Welcome to the ConocoPhillips Market Update conference call. My name is Ray, and I will be your operator for today. Please note that this conference is being recorded. I will now turn the call over to Ellen DeSanctis. Ellen, you may begin. Thank you, Ray, and greetings to our participants. We appreciate your interest in ConocoPhillips. Today's Market Update will consist of a 1 hour and 15-minute presentation, followed by a Q&A session. The presentation materials have been posted to our website. Before I describe today's agenda, I have a few important reminders, starting with our cautionary statement on slide two. Today's update will provide a 10-year outlook for our business based on $50 per barrel WTI at 2020 prices, escalated at 2% annually, as are costs and capital. This is one of several premises in today's plan. Actual results could differ materially from the projections and forward-looking statements made during this call. The risks and uncertainties in our future performance are described on this cautionary statement and in our periodic filings with the SEC. We'll also use some non-GAAP measures today. Reconciliations to the nearest GAAP measure are included in the Appendix section of today's material and on our website. Finally, the company will report second quarter 2021 results in about a month. During Q&A, we will not address any specific questions about the upcoming quarter. Here's today's agenda. Ryan Lance will set the context for today's update and present the highlights of today's 10-year plan. Dominic Macklon will provide our strategy and portfolio in more detail, and he will also address our Net-Zero ambition. Nick Olds will then provide an update on our Alaska and international segments, followed by Tim Leach, who will cover the Lower 48 region. Bill Bullock will provide a summary of the financial highlights of today's plan, and Ryan will make some closing statements before hosting Q&A. Our call will conclude a few minutes before 11:00 A.M. Central Time. Welcome again. Now I'll turn the call over to Ryan. Thank you, Ellen, and thanks to everyone on the call for your interest in ConocoPhillips. It's been a very busy time at our company, as you can imagine. My team and I appreciate the opportunity to provide today's update. Needless to say, a lot has happened in the 18 months since we last laid out a multi-year plan. Most of all, 2020 happened. Not only did our value proposition perform as intended throughout the year, we viewed the downturn as an opportunity to take our returns-focused, shareholder-friendly value proposition to the next level. That opportunity came in late 2020 with the Concho transaction, which has been transformational, as you'll see today. Since 2016, we've been on a continuous path to be the most relevant, sustainable E&P company in the business. We believe today's plan takes another step forward in that direction. We're especially pleased to provide this update against a backdrop of what we think is a truly defining moment for the E&P sector. What do I mean by that? On one hand, the macro setup is encouraging. As the chart on the left of the slide five shows, we have the most constructive commodity price outlook we've seen in a while. Prices are trending well above our own reference planning price band. E&P companies are benefiting from the great reset of 2020, but also continue to exercise discipline and return capital to shareholders. We see indications of interest from new investors who've joined the industry in recent years. On the other hand, there's still a great deal of uncertainty about how prices will play out. The industry remains volatile. Investors have long memories for the poor performance this sector delivered over the past decade. It's not a sure thing that discipline will hold across the sector, and inflation is rearing its head. Of course, addressing energy transition is rapidly becoming one of the most important issues for the industry. It's not certain or obvious how these factors play out, but successful strategies are all about making thoughtful, rational choices in the face of uncertainty. Especially now, the sector needs leadership and conviction in the form of a credible, compelling, and durable plan that can attract long-term sponsorship, and that's what we're bringing today. To us, there's no debate about what sector leadership requires. We call it our Triple Mandate, and it's shown in the middle column. We must continue to meet demand on any energy transition pathway through the most disciplined capital allocation and strongest execution in the business. We must deliver consistent and compelling returns on and of capital, and we must achieve our Net-Zero ambitions for our operational emissions. We embrace this mandate because we believe there is a valuable role for companies like ConocoPhillips in the energy transition. On the right, we list the highlights you'll hear today. We're announcing expected post-Concho transaction synergies and cost savings of $1 billion annually, a doubling of our expected synergies at the time the deal was announced. Based on the efficiencies we believe we've already captured, we're lowering our 2021 capital and cost guidance by a combined $300 million. At the same time, we're increasing our 2021 planned returns of capital with an additional $1 billion of share buybacks. This brings total announced 2021 returns of capital to about $6 billion, or roughly 8% of our market cap today. Our updated 10-year plan has the same discipline as our 2019 plan, but is far stronger financially and brings greater flexibility to adapt successfully through the inevitable changes that lie ahead. Finally, you'll hear that we expect to meet our Net-Zero ambition for Scope 1 and 2 emissions. Underpinning today's plan is our proven value proposition and our strategic objective to deliver superior returns to shareholders through cycles shown on slide six. You are all familiar with this. Our value proposition framework consists of three elements. The Triple Mandate I just described, which ensures everything we do is aligned to the underlying realities of our business, not short-termism. We're in this for the long haul. Our foundation of principles shown in the middle column. Balance sheet strength, peer leading distributions, disciplined investment, and ESG excellence. Financial returns are at the center because this is absolutely what matters most. Finally, our capital allocation priorities are shown on the right. They haven't changed since we rolled them out five years ago. This is the value proposition that has guided our company since 2016. It was validated through the challenges of 2020 and put us in a position to acquire Concho. It is unwavering and is our commitment to our greater responsibilities, including safety, ESG performance and engagement, and to diverse, inclusive, engaged workforce who make everything possible. Let's go to this plan on slide seven. Today's plan is just one version of many plans that could transpire in the future. It is a credible proxy for how you should expect us to run the business. I'll say up front, the plan excludes Willow and the North Field Expansion, due strictly to the current uncertainties on both projects. Dominic will provide a Willow sensitivity in his presentation. It's too early to have a sensitivity for NFE. Both projects must meet our allocation criteria for funding. What will become obvious as we go through today's material is that we have flexibility and capacity to fund both these projects should they advance. Let me step through the numbers. On the left, we show sources and uses of cash from operations. The plan is expected to generate about $145 billion of CFO over the 10 years at $50 per barrel WTI real. We also provide a CFO sensitivity to $40 per barrel and $60 per barrel prices. They're shown as dashed lines in the green sources bar. Capital in the base plan is expected to be $73 billion, or just over $7 billion on average. In this plan, we assume those additional distributions will be allocated to share repurchases. Finally, we expect to reduce debt by $5 billion. Throughout the plan, we retain about $10 billion on the balance sheet. That's the choice we've made to provide resilience, capture incremental opportunities, or fund longer cycle time projects such as Willow or NFE. You can see that the sources and uses are balanced at our reference price of $50 per barrel. We more than cover planned capital and dividends at $40 a barrel, and we have significant additional cash flow upside above $50 per barrel. Some key highlights of the plan are shown on the right. This plan assumes a roughly 40%-50% reinvestment rate. Consider that just a few years ago, the E&P industry spent more than 100% of cash from operations. We have been a leader in discipline and will continue to be so. We anticipate distributing more than $65 billion to owners in our base plan, representing greater than 45% of cash from operations over 10 years. Distributions are funded organically in this plan. That's a significant distinction versus our prior plan, which required balance sheet cash and proceeds to partially fund distributions in the early years. Our cash flow breakeven is expected to average $30 per barrel WTI, down from the prior plan. Most importantly, we expect to grow our return on capital employed by 1 to 2 percentage points per year. Let me bottom line this even more. Over this plan period, CFO is expected to increase 50%, and our expected share repurchases would result in a reduction in our share count. Cash flow up, share count down, plus a growing dividend should deliver double-digit total shareholder returns each year at $50 per barrel with significant upside. Remember, at least 30% of upside goes to owners because our distribution mechanism is based on cash from operations, not free cash flow. As we did in 2019, we challenge any other E&P to show you a better plan with duration. Our proven value proposition, our track record, the uplift from Concho, and the demonstrated ability to work in high and low prices in a rapidly evolving world is unmatched. This plan reflects a combination of high quality, diversified global business, and a massive Lower 48 shale business. We have a unique company where every asset plays a role. We intend to run the shale business in a very disciplined manner for free cash flow and full cycle all-in returns, not growth. Our legacy business will also do its part to fulfill our Triple Mandate and contribute toward our strategic objective to deliver superior returns through cycles. Now, before I turn the call over to Dominic, I'll make one final comment. I've been a part of many integrations in my career. Successful transactions are rare, but I've never seen an integration work as collaboratively as the one between ConocoPhillips and Concho. There's excitement and shared passion to make this a successful transaction in every way, a tremendous credit to our entire organization. I truly believe it will prove itself to be a model to the industry as we continue to capture value from this incredible combination. Let me turn the call over to Dominic. Well, thank you, Ryan, good morning to our listeners. My task for this section is to demonstrate why we believe this 10-year plan is so compelling, not just in its own right, but relative to our prior 10-year plan. I'll begin on slide nine. As Ryan said, the theme for this Market Update is to demonstrate our conviction that we are uniquely positioned for this moment in our sector. My comments will address three topics. First, the compelling plan itself, which reflects significant improvements over the past 18 months from extensive self-help and the transformational impact of the highly accretive Concho transaction. As strong as we believe our current plan is, we have a relentless focus on further enhancing it. Finally, it's never been more important to have the systems and processes to monitor and adapt to future uncertainty. Our company has embedded capability that informs our choices and allows us to successfully adjust as needed. Of course, our future requires taking measures to meet our net- zero ambition on our operational emissions, and I'll describe our early plans and programs in support of this. Now let's address our new 10-year plan, starting with an update on the Concho integration on slide 10. I'm very pleased to share that the synergies and the pace of delivery are exceeding expectations. It's clear that the combination of the companies, including self-help, has yielded value well beyond our initial assumptions. As the integration lead for ConocoPhillips, I can say we really are very pleased with the way our teams are working together and what they have already achieved. We are now comfortable announcing that we expect to achieve annual synergies and savings of at least $1 billion. That includes an additional $250 million since our last update. As Ryan said, this is double our original estimate. I'll take a moment to step through this slide. The blue and gray bars on the left reflect the breakout of our previously announced expected synergies of $750 million. Next to those, you'll see four green bricks representing the expected further $250 million of capture. $200 million of that comes as capital savings and about $50 million as margin improvements from higher netbacks captured by our commercial team. The capital is sourced primarily from lower drilling and completion costs and supply chain efficiency in the Lower 48. Tim will share more on this in his section. Focusing now on the total expected synergies and savings bar on the far right of the chart, the $1 billion is made up of $600 million operating cost savings, $350 million capital, and the remainder from margins. Now, most importantly, these are showing up in our bottom line performance. Let me take a minute to first address the impact of these operating cost savings. As a baseline, we use our 2019 pro forma adjusted operating costs of $7 billion. That was the last normal year pre-COVID. As we said back in February, as the $600 million of cost savings shown in blue on this chart ramp in addition to $400 million of sustainable savings from 2020, we anticipate our operating costs in 2022 will be about $1 billion lower than 2019 at about $6 billion, and that assumes flat production at 1.5 million barrels a day equivalent. The additional good news today is that we are realizing these savings well ahead of schedule, and that's why we're in a position to reduce our full year cost guidance for 2021 down to $6.1 billion. Moving to the $350 million of capital savings shown in the gray bar, $150 million of this was from reduced exploration spend, and that's already factored into our 2021 guidance. The additional $200 million of savings identified is now also beginning to flow to the bottom line. As a result, we're reducing our 2021 capital guidance to $5.3 billion. These identified annual savings have been incorporated into our 10-year plan. Now, we certainly expect the value capture from the transaction will continue to increase, but since the majority of these synergies are now showing up in our 2021 guidance, this is the last time we will show a synergy scorecard. From here on, the proof of further capture will come in the form of stronger execution of the business and better bottom-line results. Ryan showed you a sources and uses view of our 10-year plan. Slide 11 shows the key drivers and outputs of the plan underpinned by a high-quality resource base and our capital allocation discipline. As for the key drivers shown on the left, the plan contemplates average capital of just over $7 billion across the 10 years or approximately a 50% reinvestment rate. Production increases modestly in the low single digits. We could grow production at significantly higher rates, and we have that flexibility should there be a clear and sustained market signal to do so. That's not our base plan. Of course, there could also be periods where it makes sense to hold production relatively flat, just as we have done last year and into this year. Production rates in any given period could vary as an output of our allocation decisions. The plan was designed around an objective to efficiently and profitably expand our cash from operations, which importantly is the basis for our returns of capital commitment to shareholders while also balancing program pace and reinvestment rate. The right side of this chart shows the 10-year free cash flow profile stacked by our Lower 48 and Rest of World regions. Free cash flow grows at a cumulative average rate of 6%, culminating in over $70 billion of free cash flow over 10 years. In this plan, we distribute most of this to shareholders. This is an even stronger plan than we laid out in 2019. As we said then, any acquisition had to make our company better. The Concho transaction did just that. Now, as a reminder, the plan assumes a WTI price of $50 with 2% inflation. I know some of you will be curious if we were to strip out inflation from both price and expenditures, there would be an impact of less than $5 billion to this 10-year total free cash flow. Finally, as Ryan mentioned earlier, the plan excludes Willow and North Field Expansion or NFE. On slide 12, I'll provide a high-level reconciliation of today's plan to our prior 10-year plan, and I'll also include a sensitivity on Willow. NFE isn't in hand yet, so we don't have a sensitivity to show. We provided a fair amount of detail on this slide. I will just hit the high points. The waterfall on the left summarizes the plan on plan variance items. Despite the 2020 reset and slightly lower reference prices, which are partially offset by the two-year time shift, the highly accretive Concho deal, along with our self-help, results in an expected 40% increase in free cash flow for only a 27% increase in share count for the Concho transaction. This metric, more than any other, clearly demonstrates the strength of the transformation. Although we are a bigger company now compared to 2019, the plan has similar average annual capital of about $7 billion, and that's for about the same production growth rate. This translates to the improved reinvestment rate and free cash flow breakeven price you can see on the slide. We have also provided the impact to these metrics, including Willow, assuming we advanced the project at 100% working interest. This shows the project would be free cash flow accretive even within the 10-year period with about a 10% increase to average capital and modest impacts to the other metrics. Nick will share more detail on Willow in his section. In 2019, we believed our 10-year plan was compelling and groundbreaking. As these crucial metrics demonstrate, this plan is even more so, and we still retain significant exposure to upside and our important diversification advantages. I will note we have included a table of key metric comparisons in the appendix for your reference. Moving now to slide 13. As compelling as today's plan is, we will maintain a relentless focus on enhancing it by continuing to drive improvement across every part of the business, including further lowering our cost of supply, leveraging and protecting our portfolio differentiators, applying our rigorous capital allocation process, and continuing to high-grade our portfolio. On the next few slides, I'll dig into these topics in a bit more detail. We believe ConocoPhillips has many competitive advantages, but one we lay particular claim to is our diverse low cost of supply resource base, which was enhanced significantly by the addition of Concho's top-tier position in the Permian. On the left-hand side of slide 14, we've shown our total greater than 20 billion barrel resources under $40 cost supply as a tree chart by geography and asset level. The average cost of supply of this is approximately $30 a barrel. For the first time, we're also showing you the cost of supply of the resources produced in this plan over the next 10 years. That's shown on the right. There are two key points from these charts. First, the resources produced in the 10-year plan have an average cost supply even lower at less than $28 a barrel. Second, the 10-year production and development inventory are diverse geographically by short and long cycle and by maturity. In the plan we're showing you today, every asset plays a role. We hold high-quality resource across a variety of asset classes for a reason. Our diversification and our flexibility enable us to deliver more consistent returns on and off capital through cycles. This is an advantage that no other independent E&P has at even close to our scale today. Given our diverse asset mix, even post-Concho, we have a structural advantage versus our U.S. independent peers with our lower base decline rate. A low base decline means lower reinvestment rates to maintain production. On the left-hand side of slide 15, we show our base three-year annual decline rate, which averages about 11%. In this third-party analysis, the peer decline rates average about 18% over the same time frame. After three years, this translates to approximately 35% less capital for ConocoPhillips to stay flat versus our peers. With the same analysis towards the end of our 10-year plan, when unconventionals will have increased as a proportion of our production, the base decline rate increases to about 12%. With the inclusion of Willow, this would improve back to 11%. While our overall decline rate is up modestly post-Concho, we clearly have an advantage. Now I want to quickly cover two topics that will play an ongoing role in further enhancing our plan, beginning on slide 16. First, our optimized plateau model shown on the left. We introduced this at our analyst meeting in 2019, and it continues to be an important criterion in our capital allocation across all assets. The methodology provides rigor for determining the asset investment pace that optimizes value, capital efficiency, and returns through cycles without overcapitalizing. This establishes the optimal plateau level for an asset, but it doesn't fully address the optimal pace and path to get there, particularly for an asset like the Permian that is early in its development cycle. In isolation, the optimal path would be dictated by the pace at which additional activity could be added while maintaining execution efficiency and capturing the learning curve. However, factoring in macro and corporate considerations, the path to plateau could vary as illustrated on the right. Each of these concepts are core to our capital allocation processes and to our efforts to continuously enhance our programs and plans to drive superior returns. Another way you should expect us to enhance our plan over time is by continuous portfolio high-grading. The table at the top of slide 17 highlights our capability and track record as disciplined sellers and buyers of assets. These have enabled us to improve the underlying metrics shown here, most notably a $10 a barrel improvement in both average cost of supply and free cash flow breakeven since 2016. Active portfolio management will remain key to our strategy. We have a well-understood discipline framework for all transactions. With a very large resource base which can sustain current production rates for more than 35 years, we intend to use our capability to prune assets from the portfolio that won't be capitalized in our plans or those that are very mature and less competitive. This will accelerate value and generate an additional source of cash above the base plan. Over the next 18 months, we have a target to sell $2 billion-$3 billion of assets that meet the criteria I just described. Again, the net proceeds would be considered cash that's available to deploy for incremental value. As illustrated in the diagram on the lower right, one future use of cash proceeds will be to organically restore productive capacity following an asset sale. We have exceptional depth of local supply, high-margin opportunities for that purpose. Economies of scale are important in our business, and we want to maintain those efficiencies while further improving breakevens and cash flow generation capacity. Additional potential uses of surplus cash from proceeds include funding longer cycle, high-quality investments, including low carbon opportunities, as well as, of course, distributions to shareholders. On to slide 18, and I hope by now we've established that we have a very compelling plan and a commitment to enhance that plan through actions we control. How do we manage the future uncertainties that we don't control? How do we demonstrate to ourselves and our stakeholders that our plan is viable and distinctive in the face of change? We start by devoting considerable time and thought to how the future could play out. This is a core aspect of how we lead and manage the business. We have proprietary scenario modeling processes and unique capability to test plans against future possible outcomes. While we can't predict the future with precision, it's not likely to sneak up on us. We have a history of successfully adapting and often leading in the face of new realities. This was true when we launched a new value proposition for the industry several years ago that is now widely followed. This was true when we became the first U.S.-based oil and gas company to adopt a Paris-aligned climate risk framework that included a net- zero ambition for Scope 1 and 2 emissions, advocacy for a price on carbon, and a new Triple Mandate for our business that Ryan described in his opening. We believe our climate risk framework is both ambitious and credible and takes into account our Triple Mandate shown again on the left-hand side of slide 19. The chart on the right side illustrates our Paris-aligned net- zero ambition on Scope 1 and 2 emissions, those are the emissions we control, by around 2050. We've set a medium-term target to reduce our GHG intensity per BOE on operational emissions by 35%-45% by 2030. That gives us an important interim step in support of our Net-Zero ambition. We also have separate near-term ambitions to achieve zero routine flaring and further reduce our methane emission intensity by 2025. The text along the foot of the slide summarizes the key actions we are taking to further reduce our emissions. We have over 100 identified emission reduction projects, about half of which generate an economic return. The other half have the potential to do so over time. We're allocating about $80 million of funding to this activity in 2021. Prioritizing investments in low GHG intensity assets such as Permian and Alaska also helps drive toward our near and medium-term targets. Regarding Scope 3, or end-use emissions, we have long agreed with the need for these to be addressed, a position we have consistently held since 2003. As an E&P company active only in the upstream side of the business, we do not produce end-use products directly for consumers. It is also the case that if everyone addressed their Scope 1 and 2 emissions, Scope 3 would also be addressed. This is why we continue to advocate for an economy-wide price on carbon as the most effective way to address end-use emissions on the demand side, as well as provide the economic incentive for solutions such as carbon capture and storage. That being said, we acknowledge the majority support received at our recent annual meeting for an advisory shareholder proposal that included a Scope 3 target for us as an E&P company. In the coming months, we'll be engaging further with our shareholders for alignment around our climate and energy transition plans and our related target framework. Finally, we have formed a dedicated low carbon technology organization that is responsible for identifying and prioritizing global emissions reduction initiatives, as well as evaluating and developing business opportunities for the energy transition. These could include carbon capture, use and storage, offsets, and blue and green hydrogen. We've covered a lot of ground at a quick pace. I'll end with a repeat of today's plan summary on Slide 20. The many actions we took over the past 18 months, big and small, have established us as the strongest competitor in the business. We'll keep improving this plan, but in the meantime, our dedicated workforce is focused on safely executing our program and bringing this plan to life. Now it's my pleasure to turn the call over for our operation reviews, beginning with Nick. Thanks, Dominic, and let me welcome to our listeners as well. My task for this morning is to update you on the advantaged business segments in Alaska and international we have inside ConocoPhillips. Let's jump right into the material, beginning on Slide 22. As Dominic said earlier, every asset in ConocoPhillips plays an important role in our portfolio and in the success of our plan. This slide succinctly describes the unique diversification advantage our Alaska and international assets offer as a powerful companion to our Lower 48 business. Over the course of the next decade, our plan anticipates our Alaska and international businesses will produce almost 3 billion barrels with an average cost of supply less than $25 per barrel on a WTI basis. Capital over the 10-year plan averages $2 billion annually, excluding Willow and North Field Expansion. I'll talk about both of those projects in the next few slides, but for now, they're not reflected in today's plan due to current uncertainties. On the same basis, production is expected to remain roughly flat at about 770,000 barrels of oil equivalent per day, sourced from legacy positions in Alaska, Norway, Asia, Canada, our emerging unconventional Montney position, and our very stable and predictable LNG businesses in Qatar and Australia. The assets themselves are diverse, but in aggregate, they offer strong margins, longer life, low decline characteristics that structurally lower our capital intensity as a company. They're expected to contribute about half of the plan's free cash flow, or about $35 billion over the next decade. Next, I'll walk you through some plan highlights area by area, beginning with Alaska on Slide 23. Alaska will continue to play an important role in our company for years to come. We have a 40-year history as a proven responsible operator with relationships that run deep. Alaska consists of a set of world-class oil field developments that leverage infrastructure hubs. That is represented by the rings around the three big fields on this map. That is Prudhoe, Kuparuk, and Alpine. Years after the initial development of these fields, we continue to identify and invest in low cost of supply projects that are capital advantaged because of access to existing infrastructure. We also have a long track record of identifying new development opportunities that arise from technology advancements that have occurred on the North Slope in recent years. Technologies such as extended reach drilling and coiled tubing drilling enable us to reach more resource from longer distances and with a reduced footprint. In today's plan, we have an extensive inventory of development projects, including Nuna, Eastern Nuna in the Kuparuk field, and Narwhal in the Western North Slope area. We have our bread-and-butter development work across the area as well, including the recently discovered Coyote trend at Kuparuk and our extended reach drilling rig or ERD program in Western North Slope. As shown in the lower-left side of this slide, over the next 10 years, the Alaska fields are expected to deliver about 850 million BOEs of production at an average cost of supply less than $30 per barrel on a WTI basis. We expect our development projects will more than offset our low base decline of 4%. That's a two percentage point improvement from 2019 plan, enabling us to maintain production of over 200,000 barrels of oil equivalent per day for the decade as shown in the lower right. I'll share a short case study using Alpine as an example of our infrastructure advantages in Alaska. Like all great Alaska fields, the story of Alpine can be summed up in a simple statement, big fields get bigger. As you can see on the timeline in the upper right side of slide 24, Alpine was sanctioned over 20 years ago. It was approved as a 430 million BOE standalone development that included a single central processing facility and two drill sites. Since then, cumulative production has nearly been 600 million BOEs, or 30% beyond the initial estimates of recoverable oil. Currently, we have identified plans in hand that are expected to yield another 600 million BOEs of future production. That means our current estimate of ultimate recovery could be almost three times greater than our estimate at project approval. By the way, the identified future development inventory has an average cost of supply of less than $30 per barrel on a WTI basis, reflecting that infrastructure advantage that makes these assets so attractive. The chart on the right indicates how phases of development projects have impacted field productivity over the past two decades as this great field has undergone cycles of renewal and regeneration. To bring you up to date on a few current projects while we're here, Greater Mooses Tooth 2 is on schedule and under budget for startup later this year. This is projected to add about 30,000 BOEs per day, which will restore rates to the levels of about 10 years ago. This can be seen in the yellow wedge on the lower right side of the slide. Also shown on this map is the outline of the area that's currently being accessed by our extended reach drilling rig. This rig is now drilling the first Fiord West well from the existing CD-2 pad, which is about 7 mi to the north. This will access more than 45 million BOEs of resource from the existing CD-2 pad. It'll be tied back to infrastructure and is scheduled for first oil later this year. This is what we call growth without new gravel. Before I conclude my Alaska comments, I'll move west to the National Petroleum Reserve to discuss Willow, which we believe could be the next great Alaska hub. Dominic showed you a plan sensitivity for Willow, and I'll provide a project update. We've now completed our appraisal work of Willow with a 12-well program that de-risks the resource. We've incorporated the appraisal information into our front-end engineering and design, also known as FEED, a process that optimizes the plan of development for this new world-class opportunity. Slide 25 describes our planned field development, our project timeline, and provides the capital and production impacts for this project. We've had several years to consider and evaluate various plans of development using our optimization models. We have concluded that the highest economic value will be achieved using a modularized central processing facility with a capacity of 180,000 barrels of oil per day and 250 million cubic feet per day of gas handling. Field development will require approximately 200 wells, which will be drilled from only three drill sites, thus greatly minimizing our footprint and enabling us to capture efficiencies. On our current timeline, first oil occurs about six years after we take our final investment decision or FID, and we're on a path to have FID completed by year-end if the litigation uncertainties are resolved. At 100% working interest, we estimate the project requires approximately $6 billion of capital to first production, including pre-drilling development wells. The estimate for the total plan of development is approximately $8 billion to develop a recoverable resource, which is estimated at 600 million BOEs. Willow is very competitive on a cost of supply basis in the mid-$30s per barrel, and we have identified up to 3 billion BOEs of nearby prospects and leads with similar characteristics that could leverage the Willow infrastructure. This offers significant long-term upside to this project. To conclude, we have every reason to believe that Willow should and will be developed. However, we've been clear that we won't take the final investment decision until the legal risks are resolved. That wraps up my review of Alaska. Now to Canada. I'll start with Surmont asset on slide 26, which has been transformed into a more robust free cash flow business while also lowering our GHG emissions. This is exactly what we expect every asset to do. Since 2019, our Canadian team has focused relentlessly on improving the profitability of our oil sands business by lowering the cost structure, deploying innovative technology to improve capital efficiency, and executing projects like the Diluent Recovery Unit and dual diluent. These projects, which will be in service later this year, provide commercial flexibility and expand margins, which drive down the cost of supply. As a result of our comprehensive efforts, the cost of supply of Surmont has improved by 20% versus the prior plan. As the graph in the upper right shows, in today's plan, Surmont grows modestly using existing infrastructure with an average annual capital of about $80 million. Full field CapEx is lower than our prior plan with 100 fewer wells due to recovery factor improvements, deployment of innovative flow control devices, and optimizing pad sequencing. Free cash flow and profitability are important, but so is making meaningful progress on reducing emissions. We have successfully commercialized non-condensing gas technology after seeing a reduction of 20% in steam oil ratio in the field pilots, and we've recently started a steam additives pilot. Today, we have line of sight to a 30%-40% reduction in GHG emissions intensity with an ambition of a 50% reduction by 2030. Our Surmont asset is performing its role in our portfolio. Our Canadian team is creating a much more resilient asset with stable production and free cash flow generation to fund the Montney growth story you will hear about on slide 27. At Montney, we have built a legacy position in this unconventional liquids-rich play. With the 2020 acquisition from Kelt, we have a core of the core position of 300,000 acres in the sweet spot of the play, as shown on the map to the left. This large contiguous resource base is still largely undeveloped. We continue to evaluate and optimize our development plans while staying disciplined and going at a pace that allows us to gather data, learn, and maximize value. By the way, we are not reinventing the wheel here either. We are reaping the benefits of applied learnings from our Lower 48 unconventional resource expertise as we go. Although we're still in late stages of appraisal activity, that expertise has already paid off. After only four pads, we've already seen significant progress on efficiency and cost improvements, including a 35% improvement in drilling days per 10,000 ft drilled, a 30% increase in frac stages per day, and a 25% improvement in drilling costs over the program so far. Currently, the asset is producing approximately 30,000 barrels of oil equivalent per day, of which 50% is liquids. Over the 10-year plan, we expect the liquids rates to grow to about 60%, with the majority being high-value condensate. As shown on the right, our 10-year development plan grows Montney to about 180,000 barrels of oil equivalent per day as we exit the decade. Now I'll move to Norway and Asia on slide 28, where we have strong legacy positions that represent a competitive advantage for ConocoPhillips because they deliver high-margin production and significant free cash flow at some of the lowest cost of supply inventory in our portfolio. We have several highly competitive projects in the inventory that average less than $20 per barrel cost of supply, which is an improvement over our 2019 plan. Like our other great conventional fields, these opportunities leverage existing infrastructure and utilize standard repeatable project designs to drive capital efficiency and lower capital costs. In aggregate, these assets decline modestly over the 10 years but are still expected to generate $7 billion of free cash flow over that timeframe. Finally, as we announced last year, we have several discoveries and new licenses that we'll be exploring and appraising over the next several years. In Norway, we'll be appraising the recent Slagugle and Warka discoveries, and in Malaysia, we've added prospective new operated exploration acreage at SB 405. I'll conclude my asset tour on slide 29 with a quick overview of another significant competitive advantage for ConocoPhillips, and that's our interest in QG3 and APLNG, two premier LNG projects. These two assets today produce about 200,000 barrels of oil equivalent per day. Over the next decade, production remains roughly flat at an average of about 180,000 barrels of oil equivalent per day. As Dominic described, assets like these play a significant role in our portfolio by lowering our aggregate decline rate. In Qatar, we were invited to bid on our North Field Expansion. We like the project very much, but it must meet our cost of supply and financial framework to add it to the inventory. More to come on this. Our LNG operations are performing extremely well. APLNG downstream operations recently benchmarked as top quartile. There is a tremendous effort underway to reduce cost and improve efficiency to maximize near-term distributions while maintaining production. Already, these efforts have lowered the five-year cash breakeven for this project to the mid $20 per barrel. I'll wrap up with the key drivers for the Alaska and international 10-year plan shown on slide 30. Under our current plan for an average annual capital of roughly $2 billion, these assets are expected to maintain about 770,000 barrels of oil equivalent per day of high-margin production over the decade. These regions benefit in aggregate from low-cost supply inventory with upside from future projects, infrastructure advantages, and low capital intensity characteristics. Over the next 10 years, we expect the assets to generate free cash flow of about $35 billion, yielding roughly a 40% reinvestment rate over the plan timeframe. The Alaska and international businesses represent a truly unique diversification advantage compared to our peers. As I said earlier, it represents a powerful companion to our Lower 48 business, which Tim will now address. Thanks, Nick. When you look at the quality of the assets Nick described, combined with the Lower 48 assets, I think you'll see that we have the best of both worlds. That was a big driver in the decision to bring Concho into the mix. Before I begin, some of you know me from my prior life in the industry. I spent my entire career building Lower 48 companies around four philosophies that I think matter most: great assets, high-performing teams, smart capital allocation, and strong balance sheets. ConocoPhillips has the best of all four of these. I believe it's only going to get better. The reason I bring this up is to say that my optimism since joining ConocoPhillips continues to increase. After only six months, I believe we've quickly established our Lower 48 business as an industry leader. You've heard already, the ConocoPhillips and Concho integration is progressing successfully. The combination of our two companies presents an opportunity to build and optimize a business that couldn't have existed for either of us alone. Our teams are working well to simultaneously execute every step shown on slide 32: synergies, execution, technology and innovation, emissions reduction, and commercial advantages. Also, I hope you notice that our one Lower 48 logo, it represents the concept of building one great business regardless of our heritage. As I step through today's deck, there are themes that I want you to take away from my comments. Our approach to this combination is focused on ensuring that the resulting company is stronger than the two companies individually. We've assembled the best assets and the best team in the business. Operational excellence and capital efficiency are paramount to our success, and it's clear to me that we've only just begun to realize the true value of the combination. The Lower 48 region is expected to generate significant free cash flow. When combined with the rest of our global assets, we have a great formula for delivering superior returns on and of capital through cycles. We're committed to playing an important role in the company's Triple Mandate by developing the lowest cost and cleanest barrels with the best returns. Not only did the transaction combine two quality teams, but it combined two great asset positions, as shown on slide 33. The depth and quality of our inventory gives us flexibility and optionality to adapt to market conditions and continuously enhance our development plan. ConocoPhillips has a major presence in the core of all the major oil-rich basins in the Lower 48, as shown across the top of this slide. Our position includes more than 1.5 million net acres. The wedding cake on the lower left represents the resource we expect to produce in this 10-year plan. Under the plan, we'll produce 3.9 billion equivalent barrels with an average cost of supply of less than $30 per barrel and drill approximately 6,800 wells with a fully burdened average cost in the low 30s WTI. One of the significant advantages we have in the Lower 48 is our ability to leverage our learning, knowledge, and expertise across these four basins. This will have a substantial impact on accelerating learning curves and driving efficiency. Slide 34 shows our big four unconventional basins with some key statistics from today's plan. In this plan, we're choosing to fund a more disciplined program overall versus focusing on a quicker ramp to plateau. We still have a lot of work to do to optimize our development plans at the basin level and at the overall region level. That work is underway and will be ongoing. Now a few comments on each basin. I've spent 40 years working the Permian. Concho's experience in the basin gives us a knowledge advantage from an execution standpoint, and we're quickly applying that experience to the Heritage ConocoPhillips position. The company's expanded size and scale give us advantages we wouldn't have had on the Concho side without this transaction. We've got more chips to play. Our Permian position has the highest single well EURs in both Delaware and Midland, and we're one of the top producers in the basin. The Permian is expected to generate almost 65% or $23 billion of the 10-year free cash flow from the Lower 48. Moving to the Eagle Ford. We're positioned in the core of the liquids-rich part of the play with more than a decade of inventory. We just achieved a milestone by bringing on our 1,500th well. We're the second-largest producer in the basin with the highest EURs. We're lowering our cost to supply through technology wins like refrac. What we learned in the Eagle Ford, we're taking to other basins. In this plan, the Eagle Ford is expected to generate $8 billion of free cash flow. The Bakken represents a material position in an oil-rich basin that is generating steady cash flow from consistent performance. The teams are rapidly innovating and currently outperforming production expectations with lower capital spending. Resource estimates have increased by over 20% from completion optimization work, and we've seen considerable progress on our emissions. Flaring has been reduced by more than 75% since 2019, and we're on track for zero routine flaring by 2025. Bakken is expected to generate $4 billion of free cash flow in today's plan. Ryan described the $1 billion of synergies we've identified so far, and he also mentioned that we believe we have numerous additional opportunities for value capture as our integration progresses. Slide 35 shows four examples of value drivers on a pro forma basis from 2019 to present. It shows that prior to our merger, both companies were improving efficiencies. That's continued post-transaction. For example, a 30% reduction in drilling days driven by automation and technology. A 30% increase in efficiencies in frac stages, primarily due to twin frac technology. A 10% improvement in production per foot and a 15% improvement in operating cost per BOE. Each of these improvements matter, they are most impactful when they're added together. Here on slide 36 is an example from the Delaware Basin of the power of compounding the incremental improvements from the prior page. In this example, since 2019, our cost per foot for a single well in the Delaware has improved by 30% structurally or 40% if you count the benefit of deflation. Each one of these bricks represents the many actions to improve efficiency. When applied across our well inventory, you begin to get a sense of how impactful our future efficiency uplift could be. On the next three slides, I'll speak to some of the technology that could yield further efficiency gains across our entire business that are not yet reflected in today's plan. These are the things I'm most excited about. How can we get more for less? What I'll describe aren't necessarily new technologies. What's new is how we're rapidly transferring technologies and adopting best practices. Because of our scale, the value of these advancements is greatly amplified. Slide 37 gives you two examples of drilling efficiency technologies. First, slim hole drilling. This design changes improved rates of penetration by about 30% and reduced drilling costs by more than half a million dollars per well. We use less expensive drill bits, smaller diameter holes, resulting in faster drilling and smaller surface and intermediate casing, all while preserving the 5.5 i nch production casing. This is not a new concept in the Permian, but a great example of how our combined company is quickly adjusting. Right after the deal closed, we quickly modified our permits on the Heritage ConocoPhillips wells to include a slim hole design based on our experience. On the very first well, we reduced spud to spud days by 50% and saved more than $1 million versus AFE. Automation of drilling operations is an area where the Eagle Ford team has led the industry. We've been able to utilize data from past drilling programs to automate our drilling and improve curve drilling times by 20%. Stuck wireline events have reduced by 65%. We recently drilled our first 14-degree curve, a 40% higher build angle than our typical horizontal well. That added an additional 300 ft of lateral or a 4% improvement at no cost. Next, I'll describe two completion technology examples, twin fracs and alternative fuel fracs, shown on slide 38. Twin frac or simulfrac technology is being widely adopted across the industry, but we've been quick to implement the technology in all four of our core basins. We've achieved a 40% reduction in our frac cycle times, which means we bring production on more quickly. On average, we're realizing savings of about $200,000 per well, and we're getting our wells online 1-2 weeks earlier, depending on the lateral length. In 2021, approximately 35% of our completions will be done using twin frac, and we expect our use of this technology to increase in 2022. Next, dual fuel and e-fracs reduce fuel cost and emissions. We successfully utilized both technologies in the Permian. In 2021, 96% of the wells we completed in the Permian utilized one of these two technologies. With e-frac, frac pumps are powered on-site using CNG or fuel gas. This eliminates diesel usage, improves productive time by reducing maintenance, and generates more usable horsepower. It also reduces noise and emissions significantly. Dual fuel is a technology Concho began implementing in 2019. Dual fuel frac spreads utilize frac pumps that run off a mix of diesel and CNG. As we refined our approach, we've been able to routinely reduce diesel usage by more than 65%, which not only generates significant capital savings on fuel but also reduces emissions. Currently, we're seeing savings of almost $100,000 per well utilizing this technology. We see additional upside to both dual fuel and e-fracs as we expand our utilization of lease gas. Final technology I want to touch on are refracs and accelerating value from big data, specifically multivariate analysis or MVA. I'm on slide 39. We talked about our application of mechanically isolated refracs in Eagle Ford before. By late 2019, we completed 15. Now we've completed more than 50. The graphic on the upper left of this slide shows production rate versus time. As you can see, we've realized a significant uplift. On average, our refracs added an additional 75% reserve recovery at a fraction of the cost of a new well. In the Eagle Ford alone, we've identified more than 350 candidate wells for refracs, and we're continuing to test several promising concepts that could improve performance and significantly expand our inventory. We're also beginning to fully leverage our Eagle Ford experience to expand our refrac program into the Permian. We have plans to test refracs in the Midland and Delaware basins later this year. MVA is an applied technology that could provide tremendous upside to our 10-year plan. In the Bakken, we've used MVA to modify our completion design based on individual well characteristics. We compiled a dataset consisting of 43,000 data points from 1,300 wells in the basin, then used MVA to design customized completions for every well based on its specific characteristics. This allows us to avoid things like over-fracking wells where larger completions are less beneficial and apply larger completions where it pays off. We expect to realize resource improvements of more than 20% and a cost of supply improvement of up to $4 per barrel in our core area from this application. We've already begun expanding the MVA application to other assets to create the best development strategy across our entire business. These last few slides were short examples of many efforts we have underway across the Lower 48 to improve efficiency and performance. They're not fully baked into our plans, but could significantly expand the value of our Lower 48 franchise. In addition to technology, there are further upside opportunities not yet included in our plan from the commercial part of our business. ConocoPhillips' commercial position and capability open up new options to capture additional margin for the products previously produced by Concho, the addition of the Heritage Concho volumes increase the scale of ConocoPhillips' commercial operation. Through our capability and market access, Heritage ConocoPhillips assets have often seen a sales premium on Delaware production of up to $1 per barrel on netbacks versus Heritage Concho netbacks. That's due to the access to diverse markets for Permian production, including Gulf Coast access for crude and West Coast access for gas. This advantage can now be applied to the much bigger post-Concho position in the Permian. ConocoPhillips markets more than 1 million barrels of oil a day, and we're a top five North American natural gas marketer of more than 9 BCF a day. We see potential to add value to both Heritage positions by leveraging legacy commercial relationships. We're just getting started on looking for uplift opportunities from improved contract terms and optimizing commercial offtake options. Lastly, I want to point out that our larger footprint provides even more opportunity to high-grade our portfolio through trades, divestitures, and bolt-on acquisitions. This is something that we've always been keenly focused on and will remain a key part of our strategy. Complete with the Lower 48 10-year plan metrics shown on slide 41. Like the Alaska and international business, this region creates a massive amount of value and contributes significantly to the company's plan. Over 10 years, this plan is expected to generate over $35 billion of free cash flow, an 80% increase compared to the Lower 48 region in the prior 10-year plan. We remain disciplined with expected average annual capital of about $5 billion for modest growth. This implies a reinvestment rate of under 60%, far lower than shale businesses historically. We intend to lead and manage our shale assets for value, durability, sustainability, and returns of capital. Hopefully you sense my excitement and optimism for what our Lower 48 is today, but also what it can be in the future. Thanks for your time, and now I'll turn the call over to Bill to cover the financial plan. Thanks, Tim, and thanks to our callers for joining us today. I'll be summarizing the financial elements of our compelling 10-year plan. Let's begin on slide 43. We believe the plan we've laid out today responds to this defining moment for our business. There's an opportunity for renewed interest in our sector, one that we want to seize. Our disciplined value proposition aligns with the financial framework investors want. A strong balance sheet, returns on capital, and returns of capital. We have a proven track record of performance in applying these principles, and we firmly believe they remain as important as ever. First, we want to maintain our A-rated balance sheet. Across our 10-year plan, the leverage ratio stays very healthy, with average net debt to CFO of 1 x or less. As we previously announced, we intend to reduce debt over the next five years, which will further strengthen our balance sheet, reduce interest expense, improve our free cash flow breakeven price, and provide resilience in periods of volatility. Next, returns on capital improve steadily across our 10-year plan. Our goal is to be competitive with the returns of the broader market, and we believe this is critical to increasing sector sponsorship. Finally, consistent, sustainable, and compelling returns of capital. It's essential for expanding our investor base. As you've seen, this plan has the capacity to distribute about 45% of cash from operations. That's at prices of $50 per barrel WTI, exceeding our commitment of greater than 30%. On the next few slides, I'll cover these topics in more detail, starting with slide 44. We consider our balance sheet to be a competitive advantage, and we think performance through 2020 reaffirmed this. We easily maintained our dividend and never needed to access the capital markets for liquidity. We were able to voluntarily curtail production at the lowest point of the downturn and preserve that production for the recovery. We estimate that decision will yield over a 50% rate of return as strip prices. We emerged from the historic downturn with a strong cash position, with net debt to CFO of less than 1x, and with our A rating intact. The upper left chart plots consensus 2021 net debt to CFO for ConocoPhillips, for our peers, the S&P 500 Energy, and S&P 500 Index. Simply put, our company's balance sheet is one of the strongest in the industry, and we intend to further enhance our balance sheet strength and our resilience with a $5 billion debt reduction program, and that's over the next five years. As shown in the upper right, we plan to lower our gross debt to $15 billion and reduce annual interest costs by at least $250 million. We expect this process could also include a refinancing of a portion of our higher coupon debt. As the lower left chart shows, our net debt to CFO ratio improves through the course of the plan. Balance sheet strength is a critical component of our financial framework, and we treat it as a strategic asset, just like our low cost of supply resource portfolio. Now moving to slide 45. One of the fundamental changes needed to make our industry more investable is attractive through cycle returns on capital. We believe ROCE is one of the best measures of a company's long-term performance. In the upper left, you can see ROCE for the S&P 500 Energy Index over the past four years. We're showing this period as 2017 was the first full year after our strategic reset and after the launch of our new value proposition. The median returns over that timeframe for our sector were 2%, while top quartile delivered 7%. Comparable metrics are shown in the middle row for the broad market index for the last 20 years. Median returns were consistently 10%. Top quartile returns were 16%. The bottom row identifies ConocoPhillips ROCE. It begins with the four-year average for 2017 through 2020. This is the same four-year period as the energy index. Our average annual returns were 6%, close to the top quartile for energy, but simply not good enough. We don't think they're good enough. In today's plan, at $50 per barrel real, our projected returns grow to 13% within five years. By the end of the plan period, we expect our returns to be differential to our industry and competitive with the top quartile of the S&P 500. That is the prize for us. Now the charts on the right show the trajectory of earnings and ROCE over the plan period. Our earnings are expected to grow as our disciplined capital approach and our investment in low cost of supply resources yields higher margin volumes with lower DD&A rates. Our captured cost synergies will further improve earnings by lowering operating costs. ROACE growth comes from both improvements in both the numerator and the denominator. Even with a substantial increase in earnings, the company's capital employed is not expected to grow as excess free cash flow is allocated primarily to shareholder distributions. As a result, ROACE should grow significantly over the next 10 years. On slide 46, ConocoPhillips has one of the clearest commitments to shareholder distributions. We have a track record of delivery. The company is committed to a distinctive, sustainable shareholder distribution policy, one that is tied to total cash from operations we generate in a year, and this is regardless of capital expenditures. Our commitment is to return greater than 30% of CFO each year, and is comprised of a competitive, growing ordinary dividend and supplementary distributions, which we have historically made through share buybacks. Since we established this priority in late 2016, we have exceeded our target with cumulative distributions of 45% of CFO. Looking at 2021, we are on track to return a similar amount, and that's shown on the right. First, our commitment to the ordinary dividend remains unchanged. In March, we announced the resumption of our buyback program at $1.5 billion. In May, we announced plans to begin selling our position in Cenovus and exchanging into ConocoPhillips shares over the next year and a half. Depending on Cenovus share price, that represents about $1 billion of additional buybacks this year. Today, we announced an additional $1 billion in increase in buybacks for 2021. With today's increase, total planned distributions for the year are now about $6 billion. That represents approximately 7% of today's market cap. As you saw on Ryan's opening slide, today's 10-year plan sources and uses are balanced at the reference price of $50 per barrel. It all requires no drawdown of cash balances or asset sales to execute the plan. This is a robust plan. It performs exceptionally well. I think it's also safe to say that, at least in the near term, there's significant price upside to our plan. That's described on slide 47. We've talked about our torque to price upside before. As a reminder, we are unhedged, oil-weighted, and operate primarily in favorable tax and royalty regimes. We are also continuing to drive efficiencies across the entire business, as you've heard today. Our current sensitivities are shown in the lower left corner. Every dollar of oil price represents about $300 million of additional annual CFO. Today's plan at $50 a barrel is expected to deliver about $145 billion of cash from operations over the next 10 years. Round numbers, expected CFO would be about $175 billion at a $60 barrel reference price. That certainly won't be a planning case for us anytime soon. In the short term, we expect to have additional cash to deploy from upside and from proceeds. How do we think about deploying this excess cash? That's shown on the right. We continue to utilize the clear framework we laid out in 2016 and follow our priorities. We've satisfied priorities one and two, even at our lower reference case. In today's plan, priority three, our balance sheet, is fully satisfied. That leaves priorities four and five. Priority four is all about returns of capital. It is shown here in a bolder format to indicate that we would expect additional distributions to be our primary allocation. In other words, shareholders benefit directly from higher prices as CFO grows. As for priority five, we would expect to deploy some available cash to strong and accretive long or short-cycle investments, including potential low-carbon investments if they meet our disciplined framework for returns. That wraps up our financial summary. To recap, our balance sheet stays strong and resilient. Our ROACE improves, consistent with our ambition to be competitive against the broad market. We distribute a very significant percent of cash from operations to shareholders over the next 10 years, just like we have in the past, with upside to those distributions if cash improves beyond the plan from higher prices or proceeds. We believe this is an exceptionally strong plan that once again sets us apart. Now, I'll turn the call over to Ryan for closing comments. Thank you, Bill. Before I turn the call over to Q&A, I want to thank our listeners again for your participation today. I also want to publicly thank my team and the entire ConocoPhillips organization, not only for their tremendous day-to-day contributions, but also for their support in preparing today's material. All of us here recognize this is an important moment for our sector. We believe our company can meet this moment in a very compelling way by embracing the opportunity to play a valued role in the energy transition with our Triple Mandate shown on slide 50. That is we'll meet any reasonable transition pathway by investing in the lowest cost of supply barrels. We'll deliver competitive returns of and on capital and achieve our Net-Zero ambition. Our proven value proposition guides us in the short, medium, and long term. We are exceeding expectations in 2021. We believe our updated 10-year plan is exceptional. At our reference price, we grow CFO significantly. We invest about 50% of that CFO while expecting to return most of the remainder to our shareholders. Our breakeven price drops. Our balance sheet stays strong, which improves our resilience to cycles. Importantly, we see a way to make return on capital employed competitive with the broad market, all while retaining flexibility to adapt as the future unfolds and remaining focused on delivering superior returns through the cycles. As I said at the outset, since 2016, we've been on a continuous path to be the most relevant, sustainable E&P company in the business. We believe today's 10-year financial and operational plan takes another step forward in that direction. Now I'll turn the call over to the operator. We'll start our Q&A. If you would like to ask a question, please use the raise hand button at the bottom of your screen to enter the queue. When your name is announced and it's your turn to speak, please follow the prompt on your screen to unmute your microphone and state your question. Our first question comes from Jeanine Wai from Barclays. Jeanine, please follow the prompt on your screen to unmute your microphone and state your question. All right. Hi, good morning. Can you hear me? Yes, we can, Jeanine. Good morning. Good morning. Thanks so much for all the details today. Really appreciate it. Our first question is really just on free cash flow allocation. Today, you once again demonstrated that your commitment to shareholders is very strong, with increased buyback this year and also more progress on integrating the Concho assets. It really strikes us in our model that at the current strip, and even after paying back the $65 billion in cash, or just paying that out to investors, you end 2025 with over $17 billion in cash, and you probably end the 10-year period with over $30 billion in cash. This is a very high-class problem, and I know you just went over some of the priorities on slide 47. It seems like priorities one and two and likely three will be satisfied. If the current crude market plays out, should we really think about additional buybacks as the first call on cash in excess to your $10 billion minimum balance? Or just broadly, how should we think about the free cash flow allocation between the base buybacks for the debt reductions and opportunistic portfolio replenishment in priorities four and five? Yeah, let me take a shot at that. Bill can chime in as well anything that I miss. I think you're right. Jeanine, we recognize, I guess, if the strip curve plays out, you've seen the torque to the upside in the company at $60 per barrel and what happens to our cash flow and our free cash flow. We'll remain pretty disciplined on our capital investment. We're waiting to see how the market responds, how the macro rebalances itself as the demand continues to improve and the excess supply that the OPEC Plus group has kept off the market. We'll see how that transpires over the next couple of years. You've seen our allocation. The balance sheet is strong. We have a plan to reduce the gross debt over the next five years by $5 billion. Really, the call on most of that free cash flow should expect to go back to the investor and to our shareholders. That's been our plan. Our commitment is greater than 30% of our CFO, and I remind people that's our cash flow operations. It's not free cash flow. As the commodity price improves, investors get greater than 30% of that cash flow, not just of the free cash flow. We've been committed to that. You look over the last six years, our return of that cash has been over 40%. That's really our intention. Our commitment is over 30%, and you can see what our intention has been, and so that's how we think about it. This plan, it's allocated to the share buyback channel. We've looked at different ways of returning capital back and continue. Right now we believe our shares are a really good buy. We're buying our shares back, and have committed to that $6 billion amount in 2021. Okay, great. Thank you. Our second question is on just M&A and portfolio recycling, everybody's favorite topic. Conoco has been active in the M&A market, both as a seller and more recently a buyer. It would seem that the $10 billion in minimum cash reserve that you all talked about would include some strategic cash for projects and otherwise. Our question is, what does the current M&A landscape look like to you, given perhaps the more recent development that some sellers are motivated more by shareholder initiatives more so than asset value? Has Conoco's M&A hurdles really increased as well, given recent shareholder focus on emissions? Thank you. Yeah, thanks, Jeanine. I think we're pretty focused right now on integrating the Concho transaction, and Tim talked about all the outstanding things that are happening in our Lower 48 organization as we've brought Concho into that. The markets can change. They go up, they go down. Our framework does not change. The cost of supply framework that we described to you back in great amount of detail in November of 2019 at our last AIM, it remains in place. It's what guided us through the downturn in 2020 and continues to guide us today. Obviously, we look at things. We think more consolidation needs to occur. I think we believe we've done a pretty good job of pulling together these two great companies with Concho and ConocoPhillips. You should expect us to We stay in the market, and that's both on the selling and the buying side. You described today $2 billion-$3 billion of dispositions. We're going to take the opportunity in this kind of a market to move some things out of the portfolio that aren't competitive on a cost of supply basis for capital inside our portfolio. That's what we, to your point, we've had a track record of doing that for a long period of time, and you should expect us to continue to high-grade the portfolio when you see the opportunity, both on the buying and the selling side. Our next question comes from Neil Mehta from Goldman Sachs. Neil, please follow the prompt on your screen to unmute your microphone and ask your question. Great. Ryan and team, can you hear me okay? Yeah, we can, Neil. Thank you. Thank you. First question is around Willow. Can you just walk through in a little bit more detail what are the gating factors that you're watching here before moving to FID, and in particular around litigation? You made some references to it. How do you know the coast is clear before moving ahead with the project? Yeah. Thanks, Neil. I'll just maybe at a high level let Nick chime in a little bit. He's responsible for that area. At a high level, we're just not going to move forward till we get all the pieces put together before we take FID. We just won't get out over our skis in terms of the project. There's been some uncertainties that have been resolved over the last couple of years. There's kind of one remaining. I can let Nick talk you through some of those details. Yeah, Neil, we hope this will be resolved later this year, but it's still uncertain. You saw that the Biden administration also cleared up the review of the record of decision. That's very favorable as well, a positive outcome. Just really showcasing that the BLM and the cooperating agency has really done a thorough, robust review of the record of decision. The Department of Justice issued a brief. We expect the Alaska District Court to have a decision in the third quarter. That could go into appeals. We're watching that closely. Obviously, we've intervened on that case. We've been successful in the past. We've got significant support, as you've seen from the North Slope Borough and the State of Alaska. Our key focus right now is really on that front-end engineering design to continue to refine the cost, the schedule, and any final development considerations targeting FID later this year. As I mentioned in my prepared remarks, we won't FID this until we get actual certainty in these legal risks. I would add, Neil, that this isn't unusual for Alaska. Just about every project up there has gone through this. We know it's coming, we plan for it, and we know how to deal with it. Thanks, guys. The follow-up is around ESG. In this presentation, really appreciated the focus on ROCE and the multi-year target and the aspiration of getting into the first quartile. I think that resonates well. At your May Analyst Day or May shareholder meeting, there was a resolution around Scope 3 targets and investors asking Conoco to take that into consideration around strategic planning. Can you just provide your thoughts around that? What does it mean in practical terms in the way that you approach your business? Or is this something that you're already taking into consideration, so as the investment community, it doesn't have a real bearing on the way we should evaluate the company? Hey, Neil, it's Dominic here. Happy to address that. Obviously, this is an important area, which is why we wanted to address it directly in our prepared remarks. I think just to recap some of those points. We do believe our climate risk framework is both credible and ambitious and addresses the realities of our Triple Mandate. Meet transition pathway demand, deliver competitive returns, and achieve Net-Zero emissions on the emissions we control, which is just Scope 1 and Scope 2. Concerning Scope 3, of course, if everyone addressed their Scope 1 and 2 in a similar way, then Scope 3 would be addressed, and that is not a trivial point. It's a very important point. We agree that end-use emissions need to be addressed. We've actively advocated for that really since 2003, and we really see that as the most effective way of actually dealing with Scope 3 emissions on the demand side. I think that you can hear that we've given a tremendous amount of thought to this, but we do acknowledge the shareholder resolution. Our priority is now to engage further with our stakeholders, our shareholders, and talk about all this. Talk about our climate energy transition plans and our related target framework, and we'll see what happens as a result of all of that engagement. Hopefully, we've laid out just clearly how we think about this. Our next question comes from Alastair Syme from Citi. Alastair, please follow the prompt on your screen to unmute your microphone and state your question Hi, thanks for taking my question. It was really just one question. ConocoPhillips is known a lot for the scenario modeling that you do. I just wanted to get your perspective about how you think that as U.S. shale gets its act together, which I guess others will logically follow the lead that you're showing here. How that happens, how you think OPEC + might or should react to that scenario. Yeah. Thanks, Alastair. I hope we've been pretty encouraged over the course of the last year and a half. We've seen the E&P sector kind of take up the value proposition that we've been espousing for a number of years, and we're strongly encouraged by that. I think as we look at our scenario plans, we look at a number of different cases of U.S. tight oil growth, and we follow all the key indicators to try to track that to see which direction we're going. I think we're encouraged that investors have weighed in and have said, "Don't go back to not only investing over 100% of your cash, but invest something quite a bit less and give some of that back to the shareholders." I think we've seen that. That should moderate growth. That should be a more reasonable pathway coming out of the U.S. tight oil. Now we've seen some of the privates take advantage of the current market and are growing, but they don't have the rock that we do, so they don't have the quality that we do. I guess it'll become more important down the road who has those best rocks because that's where you're going to get the best returns in this business. We watch it pretty closely, but I think the discipline is holding, and we don't really see today a pathway where the U.S. starts to overwhelm such that OPEC would get concerned about that. I think the question becomes when OPEC gets all their spare supply back into the market, what is the price at that point in time? That's what we're watching in our scenario monitoring pretty closely. Once we return to 100 million barrels a day of demand, and OPEC's able to return all of their spare supply into the market and make sure that inventories remain at five-year kind of average levels, we need to see what the price does there. Because that'll be a signal to the U.S. tight oil group as to how much demand there is for U.S. crude. That's what we're watching pretty closely. Hopefully you saw it today, Alastair, through our conversation that we're committed to running the Concho business for returns, not for growth. That's going to be really important, and that's where the rock and the resource is really important. Our next question comes from Roger Read from Wells Fargo. Roger, please follow the prompt on your screen to unmute your microphone and state your question. Okay, I think I did that right. Good morning, everybody. Good morning, Roger. Ryan, I'd like to ask you one specific question. You did a great job of highlighting how the plan, the execution has improved since the original layout about two years ago. As you look over the next 10 years here, a couple of things have been highlighted, such as refracs, as an example, where do you think the potential to outperform this plan is, obviously just excluding higher commodity prices? Is it things like refracs? Is it going to be from the sell-down potentially of Alaska projects as they move forward? Seems like CapEx goes up if Alaska moves forward, I'm not sure that necessarily changes things that much. I was just wondering, as you look at it, where do you see flex? Where do you see rigidity? Yeah, I'll maybe make two comments, let Tim chime in. There's a big portion of what he described it is, and I think we're all excited about the upside that's starting to materialize in the Lower 48. I think it is all around technology and understanding the different spacing and stacking and completion techniques and all those kinds of things as we bring Concho and ConocoPhillips together and maybe let Tim comment on some of what he sees on the technology in the future, I think in the Lower 48. Then maybe even Nick can comment because this is not unique to the Lower 48. It's occurring across our conventional business as well. Yeah, I think if you take anything away from my comments, it's just how much upside I believe really exists when you combine all the technology and our great position in these four big basins. These incremental changes, it's not just refracs, it's a whole laundry list of things that make the business better. The structural improvement between 2019 and today of 30% that I talked about, as I mentioned, I think we're just starting to scratch the surface on what we can do. Roger, just two points on Alaska and international. You've probably seen a common theme throughout was really leveraging existing infrastructure. You mentioned Alaska, and I'll just address one, for example, that Coyote opportunity that we've identified in Kuparuk and have recently been appraised by an offset operator. That's not in the plan. We've got existing infrastructure, pads, facilities with flow lines that we can leverage it. We're going to go out and test that opportunity and look at development in the future kind of the back end. Things like that are the upside that we definitely see, but leveraging that existing infrastructure. The last thing I would add, Roger, is just the high-grading opportunity within the portfolio. We described a little bit of that today. We'll continue to see that kind of opportunity. We'll want to replace some of the productive capacity. We'll just want to replace the CFO that we lose through that high grading with even higher margin, better production coming back into the mix as we go through that high grading exercise. We're going to continue to do that. We'll be pretty ruthless inside the portfolio, and I think that represents opportunity that's unquantified in this plan that we'll just continue to do it. I think Tim referred that the buying, selling, trading around the assets and the commercial acumen that we bring to the full complement of assets are just going to continue to provide upside. Our next question comes from Phil Gresh from JP Morgan. Phil, please follow the prompt on your screen to unmute your microphone and state your question Yes. Hi, good morning. Good morning, Phil. Ryan, your plan here is clearly very balanced between CapEx and return of capital, and it results in a 3% type production growth outcome. That production growth outlook is pretty similar to the one from 2019. It was 3% + at the time. Since 2019, we've seen more concerns around long-term demand growth, ESG risks, et cetera. I'm just curious how you think about the decision to continue to grow at the 3% type pace versus returning more capital to shareholders sooner. Yeah. Accelerating emissions reductions, et cetera. No. Thanks, Phil. We've said for a long time, our production growth is kind of an output. We look at our plans, and we look at how we maximize returns and how we go through the discipline of capital allocation. That's at the highest level. To your comment, it's not only about how we allocate capital at the asset level, it's how we think about returning it back to the shareholder and how we advance the returns of capital that we're getting. We're trying to balance all those things, some competing metrics inside the business. My implication, I think what you're saying is, what about a sustaining case inside the company? Why grow at 3%? I think when we look at the cost of supply of the resource that we have in the base, the modest growth that we're showing at the company level actually accelerates return on capital employed. It's not just about returns on capital, but it's about getting our returns on our capital back to something that's competitive with the S&P 500. Our dividend today yield is twice the average of the S&P 500. Now it's all about incrementing the returns and how can we make those investments to do that. We wouldn't be making those investments if we didn't think it was accretive to our returns profile. That ultimately leads to more cash flow, which ultimately leads to more distributions in the business. I think that's what we're trying to balance, Phil, as we go through that. We think we've hit the sweet spot, but we've got a very flexible and resilient portfolio, so we can react to the downside, and we can react to the upside as well. We're just not going to over-capitalize what we're doing in the business. Like I said, Phil, obviously, our Net-Zero framework is very much at the front of our minds as we consider that growth. As we look at the areas that we plan to preferentially invest in the Permian, Alaska, part of that is because those are very low GHG intensity assets, well below 15 kgs of carbon dioxide equivalent per BOE. That is very much compatible and all part of our plan. Our next question comes from Ryan Todd from Piper Sandler. Ryan, please follow the prompt on your screen to unmute your microphone and state your question Great. Thanks. Maybe want to start out for Tim. We appreciate some of the details on the Lower 48 outlook. Within kind of the base case plan, can you maybe talk about what your base assumptions are in terms of rig activity over the course of the plan or over the next few years going forward? What your assumptions are for well cost? I know that you have some detail in terms of how much they've come down over the last couple of years. What sort of inflation, if any, do you project in the plan from here? Yeah, I'll address some of that. When you look at the Lower 48 and the Permian specifically, we still believe strongly in that optimized plateau. The Permian doesn't get to its optimal plateau rate in this decade. We are clearly showing a constrained, disciplined case as we add activity and add capital. I don't think focusing on rig count is probably the right thing to do. Many of my comments talked about how much faster we're drilling wells today than we have in the past. The rig count expansion, I think, will be more muted just because of efficiency gains. The real great thing we have throughout our portfolio is ability, based on these technology breakthroughs, to allocate capital in different places and be very flexible. I think that's the driver. I think one of the benefits we're seeing, as Ryan mentioned, by returning capital to shareholders and the muted response to a higher oil price, while we've experienced inflation in some items in our business, inflation hasn't been the driving force. As Ellen mentioned at the introduction, in the plan, we've got about a 2% cost inflator over the life of the plan. Our next question comes from Doug Leggate from Bank of America Merrill Lynch. Doug, please follow the prompt on your screen to unmute your microphone and state your question Did I do that, Ryan? Can you all hear me? Yeah, we can, Doug. How are you this morning? Awesome. Good. Thank you, Ryan. I hope I won't get in trouble here for two and a half questions. My first one is a clarification point, if I may. On the press release, in the footnotes, it talks about real 2% inflation. Can you just clarify what the oil price and gas prices you're assuming at the end of the plan? It looks to me it's about 62 WTI, 68 Brent. It doesn't look like gas is being inflated. Just a clarification, because I'm having a tough time getting to Dominic's $5 billion delta if we don't include the inflation. $68 is a pretty big number in 2031. Clarification, please. Hey, Doug. Good morning, it's Dominic. Yeah. Actually, you're pretty spot on there. If you look at the WTI $50 real 2020 basis by the end of the plan is $62 WTI. Brent's about $5 higher than that. Actually, I think it gets to about $68. On the gas price side, we do have a little bit of character in that. Essentially, it starts around $3 and ends at about $4 in nominal terms. Okay. Thank you for that. I'll try and be quick on my questions, Ryan. If I may, I want to address something you said in your remarks about buybacks. We think Conoco is a good buy here. Forgive me for this, value is defined by free cash flow, right? If I take a $7 billion annuity, just simply at a 7% discount rate, I know you're not an annuity, net of debt, that would be higher than you are today. My point is it's subjective on the oil price. If investors have a different view of the oil price, they're going to have a different view on your decision to buy back stock. Can you help reconcile why it's management's position to buy back stock because you think you're a good buy? I want to ask this respectfully. That's not really management's job to decide if you're undervalued or not versus paying a sustainable dividend. Well, I do think it's management's job, Doug, to understand what our intrinsic value is and understand what our share price is relative to that intrinsic value. We make sure that we're making accretive and value-adding decisions to how we're returning capital employed. Again, Doug, I go back, we've studied this 30 ways to Sunday and have done it a lot. I think we've described it to you in a fair amount of detail as well, that the methodology really doesn't matter at the end of the day. The commitment to return a significant portion of your cash flow does, it's not a significant or a portion of your free cash flow. It's a portion of your cash flow that's pretty important as you go through that. Right now, we look at it based on the intrinsic value of the company and think our shares are a good buy today. I've said in the past, we studied it quite a lot, and we're flexible. We're open to other forms, but right now we're buying our shares back all day long. Our next question comes from Scott Hanold from RBC Capital Markets. Scott, please follow the prompt on your screen to unmute your microphone and state your question. Thanks. Appreciate the time here. I have a question on your view of the cash returns. I mean, obviously you have spoken about the buybacks as a real attractive option right now. Can you talk to us about where you are in terms of thoughts on special dividends and variable dividends? Certainly, you all, as you stated, will have a lot of free cash flow in this outlook, especially at the current commodity price drift. Where are we in the discussion of other forms of returns such as variable or special divvies? Well, as I said here, just to answer Doug's question, Scott, we remain open to other forms of distributions. Today, we think the best pathway is through the share buyback channel. We've had a lot of discussions on the management team and certainly with our board about the different channels, and we'll continue to have those conversations, and we're open and flexible to them. As I said today, we like the shares for the per metric. It helps in the base dividend. It helps manage that through the cycles and the per share metrics that they come from the share buyback channel. Again, we're looking at other things, and we also look at the macro. Is $70 oil going to persist for a while? There's a little bit of uncertainty around that as well. I think the message I would give to you all is we're flexible, and we're considering all the different options to make sure that we maximize value for the company and maximize the return and what's important to the shareholders. Our next question comes from Paul Cheng from Scotiabank. Paul, please follow the prompt on your screen to unmute your microphone and state your question. Hi. Can you hear me? Yes, we can, Paul. Hey. Hi, Ryan. Good morning. Good morning. Two questions, please. First, you're looking at your current R/P ratio, you indicated about 36 years. With the uncertainty of the future oil demand, say, a lot of people think that in 10-20 years' time, demand may peak and start to be in decline. When the management looking at your business model, is the business model trying to maintain your R/P ratio relatively steady or that you will allow it to shrink over time as you increase your production? That's the first question. The second question, maybe this is more specifically for Tim. You give a very thorough overview on the Lower 48. Can you tell us that what is the Eagle Ford and Bakken in terms of the more specific outlook? In the 2019 plan, Eagle Ford is targeting plateau around 300,000 BOE per day, while Bakken is about 90,000 BOE-100,000 BOE. I'm trying to understand that with the addition of the Concho assets, how those previous objective or targets have been changed. Yeah, thanks. We're not managing an R/P ratio call. We're finding the best things in the portfolio and willing to high grade. We're not trying to set and improve and either increase or decrease our R/P over time. Probably not one of the inputs into the model. I would just say that, as we run our scenarios and we think about, even the IPCC report, the IEA estimates, 2050 under some of their low carbon scenarios, the world is still using 40%-50% of oil and gas in the energy mix at that time. Our view, which is why we're hyper-focused on cost of supply, and it's why we show you the wedding cake and why we're probably the only E&P in the business that shows you a fully loaded cost of supply so you can understand what kind of resource we're investing in and how resilient it can be through those different transition pathways, depending on what oil price and where demand actually ultimately peaks and where it goes. We don't believe the existential threat to this business is right around the corner. We don't think it's in the next couple of decades, for that matter. We're actually investing in the business for the long haul and just trying to be hyper-focused on where we make those investments to make sure that we're delivering the lowest cost supply resources, therefore giving us the highest returns in the business. We're going through that process right now that Eagle Ford returns back to some plateau, and it may be a little bit different, maybe the same that we showed in 2019, but we've got a lot more assets in the portfolio. We are redirecting capital more to the Permian relative to where we were in 2019 to both the Bakken and the Eagle Ford. You'll see more of that as we just go through the quarterly performance of the company. Our final question comes from Jeoffrey Lambujon from Tudor, Pickering, Holt. Jeoffrey, please follow the prompts on your screen to unmute your microphone and state your question. Good morning. Can you all hear me okay? Yes, we can, Jeoffrey. Great. Just one question from me on the low carbon organization that you've formed internally. You mentioned carbon capture utilization and sequestration as a potential opportunity for that team. I think in the recent past, you've spoken to some assets that are in the portfolio that might be conducive to those types of projects. My question is there anything that you'd highlight that you might be working on as first milestones or even first steps on the pursuit of some of those initiatives? Hey, Jeff. It's Dominic here. We're not ready to share specifics, but I can assure you we're looking at both the assets that could be relevant in this area. Also we're looking at how do we leverage the capabilities that we have as a company that are very adjacent to these low carbon opportunities. That's not just carbon capture and storage, but as we look at blue hydrogen and even green hydrogen. When you look down the value chain, we see that we have quite a bit to offer in those spaces. I would say too early to say specifics, but certainly we're working very hard on these opportunities. We'll now turn the call back to Ellen. Thank you again, Ray. Thank you to our participants. It's really been a pleasure to lay this plan out for you this morning. We thank you again for your interest in the company, and we look forward to, we hope, seeing you in person on the road shortly. Again, thank you and have a great day and a great weekend. Bye-bye