Good morning to everybody. It is really a pleasure to see all of you today. My name is Ellen DeSanctis. I am 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 are going to hear from four of our senior executives. At this time, I would like to introduce them and tell you about today's agenda. Ryan Lance, our Chairman and CEO, will address our value proposition. That is the disciplined, returned-focused way we are going to deliver value to shareholders. Don Wallette, our EVP of Finance and Commercial and our Chief Financial Officer, will cover our four key financial priorities. Al Hirshberg, 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. Then we will begin our question and answer session. Today's presentation is being webcast. Materials are now available on our website. Later today, we will 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. I just want to make you aware that reconciliations of GAAP terms to non-GAAP terms can also be found on our website. Again, welcome.
Thank you so much for being here and for participating by webcast. Now it is my pleasure to turn the meeting over to Ryan.
Thank you, Ellen. 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. Today, my executive team and I will lay out the value proposition for the company. We are going to describe the details and the proof points around our strategy. We will 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&P company that we can be, but a truly distinctive E&P company, one that is focused on discipline, returns, and creating value through the cycles.
I'm going to start with a few slides today, then I'm going to turn it over to Don and to Al and to Matt for the rest of the presentation. Let's get started. Can an upstream company deliver value through the cycles with a returns-based value proposition? 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? 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. 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 upcycle. 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 of 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. 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 three 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. All three of those principles are linked by a strong focus on returns. Certainly, these are necessary or not necessarily necessary, but they're sufficient, sorry, to describe how we're going to allocate our cash flow and how we're going to create value through the cycles. In the middle column, we've tried to describe our five priorities for cash allocation. These describe the order in which we intend to allocate cash flow as prices rise and as they fall. Our first priority is invest a sufficient amount of CapEx into the portfolio to maintain and pay flat production and pay our existing dividend. 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. Our third priority is to reduce the debt. Initially, we set a target of less than $25 billion, and today we're setting an explicit target of $20 billion, and we want to maintain our A credit rating. Our fourth priority is to supplement the dividend with share repurchases. Between the two, we have a target to return at least 20%-30% of our cash from our operations back to you, our investors, our owners. Finally, we'll put money into our high return, disciplined organic growth portfolio.
Since we rolled out these priorities in July, I think they've been received fairly well conceptually, 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? Earlier today, we announced several actions to accelerate our value proposition. They're shown on the right-hand side of this slide. We announced an initial $3 billion 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 billion to $8 billion of assets. Now that our major capital investments are rolling off the portfolio, we're putting more money to our shorter cycle, flexible investments. Finally, you see we're announcing our guidance for our 2017 operating plan.
It consists of $5 billion of capital, a $6 billion 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.
I know this is conceptual, let me make it real. The bottom part of this chart demonstrates how this strategy would work over the next three 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. When you include proceeds from dispositions, we can achieve our debt target of $20 billion and execute a $3 billion share repurchase program and deliver up to 2% high return disciplined organic growth. If you read further to the right of this slide, you see that prices above $50 Brent, we'll have available cash to make choices.
We can buy more shares or we can increase our investment into a high return organic growth. 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, it's compelling, and here's why. 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, 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, you're going to get a lot of detail about that transformation in the presentations that are coming up. Let me give you the bottom line.
We've reduced our break-even 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 focused exploration for $5 billion. We've significantly increased our capital flexibility and our strategic flexibility now that our mega projects have started to roll off the portfolio. Our resource base today contains 18 billion barrels of resources at less than $40 cost of supply. That's 18 billion barrels at less than $40 cost of supply. This transformation required many difficult decisions and really a tremendous effort on the part of our workforce. 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. 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? We do that with a $5 billion-$8 billion asset disposition program, and we reduce our debt down to $20 billion. We also do that by improving the underlying margins that these portfolio actions help, by starting to execute a $3 billion share repurchase program, and by having peer-leading upside as prices recover. Finally, what differentiates us as an E&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%-30% of our cash flow back to our shareholders through a growing dividend and through buybacks.
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&P company today that offers this level of transformation, acceleration, and differentiation. 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 the improve points around our value proposition and the strategy that I've outlined here today. Don's going to cover the financial priorities and how much we've really transformed the company. Al's going to provide an update on the portfolio and how it's differential to our competition. Matt's 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 out-compete.
All the speakers and I will come back at the end and take your questions. 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 four 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. First, 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. Second, 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 billion we're targeting.
Based on our plans, we think $20 billion is an appropriate debt level for our company and is achievable within a few years with planned asset sales. Third, we're differentiating ourselves from our E&P competitors by setting a payout target range of 20%-30% of operational cash flows. We'll soon begin our $3 billion share repurchase program. 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 two years ago, we needed oil prices over $75 a barrel to break even. 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 two-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 across the price cycles and positioned to generate strong free cash flow. 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. Two years ago, we said it took $9 billion 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 billion a year to sustain production. Less than $5 billion. 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. The capital intensity of our other conventional and unconventional assets is low too. Al's going to give you all the details you need 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 five years, we would be able to keep production flat with less than $1 billion a year to support base production and under $4 billion 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 2017 to our largest U.S. E&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, we believe it also serves to high-grade investment returns. When your treadmill's 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&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, 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. We retain a large portion of the price-related margin improvement. 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, 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 and to the right is where you want to be, and that's where we are. 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.
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 billion is not arbitrary. This level of debt would be about two times the estimated operational cash flows in 2019 at $60 oil, or about three 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 it's 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 dashed 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 we'll 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 billion. As you can see on the right, this would represent a reduction in balance sheet debt of about $7 billion, which would translate to a leverage of around two 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 where it's important to maintain a low breakeven price. 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&P 500 and quite a bit higher than most E&Ps. A resilient and steadily growing dividend is 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. 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. Pretty much any relative valuation metric would support that view. Strong distributions reinforce discipline, and that elevates the returns on our capital program. 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 billion required without needing any further help from the market. Should we realize improved prices, we'll have the ability to accelerate both debt reduction and share repurchases, we're willing to do that. Lastly, we view the 20%-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 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, 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, we expect that our planned dispositions will also be accretive to corporate returns. 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, 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. 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, 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. Among E&Ps, our commitment to a payout target range makes us unique. 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. 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. Recall that at the time of the spin, we had plans to sell between $8 billion and $10 billion 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.
It sort of stopped working on us 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. Importantly, against that early goal to sell $8 billion to $10 billion, we've actually realized proceeds of over $16 billion 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. We know how to divest assets when that's what's best for the company. We're certainly willing to focus our portfolio where it makes sense.
We've probably never really done reshaping and optimizing the portfolio. 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 billion and $8 billion of assets over the next two years as part of accelerating our value proposition. 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. This program targets areas and assets that are in an active A&D market. 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 throughout my section does not try to adjust for these asset dispositions. Let's shift gears now and talk about our resource base and future investments. Need you to advance it for me.
Last year, we showed you that our total resource base was about 44 billion barrels, with around 24 billion of that being below $75 Brent cost to supply. In today's world, though, we think focusing on a cost to supply less than $50 a barrel is more appropriate. Last year, we had about 13 billion barrels of our resource that was less than $50 cost to supply, as shown in the left-hand bar. Since then, we've added almost 6 billion barrels through cost reductions, recovery improvements, and further appraisal work. This has happened across our portfolio. Today, we have about 18 billion barrels of resource that's under this new $50 a barrel cutoff for cost to supply. As Ryan mentioned, the average cost to supply of these 18 billion barrels is below $40 Brent.
That 18 billion barrels is a 35% increase from just last year, and it includes the effects of upward pressure on our cost to 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 to supply. Cost to supply is the Brent 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. When we talk about cost to 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. 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 net back price for the products that are being sold. This calculation can be useful, but it doesn't provide a level playing field for allocating capital across a diverse global portfolio like ours. We add product mix and transportation differentials to this. This gets you to the middle gray bar. That represents a cost to supply that's been adjusted to a 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&A overhead, and the price-related inflation and currency changes. On this last item, we want to build our forward corporate cost to supply curve, we don't want to build it using the low point in the overall deflationary cycle for costs. What we've done here is we've adjusted all of our cost to supply calculations to reflect the cost and Forex inflation that we would forecast for a $65 a barrel Brent world.
That's what all the numbers I'll show today on cost of supply have that basis. 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, project returns are never going to add up to corporate returns. 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. We're taking it up a notch over what we had last year.
This chart shows only our 18 billion barrels of captured resource that has a cost of supply below $50 Brent. Of course, there's another 27 billion barrels of captured resource base on the right-hand side of this curve, but we don't include it here because those cost of supply are still above $50 a barrel. Until we 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. In this slide, each of the bars has a solid area and then a shaded area above it that shows the burden. 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.
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. 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. 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. Let's dig into the details.
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 billion of annual CapEx over a period of more than five years. Let me show you the high-level math because it's really made possible by our unique portfolio. 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 billion barrels, we have about 5 billion 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 a half a billion dollars in most years. That's what I'm showing with the dollars in the left-hand side of the area chart. Moving up to the next wedge is our conventional asset class, which holds about six of the 18 billion 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 billion of capital in most years. Finally, the top is our unconventional asset class. It holds about 7 billion 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 billion in most years. The bottom line is we can hold our overall production flat for the next 5+ years for around $4.5 billion of CapEx per year. I should point out that these numbers, these capital numbers include about a half a billion dollars of focused exploration spend annually. That's the reason that we expect to grow our production a small amount next year. We quoted in Ryan's slide 0-2% because the total CapEx number that we've quoted now for 2017 is $5 billion above the $4.5 billion that we need to stay flat.
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, Surmont and FCCL. 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 billion barrels with a cost of supply of about $40 a barrel. You'll see shortly they hold a tremendous amount of upside through technology development.
I'm now going to go through most of these assets one by one, beginning with APLNG. Train 1 started up in late 2015 and is exceeding expectations with production at about 110% of nameplate capacity. We just finished the rigorous lenders performance test on Train 1 with flying colors. Recently, we announced a significant milestone with the smooth startup of Train 2. As you know, all 6 of the new LNG trains on Curtis Island have used the ConocoPhillips Optimized Cascade technology, 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 billion 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 2006, but it's still going strong. Over the past five 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. While Darwin is mature, we're currently evaluating options for backfill after Bayu-Undan field depletes, 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. We've also identified an additional 25% capacity increase on top of that we can develop through brownfield expansion at the existing Surmont Two site. 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 Two. 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. 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 improvements so far have been in the gray part of the cost bars, the well pad surface facilities. We're using a process called zero base 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. 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, they're not done yet. They still have some more ideas, they're well advanced to drive down costs even further. We have another 13 billion barrels of oil sands in our captured resource base that currently has a cost of supply that's above $50 a barrel. These barrels are not counted in the 18 billion barrels that I've been talking about. 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, 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, 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 billion barrels into our below $50 a barrel resource base. 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, 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, we'll expect to have results in 2017. Here's how I'd summarize the value and the importance of this LNG and oil sands asset class to ConocoPhillips. It represents half a million barrels a day of production, flat production, for decades. Our mega project's complete, we're now in operating mode. We'll continue testing and implementing new technology to drive further improvements, these assets, as a group, generate positive cash flow above $40 a barrel Brent, with good upside to higher prices. 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 U.K., 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 billion barrels is really attractively distributed across the company's cost of supply spectrum. The fully burdened average cost of supply of this 6 billion barrels is below $35 a barrel. With this asset class, there are two kinds of programs. First is the conventional drilling programs that take place within existing fields and adjacent to existing infrastructure. Over the next five 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, improved technology has really allowed us to lower the cost. It's straightforward, it's predictable. 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 three years, our experienced project teams have executed over $5 billion of these kinds of projects, ones like those shown in the upper left, CD5, Eldfisk South, et cetera, 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. 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 $1.7 billion 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 five years, as shown in the production plot in the bottom right. 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 the 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. Remember, Brent was over $100 back then, so this was a good project. 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. 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. 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 three of our upcoming projects in Norway that have been advancing through our project gates. Tommeliten Alpha, Tor II, and Eldfisk 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 cost for these three fields down by about 50% over the past four years. 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. That wraps up our conventional asset discussion. You can see that it's a very important part of our business.
We've got 6 billion barrels of resource averaging less than $35 a barrel cost of supply that could deliver growth from projects and development drilling programs. We have a strong track record of successfully executing on both of those. Now on to what everyone wants to talk about the most, the unconventionals. On the next set of slides, I am 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 three key takeaways. First, our unconventional 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. Second, we have many years of additional inventory and running room in our mature plays.
Third, we have the potential to add significant resource in our less mature plays. Our North American unconventional assets are focused in the areas shown on the map on the right. On the left, you can see where these unconventional assets fit into our corporate cost of supply curve. Today, this represents 7 billion barrels with a less than $35 a barrel average cost of supply. 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&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. 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 am talking about in the technology area on the next few slides. I am 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. Even with lower rig and activity levels, we never stop 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. 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. By the way, it's not a one-size-fits-all kind of situation. We understand what works best in the many different sub-plays that we have across our acreage. This has allowed us to increase our Eagle Ford EUR from 2.5 billion to 3 billion barrels, a 20% increase from just last year. 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 2.4 billion 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 has left for the Permian. That makes our contracting easier and improves our netbacks. 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 five rigs there in 2017. As part of the transformation of our business that lets us thrive at lower prices, we've been driving the Uberization of the oil field. 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 five percentage points, and we've driven down our lifting cost to below $2 a barrel.
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. 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 two 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. 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 at 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 five 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 four different colors represent distinct producing zones, two 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. What all this tells you is that when you're not just chasing rate, you can 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 half a billion barrels to our Eagle Ford resource base since last year from these kinds of advancements. From day one, 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 the pace of improvement has 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 wells 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. 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. You could 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 this acreage before running a lot of rigs has been in stark contrast to many of our competitors. That's the picture this slide tells.
It makes two key points. First, we are obviously in the heart of the play where others have been drilling aggressively all around us. 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 multi-year 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 is 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 is below $25 a barrel.
That is about a mid-teens after-tax cost of supply on a single well basis that others often quote. That is truly a best-in-class play. Don't take our word for it. Here is the chart I show you every year from the three 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. It is not hard to see why ConocoPhillips is still actively pursuing the Eagle Ford and has plans for many years of profitable drilling here. These days, everyone wants to talk about the Permian Basin. Let us take a closer look at our position there. In the Permian, we are applying our normal discipline returns-focused approach to appraise and develop our acreage. We expect to be running between one and two rigs there in 2017.
We have about 1 million acres across the Permian Basin, broken into the three areas shown on the map. I am 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 are only carrying about 300 million barrels in our unconventional resource for this acreage in our low cost of supply curve. We see potential for significant growth as we are 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 is held by production. While we are evaluating our unconventional potential using our latest technology and tools, we have also been putting our unconventional technology to work in our conventional developments here.
For example, in the Central Basin Platform, we had a five-well pilot program this year to test out our unconventional technology in the Wichita Albany formation. These wells outperformed our expectations, and they have paid out in just 10 months, even in a low-price environment. We plan to drill more of these kind of wells in 2017. We also have another pilot program plan 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. I will discuss them in a bit more detail next.
We've worked to core up our acreage in the two 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 six-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. With the progress that we've made here so far, we've increased our resource base for the Delaware from 1 billion barrels last year to $1.8 billion barrels this year, and it averages a cost of supply that's less than $40 a barrel for that $1.8 billion barrels.
Almost all of the resource that we're counting here in this $1.8 billion barrels is just in the Wolfcamp, 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% where you're able to do them. We've also reduced our completion cost by about 50% since 2014. We currently estimate we've got 1,400 drilling locations with an average fully burdened cost of supply that's less than $40 a barrel. Next, let's look at the Bakken, where we have an interesting new development that's hot off the presses. First, the basic stats. We've got about 600,000 net acres here with about 700 million 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 cost by about 45% since 2014, and the third-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 can 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. Very recently, we've 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. For you reservoir engineers out there, this is a plot of productivity index versus cumulative 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. We'll be adding rigs here, and we currently plan to run four rigs in 2017 in the Bakken. Let's move a little further north next. In Western Canada, we have over 3 million 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 billion 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, so 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 Falher-Wilrich, and we are 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 two 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 five-month cumulative production levels that are above both the upper and lower Eagle Ford reservoirs in the same area. The Austin Chalk clearly presents some upside across parts of the Eagle Ford acreage. We plan to drill some more of these wells also in 2017. In addition, we have two significant acreage positions that we're testing in South America, in Colombia and in Chile. We've got appraisal activity planned in both places in 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 billion barrels in last year's resource base to 7 billion 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 billion barrels that's 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 three Lower 48 unconventional areas that are listed. It shows our current estimate of the three-year production compound annual growth rate that would result for these three areas with differing numbers of rigs running. 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 six rigs, half as many rigs. 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 $4.5 billion of CapEx per year. To summarize the value of our robust unconventional asset class, it provides our most flexible and some of our lowest cost of supply resources in the company. It's been built into an enviable position through leading unconventional technologies that are applied to maximize value. That wraps up our tour of the three 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 $9.7 billion in 2014 to a planned $6 billion next year, and we can hold our production flat now for years at a time for CapEx of $4.5 billion a year. That's half the $9 billion that we quoted you at last year's meeting. Our flexible portfolio allows us to deliver our value proposition with low execution risk and through the cycles.
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. Good job, Matt.
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 the strategic flexibility to consistently deliver returns in an uncertain future. I'm going to start where Al left off with the cost of supply. I brought myself an extra one just in case. I'm going to start where Al 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. I know you've all been wondering, how does this cost of supply metric translate into returns? Here's the decoder ring. It has cost of supply on the X-axis and returns on the Y-axis.
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. In fact, for the next five 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 and $60 a barrel. You can see that the $50 a barrel line crosses the $50 cost of supply at a 10% return, and that's a good thing because that's the definition of cost of supply. Much more importantly, it crosses the red dashed line, the average cost of supply of our investments at 30%.
If prices average $50 a barrel over the next five 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. I know you hear people making claims about returns based on well site economics, and I know that you know that these are not very useful pieces of information because they don't reflect corporate returns. Because these returns are fully burdened, they do reflect how corporate returns will change over time with this level of return at the individual annual capital programs. That's why this portfolio is so valuable to a returns-focused company. 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 $4.5 billion a year. 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 five years. I'll start with the cost of supply stacked bar 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, we're going to finish those projects, 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 multi-year 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. 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. Those commitments are balanced by close to half of our capital being flexible. Much of that, although not exclusively, focused in the North American unconventionals. Part of that flexible capital is exploration.
Since our decision to exit deep water, 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. We've designed this strategy with off-ramps so that it's a flexible exploration strategy. That's a lot of flexibility. 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. That means we have to embrace uncertainty. 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.
Everybody knows that one of the most important characteristics of a scenario name is alliteration. 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. There's been some relenting over the last few years, but 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 four. Robust recovery is self-explanatory. Strong demand growth requires higher marginal supply cost production like deep water.
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. Because we describe 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. We've identified more than 150 indicators that we monitor. We have subject matter experts who 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.
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. We find the scenario planning process to be much more insightful than trying to explicitly predict price. 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. Let's test some of these scenarios to see how resilient our strategy is.
I'll start by using these three cases, $50, $60, and $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&P company's 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 they are, priorities one through five. First, a $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 billion debt target by the end of 2019. Through a growing ordinary dividend and the share buyback program we announced today, at $50 a barrel, we actually pay out more than the 30% of our cash from operations to distributions to shareholders.
We limit our capital to $5 billion every year. 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% and 10%, towards the top end of that range. In a $60 a barrel price environment, we achieve the first three priorities. 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%-15%. In a $70 a barrel case, we have the same opportunities. Now we can deliver 15%-20% compound annual growth in returns when we combine the debt-adjusted production growth per share with the margin growth and the dividend yield.
One of the strengths of a strategy with embedded flexibility is that we'll have choices to make as the macro environment evolves. 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. As Ryan said earlier, they're not mutually exclusive.
For example, you'll notice in this $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. It's likely that if we find ourself 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 one. This is one example of how a cycle might play out over the next five years. In this case, prices are $50 a barrel next year. They recover to $65 in 2018, $75 in 2019. Then crash to $40 a barrel in 2020. Modestly recover to $50 a barrel by 2021.
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 billion by the end of 2019, grow our dividend, and distribute additional cash to shareholders through buybacks. 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.
This illustrates a key characteristic of our strategy that 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%-30% range. In fact, in this scenario, we're doing that in years one, years four, and years five. 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. We have literally dozens of cases like this that we run in our strategy simulator, this is a very robust strategy across multiple types of cycles. 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, we don't know how governments will behave. As we navigate these uncertainties, management judgment is still important. 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? How will we exercise strategic flexibility to maximize value? 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. Rather than show more cases, here's a summary of what you should expect in the next three 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. They're cash from operations, cash on hand, and proceeds from dispositions.
First use of cash is to maintain our production. This takes about $4.5 billion a year. We pay the current dividend and increase the dividend each year. Over these three years, we'll retire $7 billion of debt to get us down to our $20 billion target. In parallel, we'll execute the $3 billion stock buyback program. 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. If prices are above $50 a barrel, we'll allocate the free cash flow based on the decision criteria I discussed earlier. 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&P company designed to deliver disciplined returns through the cycles.
Just to put that transformation in context, have a look at this. 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 has shifted in a positive direction. From a financial perspective, we've changed our breakeven price from over $75 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 billion, which is $3 billion less than we had at the time of the spin. 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. We have a massive resource base that includes over 18 billion barrels with an average fully burdened cost of supply of less than $40 a barrel. I'm not sure if Al mentioned that earlier. From a strategic flexibility perspective, we have a much more flexible capital program now with no mega projects, and we're 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. 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. We're focused on improving relative and absolute returns, not absolute growth. We're accelerating this strategy with $5 billion-$8 billion of dispositions over the next two years that will continue to focus the portfolio.
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. 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. You guys have been patient, so let me just wrap up really, really quickly for you, and then we'll get to your questions. Hopefully what you've seen today is we've dramatically transformed our company. We've lowered the break-even 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 $5 billion-$8 billion disposition program and a $3 billion share repurchase program. Finally, I think we're differentiating ourselves. We're differentiating ourselves from other E&Ps with a flexible, low cost of supply resource base. We are an E&P company that's going to be disciplined and really focused on returns. Thank you for your attention. We'll take your questions.
Sid and Vlad will be kind of on each half of the room here a little bit. 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. Please raise your hand and give us your company name, and we'll go from there. Go ahead, 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. On this point, when considering 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? If so, what should they be? It might be too early to think about that, and that's a springtime item, but how are you thinking about that?
No. Thanks, Doug. Yeah. No, absolutely. We've had a longstanding, both in terms of our short-term incentive programs and our longer-term incentive programs. We have them tied to total shareholder return. We have them tied to total return on capital employed and cash return on capital employed. That sits in both for me and all my top executives, and in fact, our short-term program is ubiquitous across the whole organization. It includes operating results like are 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. We look at all those three absolutely and relative performance on all three of those measures.
Those are the ones you like in the future too, Ryan?
Yeah, I think we're playing with debt-adjusted per share metrics as well.
Sure.
We're thinking about that as a possible metric as well.
Okay.
It takes a lot longer time for that to materialize, but it shows a very high correlation to performance.
Great. Thanks.
Yeah. Over here. I'm just going to go between the guys.
Yeah, thanks. It's Jason Gammel with Jefferies.
Hi, Jason.
I just wanted to ask about how to think about the share repurchase program relative to debt repayment. It was pretty clear that simply paying off maturities was how you were going to handle debt. 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 investment proceeds?
Yeah. 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. 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, that comes before share buybacks. Don can address, I think, maybe the specifics around how we're thinking about it.
Yeah, Jason. I think history kind of shows that market timing approaches don't generally work out real well sometimes for companies. Our approach is probably going to be more of a cost averaging. 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. You'll obviously see them in our financial disclosures.
All right. Here, Doug.
Thanks, Ryan. It's Doug Leggate from Bank of America. Two questions, if I may. The first one of the perhaps the obvious things that's missing from your use of cash are acquisitions, 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 the range of growth options that you've laid out, just committing to short cycle from the existing portfolio without damaging portfolio integrity?
I can let Al chime in here as well, Doug, 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-
That's exactly right. If you look at that cost supply curve I showed you, the kind of stack of the three different asset classes where we do have 800,000 barrels a day of our roughly 1.5 million barrels a day production today 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. 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 billion barrels that are out to the right because they're above $50 right now. Some of those are at $51. There's a lot of stuff in $50-$60 that obviously we expect to continue improving that. Particularly in the unconventional where you see 7 billion 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.
Doug,
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. With the portfolio that we have, we don't have to run really hard on that treadmill. It's $4.5 billion to maintain flat production. We can do that for a decade.
Maybe a simple way of summarizing the answer, Ryan, what happens to reserve replacement over the next five years?
Yeah. Again, I'm not worried about it. The macro 18 billion 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. It will be lumpy. With 18 billion barrels, it's going to move into reserves over the course of time as we execute this plan, doesn't give me a concern about reserve replacement. Matt can share with you the details.
Yes, in any given year, our reserves replacement ratio is going to vary. We expect over the first five 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 Surmont or the backfill for Darwin LNG, we're likely to be above 100%. In the years where we're not sanctioning those sort of projects, we're likely to be below 100%. 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. Our RTP ratio just now, reserves to production ratio, is about 14 years. That's higher than most of the competition, including the integrated companies.
If over time that RTP ratio comes down a little bit, that's fine. We're not too concerned about that.
In fact, you should want that.
Yeah.
You should want us to get that down a little bit.
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.
Wherever you are.
Phil Gresh, JP Morgan. 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. I was hoping you could elaborate a little bit more. You obviously talked about natural gas as one of the target assets, 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 billion of CFO in 2019 at $60. Is that post-asset sales? How much cash flow goes away with the asset sales under your assumptions?
You want to take that one, Matt?
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. When I mentioned, I think you're getting that from the 2 times leverage in 2019. That would imply about $10 billion, and we think we're capable of doing that in that timeframe. That's ex dispositions. Any cash flows from the dispositions that we have would come out of that. We cannot 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. 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.
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. You can use North American natural gas metrics and zero in probably on what volumes and cash flows that might represent.
Okay, thanks. 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're kind of at the low end of that range. Maybe just walk us through how you manage a mid-40s type of scenario if we see it repeat again in 2017.
Well, I think that's the beauty of the priorities that we've laid out is just start to take them in reverse order. If we're in a sub $50 world or a $45 world, we've just shown you we've got a half a billion 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 expiration 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. You just work backwards, and if it's even worse, we may not accelerate some of the debt repayment if you found yourself in that period long term.
I think that's the beauty of the flexibility that we've created in the portfolio. I would take the priorities in an up world, I would reverse them in a down world. Over here, Ed.
Yeah. Ed Westlake. Maybe a follow on the disposals. 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, do you think the market is actually large enough and obviously to absorb the sales?
Yeah. Matt's managing that process, let me let him.
Yeah. I think the assets that we're marketing, we know there's a lot of interest in. We feel pretty confident that we'll be able to execute this disposition program. We're not going to sell these assets unless we get full value. There's a lot of interest in the types of assets that we are likely to market.
follow 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. 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 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. 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 billion barrels across our corporate cost of supply and have those numbers be fixed at roughly the low point in the cost cycle where we are now. 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. The most sensitive to that, the parts of our portfolio affected the most was the Lower 48 unconventional.
Those are the ones who cost of supply went up the most from doing that. Also, ForEx is a significant factor in a lot of our overseas locations. We also put that in for a $65 world. I touched on it some there. Lots of different new technologies that we're working on that are driving down the structural side of the costs. That work, of course, is continuing. I don't see any slowdown in that.
Go over here, Paul.
Paul Cheng, Barclays. Ryan, a few 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. If asset sales slow down or they drag out or we reach a lower end of that range that we've decided, start with our fifth priority and work yourself backwards, that's how we're going to manage the system to the cash flows that we have.
Okay. Second question. 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, 5-10 years without stretching your organization?
Well, Al can speak maybe more to that specifically, too. Let me give you a high-level view in my words around it. 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. That's a very disciplined capital program. That's not reinflating or going back up. We feel like we have the organizational capacity and we've kept that because we've resized the organization to fit that capacity. I think as Al probably pointed out, we do think there's scope to grow in terms of the resource base that we do have, we've got the capacity in place right today. It's not just to manage three or four or five 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 if you think about the chart that Matt showed where he had the price cycle, 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. You saw some capital growth in there. If you look at that chart, you'll get an idea of it. 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 much we could grow the Bakken and the Permian and the Eagle Ford, those 3 areas with different numbers of rigs.
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.
Follow on that. If we're looking at after you spend a $1 billion in the maintenance CapEx, what's the underlying decline curve on the base operation? Thank you.
The underlying decline, it varies in different years. It's generally in the 8%-10% range unmitigated. As some of the APLNG and Surmont Two, 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. As we move later out in time and increase the amount of our capital going to unconventional, it'll drive it back in the higher direction. In that range is a pretty good range.
All right, Neil here.
Thanks, Ryan, I appreciate that you fully burdened the cost of supply work. I thought that was very insightful. Curious for both you and for Matt how this work influenced your view of the oil macro, given how low the cost of supply curve looks for ConocoPhillips. Does it change the way you think about ultimately the equilibrium price for oil? I have a follow-up.
Yeah, Matt, go ahead.
Yeah. As we look at these scenarios and assess the probability, that's one of the things that's guided us towards if you're going to be successful in a world of lower, more volatile prices, which is what we expect, then you have to have a low break-even, you have to have a low cost of supply, you have to have flexibility, and you need to be disciplined. That's what we've designed our strategy to do, it has been guided very much by the way that we see the future unfolding.
I worry, Neil, I don't think everybody else in the E&P world has the same discipline. I think that informs, just reinforces our view of concerns around the macro and concerns that it is a well-supplied world. 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. 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 at different levels?
Yeah, I think let Al chime in as well here. No, each one of the plays have a spread across the supply curve, and each play has very low up to the $50. It 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 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. One of the things we've done over the past year plus is put a lot more granularity in that. Each of our unconventional areas, I talked earlier about those different subplays and how we optimize the spacing and stacking completion designs differently across those. Each one of those is a separate data point basically, and that cost of supply curve. That's given us a lot of interesting insights. There is a fair amount of variability. The Eagle Ford is not all one thing. It's got a lot of variability in it.
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. You see pieces of all those plays further to the right on our cost of supply curve also.
Oh, sorry.
Go ahead.
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. It is not that simple, but that is how we are 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. How do you think about the pace of dividend growth in terms of something we should think of going forward? Is targeting a dividend yield that's effectively in line with S&P average, is that enough? Does it distinguish itself enough versus your peers? 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?
Yeah, I think it's a good question. We're not trying to target a yield or something like that. 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. We also wanted to get it at a level that we knew we could grow it annually. Our intention is not to get back as fast as we can to $3.7 billion worth of dividend payment that we had, say last year. Growing it annually is a very important part of the offering we think we have to the market. 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. As we've laid it out, that is our second priority. Our second biggest priority is to grow it annually. You should expect that from us. 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? You should look at us to be growing it annually.
Thanks. 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? How much benefit is there, I guess, to economies of scale within the basin? If we look at your positions, 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? Would you consider yourself to be a consolidator? How would you think about the pluses and minuses.
You want to take that?
of your operations? Yeah, I think 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 a 10,000-foot lateral versus a 5,000-foot in a typical unconventional development adds about 30% to your NPV. That's one thing you're really after as you try to core up in those areas. We've kind of developed a bit of a concept of a minimum efficient unit size. When you're running just one or two rigs, it is inefficient relative to how many frack crews you need and that sort of thing. What you see us running once we're into manufacturing mode and running more rigs, 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 frack crews and allow you to have economies of scale and move efficiently. Those are the two places where we're in that mode. 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.
We give our people, we call it affectionately knife fighting money. 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're doing that in the Midland Basin and in the Delaware Basin and the Permian. We're doing that in the Eagle Ford every day. 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
Thank you. 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. secondly, that you're an E&P that is a dividend and buyback or a 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 it, if Eagle Ford is your focus. secondly, can these unconventional businesses actually be run for free cash flow and dividend? Wouldn't you be better maybe splitting the whole unconventional business off into its own growth model and leaving the cash return hub run?
I think it's amazing. Let me take the first one. We do get a lot of questions about the Permian. 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. We're going to make sure we figure out how to go do it. It's compelling. It's a 1.8 billion 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 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. We've got a 1.8 billion barrel position. We know how to monetize it. The NPV of the learning curve dramatically exceeds the NPV of acceleration. When 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. You talk about the spin. 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. 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. Those companies are actually trying to get more unconventional and conventional opportunities. 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. 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 1 billion barrels there that we thought we could develop below $50 a barrel. If I were trying to sell that acreage last year, that's what would've been in my data room. Here, just a year later, it's increased 80%, and that's just the Wolfcamp up to 1.8 billion barrels that's below $50 cutoff. What do you think is going to happen next year or the year after? There's a lot of growth that's going to come there. It's obvious. Why would I sell that before I understand all that? You're selling it cheap if you do that.
Over here. Thanks.
Asit Sharma, CLSA. Two questions. First, on APLNG cost of supply, less than $30 a barrel. Surmont, less than $40. Pretty impressive. Could you talk about cash margin per BOE at a $40, $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.
Do you want to take that?
Go ahead.
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 Qatargas 3, et cetera. If you think about the newer pieces that people have been trying to understand in APLNG and Surmont, FCCL, those pieces. If you take the two 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. At around $50 is when we expect both FCCL and APLNG would send cash back to the shareholders. 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, of course, it goes up rapidly as prices go up from there.
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 flow sensitivities, as Al said, we're expecting that as oil prices approach $50 and beyond, they would start contemplating distributions. Those sensitivities will show you the slope of how cash is moving with price.
That's helpful. Second question. Al, on the Delaware Basin, 1,400 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, a per BOE number? I mean, you broadly talk about cost of supply. How does it adjust for gas mix?
Yeah. 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. When you see these numbers in the gasier plays that are adjusted to Brent, it's done that way on a value basis. 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. That's how we're able to quote. It is an BOE cost of supply. 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.
Thank you. Let's go back there.
Yes. Scott Hanold from RBC. 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? Specifically with what you see right now, and how that might change, how quickly can you adjust your budget? How sustainable do those signals need to be to say, "We're going to put in five 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, on how reliable have those scenarios been and the probabilities associated with those scenarios been. We started this scenario process in 2012. The highest probability scenario at that time 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 a 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, that's not going to be good for us. It's not that we knew with absolute certainty that that's the scenario that was going to evolve, because you never know with absolute certainty how things are going to evolve.
It very much was in our mind as we embarked upon this transformation journey to get to a place with lower break even, with a lower cost of supply, and more flexibility. It has been helpful from guiding the way that we've behaved over the last five years.
And since-
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. 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 price.
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. 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. 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, $110, I think, in 2012. That kind of illustrates that it's not a perfect system like Matt said, but it does give you a lot of insights.
It does one other thing, too. It gives you no regrets decisions. 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?" It gives you a certain level of decisions that says, "I wouldn't regret doing these under any scenario we might find." I'd take you back to the end of 2014. Our company got a lot of criticism. We took capital from about $17 billion down to 11. People were thinking it was going to be a V-shaped recovery coming out of the recession. We got a lot of people commenting about you're overreacting.
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." In fact, looking back on it, if you ask me what we should have done differently, we should have taken it down even harder and faster because we were starting to build the flexibility of the company to be able to do that. At this spin, we were executing eight mega billion-dollar projects in parallel, and we didn't have the flexibility, and that's what frightened us with that scenario. Over here. Doug.
Hi, John from SocGen. For a more shorter cycle-driven business model, is it time to hedge or will a lower leverage balance sheet be your hedge?
Don.
Yeah. 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 in a constructive way. 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. 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 a strong balance sheet.
Okay. Next question. With the sale of the natural gas reserves or assets in North America, are you finally going to break even on a profitability basis in Canada and the U.S. in a $50 world?
Would we be break even on a cash basis or an income basis?
Net income.
Net income basis. That'd probably still be a bit of a stretch on a net income basis, but we're getting close. Okay.
Guy Baber, Simmons & Company. Thank you guys very much for all the detail today. Very much appreciated. It appears that the 18 billion barrels of low-cost resource base is more of a focus for you than the 8 billion barrels or so of proved reserves. Have F&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&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. Then just to confirm, are the spending plans you've highlighted, that's sufficient to hold that 18 billion barrel resource base flattish to growing despite the fact that your 1P reserves might decline a little bit?
Yeah. You want to take that?
On the F&D math, 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&D insight into that, if we were just to sustain flat production and spend $5 billion a year, which is actually a bit more than flat production, you do the math on that, just direct math on that would imply an F&D cost of less than $10 a barrel. That's pretty impressive if it's real, and it is real. There are two reasons why that's showing up. One 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 we'll be drilling in the next 5 years will be somewhere between 900,000 and 1 million barrels of resource reserves associated with it once it's on the books. Fully loaded, including tying into our existing infrastructure, it'll probably cost $6 million, $6.5 million. The F&D in Eagle Ford is somewhere between $6 and $6.50. If you go to our more conventional projects and you use an example like in Norway, Al mentioned the Tor II or the Tor redevelopment. That's about 20 billion barrels net. It's about a $240 million project, so about $12. When you put the-- there's other examples all around the portfolio, China and-
20 million barrels.
20.
Million.
Million barrels.
Not billion.
Yeah. 20 million barrels and $240 million. About $12 a barrel F&D. As you go around the portfolio and you average it, you get to a place that's $10 a barrel. That's an F&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. On a GAAP basis, it's only half a billion dollars a year to keep it flat. Even on a PC basis, that only adds about $800 million a year. Even if you do this F&D math on a PC basis, you're only at $11 a barrel of F&D. It's all about the shift to the low cost of supply. That's where we're putting the money.
Over time, we'd expect to be around 100%, and it is a very low F&D.
That's very helpful. You guys also gave some helpful charts in the back that show production by region, expecting a decline in the Lower 48, which I guess should be expected here. Can you talk about, as you're going from three to eight rigs, some of the lag times associated with arresting that decline and then getting back into a growth mode? 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 that that's giving for you?
Sure. I guess, first, if you look at the three rigs we ran most of the year, I talked on the 3Q call about being at eight by the end of the year. If you added up all the rigs I talked about during the other talk, you could see that we expect to get up to around 12 next year, although it'll build over time. The average number of rigs in 2017 in our current plan is more like 11. With that kind of program that you get at this $5 billion capital level, we would expect our Lower 48 unconventional year-over-year 2016 to 2017 to decline about 6%, 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, plug in however many rigs you want to, you get the answer. Until it gets better again.
You're right. The profile does sort of dip because we're going through three rigs, we'll dip early in the year, we start to recover, come back out of that.
The second part of your question about 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. What we've found is that there are suppliers that are in that area that don't want to leave, and that are out of business. 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. 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 to keep it flexible for us.
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.
Al mentioned it briefly. He talked about the netback. Everybody built export facilities, and there's refineries on the Gulf Coast now that are tuned up to condensate, and they see the condensate dropping. You get netback realizations too. 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. 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. Whether it's DAPL or it's Keystone or it's more product up to the East Coast and all that. I would certainly hope that the way we think about infrastructure in the U.S. 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. 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.
I think just generally recognition of what jobs and improvements to the economy this industry makes. Now we're going through a 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 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. I think that's where we can play in that.
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 to just 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. 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. If we do get some change in the pace of that regulatory, that'll 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. 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 exposed to the 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. 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, we will be exposed to that kind of stuff.
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. 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 heard today, hopefully, is our value proposition, you understand it, how it's going to go into action, how we're a company that's going to be managing free cash flow and managing returns. 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.