ConocoPhillips (COP)

Analyst & Investor Meeting

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Nov 10, 2016

Good morning to everybody. It's really a pleasure to see all of you today. My name is Ellen DeSanctis. I'm the Vice President of Investor Relations and Communications for ConocoPhillips. On behalf of our entire leadership team, it really is my pleasure to welcome you here today to our 2016 Analyst and Investor Meeting. Today, you're going to hear from 4 of our senior executives. And at this time, I'd like to introduce them and tell you about today's agenda. Ryan Lance, our Chairman and CEO, will address our value proposition. That's the disciplined, returned, focused way we're going to deliver value to shareholders. Don Wallet, our EVP of Finance and Commercial and our Chief Financial Officer, will cover our 4 key financial priorities. Al Hirschberg, our EVP of Production, Drilling and Projects will discuss our extensive resource base and our investment in portfolio choices. Matt Fox, our EVP of Strategy, Exploration and Technology will describe the strategic flexibility that can allow us to deliver strong performance through price cycles. Ryan will come back for some quick closing comments and then we'll begin our question and answer session. Today's presentation is being webcast and materials are now available on our website. Later today, we'll have a transcript and a replay of this meeting available as well. We will make some forward looking statements here this morning. The risks and uncertainties in our future performance are described on the cautionary statement shown here and in our periodic filings with the SEC. We will also use some non GAAP terms here today. And I just want to make you aware that reconciliations of GAAP terms to non GAAP terms can also be found on our website. So again, welcome. Thank you so much for being here and for participating by webcast. And now it's my pleasure to turn the meeting over to Ryan. Thank you, Ellen, and good morning. Thank you for showing up and for your interest in the company. Appreciate those in the room here today and those that are joining us on the webcast. So today, my executive team and I will lay out the value proposition for the company. We're going to describe the details and the proof points around our strategy. We'll talk about the plans, the actions, the decisions and the outcomes that you should expect from us in the future. What you hear today is aimed at creating not only the best E and P company that we can be, but a truly distinctive E and P company, one that is focused on discipline, returns and creating value through the cycles. So I'm going to start with a few slides today and then I'm going to turn it over to Don and to Al and to Matt for the rest of the presentation. So let's get started. So can an upstream company deliver value through the cycles with a returns based value proposition? And we think the answer to that is a resounding yes. What we're going to demonstrate to you today is that we're a value proposition that's uniquely designed for the business environment and what the industry is facing today. You might ask yourself, what is that environment? Well, we take a view that it's going to be lower, more volatile prices going forward. Not long ago, we enjoyed as an industry pretty high and stable prices, but that world has changed. And here's what that means to us strategically. You can't count on rising commodity prices to bail out your business model. You have to position the business for the cycles. You can't chase them up and you can't chase them down. We're shifting our mindset to be a business that is managed for free cash flow. That allows investors more resilience to the downside and participation in the up cycle. But it means you need to have clear priorities in terms of how you allocate your cash flow. It means you can drive predictable performance by maintaining a strong balance sheet and by having a low cost to supply resource base and preserving strategic flexibility. You win in a world of more volatile prices by having a clear value proposition and a compelling strategy. So this is our value proposition on a page. The principles of that value proposition are shown on the left hand side of this slide. We have 3 core principles. It's about a strong balance sheet, it's a dividend that grows over time and it's disciplined growth. That growth can be absolute and per share. And all three of those principles are linked by a strong focus on returns. Now certainly, these are necessary or not necessarily necessary, but they're sufficient sort of to describe how we're going to allocate our cash flow and how we're going to create value through the cycles. So in the middle column, we've tried to describe our 5 priorities for cash allocation. These describe the order in which we intend to allocate cash flow as prices rise and as they fall. And our first priority is to invest a sufficient amount of CapEx into the portfolio to maintain and pay flat production and pay our existing dividend. Now let me be clear. This doesn't mean we have a goal just to maintain flat production. It means that before we'll increase available cash flow to absolute growth, we want to satisfy the other priorities first. Our second priority is to grow our per share fund on the dividend annually. Now our third priority is to reduce the debt. Initially, we set a target of less than $25,000,000,000 and today we're setting an explicit target of $20,000,000,000 and we want to maintain our A credit rating. Our 4th priority is to supplement the dividend with share repurchases. Between the two, we have a target to return at least 20% to 30% of our cash from our operations back to you, our investors, our owners. And then finally, we'll put money into our high return disciplined organic growth portfolio. Now since we rolled out these priorities in July, I think they've been received fairly well conceptually, but you've had a couple of questions for us. How are you going to operationalize them? And how are you going to put them into practice and when? So earlier today, we announced several actions to accelerate our value proposition, and they're shown on the right hand side of this slide. So we announced an initial $3,000,000,000 share repurchase program. It represents about 6% of our shares, and we're going to get started this quarter. We announced a plan to sell $5,000,000,000 to $8,000,000,000 of assets. And now that our major capital investments are rolling off the portfolio, we're putting more money to our shorter cycle flexible investments. And then finally, you see we're announcing our guidance for our 2017 operating plan. It consists of $5,000,000,000 of capital, a $6,000,000,000 adjusted operating expense and expected production ranging from flat to 2% versus our 2016 volumes. I think these actions demonstrate our commitment to the value proposition. It's real and it's driving our strategy. Can you advance the slide for me, please? Thank you. This slide represents our strategy on a page. The top part is our aspiration, our goal to deliver value through the cycles. In a price range of $50 to $60 Brent, we would expect to maintain our strong balance sheet, allocate free cash flow between per share and absolute growth. When you see excursions above and below this range, we expect to exercise flexibility that we built into the portfolio and take the highest value actions for our shareholders. With this approach, we expect to deliver double digit returns to our shareholders annually. Now I know this is conceptual, so let me make it real. Now the bottom part of this chart demonstrates how this strategy would work over the next 3 years at prices of about $50 per barrel Brent and with the acceleration actions we just talked about. If you read from the left to the right, at prices of about $45 to $50 we can maintain our production, pay our existing dividend, grow the dividend and pay off some debt. Now when you include proceeds from dispositions, we can achieve our debt target of $20,000,000,000 and execute a $3,000,000,000 share repurchase program and deliver up to 2% high return disciplined organic growth. And if you read further to the right of this slide, you see that prices above $50 Brent will have available cash to make choices. We can buy more shares or we can increase our investment into a high return organic growth. Now by the way, I don't view these as mutually exclusive. If we find ourselves in this kind of a situation, we're willing to allocate cash to both accelerated shares and growth. We believe this strategy is viable through the cycles, it's competitive among energy investments, and it's compelling, and here's why. So I opened with a question. Let me close with a couple of questions as well. Why is ConocoPhillips a compelling investment now? I think there's three reasons and they're shown on this slide. It's the transformation, the acceleration and the differentiation. First, we've transformed our company in the past couple of years, and you're going to get a lot of detail about that transformation in the presentations that are coming up. But let me give you the bottom line. We've reduced our breakeven cost from over $75 a barrel to less than $50 a barrel. We've lowered the capital intensity in our business. We can grow our production and modestly invest in in flexibility and our strategic flexibility now that our mega projects have started to roll off the portfolio. Our resource base today contains 18,000,000,000 barrels of resources at less than $40 cost of supply. That's 18,000,000,000 barrels at less than $40 cost of supply. Now this transformation required many difficult decisions and really a tremendous effort on the part of our workforce. And that for that, I'm extremely grateful. Thanks to their hard work, we're in a much better position to perform and succeed through the cycles. But we also know need to know we know we need to accelerate our value proposition, and we are. Investors don't have to wait for significant price to move to the upside before our priorities start kicking in and we can accelerate value. How do we accelerate value? Well, we do that with a $5,000,000,000 to $8,000,000,000 asset disposition program and we reduce our debt down to $20,000,000,000 We also do that by improving the underlying margins that these portfolio actions help. By starting $3,000,000,000 share repurchase program and by having peer leading upside as prices recover. Now finally, what differentiates us as an E and P company? We're changing our business model for free cash flow, and we're laying out clear priorities on how we'll allocate that cash flow. We're focused on returns, not absolute growth. We're distinguishing ourselves with a target to return 20% to 30% of our cash flow back to our shareholders through a growing dividend and through buybacks. And we have a unique low cost of supply resource base that can drive double digit returns with very low execution risk. I don't think there's another E and P company today that offers this level of transformation, acceleration and differentiation. So this is where I turn the meeting over to Don and Al and Matt. They're going to provide you a lot of detail about improve points around our value proposition and the strategy that I've outlined here today. Don is going to cover the financial priorities and how much we've really transformed the company. Al is going to provide an update on the portfolio and how it's differential to our competition. Matt is going to come back and tell you how we think about uncertainty and how we manage that and how that translates into strategic flexibility and sets us up to outcompete. And all the speakers and I will come back at the end and take your questions. So now let me turn the meeting over to Don. Well, thank you, Ryan. Good morning. Ryan just laid out the summary views of our unique value proposition and strategy. I'm going to show you how these are underpinned by a credible and disciplined financial plan consisting of 4 key priorities: generating strong free cash flow strengthening the balance sheet increasing returns to shareholders and focusing on improving financial returns. These are highlighted on the next slide. 1st, we intend to compete on free cash flow. We're managing the business to generate free cash flow by consistently operating well, lowering our breakeven price and maintaining a low capital intensity level. These actions also provide differential upside as prices recover. 2nd, we're going to maintain a strong balance sheet through the cycles. As Ryan mentioned, we further defined our debt goal by saying exactly how much under $25,000,000,000 we're targeting. Based on our plans, we think $20,000,000,000 is an appropriate debt level for our company and is achievable within a few years with planned asset sales. 3rd, we're differentiating ourselves from our E and P competitors by setting a payout target range of 20% to 30% of operational cash flows and we'll soon begin our $3,000,000,000 share repurchase program. And we intend to steadily increase our dividend rate and have targeted annual increases. Last but certainly not least, we're focused on improving both absolute and relative returns on capital. We're doing that by investing in the lowest cost of supply, highest return projects in our portfolio and by continually improving the margins across our businesses. I'm going to explain how each of these priorities provides ConocoPhillips with a distinctive competitive advantage. No matter where you are in the price cycle, a low breakeven price wins. That's how you compete on free cash flow. We define breakeven price as the Brent price needed to sustain production and pay our dividend. Only 2 years ago, we needed oil prices over $75 a barrel to breakeven. You've seen from our recent performance that our breakeven is now under $50 a barrel. As Ryan described, our company has undergone a dramatic transformation over a short period. We'll enter 2017 as a much different company than just a few years ago. We've pulled a lot of levers to structurally lower our breakeven price. This chart captures the magnitude of the changes since 2014. Our capital guidance as shown in the gray bar is down 70% from 2014. Adjusted operating cost guidance in the blue bars is down almost 40%. Our current dividend distribution in the orange is down by 2 thirds. In total, this represents a reduction of almost 60% since 2014. The waterfall shows the key drivers of this reduction, completing major projects, our decision to exit deepwater exploration, driving efficiencies across the business, reducing the dividend and capturing deflation. The important point here is that these reductions are sustainable and structural. We're a company that's now designed for resiliency Low capital intensity combined with low operating costs simply means more free cash flow. Cash flow that can be used to strengthen the balance sheet, to increase returns to shareholders and to invest in high return development opportunities. 2 years ago, we said it took $9,000,000,000 of capital to maintain our production levels. The high capital intensity was partly due to the long cycle mega projects in our portfolio. Those are now largely complete and ramping up to peak capacity. Today, we require less than $5,000,000,000 a year to sustain production, less than $5,000,000,000 And here's why. Our production is underpinned by our long life LNG and oil sands projects, which will soon represent about 500,000 barrels a day of essentially no decline production. Very low levels of sustainable capital are required to keep these facilities full and they'll stay full for decades. And the capital intensity of our other conventional and unconventional assets is low too. Al is going to give you all the details you need about to understand this in a few minutes. The key point is that our portfolio has a very competitive unmitigated decline rate. That's indicated by the chart on the left. For at least the next 5 years, we would be able to keep production flat with less than $1,000,000,000 a year to support base production and under $4,000,000,000 a year to replace base decline. If you consider capital intensity as the percentage of cash flow required to keep production flat, we would weigh in at about 70% at $50 oil and only 50% at $60 oil. The chart on the right puts this advantage in a competitive context. This is third party data that compares our capital intensity in 20 17 to our largest U. S. E and P competitors. What we're seeing here is each company's stay flat capital relative to their 2017 cash flow estimate, stacked from lowest capital intensity to highest. As you can see, we're top decile. Not only does low capital intensity allow more headroom for free cash flow generation, but we believe it also serves to high grade investment returns. When your treadmill is not running at breakneck speed just to keep up, you can focus on quality and not quantity. On improving returns rather than increasing production. We have another distinctive advantage in our ability to generate free cash flow. That's the upside we have to price recovery. The chart on the left is consensus data on cash flow improvement from 2016 to 2017. We lead the group of companies shown here, which includes both integrated and E and P companies. The drivers behind this, we start sooner and we accelerate faster. We start generating cash sooner because as you've seen, we've been aggressive on lowering cost across our business And we accelerate faster for a number of reasons. Part of it is product mix. We're highly leveraged to oil prices. In the appendix of your books, we've provided for the first time cash flow sensitivities. You'll see that if you apply a uniform percentage increase across all the products that we produce, 85% of the incremental cash flow is related to liquids pricing, 85%, only 15% to natural gas pricing. Part of the acceleration is due to our portfolio. The vast majority of our production is located in favorable fiscal regimes. So we retain a large portion of the price related margin improvement. And part of it is due to our current tax position. We're not in a taxpaying position in a number of jurisdictions and that will likely continue for the rest of the decade. The upside to price recovery will drive free cash flow momentum, but it will also drive significant improvement in returns. The chart on the right, again using consensus data, is showing expected returns improvement plotted against expected production growth on a debt adjusted per share basis. High into the right is where you want to be and that's where we are. So as we approach a period of improving prices, we have some strong tailwinds that provide for distinctive free cash flow generation and that will also boost returns relative to our competitors. The next financial priority is maintaining a strong balance sheet. Financial strength is a source of competitive advantage, especially in a cyclic business such as ours. We're in a sound financial position with a strong investment grade credit rating coming out of the worst of the cycle. We have no secured debt or convertible debt, and we have a large credit facility with no financial covenants. But our leverage is too high, and we're committed to bringing it down. We aim to return to a solid A credit rating across the board. This level of financial strength is important as it ensures that we maintain adequate borrowing capacity and continuous access to low cost debt through the down cycles. Our target of $20,000,000,000 is not arbitrary. This level of debt would be about 2 times estimated operational cash flows in 2019 at $60 oil or about 3 times at $50 This is a range that we're comfortable operating in. On the next slide, I'll show you how we plan to reach our target debt level. Reducing our leverage is a priority. It's important and is very manageable over time. Our plan paces debt reduction and balances our goal to strengthen our financial position with other corporate priorities. We plan to retire outstanding bonds as they mature. That's what's indicated by the green dash boxes on the left side of the chart. We also have a term loan that's due in 2019, that's shown in orange. We took that loan rather than issue bonds because we wanted the flexibility to efficiently retire debt early if we had the opportunity and will likely do just that as proceeds from asset sales are realized. By year end 2019, we expect to achieve our debt reduction goal with balance sheet debt down to $20,000,000,000 As you can see on the right, this would represent a reduction in balance sheet debt of about $7,000,000,000 which would translate to a leverage of around 2 turns at $60 oil. As Ryan described, our plan for returning capital to shareholders will be achieved through our dividend and a more flexible distribution component, share repurchases. We think flexibility makes sense for a commodity business when it's where it's important to maintain a low breakeven price. But we also believe it's important to have a meaningful and growing dividend. Our dividend today is set at a level that supports free cash flow generation and can increase steadily with growing cash flow. We've set it as a priority to increase our dividend rate annually. As you can see from the chart on the left, our dividend is competitive compared to the S and P 500 and quite a bit higher than most E and Ps. A resilient and steadily growing dividend core to our value proposition, but it's only part of the shareholder distribution story. If we go to the next slide, I'll talk about the other part of the story, share repurchases. We believe share buybacks make a lot of sense and we think that now is a good time to start a buyback program. Buybacks will underscore our commitment to distinctive shareholder distributions. Based on our current dividend, fully executing the authorized program would represent an increase in shareholder payout by about 80%. We think it's a good use of cash as we consider our shares undervalued and pretty much any relative valuation metric would support that view. And strong distributions reinforce discipline and that elevates the returns on our capital program. And importantly, as the chart on the right illustrates, both our deleveraging and our share buyback plans are executable in a low flat price environment. The combination of asset sales and surplus cash balances provides the $10,000,000,000 required without needing any further help from the market. Should we realize improved prices, then we'll have the ability to accelerate both debt reduction and share repurchases and we're willing to do that. Lastly, we view the 20% to 30% payout range as an average through the cycle target. In any given year, we may exceed the top end of this range. I couldn't speak credibly about financial priorities without discussing returns. In fact, returns are at the core of our strategy and every and they factor into every decision that we make. The chart on the left shows our performance peers and consensus estimates of absolute improvement in capital returns from 2016 to 2017. ConocoPhillips is at the top of the list. Part of this is due to the leverage to price recovery I spoke about earlier, but this also reflects the significant and sustainable cost reductions we've made in the underlying business. Even in a flat price environment, there are a number of factors that would improve returns. The completion of major projects and placing those assets into service will improve capital productivity, as will the investment in our high return development opportunities. Our smaller and more focused exploration program is expected to improve returns and we expect that our planned dispositions will also be accretive to corporate returns. So when we think about improving returns, we're not thinking about price. We're focused on the things that we control, value adding portfolio decisions, investment choices that increase returns and efficiencies and structural changes that lower our cost. Let me wrap up my section with a few key points that illustrate why our financial priorities make ConocoPhillips truly distinctive. Cash flow neutrality is no longer an aspiration, it's a fact. And we have the potential to generate free cash flow at a rate that few companies can match. We're committed to maintaining a strong balance sheet and we have a sound plan for achieving our debt targets, yet one that also allows us to progress other corporate priorities. We intend to share a healthy portion of our cash flow with investors and among E and Ps, our commitment to a payout target range makes us unique. And last, you can count on us to focus on returns. Now I'll turn the presentation over to Al, who will discuss the depth and quality of our low cost of supply portfolio. Thanks, Don. Okay. Today, we're going to take another close look at our asset portfolio, updated for all the changes and improvements that we've experienced since last year's analyst meeting. In a nutshell, our portfolio keeps getting better and better as we work on every aspect of cost, returns, technology and execution. I'll start with some discussion on how our asset base has evolved over time. This map shows the places we had activity in around the time of the spin. Not that long ago, we were in 28 places. Many of these places were vestiges of our time as an integrated oil company. And recall that at the time of the spin, we had plans to sell between $8,000,000,000 $10,000,000,000 of assets to allow us to focus on the very best part of our opportunity set. On the next slide, we'll time travel to the present. Well, I've sort of stopped working on this again. Today, we've reduced our global footprint and we're in about half as many places. We like to say, and by we, I really mean Matt likes to say, that we're diverse but not diffuse. I don't quite get the accent right, but that's how he says. We've exited several non strategic areas and we've also refocused our exploration activity. And importantly, against that early goal to sell $8,000,000,000 to $10,000,000,000 we've actually realized proceeds of over $16,000,000,000 from our asset sales. Those proceeds came from exiting areas like Kashagan, Russia, Algeria, Nigeria and we did all that at a time when oil prices were much higher. So we know how to divest assets when that's what's best for the company. And we're certainly willing to focus our portfolio where it makes sense. And we've probably never really done reshaping and optimizing the portfolio. So what I want to do next is show you what our next steps are in that plan. As Ryan and Don both mentioned, we plan to divest between $5,000,000,000 $8,000,000,000 of assets over the next 2 years as part of accelerating our value proposition. Now the assets that we're planning to divest represent a strategic decision to reduce our exposure to North American natural gas. As you can see on the left hand side of this chart, we've already made a lot of progress in that regard. Back at the time of the spin in 2012, North American natural gas was about 28% of our total corporate production. Today, it's down to 18% And this plan would take us further down that path, leaving us in the right hand bar chart at less than 10% of our production coming from North American gas. This will have the impact of improving underlying returns and cash margins on our remaining portfolio. And this program targets areas and assets that are in an active A and D market. So while these are high quality assets, they're not attracting development capital in our current plans. And therefore, we think they're going to be likely be more valuable to other operators. By the way, the material all through my section does not try to adjust for these asset dispositions. So let's shift gears now and talk about our resource base and future investments. I need you to advance it for me. Last year, we showed you that our total resource base was about 44,000,000,000 barrels with around 24,000,000,000 of that being below $75 Brent cost of supply. In today's world though, we think focusing on a cost supply less than $50 a barrel is more appropriate. Last year, we had about 13,000,000,000 barrels of our resource that was less than $50 cost supply as shown in the left hand bar. Since then, we've added almost 6,000,000,000 barrels through cost reductions, recovery improvements and further appraisal work. This has happened across our portfolio. Today, we have about 18,000,000,000 barrels of resource that's under this new $50 a barrel cutoff for cost of supply. But as Ryan mentioned, the average cost of supply of these 18,000,000,000 barrels is below $40 Brent. So that 18,000,000,000 barrels is a 35% increase from just last year, and it includes the effects of upward pressure on our cost of supply from the more rigorous burdening process that we've implemented over the past year, and which I'm going to discuss next. The first thing I want to do here is reacquaint you with a concept that's absolutely core to ConocoPhillips and that concept is cost of supply. Cost of supply is the BRIM equivalent price that it takes to get a 10% after tax return on an investment. It's the primary metric that we use to optimize capital allocation and it has the benefit of being price forecast independent. Now when we talk about cost of supply, we mean fully burdened in a way that I don't think other companies talk about it. The goal here is to have as tight of a tie to our corporate level returns as possible. So let me step you through this. The furthest left bar on the chart takes into account only direct capital and lifting costs for a single well and it uses a wellhead netback price for the products that are being sold. This calculation could be useful, but it doesn't provide a level playing field for allocating capital across a diverse global portfolio like ours. Next, we add product mix and transportation differentials to this. This gets you to the middle gray bar. That represents a cost of supply that's been adjusted to the Brent marker. This middle gray bar is what we think of as single well economics. And this is what we think many companies talk about when they quote returns. Although you have to be careful here because we've noticed that most of the companies when they're talking about that are using a before tax number and that of course lowers the cost. From here, we add a number of additional burdens that should be included in the math. The cost of infrastructure, the cost of both local and corporate G and A overhead and the price related inflation and currency changes. Now on this last item, we want to build our forward corporate cost of supply curve, not we don't want to build it using the low point in the overall deflationary cycle for costs. So what we've done here is we've adjusted all of our cost of supply calculations to reflect the cost and ForEx inflation that we would forecast for a $65 a barrel Brent world. So that's what all the numbers I'll show today on cost of supply have that basis. So when I quote you a cost of supply number, I'm using that far right bar. We believe this is a more accurate way to talk about cost of supply. If you don't include all of these items in your math, then project returns are never going to add up to corporate returns. So now let's move on to the results we get from using this tool. This is what we call our corporate cost of supply curve. Showing you this data is the next logical step in the process we started at last year's analyst meeting to provide an unprecedented level of transparency in our disclosure of what's in our total resource base as a company. So we're taking it up a notch over what we had last year. This chart shows only our 18,000,000,000 barrels of captured resource that has a cost of supply below $50 Brent. Of course, there's another 27,000,000,000 barrels of captured resource base on the right hand side of this curve, but we don't include it here because those cost supplies are still above $50 a barrel. And so until we get to figure out a way to get those below $50 we won't include it in this chart. Everyone in our company knows that if you aren't below $50 you're not even invited to the capital allocation discussion. Now on this slide, each of the bars has a solid area and then a shaded area above it that shows the burden. So I just want to explain that part. The solid part of the bar is equivalent to what I was calling earlier the single well economics. So the solid part of the bar is the same as the middle gray bar from my last chart. If you go all the way up to the top, including the shaded area, that's the fully burdened cost of supply that's equivalent to the right hand bar that I showed you on the last chart. So when I refer to cost of supply for the rest of this discussion, I'll always be talking about the very top parts of those bars. Now before we leave this chart, I just want to make one more point about the color scheme, because it's going to be the GPS for the rest of my discussion. On this chart, LNG and oil sands are shown in orange, our conventional assets are shown in green, and our unconventional assets are shown in yellow. So now let's dig into the details. Okay, so this is the key slide right here for those of you who are trying to figure out how can these guys hold their production flat or even grow slightly for less than $5,000,000,000 of annual CapEx over a period of more than 5 years. So let me show you the high level math because it's really made possible by our unique portfolio. So what I've done on this page is bucket our assets from the low cost of supply curve into 3 asset classes, each of which serves a very important role in our portfolio as summarized on the right hand side of the slide. Starting from the bottom of the 18,000,000,000 barrels, we have about 5,000,000,000 barrels that are in our LNG and oil sands asset class. This is the resource that provides 500,000 barrels a day of our production that stays flat for decades with very low sustaining capital, roughly about $500,000,000 in most years. That's what I'm showing with the dollars in the left hand side of the area chart. Now moving up to the next wedge is our conventional asset class, which holds about 6 of the 18,000,000,000 barrel total. This set of assets produces about 800,000 barrels a day in round numbers. In our stay flat production case, this asset class gets about $3,000,000,000 of capital in most years. And then finally, the top is our unconventional asset class. It holds about 7,000,000,000 barrels of low cost of supply assets, but it's also growing. This set of assets produces about 250,000 barrels a day in round numbers. This is the higher decline part of our asset base, we can hold unconventional production flat and also offset small decline in our green conventional wedge for about $1,000,000,000 in most years. So the bottom line is we can hold our overall production flat for the next 5 plus years for around $4,500,000,000 of CapEx per year. And I should point out that these numbers, these capital numbers include about $500,000,000 of focused exploration spend annually. So that's the reason that we expect to grow our production a small amount next year. We quoted in Ryan's slide 0% to 2%. Because the total CapEx number that we've quoted now for 2017 is $5,000,000,000 above the $4,500,000,000 that we need to stay flat. Now the entire remaining part of my presentation is really designed to give you additional color and detail on these three asset classes. We're going to start with the bottom one, LNG and Oil Sands. Here's the big picture for our LNG and Oil Sands asset class. These assets consist of QG3 in Qatar, Darwin LNG in Australia, APLNG in Curtis Island and the oil sands in Canada, Sirmont and FCCL. Now by the way, Alaska LNG is not included in the numbers here because its cost of supply is still too uncertain. The cost of supply from this part of the portfolio is highlighted in orange across the corporate cost of supply curve. In aggregate, these assets contain 5,000,000,000 barrels with a cost of supply of about $40 a barrel. And you'll see shortly they hold a tremendous amount of upside through technology development. So I'm now going to go through most of these assets 1 by 1, beginning with APLNG. Train 1 started up in late 2015 and is exceeding expectations with production at about 110% of nameplate capacity. And we just finished the rigorous lenders performance test on Train 1 with flying colors. Recently, we announced a significant milestone with a smooth startup of Train 2. Now as you know, all 6 of the new LNG trains on Curtis Island have used the ConocoPhillips optimized cascade technology, and we've really been pleased with how trouble free the performance of all the LNG trains on Curtis Island have been. Overall, this asset represents over 1,000,000,000 barrels of our resource base with a point forward cost of supply that's less than $30 a barrel to cover operating costs and sustaining capital in the upstream. Darwin is a more mature asset, having started up in 2,006, but it's still going strong. Over the past 5 years, our operating team has been able to increase the plant's capacity by about 10% for virtually no CapEx. They've done this through the use of integrated operating practices and advanced data analytics. That's the real power of these kinds of assets. Now while Darwin is mature, we're currently evaluating options for back fill after Bayou Undenfield depletes, and that's going to give the plant a whole new generational lease on life. Turning to Surmont, our mega project is now complete. In the top left, the bar for 2018 shows about the rough production level we expect to have once we're fully ramped up, but before any debottlenecking work. We've already identified about a 25% capacity increase that we can put in place for less than $40 a barrel cost of supply through small low cost debottlenecking projects. Then we've also identified an additional 25% capacity increase on top of that that we can develop through brownfield expansion at the existing Surmont II site. Now on the right hand side, there's a few technology developments to discuss. I've mentioned our work on flow control devices, FCDs in this meeting in previous years. We now have over a year's experience with flow control devices in many of our wells at Surmont too. And I really have to say it's not every day that you develop a single technology that can give you a 100% increase in the cumulative oil production over 12 months' time from your well pairs. These FCDs have been so effective that we've even developed a way to retrofit them into wells that we drilled that didn't originally have them. Now we've also made a lot of progress on reducing our cost structure at Surmont with line of sight to a 50% decrease in our well and pad costs through standardized pad and well designs. You can see on the lower right that the most dramatic improvement so far have been in the gray part of the cost bars, the well pad surface facilities. We're using a process called 0 based design. We question the need for every component in the design and we get rid of it if we don't need it for a safe, environmentally sound or reliable operation. So I want to show you what this looks like. As we move from the previous design shown here to the current design, the footprint and height of the facility have been reduced dramatically, driving down the amount of structural steel, piping and electrical components required. This has been amazing progress by our Surmont team, but they're not done yet. They still have some more ideas and they're well advanced to drive down costs even further. We have another 13,000,000,000 barrels of oil sands in our captured resource base that currently has a cost of supply that's above $50 a barrel. So these barrels are not counted in the 18,000,000,000 barrels that I've been talking about. But they are an opportunity that's grist for the technology mill. Last year, I said that we were targeting about a $25 a barrel cost of supply reduction for new oil sands developments and that we'd already made some good progress toward this goal. We've now captured over 90% of that $25 a barrel cost of supply reduction for multiple improvements and we've identified another $10 a barrel of cost of supply reduction that we can achieve through netback improvements and through additional technologies. That's the kind of change that could move some of these 13,000,000,000 barrels into our below $50 a barrel resource base. Now one of these new technologies is non condensable gas co injection, which is shown in this graphic on the right. We inject a small amount of methane with the steam and it forms an insulating gas blanket at the top of the steam chamber to reduce heat loss to the overburden. Our modeling shows that this idea could reduce both steam oil ratio and our greenhouse gas intensity by up to 20%. We have a low cost NCG pilot planned to start before the end of the year and we'll expect to have results in 2017. So here's how I'd summarize the value and the importance of this LNG and oil sands asset class to ConocoPhillips. It represents 500,000 barrels a day of production, flat production for decades. Our mega project is complete and we're now in operating mode. We'll continue testing and implementing new technology to drive further improvements. And these assets as a group generate positive cash flow above $40 a barrel Brent with good upside to higher prices. So now let's move on to the conventional asset class. This is a set of assets that's often overlooked since the shale frenzy. This is the great stuff that people have just forgotten to ask us about. You find these assets in our legacy positions in the UK, Norway, Alaska, China, Indonesia, Malaysia as well as the Lower 48 and Canada. The cost of supply curve for these assets is shown in the lower left. The 6,000,000,000 barrels is really attractively distributed across the company's cost of supply spectrum. The fully burdened average cost of supply of this 6,000,000,000 barrels is below $35 a barrel. Now with this asset class, there are 2 kinds of programs. First is the conventional drilling programs that take place within existing fields and adjacent to existing infrastructure. Over the next 5 years, we expect these kind of drilling programs to add 150,000 barrels a day to our production. This is the quick payback stuff that we've been doing for years, but improved technology has really allowed us to lower the costs. It's straightforward and it's predictable. Now the second type of investment we have in this asset class is these medium cycle, lower risk projects that we've also been doing for many years. On the next few slides, I'm going to show you some more details on these kinds of projects. As I mentioned a moment ago, this page summarizes some information I think is often overlooked, our pipeline of smaller, medium cycle projects. In the past 3 years, our experienced project teams have executed over $5,000,000,000 of these kinds of projects, ones like those shown in the upper left, CD5, Elthif South, etcetera. And they've done it ahead of schedule and under budget. Projects like these add chunks of production, generally very high margin that extend the life of our great fields. And as you can see from this chart, we have a number of opportunities that are in progress, which should add significant production over the next few years. We expect to spend an average of $1,700,000,000 a year on these projects with an average cost of supply that's less than $40 a barrel and add about 130,000 barrels a day over the next 5 years as shown in the production plot in the bottom right. Now in the next few slides, I'll show you some highlights from some of these key areas. We'll start in Alaska, which has been an area of renewed interest and activity for us since fiscal regime improved a couple of years ago. On this slide, I'm showing you a case study of our CD5 project. We took this project to our Board for sanction in 2012 with an expected cost of supply of $66 a barrel Brent. Now remember, Brent was over $100 back then, so this was a good project. But we didn't stop there. Our very experienced project team in Alaska has been working a series of these types of projects, these medium sized projects like CD5 over the years. So despite the high level of inflation in the industry at the time, they were able to optimize the development further and drive capital cost reductions during project execution through some of the actions that are shown on the right hand side of the chart. These are not cyclical savings. Our drilling and operating teams were able to achieve cost efficiencies through innovations like performance based contracts. We also changed to multilateral wells to unlock additional resource and we've continued to push the envelope on the length of these laterals. These longer wells have resulted in improved well performance over what we expected at FID. So the important point is this, after starting up in 2015 and then this year putting this project through our rigorous post audit process, we found that we had actually achieved a $40 Brent cost of supply, a 40% decrease on a full cycle basis compared to what we had in our sanction AFE. The same forces have been underway in Europe at our legacy fields there. We looked at the progress that we've been making on 3 of our upcoming projects in Norway that have been advancing through our project gates. Tomalitin Alpha, Tor 2 and Elvifs North. Norway is another place where we have a very experienced project team that's been able to execute these medium sized projects successfully for many years in a row. They've made big new strides in minimum facility designs, standardized unmanned platforms that we call subsea on a stick because it looks so different and slimmed down from what we've often built in the past. The bar chart on the lower left shows how we've driven the full cycle costs for these three fields down by about 50% over the past 4 years. Now the same is true in China. Here's another case study. This time, the Bohai Wellhead Platform J. Again, we've achieved a 50% reduction in full cycle cost of supply, this time by capturing both structural and cyclical cost savings and efficiency improvements. So that wraps up our conventional asset discussion. You can see that it's a very important part of our business. We've got 6,000,000,000 barrels of resource, averaging less than $35 a barrel cost of supply that could deliver growth from projects and development drilling programs. And we have a strong track record of successfully executing on both of those. Okay, now on to what everyone wants to talk about the most, the unconventionals. On the next set of slides, I'm going to take you through our unconventional position and the very significant progress that we've made there since our last analyst meeting. In this section of the presentation, I want to impart 3 key takeaways. 1st, our development and technology teams have driven significant improvements over the past years, both adding resource and lowering the cost of supply from our existing resource in these plays. 2nd, we have many years of additional inventory and running room in our mature plays. And third, have the potential to add significant resource in our less mature plays. Our North American unconventional assets are focused to the areas shown on the map on the right. On the left, you could see where these unconventional assets fit into our corporate cost of supply curve. Today, this represents 7,000,000,000 barrels with a less than $35 a barrel average cost of supply. So let's start with a little context on the size and the quality of our North American unconventional position relative to our competition, both IOCs and the E and Ps. This chart shows WoodMac data for the value of the top 10 competitors North American unconventional positions and ConocoPhillips in the red came out on top. Now this result did not happen by accident. Our people have developed some great unconventional technology that's been driving our advancement. I plan to show you just a few examples of what I'm talking about in the technology area on the next few slides. I'm going to start my discussion in the Eagle Ford, where we have a best in class asset. The equations in the upper right of this slide describe the state of our resource understanding and incorporate the learnings that we've been pursuing over the last few years. Although I do expect that there's more improvement to come here. So even with lower rig and activity levels, we never stopped doing the science and the testing of new ideas. Recall, when we talked about the Eagle Ford last year, we said we were piloting well spacing, stacking and completion designs. Well, we now think that we're cracking the code on these key elements. We understand the optimal well spacing and stacking as well as the optimal completion designs as we move across our play. And by the way, it's not a one size fit all fits all kind of situation. We understand what works best in the many different sub plays that we have across our acreage. Now this has allowed us to increase our Eagle Ford EUR from 2,500,000,000 to 3,000,000,000 barrels, a 20% increase from just last year. But more importantly, for a returns focused company, we've reduced our capital cost by 40% and our lifting cost by 30% since 2014, even while we were increasing the size of our completions. These improvements have allowed us to increase the amount of resource with a cost of supply below $40 a barrel by 40% to the 2,400,000,000 barrels that's shown on the chart. I also have to point out that working in the Eagle Ford has gotten even better as much of the competition is left for the Permian. That makes our contracting easier and improves our net backs. So while the Eagle Ford seems like old news to much of industry, it's really coming into its prime for us and we plan to run 5 rigs there in 2017. Now as part of the transformation of our business that lets us thrive at lower prices, we've been driving the Uberization of the oilfield. Our operations personnel are guided by real time data analysis accessed by smart devices in the field, allowing us to predict equipment breakdowns before they occur and prevent them. The result is that we've increased our uptime by 5 percentage points and we've driven down our lifting costs to below $2 a barrel. And on the right, our drilling teams continue to make great strides in reducing our costs. Some people thought that we were reaching the limits on our improved drilling back in sort of late 2014, reaching the limits on our improved drilling times. But in early 2015, we implemented our new advanced analytics engine, which has given us new insights into how to reduce our drilling times. This has put us on a faster improvement slope and that's saving us real money. Next up are 2 proprietary technologies that differentiate ConocoPhillips from the competition in the development of unconventional assets. Let me sum up the chart first and then we'll get into the details. Knowing how the rock fractures and how to optimize the completion design, plus what layers are contributing to the production and how that changes over time means competitive advantage in the form of increased ultimate recoveries and lower cost of supply. So on the left, remember the SRV, the stimulated rock volume work that I've told you about before. I told you last year that our scientific work was indicating an additional EUR upside if we could break the rock more effectively. Our SRV work has given us detailed insights into how the rock fractures, not by inference, but by direct measurement by coring the rock both before and after hydraulic fracturing. The chart on the left shows you at a high level what we've learned and how we're using it. You can see differing levels of fracturing effectiveness through time and next to it color contour images, which show the effectiveness of the different frac designs. We measure this data in real time. The hotter the colors, the better the SRV. We've already made tremendous progress in increasing our production rates and recoveries by improving the SRV. It's never going to be perfect, which would be solid red there on the chart because of mother nature's inherent heterogeneity, but we think we could come close with continued technical work. On the right is an important scientific technique that we've been using to great advantage for over 5 years now, but we're only revealing for the first time today because we can see that some others may be starting to catch on to this idea. We call it time lapse geochemistry. By fingerprinting the unique biomarkers that are present in the oil and gas in each zone, we can get direct insight into our vertical drainage heights. That's something that others just guess at. This allows us to optimize our vertical well placement across the different areas of the field. In the example shown, the 4 different colors represent distinct producing zones, 2 each in the upper and the lower Eagle Ford. The bar chart on the right shows that the production contribution from the different zones changes over time. That's the time lapse part of the technology. In this example, the well drilled into the Lower Eagle Ford has tapped into the Orange Upper Eagle Ford initially, but then those fractures close over time telling us that in this area of the field, we still need another well above this one in order to fully drain the uncaptured barrels or possibly a refrac job, but we need to do something else to capture those barrels. So what all this tells you is that when you're not just chasing rate, you could take the time to do the science that maximizes the long term value of these assets. The next slide really makes this point clearly. Over time through our scientific advancements like the ones I was just discussing, we've been able to divide our Eagle Ford acreage up into many different sub plays, each with its own customized spacing and stacking and customized completion design. This optimization allows us to get more barrels out of the acreage without over capitalizing. We've added another 500,000,000 barrels to our Eagle Ford resource base since last year from these kinds of advancements. From day 1, our philosophy on the development pace in the unconventionals has been to maximize capital efficiency by making sure that we're well advanced on both the cost and the technology learning curves before we scale up and run large numbers of rigs. We think this leads to higher value, not just because of the pace of improvement have been so rapid in recent years, but also because it allows us to optimize our infrastructure costs and maximize our ultimate recoveries efficiently without drilling more wells than is necessary. If you go into an area and you drill it out with your well spaced too closely together or stacked wrong or with a suboptimal completion design, you not only will likely spend more money than necessary, you'll also likely lose resource that you can never recover. So the bottom line is this, we believe you need to do the science before you spend the capital in these unconventional plays because you just can't do it right after you've done it wrong. Now you can maybe guess where this discussion on the Eagle Ford is heading next. Our approach to making sure that we know how to optimize the developments of these acreage before running a lot of rigs has been in stark contrast to many of our competitors. That's the picture this slide tells. If you look at our acreage in yellow, we're surrounded by dense black lines that represent the competitor wells drilled adjacent to our acreage, and it makes 2 key points. 1st, we're obviously in the heart of the play where others have been drilling aggressively all around us. And second, ConocoPhillips has plenty of high quality well locations yet to be drilled, but we also have enough wells across our acreage that we understand what we have. We can now execute a multiyear optimized campaign that maximizes the value. We currently estimate that we have about 3,500 locations to drill that have a fully burdened cost of supply that's less than $40 a barrel. In fact, we estimate about 25% of our remaining resource in the Eagle Ford has a cost of supply that's below $25 a barrel. That's about a mid teens after tax cost of supply on a single well basis that others often quote. That's truly a best in class play, but don't take our word for it. Here's the chart I show you every year from the 3 different third party data sources. We again have the lowest cost of supply, the highest liquid rates per well, and the highest net present value per acre. So it's not hard to see why ConocoPhillips is still actively pursuing the Eagle Ford and has plans for many years of profitable drilling here. But these days everyone wants to talk about the Permian Basin. So let's take a closer look at our position there. In the Permian, we're applying our normal disciplined returns focused approach to appraise and develop our acreage. We expect to be running between 12 rigs there in 2017. We have about 1,000,000 acres across the Permian Basin broken into the 3 areas shown on the map and I'm going to take some time to characterize each one of them. In the Midland Basin, we have about 160,000 net acres with a legacy conventional position and developing unconventional potential. At this point, we're only carrying about 300,000,000 barrels in our unconventional resource for this acreage and our low cost of supply curve, but we see potential for significant growth as we're still evaluating and coring up our position here. In the Northwest Shelf and Central Basin platform, we have about 760,000 net acres with about 40,000 barrels per day of net production in our legacy position that's held by production. While we're evaluating our unconventional potential using our latest technology and tools, we've also been putting our unconventional technology to work in our conventional developments here. For example, in the Central Basin platform, we had a 5 well pilot program this year to test out our unconventional technology in the Wichita Albany formation. These wells outperformed our expectations and they've paid out in just 10 months, even in a low price environment. So we plan to drill more of these kind of wells in 2017. We also have another pilot program planned that will test the Yeso formation in the Northwest Shelf using our unconventional completion technologies. In the Delaware, we now have about 75,000 net acres and over 20,000 barrels per day of net production, having sold some of our smaller positions that were not in the core of the play. Our remaining focus areas are top tier, and I'll discuss them in a bit more detail next. We've worked to core up our acreage in the 2 focus areas shown on the map, China Draw and Red Hills, and we're employing the same philosophy that we used in the Eagle Ford, taking the time necessary to ensure an efficient returns focused development plan to maximize recoveries without over capitalizing. The map shows color contours from public data on 6 month cumulative production from the Wolfcamp 1. The red areas have the highest production. So you can see that our focus areas are well placed on the map. So with the progress that we've made here so far, we've increased our resource base for the Delaware from 1,000,000,000 barrels last year to 1,800,000,000 barrels this year, and it averages a cost of supply that's less than $40 a barrel for that 1,800,000,000 barrels. Now almost all of the resource that we're counting here in this 1,800,000,000 barrels is just in the Wolfcamp. So I suspect that we're not finished increasing our Delaware resource number given the stacked pay that we have in the area. Coring up our acreage has also allowed for 10,000 foot laterals to be drilled. We estimate that these longer laterals increase value by 30 percent where you're able to do them. We've also reduced our completion costs by about 50% since 2014. We currently estimate we've got 1400 drilling locations with an average fully burdened cost of supply that's less than $40 a barrel. So next, let's look at the Bakken, where we have an interesting new development that's hot off the presses. But first, the basic stats. We've got about 600,000 net acres here with about 700,000,000 barrels of resource in our low cost of supply curve. Our models and our pilot programs have confirmed our spacing plans and also our Middle Three Forks infill potential across parts of our acreage. We've reduced our completed well costs by about 45% since 2014 and the 3rd party data on the left hand side shows you that we have the lowest well cost per barrel in the Bakken. In the upper right, you could see the 40% increase in cumulative production that we've experienced from our middle Bakken wells since our last major completion design change, which was in 2014. But very recently, we developed a new completion design based on our learnings from our stimulated rock volume work that I was discussing earlier. These early results in the middle Bakken are shown in the plot at the bottom right. Now for you reservoir engineers out there, this is a plot productivity index versus cum production. For everyone else, the higher the curve is, the better it is. The blue and the orange lines correspond to the completion design shown in the upper right production plot. The green curve is the new design. We're getting better results with the new design indicating potentially significant improvement in the stimulated rock volume. So we'll be adding rigs here and we currently plan to run 4 rigs in 2017 in the Bakken. So let's move a little further north next. In Western Canada, we have over 3,000,000 net acres with about 100,000 barrels per day of current production. Much of this acreage is prospective for unconventional development. We've reduced our operating costs here by about 30% since 2014, and we have significant midstream infrastructure across the area that can add value to our future developments here. We currently show about 1,000,000,000 barrels of low cost of supply unconventional resource here, but it's still very early days. It's easy to see how it could grow quite significantly over time. We're again using the patient returns focused approach that I described to you earlier in pursuing this Western Canada unconventional potential. We have been increasing and coring up our position in the liquids rich play areas through non core land swaps. The Blueberry Montney is a good example of this, where we've quietly assembled a very nice position of over 80,000 net acres that's fairly contiguous as shown in that inset map. The acreage in blue was added just this year. If you go back to 2012, we only had about 14,000 acres in this area. It's been a significant low cost acreage build for us. We've recently had a rig in the field drilling appraisal wells in different zones in both the Montney and the Flair Woolridge, and we are actively still actively appraising. I'd also like to summarize the progress of some of our less mature unconventional appraisal areas. In the Niobrara, we have about 100,000 net acres and as shown in the plot at the upper right, the 2 times production improvement that we got from our new completion designs has been confirmed over much longer periods of time. We plan to have a rig here in 2017 doing further appraisal and piloting work. Work to evaluate the Eagle Ford Austin Chalk is also underway, but the resource potential has not yet been fully assessed, so we've not yet added any new barrels to our resource base for this formation. We do have some early data that shows very strong results with a 5 month cumulative production levels that are above both the upper and lower Eagle Ford reservoirs in the same area. So the Austin Chalk clearly presents some upside across our parts of the Eagle Ford acreage. We plan to drill some more of these wells also in 2017. In addition, we have 2 significant acreage positions that we're 2017. I'm going to wrap up the unconventional section with this summary chart, showing with the bars on the left how we've increased our unconventional resource with low cost of supply from about 4,000,000,000 barrels in last year's resource base to 7,000,000,000 barrels in this year's. In the middle of the chart, we show our estimate of that resource and remaining locations in the Eagle Ford, the Delaware and the Bakken. The approximately 2,000,000,000 barrels that shown under emerging plays under appraisal includes the Permian Midland Basin, the Niobrara and Western Canada. We have not tried to estimate the drilling locations that are under $50 a barrel for those areas yet. On the right is an interesting curve that applies to our top 3 Lower 48 unconventional areas that are listed. It shows our current estimate of the 3 year production compound annual growth rate that would result for these three areas with differing numbers of rigs running. So at last year's analyst meeting, we thought we needed 12 to 13 rigs to hold this production from these three areas flat. We now estimate that off the low point in 2017, we could hold production with only 6 rigs, half as many rigs. And we could grow production about 20% in these three areas by running about 15 rigs. These are the kinds of changes that allow us to hold our production flat for just $4,500,000,000 of CapEx per year. So to summarize the value of our robust unconventional asset class, it provides our most flexible and some of our lowest cost supply resources in the company. It's been built into an enviable position through leading unconventional technologies that are applied to maximize value. So that wraps up our tour of the 3 asset classes in ConocoPhillips, each with its own important role to play in our overall portfolio performance. I want to close by putting up our corporate cost of supply curve again. The large portfolio of diverse and low cost of supply assets shown here is what will differentiate us by providing predictable, consistent performance to investors for decades to come and through the inevitable price cycles. At the last analyst meeting, we promised you that we were going to transform our company to be more focused and efficient, and we've delivered on that promise. We've reduced our OpEx from $9,700,000,000 in 2014 to a planned $6,000,000,000 next year. And we can hold our production flat now for years at a time for CapEx of $4,500,000,000 a year. That's half the $9,000,000,000 that we quoted you at last year's meeting. So our flexible portfolio allows us to deliver our value proposition with low execution risk and through the cycles. So now I want to turn it over to Matt for a fascinating discussion around how this portfolio underpins our strategic flexibility and allows us to prepare for an uncertain world. Thanks, Al. Good morning, everyone. What I want to do now is to take the financial priorities that Don outlined and the portfolio that Al just described and put it in a strategic context because it's the combinations of our priorities and our portfolio that gives us a strategic flexibility to deliver consistently deliver returns in an uncertain future. And I'm going to start where Al left off with the cost of supply. I'm going to I brought myself an extra one just in case. I'm going to start off with start where I'll left off with our massive low cost of supply resource base because that's what underpins the strategic flexibility and our ability to deliver strong returns through the cycles. And I know you've all been wondering how does this cost of supply metric translate into returns. Well, here's the decoder ring. It has cost of supply on the X axis and returns on the Y axis. And because this cost of supply is fully burdened, that means these returns are also fully burdened. We are only going to invest in opportunities that have a cost of supply of less than $50 a barrel. That's what's shown in the green shaded area. And in fact, for the next 5 years and beyond, the capital weighted average cost of supply is less than $40 a barrel. That's the dashed red line. The solid lines represent Brent prices of $50 $60 a barrel. You can see that the $50 a barrel line crosses the $50 cost of supply at 10% return, and that's a good thing because that's the definition of cost of supply. But much more importantly, it crosses the red dash line, the average cost of supply of our investments at 30%. So if prices average $50 a barrel over the next 5 years, we will deliver a fully burdened 30% internal rate of return on our new capital. If prices average $60 a barrel, those fully burdened returns will grow to closer to 45%, 45% fully burdened. Now I know you hear people making claims about returns based on wellsite economics and I know that you know that these are not very useful pieces of information because they don't reflect corporate returns. But because these returns are fully burdened, they do reflect how corporate returns will change over time with this level of return at the individual capital annual capital programs. That's why this portfolio is so valuable to a returns focused company. And it's not just a high return portfolio. It's designed to create strategic flexibility too. I'll describe the capital required to sustain existing production in each of the portfolio categories on the left, totaling about $4,500,000,000 a year. But assuming prices recover, we'll be investing for disciplined growth. And on the right, you can see the flexibility and cost of supply characteristics of that total capital over the next 5 years. I'll start with the cost of supply stacked bars shown in green on the right chart. This stack averages the less than $40 a barrel I mentioned a few minutes ago. On the blue stack, you can see how this lines up from a strategic flexibility perspective. Starting from the bottom, we are always going to invest in our base to ensure the safety and reliability of our existing assets. We have projects that are in execution, and we're going to finish those projects, and the vast majority of them will be on production by 2018. We're still going to invest in new high quality, low risk projects across the portfolio in places like Alaska, Canada, the U. K, Norway, Malaysia and China. We have some multiyear drilling contracts, mostly in our international business to drill very low cost of supply wells, and we're happy to do that for years to come. Now all of those categories represent committed capital. We're willing to make those commitments because they're all low cost of supply sources of production. But those commitments are balanced by close to half of our capital being flexible. Much of that, although unconventionals. Part of that flexible capital is exploration. Since our decision to exit Deepwater, we've redesigned our exploration strategy to focus on a few key existing business units and a few key international new ventures where we see the potential to discover new sources of supply resource that can compete in our existing portfolio. And we've designed this strategy with off ramps so that it's a flexible exploration strategy. That's a lot of flexibility. And that's a good thing because flexibility is essential in an uncertain world. Ryan said at the outset of this presentation that we are positioning ConocoPhillips to work at lower prices and in a more volatile environment. And that means we have to embrace uncertainty, and we use scenarios to help us do that. The graphic on the left shows a high level view of some of those scenarios. The axes represent uncertainty in future supply and future demand. Now everybody knows that one of the most important characteristics of a scenario name is alliteration. So you can see that all of our scenarios are alliterated. The unrelenting unconventional scenario, which we used to call tidal wave until we discovered the importance of alliteration, is where we have rapid growth in unconventional production into weak global growth. That's where we were from 2012 to 2014. Now there's been some relenting over the last few years, this is a very plausible scenario for the future. The demand destruction scenario represents a world where carbon constraints or technology advances in renewables or electric vehicles result in persistent reduction in demand for fossil fuels. Over the long term, this is the lowest price scenario of these 4. Robust recovery is self explanatory. Strong demand growth requires higher marginal supply cost production like deepwater. The resource restriction scenario is where we have high demand growth but with limitations placed on the development of unconventional reservoirs. This is the highest price of these four scenarios. Now because we described the world in each of these scenarios, we can anticipate the signposts that will tell us when we're moving into or moving out of each of these states of the world. And we've identified more than 150 indicators that we monitor. We have subject matter experts to track the signposts and we use a proprietary web crawling tool to search the Internet for their occurrences. We use this approach to assign probabilities to the scenarios and monitor how those probabilities are changing with time. The primary purpose of this is to test our strategic alternatives to see how they perform in these different worlds. And one of the big things that's clear through this work is that flexibility itself has intrinsic option value. That's why we've designed this portfolio to have flexibility, and we're willing to use it in a disciplined way. Now we find the scenario planning process to be much more insightful than trying to explicitly predict price. But you guys don't mind predicting price. And frankly, you're all over the place. Although there's a general consensus that we're on the verge of a price recovery. There's a very wide range of where that price recovery might end up ranging from the mid-50s to the mid-80s. In essence, this reflects different scenarios in the minds of the professional prognosticators that put together these forecasts. So let's test some of these scenarios to see how resilient our strategy is. I'll start by these using these three cases, dollars 50 $60 $70 a barrel, real Brent. We'll then look at a cyclical price case, which is a more difficult but essential test for an E and P company strategy to pass. In all of these cases, we execute the acceleration actions that Ryan described earlier. We measure the resilience of our strategy by its ability to achieve the priorities we've laid out. Here, we are priorities 1 through 5. First, the $50 a barrel case. In this scenario, we achieve all of our priorities. We can sustain our current production adjusted for dispositions and reach our $20,000,000,000 debt target by the end of 2019. Through a growing ordinary dividend and the share buyback program we announced today, at $50 of our own, we actually pay out more than the 30% of our cash from operations to distributions to shareholders. We limit our capital to $5,000,000,000 every year, and we deliver modest production growth. This is essentially the case that Ryan and Don described earlier. When we aggregate debt adjusted production growth per share and margin growth and the dividend yield, we get total compound return in this world of between 5% 10%, towards the top end of that range. In a $60 a barrel price environment, we achieved the first three priorities and we've got the capacity to balance increased distributions with higher return production growth of up to about 4% or 5%. This results in total annual returns of 10% to 15%. In a $70 a barrel case, we have the same opportunities, but now we can deliver 15% to 20% compound annual growth in returns when we combine the debt adjusted production growth per share with the margin growth and the dividend yield. Now one of the strengths of the strategy with embedded flexibility is that we'll have choices to make as the macro environment evolves. But for this to work, we need to have consistent decision criteria that we'll use to make disciplined decisions. To allocate the next dollar between additional buybacks and growth, we'll be considering where we think we are in the cycle using our scenario monitoring tool as a guide. We'll be considering the absolute and relative valuation of our shares and the returns associated with incremental capital spending. Increasing distributions or investing for high return growth will compete for use of that excess cash flow. But as Ryan said earlier, they're not mutually exclusive. For example, you'll notice in the $70 a barrel case that after achieving the payout target, we could choose to invest in the portfolio and grow up to 8% on our high return short cycle inventory. But it's likely that if we find ourselves in a place where we have significant free cash flow, we would continue to balance disciplined growth with other uses of cash. The key point is that these decisions will be made based on consistently delivering value for shareholders through the cycles. Talking of cycles, let's test the strategy against 1. This is one example of how a cycle might play out over the 5 years. In this case, prices are $50 a barrel next year. They recovered to $65 in 'eighteen, dollars 75 in 'nineteen and then crashed to $40 a barrel in 2020 and modestly recover to $50 a barrel by 2021. So let's see how our strategy performs in this cycle. On the right, you can see our cash allocation each year to capital in blue, debt reduction in gray and shareholder distributions in green. As in all the other cases, we get our debt down to $20,000,000,000 by the end of 2019, grow our dividend and distribute additional cash to shareholders through buybacks. And you can see we do this consistently through this cycle. We're able to do this because we don't chase growth and overreact to price increases by rapidly increasing our capital, especially if we're in a rapid inflation environment. In fact, in this case, we'd expect our scenario monitoring system to be giving us indications that we're in a cycle, and we hold some cash in the balance sheet so that we can continue shareholder distributions in the low part of the cycle. And this illustrates a key characteristic of our strategy that Al and sorry, Ryan and Don alluded to earlier. If we believe it's the highest value choice for shareholders, we'll increase our annual distributions above the top of our 20% to 30% range. In fact, in this scenario, we're doing that in years 1, years 4 and years 5. In this case, when we aggregate debt adjusted production growth per share and margin growth with the dividend, we deliver around 10% compound annual growth in returns. Now we have literally dozens of cases like this that we run-in our strategy simulator, and this is a very robust strategy across multiple types of cycles. But it doesn't lend itself to a simple strategy algorithm or a slogan like drill, baby, drill or give all the cash back to shareholders because we don't know how prices will evolve. We don't know how technology will change, and we don't know how governments will behave. As we navigate these uncertainties, management judgment is still important. So to decide if this is an attractive value proposition to invest in, what shareholders want to understand are what are our financial priorities, What's the depth, quality and flexibility of this portfolio? And how will we exercise strategic flexibility to maximize value? And hopefully, we've been clear today. We'll do this through a balance of financial strength, differential distributions to shareholders and disciplined returns focused growth. So rather than show more cases, here's a summary of what you should expect in the next 3 years. I'm going to build up a view of sources and uses of cash from 2017 to 2019 at prices of $50 a barrel. Sources are on the left here, the cash from operations, cash on hand and proceeds from dispositions. First use of cash is to maintain our production. This takes about $4,500,000,000 a year. Then we pay the current dividend and increase the dividend each year. Over these 3 years, we'll retire $7,000,000,000 of debt to get us down to our $20,000,000,000 target. And in parallel, we'll execute the $3,000,000,000 stock buyback program. And even at $50 a barrel, after meeting these higher priorities, we can invest the capital request required to get modest production growth and associated margin growth. Now if prices are above $50 a barrel, we'll allocate the free cash flow based on the decision criteria I discussed earlier. Now this level of strategic flexibility has been a direct result of actions we've taken since the spin to transform ConocoPhillips into a leaner, more resilient E and P company designed to deliver disciplined returns through the cycles. And just to put that transformation in context, have a look at this. Because we've all been in the middle of so much change, it's easy to miss the entirety of how we've transformed ConocoPhillips since 2012. Each of these sliders represent a critical strategic measure that is shifted in a positive direction. From a financial perspective, we've changed our breakeven price from over 70 $5 a barrel to less than $50 a barrel through a combination of sustainable change to our cost structure and reducing the capital required to maintain production. We've taken on additional debt through this cycle, but we have a plan in place to take that debt down to 20,000,000,000 which is $3,000,000,000 less than we had at the time of the spin. And we've moved to a more flexible, therefore, more sustainable distribution philosophy combining a growing dividend with share buybacks. From a portfolio perspective, we're in half as many places as we were at the time of the spin, and we're going to continue to focus this portfolio with the dispositions we announced today. Partly as a result of the dispositions, but also because of the choices we've made for an investment portfolio over the last few years, we've changed our product mix to focus on higher margin barrels. And we have a massive resource base that includes over 18,000,000,000 barrels with an average fully burdened cost of supply of less than $40 a barrel. I'm not sure if Al mentioned that earlier. And from a strategic flexibility perspective, we have a much more flexible capital program now with no mega projects, and we are not chasing production growth. Instead, we are committing to growing production per debt adjusted share with margin growth through a balanced approach to distribution and high return investment in the portfolio. And that's all based on a dynamic scenario monitoring process that embraces the uncertain future that we see and the expectation of price cycles. This is a transformation that we believe has set us up exceptionally well for the world ahead of us with a strategy that we believe represents a distinct, interesting, viable and achievable shareholder value proposition. The strategy is driven by free cash flow generation with peer leading upside to price. It's underpinned by a strong balance sheet and a low breakeven price. And we're focused on improving relative and absolute returns, not absolute growth. We're accelerating this strategy with $5,000,000,000 to $8,000,000,000 of dispositions over the next 2 years that will continue to focus the portfolio. And it is a remarkable portfolio that can support over 30 years of production with an average cost of supply of less than $40 a barrel fully burdened. The strategy is designed by the dynamic scenario monitoring process and the right balance of commitment and flexibility. The fundamental objective of this strategy is to deliver shareholder returns through the cycles, and that's what we are committed to deliver. Now I'll hand the presentation back to Ryan to summarize the key themes you've heard today. All right. Thank you, Matt. And you guys have been patient. So let me just wrap up really, really quickly for you and then we'll get to your questions. So hopefully, what you've seen today is we've dramatically transformed our company. We've lowered the breakeven cost of the company. We've lowered the operating cost of the company. We've lowered the cost of supply in our resource base. We're accelerating the value proposition through a $3,000,000,000 to $8,000,000,000 disposition program and a $3,000,000,000 share repurchase program. And finally, I think we're differentiating ourselves. We're differentiating ourselves from other E and Ps with a flexible, low cost of supply resource base. And we are an E and P company that's going to be disciplined and really focused on returns. So thank you for your attention. We'll take your questions. A little bit Sid and Vlad will be kind of on each half of the room here a little bit. So if you can, I'm going to ask the guys to come back up here. Raise your hand. I'm going to just go between Sid and Vlad and we'll have plenty of time to take all your questions. And please raise your hand and give us your company name and we'll go from there. So Doug? Ryan, the new business model and the value proposition is one that has led to pretty positive shareholder outcomes during decades past, especially when management teams remain focused and committed. And on this point, we consider the new approach and also that energy executive pay incentives should connect to higher shareholder returns. My question is, how do you guys ensure that the linkage is present for your plan in the future and that everybody's focused on the same goals. That's the first part. The second part is, should some metrics be prioritized over others with the new plan? And if so, what should they be? It might be too early to think about that. That's a springtime item, but how are you thinking about that? No, thanks, Doug. Yes. No, absolutely. So we've had a long standing both in terms of our short term incentive programs and our longer term incentive programs. We haven't tied to total shareholder return. We haven't tied to total return on capital deployed and cash return on capital deployed. So that sits in both our for me and all my top executives. And in fact, our short term program is ubiquitous across the whole organization. So includes operating results like we meeting our budgets and our targets on costs and capital and production and on safety, but it also includes return on capital employed and cash return on capital employed. So we look at all those 3 absolutely and relative performance on all three of those measures. And those are the ones you like in the future too, Brian? Yes. And I think we're playing with debt adjusted per share metrics as well. So we're thinking about that as a possible metric as well. It takes a lot longer time for that to materialize, but it shows a very high correlation to performance. Yes. Where is over here? I'm just going to go between the guys. Yes. Thanks. It's Jason Gammel with Jefferies. I just wanted to ask about how to think about the share repurchase program relative to debt repayment. And it was pretty clear that simply paying off maturities was how you're going to handle debt. But should we think of the share repurchase program as being kind of a pro rata process over the course of the next 3 years? Or is it going to be more tied to the inflow divestiture proceeds? Yes. So I'll let maybe Don go through the math, how we're thinking about that in terms of your question, Jason. I'd just say from a high level, again, look at our priorities. So our priorities are going to be to get the debt down. We think we can do it ratably over time with the maturities that we have, but that comes before share buybacks. But Don can address I think maybe the specifics around how we're thinking about it. Jason, I think history kind of shows that market timing approaches don't generally work out real well sometimes for companies. And so so our approach is probably going to be more of a cost averaging. And so I think you can expect us to be pretty consistent in our share repurchases over time. We're not going to be able to forecast our share repurchases or provide guidance or anything like that, but you'll obviously see them in our financial disclosures. All right. Yes, Dave. Thanks, Ryan. It's Doug Leggate from Bank of America. So two questions, if I may. The first one, one of the perhaps the obvious things that's missing from your use of cash are acquisitions. And I guess when you look and I guess large capital projects, which don't appear on the schedule either, do you think you have the portfolio integrity currently to deliver your the range of growth options that you've laid out just committing to short cycle from the existing portfolio without damaging portfolio integrity? Yes, I can let Al chime in here as well, Doug. But absolutely, I mean, when we look at the veracity of the opportunity set that we have, when we look at those kinds of metrics, we can hold this for well beyond a decade. Al, you might. Yes, that's exactly right. If you look at that cost supply curve I showed you, the kind of stack of the 3 different asset classes where we do have 800,000 barrels a day of our roughly 1,500,000 barrels a day production a day comes from those conventional areas where we have a lot of infill drilling around infrastructure and new projects that we have planned what we call the medium cycle projects. You're right, we don't have any of the big mega projects planned, which we think is a good thing, maintains our flexibility and keeps us in that core zone of the kind of work that we've done a lot of and very repeatable good results. And you can when we plug that into our plans, it goes out, as Ryan said, 10 years of good low cost of supply assets that you can develop in that time. In addition, I really didn't focus today on the other 27,000,000,000 barrels that are out to the right because they're above $50 right now. But some of those are at $51 and there is a lot of stuff in $50 to $60 that obviously we expect to continue improving that. And so and particularly in the unconventional where you see 7,000,000,000 barrels there that's already below $50 you can imagine that in the flexible area, we've got lots of opportunities for many years to come, decades to come. And Doug, I would add just one thing. I think when you're not chasing growth, when you're chasing returns, you don't have to get on this treadmill and run really hard. And with the portfolio that we have, we don't have to run really hard on that treadmill. It's $4,500,000,000 to maintain flat production. We can do that for a decade. It's very simple way of summarizing the answer, Ryan. What happens to reserve replacement over the next 5 years? Yes. I'll let again, I'm not worried about it. So the macro, 18,000,000,000 barrels are going to move to reserves over the course of time. I can let Matt talk to you about the math and the numbers, Doug, a little bit. But it will be lumpy. But with 18 barrels, it's going to move into reserves over the course of time as we execute this plan. It doesn't give me a concern about reserve replacement. But Matt can share with you the details. Yes. In any given year, our reserve replacement ratio is going to vary. We expect over the 5 years, first 5 years of the plan, that we'll average about 100%. In the years where we're sanctioning major projects like Bohai Phase 4 or the debottlenecking at Sermonte or the backfill for Darwin LNG, we're likely to be above 100%. And in the years where we're not sanctioning those sort of projects, then we're likely to be below 100%. And that's okay. It's going to be lumpy. One of the reasons that's okay is that our strategy is designed to move our average asset base to a shorter cycle time, shorter than our current cycle time. So our RTP ratio just now reserves the production ratio is about 14 years. That's higher than most of the competition, including the integrated companies. So if over time that RTP ratio comes down a little bit, that's fine. We're not too concerned about that. And in fact, you should want that. You should want us to get that now. And Doug, if I could just add one thing, just to point out that we do have an acquisition in our plans. We plan on buying a little bit of ourselves, right? Just to make a pitch, I think that's a pretty good investment, probably the best acquisition we can make. Yes. Dobreis, JPMorgan. First question is just on the asset sale side of things. Obviously, this is a critical part of the financial plan over the next couple of years. So I was hoping you could elaborate a little bit more. You obviously talked about natural gas as one of the target assets, but maybe help us think through how bite sized these pieces are versus chunky, how ratable the asset sales plan would be, what kind of production you would anticipate would be going away in cash flow? I know you said $10,000,000,000 of CFO in 2019 at $60 is that post asset sales? And how much cash flow goes away with the asset sales under your assumptions? Well, Phil, I'll take the last part of that. Some of the other guys may want to address the asset sales pace and the other questions that you had. But when I mentioned, I think you're getting that from the 2x leverage in 2019, that would imply about $10,000,000,000 And we think we're capable of doing that in that timeframe. That's ex disposition. So any cash flows from the dispositions that we have would come out of that. We can't really estimate the cash flows that would come out of the dispositions very well because it's going to depend on which assets that we ultimately sell. And we always have a we're always in the market with assets, and we always have a bigger plate of assets than what we eventually close on because we're only going to sell the things that we can get full value for. So I would add that's why we haven't really disclosed. We're going to be marketing a lot more assets probably than what that range might imply just to make sure that we can hit that range. But you can use North American natural gas metrics and 0 in probably on what volumes and cash flows that might represent. Okay. Thanks. And then I guess the second question would be, first of all, thanks for all the sensitivity analysis. Just thinking through if we're in the spot price world again in 2017 where we're kind of in the mid-40s. Obviously, this year, your asset sale target you kind of at the low end of that range. So maybe just walk us through how you manage a mid-40s type of scenario if we see it repeat again in 'seventeen? Well, I think that's the beauty of the priorities that we've laid out is just start to take them in reverse order. So if we're in a sub $50 world or $45 world, we've just shown you we've got a $500,000,000 of CapEx above our stay flat number that we would look to roll off. That's the flexibility that Matt talked about. We have flexible exploration programs that we could start to roll off. If we thought we were going to be there in a lengthy period of time and it was going to last for a long time, you could obviously suspend the buyback program. So you just work backwards and if it's even worse and we may not accelerate some of the debt repayment if you found yourself in that period long term. And I think that's the beauty of the flexibility that we've created in the portfolio. And so I would take the priorities in an up world and I would reverse them in a down world. Over here, Ed? Ed Westlake, maybe a follow on on the disposals. I mean, a lot of gas is on the market, not just from you, but also from your competitors. Maybe give some color on where we are in data rooms. And do you think the market is actually large enough, I mean, obviously, to absorb the sales? Yes. Matt's managing that process, so let me let him Yes. I think we the assets that we're marketing, we know there's a lot of interest in. So we feel pretty confident that they that we'll be able to execute this disposition program. We're not going to sell these assets unless we get full value, but there's a lot of interest in the types of assets that we are likely to market. And then follow ons on you mentioned cost inflation as the industry gets back to work as a potential risk and you've modeled it. You've also potentially still got some deflation from technology and from being in the more conventional area because most of the money seems to be going back into shale. So maybe talk a little bit about what you think the biggest drivers are to actually maybe even lower costs in that conventional bucket further from here? Okay. I mean, I think you're right that there is still particularly in Europe and Southeast Asia, we're still continuing to experience deflationary forces, although it's pretty well hit a bottom in most of North America. And so there is still more room to go there. All we were trying to do in the cost of supply side of things is we didn't want to show you that 18,000,000,000 barrels across our corporate cost of supply and have those numbers be fixed at the low point, roughly the low point in the cost cycle where we are now. And so we took the same models that we've showed you before, our supply chain model, and put in a $65 Brent world and let those costs go back up. And so the most sensitive to that, the parts of our portfolio affected the most was the lower $48,000,000 unconventional. Those are the ones who cost supply went up the most from doing that. But also 4x is a significant factor in lot of our overseas locations. We also put that in for $65 world. But we've got I touched on it some there, lots of different new technologies we're working on that are driving down the structural side of the costs and that work, of course, is continuing. I don't see any slowdown in that. Over here, Paul. Paul Chan, Barclays. Maarten, three questions. First, based on your earlier comment, should we assume that in the event if the asset sales proceed did not go as planned or somewhat disappointing on the process, the first thing you will slow down or cut back will be on the repurchase instead of the debt reduction? Well, again, Paul, follow our priorities. So if asset sales slow down and we can't or they drag out or we reach a lower end of that range that we decide, start with our 5th priority and work yourself backwards. And that's how we're going to manage the system to the cash flows that we have. Okay. 2nd question, Dan, if we forget about the cash flow availability for a minute and just looking at your organizational capability and also the asset, the resource base that you have, what is the realistic sustainable growth rate you can target for the next say 5 to 10 year without stretching your organization? Well, I'll let Al can speak maybe more to that specifically too. But let me give you a high level view in my words around it. So the reductions that we made over the course of I'd say 2016 have largely been done to get the organizational capacity match with the capital program we see going forward. And that's a very disciplined capital program that's not reinflating or going back up. So we feel like we have the organizational capacity and have kept that because we've resized the organization to fit that capacity. But I think as Al probably pointed out, there's we do think there's scope to grow in terms of the resource base that we do have. And we've got the capacity in place right, Dave. It's not just to manage 3 or 4 or 5 rigs. I think a good way not to put too fine a point on it, but to get you to the answer you're looking for would be to if you think about the chart that Matt showed where he had the cycle, the price cycle and he showed you 5 years of CapEx and an example of what we would do. Our organization is structured to execute a program like that. So you saw some capital growth in there. If you look at that chart, you'll get an idea of it. And so we're set up to be able to execute that sort of environment with the organization we have now. If you also think about that curve that I showed on one of my charts of how we could how much we could grow the Bakken and the Permian and the Eagle Ford, those three areas with different numbers of rigs. That if you connect that to those CapEx curves, it kind of gives you an idea of what we could do with that flexible part of our portfolio, which is the unconventional that we would move up and down. If we're looking at after you spend $1,000,000,000 in the maintenance CapEx, what's the underlying decline curve on the base operation? Thank you. Yes. The underlying decline, it varies in different years. It's generally in the 8% to 10% range, unmitigated. And as some of the APLNG and Surmont 2, some of those new fields that are in that bottom category, that's the real flat production come online, it's been driving that decline lower. And as we move later out in time and increase the amount of our capital going to unconventional, it will drive it back in the higher direction. But in that range is pretty good range. Thanks, Ryan. And I appreciate that you fully burdened cost of supply work. I thought that was very insightful. I'm curious for both you and for Matt, how this work influenced your view of the oil macro, given how low the cost to supply curve looks for ConocoPhillips, does it change the way you think about ultimately the equilibrium price for oil? And I have a follow-up. Yes. Matt, go ahead. Yes. So as we look at these scenarios and assess the probability, that's one of the things that's guided us towards you're going to be successful in a world of lower and more volatile prices, which is what we expect, then you have to have a low breakeven, you have to have a low cost supply, you have to have flexibility and you need to be disciplined. And that's what we've designed our strategy to do and it has been guided very much by the way that we see the future unfolding. And I worry, Neil, I don't think everybody else in the E and P world has the same discipline. So I think that informs just reinforces our view of concerns around the macro and concerns that it is a well supplied world. And if you want to be resilient to that world, you better have flexibility and you better have returns in mind and you better have a portfolio that can sustain your production at a very low amount of capital because it is a well supplied world. I appreciate that. And then the follow-up is on this curve. Specifically, as you think about the different parts of the unconventional portfolio, the Eagle Ford versus the Permian versus the Bakken, do you find on the curve that specific regions fall in different parts of that curve? Or does the core of the different plays ultimately compete in different levels. Yes, I think let Al chime in as well here. But no, we each one of the plays have a spread across that cost of supply curve. And each play has very low up to the $50 depends on where you're at in which play. One of the interesting things that we've done, it's given us a lot of insight over the versus last analyst meeting when we first started showing you the quality of our resource base. If you went back to that point in time, we had our Eagle Ford in there as just one dot. And one of the things we've done over the past year plus is put a lot more granularity in that. So each of our unconventional areas, I talked earlier about those different sub plays and how we optimize the spacing and stacking completion designs differently across those. Each one of those is a separate data point basically in that cost of supply curve. And that's given us a lot of interesting insights. I mean there is a fair amount of variability. The Eagle Ford is not all one thing. It's got a lot of variability. So it is kind of like what you talked about. The heart of each of those, the best parts of those plays tends to be over toward the left. And you see pieces of all those plays further to the right on our cost of supply curve also. And this is sorry, this is an oversimplification. But the way I describe it is, I need to know when to put the next rig into the Permian, when to put the next rig into the Eagle Ford or when to put it into the Bakken. And it's not that simple, but that's how we're describing it to ourselves. So we know when the next set of rigs going to a particular asset is drilling the best of those assets. Over here. Ryan Todd at Deutsche Bank. Maybe within the context of your cash return to shareholders, if we can think a little bit about dividend versus buyback, I mean, how do you think about the pace of dividend growth in terms of something we should think of going forward? And is targeting a dividend yield that's effectively in line with S and P average, is that enough? Does it distinguish itself enough versus your peers? And there are a number of peers maybe on the integrated side that aren't on this comparison chart. Is your dividend yield high enough relative to some of those as well? Yes, I think it's a good question. We're not trying to target a yield or something like that. But when we went through the painful effort of resetting our company, which included reducing the dividend back in February, we wanted to get it to a level that was competitive through the cycles. And we also want to get it at a level that we knew we could grow it annually. Now our intention is not to get back as fast as we can to $3,700,000,000 worth of dividend payment that we had say last year. But growing it annually is a very important part of the offering we think we have to the market. I'm not I don't have a target percentage in mind. Again, we're going to look at the macro considerations. We're going to look at where we're at in the cycle. We're going to look at how we're competing across all the priorities that we've got. But as we've laid it out, that is our second priority. Our second biggest priority is to grow it annually. And you should expect that from us. But I'm not going to get locked into what percentage growth that's going to look like every given year. It's going to be dependent on how we find the situation, the financial capability. Have we met all our priorities? Are we getting the balance sheet down? Are we doing all the things that we said we're going to go do? But you should look at us to be growing it annually. Thanks. And then maybe for a second question on if we think of the way that you look at managing operations in your U. S. Onshore basins, is there a benefit on a basin level to how much benefit is there, I guess, to economies of scale within the basin? And if we look at your positions, I mean, you've got a relatively large position in the Eagle Ford, varying degrees of large or not so large in some other basins. Is there a benefit to consolidation in some of these basins? And would you consider yourself to be a consolidator? How would you think about the pluses and minuses of your operations? Yes. I think there is the first benefit you get when you core up and consolidate an area is the ability to drill these longer laterals, which makes a huge difference. I said it's a 10,000 foot lateral versus a 5,000 foot in a typical unconventional development adds about 30% to your NPV. So that's one thing you're really after as you try to core up in those areas. But we have we've kind of developed a bit of a concept of a minimum efficient unit size. So it is when you're running just 1 or 2 rigs, it is inefficient relative to how many frac crews you need and that sort of thing. So what you see us running once we're into manufacturing mode and running more rigs, so that's the mode we're in Bakken and next year in Bakken and Eagle Ford. We are running numbers of rigs that match up nicely with our frac crews and allow you to have economies of scale and move efficiently. So those are the two places where we're in that mode. And in places like the Delaware that I talked about, we've been working to core up in Midland Basin also to get to that core piece of acreage where we can drill the longer length laterals and have enough good spots that we want to drill to get those economies of scale before we go in there and run multiple rigs. So we give our people, we call it affectionately knife fighting money. So they're in there every day. We're in the market every day coring up. We're in the market trading, swapping. You saw some of that in Western Canada. We were doing that in the Midland Basin and in the Delaware Basin and the Permian. We're doing that in the Eagle Ford every day. So some consolidation makes a lot of sense. As long as we can get stuff into the portfolio that competes on a full cycle cost of supply basis with everything that we're doing, we're not going to dilute that in terms of the returns. Paul? This is Paul Sankey at Wolfe Research. There's a couple of differentiations that you made. One is the Eagle Ford and the high level of activity, maybe more delayed level of activity there. And secondly, that you were in E and P that is a dividend and buyback or cash return player. Firstly, I was wondering why you wouldn't be disposing of the Permian stuff if you're not really going to be drilling at the Eagle Ford is your focus? And secondly, can these businesses, these unconventional businesses actually be run for free cash flow? And dividend, I mean, wouldn't you be better maybe splitting the whole unconventional business off into its own growth model and leading the cash return run? Yes. No, I think, Simeon, this is so let me take the first one. We do get a lot of questions about the Permian. So hopefully if you listen today and you talked about what we've learned in the Eagle Ford, we intend to do that same thing in the Permian. Those resources aren't going away. They're not going to get competitively drained by other people. And we're going to make sure we figure out how to go do it. And it's compelling. It's a 1,800,000,000 barrel resource for the company. And we're going to do it right. We're going to maximize returns. We're not going to go fast. The guys that went fast in the Eagle Ford destroyed returns. And they can't go back. We're not going to do that in the Permian. We're not going to do that in the Bakken. We're not going to do that in Western Canada. We don't have to. We don't have to move fast because we're not chasing growth. So we've got a 1.8 bane barrel position. We know how to monetize it. The NPV of the learning curve dramatically exceeds the NPV of acceleration. So when we look at it and we look at it and this is based on our past experience. This is what we've done. This is what we've accomplished in the Eagle Ford. That's why the Permian is still very, very valuable to the company. So you talk about the spin. So we get that a lot. Why don't you spin off the unconventionals? Well, there's a bunch of companies out there that are in the LNG and the oil sands today. And what are they trying to do to their portfolio today? They're trying to diversify it into shorter cycle, more flexible investments to deal with an uncertain world, low commodity prices, a lot of volatility. So those companies are actually trying to get more unconventional and conventional opportunities. So if I were to do that and I was a company that was left over without the unconventional, what would I be trying to do? I'd be trying to get more of just what I spun off. So it just really doesn't make a lot of sense to me because we've got a very strong plan to maximize value, maximize returns back to the shareholders and we are going to exploit it. We're going to exploit it right. We think we bring differential knowledge and differential technology to these kinds of plays that will maximize the value for you, for all the shareholders in our company. One more point I would add to what Ryan said about the Permian. If you think about the data I showed you today just on the Delaware, a year ago we had a 1,000,000,000 barrels there that we thought we could develop below $50 a barrel. So if I were trying to sell that acreage last year, that's what it would have been in my data room. And here just a year later, it's increased 80% and that's just the Wolfcamp up to 1,800,000,000 barrels. It's below $50 cutoff. And so what do you think is going to happen next and the year after, the year after? There's a lot of growth that's going to come there. It's obvious. And so why would I sell that before I understand all that? You're selling it cheap if you do that. Over here. It's Cielo said. So two questions. First, APLNG cost of supply less than $30 a barrel, sirmon less than $40 pretty impressive. Could you talk about cash margin per BOE at a $50 Brent? In other words, trying to get a sense of annual cash generation for the 500,000 barrels a day steady production that we're talking about. If I talk about the different pieces there, that total wedge generates cash, as I said earlier, at about $40 a barrel is when it starts. Of course, that includes Darwin and Cutter Gas 3, etcetera. If you think about the newer pieces that people have been trying to understand in APLNG and CERMOT, FCCL, those pieces tend to if you take the 2 joint ventures first, they both start to generate cash inside the joint venture at around $45 Brent. That doesn't mean we get the cash out of the joint venture necessarily. Those ventures hold a certain amount of cash when they're generating not large amounts. But at around $50 is when we expect both FCCL and APLNG would send cash back to the shareholders. So that gives you an idea of the kind of range they're in. At Surmont, at around $45 you're roughly at breakeven on cash margins there. And of course, it goes up rapidly as prices go up from there. And just to point out again, in the back of your books for the equity affiliates, which would include FCCL and APLNG, we've provided cash sensitivities, cash flow sensitivities. And as Al said, we're expecting that as oil prices approach $50 and beyond, then they would start contemplating distributions. And so those sensitivities will show you the slope of how cash is moving with price. That's helpful. The second question, Al, think on Delaware Basin, 1400 locations, you mentioned cost of supply less than $40 a barrel. What's the gas mix assumption? In other words, is it a per barrel number or per BOE number? I mean, you broadly talk about cost of supply. How does it adjust for gas mix? Yes. The way we do cost of supply when we adjust for gas is not a 6 to 1. We don't do it on an energy equivalent. We do it on a value equivalent basis. So when you see these numbers in the gassier plays that are adjusted to Brent, it's done that way on a value basis. So if it's AECO or it's Henry Hub, it's Europe, whatever market it's in, that relative value between the gas in that market and Brent is how we adjust. And so that's how we're able to quote. It is an OEB cost of supply. Now to take your question on the Delaware specifically, in the Delaware, we're about 40% gas from that production, about 25% NGLs and the rest oil, just to give you an idea of the mix. Scott Henn from RBC. So the question I have is, we appreciate the discussion around how you manage commodity price volatility. It was really helpful, especially with how you prioritize your different objectives. Specifically, could you give us some sense on historically how good have those tools been in terms of forecasting what may or may not happen with oil prices? And specifically with what you see right now and how that might change? How quickly can you adjust your budget rate? How sustainable do those signals need to be to say we're going to put in 5 more rigs into the Eagle Ford or we're going to go and look at some of those conventional opportunities we have? You want to take that, Matt? Yes. So on the how reliable have those scenarios been and the probabilities associated with those scenarios been, we started the scenario process in 2012. The highest probability scenario at that time was what we was the unrelenting unconventionals, what we called tidal wave at the time. It wasn't 100% probability, but it was a high probability. As a result of that, we embarked upon this journey of transformation because the concern that if we end up in a low price environment and we don't change the characteristics of the company to be successful in that environment, then that's not going to be good for us. It's not that we knew with absolute certainty that that's a scenario that was going to evolve because you never know with absolute certainty how things are going to evolve. But it very much was in our mind as we embarked upon this transformation journey to get to a place with lower breakeven, with a lower cost of supply and more flexibility. So it has been helpful from guiding the way that we've behaved over the last 5 years. And since that time, it's become much more sophisticated. We didn't have a web crawling algorithm to go out and look for these indicators. We didn't have 150 indicators at the time. We've become more sophisticated. It's not perfect. None of these sort of tools are perfect. And it's primarily about the insights that you gain and how it makes you think about the strategy rather than the absolute ability to predict the price. And the thing that, that tidal wave scenario that's called unrelenting some alliteration now, the thing that it didn't have versus what's actually happening is it wasn't combined with OPEC decides not to be a cartel anymore at the same time. And so if you look back at 2012, like Matt said, with that tidal wave scenario, we had a lot of oil coming out of the unconventionals in that scenario, but it only drove us down to a Brent price in the 50s, which seemed really low at the time when we were at $100 something, dollars 110 I think in 2012. So that's kind of illustrates that it's not a perfect system like Matt said, but it does give you a lot of insights. And it does the right thing too, it gives you no regrets decisions. So when you look at everything across your portfolio, you say, well, if this happens and it does, what are the decisions you wouldn't regret doing? And so it gives you a certain level of decisions that says, I wouldn't regret doing these under any scenario we might find. And I'd take you back to the end of 2014. Our company got a lot of criticism. We took capital from about $17,000,000,000 down to $11,000,000,000 People were thinking it was going to be a V shaped recovery like coming out of recession. And we got a lot of people commenting about you're overreacting. And you're but when we looked at it, we said we're not going to regret taking the capital down as hard and fast as we can, because we don't know what's going to come on the other end of this. And in fact, looking back on it, if you ask me what we should have done differently, we should have taken it out even harder and faster, because we were starting to build the flexibility of the company to be able to do that. At the spin, we were executing $8,000,000,000 projects in parallel And we didn't have the flexibility. And that's what frightened us with that scenario. Over here. John Kirillinsakian. For a more shorter cycle driven business model, is it time to hedge or will the lower leverage balance sheet be your hedge? Yes. Our views really haven't changed on hedging. When we take a through the cycle view, we do consider hedging to be a zero sum game and considering the cost, which can be appreciable, it's probably less than a zero sum game. As we look in the short term, we view the market as moving way. And we spent some time today trying to demonstrate our leverage to price recovery. And that's just something that we don't want to take that upside away from our investors. But I think that your point is right and would absolutely agree with you. We think that the best insurance is a low cost structure, a low cost of supply and strong balance sheet. Okay. Next question, with the sale of the natural gas reserves or assets in North America, are you finally going to be breakeven on a profitability basis in Canada and the U. S. In a $50 world? Room. Would we be breakeven on a cash basis or income basis? Net income basis. That'd probably still be a bit of a stretch on a net income basis, but we're getting close. Scott Babers, Simmons and Company. Thank you guys very much for all the details today. Very much appreciated. It appears that the 18,000,000,000 barrels of low cost resource base is more of a focus for you than the 8,000,000,000 barrels or so of proved reserves have F and D metrics on proved barrels, therefore, lost some relevance, which are a little bit more transparent to us. How do you guys think about F and D through the cycle, which you included, I think, in your presentations last year, really in the context of your $10 a barrel of capital intensity in the upstream right now. And then just to confirm, are the spending plans you've highlighted that's sufficient to hold that 18,000,000,000 barrel resource base flattish to growing despite the fact that your 1P reserves might decline a little bit? Yes. You want to take that? Yes. And then on the F and D math, so in response to an earlier question, I said our expectation was over 5 years we'd have 100% reserve replacement, but it would be lumpy. To get some F and D insight into that, if we were just to sustain flat production and spend $5,000,000,000 a year, which is actually a bit more than flat production, if it's real and it is real. There are two reasons why that's showing up. 1 is the quality of the portfolio that Al went through to give you a couple of examples of that. In the Eagle Ford, a typical well in the Eagle Ford that will be drilled in the next 5 years will be somewhere between 900,000 and 1,000,000 barrels of resource reserves associated with it once it's on the books. And fully loaded, including tying into our existing infrastructure, it'll probably cost $6,000,000 $6,500,000 So the F and D in Eagle Ford is somewhere between $6,000,000 $6,500,000 If you go to our more conventional projects and do use an example like in Norway, Al mentioned the Tor 2 or the Tor redevelopment. That's about 20,000,000,000 barrels net. It's about $240,000,000 project, so about $12 So when you put and there's other examples all around the portfolio, China 1,000,000 barrels. 20. 1,000,000. 1,000,000 barrels. Not a barrel, not a 1000000. Yes, 20,000,000 barrels $240,000,000 so about $12 a barrel F and D. So as you go around the portfolio and you average it, you get to play to a place that's $10 a barrel. Now that's F and D on a GAAP basis. One of the other reasons that it's low is because a third of our production isn't declining and it doesn't require very much capital to keep it flat. So on a GAAP basis, it's only $500,000,000 $500,000,000 a year to keep it flat. And even on a PC basis, it's only that only adds about $800,000,000 a year. So even if you do this F and D math on a PC basis, you're only $11 a barrel of F and D. So it's all about the shift to the low cost of supply. That's where we're putting the money. And over time, we'd expect to be around 100 percent and as a very low F and D. That's very helpful. And then you guys also gave some helpful charts in the back that show production by region, expecting a decline in Lower forty eight, which I guess should be expected here. Can you talk about as you're going from 3 to 8 rigs, some of the lag times associated with arresting that decline and then getting back into a growth mode? And then also, can you maybe talk about some competitive advantages from adding back rigs in less active basins, I. E. Not the Permian and some of the advantages and maybe that's getting for you? Sure. I guess first, if you look at the 3 rigs we ran most of the year and I talked in 3Q call about being at 8 by the end of the year. And then you could if you added up all the rigs I talked about during the other talk, you could see that we expect to be to get up to the other talk, you could see that we expect to be to get up to around 12 next year, although it will build over time the average number of rigs in 2017. Our current plan is more like 11. With that kind of program that you get at this $5,000,000,000 capital level, we would expect our Lower 48,000,000 unconventional year over year 2016 to 2017 to decline about 6% then and then start growing from there. If you want to get an idea of how it grows, all you got to do is take that nifty curve that I gave you and plug in how many rigs you want to and you get the answer until it gets better again. But you're right. The profile does sort of dip because we're going through 3 rigs and we'll dip early in the year and then we start to recover and come back out of that. And then the second part of your question about the really the upside of being in the places where everybody else has left. It's really been fun to do that compared to the usual. We're all elbow to elbow in the same place like it was in the earlier days in the Eagle Ford. I mean what we found is that there are suppliers that are in that area that don't want to leave and that are out of business. And so it's been a very attractive market for us to be able to lock down stimulation crews and rigs and all the other services that we need. And we found those contractors in those areas to be willing to give us some lock time as well, where we still have the ability to cancel on short notice if we to keep it flexible for us. But in the event we keep going, they're willing to hold the prices for periods of time. It's harder to get that kind of arrangement in the Permian where everybody can palpably see the increase that's already underway. And Al mentioned it briefly, Guy. He talked about the netback. I mean, everybody built export facilities and there's refineries on the Gulf Coast now that are tuned up to condensate. They see the condensate dropping. So you get netback realizations too. So it's not just on the cost side of it, but it's the revenue side that we're starting to see improvements in as well. So it extends across the whole value chain. Thanks. Roger Read, Wells Fargo. Maybe going off a little bit of what was in the presentation, but certainly topical, the election ends up very different. Republicans in charge across. You were able to get export policy through in a less than favorable political environment. Just curious, is there anything maybe on a wish list or potentially gets accelerated that you'd like to see here? Well, I sure hope that infrastructure, which is something that's gotten really bottlenecked up for unusual and I think very political reasons rather than reasons that make a lot of sense. So whether it's DAPL, it's Keystone or it's more product up to the East Coast and all that. So I would certainly hope that the way we think about infrastructure in the United States and we think about what's happening there that we can make some progress with the new administration. I think the tax code, I think there's an opportunity there for business and this is maybe broader than our industry. But as we think about lowering the base rate, making it more competitive globally, dealing with trapped cash and some of those issues will be a big benefit to business. And I think just generally recognition of what jobs and improvements to the economy this industry makes. Now we're going through downturn. We've lost a number of people in the business. We know that the cycle is going to improve and rigs are going to come back to work. And we can be a big help to the economy and certainly in the jobs and in our industry pays in terms of blue collar work, our industry pays some of the best wages in the U. S. Today. We offer medical plans, we offer retirement plans, we offer 401s and we offer very competitive base rates. So I think that's where we can play in that. And one more thing I would add to that wish list is on the regulatory front. One of the things that's been pushing up our cost of supply, one of the up forces that we've been battling is rapidly increasing regulatory load that's been driving not just overhead, all the people it takes you to keep up with all the paperwork and all the new rules that keep coming out and some of which aren't even written down. People show up in the field with verbal new rules, but it's also hitting our lifting costs. They're driving new things that we're having to do as part of our operating costs at a pretty rapid pace. So if we do get some change in the pace of that regulatory, that will help us to maintain our cost of supply as well. Let me take one more, please. Thanks. It's Blake Fernandez with Howard Weil. Ryan, the portfolio is clearly shifting more toward oil. And many of your integrated peers seem to be emphasizing gas growth long term based on global demand trends. I can appreciate that shorter term you're having to focus on where the opportunities are. But just longer term, do you feel like there's a need to kind of better balance the portfolio? Well, I think as we look at it, we're kind of agnostic as to what product mix. That's what hopefully you saw from a cost of supply analysis here, whether it's North American Gas or it's international gas tied to an LNG project or it's an oil development. We're fairly agnostic to that. I think we're exposed to the LNG business. We're international gas business. We have a big pipeline business in Indonesia that sells to Singapore and sells to Malaysia. We've got a very large LNG business with Qatar, with volumes now of APLNG Train 2. Darwin plans to we will backfill Darwin because it competes on a cost of supply basis, not because we're really enamored with LNG going in Asia. We happen to think that's a great market. We think it's a growing market. So we will be exposed to that kind of stuff. But I'd say we're not going out there and telling everybody we are targeting this specific piece of the value chain, this specific product in this specific geographic region. We're looking at it on a cost of supply basis and does it compete in the portfolio for capital. All right. Well, thank you all very much. I appreciate again your attention and your interest in the company. What you're doing today hopefully is our value proposition. So you understand it how it's going to go into action and how we're a company that's going to be managing free cash flow and managing returns. So that concludes what we have today. Hopefully, we do have lunch. If folks can join us for lunch, we'll spread out and have some opportunity for more questions and answers. Thank you.

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