is now open. Yeah. Good morning, team, and thanks for taking the time. Our first question is around Willow, and recognize, there's still some gating factors to getting it towards FID, but it seems to be moving the right direction. Just talk about how you're thinking about that project, what remains outstanding to get it to FID? Then any thoughts on costs as well? The latest number we have is $8 billion all in. Is that still good to go by, or how should we think about that? Hey, Neil, this is Andy. Yeah. There's been a lot of moving parts on Willow since the last earnings call. Let me just step through where we are in the overall approval process, and then I can clear where we are with CapEx and scope. With the approval process, I think most people saw that the final supplemental environmental impact statement was released by the Biden administration earlier this week. That should be published in the Federal Register in the next day or so, and then that starts the required 30-day clock before the ROD can be issued. Given the Biden administration's commitment to the Alaska Congressional Delegation, we then expect to receive that ROD in the first week of March. Once the ROD has been issued, our focus for 2023 will be to immediately initiate gravel road construction, ramp-up fabrication and supply chain activities. We're gonna need to take a look at the ROD in some detail, but assuming it's consistent with the BLM's three-pad preferred alternative and there are no new unworkable restrictions added, we would then proceed to final investment decision. Switching to CapEx, 2023 is very dependent on the ROD timing. As Bill mentioned, we've given a range. With the ROD timing, any resolutions of outstanding issues, what we're guiding is about $100 million-$400 million of incremental spend in 2023. In terms of the total project costs, we have recently gone out to market to update our cost estimates, and we have seen some inflationary pressures. We've also refined the scope, including an update to accommodate the BLM's three-pad preferred alternative. We're in the process of finalizing our cost estimates, but we'd anticipate the AFE to first production to be in the $7 billion to $7.5 billion range. The increase versus the update we provided in 2021 is split about 50/50 between inflation and scope refinement. Hopefully, that gives you a pretty good update on where we are with Willow. At our April Investor Day, we're happy to go into some more details. That 7.5, Andy, compares to the 6 before, it sounds like. Be the apples to apples. That's correct. That's an apple. Okay. That's great. The follow-up is just around return of capital. Last year was an outstanding year, 53% back to shareholders and of the cash flow. The guidance this year, $11 billion, also implies a very strong return of capital number. I know we often anchor to the 30% or greater than 30%, but is the message we should be interpreting that there's a new normal here around return of capital and the bar has been reset higher? No, we're not trying to message that, Neil. What I remind people is the 30% commitment that we have is a through the cycle commitment. We've also told the shareholders that when prices are above our mid-cycle price, you should expect higher distributions for the company, and that's consistent with what we've done over the last number of years. As we look today at where the strip is trading, where the regional differentials are at, you know, we've kind of picked $11 billion at an $80 price deck. That's how we're going into the year. It represents about 50% of our cash flow. Again, that 80 is well above our mid-cycle price and our commitments tied to a through the cycle kind of mid-cycle price call. It just represents that we are constructive with the environment that we see today, and we expect the prices to be above our mid-cycle price call, which should inform that the distributions would be above that 30% as well. Great. Thanks, Neil. Next question. Our next question will come from Doug Leggate with Bank of America. Your line is now open. Well, thank you. Good morning, everyone. Happy New Year, guys. Sorry, Doug. Bill, I think I didn't actually get to write down the numbers quickly enough. Could you just go through again the expected cadence of the three LNG projects? Full disclosure, I think we had expected a slower pace on Sempra or on Port Arthur, I guess. Can you just walk us through how you expect that cadence to look, please? That would be really helpful. I've got a follow-up, please. Yeah, sure, Doug. I'm happy to. Let me just kind of start with a bit of a high-level view. We've put the bridge from 2022 to 2023 in our documents for today. I'll start with kind of our exit rate. If you look at our fourth quarter base capital spend, that would annualize out to about $8.9 billion, with a low single-digit inflation rate versus 2022's exit rate. We've got some phasing in Norway and the additional incremental emissions reduction that gets you to about $9.2 billion, which is midpoint of our guidance. Really the incremental spend is on LNG projects in Willow, and that gets us to $11 billion midpoint of the guidance range. I think that the primary issue here on cadence is likely the front-end nature of Port Arthur LNG spend, which really the market had no way of knowing. As you'll recall, Sempra's communicated a phase one gross cost of $10.5 billion for the EPC, on top of which there's gonna be owners costs and other miscellaneous costs to bring the project online. Doug, the project currently lining up debt financing for a portion of this spend. You roll that all together, we would expect our 30% share of the net equity capital to be just under $2 billion over the five-year investment period. The front-end nature of the equity component is going to result in over half of that $2 billion occurring in 2023. That's what we've included in our 2023 capital guidance. The project is still waiting on FID, but we do expect that in the first quarter, and we will be talking to more about this in April. If you've been modeling a more ratable spend over five years for Port Arthur, that would be about $400 million in 2023 or about $600 million-$700 million less than our guidance. I think that that might be some of what you're seeing in kind of the LNG spend. I think it's obvious with over half of the Port Arthur spend in 2023. Obviously, the spending 2024 and beyond is going to be less than a ratable rate. I think that's probably the main gap in LNG spending that you're seeing. That's really helpful, Bill. You're exactly right. We were not expecting half, but of course, that means that the other half is, you know, probably more ratable, I'm guessing, over time. That's really helpful. My follow-up is a favorite topic of mine, Bill. I hate to get in the weeds here, again, another sizable deferred tax credit this quarter, although it does kind of look a little bit more like you're, you know, almost like you're moving to a new normal based on your U.S. spending, you know, thinking IDCs and things of that nature. You know, am I thinking about that right? Should we be expecting a sort of ratable deferred tax credit going forward in your cash flow? I'll leave it there. Thank you. Well, yeah. Deferred taxes were a source of a $500 million in the fourth quarter, Doug, and we had a source of about $700 million in the third quarter. Now the source of those deferred taxes is primarily due to the impact of intangible drilling costs and generating deferred tax liabilities now that we're in a U.S. cash tax paying position. Now, as we look at 2023 at current investment levels, we'd expect deferred taxes are going to continue to generate a source of cash on a normalized basis. I'd expect the deferred tax source full year to be lower in 2022. Now, we are in a U.S. cash tax paying position for the full year, we also utilize all significant U.S. net operating losses, NOLs, and EOR credit carry forwards in 2022. That utilization generated a larger source of cash last year compared to what we're gonna be seeing in 2023. Again, really helpful. Thank you. Thanks. Next question. Our next question comes from Stephen Richardson with Evercore. Your line is now open. Thank you. Ryan, there's been a lot of focus on the Permian Basin of late, certainly from an industry perspective. You know, not all of it has been, you know, good, we'd say. I'd love if you just took a moment and help us differentiate, you know, Conoco's asset in the basin, what you're seeing from your asset. Certainly some of the performance speaks for itself. I'd love if you could address that today. Yeah. Thanks, Steve. Let me make a couple of comments, and then I'll turn it over to Nick for maybe a couple of his thoughts in a bit more detail. You know, we're not worried about, you know, our long-term development plans in the Lower 48. We see durability to our plans, and I know there's been a bit of noise about productivity and length and durability. You know, we've been up a long time. We know what we're doing after the acquisitions that we made over the last year and a half. You know, I don't have any concerns about the durability, the length, the efficiency of our program. Maybe I'll let Nick provide a few more detail and color on that comment. Good morning, Steve. Yeah, I'll give a little more color on that one. Maybe start with just the well performance that we're seeing versus the type curves. If you look at our 2022 development wells, they've been performing, you know, slightly above the curve expectations across all 4 basins, including the Permian Basin. That strong performance reinforces and validates the development plans that Ryan just mentioned, which is our focus on maximizing returns and recovery while minimizing the future interference. If we step back in time, you know, we've been incorporating a lot of the learning curve from our developments over the past three to four years. In fact, you know, when you look at our accelerated learning curve, we've drilled the most horizontal wells in the Delaware and Midland Basin more than any other company. When you combine that data along with our significant operated by others portfolio, and then the learnings in our mature development in Eagle Ford and the Bakken, that's really helped us hone in on the best development approach of the stack. In summary, Steve, if you look at our production performance, you know, at or slightly exceeding type curve expectations combined with the development strategy, we're very confident in our long-term outlook for these assets, and we'll update you more at AIM. That's great. Thanks. I really appreciate it. I mean, if I could, just one quick follow-up, Nick. Could you just address the 25,000 acreage of swaps and coring up that you mentioned this morning? I would, you know, I mean, one of the questions, I guess, is. Steve. Oh, sorry. You got me? Steve, you're breaking up. Sorry. No, we didn't catch your question. Thanks. Sorry, it must be the phone line. Can you try again? The question is on the yeah, the 25,000 acres on the core-up. I just wondering if we could address, Nick, how much more to go is there on that side, and where are you just looking at the checkerboard of the, of the map down there? Steve, maybe I'll just go back for the whole audience on what we've done in that space. We've been very focused on the acreage optimization, as you mentioned on trades and swaps. Last year, we completed 15 trades, and that gives us a total about 25,000 acres since the Concho transaction. A couple points I just want to address. These core-ups have doubled the average lateral length of more than a year's worth of inventory. That's at our current level of drilling activity. The ability to drill extended laterals greater than one mile can reduce our cost of supply by 30%-40%. That's significant. To put that in perspective, Steve, our quality position in the Permian has an inventory with roughly 60% of our wells that are greater than two-mile lateral, 60%. If you look at 1.5 miles or greater, that's an additional 20%. That's a robust inventory that we have out there. If you, we will continue to, as you mentioned, to core up in 2023 through acreage and swaps there. We've got a significant, deep, robust inventory with those longer laterals. Thanks so much. Great. Thanks, Steve. Next question. Our next question comes from John Royall with JP Morgan. Your line is open. Hey, guys. Good morning. Thanks for taking my question. My first question's just kind of a broad one on the upcoming Investor Day. You guys haven't done one for several years. Anything on what we can expect from the presentation in terms of the longer-term plan or maybe a breakdown of certain assets or projects? Just any color on that would be great. John, thanks. We, I think we'll show why we're pretty excited about where the company's gone. We've got a better plan. It's, you know, the strategic and the financial plan of the company got better duration, better depth, and we'll show that to you what it means for the company for decades to come. I mean, we're pretty excited about where it's at. We'll do a deeper dive into where we're at in the Lower 48, our global portfolio, as well as the LNG business that we've been developing here over the last year and a half. Look forward to sharing kind of our excitement around our plans, where it's headed, and just the quality of what we're doing, both strategically and financially. Great. Thanks, Ryan. Just a question on the guidance for 1 Q production, a little bit below the full-year guide, and you guys called out the maintenance number there. Maybe just some color on would be helpful on how you expect production to phase in throughout the year. Should we expect it to be more back-end loaded, or maybe more towards the middle given the lighter one Q? Yeah. Hey, John, it's Dominic here. Yeah, I think as Bill remarked, we do have above normal seasonal maintenance in the first quarter. That's at Qatar trains 6 and 7, but also Eagle Ford Sugarl oaf, our stabilizer facility down there. We've actually been preparing that for a bit of expansion. That, that explains the Q1s rate. Thereafter, you know, our expectation is that each quarter will be around 2%-3% year-on-year growth. That's, that's really our base case. Thank you. Great. Thanks, John. Next question. Our next question comes from Jeanine Wai with Barclays. Your line is now open. Hi. Good morning. Good afternoon, everyone. Thanks for taking our questions. Our first one. Good afternoon. Good morning, Ryan. Our first one may be following up on Neil Mehta's question on the cash return for the year. We realize that it's still early in the year, but you've already declared the VROC for the first part of the year. How are you ultimately thinking about the split of the $11 billion of total cash return between cash and buyback? Is the buyback more of a function of your mid-cycle price assumptions? Yeah. I think the majority of our buyback is tied back to ratably buying our shares in our mid-cycle price assumptions. We try to ratably buy some shares as we go through the year. We buy some variable shares depending on where we see the market. I would say as we're going into 2023 right now, we're thinking roughly 50/50% between cash and shares in terms of the absolute return back to the shareholders. The $11 billion would be split roughly $5.5 billion and $5.5 billion. That's our thinking as we start the year, we'll watch the commodity price and where things develop as we go through the course of the year. Okay. Very helpful. Thank you. We'll pencil that in. Our second question, sticking with 2023, but moving to CapEx here. We noticed that there's about $500 million-$600 million of incremental inflation included in the budget versus 2022, and there's some noise with the categorization of the Port Arthur spend. It looks like Lower 48 will comprise about 60% of total CapEx for 2023. Our question is, how much of that $500 million-$600 million of incremental inflation is in the Permian and Lower 48 versus maybe other parts of your portfolio? What's your estimate on how inflation ended up by region in 22, and maybe any assumptions that you have in your budget for 23 inflation? Thank you. Let me take a quick high-level shot. I think if you're kind of looking at exit rates from 2022 going into 2023, it's kind of low single digits. If you're kind of looking at what's the increase annually year-over-year, it's more like mid-single digits. I think the difference we're seeing this year maybe relative to last year is we see that mid-single digit inflation applying across the whole global portfolio, and it's slightly higher in the Permian to the question that you asked. Yeah, We're seeing some categories of spend that are key to the company actually start to plateau and maybe even roll over a little bit. One we're watching pretty closely is OCTG, you know, tubulars. Some of the raw materials that are going into making those are starting to come down and deflate a little bit. We're starting to see that category of spend sort of roll over. We're seeing the rate of increase kind of in the onshore rig market start to lessen a little bit, which is good. We need that. When we kind of wrap all those categories of spend together for the company, it kind of manifests itself in an annual year-over-year inflation in the mid-single digits. Great. Thank you. Thanks, Jeanine. Next question. Our next question comes from Ryan Todd. Apology, Todd with Piper Sandler. Thank you. Maybe a follow-up on the Permian. I'm not sure if you mentioned this earlier, but can you talk a little bit about what is assumed in your current guidance, I guess, both capital and production for the year? It sounds like the guide assumes kind of flat activity levels in the Permian versus late 2022. Is that correct in terms of how we should think about activity levels, and how should we think about the trajectory of production in the Permian over the course of 2023? Yeah. Ryan, this is Nick. Yeah, let me walk you through that. As you mentioned, we've assumed a level-loaded steady-state program for 2023 based on that second half of 2022 for rigs and frac crews. You know, the focus for this year will really be around improving capital and operating efficiency. Now, we do expect some modest growth in partner activity as the year progresses, and then we have some larger operated pads that will come online in kind of 2Q, 3Q. Our Lower 48 plan will deliver production in that mid-single- digits, with the majority of that growth weighted to the Permian. Now, with respect to the profile shape, it'll be kind of mid to back-end weighted in 2023. As we talked about, Dominic mentioned this, we do have that Eagle Ford, Sugar loaf stabilizer maintenance that's going on. Actually, I'm pleased to mention that the turnaround that Dominic referred to was five days, and we completed that successfully in January. We will have a little bit of brownfield modifications on that stabilizer through mid-February as well. Then I'll mention too, kind of month- to- month, we'll have, you know, wells, a little bit of lumpiness, but in the back end, we'll be weighted in 2023 for a production profile. Great. Thank you. That's very helpful. As we think about your emerging kind of global gas strategy, how should we think about your approach to the gas portfolio on these projects? Should we expect the majority sold under long-term contracts with a percentage held for spot sales? Will you look to correspondingly build out your global gas trading capabilities similar to your European peers? Maybe as you're out marketing these volumes, are you seeing anything to comment on in terms of the environment, whether global gas just tightness is helping, you know, sales pricing out there? Any high-level views on your global gas strategy there would be great. Yeah, sure. This is Bill. I'll just start with, you know, we've got a really strong understanding and presence in the LNG market and have had for several years. We're regularly selling spot volumes into Asia off of our AP LNG venture, we do think that Europe's going to be a long-term market for U.S. Gulf Coast. You will have seen where we recently secured regas capacity in Germany, which we're really happy about and excited about. We're looking at the best options in terms of long-term placement, but these are 20-year projects off the Gulf Coast. We think that the long-term strength of international pricing, relative to U.S. gas is gonna be pretty interesting. That driver and that strength in LNG, we think is gonna be driven by its role in energy transition and reducing carbon emissions. As you see us build out our LNG portfolio over the next few years, we may take some longer-term contract decisions then there. Right now, we're not really disclosing where we're at for competitive reasons in terms of how we're developing that market. Great. Thanks, Ryan. Michelle, next question. Our next question comes from Devin McDermott with Morgan Stanley. Your line is now open. Hey, good morning. Thanks for taking my questions. I wanted to first follow up on some of the CapEx questions earlier. You laid out the $1.6 billion-$2 billion of spending this year on major projects, and you talked with some good detail about Port Arthur. It's not necessarily ratable across the projects, but when you put it all together, I was wondering if you could talk about how you see the magnitude of major project spend evolving or changing over the next few years outside of Port Arthur. What are some of the key moving pieces that we should be thinking about across the projects that could move that number higher or lower? I think we tried to explain kind of a bit about the front-end loading on the Port Arthur project. You ought to expect that's gonna come down, you know, as you look into the two, three, four years. Some of the other moving pieces, you know, if the commodity price environment supports it, we wanna see some ramp in our Lower 48 activities up to our optimized plateau across the various assets. You'll see Willow ramping up if we get an adequate project approval from the federal government. That'll come in. Obviously, there's some inflationary forces as well as we think about where it's going. There's a lot of moving pieces, but you know, that's kind of how you should think of the different pieces that we're looking at as we kind of think about the longer-term nature of the capital. We'll be prepared to talk about that at AIM in our panelist meeting coming up in April. Got it. Makes sense. Just a quick follow-up on NFE and NFS. Are those fairly ratable over the next few years? Any additional color on those projects specifically? Yeah. This is Bill. You saw us in the fourth quarter make our initial catch-up payment on NFE. Then you should expect that those projects are funding through the next couple of years. Okay. Thank you. Thanks, Devin. Next question. Our next question comes from Paul Cheng with Scotiabank. Your line is now open. Hey, guys. good morning. Good morning, Paul. Can I go back into Permian? You guys talking about earlier in your prepared remark on the inventory for the two-mile well. I think the industry also think that the 3-mile may actually work even better. Can you talk about that? I mean, based on where you are today, what's the inventory that on the three miles and whether that there's a lot of opportunity there. You also don't know whether there's an update, you can provide on the plateau, longer term plateau rate that you expect for Permian and that when that you will be able to get there. That's the first question. The second question that, I have to say, I was super impressed that your Bakken production is actually flat sequentially from the third quarter. Given that the winter storm hit them so severely. I mean, out of the 27,000 barrel per day, I mean, how much is on the Bakken, and how you'll be able to get it so that you can actually get it flat? This is Nick there. I'll just kind of walk you back through kind of the inventory related to our longer laterals as we've done the core up. Again, you know, over 60%, Paul, is greater than two-mile laterals, and that does include the three miles as well. That's a significant part of our inventory in the Permian Basin. We've actually, this last year in 2022, brought on, I think, more than 30 wells that are in the 3-mile category and are seeing very encouraging results. We'll continue to execute those as we go forward. As we continue to core up and do swaps, that'll give us more inventory as well for that longer lateral execution. You will see probably cost of supply of around 30%-40% reduction as we drill those longer laterals. Yeah, Dominic. With respect to plateau. I'm sorry, Dominic. For the 60% you're talking about two mile plus, what percent of them is actually in the three miles category? Yeah, Paul, I don't have that in front of me at this point in time, but let's wait till AIM, and I'll give you a further update on that overall three-mile categorization. Okay. Okay. On your second part of that first question, related to plateau. Again, we'll update the group on the overall Permian plateau, Eagle Ford and Bakken, at the April 12th investor day. Obviously, there's a number of factors that go into that. The macro, maintaining execution efficiency, continuing to capture the learning curve and capital efficiency. You know, right now with our mid-single-digit growth, we feel that's right in line with what we've communicated earlier. Your second question was related to weather. Glad you brought that one up. Again, Bill, you had mentioned 27,000 barrels a day for fourth quarter 2022. Just a quick breakdown on that. That's 13,000 for Permian, 10,000 for Bakken, and then less, 4,000 in Eagle Ford. I think you asked, kind of maybe quarter to quarter, Q3 to Q4. You're right. It was flat. We're at 96,000 barrels equivalent per day. Paul, the main driver for that is what we had some really strong operated wells that carried into Q4. Then on the operated by others, we had some larger pad projects come online in Q4 that offset that weather. Thanks, Paul. Next question. Our next question comes from Robert Brackett with Bernstein. Your line is now open. Hey, good morning. A bit of an old school question on your reserve replacement. Historically, LNG FIDs were big blocky chunks of gas reserves going into the portfolio. That's not really gonna be the case for a midstream asset like Port Arthur. I'm curious, can you go into a little more detail on the oil/gas mix shift on the reserve replacement and how to think about the cadence of LNG coming in through that? Hey, Bob, it's Dominic here. Let me talk a bit about that. I mean, we're obviously very pleased with our organic reserve replacement ratio this year, 177%. The real drivers for that, I mean, obviously the LNG, we did have some booking there from NFE as we commenced payments on NFE. We also saw some bookings from AP LNG performance and from for some project advancements in Norway. Our international portfolio was contributing. The main area this year was actually in the Lower 48 development program, and that's particularly in the Permian, and that included an increase to our PUD bookings by extending the proved area we established by reliable technology, which is an SEC term, so it's consistent with SEC requirements. Basically, we have a very extensive geoscience and reservoir engineering data set across the Permian now that allows us to support that. You know, and you'll be aware, Bob, just the rigor and the process and the controls governing the reserves booking process. You know, this further demonstrates the depth and quality of our Lower 48 inventory. That's really the story this year. Going forward, you know, we'll continue to see bookings in the Lower 48. We'll see bookings in Alaska, obviously, with pending FIDs. Then we'll continue to see some LNG bookings as well, particularly on the resource projects, as we call them, NFE and NFS. You're absolutely right what you're saying about Port Arthur. I think you'll see a mix going forward. As it stands now, you know, our Lower 48 represents about 46% of our reserves, the remainder across international. Yeah, we are certainly appreciating the performance of our sort of diversified portfolio around our reserves bookings. Thanks for the question. Very clear. A quick follow-up on the portfolio. Great opportunities in 2020 to rebuild the portfolio. 2021, again, in the Permian. 2022 was very much an LNG-themed year. Is the star of the show for 2023 Willow FID? How do you think about the portfolio where it stands today? You know, we're pretty pleased where the portfolio is at. I mean, Dominic did a good job of kind of going across the globe. I think we spent a lot of time over the last five years really coring up the portfolio, really focused on getting it as low cost of supply as we can, getting the margins as expanded as we can, leading to kind of the returns and the productivity that we're seeing today. We're just hyper-focused on making sure the efficiencies are there and the returns are there. Pretty happy with where we stand today. As you rightly note, Bob, we're leaning in a bit on some of these mid and longer cycle projects because we're just very constructive. The world's gonna need this oil. It's gonna need low greenhouse gas and emissions intensity oil. It's gonna need low cost supply oil. That's what we're all about. That's what we're doing in our portfolio. Most recently leaning in on the LNG side because we think the world's gonna need this gas as part of the transition that we're going through. Thanks. Very clear. Thanks, Rob. Thanks. Next question. Our next question comes from Neal Dingmann with Truist Securities. Your line is now open. Good morning, all. Thanks for the time. My question is around just production and maybe around the Permian. You know, I'm just trying to get a sense of you've got, I think, the 1%-4% type overall growth. I'm just trying to get a sense of expectations for the Permian, if you would back out obviously what's going on up in Alaska. Have you all clarified or, you know, kind of said what the expectation is at? Second part of that, it sounds like it's gonna be pretty. That growth you expect in the Permian, I assume it would be pretty linear for the entire year, if you could comment on those two things. Yeah, Neal, this is Nick. Again, for the Lower 48, we'll deliver production growth in that mid-single digits. The majority of that growth is gonna be weighted to the Permian. With respect to the profile shape, it's gonna be more mid to back-end weighted. We've got some operated larger pads that are gonna be coming on kind of the mid-year to third quarter. Then we've got modest operated by other growth going through the year with more of the kind of the back end for Lower 48. Does that help? That's very clear. Just 1 last one. You all are obviously in a fantastic position financially. You've done some, you know, really positive M&A deals in the past, I think actually in the last two years, among the best that I've seen out there. You know, my question when it comes to M&A, how do you view the landscape today? I I mean, obviously prices are up. Maybe, you know, commodity prices are up, so maybe expectations are higher. Just wanting overall, how do you view the M&A landscape? Yeah. Thanks, Neal. I mean, we're in the market every day. We're, you know, we're trading. We're thinking about the market. We see what's going on every day. We think, you know, generally there's more consolidation that's needed in our business. It's pretty tough at these kinds of elevated prices, you know, we watch it every day. I think it, we've been pretty clear and consistent about our financial framework and how we think about M&A. That has not changed. As we think about cost of supply, we think about assets that we can make better or can make our company better or improve our long-term plan, we know the assets that we like, we watch those constantly. You know, it's a tougher market at these kinds of prices to transact. Some of the transactions that have occurred this year, we've looked at them, we've seen them, we've watched them. They just don't fit our framework. They, they don't make us a better company. Thanks. Very clear. Thank you all. Next question. Our next question comes from Paul Sankey with Sankey Research. Your line is now open. Hi, everyone, thanks as always for the great disclosure. In fact, you guys have been leaders in the industry in many ways, starting with the really the first capital discipline cash return framework. You're in position to make acquisitions at the bottom of the cycle, now you're saying that you're leaning in, is the word, [Brian Rickmers], to sort of megaproject development using an $85 oil price assumption. Is this an indication that the industry is going to have to follow you? Or is it more that these major opportunities have come up in 2023? Further to the $85 price assumption, could you just remind me what gas price assumption you're using? What would you cut if oil prices went to, say, $60 over the course of the year? Thanks. Yeah. Thanks, Paul. No, I think we're. Yeah, I think our view pretty constructive over the next number of years and through the decade. The time you wanna do some of these big projects are the front end of the cycle. We probably are a bit unique given our global diversified portfolio. We have opportunities in Alaska and Norway, in the Far East, in the Middle East. You know, we look at those, make sure they fit our framework around cost of supply and what we want to go invest in. As we look forward, we believe, you know, now is the time to be doing these projects, which is why you see us leaning in on the LNG side. We're constructive on the gas and why we, you know, we're moving forward with our little project up in Alaska. I'll make a side comment. You know, this is what the administration has asked us for. U.S. production that's low GHG emission production. This is exactly what the administration has asked us to do as an industry, and that's what we're trying to do as a company. Now, you know, looking forward, I think we'll talk at AIM about where we think mid-cycle price is, and frankly, we think it's probably come up from where we've been over the last five, six years. We'll show that to you at AIM. Finally, to your last question. Yeah, we've set a cash return target at $80 WTI, $85 Brent, and I think it's $3.25 Henry Hub. Those are the assumptions we made that underpin the $11 billion. The price would have to go down considerably. I mean, you said, you know, into the 60s full year average, I think, before we would talk about changing that. We're prepared to use our cash on the balance sheet to fund these projects. That's why we have that cash. That's why I have that financial strength and that resilience. We're happy to use the cash if we need to. I think it's resilient across a broad range of prices in terms of what we've established as our distribution target for the year. Great. Ryan. Thanks. Following on the leadership, you were instrumental in the export ban being lifted. Can you talk a little bit more about Willow? There's obviously some, you know, but you mentioned low GHG. Can you talk a bit about how it fits alongside what you just said about the administration asking for this in terms of its environmental footprint? Thank you very much. Yeah. No. It's, it'll be some of the lowest GHG emission, production in the world, less than 10 kilograms per barrel. It's, you know, it's gonna be something that, we believe is what the world needs right now as we go through this energy transition. We need more oil and gas. We need more base load to, supply the world reliable and affordable energy. Coming from the United States and North America broadly and in general is the right thing to be doing right now. It comes from companies like ours that have, over 40 years experience on the North Slope. We know how to do this. We know how to do it responsibly, and all the stakeholders support it, including the native community on the North Slope, the Congressional Delegation, the union labor leaders who need this, opportunity for employment in Alaska. There's full alignment behind what we're trying to go do there. It's just the politics in D.C. Thank you, sir. Thanks, Paul. Michelle, I think we have time for one more question. Our last question comes from William Janela with Credit Suisse. Your line is now open. Hey. Good morning. Thank you. I wanted to ask on the pace of CapEx as you move through this year. I'm wondering with all the major project components, if there are some quarters that might be chunkier than others or if there are any other timing or seasonal factors to consider. Any guidance you can give there in terms of how to think about the progression of quarterly spending for some of those bigger ticket items as well as the base business, would be very helpful. Thanks. Thanks, Bill. It's Dominic here. The way it's gonna work out, we think, is pretty ratable through the year. You know, we've got consistent activity in the Lower 48 level loaded. You're right that there is gonna be a bit of lumpiness around some of the project spend. For example, in the first quarter, we do have a modest upfront payment in Q1 on Port Arthur, assuming that's sanctioned. You know, if you are running a fairly ratable profile, that would, that would be a good estimate. Great. Thank you. Okay. Great. Thank you. operator, I think, this would wrap up the call. Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.