All right. Well, good morning, everyone. My name is Phil Gresh. I'm the Vice President of Investor Relations for ConocoPhillips. On behalf of our entire executive leadership team, it is my privilege to welcome you to the 2023 Analyst and Investor Meeting. I'm gonna quickly review today's agenda. First, Ryan Lance will begin by reaffirming our durable returns-focused value proposition, and he'll present an overview of our updated 10-year financial plan. Dominic Macklon will then describe our differentiated strategy and portfolio, which forms the foundation for this plan. Next, you'll hear bottoms-up details from the rest of the leadership team. Andy O'Brien will talk about Alaska and International. Bill Bullock will discuss LNG and Commercial, and Nick Olds will talk about the Lower 48. Bill will then come back up and provide a summary financial detail of the plan, and Ryan will give some closing comments. We'll have a short 10-minute break before the Q&A. We expect the presentation to take about 75 minutes. We'll be making forward-looking statements today. Actual results could differ materially from the projections you see. The risks and uncertainties in our future performance are described in the cautionary statement shown here and in our periodic SEC filings. We'll also use some non-GAAP financial measures today. Reconciliations to the nearest GAAP measure can be found in the appendix section. Again, welcome. Thank you for your interest in ConocoPhillips, and it is now my pleasure to turn the meeting over to our Chairman and CEO, Ryan Lance. Thank you, Phil. Well, good morning and welcome. Welcome back, I guess I should say. I wanna extend my welcome and thank you all for joining us today for our 2023 Analyst and Investor Meeting. It's been a long time. We appreciate the opportunity to speak to you today, and we appreciate certainly the interest in the company. Boy, how time flies. It's been a little bit over three years since we were last here, and certainly a lot has changed. We've been through a global pandemic where we saw the biggest ever drop in global demand that we've seen in this industry. Then just as demand was starting to recover, Russia invades Ukraine. Now energy security and affordability are at the forefront of the conversation. You fast-forward to today; the macro environment is really quite uncertain as central banks try to tamp down inflation without triggering a recession. You can count on one thing that has not changed, and that's ConocoPhillips's relentless focus on value creation. It's guided by our foundational principles, our financial priorities, and our talented workforce, which you'll hear all about today. The bottom line, we're a much stronger company today than we were in 2019. We have a better portfolio, we have a stronger financial plan, and we look forward to sharing that with you. Before I get into the nitty-gritty details of the business today, I wanna step back for a minute and say, and answer that question, why are we here? Really it's quite simple. Why we believe ConocoPhillips remains the must-own energy company in your portfolio. I say that recognizing that the macro environment is quite uncertain, we're built for this. Let me tell you why. First, we have the conviction to share with you a 10-year plan, a plan that has been battle-tested through the cycles, one that has delivered and will continue to deliver improving and competitive returns on and of capital to all of our shareholders. Bill will tell you a lot about that today. Second, we have the deepest, most durable and diverse portfolio of any of our E&P peers. Dominic, Nick, and Andy are gonna show you the deep duration of our portfolio. Third, we're well-positioned to play in the upcoming energy transition. We have a relentless focus on our triple mandate, and that is including an acceleration of our GHG emission reduction initiatives that Dominic will share with you today. You know, I've been the CEO for a little bit over 10 years. Back in 2015, we took our team off-site, and we wanted to describe to ourselves what the best E&P company would look like. What kind of portfolio, what kind of balance sheet, what kind of value proposition. Then we set out to go build that. I could tell you today we've done that. We're resting, and we're constantly trying to improve not only our portfolio but our financial plan. Yet today, we think they're the best in this business. Let me spend a few minutes talking about our returns-focused value proposition, and that's core to how we think about running the company. The most important thing about this slide has not changed. First, there's our triple mandate, that ensures that everything we do underlines with the base realities of this business. We're committed to meeting today's energy pathway demand while delivering superior returns on and of our capital. We remain focused on delivering our net zero operational emissions ambition. Second is the foundational principles. It's about balance sheet strength, peer-leading distributions, disciplined investments, and ESG excellence. Third, our foundational priorities, our financial priorities. Again, these haven't changed since we rolled them out over seven years ago. In fact, they've only been further validated by the cycles that this business has been through. Finally, underlying all of this is our unwavering commitment to sustainability and responsibilities, including engaging with a high-performing, diverse workforce who make all of this plan possible today. It is this philosophy and this commitment that has anchored the continuous improvement that you've seen at ConocoPhillips since our strategy reset in 2015. We have streamlined our portfolio through acquisitions and divestitures to create an asset base that has significant low cost of supply resources. You're gonna hear that term, low cost of supply, a few times today. We kinda like it. It's a bit of our Northern Star. I probably should have checked what the over-under was on how many times we would say that, but I'm sure a few of you are keeping track. It's that portfolio that is really driving the cash flow growth and the returns growth at our mid-cycle price of $60 WTI. The proof point, history shows that we are stronger, a bigger resource base, a better balance sheet, and we have grown this company over the last four years competitively. We've done this while being a better environmental steward. It's our confidence in this framework that allows us to give you an updated 10-year plan, and it keeps getting better. What is our outlook for the next 10 years? Here's our 10-year plan on a page. Should look very familiar to you, what we showed you in 2019. The punchline is that we can deliver durable returns and cash flow growth for the long term. This is not just versus industry, but versus the general market. Point one, we expect continued ROCE improvement from our mid-teens level today at a $60 WTI, and we're committed to compete against the top quartile in the S&P 500. Point two, we expect top quartile ordinary dividend growth, and again, that's at $60 WTI, and we provide full upside to a higher priced environment. Point three, we have the distribution capacity of greater than 90% of our market cap, and we're not done there. Again, you get higher market cap and distribution upside with a higher-priced environment. Point four, we have a free cash flow breakeven of $35 per barrel. Finally, we have line of sight to 6% CFO growth and 11% free cash flow growth. As I said in 2019 and again in 2021, we challenge any other energy company to show you this kind of a plan with this kind of duration. With that, let me introduce Dominic, and he'll come up and talk to you about how our strategy and our plans fit this 10-year plan. Dominic. Well, thank you, Ryan. Good morning, everyone. It's very good to see you all. I'm very pleased to have this opportunity to further demonstrate why we believe this 10-year plan reflects an industry-leading value proposition. Our strategic objective remains very clear: to deliver superior returns through the cycles. That's easy to say, but it's more difficult to do. It requires strategic clarity, conviction, and disciplined execution. It's our strategy that powers our returns-focused value proposition. Our strategy can be summarized across three key dimensions. First, how we allocate capital. We have to be experts at the allocation of capital. This is the foundation of our strategy. The foundation of our capital allocation is our continued commitment to disciplined reinvestment rate. That's fundamental. That discipline, together with our relentless focus on cost of supply, drives both our returns on and of capital. Second is the portfolio that we choose to have. Through our acquisitions and portfolio management, we have created a differentiated resource portfolio that is deep, durable, and diverse. We have the leading Lower 48 unconventional position, and that's complemented with really premium assets in Alaska and internationally. Third, how we play a valued role in the energy transition. We were the first U.S.-based oil and gas company to declare a Paris-aligned net zero ambition for our operational emissions. We're accelerating our GHG intensity emissions reduction target through 2030. We have successfully grown our LNG portfolio, a fuel that is crucial to provide reliable lower carbon energy for the long term. We are continuing to evaluate potential new low carbon business options in hydrogen and carbon capture. I will talk briefly to each of these three areas, starting with our capital allocation framework and our commitment to a disciplined reinvestment rate. As many of you know, we rolled out returns focus value proposition in 2016, and at the time, the industry was overcapitalizing to drive production growth, but at a low return of capital employed and without competitive returns of capital. We broke rank. We were the forerunner with our strategy reset, and as you can see, this changed the way we look at the world. From 2017-2022, our reinvestment rate was nearly half that of the prior five years. This has been the foundation for our track record of peer-leading returns that Bill will talk to shortly. This philosophy is here to stay. At $60 WTI, our reinvestment rate averages around 50% over the 10-year plan, and it remains below 60% throughout, just as it has been over these past five years. This is while driving approximately 6% CFO growth over the decade. With ConocoPhillips, you get competitive returns of capital plus durable CFO growth. It's our commitment to a disciplined reinvestment rate that underpins all of that. Next, I wanna talk about our low cost of supply framework. I don't know how many times we've said that now, but there's gonna be more coming. We first introduced this in 2016 as part of our strategy reset, and when it comes to capital allocation, as Ryan mentioned, this remains our north star to this day. As a re-reminder how we actually calculate this, we build up to this for every asset, normalize around what price is required to achieve a 10% forward rate of return. It's critical to highlight this is a fully burdened metric with everything taken into account. Our allocated G&A, everything, the kitchen sink included. This helps ensure our investments make a true economic return even in the down cycle and manifest crucially as improving ROCE at mid-cycle and above. It's entirely different to single well returns, which can significantly mislead to those bottom line returns that you're gonna see. As we showed earlier, we have updated our view of mid-cycle prices from $50-$60 WTI. However, that does not mean we have changed our less than $40 cost supply standard to drive that discipline in the company. Just as we remain committed to a disciplined reinvestment rate, so we remain committed to our cost of supply framework. Low cost of supply wins. Now you might be wondering, and you may have asked questions in to yourself about what drives the balance between our short and long cycle investments in decision-making. For example, why don't we just invest more in the Permian? Well, after satisfying those two primary criteria I've just described, there are secondary criteria that we consider very carefully to strike that optimal balance. We believe it's very important and valuable to maintain diversity in our portfolio, including balancing short cycle flexible assets with longer cycle low decline assets, as well as diversity in product and market exposure. Our conventional low decline assets provide a really very important advantage for us today in our reinvestment rate and our resilience as well, and we want to maintain that balance. Assuming our primary criteria are satisfied first. Predictable execution. A strong track record and predictable execution is also something we pay very close attention to, particularly on our larger projects. Andy and Bill will highlight how we think about this and what we call the execution pedigree of our larger projects and for both Willow and our LNG projects. The outcome is a balanced production growth outlook with around 4%-5% production CAGR and a relatively consistent production mix. Moving on to my second focus area. On this slide, we take great pride in sharing the depth and quality of our portfolio. Now we've been providing these updates on this chart for many years. It's probably familiar to you. We continue to be the only oil and gas company to provide this level of portfolio insight. We think that takes on additional significance right now because there's a lot of questions out there across the sector around companies' portfolio inventories. On the left side, you can see we have approximately 20 billion barrels equivalent under $40 cost of supply, and that's at an average of around $32 a barrel. This would be sufficient to maintain our current production levels for more than 30 years. That's pretty deep. All those resources provide a fully burdened 10% return at under $40 a barrel. That's what makes it durable. On the right side, we show the broad geographic distribution of our production over the next 10 years. That highlights the diversity. Nick and Andy will share further about the depth and quality of our portfolio. It's a very important area for us to discuss this morning. As Ryan mentioned, acquisitions and active portfolio management in recent years have significantly strengthened our portfolio and our performance. To make clear-headed decisions around M&A, it requires the same discipline and rigor that we apply to our organic investments. That's why we continue to use a cost of supply framework to evaluate all our transactions. Particularly in the case of acquisitions, this ensures we stay focused on the full cycle economics and the bottom-line returns rather than just short-term accretion metrics. The key message on this slide is really that you can expect us to continue with the discipline and the patience that we have had around our transactions to further improve the company. For my third and final topic of this section, I'd like to address our actions and our progress to position the company to play a strong and valued role in the energy transition. We know it's the low cost of supply, low GHG intensity barrel that will win, and we are making good progress on our GHG intensity reduction. Our preliminary data for 2022 shows a reduction of greater than 40% on our gross operated emissions intensity, and that's against our 2016 baseline. With this progress, today we are announcing an acceleration to our 2030 target from the current 40%-50% reduction to a 50%-60% reduction, that's on both a gross operated and a net equity basis. Of course, these are supported by our zero routine flaring target and our methane intensity targets, these are both crucial areas for our company and for our industry. Methane and flaring represent one of four key areas we're focusing on. Andy and Nick will mention some of the practical examples of how we're reducing emissions across our assets. We remain highly committed to our net zero journey. Next, I want to share a bit about our strategic perspective on liquefied natural gas or LNG. We firmly believe LNG is going to play an increasingly crucial role in the global energy mix as a reliable and dispatchable lower carbon fuel. Let's not forget the remarkable impact gas has already made here in the U.S., where switching from coal to gas and power generation has significantly reduced CO2 emissions. While coal has been declining in the U.S., you probably all know global coal demand has been steadily growing and has yet to peak. LNG can play a similar role in Asia and in Europe and around the world. For example, looking at the full lifecycle emissions, that's the full lifecycle of U.S. LNG sourced from the Permian Basin and delivered into Germany, it offers a greater than 40% lower emissions to coal for power generation. The benefits are very similar delivered into Asia. The bottom line is the long-term outlook for global gas is very robust. Not just due to Europe's immediate goal to reduce dependence on Russian supplies, but in meeting the energy demand of a growing global population, displacing coal, and working alongside intermittent renewables. LNG is a key element of our long-term strategy, and Andy and Bill are going to share more about the strength of our LNG portfolio shortly. Which brings me to my concluding slide and the summary of our 10-year plan. At $60 WTI, our plan generates $115 billion of free cash flow available for distributions, which as Ryan said, is more than 90% of our market cap over these next 10 years. For our capital outlook, we would expect it to average around $10 billion in the $60 WTI case, delivering that 4%-5% production CAGR. Importantly, our plan remains resilient to the down cycle with an average free cash flow breakeven of $35 a barrel. We maintain full upside to the price upside, full exposure to that price upside. We don't hedge, as you know. This is all a result of the clear choices and decisions that make up our strategy. If there's one key message to take away from my section today, it would be that with ConocoPhillips, you can have your cake and eat it too. You can have competitive returns plus durable CFO growth. I'll hand over to Andy to provide more insight into our premium assets in Alaska and internationally. Andy? Thanks, Dominic, and hello everyone. I look forward to updating you today on our plans across our Alaska and international assets. This is a fantastic set of assets made even more powerful when combined with the rest of our portfolio that Bill and Nick will cover. As I step through, there are three key themes I'd like you to take away from today. First, Alaska and International provides material diversification to our portfolio. Second, this business delivers meaningful high-margin production growth. Third, our low reinvestment rate provides significant free cash flow to the company. This material, diverse, and low cost of supply resource base differentiates us from our domestic E&P peers. Nobody else has this advantage. Let's get started with cost of supply. The chart on the left shows our deep inventory of low cost of supply resource across a spectrum of asset classes. We have long life sustaining cash flows in LNG in Surmont. In the Montney, we're building our next core unconventional position. Our conventional international assets are all linked to Brent or international gas prices. In Alaska, we manage a high-margin legacy business with the next development in Willow to follow. Now, the right-hand side of this chart may be surprising to some. We expect Alaska and International to deliver a 4% CAGR of high-margin production growth at only a 40% reinvestment rate. That growth is not all from Willow. We're expanding the LNG business in Qatar with North Field East and North Field South. We intend to steadily ramp up production in the Montney, and we expect to grow our core Alaska business outside of Willow. I'll share the details of each on the subsequent slides. LNG has been a cornerstone of our portfolio for years, and we're leaning in with proven assets and proven partners. Qatargas three continues to be a star in the portfolio, supplying LNG to the Asian and the European markets. Year in, year out, QG3 delivers consistent flat production, but negligible reinvestment. The North Field expansion projects represent the next stage of our 20-year relationship with Qatar. Across the North Field expansion, we were awarded 2 million tons per year with first LNG from NFE expected in 2026. NFE and NFS are as close to manufacturing mode as you will see in the LNG industry. We anticipate our share of capital for NFE to be approximately $900 million with NFS in the same ballpark. Moving to APLNG, the strength of our Brent-linked LNG contracts delivered over $2 billion of distributions to ConocoPhillips in 2022. We also opportunistically added to our position in 2022, and we will have paid back approximately half of that purchase price in just over one year. We operate the LNG facility, and it continues to run really well. It consistently benchmarks globally in the top quartile of all LNG facilities. When Origin's sale to EIG and Brookfield closes, we'll also take over operatorship of the upstream assets, and we'll increase our working interest by another 2.49%, taking our total ownership to just under 50%. The terms of the acquisition are essentially the same as the 10% that we purchased last year. We know these assets really well. Origin Upstream has a talented workforce. We look forward to bringing our international upstream and commercial expertise to help further optimize the assets. Overall, our LNG business is a stable and predictable part of the portfolio that allows for growing long cycle cash flow generation. Similar to LNG, Surmont's another long life, low capital intensity asset. Our optimization is delivering production growth with top quartile steam-oil ratios, lower cost per barrel, and lower emissions intensity. Despite no new pads since 2016, these optimizations allowed us to achieve record production levels last year. We're currently drilling our first new pad in seven years. With a cost of supply of just $15 a barrel, Pad 267 will deliver some of the lowest cost of supply resource in our entire portfolio. It will lengthen the production plateau, and it will further lower the steam-oil ratio. We're about halfway through drilling, and we're seeing costs of 30% cheaper than the last time we drilled in Surmont. We expect to have first steam in Q4 this year. In conjunction with the operational optimization and the low cost of supply development, we're equally excited about the opportunity to materially reduce our emissions. We think about this in three categories: application of current technologies, new technologies, and CCS. We're currently conducting pilots with current and new technologies focused on reducing the steam and/or increasing the production. We're also a member of the Pathways Alliance, a unique partnership that's collaborating with both the provincial and the federal government to evaluate the commerciality of large-scale CCS in Alberta. Moving from Alberta to British Columbia, let's take a look at our unconventional Canadian asset. In the Montney, we've successfully completed the appraisal phase and landed on a two-layer plan of development. This is enabling us to high-grade the resources to 1.8 billion barrels of oil equivalent at a cost of supply in the mid-thirties. We're excited to be transitioning to a steady development plan, our experience in the Lower 48 is allowing us to rapidly move along the learning curve. We plan to add a second rig in 2024, that will allow us to run one continuous frac crew. What's also compelling about the Montney is that we can grow over 100,000 barrels a day over the next decade with just two rigs. That production is 60% liquids with a long-term commercial offtake in place. I'll move to our international conventional assets. Over the years, we've high-graded this part of the portfolio, and we now operate in four countries, Norway, Libya, Malaysia, and China. Norway is a great example of how we leverage existing infrastructure. We expect to have four subsea tiebacks all on stream in 2024. In Malaysia, we continue to add high margin, low cost of supply opportunities. In China, we're progressing a wind farm project that will both reduce our GHG emissions and lower our operating costs. In aggregate, we see the international conventional business as a strong free cash flow generator, providing about $1 billion a year over the next decade with very low reinvestment rates. I'll end my asset tour with Alaska, and we'll start with the legacy business. We have over 40 years as a proven, responsible operator in the state. We're currently producing about 200,000 barrels a day of high-margin oil with Brent link pricing. Even after 40 years, we still see underlying growth potential, and that excludes Willow. This is driven by a combination of infill drilling and step-out pads. Coyote is a great example of developing a new reservoir from an existing pad. Nuna is a great example of a new pad tied back to existing infrastructure. Between these two projects, we've got about 65 wells planned with a peak production of about 40,000 barrels a day. Importantly, both of these projects have cost of supply in the low twenties. We'll continue to invest about $1 billion a year to profitably grow our Alaska legacy business at about 2%- 3% a year over the next 10 years. Let's move to Willow, our next development to the west. I know Willow has garnered a lot of interest. I'd like to start by talking about where we are in the approval process and then share some additional details about the project. We were pleased to have received a record of decision from the Biden administration authorizing a three-pad development. I did wanna just take a moment to thank the Alaska Congressional Delegation, the Alaska Native communities, the governor, the state legislator, and organized labor groups for their unwavering support for Willow. As anticipated, since the record of decision, two lawsuits have been filed, but we expect timely resolution. The responsible government agencies have all been really professional with their analysis, and they agree with ConocoPhillips has addressed all of the issues required for them to grant their approvals. Moving to the project, Willow is a 600-million-barrel resource that we'll develop from 3 pads. Willow is located just 8 mi. Yes, that's 8 mi from our existing infrastructure. It's an extension of our Alaska business. The chart on the lower left compares Willow to our existing infrastructure. We have successfully developed over 120 drill sites connected to 13 central processing facilities. Willow is simply another three drill sites connected to one new central processing facility. Equally important is the design and the execution. When the project permitting got delayed, we did not stop planning. We used the two extra years to complete all of the major engineering and FEED work. We are ready to begin the execution phase of this project. The construction scope will be executed by our teams working with proven North Slope contractors who all have an excellent track record. As an example, over the past five years in our legacy business, we've delivered a similar drill site, pipeline, and road construction scope as we will do for Willow on schedule and under budget. In summary, the design is well advanced. We've done these many times before. We're prepared, and we are ready. Quickly shifting to the drivers, I wanted to provide some guidance as you help about thinking about modeling Willow. On the left side, we provide a look at our capital. The capital is gonna be about $7 billion-$7.5 billion to first oil for about $1 billion-$1.5 billion a year per year through 2024-2028, with 2024 being on the lower end of that range. About one-third of the total capital is for processing facilities, two-thirds is for drilling and infrastructure. We've also provided some key milestones below, as a reminder, first oil is expected in 2029. On the right of the slide, we provide a look at our production. By pre-drilling the initial wells, we can maximize our cash flows, we'll quickly reach peak production of 180,000 barrels a day. As a reminder, the margins we achieve from Alaska have averaged 40%-50% of Brent since 2016. It's also worth noting Willow's oil quality is better than the typical Alaskan barrel, and its operating costs will benefit from leveraging existing pipeline infrastructure. I hope you find the capital, the production, and the margin information useful when you're assessing why we see Willow as such an attractive opportunity in our portfolio. Let me wrap up where I started. Our Alaska and international assets provide a unique advantage to ConocoPhillips. The production delivers a 4% CAGR of high-margin production growth at an extremely competitive 40% reinvestment rate. This plan generates significant free cash flow of $50 billion over the next 10 years at a $60 WTI with upside to higher prices. This material, diverse, and low-cost supply resource differentiates us from our domestic E&P peers. I'll finish exactly as I started by saying nobody else has this advantage. I'll now hand over to Bill to build upon my earlier LNG comments and talk about our commercial LNG portfolio. Thanks, Andy. Well, thank you, Andy, and good morning, everybody. I'm gonna be rounding out our LNG business efforts. I'm gonna focus on our North American footprint and on our recent investment in Port Arthur LNG in particular. I'm also gonna share a bit about our global commercial organization, one that I lead. Let me just tie back to what Dominic shared. We believe that LNG markets are going to show strong demand growth for decades to come. That's driven by energy security needs, that's driven by the energy transition, and it's also driven by coal to gas switching for electric power generation. In addition to our foundational positions in both Qatar and Australia, which you've just heard about from Andy, we are very excited to add the Port Arthur project on the U.S. Gulf Coast to our portfolio. I'm going to provide more details on why we like Port Arthur in just a moment. It's also important to note we have a world-class global commercial organization, one that's in the market daily, that's optimized our assets to enhance our margins. Our extensive global commercial footprint is a significant advantage for ConocoPhillips. In the LNG business, this is one that we know really well. We've been in it for 60 years. In fact, we opened the Japan LNG trade with sales from Kenai, Alaska. Let's start with the LNG macro. We see robust LNG demand growth well into the middle of the century, really led by Asian demand. We also believe that North American liquefaction, with its access to abundant gas resources, this is gonna be well-placed to meet this demand. In fact, North American liquefaction needs to more than double over the next decade to meet this demand. Given our views on global supply and demand for LNG, we believe that expanding our footprint with the Port Arthur project plays an important role in growing a balanced global portfolio. Port Arthur is well-positioned to serve both the European markets and Asian markets. Looking on the right-hand side, you can see our current and our forecast net exposure to LNG markets. Today, we have 6 million tons of LNG. This is from Qatar and Australia, and we see this more than doubling by 2028 with our additions in Qatar at NFE and NFS and with Port Arthur. I think it's also worth noting that this is balanced. It's balanced across the three largest regions for LNG supply. That's Qatar, that's Australia, and that's the U.S. Now from a capital perspective, this is very, very important. We expect to spend less than $4 billion on our LNG growth efforts. This is at Qatar and it's at Port Arthur. As I mentioned on our fourth quarter call, Port Arthur spending is just under $2 billion, and we expect a little over half of that spending in 2023. Now, I do wanna speak about Port Arthur in more detail. We do believe that Port Arthur is a very attractive integrated project for ConocoPhillips, and clearly, our decision to participate in both equity and offtake was instrumental to launching this project. Phase One FID is now complete. Startup is slated for 2027. There are numerous reasons why we like Port Arthur. First, we're working with a high-quality operator with Sempra. The EPC contractor is Bechtel, and Bechtel has just recently completed a similar facility in the Sabine Pass. Second, location. Location is clearly important for LNG gas supply, and we think that the U.S. Gulf Coast is attractive, particularly the Texas side of the Sabine Pass. It's in close proximity to fast-growing, low-cost, low greenhouse gas basins like the Permian, like the Haynesville. These basins, they're close to existing infrastructure, which they can leverage. Not only that, though, they can potentially benefit from the rapid development of intrastate pipeline expansions like we've recently seen coming out of the Permian Basin. Third, and perhaps most important, our investment has a high degree of optionality, and I'd like to walk you through some of those options at this time. First, we have access to excess uncontracted volumes from phase one. Second, we have options on future phases at Port Arthur LNG and on the West Coast at Energia Costa Azul, and these options are for equity, for offtake or for both. Finally, regardless of whether we participate in future phases at Port Arthur LNG, our phase one infrastructure is structured to economically benefit from the economies of scale and the efficiencies of those future phases. It's important to note at this time we're very focused on market development. We're prioritizing that over offtake and equity, but these are long-dated options, and long-dated options often have significant value. One final point on Port Arthur is we're evaluating carbon capture sequestration opportunities with our partner, Sempra, and that's really focused on lowering the greenhouse intensity of LNG produced at the site. Shifting to offtake. We have 5 million tons of offtake from Port Arthur phase one. We have a highly competitive liquefaction fee, which we believe further highlights the importance of the integrated nature of our investment. Now that FID has been announced, we're receiving significant customer interest and our market development is well underway. When you pull this all together, we believe that Port Arthur is a unique opportunity and a compelling opportunity for ConocoPhillips. Let me dive a level deeper on offtake for Port Arthur. While the project has just recently sanctioned, we have been actively developing market in both Asia and Europe for quite some time. Let me give you an example. You know, we've secured regas capacity at Germany's first onshore LNG regas terminal, aptly named German LNG. We previously communicated that a portion of our capacity position at German LNG Terminal, this has been allocated to our 2 million ton offtake commitment from Qatar from NFS and NFE. The remainder of our capacity at German LNG, this allows us to place some of the volumes from Port Arthur into the German Trading Hub Europe market. This secures a Henry Hub to THE margin. More than that, we've retained the upside of being able to divert these volumes if margins are better elsewhere around the world. That effectively delivers the higher of THE or rest of world pricing for this portion of the volume. It takes a global commercial organization to be able to do that. I want to take a moment to talk about our commercial organization and really to give you some perspective on why we are differentiated when it comes to our LNG marketing and optimization strategy. First, we have significant scale. We have commercial offices in six locations around the world. We have LNG teams that already exist and have been in place for a very long time in Asia, in Europe, and in the U.S. Second, we have the breadth and depth of skill sets across a variety of different commodities in different markets. For instance, we continue to be one of the largest marketers of natural gas in North America. We've got a strong marketing capability, and we've got deep insights in sourcing gas supply. In fact, we are going to be managing gas supply for Port Arthur. Turning to Europe, we're active in all the liquid gas markets in Europe. That includes THE, that's thanks to our position with equity production from Norway. The bottom line is we have a strong commercial advantage, one that allows us to optimize our margins across the globe. Other E&P companies do not have this capability, they would find it very difficult to replicate. To wrap up, we see strong demand growth for LNG markets over the longer term. We're well-positioned with excellent assets in low-cost regions around the world, we have a world-class commercial organization which clearly underpins our global LNG efforts. Now I'd like to turn it over to Nick Olds. Nick's gonna come talk about our industry-leading position in the Lower 48. Nick? All right. Thank you, Bill. Thank you for giving me the opportunity to talk about the Lower 48 business. I'm excited to go over our plan today, highlighting our top-tier Lower 48 portfolio that we believe is highly differential. I think you'll see that ConocoPhillips has a best-in-class portfolio. As I step through this section, there are three key elements that I would like you to take away from the presentation. First, we are a leader in the U.S. unconventionals and the only E&P with core positions in key four Lower 48 basins. Second, our plan delivers well over a decade of disciplined production and cash flow growth. Third, we have an incredibly talented team that is not satisfied with the status quo. This drives a relentless focus on enhancing our performance, which you'll hear about today. Bottom line, we have a great Lower Forty-Eight portfolio to show you, one that's durable, low cost to supply, low GHG intensity, and will continue to generate significant cash flow for years to come. We recognize one of the key industry questions is about depth and durability of the unconventional portfolios. Not only is ConocoPhillips the largest unconventional producer in the Lower Forty-Eight, but we also have the most remaining net inventory compared to our peers. Looking through a different lens, we can grow production 5% per year for a longer duration than most of our peers. Additionally, we have low cost to supply resource base averaging $32 per barrel, fully burdened. Our cost of supply framework provides confidence that our inventory is durable through the price cycles. We have a very competitive and diverse portfolio with Eagle Ford and Bakken sustaining production through the decade and the Permian serving as a key growth engine of the Lower 48 and the company. In the next few slides, I'll dive deeper into the Permian program. Now, we have significantly grown our Delaware footprint with over 650,000 unconventional net acres spanning across this prolific basin. The Delaware is our primary growth engine, representing almost two-thirds of our Permian operated drilling inventory over the next 10 years, growing at high single digits through the decade. We have a development strategy that allows us to optimize the full field and has delivered improved production performance. Since 2019, Delaware 12-month production per foot has improved 30% while also increasing well lateral length. Our development teams are continuously incorporating year-over-year learnings throughout the plans, and we're confident in the quality of our acreage and in the consistency of results for years to come. As a further proof point, we are peer leading in value delivery measured as capital efficiency. Ongoing drilling and completion efficiencies, infrastructure development, and water management further reduce our cost of supply. Our Delaware has demonstrated performance, best-in-basin results, and high single-digit growth into the next decade in the sweet spot of the basin. This is not the only position we have in the Permian. Similar to Delaware acreage, our Midland asset is also in the sweet spot with about 250,000 unconventional net acres. Midland represents about 1/3 of the operated development program over the decade, growing at low to mid-single digits. We like our position in the Midland Basin as it's more mature in the Permian play and delivers consistent competitive performance in an oil-rich part of the basin. Similar to the Delaware, we've seen improvement in 12-month cumulative production improving by 6% since 2019. We continue to improve efficiency by leveraging new drilling and completion technologies while increasing lateral length. We're very focused on continuously improving capital efficiency in the Midland Basin with a target to be top tier. While both Delaware and Midland are demonstrating great performance, we're also focusing on making these assets even better through continuous improvement, which brings me to our acreage optimization. Our expansive acres position continues to provide core up opportunities. These trades have focused on increasing lateral lengths, which we know can reduce cost supply by 30%-40% versus 1-mile laterals. The example shown is part of what we've recently done on a Permian transaction. We've successfully closed 20 acreage trades since 2021, unlocking long lateral development. Today, 80%, let me repeat, 80% is 1.5 mi or longer. That's a lot of long laterals. From 2022- 2023, lateral length has increased 14%, and we're not done yet. More trades are already in the works; our teams continue to look for ways to further enhance returns and the durability of our portfolio. We leverage our Permian long lateral learnings to accelerate improvement in the Eagle Ford, the Bakken, and the Montney. We have top-tier acres position and inventory depth in the Permian, as well as further upside. Pulling our Permian story together, our plan provides 7% production growth with free cash flow doubling by the end of the decade with only a 50% reinvestment rate. This plan generates significant cash flow of $45 billion over the decade at $60 WTI. That's almost 40% of our total company free cash flow. In addition, we have significant torque to the upside. The bottom line, we have one of the largest unconventional acreage positions and well inventories in the Permian, and our demonstrated performance provides confidence in the plan we're showing today. This truly is an asset that keeps getting better and better. Moving to the Eagle Ford and Bakken, these assets represent a considerable portion of our Lower 48 portfolio. We have roughly 200,000 and 560,000 unconventional net acres in the sweet spot of these premier basins. These assets have consistent proven track record of performance, delivering top-tier. That's top-tier capital efficiency. Combined, these assets sustain production of approximately 330,000 barrels equivalent per day throughout the decade, with Eagle Ford growing at low single digits and Bakken operating close to plateau. Eagle Ford continues into the next decade. These assets benefit from existing infrastructure capacity and liquids value optimization through our condensate processing facilities. In addition, we're expanding our resources through technology wins like refracs, which are highly economic, low $30 cost of supply, and can increase the ultimate recovery of the well by 65% compared to its original completion. In the Bakken, we continue to realize benefits from the low capital intensity oil-weighted margins. The team continues to drive down costs and innovate through data analytics, yielding optimized completion designs resulting in well productivity improvements. Both assets significantly deliver and reliably deliver free cash flow over the decade of $20 billion of free cash flow at $60 WTI. We're always seeking value enhancement opportunities that allows us to achieve more for less, which brings me to my next topic of innovative technology. We're not a single basin E&P. Sharing knowledge and technology across our unconventional assets and the Montney is a key advantage as it unlocks acceleration of learning curves and drives efficiency. Continuous improvement is a core part of our culture, and it's embedded in what we do every day. Technology application is enabling and accelerating this continuous improvement. I'd like to highlight a few examples. First, Permian drilling efficiency increased by 50% since 2019. The teams have been high-grading rigs, we've been incorporating slim hole designs and prioritizing longer laterals. Second, we have improved our Permian completion efficiency by 60% through design changes, simulfrac and more wells per pad. We have enhanced our completion activities through dual fuel and eFrac technologies, which reduce costs and emissions. Over 50% of our 2023 Permian wells will be completed using simulfrac, that's up from 35% last year. We'll continue to look for options to increase this. Bottom line, these efficiencies allow us to deliver more barrels per rig line. Finally, by using drones as part of our production and emissions surveillance, we can increase the inspection frequency, identify repairs, and reduce downtime. Many of our innovative technologies enhance value while also reducing our emissions intensity, which leads me to our next topic. Let's talk about sustainability. We have delivered considerable improvements, reducing our GHG intensity by 50% through a combination of growing our low-intensity Permian assets and executing emission reduction projects across the Lower 48. We're eliminating gas-driven pneumatics across our facilities and continuing to advance our methane monitoring capabilities. We have reduced our associated gas flaring by 80% since 2019 and do not routinely flare due to pipeline constraints in the Lower 48 or anywhere else in the portfolio. In the Permian, over 50% of our water for hydraulic fracturing was recycled produced water. We're working to increase that as well. These actions have improved our Delaware frac cost per barrel by approximately 50% from before using recycled water versus other sources. All these reductions help us improve the sustainability of our assets while lowering our cost of supply. Okay, now to sum it all up for Lower 48. Lower 48 serves as a growth engine for the company. It's a powerful free cash flow machine. This region creates enormous value and contributes significantly to the company's plans. Similar to what you heard from Andy on the Alaskan international businesses, we remain disciplined with expected average annual capital of $6.5 billion at $60 WTI, delivering a 5% production growth. This implies average reinvestment rate of 50%. Over the 10-year period, this plan generates $65 billion of free cash flow at $60 WTI with torque to the upside. We intend to lead and manage our shale business for value, durability, sustainability, and returns of capital, and are excited and optimistic about the future of Lower 48. With that, I'll turn it back over to Bill to cover the financial plan. All right, thank you, Nick. You've now heard from Dominic regarding the clarity of our strategy, one that delivers superior returns through the cycles. Andy, Nick, and I, we've taken you through our best-in-class portfolio that really underpins the strategy. Now I'm very excited to pull this all together for you for a compelling 10-year financial plan. Now, as Ryan said in his opening remarks, ConocoPhillips offers a tested and robust framework, one that delivers compelling returns on and of capital while growing durable cash flows well into the next decade. We've got a proven track record of strong returns. We see continued improvement in this area in years ahead, our three-tiered distribution framework is distinctive. It is based on CFO, not free cash flow. Our plan produces solid growth in both CFO and free cash flow over the entire 10-year plan period. This rewards shareholders both now and into the future. Finally, we remain committed to our A-rated balance sheet, one that's resilient through commodity prices. I'm gonna show you a stress test here in just a moment to demonstrate this point. Finally, and I can't emphasize this enough, our financial priorities are unchanged. In fact, our financial priorities have been successfully battle-tested through major economic events over the last five years. I'm gonna start off with returns on capital employed. Of course, this is a pillar of our triple mandate, and as you can see on the left-hand side, we have demonstrated industry-leading ROCE versus energy peers. Going forward, we are not standing still as we believe that our ROCE will continue to improve over the next decade. This is driven by earnings growth of about 10% per year. This should lead to about a one percentage point expansion per year in our ROCE on average over the 10-year plan. Of note, this plan, it delivers ROCE in the top quartile at the S&P 500 at $60 WTI. Top quartile ROCE, that remains one of our primary objectives. Now moving to cash flows. We expect to generate a 6% CFO CAGR and an 11% free cash flow CAGR at $60 WTI. It's driven by our 4%-5% production growth outlook and our disciplined reinvestment rate. Regarding our longer cycle investments, we expect cash flow generation to begin at NFE in 2026, NFS in Port Arthur in 2027, and Willow in 2029. Once all these projects have started and are online, we expect to see uplift to our CFO of three and a half billion dollars in the 2029-2032 period annually at $60 WTI. At $80 WTI, that would grow to about $5 billion annually. On the right-hand side, you can see this translating into increasing free cash flow over the back half of the decade as well. That's given that there's fairly minimal sustaining capital required for these investments. All in, we expect to generate $115 billion of free cash flow over this 10-year plan period, and of course, that would be available for shareholder distributions. Let's move to shareholder distributions. The key message here is that we are highly confident in maintaining our commitment to distribute greater than 30% of CFO to our shareholders through the cycles. We also believe that our shareholder distribution policy, as I mentioned, is distinctive. It is based on CFO, not free cash flow. Investors rewarded right off the top. This is before capital expenditures. As our track record demonstrates, over the last five years, we've returned 45% of our CFO to our shareholders, and that's at an average WTI price of $64 per barrel. This has been in line with the average distributions for the majors and well ahead of E&P peers. Additionally, our range of distributions of CFO has been the most consistent of anyone in our peer group. From a distribution yield perspective, we have returned a greater percentage of market cap back to our shareholders and our peers at about 7% annually over the last five years. Looking ahead, our plan returns 9% of our market cap annually over the next decade, of course, in the form of dividends and distributions and buybacks. I'd like to shift to distribution channels, and I wanna spend a minute talking about our three-tiered framework. Tier one is the ordinary dividend. Over the past five years, we have achieved a 12% annual growth rate in our ordinary dividend. This has been top quartile with S&P 500, and as you heard from Ryan, that remains one of our long-term objectives. Tier two is our share buybacks. When you combine that with our base dividend, that achieves our commitment of returning greater than 30% of CFO to our shareholders through the entire cycle. It's not just at mid-cycle. I'm gonna show you a sustaining case here in just a moment to demonstrate how we can do that. Finally, tier three. Tier three is our variable return of cash, our VROC. Last year was our first full year of implementing the VROC. It's another efficient form of capital return and one that we think is very useful, particularly in periods of time of above cycle pricing. I'd like to move to the balance sheet for just a moment. We're well underway with a debt reduction plan that we laid out in 2021 following our Permian acquisitions. We've now paid down $3.3 billion of debt as of year-end 2022, with $1.7 billion to go by 2026. This is very manageable. From a leverage ratio perspective, we're in a very strong position. Our leverage ratio is currently 0.3 turns. We expect further improvement on this ratio over the course of the plan period. Simply put, our balance sheet is in great shape. All right. The two other topics that I wanna hit on today is our priorities for cash on the balance sheet and a stress test. Let's start with cash on the balance sheet. We remain committed to the same framework that we've talked about in the past. We start with $1 billion of operating cash on the balance sheet. This is for working capital needs. $2 billion-$3 billion on the balance sheet is reserve cash. That's really to handle near-term commodity price volatility. The rest is strategic cash. Of course, that can be used for several purposes, including funding longer cycle projects and for supporting our buybacks through lower commodity price periods in the cycle. All right, I wanna move the stress test case now on the right. Here we're showing a two-year $40-barrel WTI case. Clearly, this is conservative. Particularly given recent history where we've just gone through one of the worst downturns, and we saw a $40 WTI price for one year, of course, that was in 2020. In this scenario, our leverage does not go above 1.5 turns through a two-year $40 stress test, and this is without cutting capital from our base program. It is while funding our longer cycle projects, while meeting our commitment of returning at least 30% of our CFO to our shareholders through the cycle. We can do all this without having put additional debt on the balance sheet. To do this, of course, we would use some of our strategic and some of our reserve cash. That's precisely why they are on the balance sheet. The key point here is that our balance sheet, it's a strategic asset. It positions us very well for any future downturns, to be able to manage through them quite well. Let me just kinda recap the whole plan. This is a very strong financial plan. It delivers both highly competitive returns and cash flow growth. It generates top quartile ROCE at $60 a barrel. We've got 6% CFO and 11% free cash flow growth annually. It returns 90% of today's market cap at a mid-cycle planning price of $60 a barrel WTI. It also delivers what we expect is gonna be top quartile dividend growth rate throughout the plan period. Finally, it maintains our fortress balance sheet. This provides strategic flexibility for us and really resiliency to any potential downturn scenarios. That wraps up the financial plan. It is a very strong financial plan. Before we go to Q&A, Ryan's gonna come back up for a few closing remarks. Ryan. Thanks, Bill. Thank you, Bill. Let me wrap up the presentation, and we'll go back to where we started today. Our goal was pretty simple, and I hope you saw that today. It's to share with you why we believe ConocoPhillips is the must-own E&P in your portfolio. Dominic described how we think about the strategy and how that plays into our plans. Andy, Bill, and Nick took you through a portfolio that we know is differential to all of our E&P peers. Finally, Bill showed you a pretty compelling financial plan that we think is distinctive and that no one else can match in our business. All combined together with our world-class workforce, you get the best E&P company in the business today, and you get it over the long term as well. With that, thank you for your interest. Thank you for your time. We're gonna take a 10-minute break. I'll bring the management team back up on stage. We'll take your questions. We'll see you in 10 minutes. We're almost over. Now it's your turn. Phil's gonna lead the Q&A. He'll call on people in doing that. We have a couple of folks with microphones here. If you would just please raise your hand, Phil will call, and we'll get started. Thank you. All right. Yeah, good morning, everyone. As you all know, one question and one follow-up, please. Let's start here with Ryan. Oh. Can you do the remote mic? Is it on, Troy? Yeah. Go ahead, Ryan. All right. Thanks. Ryan Todd at Piper Sandler. Maybe a question starting out on cadence to CapEx over the next few years. You've given some buckets there. Particularly as we think about the base business and the Lower 48, it looks like you'll be able to hold the Lower 48 capital budget relatively flat over the next three or four years. Is that a fair statement, and what goes into that in terms of assumptions from inflation or activity levels across the, you know, the assumptions on. Yeah, I can maybe make a couple comments. I ask Nick to chime in as well. As you see, sorta, there's portfolio changes that are occurring over the course of the next number of years. Things in Norway are coming back down a little bit. Other places are coming down. The places that are coming up is some of the LNG investment. Obviously, the Willow investment that we've got. We do have some ramp built into our Lower 48, I think, which is maybe more, more to the point of your question, Ryan. Maybe I can let Nick address that. Thanks, Ryan. So just taking it back to 2023, you see a little bit over $6 billion for Lower 48, and that is in an $80 world. In the remaining part from 2024 to 2032, with respect to capital, we're in a $60 world, so there is some deflation that is incorporated into it. We do grow overall for Lower 48 at 5%, so we'll be adding rig activity level and frack activity level to get to the 5%. Then in the Permian Basin, same, about 7% growth there. Again, we'll be adding that activity level throughout the decade. Again, 2024 to 2032 is in a $60 world. Thanks. Maybe a totally separate gear from a follow point of view. As we think about your LNG portfolio, you talked a lot about the globally diversified portfolio. It grows significantly over the course of the decade. How much merchant risk are you comfortable with? There's some visibility on contracts right now. Not a lot of visibility, a lot of open market risk. Are you comfortable with that much merchant risk on the spot markets? Would you look to term up more of that? How do you think about as you manage your global gas business over the course of the decade? I can let Bill I just say, you know, we're not looking to become a full merchant marketer of LNG. You'll see a mix in our portfolio as we go forward marketing some of that. Bill can speak to some of those specifics. Yeah. Sure, I'm happy to talk about how we think about that, Ryan. And it's clearly a topic that's on our mind. When you look at the projects like Qatar and APLNG, these are more E&P type nature. The merchant risk ones I think you're talking about is things like Port Arthur, where we've got 5 million tons. We hopefully shared with you how we think about that with a little bit of a vignette. We're thinking about going into German LNG on that. That gives you an idea of how we think about that. I think that, you know, what's important is when you have 5 million tons of length, you should be looking for us to be explaining what we're doing to place those before taking out additional length. as we think about that length, a portfolio that really looks like delivered at terminal sales into Europe and Asia with maybe some FOB sales, we're looking at term length on that. as you build these portfolios out, you have length, you place. That market into offtake before you start adding length into that. That's kind of how we think about the portfolios. You need to have a place before you take more. 5 million tons is quite a bit right now. All right. Doug. Thanks, Phil. Thanks, everybody for the great presentation this morning. I guess, I've got two questions, one follow-up. My first one is an interrelated question. The 10-year operated inventory in the Permian, your unconventional business grows 50% by 2030, so more or less 10 years. What does the inventory look like in 2030, given that the unconventionals will be about two-thirds of your production at that point? Yeah. Yep. If you look at... Let me just take you back to panel two of my section. We have just under 12 billion barrels of inventory that's less than $40, averaging $32. Specifically on the Permian, in the Delaware, two-thirds of our operated program will be focused in on the Delaware. The remaining one-third will be in the Midland Basin. As I mentioned in my wrap-up slide, we don't plateau until the second decade. If you take a look at that inventory that underpins the 12 billion at current rig activity levels, that's well over two decades of inventory life. Okay. Thank you. My second and my related part to that is when you look at your breakeven, the $35 breakeven, presumably that excludes the dividend, just for clarity. Yes. I don't think it does. It does. What does that sustaining capital breakeven look like in 2030 to a bigger part than when the conventionals are two-thirds of the production? Thanks. Yeah. Dominic can handle that. Doug, there's maybe two different ways we'll think about that. There's the sustaining capital and then there's free cash flow breakeven. If I think about free cash flow breakeven, we said average of $35 over the 10-year period. It starts, the first half is in the high 30s, the second half is in the low 30s. We actually exit this plan in the high 20s, actually, in terms of free cash flow breakeven as our CFO grows. I know we would challenge any company to have a breakeven in the 30s for 10 years. Of course, you know, the free cash flow of $115 billion at $60, the upside there. I mean, these are very much the features why we believe we're the E&P of choice. On the sustaining capital, I'm going to preempt a question that you always ask, Doug, but it's probably connected with what you asked there. You know, so if you look at, you know, as we think about sustaining capital, which is really the capital required to sustain our current production, we think of that in a $40 world, you know, that world where you would really be concerned about that, and that would still be about $6 billion at that level. And that would grow over the 10-year period clearly as the company grows, the sustaining, but the sustaining price would come down, which is what really matters, so. Breakevens decline. Yes. The breakeven declines over time. Yeah, yeah. Neil Mehta. Thanks for doing this. The first question is for Willow. I don't know, Andy, if you want to take this. is around Willow. you know, at this point, what's left outstanding to get to FID? It feels like we're in the later innings of that process, a couple legal things that are outstanding. One of the investor concerns has been that we've seen some pipeline challenges from an infrastructure perspective around permitting and execution, whether it's MVP or Trans Mountain. This feels very different from that, so I'd love you to address that head-on. Go ahead, yeah, it's very different, Neil. Go ahead, Andy. Morning, Neil. Look, so to unwrap a couple of pieces of that, we will start with where we are in terms of what it takes to get to FID, and then we can compare and contrast the, you know, the differences of the project. Just as a, you know, a reminder of what I said in my prepared remarks. We're at a point now where we have the Biden's administration's approval of the project, and we have unanimous support from, you know, the Alaska Congressional Delegation, the governor, and the state legislator. You know, as we expected, you know, there has been two lawsuits filed. It's important to point out that the lawsuits are actually, you know, challenging the federal government. They're not challenging ConocoPhillips. They're very specifically focused on the approval process. We do wanna see how, you know, that plays out. You know, importantly, that's already progressing. We're at a point now where it's in the, you know, the Alaska Court. You know, the plaintiff, you know, request has been denied to have us stop working, so work is carrying on right now. Because of the previous, you know, cases that were on Willow, you know, the fact that, you know, we've had that extra two years, the scope of what's being challenged is very narrow. I wanna give credit where credit's due. You know, the BLM, and, you know, the other cooperating agencies, you know, they have done such a rigorous job in evaluating. This has been a five-year sort of, you know, review process of Willow. you know, we're very confident that where we are in that process, we are in the final innings. You know, we wanna see those legal cases progress. It's, it's encouraging to see that, you know, the plaintiffs were denied their request to have us stop working. We think we're very close there. you know, the second part of your question around sort of, you know, maybe I'll sort of broaden it to the sort of the whole costing. If you can look at it from our perspective, and I'll compare and contrast a bit to some other projects. you know, we feel really comfortable with our cost forecast for Willow for three or four reasons. You know, again, we've had this extra time. We're now at a point where essentially 50% of the costs are locked in. The vast majority of the remainder of the costs, you know, we've effectively negotiated most of those contracts. We know those contracts are on multi-year terms, we know the rates in those contracts. We know the escalation factors in those contracts. We feel that we're in a really good position in terms of the costing. A lot of that comes back to one of my previous sort of statements around just how well-defined the scope of this project is. You know, we're so far along compared to where you'd normally be in a project, and that's really a huge advantage when you're actually then in the process of contracting it. Again, you know, this is, this is close to our existing infrastructure, as I mentioned. This is something we do day in, day out. We know what we're doing. You know, we're not off building a greenfield project here. This is kind of, you know, in our backyard. The last part of your question in terms of, you know, why is this, you know, comparing, I think, to some of the pipeline projects. You know, one of the big differences here is that, you know, when you're building a pipeline, you're often going, you know, hundreds, even thousands of mi across hundreds of different, you know, local, state, federal jurisdictions. We're building one project in the National Petroleum Reserve, and we have all of our permits already in place. When you bring that all together, you know, there isn't this sort of last mile risk. you know, we've got all the permits we need for that project. Again, don't really see there being, you know, any real analogy to those kinds of projects where they had some of the cost overruns. You know, maybe they didn't have their approvals in place, maybe the scope wasn't all built, and they have the unfortunate situation of hundreds of different approvals. Very different to our projects. I think we're in a really good shape with that. I think it's important to note, Neil, too, I'd just add that, you know, when the federal judge denied the injunction to make us stop work, I mean, she has to look at it and say, "Is there any reason to do that?" She said, no. You know, you can continue to do your work, you'll continue to go through the legal process. We're 8 mi away from existing infrastructure. That's not far, as Andy said. Ryan, my follow-up's for you. Relative to three years ago, you've done some transformative and really important acquisitions, particularly in the Lower 48. Over the course of the last decade, you've demonstrated you're very good at selling assets as a company, and you're very good at buying assets as well. What do you think the outlook is for the M&A markets for oil and gas over the next couple of years? Do you see Conoco playing a role in it? Yeah. Thanks, Neil. You know, I've said repeatedly, I think there's too many players sitting in the space. I think there's room for consolidation. Certainly, when you think about investors over the last two to three years, you know, energy hasn't been high up on your radar screen. Hopefully, we've seen some change in that with security, affordability, and the whole sustainability, that triple mandate kind of question. Obviously from the plan that we showed today, we think is incredibly resilient and incredibly compelling for people to go consider. That said, I think there are too many players in this space. I think consolidation will continue. I think this part of the cycle at the kind of commodity price we're seeing today, it's really hard. I mean, it's hard to do something that both sides are gonna find interesting and compelling. Unless you're in a position where you have to do something, you don't have any inventory, you don't have length and durability, and hopefully you see we're not in that category. Will we be aggressive portfolio managers of the portfolio? Absolutely, we will be. You'll see us. You know, if it's not competitive in the portfolio, we'll be looking to do something with the assets like that. You've seen our history of what we do. The difference is we had a few things we needed to get done over the last five, six years, and then now we've got the portfolio really where we like it as a result of the transactions over the last couple of years. We are in a different place today than what I would describe as five years ago. Okay. I'll go to Roger. Thank you. Roger Read, Wells Fargo. One question I'd like to ask on, I guess, corporate decline rate, you know, where you are today and where it goes over time with an increasing contribution from unconventionals as a% of the total? Yeah. Dominic has that. Yeah. That's something we watch closely. It's an advantage of our company versus other E&P companies, and it's part of the rationale behind wanting to maintain the balance in our portfolio so long as our criteria around disciplined reinvestment rate and local supply are met. Right now, if you look at our, we like to think in terms of three-year compound annual decline rate because it's a significant financial period. We would be in the sort of 12%-13% range in terms of unmitigated decline, and that compares with a typical E&P company will be in the high teens. It's about a 30% advantage, if you like to think of it that way. You know, maybe another data point. Over the 10-year plan, the cadre over the 10-year plan is about 9% unmitigated. Then the trend of that through the plan, it stays pretty consistent because we are adding-- although we are growing the Lower 48, we are adding LNG and Willow in there as well. That's an important advantage for the company that underpins our reinvestment rates and free cash flow and everything. That's where we are. Not to quibble too much, but I don't know many E&Ps with a high teens decline rate. We don't like to disparage other people too much. Well, in a three-year base, I mean, instantaneous, if you take a one year, it's gonna be a lot higher than that. If you take it over a three-year basis, you know, you might get something like that. I appreciate that. My unrelated follow-up is on the marketing side. With the addition of Port Arthur and some of the other LNG, 10 billion of gas, 1 million barrels of oil or liquids a day, do you see that changing as well over time? I mean, you talked about where it is, not necessarily growth. I am just curious, does that expand along with the overall business? Go ahead, Bill. Yeah. Yeah, sure. We did provide some marketing metrics in terms of our size. I think North America, you know, we're in the market daily. We're several multiples of what our equity production is. That's really driven by a low-risk trading model. I think we're pretty happy with where we're at, but we're always looking for opportunities there. Roger, on the crude side, that's more just our equity production. And that's driven by the business model we have. We actively trade on the gas side and actively market on that and originate that. On the crude side, we're more placing our barrels into markets at appropriate pricing. Possibly some growth on the gas side that fluctuates year-t o- year. You can see that on the rankings every year that come out for North American European marketers. That's where I'd see the, I'd be watching. Crude is just placing our barrels in the market. Let's go over here to Sam, and then we'll come back over to Devin after that. Hey, thanks, everybody. This one's just a clarification on total capital, kind of related to Ryan's question, over the horizon. Next year you have a natural benefit from the front-end loaded Port Arthur payment rolling over. Mm-hmm. It sort of gets replaced by Willow, and you're early in the ramp in Lower 48, so your activity needs are lower, I guess, than they are at the later end of the, of the period. Then you might have some deflation that's coming in early. So is 2024 kind of a, kind of a real gap down in the total capital outlook, potentially at least, versus the, versus the trend line over the 10 years? Go ahead, Alan. We're not going to tell you what 2024 capital is going to be, but I think the range that we've put out there, that $10-$11 is a good working point. I mean, the $10 billion obviously averages at the $60 WTI case, which really, you know, if you're in a sustained $60 world, that's quite a different world to the world we're in today. We have no doubt that there would be material deflation in that world. You know, I think when we look at our U.S. supply model, we think about 20% of current activity in the Lower 48 needs more than $60 to generate a, you know, an economic return. We definitely think we would see deflation in that. Maybe, let me give you a sort of a sense of the moving parts and how this whole plan comes together. You know, from a pre-productive or longer cycle capital, we're about $2 billion this year. For the next five years, that will be about $2 billion. You may ask, well, if your capital is relatively flat, where is the space for Lower 48 growth coming from? I think that's part of your question. Well, what you got to remember is in Norway and in China, as Ryan mentioned, we actually have about $700 million-$800 million of capital that is phasing out over that period. That's what creates the sort of the opportunity to allocate that to the Lower 48. Of course, after the first 5 years, your pre-productive capital longer cycle is rolling off. The second part of the plan, there is quite considerable more capacity for reinvestment. Those are the major moving parts, I think, Sam. I would add, while the profile may look a little bit different, is we elected not to add scope in 2023 in the Lower 48, that was not due to inventory or anything like that. It was just merely due to the hyperinflation we're seeing in the Permian Basin and across the Lower 48. We have the luxury, we didn't need to run that hard into those headwinds. A little bit that gets shifted a little bit just because we chose to run at a constant scope this year relative to where we were last year. Thanks. Okay. A completely unrelated follow-up, as is the trend. I think the gas supply agreement into Port Arthur is sort of an underrated attribute of the project. Is there any way we can talk through the benefits of that aspect, if it's a, like, a price basis surety or if there's some other upside that might be a part of that too? You know, 'cause it's relevant to the Permian growth outlook too, since there's gonna be some gas coming from there. Go ahead, Bill. Sure. That's an interesting question. I'd start just by saying that it's important to note that we don't make a linkage between our equity production and our supply into Port Arthur. North America is the largest, deepest gas market on the planet. Being able to procure volume into Port Arthur, you can do that with a strong commercial organization. You're right that as we're running a marketing organization, you're looking at the strength of being able to source volume. It's helpful to have experience in all the different basins and have a portfolio to bring into Port Arthur. We really bring a strength to that partnership by being able to do that efficiently and effectively through cycles, including ups and downs, which is important for our operations. That's kinda how we think about it. It does provide mutual benefits for both our marketing organization and for Port Arthur. All right. Devin's next, then we'll go over to Paul Cheng after Devin. Hey, thank you. Devin McDermott with Morgan Stanley. My first one is on the emissions reduction goals you laid out through 2030. Could you update us on how much of your capital spend is going toward achieving that? Also, you alluded to considering things like CCS or hydrogen. Can you talk a little bit more about what you're looking at there and what type of return hurdle rate you'd consider for those types of projects? Thank you. Thanks for the opportunity to provide a bit more on that. On the operational emissions reductions, so we've allocated about $300 million this year, about $200 million capital, about $100 million expense. That run rate, we've got in there through the next several years. Next four or five years actually. That, that is what we have line of sight to in terms of the projects to achieve that 50%-60% reduction. That gives you a sense of the scale and what we're doing there. On hydrogen and CCS, you know, we've selected those two areas, I think you've probably heard us talk about this a lot because they could make sense for our company in terms of the competencies and the commercial and business adjacencies we have with our LNG customers and so on when it comes to hydrogen and our competencies around CCS. You know, we're in an early stage with them both. We are active in acquiring some long-term leases in a couple of areas for CCS and we're conducting some engineering studies with some key partners. You know, we're working with JERA on hydrogen because they would bring demand. JERA, largest Japanese utility, and we have a long relationship with on the LNG side. That's important. I think important to say that they're very much in our mind for the longer term. You know, as we think about those opportunities, we are probably spending in that particular area around hydrogen CCS, around $50 million a year at the moment. Not that significant, but enough to help build the foundation of what could be business opportunities for the long term. We don't see hydrogen or CCS being a material part of our capital program this decade, but something rather that we're positioning to understand and develop and say could be interesting for the company over the longer term. It'll have to fit within our capital allocation framework, which you're again, very familiar with after having been what we've been through to date. It has to generate a return. This is not a business we're gonna do without sort of a pathway that we see to generating a decent return in the business. That's where our LNG experience, as Dominic said, bringing the market along. The market understands you gotta pay a certain price if we're gonna develop some of these projects. We wanna spend the time to understand that. The other thing I would point out is that we've isolated, we've put some visibility into the spend to meet the GHG reduction targets. I'd say that's not truly incremental over the last 10 years. We've always been doing some of this as a company, but clearly the way the market and investors are asking is now put some clarity, some visibility into it. You know, it's a license to operate spend. It's the stuff we have to do to ensure the sustainability over the long term of this business. Great. Thanks for the detailed answer. Then I'll stick with the unrelated follow-up theme and go back to LNG in North America specifically. I think one of the longer-term options you highlighted is the expansion optionality at Port Arthur, and then also potential participation in West Coast LNG in Costa Azul. Can you just remind us the scale of those opportunities in terms of size of capacity, and then also the steps toward potential commercialization there over time? Go ahead, Bill. Sure. With Port Arthur, with our investment in phase 1, we've secured options to be able to participate in phase 2, 3, and 4. It's up to 8 trains on that site. Those are options for each phase. We have the option to participate in phase 2 on Energia Costa Azul on the West Coast. That's the scope of those. I think right now what's important to note is that we're very satisfied with 30% equity in phase 1 and with 5 million tons of offtake. Taking those was a bit unique because it secured the start of the project, it secured the optionality with it, and it secured a very competitive liquefaction before. Our focus right now really is on market development for 5 million tons. Sure. Thank you. Paul Cheng, Scotiabank. Two questions. First, Willow. I think in the past you guys was talking about to farm it down to 50%. Wondering that if that is still the plan and what built in into your production outlook and the cash flow, is it 100% or 50%? If that had been changed, why change? That's the first question. Yeah. We've built Willow in at 100%, just to be very clear. We did look at marketing, three, four years ago as we were trying to think about the portfolio, think about the exposure that we had up in Alaska. We feel comfortable with the deals that we did to gain to get to 100% were really, really important because that gave us control of the pace, which and control of the investments that we wanted to go do. What you see today is an assumption that we're gonna stay at 100%. Now, over time, if we had the opportunity, the market wasn't ready because they didn't know how to risk Willow. Could you get a permit? You know, what, what does the investment stream look like? We now have gotten some of that clarity, but we're prepared to take it on at 100%. Will we have conversation? Will we entertain if somebody wants to come in and join us? We would, but that's not part of our base plan. Okay, thank you. Secondly, that, you guys talking about LNG and commercial operation. Just curious then, what kind of business model or the risk appetite model that you will adopt? Some of your larger cousin on the integrated side, especially the European and even Exxon seems like it is increasing their risk appetite and taking a far more aggressive approach in the trading. What is the approach Conoco going to be? Thank you. I can let Bill chime in. Again, I would just start by saying, you know, some of the integrated majors have a very large merchant LNG business trading, you know, spot market volumes. That's not what we're trying to build in ConocoPhillips. Just to be clear, I can let Bill talk about sort of how we're thinking about the 5 million tons, and it really does just come down to the 5 million tons at Port Arthur, and if we chose to take any capacity on the West Coast. The other LNG projects that aren't like that, they're locked into very long-term agreements and customers, both at Qatar, our Qatar volumes and our APLNG volumes. Maybe Bill can address that a little bit more on the Port Arthur side specifically. Yeah, sure, Ryan. That's a great frame. You look at things like APLNG and Qatar, those are kind of placed in long-term traditional LNG market developments with secure off takes. When you think about things like Port Arthur, I think, you know, the nature of that is more a merchant type LNG. If we were buying Henry Hub, you're trading for a margin. I think that, you know, our company is pretty conservative in terms of how we look at doing that. On our commercial business that we talked about overall, this is low risk optimization trading. You never heard us talk about really high swings on that for a reason, Paul. We run very little VAR, that's what I mean when I think that you should be thinking that we have offtake. We're gonna be fundamentally placing this into market development. You can think about that in terms of the spread for LNG for Henry Hub versus THE, TTF or JKM, but they'll be built up in positions where you're not open. Okay, Nitin. Good morning. Nitin Kumar from Mizuho. I wanna start with a follow-up on the Permian, the 7% growth. Is that baking in your current type curve? You showed, I think a 30% improvement. Are you baking in any technology, any secondary recovery, any enhancements? Then just to tack on to that, you mentioned lower costs. Is any of that cost saving coming from things like longer laterals, fracs, et cetera? Yeah. Yeah. Very good. Lot to unpack on that one. The 7% production growth in the Permian over the 10 year does factor in the most recent type curves. As I mentioned, just to kind of pulse back to the Q4 call, in the Permian, our well performance is at or exceeding the type curves, and so that's what's integrated into the plan that we showed with you. I'll take you back to the technology section as well, where we showed 50% improvement in drilling efficiency since 2019, 60% in completions. We do have some level of efficiency improvement over that 10-year period as well. With respect to EOR and those further enhancements, that's not in the 12 billion barrel stack. That's something that we'll continue to look at, going forward. Most recent type curves and most recent efficiency. Just an unrelated follow-up. You mentioned 50% reinvestment rate over the 10-year horizon, 30% of cash flow is targeted for shareholder returns. You mentioned this a little bit, but just how should we think about that 20% remaining? Is that for strategic purposes, high cycle, whatever? Well, we've said repeatedly, our 30% commitment is a minimum commitment. It's through the cycles. So I think what you have to think about is look at our last five years when the price has been above, well above our mid-cycle price. We've delivered well over 40%. I think Bill will show. Forty-five. You know, of the cash that's going from the operation. You ought to be thinking that our balance sheet's in pretty good shape. Most of the free cash flow that we're generating today is eligible for distribution. But the 30% is a through the cycle number. But that's a floor. That represents our minimum amount of our commitment that we recognize when prices are above the mid-cycle price, you're gonna get a higher percentage of that cash flow because we're generating much more. We'll go to Bob, then John. Bob Brackett at Bernstein. You spent a lot of time talking about a $60 deck. You stress test up to 80, down to 40. What if that anchor is wrong? How do you think strategically about an oil price staying north of 80 through most of that 10-year planning period? We run multiple scenarios through our price deck. We have four transition-related scenarios. We've got a high price scenario. We've got the stress test on the, on the low side case. Yeah, we know what we're going to go do. We, we have, you know, some elasticity to inflation. At these very high prices, you're gonna get more inflation. We know that just delivering the base scope is gonna take a little bit more capital. Generally, we're not looking at ramping scope dramatically if prices were to ramp. That just means we're gonna have more free cash flow, higher level of distributions, we're pretty comfortable with the scope that we're executing. The question becomes, in those higher price environments, how much does it cost to execute that scope? We do believe there's gonna be obviously some inflation. The system kinda gets capped out like it did in 2022. There wasn't a lot of more rig capacity. There wasn't any more pressure pumping capacity. The system kind of equilibrates itself over time and puts a throttle on that, on that upside. Clear. Follow-up would be, what's the role of exploration in Libya in the portfolio? Well, exploration, you know, we with 20 billion barrels of resource below $40 cost of supply, you know, the exploration for us is just near term around existing infrastructure where we know the process pretty well. It's Norway, it's Malaysia, it's what we're doing up in Alaska. We're not doing sorta high risk-Big elephant finding kind of exploration. We don't have to because of the where the portfolio resides today. I don't know, Dominic, would you add any more to that? No, I think that's right. I think we, you know, we allocate $150 million a year, which is reasonably modest. I would say that's an up to $150 million a year, depending on the quality of the, of the, of the opportunities. Yeah, Libya s interesting. It's, you know, they've done a remarkable job getting it back up to 50,000 barrels a day. I think the interest we have in Libya primarily is the conversations that we've had with the Libyan government is the resource potential is quite large, and it's very low cost to supply, but they got to change the fiscal terms. The gross margin contract that was the kind of contract that reentry was based on back in the Gaddafi era, is not one that's gonna incentivize a lot of investment. The question we really have around Libya is their line of sight to a different fiscal contract that would then represent a lot of upside, both for the country and certainly for our company. The holding cost is minimal. It's... The contract is pretty good, or it's decent. It covers our costs and sort of gives us a little bit of upside. The real question is the further prize, and that's what we're trying to evaluate. Hi, good morning. John Royall from J.P. Morgan. Thanks for the presentation today. You've spoken a lot about project spend and about total CapEx overall. Can you maybe give us a sense of sustaining CapEx on new projects once they're up and running? Just trying to understand how much higher ex growth CapEx is in 10 years versus today. Go ahead, Dominic. Well, yeah, I mean, the reason we like these longer cycle projects is they do tend to be very much lower in terms of sustaining capital. I think that probably the clearest way to demonstrate the trend of that has been I'd go back to our free cash flow breakeven and how that trends. I mean, when you get to this 28-32 period, as Willow comes online and our LNG projects coming on, our LNG really have almost no sustaining capital. It's very, very low. You get to breakevens that are below $30. That's maybe an indication of how efficient that becomes in terms of sustaining capital. You know, our sustaining capital today at $40 would be about $6 billion. That would grow with time as the company grows its production up towards 2.5 million barrels a day. The sustaining price would come down along with the breakeven. You know, that does, you know, help the competitiveness of the company in terms of reinvestment rates and free cash flow. Great. Thank you. My second one is on Willow, and I guess just Alaska growth in general. I know the natural home for A&S has tended to be the U.S. West Coast. With the regulatory environment seemingly worsening for refiners out there, it does feel like there's some risk that we'd lose some refining capacity there. Where does the incremental barrel of A&S go in that case? I assume, potentially it goes to Asia. Does that create any concern over the differential to Brent longer term? Yep. Go ahead, Bill. Yeah. Really interesting question. I think the first thing is that there's significantly more than just several orders of magnitude more volume going into the West Coast than just the production on A&S right now. You'd have to see significant reduction on the West Coast refining to really displace A&S because the shipping is just so close, right? I think that a way to think about that West Coast capacity is A&S is one of the last barrels that is going to go into the West Coast because it's just so close. I just start there, that you're a long way away, even with the reductions that we've seen even over the last five years, from displacing A&S gas into the West Coast from a pragmatic, practical standpoint. Ultimately, I mean, if you saw everything, go down, then you're correct. It would go into an Asia market because that's the next closest market. The shipping distance into Asia is actually not that far from Alaska versus the West Coast. Your margin doesn't collapse. Right. I mean, maybe it's up to $1 more transportation to get to Asia than it is to get to the West Coast, but it's still gonna trade at a Brent, and it trades, as Andy described. You know, the margin on Alaska stays quite robust even under that kind of a scenario. It trades at a Brent plus right now, and you'd have to lose a lot of market before you'd be displacing that. Okay, Paul. Thank you, Phil. Morning, everyone. Paul Sankey Research. I had a detailed question, which is just a clarification really of what you've already talked about. I got a big strategy one for Ryan. On the details, you're not including any volume assumptions in Port Arthur, you're assuming only one train. Is that correct in the CapEx outlook? The cash flow would come through to the cash flow, obviously. There's nothing in the volume target for Port Arthur. There's no assumption on CapEx of expansions, the cash flow is just added to the cash flow. That's correct. That's the detailed question. Yes, correct. Okay, thanks. Hold on. Check. Ryan, back to 2019. I think, you know, first of all, I commend you for only holding analyst meetings every three years because three and a half years 'cause you said an awful lot has happened. When we think back to the 2019 meeting, what was very clear about it, firstly, you were as often, leaders in the 10-year outlook. What was kind of blatantly obvious in that was that your growth was gonna be driven by the Permian. What was very striking is you didn't have a huge Permian position at the time. You could pretty easily derive that you would make major Permian acquisitions if you were gonna meet your plan, and you did. If we look at the plan today, it's kind of visible where everything's going to come from. I think the critique would probably be that this company looks great on 2030 free cash flow, but it's kind of a long road to get there. I was wondering, and it's a bit of a follow-up, Are you looking at more disposals, which would be the obvious way to sort of juice the performance over the next 10 years, given that you don't seem to need to make any acquisitions? Is that going to be... It's just notable that there's nothing on acquisitions nor disposals in any of your cash flows. Yeah, no, there isn't. This is the base capture portfolio as it exists today. Would we do more optimization over the course of the next 10 years? We'll see how that goes and see what the opportunity might present itself. No, this is our base plan, this is our base assets today. I'd probably take a little bit of exception. It's not back-end loaded, because we're delivering a free cash flow yield today that's competitive with anybody in the business. I think that's the point we're making. It's the best of both worlds. You get it today, and you get duration over the next decade and beyond, given the portfolio that we have. Because of the investments that we're making, the low-cost supply resource, we can keep the reinvestment rate down to that 50% level and generate 4%-5% top-line production growth that generates the 6% cash flow growth and the 11% free cash flow growth at a $60 WTI. I'm repeating myself, but again, you don't have to wait for that. It's coming today. It's coming through $11 billion of distributions at $80 that we set out today. 50% of our cash flow is going back, and that's a distribution yield that I think is competitive with anybody in the market today. Again, you get it today and you get duration and long term from the plan that we laid out. I have to commend you on a share of operating cash flow, cash return, which is also differentiated. If we look at the mega theme, is your step up in CapEx really something that the industry's going to have to follow you in, insofar as historically, you led the market in going to a low, much lower level of reinvestment? Everybody followed you. It's interesting that you're maintaining the variable dividend, because I think people will abandon that now. In the big scheme of things, are you really saying that, yeah, you can't grow in the Permian and sustain the kind of metrics that you're outlying here, and the rest of the industry ultimately is gonna have to either buy each other or step up and do this kind of CapEx increases that you're doing? Thanks. I think there's a longer-term thing that's developing in this business. I think the underinvestment in the E&P side or the resource side of the business, and we have a demand growth projection that leads us, demand growing well into the next decade. When we try to square that strategically as we think about it, yes, we see that I'd rather be leaning in on these longer cycle things early in the cycle rather than later in the cycle. That's, that has us leaning in, which is why a couple of years ago, we looked at the growing U.S. gas production we're gonna have, wanting to get out some access to more of the LNG, more access to those global markets, then clearly leaning in on some of the more mid-cycle and longer cycle projects, just because we're pretty constructive with where this is going over the next decade and beyond. We'd rather do this now, phase it in now, and not get ourselves into a position like we were when we spun the company in 2012. We were, you know, we were executing 7, 8 multi-billion dollar products at the same time. We didn't have a lot of flexibility. We're not going back to that place. That was our learning from early on in this company. We feel pretty good about where we're in. We're leaning in. Yeah, we're spending $2 billion of capital to grow and develop the company over the next decades and beyond, and just believe now is the time to go do it because it fits our framework. It fits what we do best and what we know is competitive in the portfolio. Okay. We have one follow-up, and then that's probably our last question. Hi. Thanks, Phil. Apologies for the follow-up, Ryan. Yeah, leave your $5 on the table, Doug. Paul set me up here, so I had to follow this up. This is Doug from Bank of America. The VROC. You've spent today laying out pretty compelling long-term visibility on your base business, the longevity of your assets. I don't wanna call it annuitized. You get beyond 15 years, incremental DCF is pretty small. You've clearly got capacity to have a sustainable dividend growth above what you have today. Why a variable? Do you believe it gets capitalized? What's the point? Well, I think the point is, the lesson we've learned from the ordinary dividend and, you know, our past history. As long as I'm up here, Doug, you're gonna probably get the same answer. We'll see what the next leadership has in store. I've lived through the ordinary dividend needs to be growable, needs to be growable at a top quartile rate. It needs to be sustainable. It needs to be, you can count on it every single day. It needs to be transparent. You ought to see the growth and the capability to go do that. Again, we go back to a mid-cycle price. We go back to what does it mean? What should the dividend represent at a mid-cycle price? We don't think it should be representing 100% of the return, but it should be there as a huge foundation to the company. We're gonna pay an ordinary dividend, we're gonna pay it through the cycles, and we're gonna grow it competitive with the top quartile. I don't want that dividend to get too high a burden on the company because we know the volatility is still gonna be here. Our plan, which is why we have a 3-tiered system, is the ordinary dividend you can count on. It's gonna be there. It's always gonna be there. We'll supplement that up to our mid-cycle price with some shares that we'll buy back. We'll buy those back through the cycles. We recognize when it's above the mid-cycle price, we're gonna have a lot more free cash flow, and we're gonna give that back. That's why we introduced the third channel through the VROC. We'll see over time if the reward for that is the same as doubling the ordinary dividend or something, I think is what you're suggesting. I think there's more value in being able to demonstrate top quartile S&P 500 annual growth in the dividend. That's where we think adds more value. Excellent. Well, thank you everyone for coming today. We really appreciate it. There'll be a lunch served around the side here. Yeah. Yeah. Please join us for lunch. I hope I know you want to get back and get to work, please join us for lunch, and we can continue some of these discussions. Thank you all for your attention.