Devon Energy Corporation (NYSE:DVN)
2012 Analyst Day
April 04, 2012 9:00 am ET
Vincent W. White - Senior Vice President of Investor Relations
John Richels - Chief Executive Officer, President and Director
David A. Hager - Executive Vice President of Exploration & Production
Andy Coolidge -
Chris Seasons - President of Devon Canada
Darryl G. Smette - Executive Vice President of Marketing & Midstream
Jeffrey A. Agosta - Chief Financial Officer and Executive Vice President
Bradley A. Foster - Senior Vice President of Mid-Continent Division
Kris Goforth -
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Scott Hanold - RBC Capital Markets, LLC, Research Division
Michael Kelly - Global Hunter Securities, LLC, Research Division
David R. Tameron - Wells Fargo Securities, LLC, Research Division
Irene O. Haas - Wunderlich Securities Inc., Research Division
Marshall H. Carver - Capital One Southcoast, Inc., Research Division
Vincent W. White
Good morning, everyone. Welcome to Devon's 2012 Analyst Day. We got a lot of ground to cover, so I'm going to jump right into it.
First, I've got a few introductory remarks, and then our President and CEO, John Richels, will give the big picture strategy and our multiyear outlook. He'll be followed by Executive Vice President of Exploration and Production, Dave Hager, who will present our E&P overview and also drill down on the new ventures that we've been working on. We'll then have a Q&A session and a break. We'll come back and have detailed reviews of our Permian and thermal oil assets, a second Q&A session and break after that. And we will wrap up with a discussion of our cornerstone shale plays: the Barnett Shale and the Cana Shale.
I want to point out that, for those of you that are interested in this kind of thing, there are type curves of all the key development assets in the Appendix of the book in front of you.
In addition to the speakers that we are going to introduce as they come up today, we've got a number of members of the Devon team I want to introduce. And I'll ask you guys to stand. A lot of these folks, you've talked to on the phone but you've never seen. That's -- the exception is the first one that I'm going to introduce, our Executive Chairman, Larry Nichols, most of you know him. We also have one other director with us, Duane Radtke. Where are you, Duane? There he is. Darryl Smette, who is the Head of our Marketing and Midstream Group, is with us, as well as our CFO, Jeff Agosta. Head of our new ventures group, Tony Vaughn, and head of planning, Mark Harmon. Where are you, Mark?
Also, there's a number of members of the Devon IR Team: Shea Snyder, back here in the corner; Scott Coody; and Brent Rockwood, his last week with us in investor relations, he's moving to another department of the company. We're sad to see him go. And then the young ladies that are helping us out with logistics, Sheree Russell, who I guess is out in the lobby; and a member, a professional from our corporate communications team that came along to help, Alesha Leemaster. So thanks to all those folks.
Today, we're going to present a number of 5-year forecast. And I just want to call your attention to the assumptions that underlie these forecasts. First of all, we're using strip pricing as of a couple of weeks ago and we rounded it for convenience, shown here. We assume that NGLs -- the NGL benchmark trades at 47% of WTI over this time period. We hold the current cost environment constant, and we continue to pay dividends at the current rate. We also assume that we close the Sinopec JV that was previously announced. We expect to close that in the very near future and that we enter into a second JV in 2013 that's about half the magnitude of the Sinopec deal. Based on those assumptions, we'll utilize about $1.5 billion of our cash balances through 2016.
And I just want to point out, this is the capital profile that supports that and it ranges from a little over $6 billion in the early years to almost $8 billion in 2016. This is E&P capital. You may notice that the 2012 capital is up about $1 billion from what we talked about in our year-end call. We mentioned at that time that we were working on some incremental light oil plays, new venture plays and that, if we were successful, it would -- those acreage acquisitions would be over and above that budget. We're going to show you today that we have had some considerable success in those new ventures, and we also are budgeting based on our expectations of future success in leasing in those plays.
It's important to note that this plan that we're going to unveil today really is based on the existing assets and what we see in our portfolio today, and we fully expect to uncover incremental opportunities as we go forward. So it's very likely that, over the next 5 years, we will have incremental opportunities to invest at high rates of return and that we will utilize more of our existing cash balances than presented in this forecast.
With those items out of the way -- oh, one other thing, I'm obligated to tell you guys that we're -- as I just said, we're going to make a number of forecast and projections in today's presentation. Anytime we do that, we would try to give you the very best data possible, but we always run the risk that our actual results will vary from our forecast. And for an exhaustive discussion of that, you can see the risk factors discussion in your presentation booklet today or our various filings with the SEC.
With those items out of the way, I'll turn it over to our President and CEO, John Richels.
Well, thank you, Vince, and let me add my welcome as well. Thanks to all of you for making the trek out here and visiting with us, spending so much time with us today. And welcome to the folks that are tuning in on the webcast, as well. Now I see an awful lot of familiar faces in the crowd, so most of you are fairly familiar with Devon. But let me just, for those of you who might not be quite as familiar, let me just give you the 50,000-foot view.
We're one of the larger U.S.-based independents, as you're -- as you know. We've got just over 3 billion barrels of proved reserves at year-end 2011. That's about 42% oil and liquids. And we're currently producing just under 700,000 barrels per day. And with the current high oil and liquids prices, our liquids revenue actually accounts for more than 80% of our total E&P sales. We also have a strategic midstream presence, a real important part of our business that, in 2011, threw off almost $550 million of operating profit.
So as many of you know, over the last couple of years, we have fundamentally changed the focus of the company and repositioned Devon as strictly a North American onshore player by divesting of our Gulf of Mexico and our international properties. And those divestitures were completed in June of 2011 with the sale of our Brazil assets to BP. So today, what we're going to show you is the tremendous opportunities that we have at Devon, what the future looks like. We're going to give you an awful lot of information about the company, and we hope that you walk out of this presentation as confident and as bullish about the future as the rest of us are and all of us here in the company are. And specifically, we hope that you'll leave with an understanding of the following key points.
First of all, we're a value-focused company. We're committed to delivering top-quartile per share results. And we understand that, in order to do that, we need to have very strong full cycle returns, and we have that and you're going to see a lot of information about that today.
We're a company with a very deep inventory of opportunities that work in spite of the commodity price and cost challenges that face this industry. And we have very highly visible oil and liquids growth. Our assets delivered about 20% growth in oil and liquids in 2011. And we're going to be able to continue to do that and show very strong oil and liquids growth as we move into the future.
And in addition to the strong development portfolio, we have a lot of upside from a very exciting suite of exploration prospects, and we're continuing to add to them all the time. And Dave is going to talk a lot about that here in a few minutes. And finally, this is really important: We've got the balance sheet and we got the financial strength and the flexibility to develop those assets.
So these characteristics all support our strategic objective, which is of an objective to maximize long-term value for shareholders by growing cash flow per share adjusted for debt. We've done a lot of work on this area, and some of you, we've had discussions about this in the future. We've done a lot of work over time and we found that there is a very, very high correlation. A lot of you are financial folks, you understand this very well, it's an R-squared above 90%, and my limited knowledge of -- or memory of statistics says that's pretty good. And so that is a very, very high correlation between growing cash flow per share, adjusted per debt, and stock price. And it's not surprising that debt-adjusted share growth is key because, of course, the only way we can create value for shareholders is by growing that cash flow stream of -- without, at the same time, pushing a bunch of debt and equity out the door.
So that's what we're focused on. And we've always paid attention to our balance sheet. We've been very stingy with our equity over time. In fact, it's interesting, the last marketed equity transaction that we did at Devon was in 1999, following our PennzEnergy transaction. So that's the focus of the company. That's what we -- the metrics that we use and that's what we make our decisions on.
The way we execute on that strategic objective is, first of all, by exercising strong capital discipline and allocating our capital in a way that can actually make money for our shareholders and drive shareholder value. And we do that by maximizing our operating margins, by investing in high-return projects and maintaining a low-cost structure. I think most of you that know us know that, for years, we've been a company that's had a very low-cost structure. We spend a lot of time on it. We have a lot of focus on that because we understand that investing in high-return projects and keeping the costs down will drive that margin.
We try to leverage the strong midstream operations that we have both to ensure that we don't strand the E&P capital. And that will -- if you strand that capital, of course, you destroy your returns, so we try not to strand the E&P capital and also to help us improve our overall corporate performance. And we preserve our financial strength to allow us to invest through all portions of the commodity price cycles, and all of us know that this is a cyclical business. And by preserving our financial strength, it also allows us to be nimble and to quickly react to changes in commodity prices, to industry costs and to other industry conditions. In fact, capital allocation is the most important thing that we do from the point of view of influencing shareholder value. And as we think about capital allocation, we try to stay very objective in our allocation alternatives between E&P capital projects, debt reduction and share repurchases.
We've been very fortunate over the years to be able to do a lot of each. We've funded very robust E&P projects, and at the same time, we've reduced our debt to the point where we have one of the strongest balance sheets in the industry. And we have -- we bought back more shares and have reduced our share count more than any other independent in this E&P sector.
In this business, it's very easy to think that all you ever ought to do is invest in your E&P projects. And when times are right, that's true, but we've tried to be very dispassionate in that analysis and make sure that, always, we're investing our capital in a way that's going to drive cash flow per debt-adjusted share among those various alternatives. And while we've been funding very robust E&P programs, reducing our debt and buying back an awful lot of stock, we've also been able to increase our dividend almost every year since 2004. And it's our intention to continue to increase our dividends in the future.
With our focus on value, we generate very strong full cycle returns driven by a deep resource base and which has a large component of organically generated growth projects. So what we try to do is we try to pick our positions as a first mover or an early mover to give us low acreage costs and low royalties. Those are both very, very important, of course, in the economics. People sometimes don't think that much about royalties. That's really important because it's never a sunk cost. Those royalties stay with you until the last drop of oil or the last Mcf of gas that you've produced. And it's expensive: You're paying the royalty holders costs and then give them, the royalty holder, a piece of production. So we try to keep our acreage costs down, try to keep the royalties down. We build large concentrated positions because we understand that scale breeds efficiency. We see that in the Barnett Shale, we saw it in Cana. Wherever you can get in and do things on a large-scale basis, you drive the efficiencies.
I think we've done a very good job over the years of high-grading our portfolio, so that means not only adding high-value positions and adding new opportunities but also taking assets that might one -- at one point have been good assets but move them out when they're not providing the kinds of returns that we want to see in our portfolio. In fact, we have sold about $17 billion of properties over the last 10 years, continually try to high-grade our asset base and have an asset base today that we're very, very confident and excited about. And as I said, we try to -- generally try to develop a strong midstream presence in our key plays, which allows us not only to create and capture additional value but also improves our effectiveness as a company by giving us some very valuable insights into the markets.
When you look at Devon today, following the repositioning, as I said, we are a company focused solely in North America onshore both in the Lower 48 and Canada. And I think you can see we've done a very good job in that arena for many, many years. The graphs on this slide show the results from our North American onshore operations from 2006 through 2011. And what you can see is that we've delivered very competitive production growth through that period and we've had highly competitive lease operating expenses, drill-bit replacement -- reserve replacement and drill-bit F&D through that period of time. And I will point out to you that, for a good chunk of that time, actually, all the way through 2009, we were investing large amounts of money in our offshore operations that were being fueled by revenues from onshore operations because they didn't have a lot of production attached to them. So that gives us a lot of confidence of what we can do in the future when you see that kind of performance in the past and while we were investing in a lot of non-cash flow and non-production creating assets.
As I mentioned a couple of times, our performance is enhanced by our strong midstream presence. In fact, we're one of the largest gatherers and processors of natural gas in North America. We have an ownership in about 15,000 miles of pipes and we have an ownership interest in 64 plants in the United States and Canada. Really importantly, you've seen that blue box down in the corner of that map, we also have an interest, almost a 40% interest in Gulf Coast fractionators, which is a large fractionation facility in Mont Belvieu. That's a very strategic asset for us. It not only aids in the marketing of our -- and the processing of our natural gas liquids but gives us an awful lot of insight into those markets. And as I already mentioned that, in 2011, that business generated around $540 million in operating profits. And just let me put that into perspective: In 2011, we produced about 240 million barrels, so $540 million of operating profit generated $2.25 of additional netback to Devon. So it's a very, very lucrative and profitable business for us, an important part of the company.
As I alluded to earlier, we've accomplished our strong operational performance without compromising our financial strength and flexibility. In fact, we have one of the strongest balance sheets in this sector. We've got a net debt-to-cap ratio of about 11%. What that's made up of is about $10 billion of debt and about $7 billion of cash, much of that held offshore right now as a result. It came from our international sales of the international assets, and we're holding that offshore, pending some kind of resolution on the repatriation of tax issue. But that -- those are the components of the -- of that position. And I think our financial position is something that we can't stress enough because what you're going to see today is we've put together a very, very large portfolio of opportunities, a large portfolio of development opportunities and a large and growing set of emerging and new ventures opportunities. And we got the balance sheet to develop that. So many companies in the business have put together large asset positions, but they don't have that financial position, the financial flexibility and the balance sheet strength to develop those assets, so I think it's a huge competitive advantage for us. With the -- our financial position, of course, we have a strong investment-grade credit ratings. And from a hedging point of view, what we try to do, our goal is to hedge about 50% of our production annually just to give a little more certainty around our annual operating cash flow. And so when you add together all of those factors, they allow us both to lower our costs of capital and provide us the flexibility to invest through all parts of the market cycle.
So when you put this all together, you can see that we have a highly profitable business reflected in our very favorable recycle ratio. You can see this here on Slide 16, which illustrates the point, and just let me take you through this. What we show here down to the middle of the slide is what our cash margin per BOE generated in 2011, so it's the full year 2011 results. We -- in calculating our revenue, by the way, we take out hedges because hedges just create a whole bunch of noise. They don't really reflect the underlying efficiency of the operating base or the operating assets and you can't necessarily replicate them in each period, so we take the hedges out. And this shows an unhedged cash margin per BOE. But as most of you know, cash margin is only half the equation because it doesn't take into account the cost of adding the barrels that you produced. So we try to look at recycle ratio because that levels the playing field, levels the playing field between companies and takes into account both that cash margin on the one hand and the F&D cost on the other or the cost to develop those assets, refine the assets on the other hand. So the recycle ratio, of course, is calculated by taking the cash margin per barrel and dividing it by the 3-year F&D, and it's a great measure because it shows the ability of a company to internally fund the replacement growth of reserves and production. As you can see, in 2011, for every barrel that Devon produced, we generated enough cash margin to add 1.75 barrels of new reserves. And those are pretty good results. That puts us near the top of our peer group in terms of recycle ratio. And if you go back and look over the last several years, you'll see that we were always either in the top position or close to the top in terms of recycle ratio, so it shows that we are in a position to compete very effectively with the large cap peer group in terms of internally funded growth.
Our future growth, of course, is going to be driven by our resource base, and while, as you can see, we have about 3 billion barrels of equivalent booked as proved barrels at the end of 2011. Our unproved risk resource potential is about 4x that, so we have -- under 20% of our total risked resource base is currently booked as proved reserves. And a very large component of that is in the form of crude and liquids. On the right side of this slide, you can see that oil and liquids makes up almost 50% of the -- our risked resource base.
We've always followed the strategy of having a balanced portfolio, and that goes back to the beginning of the company when Larry and his dad started this company. Right from there on, we've -- they've -- we've had a view and a philosophy of trying to have a balanced portfolio. So we're not latecomers into this era of wanting to have more oil and liquids. We've always been sort of 30-70 or 60-40 oil to liquids, and we do that because we really believe that, over time, a balanced portfolio will provide greater stability and better returns for our shareholders. One of the reasons we also like our heavy oil business because heavy oil trades differently than light oil trades and that trades differently than gas. And it provides a portfolio approach that, over time, we really think will provide greater stability and better return for our shareholders.
So let's take a look at what the next 5 years look like based on the assumptions that Vince laid out earlier. You can see from this that, based on our current resource base, we believe that we can continue to deliver overall production growth per debt-adjusted share of about 6% to 8%. And our oil and liquids production growth is going to continue to be very strong through that 5-year period, so that 6% to 8% total production growth is going to be underpinned by oil and liquids production of about 16% to 18% on a compound annual growth rate basis. And given that we produce this kind of growth with our existing opportunities set and without significantly having to significantly expand our balance sheet, it's going to make that performance highly competitive, we believe, in the industry sector.
Also, from a big picture point of view, it's really worth noting that, with the 7% overall compound annual growth rate in production, we'll be producing upwards of 1 million barrels a day just 4 or 5 years from now of which about 1/3 will be crude oil and over 50% of which will be oil or liquids.
With our production mix growing to over 50% oil and liquids by 2016, our 6% to 8% overall production growth will translate into a compound annual growth rate in cash flow per share -- per debt-adjusted share of about 13% from 2012 to 2016. And we think that that's going to look very good against the large-cap peer group over the next number of years.
Now with the results we have enjoyed and given that we've delivered some of the best full cycle returns in the peer group, given our very strong balance sheet, given the fact that we have a deep portfolio of opportunities with a lot of visible growth in oil and liquids, you might expect that we would trade at a premium, but unfortunately, we don't. As you can see from this slide, we're trading below the peer group average on an enterprise value-to-EBITDA multiple and, frankly, on just about every other metric that you could come up with. So by every measure, today we appear to be trading very inexpensively.
And you may ask why this is the case. Well, we believe the lower valuation stems from a number of misconceptions about our company, and I hope we can clear some of them up today. First one is we're often dismissed as a pure natural gas company or a company that's focused primarily on natural gas, whereas, as I already mentioned, we've always had a philosophy of having a balanced portfolio and, as you're going to hear from Dave and the other speakers today, we're dramatically growing our oil and liquids production. And it's important to note that, that growth isn't off a small base. It's not like we're producing 10,000 barrels a day of oil and liquids, that we're growing at a certain rate. We're starting off the base of about 250,000 barrels a day of oil and liquids. 150,000 barrels of that is actually crude oil. So when we're growing at 16% to 18%, we're growing that base, we're adding a lot of barrels every year to our production base.
The second misconception is that our key assets are mature and can't grow. And I think we're going to demonstrate to you today that, from our existing asset base, we can deliver the production growth that we're promising over the next 5 years. And we have a ton of running room in our key assets, and we've added and we're continuing to add a large suite of very high-quality, high-impact exploration plays that are going to supplement our growth for many years to come.
And the final -- finally, and this is probably the most frustrating and perplexing, from my point of view, and we hear it all the time, is that people think that we're going to do a big, dilutive M&A transaction. And that probably stems from a couple of areas. And let me just -- I'm going to spend a couple of minutes on this because I think it's important points so you'll understand how we're thinking about this. I think it stems from -- first of all, from the fact that it relates back to a couple of these other points: People think that we need to do an acquisition to supplement our asset base. You're going to see today that we don't. We've already got a very large portfolio of development opportunities and a large and growing set of emerging opportunities in new venture plays. We've got a lot of running room. And we think that every day of the week, we're going to generate better returns through that organic growth than we will if we go out and pay retail for something. So it doesn't make sense. We have no interest in acquiring assets that would, on a full cycle basis, frankly, slot in down into our asset base and not effectively compete for capital. So we don't need to do one.
The other is that I think people think that, because we have this cash, this $7 billion offshore, we'll be forced to spend that in an acquisition in Canada or somewhere else. That's not the case, either. I will point out to you that we've already recognized -- from a gas point of view, we've already recognized the taxes on a good chunk of that, and we could leave those funds offshore almost indefinitely because we are able to borrow in the U.S. at very low rates, rates that are about the same as we're getting on our investment offshore and so there's no negative carry. There's no incentive for us to do that, so we're going to spend that money and we're going to invest that money where it makes sense, where we generate the best returns, not where it's located.
And the third is the fact that I think, people, they kind of think it's in our DNA to do mergers and acquisitions. And we did a lot of them in the late 90s and early 2000s, but I will point out that it's -- it will -- later this month, it will have been 9 years since we acquired the large corporate acquisition we did, Ocean, in April of 2003. And I can tell you, absolutely -- I'm just being as candid as we -- with you as I can be, certainly, in the my time, in my current position here, I haven't and our management team hasn't either in the last few years spent 5 minutes thinking about doing a large merger -- M&A transaction. So I hope we can kind of put that to bed and then, as I said, spend a little more time on that, but I think it's an important point for us to deal with.
And since we're not looking at acquisitions, it could be perfectly -- it'd be the right thing for you to say, what are we going to do with our cash? Well, what we're going to do is we're going to reinvest our cash in our E&P projects. That means not only accelerating these liquids-rich projects but also bringing on additional leasing and liquids-rich plays, and we've got a lot of capability to do that over time.
And I'm just -- on a big picture point of view, let me just go back and reflect on what we've done here. When we sold these international assets, we took about 8% of our assets and we sold them for 23% of our enterprise value. We shrunk our balance sheet significantly by buying back $3.5 billion of stock, and we're now taking that capital and reinvesting it in E&P projects that have a higher rate of return and a much higher, we believe, risk-adjusted rate of return than where they came from. It's exactly the right thing to do and that sounds like a pretty good trade. We're selling out of assets and reinvesting them in assets that have a higher rate of return. And while it isn't our current intention or focus, we can always buy back stock or reduce debt, but we really think we have an awful lot of running room in our E&P projects, and you're going to see a lot about that today.
So in summary, we're a return-focused company. We have a very deep portfolio of existing and new -- existing opportunities and new venture opportunities and we're trading very inexpensively. And I hope that we're able to give you an awful lot of information about the company today and you'll really understand how we're thinking about the company, why we're confident, why we're excited about the company and where we're taking the company over the next few years.
So thank you very much. And with that, I will turn it over to Dave Hager.
David A. Hager
Well, thank you, John. Good morning, everyone. I am going to give you an overview of our E&P strategy and the resource potential that we have here at Devon, and then I'm going to continue on in talking about our new ventures activity and our exploration activity we have going on here at the company.
I think, just to echo what John said, though, we're very excited about the strength of our existing E&P portfolio. We're very excited about our growth opportunities. And if I could summarize it in one way, I would say: We are on offense. We have a very strong suite of development opportunities that are going to consistently produce strong results for a long period of time. And behind that, we have multiple oil and liquids-rich exploration opportunities. They're going to add to that growth consistently for many, many years. So we're very excited about where we're going and I'm going to give you a lot of details behind that today.
Now we have a simple strategy, really, and that's really to invest in projects that produce the highest rates of return. And we can do that because, if you look at our projects slate, for the most part, they are all very similar cycle times. We really only have one long-term type project, which will be our thermal heavy oil project in Canada. The rest of these are projects that are essentially similar cycle times where we don't have to take into account long-term versus short-term trade-offs when -- and we can use rate of return.
We also -- essentially, all of our acreage is held by production. So we can focus, again, on just drilling the highest-return projects and we don't have to worry about drilling projects that may not be value-adding just in order to get acreage held by production. We can, again, focus on rates of return. And again, as John said also, acquisitions typically don't compete well with our internal projects. We have higher returns internally as, typically, acquisitions are a much more competitive situation. And we have the technical expertise and the ability to generate grassroots opportunities, acquire it in lower-acreage costs, lower royalties, and generate much-higher returns.
So when we say we're executing based on rates of return, that's a simple concept, but it does have several key elements, which are listed here on the slide. We do want to assemble large, concentrated positions. That allows us to take advantage what we've learned about completions that optimize our production. It allows us to reduce our drilling and completion costs and it allows to develop our infrastructure in a very cost-effective manner.
John talked about the early mover advantage. Get a cheaper, lower royalty rates. We've done it in areas such as the Barnett, we've done it in Cana and we've also done it in our existing new ventures and exploration areas. Now we will balance the resource capture with the ability to execute and ability to develop that. And we're very confident that there are a lot of oil and liquids-rich opportunities yet to be found in North America.
Finally, operational excellence is what we're all about. It's -- that's what we execute very, very well, and you're going to see numerous examples of this as the people go through their own individual areas to how we've executed on operational excellence reducing cost, optimizing production.
Now we have optimized our portfolio consistently over the last 10 years, and we've taken what I would consider bold steps to create value from our positions. Since 2002, we have divested $17 billion of assets at very favorable prices. That includes, obviously, our $10 billion of divestments for our Gulf of Mexico and international positions. Now at the same time we've done that, we are investing in the future. Since 2009, we've invested more than $4 billion into leasehold capture and exploration. It is going to fund our future growth.
We also leverage our positions to increase our returns, minimize the negative cash flow associated with exploration, so we can focus our dollars on the more short-term development to optimize our production and our cash flow. An example of that, obviously, is the Sinopec JV that we've recently entered into, and I'll give you more details about that also.
And I think, most importantly, just think of this as a continuous process. This is something that we do everyday. This is what we focus on: It's how to evaluate and produce the best results for our shareholders. And we've had and we will continue to evaluate our portfolio consistently and make decisions that increase shareholder value.
So with that as an overview, I would like to talk about the total resource base at Devon. We use a widely accepted classification system for our resource estimates. This is a system that's been adopted by the Society of Petroleum Engineers and also been supported by numerous professional organizations. It's also been referenced by the SEC in a ruling for reserved determination. And I think, importantly, we put a great deal of internal effort to make sure that we are consistently classifying our resources throughout the company so that we get a great representation of what our resources actually are.
Now Devon has about 16 billion barrels of risked resource, and that -- of risked resource potential. That does not include any future lease acquisitions. Less than 20% of that is currently booked as proved so, you can see, we have tremendous growth opportunities with this resource base. And as a very large inventory of economic drilling opportunities, this is going to allow economic growth for many years, and we're going to show you a lot of details of this economic growth opportunities when we go through each of our operating areas.
Anybody can grow, but the real question is, can you grow and create significant value at the same time? And that's what we're focused on. And that's what we have done and that's what we're going to continue to do. You might also note that we have one of the lowest PUD percentages in the industry at 26%. And as a matter of fact, if you exclude our thermal, our PUD percentage is only 16%.
So let's take a look at our reserve growth since we announced our strategic repositioning in 2009. Since that time frame, we have grown our North America onshore reserves by 37% at a very competitive cost. So if you look at this slide, if you add up the blue and the orange colors, which represent in total the North America onshore, that's 2.2 billion barrels equivalent on December 31, '08. And then you can see we have grown that to 3 billion barrels here at the end of last year, or about a 37% growth rate. Then you can also look at what we have grown, the total proven reserves as the company -- including the 200 million barrels that we had booked associated with our deepwater and international position. So again, after selling that position for $10 billion, we have still grown the total proven reserve base as a company by 25%. So that's what it looks like from a proven reserve base.
Now let's look at the resource base, the total resource base. And you can see, our North America onshore total resource base has more than doubled since our last update. So again, looking at the blue and the orange parts of the curve, 7.4 billion barrels equivalent in March of 2008, grown to now over 16 billion barrels, so North America has more than doubled. And also you can see that our total company resource base has grown by 50% as well. So obviously, a lot of the deepwater in the international wasn't showing up in the proved. But you say, well, "But there's a lot of future potential. There's a lot of resource there that wasn't in the proved." But look at it. Look at how we still, even including that, we have grown the total resource base by 50% since that time frame. And that's why we have a great deal of confidence that we can deliver this consistent, strong value-adding growth. And this growth has really occurred in 2 primary ways, I would say. First, we better understand the potential of our existing development areas such as the Cana and such as the Permian. And second, we have added new resources through leasing. So let's take a look more specifically at where these resources are located.
You can see here that we have tremendous resource potential in areas such as the Permian, Cana, Canadian oil sands. And the Permian, I might highlight in particular due to its oil and liquids-rich nature, is going to be a very important part of our growth, and Andy Coolidge is going to stand up here later and tell you more details about the Permian.
We also have a far superior position in the Barnett than anyone else and we still have a very large potential there. And let's not forget the potential we have across our 4 million acres in Canada and also the potential we've added in our new ventures and the joint venture that we have with Sinopec.
You might also notice that the total unrisked potential is 32 billion barrels of oil equivalent. That's 10x our proven resource base. Now much of this resource is currently economic, although there are obviously some areas such as the Horn River and East Texas that should provide option value should gas prices improve.
So now let's take a quick look at our new ventures exploration program, and I am going into it in more detail later on. But in aggregate, we've assembled in acreage position of about 1.4 million net acres in the exploration plays we have in the Sinopec joint venture. You'll recall that our objective was to secure large acreage positions in new oil and liquids-rich plays where the competition hadn't yet driven up the prices. We have accomplished this. We got it at low acreage costs and low royalty rates. This -- and the Sinopec JV, it actually spans 5 different play types, each of which I would consider a high-impact opportunity for Devon. We are in the early stages of evaluating these plays, but we have seen some encouraging results. By the end of 2012, you can see that we're going to have drilled about 125 wells across the 5 different plays. And you can also see the leverage that's created by the joint venture a little bit here, as well, where we'll be spending about $620 million gross to the JV, on these plays this year, but net to Devon capital, we'll be spending about $170 million.
So let's talk in a little bit more detail about why -- about the Sinopec deal and why it makes so much sense. We're going to receive about $900 million in cash upfront. Now that exceeds 100% of our total expenditures on these plays to date, so we're immediately cash flow positive while retaining a 67% working interest in the plays. Then in the future, Sinopec will pay 70% of Devon's working interest cost, so in total, they are going to pay 80% of the well costs until the carry is exhausted. Now we really look forward with working with Sinopec. This is their first opportunity in the United States. We know that they are very focused on doing this opportunity with a quality operator, and we're very pleased that we're going to have the opportunity to work with them. And we think it's going to be a long and mutually cooperative relationship.
Now when you look at the rationale, I think the first thing is you have to believe, as we do, that there will be additional resource opportunities generated in the future. And a matter of fact, I'm going to show you one on the next slide. But once you understand that and once you believe that, the rationale is clear, that optimizing the economics of each venture makes a lot of sense. You're going to see the various reasons on the slide there. It improves the capital efficiency, et cetera. I won't read all of those, but you can see the reasons. But I think, in short, you can see it maximizes the cash flow per debt-adjusted share. And this does allow us to have more cash flow for our near-term development and also for future leasing projects.
So let's take a look at another play that we're putting together, and I can tell you, there are ones lined up behind this play as well. We have assembled a 500,000-acre position in the Cline Shale play on the eastern flank of the Midland Basin and we're going to get active on this play in 2012. As a matter of fact, we're currently drilling our first well in this play, and I'm going to discuss it in more details in the new ventures part of the presentation, but I can tell you we are very excited about this opportunity. It's a light oil play. We're able to get in at very reasonable entry costs. The Cline Shale is the primary objective in this play, but there is also potential in other zones as well. And we're -- based on the wells that have already been drilled in the play, we're -- we believe that even longer lateral length horizontals would generate very strong returns, and I'm going to go through that, how we think it's appropriate to drill even longer laterals that have been drilled historically in the Cline Shale.
And that said, we're not stopping there. We're playing offense. We're also building our position in another light oil play. We've already captured 250,000 acres in this play and we're targeting 500,000 acres in that play. And to even add to that, something that's not shown on this slide, when we get to the Barnett part of the presentation, I encourage you to pay close attention to the Barnett oil and liquids-rich expansion area that Brad Foster is going to talk about. This is an area where we already have 200,000 acres. It's held by production. It has about 600 million barrels of oil potential, and we've already drilled 4 great wells in this area as well. So they just keep lining up for us. And I can tell you, even beyond this play, so I'm talking about the Cline, I'm talking about another undisclosed, I've talked about the Barnett, and beyond that, we're establishing entry-level positions in other oil-focused opportunities. So I hope you can get a little bit of a picture here for why we're very excited about the potential that we have across our North America resource base and what this potential -- what this means to Devon.
Now obviously, this will impact our 2012 budget. We had originally budget $530 million to exploration drilling and the leasehold capture, and you -- this included about $225 million for blocking up our existing leasehold, rentals, et cetera, things like that. And then as I mentioned in our fourth quarter call, we really had not budgeted for large, new acreage positions. And you can see we're being very successful in adding large new light oil-oriented acreage positions at very attractive entry costs. This includes the undisclosed play that I mentioned on the previous slide, the Cline Shale play, the initial positions on some other new plays as well as adding new acreage in the Sinopec JV. So all -- and I might add, this also assumes success in this new play where we say we're captured 250,000 and we're targeting 500,000. This assumes we capture all 500,000 acres. And also, this budget increase includes our initial wells in each of these plays as well, so it's not all lease capture costs. It also includes some drilling costs in this capital increase as well. So in total, it's going to increase our 2012 capital budget by about $1 billion. Now this is part of the $1.5 billion cash outspend that Vince talked about at the beginning of the presentation.
So let's take a look at our 2012 capital allocation in general. We now anticipate our revised budget is going to be between $6.1 billion and $6.5 billion. Now if we do complete a JV on the additional exploration opportunities, and we're contemplating a JV, as Vince mentioned upfront on this, it will bring in cash, but from an accounting point, this doesn't offset -- this offset does not show up in the capital expenditures. Although, it would actually bring in cash, and we've assumed the one additional JV, as Vince explained, about half the size of the Sinopec JV. This capital here also obviously does not include the net impact of the $900 million in cash from the Sinopec joint venture, although it was included in the $1.5 billion cash outspend that Vince mentioned previously.
All of our capital this year is being directed towards oil and liquids-rich projects. We are not drilling dry gas wells. And this really shows the strength and flexibility of our portfolio. We do have significant dry gas opportunities, but they're just about all entirely held by production, so we have the flexibility to wait until natural gas prices recover.
We are returns-oriented. We're not volumes-driven, and we're not driven to pursue value destroying projects just to hold acreage. And the results really show up in our recycle ratio and the strength that was portrayed in the slide that John showed.
So let's take a look at what all this impact has on our 2012 production. Our exit rate will be over 710,000 BOE per day. And you can see our oil production growth is going to be in the order of 22% to 24%. NGL growth is going to be in the order of 11% to 13%. I think it's important to remember that about 90% of our NGLs have access to the premium Mont Belvieu market and not the Conway market. Essentially, all of our NGLs in the United States, with the exception of the Rockies, goes to Mont Belvieu. And of course, Canada goes elsewhere also, but everything else out of Canada and the Rockies has access to the Mont Belvieu market. Now we are going to have some minor declines in gas volumes, but frankly, we're not worrying about that. We're making the right decision from a value standpoint. And if the gas volumes decline just slightly, that's okay. We're really, again, focused on the returns.
So let's look at where this liquids growth is taken place. We're going to see liquids growth in each of our current core operating areas. That'd be thermal, Permian, Cana and the Barnett. And I think that's an important point to remember about Devon, and John touched on it also, that our liquids are growing in each of our key asset areas. And they are -- we are not declining in each of our key asset areas. And I think, sometimes, this fact gets lost in all the hype about all the new areas there, but it's important to remember we are creating tremendous value as we grow these assets by investing in strong rate-of-return projects in our existing core areas.
We're also going to generate very competitive F&D costs this year. This is a good metric to look at to -- for a quick glance to see if our programs are generally competitive, and you see, we will be. Our F&D is generally going to fall in the 16 to 19 BOE per barrel -- $16 to $19 per BOE range this year and we're going to be achieving 150% reserve replacement. And just remember, this is in a year where we're spending over $1 billion on acreage that doesn't add significantly to the proved reserves this year.
So now let's take a look at the long-term production growth outlook on an asset basis. I might say that this production growth rate and where we plan to grow our volumes is really based in allocating capital to highest-return projects. They're based on the commodity price outlook that Vince reviewed at the beginning of the presentation. We have tremendous flexibility to our capital allocation should prices be different than our assumptions, so the question is really less how much we're going to grow, it's just where we're going to grow based on the relative economics of the projects, and that's really being driven by the relative oil and gas -- oil and natural gas prices.
So working our way up the chart here, you can see what we classified as other assets are going to decline slightly as some of these are gas oriented. The Barnett stays essentially flat on an equivalent basis, but it is growing in liquids, and frankly, it could grow further if we put more capital to it. The opportunities are there. Cana continues on a strong growth track. It's driven by high returns in the liquids portion of the play. The Permian grows significantly due to strong returns in the oil-oriented areas. Thermal continues to grow as Jackfish 2 ramps up to full production and Jackfish 3 comes online and ramps up, and Chris Seasons is going to give you more details about that project later.
And you can see also that our new exploration areas are starting to contribute as well. Now the contribution could be more or less based on the success, and we do have the ability to allocate more or less capital to these based on success or for -- perhaps flex that capital and put more in the Barnett if we choose also. But based on this model, on a risked basis, by the time we get to 2016, if you look at the blue bar there are the top, plus I've added in a risked component from the Cline, which is added in -- which just actually shows up in the Permian, but if you look at those 2, which is really our exploration component, then our ongoing developments contribute about 88% of the 2016 production, and the exploration, only about 12%. So I think that also exemplifies the strength we have with our ongoing development areas, and yet the potential we have at the exploration areas succeed in a significant way.
In summary, we're very pleased with our portfolio and we're constantly upgrading it organically. It's a deep portfolio. It has strong economics. It's balanced and we're adding high-quality liquids growth opportunities at very reasonable leasehold costs. And you are going to see more detail on each of the operating areas that will support these overall conclusions.
But before that, I'd like to continue on and I'd like to talk to you about our new ventures exploration program. As I said, we're very excited about our new ventures exploration program. I'm going to talk at the beginning here a little bit about our overall exploration strategy, and then I'm going to go into more detail about each of the plays and why we're excited about the potential of each of them.
So first, let's take a look at our overall strategy and approach. I think the first thing to note is, our exploration team is very well resourced. We put some of our top technical talent to work in our new ventures and exploration plays and they're drawing on the experience that we've gained in areas such as the Barnett, the Cana, Permian, Canadian conventional, et cetera. We also set up a separate budget for this group, and we find that sometimes there's a temptation to rob a long-term activity, such as exploration, the budget from it to move it to the short term to maximize production volumes and cash flow. So we set up a separate budget for this group and we think that is, from an internal perspective, very important.
Again, what our objectives and strategy? We talked about this before: to establish material positions in the best plays right now and the focus is on the oil-type plays; be an early mover, for the reasons we discussed. One we haven't talked about yet is really the focus on regions with manageable operating environments, be in areas where they want the oil and gas business basically. And so we think that's important when we want to go about executing a program and we want to have consistent, repeatable results on a long-term basis. We're not in the Marcellus, for instance, and we have avoided other areas that we think have significant above-ground issues that may inhibit the ability to ramp up a program.
We utilize partnerships to improve capital efficiency and we talked about that with the Sinopec. And then once we're in there, we want to have continuous, efficient resource capture. And I think I'm trying to get the point across and I hope it is coming through clearly here that this is a continuous ongoing process. Don't think of this as just 5 exploration areas in the Sinopec JV and that's it. We have the Cline after that. We have an undisclosed play after that. We have several more in the -- that we are in the building stages. We have a very large feeder stock of opportunities that are going to continue to grow and create strong organic growth opportunities for many, many years.
And you can see the materiality, again, of our exploration efforts already. We have an unrisked resource base just with the exploration areas of 16 billion barrels of oil equivalent. That's 5x our proven resource base. And I would say that we fundamentally believe that the revolution that took place in horizontal drilling and hydraulic fracturing that really started in the gas reservoirs is going to continue for some time in the oil and liquids-rich reservoirs. And I guess, with the NCAA tournament going on, I'm in the basketball mood these days. Kentucky won the other night. The Baylor women won last night, so congratulations to them. And if I had to think of where we are in the oil and liquids-rich resource plays, I'd say we're about halfway through the first half on the oil and liquids-rich resource plays. We're into the game. We're into the groove, but we got a lot of game to play here yet and a lot of opportunity on the oil and liquids-rich resource plays. So we're very encouraged that we're going to be able to identify a lot more opportunities like that. And that's why we are going to keep a balance between the resource capture and our ability to develop these opportunities and why it makes sense to bring in strategic partners for the reasons I've already discussed.
So now let's take a look at the various areas in more detail. First off, let's start in Canada. We have a very large acreage position there, over 4 million acres where we're testing 10 different oil and liquids-rich plays. We have a very large resource, unrisked resource, associated with that. We're going to be spending about $350 million, drilling about 90 wells, testing these various plays this year. It's premature to discuss all these areas in detail. I can tell you we're encouraged by what we're seeing in the Viking and the Cardium and the Ferrier Area. We've also had some encouraging results in the Normandville area, and we also have acreage in the northern part of the Duvernay play. We're just now drilling and completing our first wells in some of these other areas, and so we'll update you throughout the year on our progress.
I might also mention we do have a very large dry gas inventory that's held by production or essentially held by production that provides optionality should gas prices improve. That's both in the conventional area as well as up in the Horn River.
And we're really confident we're going to have success in several of these oil and liquids-rich areas, but I think the biggest question is materiality. And we just need more wells to be drilled before we can answer that question.
I will say we believe 2012 is a critical year for the Canadian exploration program. We know that many of the Canadian juniors are having success in these plays, but the question is, is whether the scale will be big enough for Devon. And so if it's not, we're going to look at various ways to realize the value of our positions and our success.
So now let's take a look at our exploration opportunities in the U.S. I'm going to spend the bulk of my time talking about plays where we've already established material possessions on an individual basis. But I have mentioned already that we have a lot of exploration going on outside of the plays, we're going to discuss in detail. Some of these could develop into large material positions, some may not. That's the nature of exploration. A couple I'll mention off the top of my head here. We're not going to go into detail though. We have a great well in the James Lime in San Augustine county. The Albert 2H over there, we drilled recently, came on -- it has been on for about 21 days so far at a rate of about 681 BOE per day through the first 21 days and 2.8 million a day. And so again, that's one that we're watching and seeing whether that could develop into a material position. We also have a well in the Eagle Bind trend in Madison County near Madisonville in Central Texas. That's the Mathis 2H. And we have a 30-day IP on that well of 585 barrels a day and about 876,000 cubic feet a day.
Again, ones we haven't built into material positions yet, we're working these areas and they may be the ones we talk to you about in the future. But some will develop, some will not. But I just want to give you an idea. There's a lot of feeder stock that's going into the overall exploration program that we have going on here at Devon.
And I'd say that's really one of the reasons I said, that we're really about halfway through the first quarter here in terms of liquids-rich play maturity. There are just so many opportunities that were marginal in a vertical sense. But when we do them in horizontal drilling and hydraulic fracturing, we think that they can create a lot of value. And we really believe that the potential is enormous and we have the skills to create a lot of value from it. We started with this kind of activity in the Barnett and now we're taking it to our exploration program.
And another key thing, I think, from an organizational standpoint I'll just say is now that we're really focused as a company entirely on North America onshore. You're really seeing the potential of an organization is entirely focused just on the North America onshore resource potential. We aren't distracted by international or deepwater. All of our resources are going into our existing developments and exploration plays in North America onshore, and we're identifying a lot of opportunities.
So with that, let's look at the -- our initial new ventures positions. Now these are the 5 plays in the Sinopec joint venture. As I said previously, they totaled about 1.4 million acres. We're very excited to bring in Sinopec as a working interest owner on these plays, and we think we can create a lot of value from these opportunities. We did have several strong bids, and I think it shows that people recognize the potential of this position. We are still pretty early-on on giving the drilling results in most of them, but I'd like to give you an idea for why so many people were excited about the opportunities, and I will update you on the well results where I can.
So let's start with the Mississippian in Northern Oklahoma. We're going to have a common format for many of the slides. We go through the various areas, so I'm just going to orient you for the first time on the Mississippian here. In the text box in the upper right, we are showing, for instance, we're showing in terms of the gross to the JV and net to Devon, net acres, so 230,000 acres gross to JV net to Devon after consideration of the JV. The unrisked resource, similarly, total to the JV and net to Devon. And then capital, and again you get an idea of the capital efficiency associated with these on an individual basis, and then what our combined 2011, 2012 plans are.
Specifically, on the Mississippian, there are a lot of very positive attributes about this play. It is a light sweet crude, about 40-degree API gravity. There's a lot of existing well control and industry activity. People are aware of the activity to the north and to the northwest of us, there is significant industry activity. And there are opportunities to expand this position, and we are currently pursuing those opportunities. And there's also stacked pay potential. There's not only Mississippian potential here, but there's Woodford potential as well.
We're also -- one of the issues that has been recognized in here and many people have talked about is water production. But I will remind people that we have a very large underpressured aquifer or a zone here or rather a large aquifer, large underpressured zone, the Arbuckle, that will handle a tremendous amount of water. And we believe that ultimately, we'll have about one disposal well for about every 10 producers in this play now. And we've provided for that in our economics. Now early on, there will be a much higher percentage of disposal wells producers because if you drill a well, you have to do something with the water. And so you have to, in many cases, drill one right next to your first producer. But ultimately, as the play is developed, we'll probably scale to around 10, 1 disposal well for every 10 producers. We're also seeing increased activity on the east side of the Nemaha Ridge that is indicated in red on the slide there. And it also is more oily on the east side of the Nemaha Ridge.
So let's take a look at the Mississippian and Woodford intervals in more detail. There are several lithologies present within the Mississippian itself. There's a high porosity chert layer present, as well as a couple of different limestone intervals, what we call a more siliceous limestone as well as fractured limestone, and there are a lot of fracturing going on here. There are significant open fractures, as well as what we call a healed or closed fractures as well as what we call calcite field fractures. And I'll show you more details on that on the next slide.
Also, the Woodford is a great source rock. It is a source, obviously, for the Woodford and for the Mississippian with total granite content up to around 10%, very prolific source rock.
Looking at the type log and the gamma ray is -- for those of you -- that may not mean a lot to a lot of you, but the gamma ray is located on the left track, the resistivity in the middle track and the porosity on the right track, we can go in more details on what all that means later if you want to, but there are a little bit of science in there for you. But I think the more important thing is the bullets on the right side. It is -- Mississippian has been deposited in a widespread shallow-sea type environment, minimal structure or relief, has good thickness. And the importance of that, overall, is that it's easy to target the interval -- whatever interval you want to within the Mississippian. Again, very high-quality oil, about a 4,000 GOR. It's important to have some gas associated with the reservoir. That gives reservoir energy that helps with the producibility of the hydrocarbons. We do believe that the GOR will increase as pressure declines, and we've anticipated that in our modeling for these. We also have a very strong permeability system in here, microdarcy permeability system that's at work. And I'll show you again some of the fractures, natural fractures, that are present in this rock. Our position is somewhat less gassy than where the other industry players are playing to the north, where we're specifically located.
So let's take a look at the core in the Mississippian. The left is actually a CT scan of a core in the Mississippian while the right is more of a conventional layout of core samples in the Mississippian. So looking at the left side of this slide, you can see in the CT scan both mineralized fractures which are shown in -- which are in white and they're shown by the orange oval there, as well as what's called healed or closed or to fully open fractures that are shown -- that are in black and are indicated by the blue oval there. Now these mineralized fractures that are shown in white are actually calcite-filled, and this is what we see in the Barnett. So we're very familiar with the situation.
And I think the most important thing of all of this is that all of these type fractures, whether it be the calcite field fractures, the open fractures obviously or the healed fractures, can be reopened by fracture stimulation. This is what we've seen in the Barnett. We have a lot of experience with this. We understand this. And so fractures are important and we feel that they will be significant contributors to production.
So let's take a look at our results to date. This, again, is going to be a common format type slide for all of the different areas we go to. We're going to show target well economics. And I might say, make a comment there, that these are going to be target well economics. They aren't necessarily the first well that are drilled in the trend, but where we feel we're going to be after we drill a number of wells and after we have some learnings around cost and around completion techniques for the EURs, IPs, et cetera. This play generates very strong economics. You can see $3 million to $3.5 million of well cost, the EURs in the order of 300,000 to 400,000 BOE, with about 80% of those liquids. Very strong economics. And again, we are more oily in this area than it is to the northwest of us.
We've completed one well in this specific area, in the Mississippian, the Matthew 1-33H. That came in well above our target well economics. You can see, hopefully, on that slide or on your book here that the 30-day IP on that was 590 BOE per day. You can see that's well above the IP rate in our target economics. We currently have 2 wells that are being completed in the area and we're drilling a fourth. There's also a great deal of industry activity in the area, and we'll be participating in some of these wells. Those are indicated by the green diamonds.
So what are the keys going forward? We need to better understand the contribution from the matrix porosity versus the fracture porosity. But we are, as I said, we are very confident that fractures are going to contribute significantly in this area based on our knowledge in the Barnett. And as always, we want to optimize the drilling and completion cost, but that's what we do very well at Devon. You see a lot of examples of that when we get to our operating areas. And as an upside, we have not really tested long lateral and larger-stage completions, and we see those could be additive to the target well economics that we've set out.
In summary, we're very excited about the Mississippian. We are pursuing expansion of our position. There are opportunities to do so and the economics are very strong for these wells.
So now let's take a look at the Ohio Utica. It's obviously one of the most talked about plays in the industry. Looking at the text box, you can see we have an acreage position gross of JV of about 235,000 acres, 157,000 net to Devon, very significant resource potential of nearly 1 billion barrels on an unrisked basis to the JV and 2/3 of that for Devon. We're going to be drilling about 15 wells in the Ohio Utica this year. There have been positive industry results to date, particularly in the liquids-rich part of the play. There are some conventional historical oil and gas operations in the area, a lot of well control. And we have received favorable subsurface information, and I'm going to go through that in greater detail also.
Now our position is about 2/3 in the oil window and 1/3 in the liquids-rich gas window. Now we like the oil window for a couple of reasons. First, we do have a large amount of gas and natural gas liquids in our portfolio, and we're enhancing our light oil base. But additionally, we have some core data that indicates we have similar type permeabilities across the oil window to what we have in this core that's located in the oil window. We could produce at rates that produce, generate very strong economics. And I'm going to show you some of the details behind that work in the following slides.
So let's start by taking a little closer look at the Utica. It is a shale. It's really a laminated mudstone shale/limestone. The limestone, again, helps with the frac-ability of the reservoir. It has significant in situ or in place fractures present in the system. It's nice to have -- have frac barriers above and below to minimize water production that is associated with it. We are focused on the Point Pleasant unit as is the rest of the industry. It has a prolific source rock in reservoir and there's some upside from some other formations as well.
But let's -- more specifically to type log here, as I said, we are focused primarily on the Point Pleasant unit of the Utica, good thickness, consistent thickness across the entire area, low structural relief, so again, easy to target, easy to stay in zone in this. And this spans the entire area from the dry gas window to the oil window. So if you go -- if you look at the Utica, you start over on the Pennsylvania-Ohio border. There's essentially a dry gas play over there as you move to the west. You become shallower as you move from a dry gas window to a liquids-rich window to an oily window. And it's not a bright line in between. It's a gradual transition as you move across this entire area and exactly where that transition goes from dry gas to liquids rich to oil are still being determined. And I know there are some new studies [indiscernible] from the DNR of Ohio yesterday. I was laying some things out, but I can tell you, it's still being determined exactly where that transition is taking place.
We also see a strong permeability system, a microdarcy permeability system, and that's what I'm going to show you on the next slide. This is somewhat technical, but I think a fairly interesting image here that we have here. This is actually an electron microscope analysis of a core in what's the Harstine Trust well that's located in Knox County, which is in the oil window. And what you're looking at here is the actual image of the pore throats themselves or the size themselves. Again, this is an electron microscope image, so greatly, greatly magnified. And so this is the actual size of the pores through which the hydrocarbons will pass. And the measurements here that are shown on the image are in nanometers. You can see they range from double-digit to triple-digit in size. Now for reference, we've shown at the bottom of the image there that the an actual oil molecule is about 0.5 to 3 nanometers in size. So you can see these pore throats are sufficient in size to allow oil to pass through them.
Now in addition to that, we have conducted permeability analysis from this core that indicates up to 30 microdarcies of permeability. And you can see by the text box at the lower right how this compares to other shale plays. Now this is important because we do realize that in the oil window, it's fairly shallow and we're probably normally pressured in the oil window. We may be somewhat overpressured towards the eastern part of the oil window, but it gradually grades from an overpressured environment in a liquid-rich window to a normally pressured window toward -- by the time we get to the west side of the oil window. So it's probably somewhat normally pressured, somewhat shallow, so you need to have good permeabilities to make this play work. But I think the most important thing is to summarize all this. If we have anywhere near these permeabilities, even in normally pressured reservoir that is at this depth, we're confident that we will be able to produce oil at sufficient rates to generate very strong economics. So really, the question is how indicative is this core of the permeability that exist throughout the window. And that's why we just need more well results.
So let's take a look at what we're doing now up there this year. We're currently completing our first well. That's going to be the Eichelberger well that's located there in Ashland County. And we're drilling the second well. That's the Richman Farms well. It's just to the northeast in Medina County. We're going to have, I said, a total of about 15 wells that we're going to drill this year, both in the oil window and in the liquids-rich window. You can also see on this slide the location of this Harstine Trust core that I just talked about on the previous slide. It's located down there to the southern part of Knox County.
So again, if we can have well cost in the order shown there, with those types of EURs, we could have a very successful play in the oil window. And as I said about 2/3 of our acreage is in the oil window and about 1/3 in the liquids-rich window. And the liquids-rich window, I think, you can get a lot of information from other people, so I won't go into a lot of detail on that.
So let's move on and let's talk about the Rockies exploration program. Again, looking at our text box there, we have over 300,000 acres gross, about 200,000 -- over 200,000 net to the JV. Strong resource potential. And we're going to be drilling about 35 wells in our Rockies exploration program this year targeting multiple formations. We previously called this the Niobrara area. Frankly, I think it's a little more appropriate to call it Rockies oil exploration because we do have multiple targets beyond just the Niobrara that are present throughout this area. Some of the attractive attributes, we've broken this up separately for the Powder River Basin and the DJ. Again, stacked oil targets in both areas, Niobrara is in both of them. We also, in the Powder River, have the Turner, Frontier and other formations down the DJ Basin. Codell is a prospective across a good portion of our acreage, we believe, as well. We've seen economic results out there in different intervals. And we do have a lot of extra operational expertise. We've been active for a long time in the Powder River Basin. And moving down to the DJ, you can see, we think we're in the good thermal maturity area for oil generation, and Codell has good potential as well. Frankly, we haven't even fully characterized all of these zones in our resource estimate that's shown in the box. And we will -- after we get well results, we'll be able to calibrate that a little bit better.
So looking at our stratigraphic section for the Rockies oil exploration, you can see what the primary targets are in each of the basins there. High TOCs in the Mowry and the Niobrara. So it's a very good source rock, and there's other potential and other zones as well such as the Turner, Muddy, et cetera, and the Powder. And I said particularly the Codell is a nice secondary objective down in the DJ Basin.
So let's take a look at our results to date. So far we drilled 4 wells in the Niobrara, 2 in the Powder River Basin to the north there and 2 in the DJ Basin to the south. I'd say the industry results as well as our own results to date have been mixed. With our early Niobrara wells, we had noticed that there was a -- that some people had problems staying in zone in the Niobrara. So we purposely targeted what we would call quiet areas in our seismic, areas that didn't have a lot of faulting and fracturing. The good news is we stayed in zone. The bad news is we really think that the fractures and faulting are important to the overall production. So we are going to, with our future wells, target a more highly faulted and fractured zones. These faults are not large. They're in the order of 20 to 40 feet, and so you may go out of zone briefly. But we think the trade-off of going out of zone briefly versus enhancing the IPs and the EURs associated is well worth the trade-off. And so our well results, as I said, in Niobrara to date, I don't think are necessarily indicative of what we may be able to do in the future.
And our first well in the Turner was very encouraging. That's located up in the Powder River Basin. It's a Waterbuck 2342 well. We reported in the fourth quarter earnings call, it had an average of 422 BOE per day for the first 22 days of production. And I can tell you now that the 30-day rate was actually a little bit higher. It was 433 BOE per day and is still making more than 400 BOE per day currently. And as I said, as our 2012 program, we're going to be drilling a number of wells in zones other than the Niobrara to determine the potential of these areas as well.
And I think, overall, when I look at this Powder River exploration program, we're going to find that it's going to work in some areas but it's not going to work in all areas. It's not going to be your classic resource play. And so we will find sweet spots for each of these formations and we'll be able to develop those sweet spots. We just need more well control out there to determine where these sweet spots are.
So in summary, let's look at what we know and what are the some of the keys going forward. I mentioned the fractures. The initial wells had lower fracture intensity and we think fractures are the key, so we're going to be targeting more fractured areas -- not fractured areas, fractured areas in the future. Also, we think that the deeper areas of the Powder River Basin had higher GOR or that had a higher GOR, rather, are performing better. And we are going to be drilling some wells in the deeper part of the Powder River Basin later this year. So our early wells were not in the deeper part. I mentioned we've had some encouraging initial results from other zones. We've also had good results in some shallower formations. They're not in the Sinopec JV department in previous years. Again, they're not in Sinopec so I'm not talking about those so much here.
Keys going forward, 3D is important. We need to, obviously, stay in zone as much as we can and we think that was a problem with other operators' early performance. We have 3D where we're drilling now and we think that's important. And we need to determine the extent of the secondary objectives.
So if I were to summarize it all, we have confidence we're going to have success out here. We have multiple targets. We just need time to unlock all the keys to the success. It's not going to be a resource play, but there will be specific areas that will work for each of these formations and just more drilling will determine the total extent of those areas.
So let's move on to the Tuscaloosa. We have a very large meaningful acreage position there. I'd say -- again, just under 300,000 net to the JV and just under 200,000 net to Devon. Very large resource potential associated with this play. You can see an unrisked potential of 1.7 billion (sic) [1.7 million] barrels, over 1.1 billion (sic) [1.1 million] barrels unrisked net to Devon. We're going to drill about 10 wells in this play this year.
And I think, overall, when you look at this, we can see -- we know that vertical wells have had production out there. It is a highly overpressured reservoir. You put this position together, very economic price. Louisiana has a well-established regulatory environment. There is some existing infrastructure, it will have to be build out. But when I look at this play, it has a tremendous resource associated with this play and coupled with the high pressures, highly overpressured reservoir. So they can add significantly potentially to the deliverability to the rates in this. So there's a very large prize potential here. I think we are going to get good rates from these wells once we unlock the keys to completions here. I think the main issue is going to be able to get the cost down. These are relatively expensive wells for resource play.
Now I'd say the good part of that is, is this really plays to Devon's strengths. We've consistently done this in other plays. And I -- we're going to see a lot of details around that in later presentations, but I urge you to pay particular attention to the Cana presentation when we go through that because those wells were at similar depths with what we're drilling in the Tuscaloosa. And specifically, we reduced our cost on the order of 30% to 40% since the inception of our drilling program there. And that's really what the focus is going to be throughout the rest of the 2012 program.
So let's take a look at the Tuscaloosa's stratigraphic column. It is a very highly laminated lithology. It does have brittle intervals of sand, siltstone and limestone. And I know there's been there's discussion in the industry, frankly, that this is a ductile shale. It's just essentially all shale and it's going to bend and is not going to break, and that's one of the concerns about it. But I can tell you there are intervals of sand and siltstone that add to the brittleness of it that makes it frac-able. And there is a significant fracture system that's present in there. And we've get a chance to see that on the core in a couple of slides. And there has been historical oil pays throughout the stratigraphic section. The marine shale itself has produced from vertical wells. We're getting some results from the horizontal wells as well. So we know it's capable of production.
So looking at it in more detail, here's the type log again. Again, very similar to the other plays, widespread shelfal setting with low structure relief; good thickness, so again, easy to target the right interval and stay in zone; has high resistivity which indicates the very oily nature of this, and we do think we are essentially in the oil window for the bulk of our acreage position we've established there; highly overpressured, 0.7 PSI per foot, if you think of what the normal pressure gradient is out there in water is 0.465 PSI per foot, so it's highly overpressured. What does that mean? What's the significance of that? That means you can pack a lot of hydrocarbons in there due to the overpressuring and also means you potentially can have very high rates associated with this reservoir because of the pressure this is in. It has frac barriers both above and below it. That's good. You don't want to have a frac-ing in the water and you see there are some sands out there. Used to be explored for historically and -- in those Tuscaloosa sand. But there is a frac barrier between the base of the Tuscaloosa Marine sands and those sands that if you're not -- we're not frac-ing down into those sands as well.
So looking at the core, and first thing I want to say when we look at this core, they've been cleaned up. So if you're looking for the oil, don't worry, little soap and water cleaned the oil out of there, so don't think it's all dry. It's just that we've cleaned up this core. But I think you can see the amount of fractures that are present there. And so again, the importance of these fractures is that they can provide a significant benefit for the overall production. It does generate some challenges on the drilling side. I mean, you can lose a lot of fluids into those fracture that makes it challenging on the drilling side, and it's one of the challenges that we have.
But let's look at our results to date. We've completed 2 wells thus far. That would be the Beech Grove and the Soterra well. We're currently drilling 2 additional wells, the Murphy and the Weyerhaeuser well. And I would say that neither of these first 2 wells are optimum from either a lateral length or a completion design, and we really don't consider these to be indicative of what the productivity of the play is going to be once we get the completions optimized. But we understand that in Cana [ph] had better rates in north in what we consider the same geological environment. Again, we think this play has incredible potential. The resource is huge. And the prize, once we optimize the drilling and completion techniques and costs, is very compelling. We do have some learning curve to go through, but the good news is we've been through this learning curve before. The early completions, for instance, in Cana also had problems also, so we're very optimistic that we can work our way through these completions issues, work our way through the cost issues and create a great deal of shareholder value from this play.
So let's move on and talk about Michigan. Again, a very significant acreage position, very high risked resource -- unrisked resource rather, and we're going to drill about 15 wells there this year. They're going to be about equal between the Utica and the A1 Carbonate along with a couple of Dundee wells. This, also, as I said, has very large resource potential. It also has a long lease terms, you can see, on the order of 8 to 10 years. Now we know that parts of the play, particularly the Utica, are dry gas. So the long lease terms are going to give us flexibility on when to develop. But we do think there's a significant portion of the play, lease position, particularly in the A1 Carbonate, that offers rich gas to oil opportunities.
So looking at the stratigraphic section, again, 2 different target zones primarily here. The A1 Carbonate is really a laminated limestone, organic-rich limestone, and it is actually the source rock for all the old historical shallow production in the Niagara and Michigan, the Albion-Scipio trend of north and the patch reef trend around the southern flank of the Michigan Basin. The A1 Carbonate is the source rock for all of that. And then the Utica, of course, is the same Utica that we're talking about in Ohio, good very thick interval there as well. And again, fractures are present in both the A1 and the Utica.
Looking at the type log again, the A1 Carbonate is a dolometic limestones, we call it. It's what we call a vuggy porosity or vuggy ore porosity. And basically vuggy ore porosity is really where the pore space is actually composed of cavities in the rock and it's created by the dissolution or the breaking down of the limestone itself. And so it's actually holes or cavities that are present in the rock here. In addition to that, we are showing fracture porosity. And as I said, this is highly pressured -- highly fractured and overpressured. The A1, I mentioned the Tuscaloosa is overpressured, about 0.7 PSI per foot, it's actually about 1 PSI per foot going through the A1 Carbonate. So it's even higher pressure. So again, it has some of the same benefits that we talked about. A lot of storage capacity, a lot of IP capability. Some of the challenges are on the drilling side, though, obviously.
So we have started our drilling activity in Michigan. In 2011, we drilled 2 vertical wells in 2011 for core information. We've now drilled our first horizontal well, the A1, that's the -- excuse me, and the A1, that's the Cronk well, and we're awaiting completion of this well. We're currently drilling the second well also in the A1 Carbonate. That's the Wiley well that's shown here.
Some of the keys going forward on this is the maturity in the A1 and the Utica, obviously, I said, the Utica is more of dry gas up here. And where do we actually have the liquids-rich and the oil opportunities in the A1? Think of Michigan as a big -- as a basin, very simple basin. Think of it as a big bowl, and so you get shallower as you come to the edges of the bowl. And so around the flanks of the basin is where we think we will have the oil and liquids-rich-type opportunities. I talked about the pressures, the implications of such high pressure in the A1, and obviously, a lot of fractures in there that can help out, but we have to understand the significance of those to the overall production.
We do understand that other operators have had some success in the Utica, up in the Kalkaska County, and now we're just starting to get our drilling results. So we know there's going to be a lot more results at the end of this year's drilling campaign. Again, a very large resource potential and a good portion of it we think, particularly in the A1, has liquids-rich potential.
So let's review in summary all the Sinopec JV plays. This is a summary of the whole thing, in the Sinopec JV that is, a very large unrisked potential, heavily weighted towards liquids. You can see, as a matter of fact, just in the Sinopec JV, that the unrisked potential is 1.5x Devon's current proven reserve base. And we're going to have an active program this year. It's going to further define our forward plans in each of them, and we're confident we're going to have positive results.
I think one of the unique aspects of this Sinopec JV also is the fact, and it's going to be very positive I think for the long-term cooperation, is really the fact that this joint venture covers multiple plays. And inevitably, we'll want to accelerate capital in some relative to others depending on the results that we have out here. And so this is going to allow us to maintain alignment with Sinopec because they are exposed to multiple plays, and so we can accelerate in some or accelerate less in others. And we think it's really going to add to the long-term cooperation that we have with Sinopec.
But as I said, it's not just the Sinopec JVs, and so this is a continuous process and we have other plays that we are developing. And I mentioned we had a new exploration play in the Cline. We also have another undisclosed play where we captured a large position already and we're looking to add to that position through grassroots exploration leasing. We're confident we can get to the 500,000-acre target there. And just look at the unrisked resource potential associated with these plays also, and these are very meaningful positions. And also, I had mentioned, we may consider placing these in joint ventures as well for the -- obviously have the positive aspects that we've described earlier about enhancing our returns and minimizing the negative cash flow associated and all the other benefits. I do want to emphasize though that the economics of these opportunities do not depend on placing them in the joint venture. They stand on their own very, very well. It's just that it has the additional benefits that I described. And then one more time, I want to mention, pay attention to Brad's presentation when he goes through the Barnett. And look at his Barnett oil and liquids expansion area. It's not shown on this slide, but I think again, 200,000 acres held by production, 600 million unrisked potential in that area with already 4 good wells, great wells really, are located in there.
So with that, I'm going to move on and talk about the Cline Shale in a little bit more detail. It's located on the eastern flank of the Midland Basin, which is the more easterly basin of the overall Permian Basin system. And we feel, overall, that the Permian is just ripe with a lot of opportunities to apply horizontal drilling and hydraulic fracturing, to reservoirs that were marginal or non-economic in a vertical sense. In this specific area, we have about 13,000 historical wells that have been drilled through the Cline Shale interval. And so we studied these wells. They gave us a very good insight, obviously, into the thickness. In many cases, we also have porosity logs. And sometimes, we get to determine thermal maturity in this area as well from the cuttings and cores that were available from a subset of these logs.
So you will see the unrisked resource potential up there of about 3.6 million barrels equivalent, and we plan on drilling about 15 wells in this play. We're currently drilling the first one right now. Again, a very high-impact play, a lot of well control. We also have stacked pay potential. I'm not going to talk a lot about the other intervals, but there is stack pay potential in the area here as well. And obviously, being located in the Permian Basin is a favorable regulatory and above-ground environment also.
Looking at the stratigraphic section, very organically rich shale of 1% to 8% TOCs in that. It's mixed in with silt and sand, which adds -- again, add to the frac-ability or the -- of it overall, thick interval overall with good frac barriers above and below. It's located stratigraphically just below the Wolfcamp shale, but we're going to be drilling for it. It's going to be at similar depths as what the Wolfcamp shale is, because we're going to be drilling slightly further up-dip on the eastern flank of the Midland Basin. So it's going to be at depths around 5,000 to 8,500 feet.
Taking a look at the type log. Again, a lot of repeat here and you can see what we've looked for in play types. You get an idea here by seeing how much repeat there is in these bullets: low structural relief; broad shelfal setting; light oil, very high-quality light oil with some 2,500 to 3,500 GORs, so again some gas mixed in which really enhances the overall ability to produce the reservoir. Look at that primary porosities present in the shale actually is 6% to 12%, pretty strong for a resource play there with microdarcy permeability. We do believe that we are in the oil window throughout our position, so that's good. But we do have good associated gas, as I said, to help create the reservoir energy. And we've been able to analyze all these conventional wells out there that have been drilled through the Cline Shale across our lease position. So again strong porosity, strong permeability and in the oil window.
Now there have been a number of horizontal wells that have been drilled by other companies out there, primarily just to the west of our position in Glasscock County. It's very important, when you look at these target well economics that are shown here, I want to really emphasize, and we've been up here long time, but hear this point, okay, that these target well economics here are really based on 7,500-foot laterals and not the 4,000-foot laterals that have been drilled historically in the play. So this, we believe, is going to drive higher IPs, higher EURs and enhanced economics. So when you -- if you go look at the historical wells and you try to get these EURs, you're not going to get it, okay. But if you think about it, we've enhanced probably the exposure to the reservoir by probably around 75% where we've taken the target EURs going up by 25% or 30%. So if anything, we think we're being conservative in our estimates of IPs and EURs that we can get out of these. We think that over 50% of the EUR is actually going to be oil. About 1/4, about 25% is going to be NGLs, and that's going to really drive very strong economics in the play.
So we have some keys listed there. I've gone through most of those type of things before, so I'm not going to dwell on that. But I can just tell you we're very, very excited about the ability to assemble 500,000 acres in the Permian Basin on an oil-related play at very reasonable acreage cost and we're going to be moving forward with that.
So we've gone through a lot of detail on a lot of -- several new ventures exploration plays, so let's just spend a minute summarizing some of the key takeaways here. As I said, we are focused exclusively on North America now as really unleashing the potential of our technical teams to find material value-adding opportunities. We are on offense and we're going to continue this process. We're going to balance the resource capture versus our ability to fund these. But I can tell you, given our strong financial position, we see outstanding opportunities to continue to pursue this strategy.
So with that, I'm going to say that's it, and I think, Vince, we're now going to do a Q&A. Is that right?
Vincent W. White
David A. Hager
Vincent W. White
For the benefit of those that are participating via webcast, we'll ask you to raise your hand and one of our roving mics will come to you. That way, the -- those folks can hear the question, and then we'll figure out who if anybody can answer it.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
This is Doug Leggate from Bank of America. Clearly, a very extensive portfolio. No question about the progress you've made in the last year or so building that. But my question is if several of these are -- more than several of these work, what's the outlook for your capital budget? How would you intend to prioritize the emerging portfolio versus the existing portfolio? I mean, do you see another opportunity to perhaps high-grade the existing asset base by additional onshore asset sales?
Let me take -- crack it, Doug. I mean, that's a great question. And as I said at the -- in that introductory piece, as you know we've done a lot of that over the years, continued to high-grade our asset base. But we've moved a lot of stuff out. So now we're in the position of having some very large assets and that worked very well in today's market. If we do, and we're fortunate and we start to see the kind of development that Dave has indicated in some of these new plays and if we continue to be able to grow our existing development base, which I think we can over time, there are some assets that of course will fall out, that will just not have the scale or that don't give us the kinds of returns that we need. We're not going to be shy about disposing of some of those assets if that is the case because we want to make sure that we're really focusing our capital on the places where we can make the best returns for our shareholders. So there's nothing in the works on that front, but I think both by our track record in the past and our focus internally to always make sure that we're investing our capital in a way that can drive the best shareholder returns. We're not going to be shy about that if something else falls out and we're not directing capital on it and we can otherwise bring value forward for our shareholders.
As you walked through the Mississippi line, you talked a little bit about adding to that position. Any kind of clarifications you can give us on that in terms of would that mean an acquisition outright or would we be looking at doing additional leasing and kind of the current cost that you're looking at and ultimately the size you'd like to hold there?
David A. Hager
Well, Dave, we're going to have to be fairly nonspecific there, but we see opportunities both in terms of grassroots leasing as well as people that have assembled positions that may not be in a position to execute on those positions. And so we're looking at both those opportunities. We'd like to have a position out there ultimately that's similar to what we have in the Cline. I think, to be meaningful to Devon, ultimately, a position, we think, around 500,000 acres makes a great deal of sense. And if you look at -- you're going to see, we've created a lot of value in Cana and have actually a smaller position here. If you have the right value -- right position, you don't need 500,000. But earlier on in the play, something like that to -- if one of our goals, which it is, is to create another Barnett or another Cana, we think 500,000 acres in general makes sense. So even in our new ventures plays, we have somewhat less than that right now, but we see the opportunity to add to those if we have sufficient positive well results in the other plays as well, but somewhere around here is where we'll be happy I'd say.
And, Dave, if can just throw in. You asked about the cost side, what we'd be wanting to pay for that kind of acreage I think is what you're getting at. And I think what we got to do, and what we're trying to do, the way we're trying to think about this is we line up our assets by rate of return. And we developed this seriatim of opportunities. We got to make sure that as we're bringing new assets in, that they slot well into that and compete for capital. It will not -- it's not the right thing, from a capital efficiency point of view or a return point of view, to bring in assets and because of the cost that's slot down here and don't compete for capital. So we're going to be very mindful of that and be very careful about that as we continue to add assets to any of these existing areas.
David A. Hager
Yes, to say it in another way, we consider the full-cycle cost including the leasehold cost when we talk about expanding the positions. So it's not just the rate of return you're getting on the individual wells, but we have to think of the sunk cost, the leasehold cost. So we compare that to just what we can generate with our existing portfolio. And so we're not going to pay more than is necessary if it drives return for those that overall full-cycle cost beyond what we can do with other investment options we have in the company.
Two follow-ups to Doug's question. The first is when we look at your guidance or your outlook for production through 2016, how do you think about the CapEx required there? Do you think about that as in line with, above or below your free cash flow over those years? That will be one question. And then the second is there is a reference made towards if scale in Canada from the new ventures is not achieved, you would think about potentially finding some value or monetizing that. Was that a comment specifically on the new venture plays? Or do you think about that in the context of Canada overall, including the oil sands? You do have scale on the oil sands...
David A. Hager
Well, I'll try the Canada exploration and then maybe, John, you want to comment on the capital. That comment I made was specifically in reference to what we think may be an issue on the Canada exploration plays. Now that thought process, we always think about that thought process obviously in general, but specifically, we're confident that we're going to have success on some of these exploration opportunities that we're pursuing in Canada. What is less clear to us is what is the scale of those opportunities and are they going to effectively compete for capital within Devon's portfolio relative to all the other opportunities we have. They could effectively perhaps compete for capital in a lot of other companies' portfolio and not our portfolio. And if that's the case, then we're going to find ways to create value from those opportunities. Now we don't know that answer yet. We need to drill the wells that we're going to drill this year and we'll have much greater clarity on the answer to that question once we drill the wells this year. But we're going to always look to create value from these positions. And if there -- if we have good success but they're not material enough, that they're going to compete for capital within Devon, we'll look for alternate ways to realize that value. I hope that answer your...
On the capital question, Brian, I think in Vince's section, we laid out what our assumptions were for the additional capital, and there was -- we were allocating some of our -- this, the capital that we took out of our -- the sales of our assets over the last couple of years through the repositioning to our program over the next few years. I would say that if some of these things turn out in the way we hope they will over the next while, we're not going to be shy either about allocating further capital to accelerating these oil and liquids opportunities to engage in more liquids -- oil and liquids leasing because when you think about it, I made this comment earlier, think about what we did, we sold a bunch of properties and now we're reinvesting those funds in the properties that we think have much higher risk to adjusted rates of return. So certainly, from what you've seen, what we've shown you here in terms of our growth profile and our expectations over the next 5 years, that assumes an allocation of some portion of that. But frankly, we're not going to be shy about using our balance sheet if the opportunities present themselves and we think that we're generating good high-quality rates of return for our shareholders.
Vincent W. White
Yes, but specifically, it was the $1.5 billion spend of cash balances over the 5-year period in the capital program we laid out. Next?
Scott Hanold - RBC Capital Markets, LLC, Research Division
It's Scott Hanold from RBC. You talked about your midstream assets and how much value that is to Devon. But then you also made the case that your equities is also fairly undervalued to some of your peers. And how do you think about that? Is there any opportunity that you actually look at as strategic opportunity with some of the midstream assets?
Scott, that's a great question, one that we get from time to time. Let me just give you a little bit of history. Again, we haven't shied away from that if we thought it would create value. We initially -- we viewed our midstream operation as very, very integral and strategic to our operations. We've sold off lots and lots of pieces in the past. Darryl, what have we done? Probably a dozen or so sales of assets where they ended up being -- we ended up being a third-party processor basically. And that's not what we want to do at our midstream. We really want it for strategic reasons. And yet, in 2007 or beginning of 2008, we actually announced that we were going to put it into an MLP. And of course, the investment thesis at that time was these assets trade for, these MLP assets trade for 12x EBITDA and you're trading it 6 or wherever we were at that time and take advantage of that. But what we found is the assets that are in our midstream and where we generate our EBITDA and our operating profit through our midstream operation is subject to commodity price fluctuations because they tend to be percentage of proceeds liquids contracts. And so as we got more into that, it became obvious and our advice from our investment bankers was that those assets, because they have commodity price exposure, trade more like 8x rather than the 12, and we have very low basis in those assets. So we'd have to pay a big check to Uncle Sam, and frankly, it ended up -- we're given up the strategic assets and all of us the shareholders wouldn't have seen it. So we decided not to go ahead with that. It's something we revisit from time to time to see if those circumstances change, but at this point in time, it just doesn't make sense.
Vincent W. White
We've got time for one more question before break, Monroe?
In your forecast up to 2016, you're showing 1% compounded growth in gas production. You're certainly not going to drill any dry gas wells this year. But given the futures curve, have you allocated capital of dry gas wells within that forecast? And just sort of how much capital would that be over that period of time?
Yes. There are some capital allocated dry gas wells in there. I don't have the exact number for you. I'd tell you, frankly, Monroe, we've got probably the guy at the back room and give me the exact number here after the break and we can give it to you. But it is not a significant part, I can tell you, of the -- it's a pretty small part of it.
David A. Hager
The only reason that happens, Monroe, is because as we get out, we're using a price deck that is pretty close to the strip I think. And so gas prices start to go out and it starts to compete better for capital against our other opportunities. If those circumstances change, then we wouldn't.
Vincent W. White
You got a follow-up?
[indiscernible] hold your gas production fairly flat based on the associated gas coming out of these liquid plays over this period of time? And what implications that have for the industry, do you think -- when I think about that [indiscernible]
I'll let you draw the implications for the industry but yes, we can hold it fairly flat. There will be a little bit of a decline. And I can't give you the exact amount, but it will be a little bit of decline just with the associated gas with our plays.
Vincent W. White
Okay. To keep this on track, we're going to take about a 12-minute break now. We'll resume at 10:10 Central Time.
Vincent W. White
Okay, the next 2 speakers you're going to hear from, first of all, Andy Coolidge, to my immediate left, joined Devon in 1997.
Vincent W. White
If we could get you to take your seats. We'll get the show rolling. Okay, what about it? Okay. The next 2 speakers you're going to hear from, first of all, Andy Coolidge, to my immediate left, joined Devon in 1997. He holds a Petroleum Engineering degree from Texas A&M University, and he is the Business Unit Vice President for the Permian Basin. He's going to talk to you about the activity that's ramping up in the Permian. And then Chris Seasons, who is our Senior Vice President of the Canadian Division and also President of Devon Canada, will talk to you about our thermal oil assets. He has a Chemical Engineering Degree from Queen's University and joined Devon in 1998.
With those things out of the way, I'll turn it over to Andy.
Thank you, Vince, and good morning, everybody, and thank you for coming today. As Dave alluded to, the Permian Basin is one of the most exciting plays for Devon these days. Just a few high-level comments to set the stage about the Permian Basin. As you guys know, the Permian is one of the most productive oil basins in the world. It's rich in stacked-pay potential, ranging from conventional rocks, highly prolific conventional rocks that produced over 90 years ago to world-class source rocks, and really every rock in between. As new technology advances, the whole basin is changing, where some of these tighter conventional and unconventional rocks were not economic in the vertical sense are now becoming very economic with horizontal drilling and new fracturing techniques. We believe there is significant resources yet to recover in the Permian. And with that as a large acreage position, we'll have access to many of these resources.
So here's some of the key takeaways and key messages we want you to have today is, we are a leader in the basin with 1.5 million net acres of these stacked-pay potential. 80% of our current rig fleet is directed toward horizontal drilling, making Devon the most active horizontal driller in the basin. We continue to -- we will continue to expand our horizontal applications in the Permian Basin.
As Dave alluded to, we've got 7.6 billion barrels of unrisked resources. This inventory is balanced between a deep inventory of high rate of return, low-risk development projects and emerging high-impact oil resource plays. We have a lot of optionality and flexibility in the Permian Basin. We also have many zones to evaluate. I mentioned technology changes the game. We believe it continues to change the game in the Permian, and we believe there's many more resources to uncover. Lastly, with highly economic projects, we plan to deliver robust production growth over the next 5 years, and we'll show you that in a minute.
If you're not familiar with the Permian Basin, I'll give you quick, quick overview. There's 2 major sub-basins: the Delaware Basin shown in green in the west, and the Midland in the east in blue. And that's separated by the Central Basin Platform. Then you move further to the east, and you come up on the Eastern Shelf. The point to take away here is that you'll see in a minute, Devon's acreage position extensively covers all these areas across this area, exposing us to all these play types on the strat section you see on this slide. You may want to refer back to this strat section as we move through the presentation.
So here's the overview of the plays and projects we plan to talk about today with the biggest takeaway is, again, it's a very large resource base, 7.6 billion barrels net unrisked resource or over 8,000 locations. We have significant exposure to light oil, and we plan to aggressively grow this area in the near future with our current rig count at 21 moving toward 24 at year end. And I'll show you what the future rig count looks like in a moment.
So let's move onto how we are really stacking up to our other competitors in the basin. As this graph indicates, and we're on the blue bar, we're in pretty good company with our friends at Apache. We're both tied at 1.5 million net acres. We plan to continue to grow our position in the Permian.
Now let's look at these risked resources. We've got 2.8 billion barrels of net risked resource. But that little blue slither represents 7%, which is only our -- which is our proved reserves. Less than 200 million barrels of this 2.8 billion barrels is in the proved resource, which means as we aggressively grow production, we will also aggressively grow our reserves in the Permian. If you look at our risked resource by product, we stayed very liquid-rich at 74% going forward.
Again, I think there's material upside to Devon in the Permian. Again, we have a very a broad coverage. We believe there's over 50 potential play types that may exist. I think we're just scratching the surface with technology in this basin, and we'll continue to apply horizontal in many more zones, and we will be characterizing many more zones in the future. For all these reasons, we believe that Devon's risked resources are likely understated.
Now let's see some of our recent success in the Permian. We've grown our liquids production very well in the Permian over the last 3 years. We ramped up our rig -- I'll show you how -- what our rig -- operator rig chart looks like, but we -- during this period, we were ramping up our rig count. And over this period, we grew our liquids production by 16% on a compounded annual growth basis with the focus on liquids. We will continue to grow production in the Permian.
So our operational plan going forward is right here, starting with our operated rig count. Again, we are derisking our development projects and taking those guys into full development. In 2012, as I stated earlier, we'll run an operated rig count of 21 rigs, and we'll grow that to 40 rigs by 2016. So more than double the rig count over this period.
We have a very high confidence that we can execute this plan for a number of reasons. I said that we have derisked many of our projects, and we're taking many of those into the development mode. And I'll show you a few of those here in a minute. We also have been in the Permian for a long time, and we have a significant operating presence. Over that time, we have formed very strong relationships with our service providers, locking in competitive prices and securing products to service. We also have a very experienced workforce. We got a lot of fire in the belly, both in the field operations and our technical teams in Oklahoma City to grow this area.
90 years of production in the Permian means we have a very favorable regulatory in above ground environment. But there are some challenges though. Water is an issue in the Permian. But with our expertise in water management, we think we can mitigate through some of these challenges. We have several ongoing projects in the Permian right now, and throughout Devon. Kris Goforth will talk about one of those in her area.
Another challenge that we have going forward is product takeaway. And we think we can overcome this as well. This first one addresses the NGL takeaway capacity. Currently, the NGL pipelines are near capacity. So it's going to be tight. But there are several expansion projects underway. Industry has acted very quickly. And over the next 12 months, NGL takeaway capacity will double in the Permian. We feel confident about moving our product.
Oil takeaway is very similar. It's tight in the near term. There are several large expansion projects going on right now. And by mid-2013, another 435,000 barrels of oil takeaway will be available in the Permian. So when you add up our large resource base, balanced inventory of low-risk, high-return development projects, layer on our emerging high-impact oil plays, look at our growth plans in terms of our rig count and our confidence in execution, you get to the next slide, our operated production growth, over the next 5 years, we plan to increase our net production in the Permian between 20% and 25% on a compounded annual growth basis. Again, focused on light oil with high rate of return projects.
This is very exciting for the Permian, and we are ready to take this rocketship off. So let's start with 2012 budget and show you how we're going to get there. Our original guidance last time we updated you was a little bit over $1 billion. And David mentioned we have another $350 million that we're spending in the Cline through lease acquisition and the development and testing of the Cline. So we're about $1.4 billion now. The chart shows our allocation. About 60% of this capital is going to go to our near-term development projects, and the other 40% through lease acquisition and the development of our emerging plays. We're going to deliver strong growth in the Permian in 2012. 30% oil growth. At the same time, we're going to accelerate our exploration activity. So now let's get into our development plays.
These plays represent a large inventory of liquid-rich, high-return projects and will carry the load for this 30% growth. As you can see, these projects represent 85% oil and liquids content, very liquid. We have a large position across these plays that I'll discuss in a moment. 420,000 net acres in over 1,800 locations. Many of these areas exist on our legacy positions, which further enhances our full-cycle economics.
So let's talk about our first couple of plays, the Bone Springs and Delaware plays. These are tight sand oil targets. These sands were deposited off Northwestern Shelf in the Central Basin Platform and to the Delaware Basin. We've got stacked-pays in all of these. So there's several packages. These reservoirs are excellent and deliver some of the best economics we have in Devon. It's not uncommon to see wells performing over 1,000 BOEs per day. The Delaware sands, if you remember on your strat column, is the top sands that overlay the Bone Springs. We are currently targeting the lower member called the lower Brushy Canyon in Southeast New Mexico, and that ranges from 7,000 to 8,000 feet.
In the Bone Springs, we're chasing the second Bone Springs at 8,000 feet in Southeastern Mexico, and the third Bone a little deeper as you move into Texas at 10,500. We've got a large position in the Bone Springs and Delaware sands totaling 185,000 acres. And we have 550 locations identified. We believe there's upside here. As I said, these are multiple packages. So going forward, what we're going to do is we're going to move back to these locations, and we're going to layer laterals, stacked laterals in the upper parts of the Delaware. And we're not playing the first or third Bone Springs in New Mexico. We've got opportunities there. This will help us really lower cost because we'll be using existing facilities, the same location, the frac pits. It's really going to drive value for us going forward in the Bone Springs and Delaware play. We're very excited. We're also pushing these plays further to the west as well.
Our well performance continues to exceed expectations, and this slide illustrates this. The first graph on the left shows our original EUR model at 330,000 BOEs gross EUR. That's when we got started. As you can see from the black curve, that's our first 17 wells with greater than 12 months production. And we have increased our EUR model for the Bone Springs to 550,000 BOEs equivalent gross EUR. We are still -- our performance is still exceeding our current type curve. Like I said, these are high-impact wells. So if you look at the other chart on this slide, during this period from 2010 to 2012, we will grow the Bone Springs and Delaware plays 65% on a compounded annual growth basis. Currently, we're going to run 10 rigs in 2012, spend $350 million and drill 110 wells.
Now let's move to the Wolfberry. The Wolfberry is our only vertical play going on right now in the Permian. And we really like it. It's been delivering solid repeatable results, and it's very low risk. We have an inventory of 1,000 locations covering 160,000 net acres. Currently, we're downspacing to 20 acres, and we are very encouraged with those results. We also think there's a lot of upside in the upper Wolfcamp. We're now testing horizontal in a lot of areas in our Wolfberry acreage. We'll keep you updated on those results.
Here's an example how we've been proving our results in the Wolfberry, starting with the chart on the right. We've been able to decrease our drilling days from spud to rig release by 15%, down to 9.9 days. We continue to drive cost down. It's also been a very nice growth play for us. As you can see from that plot over the same period, we're going to grow production 30% on a compounded annual growth basis in these plays.
Now we'll jump up on the Central Basin Platform. These are thick carbonate deposits on the Central Basin Platform that were once vertical plays. Over 50 years, these zones have produced. Recently, we've laid horizontal wells and we're drilling stacked laterals right now in the Tubb and Wichita-Albany zones. It's very shallow. It's very cheap. It's highly economic. And our focus area on that slide there, we were able to grow our production during the same period over 21% on a compounded growth basis. We have over 200 locations identified, covering 77,000 net acres. In 2012, we aggressively ramped this program up, and we're running 3 rigs. And we're going to spend $175 million and drill 45 wells.
Now let's move to our emerging opportunities. These opportunities give us significant exposure to light oil, as Dave mentioned. These opportunities cover large areas, 800,000 acres, and we've identified 4.9 billion barrels of net unrisked resources. As Dave indicated, these are broad deposits, a very organic-rich shales. And what we like about these shales, they're carbonate-rich. They have inner beds of silk, which enhances the reservoir characteristics of these plays. We're very encouraged with early results that we're seeing in our plays to date. We're very excited about the Cline, and I'll go into that in more detail in a moment. Our plan in 2012 is to run 4 rigs, spend $575 million and drill 50 wells.
So let's move to our Wolfcamp. Wolfcamp can be a little confusing. It's a word that you hear all across the basin. For Devon, our Wolfcamp acreage exist in the Delaware Basin and the Midland Basin. Overall, we have 332,000 net acres in the play and have identified 1.3 billion barrels of net unrisked resource.
Our current focus in the Wolfcamp is in the Midland Basin where it's a little shallower. It ranges between 5,000 and 8,500 feet. We get a greater access to higher percentages of oil and infrastructure. Our results in the Wolfcamp continue to improve. And as we drill longer laterals, we were seeing improvement in well performance.
This next slide illustrates this. These 2 charts represent the first 9 wells with over 30 days of production. The top chart illustrates how we're able to lower the drilling days from over 30 down to below 15 days in the first 9 wells while drilling longer laterals from 4,000 to 7,000 feet. At the same time, we've been increasing our frac stages and getting more aggressive, and we had increased that up to 30 stages on the ninth well. As you can see in the -- from the red plot, our last well is our best well at over 425 BOEs per day. Going forward, we're going to push longer laterals. We're going to refine our completion techniques, and we believe that we will exceed these results.
Now let's move to the Cline Shale. As Dave indicated, this is a very exciting play for Devon, over 500,000 net acres and 3.6 billion barrels net unrisked resource. We've collected a lot of data in the Cline before we leased it. As Dave indicated, over 13,000 penetrations. We also have a lot of production in the Cline. To the west, we have the horizontal wells that are being developed horizontally. But through our play outline, there are several vertical wells, over 500 that have been perforated in the Cline and produced oil. So we're very excited about this play. We're not going to get into a lot of detail, but we believe there's many more zones in this play outline to chase. As Dave indicated, we are drilling our first well. We're down to our intermediate point. We've taken core in the Wolfcamp, and we are very encouraged to what we're seeing both at Wolfcamp and the upper sands in this area.
In 2012, we're going to run 2 rigs, ramping up to 4, spend $350 million and drill 15 wells. So we'll take you back right to that production curve again, and this is just as another way of looking at our compounded annual growth between 20% and 25%. As you can see, in the early time, our development plays, low-risk plays carry the load, and then you layer on the Wolfcamp Shale play and the Cline Shale.
So in summary, here are some of the points one more time. We are a significant player in the basin with 1.5 million net acres of stacked-pay potential. We are currently the most active horizontal driller. We'll expand our horizontal drilling efforts. Our large resource base of 7.9 billion barrels unrisked gives us a balanced inventory between low-risk, high-return oil development projects and emerging high oil resource plays.
We also think there's many more plays to be characterized as we apply new technology in the basin. In the end, we plan to deliver highly economic, robust production growth. Remember, that's between 20% and 25%. And if you calculate just the oil, it's 24% on a compounded annual growth basis.
I'm going to finish my section with the same analogy Dave started with on basketball. Dave was like at halfway through the first half. I'm on the bus on the way to the game. That's what we think about the Permian. It's -- we are just scratching the surface, and we're all loaded up and we're ready to go.
And I'll end it there. Thank you.
Well, given I come from Calgary, I feel obliged to go to the hockey analogy rather than talking about college basketball because that's somewhat boring. Hockey is a real game. So I'm here to talk about Canadian thermal oil. And if I talk -- think about the business in Canada, not just for Devon, but for the industry as a whole, I don't like to talk about being on the bus because I like to be -- we're actually in the game. Skating around the warm-up is not that interesting. It's actually we want to be in the game. We're in the first period here, up 3 for those who don't follow hockey, in the industry as whole. And so I think the theme as a takeaway from this as I'm chatting about Devon's position in Canada, is that while we've had tremendous success to date, there's still a lot to be learned, not only by Devon, but also by the industry as a whole. So we can expect better things to come down the road even though we've had some great success so far. So I, too, will start with the key messages. The IR people have nicely laid-out presentation here for us today that we've been instructed to follow, and I'll do my best to do that.
So let's start off with the first point here, our world-class SAGD oil position. For those who follow the heavy oil industry in Canada, there's a lot of chatter. There's been a lot of chatter of the year. Everybody has got great assets. And in the last 5 years, though we have seen production information come through, which is actually showing who really has got the great asset, and I think I'm -- I can very safely say that Devon has amongst the best assets in the industry. And frankly, for the 10-plus years that we've been focusing on the oil sands in Canada dating back to the old Northstar days, we've always focused on the top quartile rock, and we've been very diligent and very disciplined as we've gone forward in this because we're not dealing with 40 API light oil here. We're dealing with stuff that you can almost walk on unless until you put steam to it. So it's very important that you focus on the best stuff and you'd be darn good at it. So we think we are. And that's got us to where we are today.
The second point is, and you will see this through the rest of the slide, we have visible low-risk oil production. And you can definitely see where we're going with our plan here, and it's very well laid out. The third point is, I think we're about the only part of the industry as a whole that's benefiting from this tremendously low, unnaturally, if I can call it, that low natural gas prices we're seeing today. And as John and I were chatting about this yesterday, and we've talked about this a lot in the past, it's -- actually, the thermal heavy oil business is a bit of a natural hedge for Devon. Not that, that's something that's necessarily good, but it is part of the portfolio. So for us, low natural gas prices are an input cost. We burn natural gas to create steam, which allows the oil to flow and produce the oil. So the lower the natural gas price, the better it is for the returns on the thermal heavy oil business.
And finally, we'll demonstrate -- give you a few hints on some of the things, which we're pursuing to create upside in the resource estimates we currently have. So let me start off with a map. Our Canadian oil sands in the bottom right-hand corner. You've got a point-out map showing where the oil sands sit in Canada. And you'll notice we're on the northeast side of the province of Alberta.
There are 3 key areas in the oil sands. The main one is in red on your map, which is the Athabasca oil sands. That's where our position is located. The northern part of the Athabasca oil sands, north of Fort McMurray, is where you'll find the mining projects. And the mining projects have about 20% of the overall resource for Canada. And as you know, the oil sands are the third largest resource -- oil resource in the world.
So the mining projects have 20% of that. The in-situ projects take 80% of it. And really the differentiator there is the depth of the project. If you're less than 500 feet, you can mine it. If you're deeper than 500 feet, and we're sitting at about 1,600 feet, you drill for it. And you'll see in the southern part of the Athabasca oil sands that we're dominated by the in-situ projects, and you'll see down the bottom right-hand corner of the red Athabasca oil sands: MEG, Christina Lake, Jackfish, Pike, Kirby. And that's where -- that's our neighborhood, and that is the sweet spot in the Canadian oil sands.
So where is our position? So again, on the point-out map, you can see we're just sitting south of Fort McMurray. We're about a 2-hour drive. And some of you had the opportunity to visit with us last June and had the chance to fly up there. And there's a lot of bush. And also, they had a picture out in the hallway showing Pike. It could be pretty much anywhere north of Edmonton and Alberta. It's trees [ph]. And on this map, just for scale, each one of those blocks is 6 miles by 6 miles. The 2 colors for the land and the goldish color, 100% Devon land of the Jackfish area. In the green, we have the 50-50 joint venture lands with -- at Pike with BP. We bought those in March of 2010, I believe. We've also indicated on there in red the Access Pipeline. I'll talk about that a little bit later. That is a 50-50 joint venture pipeline we own that takes our product down to Edmonton and into the North American and looking forward in the world market to sell our crude and also brings our condensate supply up which we use as a diluent to blend with our oil.
So some of the characteristics for SAGD production, we have low-funding development cost, low geologic risk, high reservoir quality. And we need to have that high reservoir quality. You won't see any micro -- high-res microscope pictures for us. You can almost put your finger through the pore throats we have. Flat production profile for a long -- over a long period of time. We've got a long reserve life as well.
So let's get a little more detail on the Jackfish projects [indiscernible]. Again, just a change in scale, each one of those blocks on your map is a mile by a mile, and I know Dave talked about needing or liking to have 500,000 acres of land to -- for the new venture plays to get scale. On this little map sheet right here, you've got about 100 -- sorry, 1 billion barrels, close to 1 billion barrels of reserves in the oil sands. And that's obviously one of the key reasons that people are attracted to the oil sands in Canada as you can get a lot of reserve in a very small geographic area.
So each one of the Jackfish projects we've creatively named Jackfish 1, 2 and 3, are about 300 million barrels EUR, and that's before royalty. And -- you have to excuse me, I talked about before, royalty numbers quite a bit, because the after-royalty numbers work on a sliding scale based on oil price, so depending -- the higher the oil price, the higher the take for the government. So that number will move around depending on what your outlook is for oil. Each one of them should produce 35,000 barrels a day, and we have 100% working interest.
The end of the year, we have more than 57 million barrels booked. Now my opening comments, I made some reference to focusing on top quartile resource. The outline of the maps that I'm showing here is a 15-meter continuous bitumen pay. So that's about 50 feet. Two points to make on that. One is the continuous aspect of the bitumen pay. In our view, it's very important that you have a very thick continuous section with minimal amount of shale interbedding or water lenses within there. And that keeps your steam oil ratio down, which improves your economics.
The second point is the 15-meter comment, 50-foot mark. A lot of people will show these maps with 10 meters, some even lower than that. That's not to say that you can't get that, but from our perspective, we start at 15 meters and work up, and that's how we -- that's kind of the threshold we use for our economic cut-off. Somewhat conservative, but as I said, our view in this business is you got to be good at it and focus on the right stuff to make a good profit in the long term.
So a little more detail, Jackfish, and I'll show you some benchmarking on Jackfish 1 versus the industry. Top-tier operating performance. We got a steam oil ratio of 2.6, and that translates to about 1 Mcf of gas burned for every barrel of oil. And that's about where you want to be.
Capacity utilization, which has been a bit of a challenge for the industry as a whole. A lot of these plants have been built, and some of them haven't come close to reaching their nameplate capacity. So we've focused quite a bit on making sure we utilize what we paid for. So our capacity utilizations have been running about 96%, and our non-fuel operating cost running about $7 a barrel. When you add all those 3 things together, you can for sure say that we're a top quartile, maybe a top decile performer.
Q4 production was 31,000 barrels a day net of royalties, and we're topping at around 35,000 before royalties. 33,000 to 35,000 barrels a day, so we're at capacity.
Jackfish 2, we finished construction last February, and we put first steam in, in May of last year. In Q4, we're at -- we exited 14,000 barrels a day. We're touching about 18,000 barrels a day right now. And the production ramp up will continue through to 2012, and we're very pleased on how that project is going.
Then finally, Jackfish 3. We got our regulatory application approved in December. And I will say, I think we -- I can safely say we're about the best in the business that are getting through the application phase, which may not mean much to you, but that can add a year or 2 to your overall time line in terms of getting these projects going. We started field construction in January, January 16 to be exact. And we're actually currently 30% complete on the overall project.
And if I can get this to go, here we go. So as I mentioned, we're going to -- here's a comparison to some of the industry performance. Just a couple of key metrics we like to look at. The steam oil ratio and production per well, as I mentioned, steam oil ratio has a strong bearing on what your operating costs are. We're running on a cumulative basis. So over time, 51 months into a project, which is where we're at on Jackfish at a steam-oil ratio of 2.67, the industry is about 3.5. On a production per well, we're about double the average production per well, running 930 barrels a day versus 464 average. So clearly, we're in the right neighborhood and doing a few things right.
So the final piece to the Jackfish 100% owned lands is Jackfish East, creatively east to the east of -- I named to the east of Jackfish 1. We're about 6 miles to the east of that. Again, the 15-meter cut-off shown here, this is a smaller accumulation, about 150 million barrels, and we're about 90% delineated on that, and we expect that we can get somewhere between 20,000 and 25,000 barrels a day of production out of it. Haven't engineered this one yet because it's a little bit -- it will be a little bit different in design than we've got on Jackfish 1, 2, 3, and we expect to get this one going and the process going in 2015 and production onstream in 2018. And we'll show you a time line where -- showing where all these projects fit together in a few minutes.
Let's move on to our 50-50 joint venture with BP. There we go. This is the Pike Project. So you can see that the land sits directly to the south of our Jackfish land. And as I mentioned, we acquired this position in March of 2010, and we are the operator. So we have 50%. We see the -- before we bought it, we saw the reservoir characteristics being very similar to Jackfish. There are about 200 strat wells that have been drilled prior by BP. And I'm pleased to say that after drilling another 250 wells ourselves over the last 2 winters, all our views still hold together from what we said back in March of 2010. So we still see the potential for up to 5 35,000-barrel a day SAGD development phases on this land. So a potential pipeline development, and we're still finalizing what this will look like with our partner. We'd have a single plant pad, and on that plant pad, we'd have 3 35,000-barrel per day projects, which we developed concurrently. And by that I mean -- and you'll see this in a second, we have between 12 and 18 months between projects coming onstream as compared to doing it sequentially as we did at Jackfish, which we were about 3.5, 4 years between each one of those projects. So we're accelerating things a little bit and taking the learnings we had from Jackfish and applying them to Pike. And as mentioned at the very bottom there, we expect the regulatory filing in 2012. In fact, we -- couple of weeks ago, we put out the first notifications that we would be filing and soliciting people's input on that. So we're pushing that one ahead aggressively.
And as I said, just as a comparison, and I've got to have a log here since Dave had a whole schwack. I've actually got a scale on there for you. It's not that, that helps things out very much, but we've just got a comparison of Pike and Jackfish looking through the key characteristics, and you'll see they're very, very similar beasts. And we see a nice thick section colored in green, and that's what we're looking for is thick, continuous bitumen pay.
So here's the time line I've referred to a few times. And I will highlight that in that aqua color, I think that's a blue, the Pike projects are shown at 100%, 35,000 barrels a day each, and we have a 50% working interest in that. So for those who are doing the math, and there are probably a few people in here who've got a calculator on their desk, you need to multiply those by 50% to get the Devon share.
So Jackfish 1 came on production in 2008, Jackfish 2 in 2011. We have a bit of a range on Jackfish 3 depending on exactly how the construction schedule goes, but we'd expect it come onstream in the latter half of 2014 and ramp that up. Then we move on to Pike phases 1A, B and C. And you can see the gap between those projects is about 12 to 18 months, followed by Jackfish East in the latter part of 2018. And beyond the 2020 -- and then we've talked about our compounded growth rate out to 2020, but that is not the end of our potential for our thermal heavy oil projects. We have -- we see the Jackfish where we -- we're hoping to see a Pike 2 and perhaps more beyond that 2020 time frame. And I'll show you in a second, that gets us to that 150,000 to 175,000 barrel a day production range by 2020.
We've also got on there something called small-scale SAGD, and that is a scaled down version of Jackfish kind of project that targets smaller resource size, and I'll talk about that in a minute.
So where does that get us. In terms of our contribution to the resource numbers that Dave and John referred to in the first part of the presentation today? We contribute 1.4 billion barrels of risked resource on the thermal heavy oil business. About 1/3 of that has proved to date, has been booked to date. So that gives us the forecast outlook that we have. And we have good confidence in going from the 43,000 barrels a day we had in Q4 of 2011 out to somewhere between 150,000 and 175,000 barrels a day in 2020 and growing beyond that as well. So that's a nice 18% compounded annual growth rate.
Of course, all these questions about the economics of any projects, so we've got a couple of charts, tables here for you on that. I think the computer is stalling back there. I'm not getting any actions, so for those who've got their books -- there we go, thank you.
So starting off with Jackfish 1. And I'll say the assumptions on both of these projects are exactly the same. We -- and you can use your own assumptions, but we've just kept them pretty straightforward for you. We use blended price realizations, so that's -- they're 70% of WTI-NYMEX, which is the historic average. Condensate price is the same as WTI: $7 a barrel for operating costs non-fuel, and 1 Mcf for every barrel -- 1 Mcf of gas utilized for every barrel of bitumen produced, which are the same kinds of numbers that we've talked about for Jackfish 1.
So our capital through start-up was $620 million. And on the basis of a variety -- this matrix shows a variety of WTI prices and natural gas prices. For those who saw the slide in June, I think our natural gas prices were a little bit higher back then. Fortunately, the world has changed a little bit or continues to evolve. And you'll see that no matter what numbers you pick for your outlook, that we have very robust rates of return on Jackfish 1. And as Vince pointed out to me the other day, when we justified this project, it was on a $24 WTI oil was what our basis was. So things have changed.
So Jackfish 2 is the next slide. And sometime it'll move along here. There we go, thank you. Capital through start-up, $1 billion here. So we had a little bit of apples and oranges and also a change in -- these are in U.S. dollars, and we build in Canadian dollars, so you can't do a straight comparison saying that in 4 years, we had 50% inflation.
And I'll just go back, thank you. It's -- there's a lot of different factors here. We also had an extra pad well, instead of 1 extra well pad that we had for Jackfish 2 and [indiscernible]. So a bit of apples and oranges, but you get the general idea. And even at this higher cost, we still see some very robust economics. And one of the attractive features of the thermal heavy oil business is it's pretty predictable from a sub-surface perspective. You've got it drilled up and defined before you start for the most part, so the risk element is really more so on commodity pricing going down the road. And I think in the back here of your book, in the Appendix, there's a lot more detail on how we derive those economics and in some of the numbers that go behind the net backs that we look at here for the heavy oil.
So that's all very interesting -- oh sorry, forgot about this one, the upside of the economics. As I mentioned in the front end of this, we're in the first period of this game, and there's a lot to be learned, not just by Devon, but by the industry as a whole. So we expect that we're going to see improvements in recovery rates. We expect that facility designs will become more efficient over time, and we've seen that ourselves as we've gone from Jackfish 1 through to Jackfish 3, and part of that is in the project execution, which is no small task these days. Improvements in fuel efficiency, so burning less gas to get the same amount of oil out, and that also has implications around greenhouse gas emissions, which we're very concerned about as well. Talked about exploiting smaller resources and for sure, that is going to be out there, and we're looking at a variety of things that help us get there. And finally, solvents could improve that SOR, steam oil ratio as well. So I'll just touch a little bit on the solvents and steam oil and the small-scale steam before we jump into the marketing side of things.
On the solvent side of things, the potential benefits are many: increased production rate per well and plants, which gives us increased plant production as well; lower steam oil ratios, and this really relates back to the first comment. The real constraint on these facilities is the amount of steam we can generate. We have excess capacity of processed oil, so the lower the steam oil ratio, the more oil we can put through the system, and it reduces plant emissions as well. And we would also expect to see some increase in ultimate recovery as a result of this. But really, we're looking at bringing down our SOR and increasing our production rates.
And I will comment that while our first pilot isn't planned until later this year, we've actually been involved in solvent testing for more than 10 years, dating back to our ownership of the Dover facility in a joint industry project that we were involved in back then. So what are the risks associated with access to the solvent? If we're all in the SAGD business, if we're all successful as we think this could be, then there's going to be a lot of demand for solvent, and the solvent could be a C3, C4, C5, C6. So that's good news for the NGL producers of the world. And the real key here, I think, is solvent recovery. We're putting in a light oil product to get a heavy oil product out. So the amount that you actually lose to the reservoir is pretty critical. So we're going to pilot this to understand what those economics look like.
Finally, on the small-scale SAGD business, as I mentioned a little bit earlier, this is targeting smaller resources than the scale we're looking at for Jackfish. In our non-thermal heavy oil business, which would produce about 40,000 barrels a day on in the Lloydminster area, we have an 8 billion barrel in place resource there. And we're only recovering about 9% of it. So there's a pretty big prize if you can get after that and increase that recovery. It's tricky to do, and there's a variety of different technologies. We're exploring to do that, but small-scale SAGD is one of them.
So right now, we have about 4 prospects identified where we could apply this. We have a targeted resource of about 35 to 70 million barrels per project, and peak production rate is up to 10,000 barrels a day, so much smaller scale, but also less upfront capital and earlier time to get this onstream. So we'll see how this shakes out. We're doing the engineering work on this at the moment. And stay tuned for further updates on that project.
Okay, so we've talked about getting the resource out of the ground, the great resource we have. But clearly, people have been focused on in the heavy oil business and particularly in the last 6 to 9 months on getting product to market and access to market. Keystone XL has piloted that for everybody in spades. So let me start at the Jackfish project getting us to that pipeline infrastructure system.
As I mentioned, we have a 50% interest in the Access Pipeline. It's a dual leg pipeline that runs 200 miles from Jackfish, ultimately down to Edmonton through our Sturgeon Terminal, we have one line that takes condensate from Edmonton to our project for diluent and we have another line that takes the blend down contacting or intersecting the pipeline system in Edmonton. And from Edmonton, we can go east through the Enbridge pipeline system and ultimately, link in to TransCanada as well into Eastern Canada or into pad 2, which are the main markets, pad 2 being the main market for our crude.
We also have a physical connection into the Terasen pipeline, which is Kinder Morgan's pipeline that ends up in Vancouver. In fact, one of our crude shipments recently was shipped out of Vancouver around through the Panama Canal and ended up in the Gulf of Mexico refining complex. And we've also had quite a bit of interest from India as well. So we are looking beyond the U.S. borders to access market.
We have an application in place right now to more than double the system. But depending on how much pumping we can put out there, our share of Access Pipeline could be up to 700,000 barrels a day. So that more than handles any project that we -- or any of the projects that we envisage today. So this is a nice asset to have, and it's been quite strategic for us going forward.
So that gets us to -- into the pipeline system. Is there demand from the refiners for this stuff? And as we've seen from these 4 projects that are listed here in the next few years, we're going to see up to -- another 550,000 barrels a day of increased demand for heavy crude. So this is through 3 brownfield projects at Wood River, ConocoPhilips and Cenovus, Marathons project in Detroit and BPs project in Whiting, as well grassroots project, Northwest Upgrading that's going to be built in Edmonton. So that shows that there is quite a bit of interest in adding capacity in pad 2 to process this crude.
And finally, the last piece of the equation is the pipeline. How do we get our product to market? In black on that, you have the existing pipelines dominated by Enbridge and TransCanada. And in the colors you -- in dotted lines, you have the proposed pipelines going forward. To the west, we have Enbridge's Northern Gateway project. And then into Vancouver, we have the expansion of Trans Mountain, which is the Kinder Morgan project. We have Keystone XL, which we don't have to tell any of you about, and we also have the Flanigan South Enbridge project going from Chicago to the U.S. Gulf Coast. So we feel quite confident that capacity will be built. I believe that Keystone XL will be built and that should -- hopefully, that happens after November of this year.
So we add all of these things together, the supply, the demand story. What does this look like? This obviously impacts the economics of our overall project and what kind of differential we see on our crude. In 2012 -- or I should back up a second here. And the red line shows the industry estimated bitumen production -- incremental bitumen production growth over the next 5 years. And in the bars, we add up the refinery expansions with the pipeline and demand to look at a rough proxy for our supply/demand over the next few years.
So in 2012, when the markets balance. In fact, right now I'd say it's kind of tight, it doesn't take much in the way of pipeline disruptions to move the differential substantially, but we expect that to loosen up later this year, particularly as the Seaway pipeline reversal happens and adds 150,000 barrels a day of takeaway capacity out of Cushing. Through 2013 through '16, we're looking good from our perspective in terms of there being more demand for heavy -- Canadian heavy crudes than there is supply, and that would be dominated by the U.S. Gulf Coast. So what does that lead for us? Strong demand for our products, adequate access to markets and narrow differentials over time.
And finally, on the differentials side because this is what it all boils down to, what do we actually get for our product, what we're showing our market realizations versus percent of WTI over the last 6 or 7 years. And you can see that traditionally, it's run -- the realization has been about for Western Canadian Select, which is the primary heavy oil crude marker in Canada, has run about 70% of WTI. Last few years have been very fortunate to have it even narrower than that. And as we look forward for the next 4 years, we see quite comfortably sitting in that 78% to 80% range. So we feel quite comfortable with the fundamentals of the market in terms of the demand for our products.
So the final summation slide here, here we go. Again, hopefully, agree with me now after we've gone through the last 20, 25 minutes, world-class SAGD oil position, low-risk production growth, we benefit from low natural gas prices, and there's more to come.
So with that, I'll conclude it then.
Vincent W. White
Thanks, Chris, and we'll ask John and Dave Hager to join up us here for the Q&A. Miraculously, we're about exactly where we're supposed to be at this time, so we got some time for Q&A. Doug takes the lead again.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Thanks, Vince. If I could ask a question to both Andy and Chris. First of all, to Andy. Andy, could you tell us how you're risking your Permian outlook in terms of the production guidance you've given and also the risk resource? How are you approaching that because it looks like -- forgive me, that you might be low balling the numbers a little bit. And to Chris, can you just remind us what the cash tax outlook is for the developments in Canada?
Vincent W. White
Just a general comment about risking across the portfolio. On the -- our portfolio modeling, we start with inputs play-by-play. And on exploration, plays, there are both drillability risk factors, so there is the acreages risk as far as how much we'll be able to drill and also success, chances of commercial success risk factors. So the portfolio model weights these factors for every play input. And if in reality, a lot of the outcomes turn out to be binary, so plays dropout, others work out 100% rather than their 30% chance of success, and that's just the nature of the approach to portfolio modeling. I don't know if you have anything to add there.
Yes, the only thing I would add is depending on where you are in maturity, the risk that you apply to these, as Vince said, ranges -- it's a wide range. So your exploration projects carry a little more risk, but we have a rigorous very consistent method of risking all across the board. And that's all I have.
Vincent W. White
Yes, we consistently do look backs to calibrate our risking, and we're getting pretty good at it.
So, the second part of the question -- Doug, could you repeat that, as in cash taxes in Canada, is that correct?
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Yes, that's -- sorry Chris. So basically, the current cash tax situation with the existing projects, how to bring sensing of the incremental projects will layer in and ultimately, when you'd be in a full cash tax position on your Canadian adoption?
Right. We expect by the end of this year -- for those who aren't familiar with it, the royalty system, and I think that's what you're really getting at more so than the cash tax piece of it, the royalty system in Canada for the heavy oil sand -- for the oil sands has a pre-payout and a post-payout component to it. Both have sliding scales that are dependent on price of commodities. And we expect to have payout in Jackfish 1 by the end of this year, some time in December, depending on prices. And then we'll go from around the 6% royalty we're paying at today's oil prices to a post royalty payout, which will be -- or post-payout royalty system, which would be somewhere in the mid-20% range. We -- of course, we are spending additional capital there, and how we roll it all together will be dependent. But that's the best estimate we have for you right now.
David A. Hager
The second part of that question was when we expect Jackfish 2 to payout, again, dependent on prices, of course, but Jackfish 1 has paid out in about 5 years. I would expect that, off the top of my head, is in that 3-year range.
And 2 Permian questions, the first is on the Cline Shale. What gives you the confidence that the play goes as far Northeast as you drawn it into the Eastern Shelf? Is that based on the vertical wells that you've seen? And do they extend all the way to that area? And then secondly, I think you referenced as it relates to your Wolfberry acreage that you're drilling -- testing some horizontal wells there. Are those testing the Wolfcamp Shale? And how far north within your acreage are those -- is that activity looking?
Okay. On the Cline shale, the answer is, yes, we have a lot of vertical well control. And with vertical well control, we have the long data. We also have access to thermal maturity data that's pushing that oil window further to the East giving us very high confidence that, that is going to be prospective for oil as you move to East. On the Wolfberry question, we are testing the upper Wolfcamp section of that. We're down in -- Ector County is testing that and also Andrews County.
Back to the Permian, could you talk about just some of the constraints you're seeing right now? You've talked about NGLs could be tight. It's going to expand. But could you talk about some of the hurdles over the next 12 months? And then second question, CapEx outlook. You're 1.4 billion, I think, is what I'm looking at for '12. Can you talk about -- you go from 20 rigs to 40 rigs. What -- can you give us just some feel for what CapEx is over the next 3 to 5 years?
Vincent W. White
Let's start with the second part, then we'll have Darryl handle the infrastructure constraint.
On the capital side, I mean, we can get you the exact capital numbers as we take that out to 2016. Obviously, as we go forward, we do spend a lot of money on lease acquisition. So as we go forward, more of that money is going to be spent on our development projects. But as we increase our rig count, we are going to increase our capital.
Vincent W. White
If you look over the capital profile for the Permian over that 5-year period the way we have it modeled today, it ramps up from roughly $1 billion annually to about $1.6 billion during that time period.
[indiscernible] turn over as far as cash flow [indiscernible]?
I don't have that exact number.
Vincent W. White
Yes, what the Permian's cash flow on the day [ph] based on their prices, I don't know.
Darryl G. Smette
Are we on? As it relates to infrastructure, first on the NGL side. I think as Andy said, there's right now about 500,000-barrel capacity to move NGLs out the Permian Basin. Right now, that is not sufficient to move all the NGLs out. What's happening is some of the plants have warmed up. What that really means is that they are not extracting as much ethane and propane as they could be extracting. We think that, that's somewhere in the 30,000 to 35,000 barrels a day that could be extracted that is not being extracted. But no wells are being shut in. There are 2 NGL takeaway pipelines that are in construction. The first should be on into the first quarter of 2013, the second quarter 2013. That will add over 500,000 barrels a day capacity. So we should have sufficient capacity. And all of that capacity is going to Mont Belvieu. As it relates the crude oil side, we're really right on the edge -- well, we're right on the edge until a basin in a 50,000 to 60,000-barrel a day expansion that goes into Cushing. That started coming on the end of March of this year and is ramping up. So if you have any refinery hiccups or you have any pipeline disruptions over the next 5 to 6 months, that could impact differentials in the Permian Basin especially if production continues to ramp up. But I think as Andy also indicated on the slides that we think by mid next year, we're going to have about half of 1 million barrels of additional capacity. Most of that capacity is going to go to the Gulf Coast. So we feel very comfortable with where the pipeline infrastructure is for industry. And while we could have a hiccup here and there over the next 6 to 8 months, by the mid next year, both NGLs and oil should be in really pretty good shape.
Do you guys have any gas constraint issues [ph]?
Darryl G. Smette
Right now, we don't have any gas constraint issues. Most of the places where we're drilling now, the liquids portion is by far the greatest part of the gas stream -- or the stream. Most of the areas we're in, we do have takeaway capacity. If some of the new plays that developed are real successful, we're probably going to have to put in some infrastructure, we as an industry or we as Devon. Our past history, as get very comfortable with that is that we will put in that infrastructure. We are, right now, planning to do that as a company. If we can find that there are third parties that can do it more effectively and efficiently, we'll let that happen. But right now, we are planning to do that if this becomes necessary, and we hope it is necessary. We think that will be necessary.
What kind of working interest do you have across the Permian plays?
Yes, overall, our work interest is very high. It probably ranges between 60% and 70%. We can get you exact number. On the Texas side, it's higher. In Southeast New Mexico, it's a little bit low.
Just thinking about the Cline forecast that you've added and the fact that you haven't done a joint venture in that versus the other 5 new venture areas, does that really indicate that you have a lot more confidence in this play versus your other joint venture or new venture areas?
David A. Hager
Yes, David. We did say that we will consider a joint venture for this area as well. So I think just as a matter of -- and it's really not a matter of confidence or lack of confidence that causes us to do that. We just think that it is a way -- we have confidence we're going to continue to generate a lot of high-quality opportunities in the future. And once you have that confidence, so you can do that consistently, then really the benefits of a joint venture from a return standpoint and eliminating that negative cash flow are so strong that it just makes sense to go ahead and do that. So it's not certainly we will, but we're certainly considering that for the Cline also.
Okay. And then just kind of following up, you have included an inflow from the second joint venture. As you do that, if you did something in the Cline, an area where you have a production forecast, how does that factor out the -- you sell 1/3, and should we think about it that way?
That's all built into the model. I mean, the production forecast that you're seeing here we presented assumed that we do one more joint venture about half the size of the Sinopec. That's already factored in there.
Okay. So I guess I'm trying to get to -- is the priority to do a joint venture in the Permian or not is where I'm looping back to.
Well, I think we're going to evaluate and see if we can do one and we think it makes sense for the company, and so if we can enter into a relationship with the company that we think we can have a beneficial long-term relationship at good terms, we'll consider it. If not, we like it and we'll do it ourselves, so.
Can you talk about the -- I'm Brad Schu [ph] from Cox Partners. [ph] The capital cost in the SAGD operations, the trends there and what type of scenario would be required for you to kind of delay or shut down development of future SAGD, what kind of oil price or rate of returns would you be looking at to say, we're not going to drill or we're not going to develop any more those projects?
David A. Hager
Let me take a shot of that, guys. Certainly, inflationary pressures are out there. I mean, if you've been to Alberta, you'd never know that there was a world slowdown in the economy going on. Having said that, there are ways to control cost structure. And for us, the way we do it is we build the same thing over and over again, repeatability. We manage the projects ourselves, so we do the construction management ourselves, and we build as much of it as we can off-site, not on-site, at locations. So having said that, we are seeing pressures out there, they're not like they were in 2007. We have seen some consolidation in the industry for -- on some of these big mining projects. They employ up to 10,000 people on-site. We have 700 people on-site at peak, so there are some differences in that. So we're not seeing anything out of the norm right now in terms of cost pressures. The second part of the question in terms of economics, obviously, we look at each project as it comes along through that as we're moving into the development phase and see what our outlook is for oil prices at that time, what the labor market looks like, what the cost structure looks like and see if it still makes sense and can fit in the Devon portfolio.
Jeffrey A. Agosta
With -- just toss in, Brad, as well, that when you look at the SAGD projects, they're quite a bit different than the mining projects. The mining projects, as you know, they're build an upgrader and they have a huge capital cost. They vary a little bit, but let's put it in hundreds of thousands of barrels. For 100,000 barrels, they're spending, Chris, $15 billion or something like that.
Jeffrey A. Agosta
$150,000 of flowing barrel roughly. In the SAGD projects, our initial capital commitment is much lower. So if you want to put on the same 100,000 barrel a day metric, it would cost around $3.5 billion or something like that. So there's some variability that comes with capital cost and -- but the bigger difference is we're putting out a barrel that isn't the light sweet barrel and so they're all kind -- all the other factors that are moving, so the price of oil, the price of the diluent, the natural gas and those other factors. And so it's a very complex calculus in getting to that. And you can see from our -- as Chris said, when we approve Jackfish 1, oil was $24 and the differential was $7 and gas was under $3 or something like that. But even in today's world, that works pretty well down to about $60 or something like that because as that oil price changes, the cost of the diluent changes and other factors change as well. So it's a very complicated kind of an analysis.
The sliding royalty scale also tends to cushion your returns at the extreme. So at low oil prices, it helps your return because the royalties go down at high oil prices. It tends to start to cap your return until you break through the top end of the scale.
Vincent W. White
To keep things on track, we've got about a 11-, 12-minute break now. We'll resume at 11:30 Central Time, with the Cornerstone Shale plays.
Vincent W. White
Folks, if we could get you to take your seats, we'll get back on track here. We're going to start back up with the review of our 2 largest liquids-rich shale plays. First, you're going to hear from Brad Foster. Brad's on my immediate left. That would be the male of these 2. Brad joined us in 1999. He's a petroleum engineer, has a degree from West Virginia University. He is the Senior Vice President and in charge of the Mid-Continent division which covers both the Barnett and the Cana. After Brad talks about the Barnett, Kris Goforth, who is our VP in charge of the Anadarko basin business unit, in which the Cana shale resides, she will cover that asset. She has a petroleum engineering degree from the University of Oklahoma and an MBA from Oklahoma City University and she's been with us since 1999 as well.
So with that, I'll turn it over to Brad.
Bradley A. Foster
Vince, thank you. A pleasure to see everybody today and we had an awful lot of information we're getting into the home stretch here. That's my sports analogy, so that's all you're getting from me. But let me just -- a couple of comments about the Barnett. And I've been in this business for over 30 years. I probably don't look it, but I've been in this business for over 30 years. And there's a very few times in a person's career that they get to really work on a world-class asset. And the Barnett, by far, from my opinion, is world-class. When you look at the amount of the resource that we found, when you look at how quickly we develop the production profile of that, when you look at how we executed, and then if you look at just the amount of technology that was developed in the Barnett in the last 10 years, it's absolutely amazing. And not only -- and you saw from Dave and you saw from Andy and you'll hear from Kris, everything that we've developed in the Barnett we have transferred to other parts of our company, and not only the technology, but also the talent. The people there have created the innovation and the people that have created the continuous improvements that you're going to see through the Barnett are now throughout our organization taking these traits and characteristics and applying them to the rest of the new ventures and new exploration that Dave showed you and also to the Permian.
So let me just talk a little bit about when we got into the Barnett. We were an early-mover in the 2002 to 2006 time frame. We did the Mitchell acquisition and we did an awful lot of grassroots leasing. And we ended up with over 600,000 acres. This also gave us an attractive multiyear liquids-rich inventory, which I'll show you on the next slide. But when we went into the Barnett, there was a few things we decided that we weren't going to do. One, we tried to stay out of the highly urbanized areas for 2 reasons: one was execution risk; and the other part was just the increased cost of doing business. Even with today's depressed gas prices, we're still able to make significant free cash flow in the Barnett, and we also have a strategic midstream presence, and I'll tell you what I mean when I say that. We're able to move our production in a timely fashion. We're able to control the dependability of run times within our plants; and three, it gives us access to just about every natural gas market in the U.S.
As Dave mentioned, we also have a very interesting emerging and liquids-rich expansion area which I will spend some time further on in this presentation and give you an update on that. So let's just look at where Devon's position is in the Barnett. And as you can see from this map, if you look at the Green side, that is our liquids-rich area. And if you look at the red, that is the dry gas. If you see the gray areas, the big gray area is Fort Worth. The orange on the map is Devon's acreage position. And right through between the rich and the dry is a yield curve -- yield on gas which is 40 barrels per million. So everything on the left-hand side of that, we are calling liquids-rich. You can also see from the map, we have 2 gas plants, one in the Bridgeport Plant and also the Johnson County Plant, which I'll talk a little bit more about here in the couple of slides. From a total number of wells to be drilled, there's still about 5,000 in the Barnett, of which about 2,500 are liquids-rich wells. We make about 1.3 Bcf a day, is what we made in the fourth quarter of 2011. And as Dave mentioned before, we're not drilling any dry gas in the Barnett.
So if you kind of look what being that first-mover advantage, we've ended up with some really great acreage, 71% of it being in the liquids-rich portion of the play. It's concentrated asset which gives you economies of scale, low-cost entry point which is we have a royalty rate in the Barnett of about 19%. I'll explain to you a little bit about the strategic midstream presence, I'll give you a little more detail in another slide or 2, but all these 4 really enhance the economics of Barnett.
Here's the production profile of the Barnett, and if everybody remembers, in 2002, we got in. In 2003, we drilled our first horizontal well. From 2004 to the beginning of 2006, we actually honed our drilling expertise and got pretty good at drilling horizontal wells. And that time in 2006, the first quarter, we ramped our rig count from 16 all the way up to 40 rigs in the Barnett by the time we got to 2008. Pretty doggone impressive production growth. I think one thing I would like to point out here at the end, about 21% of the production coming from the Barnett is liquids. And again, having a midstream presence has given us the ability to move our production.
Here's kind of a map of the midstream. We have 3,300 miles of pipe, and again, the 2 plants, we have one in the West in Johnson County, which is on the west side of Johnson County; and then we have the Bridgeport which is in the west from Wise County. The Bridgeport Plant right now has a capacity of 650 million a day. We're going to upgrade it in the first quarter of 2013, which will bring it up to about 790 million a day, but it will give us 65,000 barrels of NGL capacity to process. And then as we mentioned before, all our production of NGLs coming from the Barnett go to Mt. Belvieu.
A couple of slides ago, I showed you that our average production at the Barnett was about 21% liquids. If you look at our 2012 capital, we're investing and we'll be -- the investment of 31% liquid component of our production strength. We're planning on drilling about 300 wells. We have, as we mentioned, in our earnings call, we're going from 12 rigs to 10. As you can see the average cost for those that have followed the Barnett in the past, that's 3.1 with EURs of about 3.4 Bcf equivalent. As we've high-graded our -- we continue to high-grade our investment in the Barnett and keep putting the best wells at the top. And it's some of the highest EURs we've seen in the Barnett in the number of years. So as we continue to invest in the richer products in the Barnett, we would expect to see our percentage of production liquids go up with time.
Just from a rate of returns, and again, I think everybody's got the point that we're using the strip prices that we've quoted before, but if you look at the program and look at the strip, the Barnett is giving somewhere in the neighborhood of probably a 20% to 30% rate of return, low operating cost in the neighborhood of $0.70 per M. But one thing I meant to mention, when you look at the wide range here and looking at between $2.50 gas and $4 gas. The 624,000 acres that we own in the Barnett is held by production. We do not have to drill anything to preserve acreage anymore, so we have a ton of option value in the Barnett. So depending on what price environment we're in, low gas price, high gas price, it gives us an awful lot of options of how we can treat the Barnett in the years to come as far as investment.
From a free cash flow generation standpoint, in 2011, the Barnett generated $800 million in free cash. Even when you look at the significant plant expansion that we're going to do in 2012, we still should be able to generate $600 million free cash in 2012. Just to give you a little bit and we talked little bit about our current plans, but if you look at the Barnett, the current plan with the way we run our 5-year model is invest about $1 billion over the next 5 years. Gas production relatively stays flat. The liquids production grows by 30%, and I'll just remind you what I stated on the last side, we have the option to increase or decrease spending depending on what price environment we're in.
So Dave mentioned this, and it's late in the day and I've been in operations a long time and it's tough for me to get excited about an awful lot but this is something that's pretty exciting to me. When I look at the amount of technology that's been developed in the Barnett and I look at what kind of results we're starting to see in the north Western Wise area, I think there's going to be another chapter of growth in the Barnett especially on the liquids side. We have 200,000 acres, which is basically held by production. It's been held by old conventional shallow production, legacy production for Devon, so out of the Strawn, the Caddo, the Atokas. There's no doubt that the geology up there is a little more complex than what it has been in the other parts of the Barnett. But over the last couple of years, we shot a bunch of 3D seismic out there and really identifying the number of drilling targets and then I'll show you some of the results.
Before I go there, though, I want you to take a look at this chart, and I showed you the liquids-rich portion before at 40 barrels per million. And you might not be able to see this on the graphs. Hopefully, you can see it in your books. As you go towards the northwest, you go from 40 million barrels per 1 million to 90 million to 130 million. So we're getting to some very rich opportunities.
So here are some of the results that we've seen to date. We drilled 4 wells up there. We drilled the Tinney, the Parsons, the Fitzgerald and the Forrest Lindsay. They all have 30-day IPs that are 300 to 500 barrels per day. The liquids component were somewhere between 42% and 72%. So we're continuing to derisk these plays. We're going to drill another 28 wells this year up in that area. And I think the obvious question is, why now? And if you go back and you look where prices were over the last 4 or 5 years, there's no doubt that from Devon's perspective and how we had things risked, drilling in the gas areas provided the best economics for Devon at that period in time. Now that oil has gone the other way and gas is a little more disadvantaged, and actually taking some of the technologies that we've learned in other parts of the plays and actually taking some of the technologies we learned in other parts of the company, taking some of those and transferring those back to the Barnett have given us these opportunities up into the north. The 4 wells we drilled averaged about 5,000 feet lateral. We think the EURs are somewhere between 500,000 and 600,000 barrels per well, and again, it's early days. We have 30 days IPs, but right now we're feeling pretty confident. It gives you rates of return in the 30% to 40%.
Let me just talk a little bit about continuous improvement. And if you look at this chart, and let's start with the red line. We basically doubled our lateral lengths in the Barnett over the last 8 years. Our drilling has come down from 33 days from spud to rig release to 12. So we have almost 1/3 -- almost 3x improvement on our drilling days while doubling our lateral lengths. If you look at our feet per day, it's gone up 200% since we started. So a lot of these improvements are due to drilling practices, equipment reliability but also pad drilling.
Now let me talk just about a recent multi-well pad that we brought on down in the Southeast Tarrant County, which is called Lake Benbrook. It happens to be drilled under the Lake Benbrook, but it's our Lake Benbrook pad. We drilled 36 wells off that pad. The average length was 5,000 feet per well. The longest one was over 7,000 feet and we drilled those days, spud to rig release in 11 days per well. That's come on production, came on at 80 million a day, of which about 6,000 barrels is liquids. And so very good results in that part of the play. When you look at our proved reserves in the Barnett, you can see every year they've gone up. We started that in 2002 with 1.8 Ts. To date, in the Barnett, we produced 3 TCFE net to Devon. We still have 8.1 -- we put 8.1 reserve additions on the books over that time period and we have 6.9 remaining reserves, TCFE.
And if you look at what we have as far as resource base and I showed you before it was 14.8 TCF. There's still an awful lot of resource for Devon to try to capture in the years to come. I'd also point out those reserves are somewhat similar to our production profile. You can see that they're about 22% and our PUDs are about 14%.
We have a long history of the Barnett continuing to exceed our expectations. You can see since 2004, we've had a positive revision every year. So the asset continues to overperform our expectations. Looking at the risk resource, we feel, as I said before, we still have a tremendous amount of resource. We have a deep inventory of locations, I showed you the 5,000, but 2,500 of them are in liquid locations. We have a 8-year inventory of liquid locations that we can drill and with the exciting news that we have up in the Northwestern Wise, hopefully, that will continue to grow for years to come.
So with that, I think, hopefully, going through the main points here, Devon does have the biggest and best position in the play. We have an awful lot of liquids-rich inventory for the years to come. But I'd also point we still have an awful lot of gas inventory that can be exploited and capital invested in, assuming that the environment changes. The Barnett has the ability to be an investment tool and grow or it also still has the ability to be a cash cow. We have a very strategic midstream business and we have an emerging oil play up in the northwest that hopefully over the next quarters and years to come will just be another chapter of growth as we've seen in the Barnett before.
With that, I'm going to turn it over to Kris.
Well, I'm very excited to be able to show you our Cana play. This is a very impressive resource. We have developed it organically within Devon. We're taking the learnings from the Barnett, we've applied into Cana with even better efficiency and we plan to take these same processes to the new ventures that Dave has already discussed.
Cana is an anchor resource for Devon with a very strong growth in both production and resource. We have more than 5 years of oil and natural gas liquids-rich inventory, which has very strong returns resulting in a steep growth curve that is even further enhanced by our midstream presence. All of this in an external community that is both familiar with our industry and very supportive. Cana is located in West Central Oklahoma. It has a similar hydrocarbon in place to other shale plays that you see at 50 to Bcf equivalent per square mile. Approximately 75% of the play is liquids -- oil and liquids-rich and this is an area of Oklahoma, in Western Oklahoma, we've been drilling wells for the last 90 years. So we have services, we have pipeline. They're available and very experienced personnel to go with it. So it's very favorable. And when you look at the landowners, many of them have oil and gas wells on their land, so they're very supportive, very inviting to the Cana play. It's basically open prairie. This is not an area that has any real surface problems as far as the drilling and the completion. And as I said, Devon discovered this play. It actually started in spring of 2007 with the recompletion. We quickly followed that by drilling our first well that year in 2007. And the results were very encouraging. There were some concerns early on. The first well was 12,000 feet deep, which back in 2007, that was pretty deep for a shale well and it came in at over $11 million. We had trouble frac-ing some of the initial wells, getting -- actually getting our gradually stimulations to go away, and we -- some of our early wells even produced some shale. So as encouraging as it was, we knew that there were some, definitely some issues we knew to work through.
Now the play, as you can see, has over 500 producing wells and 46 rigs running for the industry. Devon is a dominant player. We have 16 rigs running currently and our exit rate in 2011 was 275 million cubic feet equivalent per day. So what drove us to lease in this area? This is a typical well in Cana in the core area. We knew the hydrocarbons existed. As I said, we've been drilling, people have been drilling out there for 90 years, and almost every time you drilled through the Woodford, you got a gas show, oil and gas show. And we saw these reservoir characteristics. We're familiar with the Barnett. These characteristics are very similar to the Barnett. Actually, the perm in Cana, the permeability is a little bit better and the pressure is a little better. So those are both encouraging.
The Cana or the Woodford fit at a depth of 11,000 to 15,000 feet. That's similar to the Tuscaloosa, which Dave had talked about earlier. We also were able to map the extent of the Woodford and the thickness across the play prior to any leasing based on these vertical well logs that we had. So based on this knowledge, we began leasing in 2006 and 2007 in what is now the best part of the field. We have 244,000 net acres which we were able to acquire at an average cost of $2,200 an acre with a 21% royalty burden. Essentially, all of our acres is HBP, so we can develop this with the flexibility of what we think is the right investment in the Cana field. Around 80% of our acreage will produce oil and natural gas liquids. And since 2007, we've been testing across the field and building our midstream system.
Devon has discovered a significant resource that is greater than 11 TCF equivalent, and we have over 5,400 development locations identified. This is similar in size to some of the new plays that we discussed, and as you can see, that can hold a lot of hydrocarbon. So if you couple our knowledge of the Barnett with the best acreage position, you can go from testing to development in a very short period of time. In 3 years, the production in the field is over 300 million cubic feet per day. This data is through June of 2011 and it's based on public records. Devon operates approximately 70% of the production in the field, and as of last month, we were producing, out of our operated wells, over 300 million a day. We also have a working interest in the Cimarex well. And as you can see, last June, they were producing 50 million to 75 million a day. So on a net volume basis, this has a very same shape to the curve. And the uptick that you see in December of 2011, that's when the plant came back online after the tornado damage. So we exited 2011 at 275 million cubic feet equivalent per day with 27% of that production being oil and liquids. In the past, we have drilled across the Cana play. Going forward, we'll be focusing our drilling in development on the liquids-rich areas with the very best economics. This has been a very exciting play to watch. We developed it organically. We had the concept. The teams had a lot of ownership in making it work and it has been very exciting within the company.
Our ability to ramp up efficiently has also been enhanced by our midstream presence. We collaborate between the M&M groups and the E&P groups to look at not just our current year drilling program but also where do we plan to drill for the next 5 years. And the reason for this is that we need to know what are going to be the active areas, what kind of processing and takeaways needs do we have and how can we get the best market. So there is a lot of collaboration that works as we go through the development plan. As you can see, our midstream is focused in the eastern area of the Cana field, which is the better acreage. We have over 300 miles of gathering pipeline, and we 100% owned a gas processing plant that has the current capacity of 200 million cubic feet per day. To meet our growth, that plant is being expanded. And by first quarter of 2013, it will have a capacity of 350 million cubic feet per day and 30,000 barrels of liquids per day. Also, this is a historically active area, so there are pipelines across the field.
While I've discussed the plan in general, so now let's talk about how we break it up. We divided the Cana into 3 basic areas. We first have the core. When we talk about the core, that is where the Woodford is the thickest. It's also been -- it's repeatable and we know just exactly what kind of results we're going to get as we develop there. We break the core into the rich and the dry. The rich has up to 300 barrels of oil and natural gas liquids per million cubic feet. That equates to around a 1,350 to 1,400 of BTU, if you're thinking it that way. The dry is dry gas without any liquids associated. The Devon acreage, 50% of our acreage is in the core rich, and additional 20% is in the core dry. The extension is something that we're working to understand and we'll be discussing that a little bit later.
If you look a little closer at the core, as I said, this is where 70% of our acreage is located, and within the core, 90% of that is in the highest oil and liquids-rich area. It has the strongest return even in this current environment. As I said, we have 8.3 TCF equivalent of resource identified in this core rich area and over 3,000 locations. So that equates to about 50% to 60% of our resource is located right here in the core rich, which has the best metrics. The remaining 10% of our acreage in the core is in the dry, and as I said, it's held by production so we can develop that when the gas prices recover.
We're in the process of an optimum development plan and as you saw, the Barnett and where the -- the production got flat for a couple of years. So if you remember, Barnett was initially developed vertically, then we came in and we start drilling horizontal. Those were lateral length of 1,500 to 2,000 feet. In Cana, we're drilling 4,500 foot laterals right now. We initially tested the spacing between the laterals and the lateral and some of the length, we did that early on. In this way, when we come into this acreage, we don't have the vertical wellbores, we don't have the shorter laterals to work around. We can develop Cana from the very beginning at the optimum spacing and the optimum length. We're also within this core area testing some 7,500 and 10,000-foot laterals in 2012.
Moving to the extension. The extension is to the northwest, as you saw on the map, it does have greater geologic complexity. Devon's position is almost entirely in the oil and liquids-rich area. The Woodford actually thins as you go to the Northwest and then the extension is around 75 feet in thickness. It is overlain by the Mississippi and the Mississippi is thick up to around 2,000 feet. It is productive and that's the complexity of it. It contains hydrocarbon. We know it's hot there. It's the hydrocarbon storage area and we do not have any resource contributed to the Mississippi yet. So with the understanding how these 2 reservoirs will work together and Dave talked about that in the Miss play and Central Oklahoma as well. You see the same thing at the Miss over the top of the Woodford.
So right now, we have a minimal activity planned in 2012. In the extension area, the plan is to gather data, derisk the area and we'll have it for the future. Our focus in 2012 is in the core-rich area. As I said, we're in full development mode. We have strong economics in this area of greater than a 30% rate of return at the strip prices. 16 rigs are running. We expect to drill and participate, drill and/or participate in 200 wells that will spend approximately $170 million. The average well costs are $8.1 million per well with an estimated ultimate recovery of 8.3 Bcf equivalent. The program will yield 42% oil and natural gas liquids of the production reserves.
If you look at the 2012 program across a broad range of prices, you can see very robust economics, 20% to 40% rate of return. Even as low as $2.50 per M and $80 per barrel, this plays -- this program still yields a 20% rate of return. This is due to our low lease operating expenses, our low royalty burden and the high liquids content. So based on strip, we have over 5 years of development drilling that will generate this type of rate of return. So with this, Cana competes very favorably within the model.
This outlook, as we said, it's the competitive project within the Devon portfolio and it averages to spend of $1 billion per year and 20 to 25 rigs per year. We've been testing the area in the past. We're now focusing on the very best rich economics -- rich liquids and resulting in the best economics. Our liquids percent growth from 26% in 2011 to 43% in the production in 2016. As you can also see, this is a huge production growth. The production has a 5-year compound annual growth rate of 30%. The liquids are growing even faster at greater than 40%. So we have a deep inventory of development locations with solid returns of 25% to 30%.
The Cana provides significant growth in both reserves and production. It is definitely a key resource for the company. And as we focus on reserves, we're constantly looking to drive cost out of the system.
Continuous improvement. This is what Devon does. We identify plays. We test across them. We characterize the reservoir, all while we're holding acreage. We focus on the improvements across the full cycle of the investment for the project. We're also coordinating with the M&M group to enhance our returns and get the best value for our product. You've seen this exhibited in the Barnett, and as Brad had talked about, we've now taken this to the Cana with great success and our plan is to do the very same thing in the new ventures.
First, let's talk about drilling. Since 2007, we have seen a 40% improvement in the average feet drilled per day. This has resulted from technology, improved design and collaboration between our drilling engineers and our geologists, the reservoir engineers were involved as well. So the first well, as I said, was over $11 million. Actually, our first 10 wells in Cana were $9.5 million to more than $12 million. In 2012, we're expecting $8.1 million per well or a savings of 30%, and that's in an environment that saw cost escalations of 35%, so these are huge improvements.
Now if you look at the completion side. Since 2008, we will have a 72% improvement in the frac stages per day. This is through collaborating with the service company and getting a run time efficiency. Anytime you shorten the time that you can get to first production, that helps your return. It's from investment to first revenue. So we're also working on the performance, and we do that with small focus areas where we do small testings of different completions on side-by-side wells and look at landings and lateral lengths and different designs. We vary those completions. In the core rich focus area, we've been able to improve our EURs, 25% since 2008, and we plan to take that into our development program.
From an operations perspective, this is our water recycle project. This services 30 sections, which is just about 270 wells. We plan to recycle 2 million barrels of water in 2012, increasing to 7.5 million barrels by 2014. This shows an improvement of 90% on our water-handling cost within the water recycle project or $2 per barrel of water handled in savings. Not only is this a good investment, this reduces our lease operating expense. The project itself generates a 35% rate of return. At the same time, we are good stewards of the water. If you think about it, every barrel of water that we recycle is one less barrel of water that we have to produce for frac-ing.
So let's shift gears a little and look at the reserves. For Cana, again, incredible growth, 250% compound annual growth rate over the last 4 years. As of year-end 2011, we ended with 2 trillion cubic feet equivalent of proved booked reserves with over 1/3 of that in oil and natural gas liquids. With only 18% of our total risk resource booked, we have significant reserve bookings for many years to come. They said 82% of our resource is in the core with 3,000 infill locations that are oil and natural gas liquids rich. 8.3 TCF equivalent is in the core rich, out of our 11.4 resource.
So in summary, 73% risked resource in core rich; 5-year compound annual growth rate. 30% of production, over 40% for liquid; greater than 5-year development inventory of solid returns of 25% to 30% rate of return; favorable external environment, pipeline, services and a community that is kind; collaborate between the E&P and M&M segments; generate enhanced returns and the best value for the product; and continuous improvement through our extension -- and continuous improvement and our extension areas gives us additional upside. The Cana is an illustration of Devon's organic success. We've demonstrated continuous improvements in the Barnett. We've taken it to Cana and our plans are to take the same processes and learnings to the new ventures. Thank you.
Vincent W. White
Okay. I'll ask John and Dave to come up for the last Q&A session and we'll take some questions. We hope that those of you that are with us in person will stay and have lunch with the staff here and just any follow-up questions you might have. So after this Q&A, John will summarize and we'll terminate the webcast and then I hope you'll stick around.
Vincent W. White
All right, Doug.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
So 2 questions if I may. They may both be to John, but we'll see how you want to spread them around. So just a couple of points and clarity for you, John. On the production targets, we do have about -- looks about 30,000 -- 30 million barrels of exploration contribution. First of all, is that number look about right and can you confirm, does the capital plan also include the associated exploration capital? And the follow-up is just dealing with the offshore cash share buybacks and again, just -- I wanted to circle back to my first -- my first original question, which was, where ultimately do you see your capital expenditure? Is there a ceiling? Are you prepared to outspend cash flow? Are you prepared to go beyond the $1.5 billion that Vince talked about in order to accelerate beyond the current production target you've given us? Just trying to frame how conservative you've been on the guidance.
Why don't we do this, Dave, why don't you answer the first part of the question first and then I'll maybe take a crack at the second part.
David A. Hager
Yes. I don't have the -- I haven't calculated the 30 million barrels that way. The way I looked at it, I explained in my presentation as I included from the one chart there, you had the blue layer at the top, was the exploration layer on that one graph that I showed in the E&P overview, and I also included the Cline which is actually embedded in the Permian production. So it was hard for you to break that out on that graph. When I did that, I said, 12% of the production in 2016 would be associated with the exploration, layer an 88% for the ongoing development. And I haven't done the math the way you have, Doug, there. It probably does work out to somewhere around 30 million barrels. But yes, the answer is all the capital that is associated with that is embedded also into our capital forecast on a risk basis. Just as we've risked the production, we have also risked the capital, but you have it, the appropriate amount of capital to develop those exploration barrels. It's embedded in that forecast.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Yes. The -- you want to repeat the...
Vincent W. White
Yes. Let's repeat the question.
Doug was asking what the corporate and midstream capital is, and that's about $1 billion. If you take capitalized G&A and interest, the corporate expenditures and our midstream capital in 2012. Because and we have a couple of expansions in our midstream operations that are happening in 2012 that both Brad and Kris mentioned the expansion to our Cana facility and also the expansion to our Bridgeport facility.
Jeffrey A. Agosta
And all of that is obviously built into the overall model that Vince described at the beginning of the presentation that amount at the end to the $1.5 billion outspend of cash flow.
But as you look forward, Doug, I was saying earlier, what we're focused on is growing cash flow for net adjusted share, we just -- and we have a lot of development opportunities and a lot of new plays that we're developing. And it may well be, over time, we're quite prepared to use our balance sheet to fund that if it makes sense. And so as we -- Vince said earlier, this isn't a binary outcome or it is a binary outcome, even though we have characterized these new ventures plays, for example, with the certain risking factor, but we have the balance sheet to get out and to continue to grow this liquid or to accelerate the liquids-rich opportunities to bring on more opportunities and more or additional leasing opportunities as well. So that's the way it looks today, and you could well see us allocate a lot more capital over time to that because it makes sense and it's going to drive those -- our cash flow per debt adjusted share. If circumstances change, we're not going to be shy about buying back our stock either. I think we had a pretty good track record of doing that, as they said, when the times are right. But just right now, we have enough confidence and we're bullish enough about these opportunities in our opportunity set that we just see that as a better allocation of that capital. So as we said in our fourth quarter call, we're going to take a breather for the time being on the share buybacks as we continue to derisk these plays and really understand them.
Jeffrey A. Agosta
One thing I'd add, Doug, if you ask Dave if that 12% is about right for the exploration wedge. That applies to the assets that we have in-house. So we fully expect to -- that would be the derisking and moving into development phase on those assets on a risk basis, but we fully expect to develop additional exploration opportunities going forward.
Michael Kelly - Global Hunter Securities, LLC, Research Division
Mike Kelly, Global Hunter Securities. Dave, you highlighted the fact that one of the core benefits of your new ventures, joint venture structure is the fact it allows you to be, essentially dynamic with your capital allocation, really, just shifting capital to the plays that will maximize returns. Given that, I was wondering if we could glean anything from your 2012 capital allocation with the Tuscaloosa garnering the most capital followed by the Niobrara and then actually the Michigan Basin. If not, and realizing it's early days here, if you could give us a sense of your ranking in terms of...
David A. Hager
We rank 1 through 5 with the confidence level of 90% or more or something like that. No, we don't. Well, it is early days and I really wouldn't draw any conclusion from the amount of capital per play. If you ask me, I'd say and I did indicate as I was going through the presentation, that we are looking at expansion opportunities in the Mississippian, so that probably is -- probably ranks, I can say, at this point, a little above the others with confidence they will work. Where the others, and I try to, as I went through the presentation, there are certainly strong points about each and other things we need to learn about each before we move forward. So I really don't -- and I don't think I have enough data or anybody else does really ranked beyond that, other than to put probably the Mississippian are a little bit higher. The other point I want to make, and I think it's -- everyone understands this, but the way we characterize all those, we keep -- in the way -- we've characterized it all in our 5-year plan is we put it all in on a risk basis, which inevitably means some of these plays are going to work more than other plays. But we think in totality, if we risked these appropriately, we should get a response somewhere in the order of what we've shown in the plan. It's possible we could have a little bit more. It's possible we could have a little bit less. And there's maybe that question about, how can you be so confident about this target, well, EURs, IPs, et cetera, given the limited amount of well data that you have. That's what our targets are. Some of these plays will work to the degree we expect, but there is risk associated with each of them. And frankly, we don't expect every exploration play to work to the degree that we achieve those target economics. That's why we've applied that risk factor. But in totality, after you apply that risk factor and you allocate capital to the ones that are successful and fully develop those, we think we should have results that approximate what we've shown in this 5-year plan.
Yes. The Wolfcamp shale that Andy showed you was an example for when we went in with target EURs and the actual results are far exceeding those, that's a play that it looks like it's going to work.
David R. Tameron - Wells Fargo Securities, LLC, Research Division
Dave Tameron from Wells. Can you talk about this, just the decision to slow down to repurchase the shares versus reinvesting capital. You guys have always talked about as the matrix, and what does that tell us anything about the hurdle rates or where you think the current share price is. Can you just walk through your thought process?
Sure, David. I think we, as I said, we're focused -- when we make a decision, whether we're going to buyback stock or invest in our program, we're really focusing, again, on what's going to drive the most cash flow growth per debt adjusted share. And we talk long time -- actually, we talked to Jeff and his group for a long time about whether we could work out rate of return calculations on share repurchases, and he finally convinced me that you can't do that because that made too many assumptions about the stock price. So we're focused on that other metric of cash flow growth per debt adjusted share. And while we think our stock is undervalued today or valued -- it's trading at a low valuation, these opportunities that we have in our analysis actually provide even a better per debt adjusted share growth and cash flow, so that's why we're saying, hey, let's take a breather here because we want to make sure that we're allocating that money to what's going to drive the most shareholder value. And it actually ought to be a pretty good indication or a pretty good confirmation to you of how excited we are in the new plays. And because, again, we don't think that our stocks are trading high these days, but we're that much even more excited about some of these opportunities and how that can drive shareholder value over the next little while.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Irene Haas from Wunderlich. Question for you is between Delaware Basin and Midland basin, which Wolfcamp do you like better and why?
David A. Hager
Well, I'll take a stab and, Andy, come up here, if you don't like my answer. But I'd say right now, we're more focused on the Midland Basin. It's a more oil-rich play. The Delaware Basin Wolfcamp also has good potential, but it is more gas-oriented, so just the economics right now looks like I prefer to see the Midland Basin.
Yes. You covered it, Dave.
Marshall H. Carver - Capital One Southcoast, Inc., Research Division
This is Marshall Carver. I just had a quick question on those growth wedges that you have in the long-term outlook. Would the Cline play be included in the Permian growth or in the exploration growth?
As I said, that's actually included in the Permian growth on that graph. It's not in the blue. It's in the Permian growth. And so that's why it's a little bit hard to break out, but I think Andy gave you some -- if you go back to the Permian part of the presentation, I think he had a 5-year growth outlook for the Cline specifically, so you can figure out what part of the Permian is when you go to that part of the presentation.
As you think about the Permian program, you're in a couple of rigs 2 years ago. You're 10x that and you're going to double that again. How big does your Permian staff have to grow? And then what do you do and kind of thinking about the overall industry growth rate, everybody is kind of going ballistic in the Permian and then your cost structure seems like that could be up versus the plan that has a relatively flat assumption?
Yes. On the staffing question, it's something that we our planning right now. We're looking at 5-year staffing workforce model right now. As we double our rig count, we'll essentially double, I don't know if the number will be double, but we will definitely double our staff out there. We're putting those plans together right now. So as we grow in production, we'll have more people that have to go those wells, can keep those wells online. As we have more rigs running, there's more people that are doing completion work. So yes, your staff, that's definitely does grow. Now on the second question, can you repeat that one more time?
Just thinking about operating [indiscernible] flat forecast based on [indiscernible].
Yes. I've got a couple of comments having looked over the model. One is that, we've got a lot of -- we're moving rigs from the Permian, we've seen rigs from the Haynesville. There's a lot of mobility of rigs in services between plays. And while the Permian's definitely heating up from an activity level perspective, some plays are cooling off. We have seen, for the first time in years, we've seen our -- Dave's group just went through rebidding out all of our pressure pumping services for the upcoming periods and we actually saw a reduction in the pressure pumping rates. So there's reasons to think that the increased capacity on the service side is offsetting quite a bit of the activity levels and that we're finally seeing cost start to crown. One other thing I'd say, is I looked over the model, we had about $500 million a year of cash taxes in our model. And if you look at our activity levels and just look at recent history, you'll see that, that's a pretty large wedge of conservatism from a cash flow perspective and I think it gives us room. And we probably -- there may be areas we see cost creep. There might be G&A creep, I don't know, there will be on a unit basis. I would hope that our volume growth would more than offset that. But there's some room in our portfolio model for some cost escalations.
Just following up on that, when you look at your modeling plan, your margin still $25 per barrel or $30 a barrel, how is that [indiscernible] price [indiscernible]?
Well, there's a couple of things in the mix. One is the oilier that our production mix is the higher unit revenues and margins that it should generate. But we also -- we base this on the strips, so there are some commodity price escalation in our modeling that is clearly disclosed here.
I'd like to take advantage of Dave's willingness to explain everything in terms that a non-geologist might possibly understand. Now when we hear other companies like Encana talks about the Collingwood in Michigan and EOG talks about the Avalon in the Permian Basin. Are these plays that you're involved in or are they completely different?
David A. Hager
No. The Collingwood is actually a unit in the Utica in Michigan. So yes, that's part of the Michigan play. Now the Avalon is a separate play that we have a pretty significant acreage position out in the, really, spans the border between Texas and New Mexico out of the Delaware Basin, of the Permian Basin. We've drilled a number of Avalon wells. It appears that as you move across the Avalon from the west to the east, it gets a little bit more oily, but in general, it's a pretty gassy play. And we think there are some reasonable areas in the Avalon. But essentially, we have the acreage in the Avalon that we desire held by production and it is primarily gas and so we're deemphasizing that this year in terms of activity and emphasizing the more oil and liquids-rich areas.
Vincent W. White
Okay. At this point, we're going to -- I'm going to turn it over to John to wrap it up. And then like I said, we hope you'll stick around for lunch.
And I'm going to be very brief. It's been a long day, but let me just make a couple of points here before we break up.
The points we want to leave you with, we've got a very large risked resource base, 16 billion barrels equivalent. Less than 20% of that is booked as proved reserves. And the total risked resource base, we have almost 50% oil and liquids. We're going to have very robust production growth over the next 5 years in the range of 6% to 8%, and our liquids growth is going to be much higher than that, it's 16% to 18%. And when you translate that into cash flow per debt adjusted share, we see some real healthy growth over that period of time at about 13%. We think that's going to be very, very competitive in this industry.
So in summary, again, we're a returns-focused company. We've got a big opportunity set of development assets and emerging in new ventures plays and we've got a balance sheet to let us develop that. So we really -- let me just make a couple of final closing comments. We really appreciate you all being here today and taking so much of your day. We know you're busy and spent as much time with us. It's terrific. I hope that what we've been able to communicate to you is some of the enthusiasm and the excitement that all of us have about the company and why we're so confident and so bullish that we can grow the company very, very profitably and significantly over the next few years. So we really do think we're doing a lot of the right things and we're going to really be focused on creating a lot of shareholder value over the next while.
And with that, thanks again for being here and I guess we're adjourned. Please join us for lunch.
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