Noble Energy, Inc. (NBL)
November 15, 2011 9:00 am ET
John Lewis -
Susan M. Cunningham - Senior Vice President of Exploration and Business Innovation
Ted D. Brown - Senior Vice President of Northern Region
David L. Stover - President and Chief Operating Officer
Rodney D. Cook - Senior Vice President of International
Kenneth M. Fisher - Chief Financial Officer and Senior Vice President
Charles D. Davidson - Chairman, Chief Executive Officer and Member of Environment, Health & Safety Committee
David R. Larson - Vice President of Investor Relations
Unknown Analyst -
David R. Larson
We'll go ahead and get started. Again, I want to thank everybody for coming. I think you're in for a really exciting 4 hours hearing about all the great things that are going on with Noble Energy and our outlook for the future. So with that, I think you guys should have your books in front of you, all of that is all the material that we'll cover today, as well as a news release. Those that are listening on the webcast, the presentation has been filed on the webcast. And it's broken down into sections for you to make it easy. But should you want to download it, you can or you can proceed with us as we flip the slides for you. So it's your option on that. The documents have been filed or are in the process of being filed with the SEC, so if you want to look at those, they will also be on our website later today.
One note, I think, as you guys were coming in, I hope you kind of saw some of the photographs of our operations. I know you all know that we're building a lot of things around the world. We got some major projects going on. But I thought it was important for you all to see exactly what kind of progress we are making and hopefully, you've got an opportunity to see some of those photographs of just where we stand on those major assets.
One other note on the presentation today, in the DJ Basin, we have -- are going to be providing a video about halfway through the presentation. Those of you that are listening to the webcast, that video is on our website and you can download that and see it on your PC. Those of you in the room, you'll be able to see it on the screens as well as the audio that goes along with it.
Okay. All right. So first things first, just want to remind everyone that the presentation and the webcast does contain some projections and forward-looking statements. Noble doesn't provide any assurance on these statements as a number of the factors and uncertainties could cause actual results in the future periods to differ materially from what we talk about today. You can see our full disclosures about the forward-looking statements in our news release that we provided to you today, as well as the filed SEC documents.
We are also going to talk about some non-GAAP financial measures and actually probably have some terms today that will be defined in the appendix. So the last section of the book has all the terms and definitions of those that we'll be talking about. Appendix also includes our price deck that we're using in determining some of the economic values, the present values, some of the cash flow streams that you'll be seeing here today. So if you're interested in that, that's in the appendix as well.
The meeting today is really designed to provide a very in-depth look and update at the global portfolio. It's going to highlight a lot of the significant growth that we ended up reporting in the news release today and talk about the opportunities that we think is a pretty unique position for a company our size within the industry.
So let's quickly look at the agenda for today. I think we're going to start off with hitting the corporate overview stuff, and then we'll then start to talk about each one of the core areas of the organization and finish up with exploration at the end. As you can see, there will be a break. The break is going to come right after Marcellus, and I estimate that to be around 9:30. And then second half of the agenda -- the second half of the agenda is on the screen now and what we do is hope to be finished between 11:30 and 12:00. I think it all depend on what the Q&A session looks like and how long that takes.
One last thing, just a safety moment. There's many of you in here if -- there are no fire alarm practices scheduled today. So if you do hear anything, the appropriate exit is out the doors and toward the lobby and out to the front. Secondary path, should that be blocked, is moving to the other direction and there's an exit down this hallway. So just keep that in mind should something happen.
So with that, I'm going to turn the meeting over to Chuck.
Charles D. Davidson
Thanks, David. Good morning, everybody. Great turnout. This is the second time we've done this in Houston and I'm really pleased that I know in talking with many of you some last night that hopefully this format works out well. It seems likely we get a great turnout, it's growing here in the second year, gives us an opportunity to have a full team here. Also besides the speakers, we've got a number of our management here on both sides. We're in the cheap seats on the side but over here, as well as a couple over here, so at the breaks or afterwards, feel free to visit with them as well. They've got some great insights on our programs.
These events do require a huge effort and I think the team has done a great job of pulling this all together. Our effort always, and we take these very seriously, is to provide a very focused look but also a very complete look at our business. So as you go through and you look at the materials, hopefully you're not going to see too many slides that you've seen before. You're probably not going to see any that you've seen before exactly in the same form is what we're doing here because this is a fresh look, and so we intend that these are intentions to create almost everything from scratch as we build together our programs.
Our intention today is really to be as transparent as we can. We have a great program in front of us. This is really an exciting program for Noble Energy. And so we want to make sure that you do understand our long-range plans, that you understand our portfolio and it's opportunities but also that you understand our capabilities and the upside potential that exists in a number of these areas. So again, we want you to leave today with a full understanding of Noble Energy, our business plan and hopefully you'll also leave with confidence just as we have confidence in our ability to execute this plan.
I'll tell you upfront that you're probably going to see more changes as part of this program today than we've presented for many years. Perhaps more change than maybe since Patina, the merger of Patina. So before you get worried, I think all the changes are positive. But a lot has happened in the last 16 months since we were together in June of 2010. A lot has happened. It's had a dramatic impact on the company, it's dramatically changed our growth profile going forward and that's what we're going to be highlighting. So a lot has changed. We've had major discoveries. Major projects moving forward, a major acquisition and we sanction some major programs as well. So all of those are folded into our program.
So I think with that, let's go ahead and jump right in. And I'll start and talk a little bit about how we've positioned the company today. Obviously, everyone's aware that we've added a fifth core area in the Marcellus until we'll certainly be spending some time on that this morning. But we're going to talk about all 5 of our core areas. And there is one thing that will jump out as we get into it, and Dave will focus on it some in his presentation, is that every one of these core areas has stunning growth over the next 5 years. You'll see it. It's not just 1, not just a 2 but all 5 of our core areas have very strong growth. Each area is projected to have double-digit compound annual production growth over the 5-year period, with the lowest being 14% and the highest being over 100% growth.
Out to fairness just so that you read all the fine print, we took out the Alba LNG because that gas is sold at $0.25, we didn't think it's appropriate to include that in the calculation. So as we go through, we have eliminated that as we've calculated those growth rates. And it's no surprise that the reserves are growing as well. In fact, as you look at these numbers, almost everything you see is going to be a higher number, a higher growth rate substantially than what you saw a year ago.
We've talked about our major projects in the past. Well, they're now. They're truly here. We've announced, as you saw it in our release, that Aseng in Equatorial Guinea is on production. It went from literally commissioning to full production in just a matter of a few weeks. It's 7 months ahead of schedule, it's under budget and I can't say enough about the team that pulled that together. That is a world-class project and that is world-class performance because we do a lot of benchmarking and we know that it's very unusual to pull off a greenfield project in West Africa and do it that far ahead of schedule and under budget. So the team is doing well and so today, we have a field that's now producing right at 50,000 barrels a day, stellar performance. And I think that's just an indicator and we know that we've got many, many more projects on the heels of Aseng and so it's important that we start out right and they did it right with Aseng.
The other thing that comes out is the value of these projects goes up every day. It's just the nature of present value. In many instances, you'll see that as they progress, come closer, the value goes up. Now one of the big one, I'm looking at a full cycle economics. So as we go through the program, you'll see a lot of full cycle cradle-to-grave rates return and NPV. But for many of them, as you look at it today as investors, that value is much higher because in some instances like Aseng, the capital has all been spent, they're much closer to production than what they were when we sanctioned it when those returns were put together. And to give you an example, we'll show some of these, the full cycle net present value of Aseng and Galapagos, this is net of Noble, about $1.9 billion. But if you look at the value of those projects today going forward, it's $1 billion higher, it's $2.9 billion because of the capital we spent and the fact that the production is that much closer. So again, it's a matter of everything continues to get better and better, the closer we get at the value accretion that we've talked about in the past.
Our portfolio of reserves -- resources continues to grow. They've grown a lot. Dave will highlight the changes. But the bottom line is that net risk resources have grown 75% since we last met in June of last year. So that today, our net risked resources are 7.4 billion barrels.
Exploration. We'll talk about that. Susan will talk about that and will also be touched upon in several of the areas, but it's been a big driver of our success. There have been many examples of companies who have been successful in exploration and then quit. We all have our own personal examples of where we've seen that happen. In many instances, it was due to the fact that the company couldn't afford to continue with exploration while they developed their legacy discoveries. We think that's a fatal flaw. We think that's a fatal business law to ignore the part of the business that got you to where you are today. So our program and our plan certainly allows us to continue to fund exploration while we're making all the investments that are necessary to develop these great discoveries that have been made over the past several years. And we believe that's what then makes it a sustainable program that is clearly an industry leading, and Susan will talk a bit more about that as well.
We can do all of that because of the financial position we've built. Ken will talk about our balance sheet and some of our strategies on that. But clearly, we have gone through our programs, we've designed the strategy of this business such that we can accommodate success. We can do things like explore and continue to explore while we develop major projects. And we have the capacity to take advantage of incremental opportunities, such as what we did with the Marcellus.
So when you look at this year's program, yes, we're drawing on that financial capacity more in terms of capital investment than what we showed last year, but I think we're also showing that those investments are expected to deliver very material incremental value.
Finally, we take a huge pride in the organization that's been built in this company. We're attacking a very large and diverse set of opportunities but I think as you look at the capabilities of the organization, you look at examples such as delivering Aseng early and under budget, or when you look at the major transformation that we have underway in the DJ Basin, or if you look at how Noble Energy as an independent with the company that helped lead the industry back to drilling in the Deepwater Gulf of Mexico by securing that first permit, it really evidences the kind of capabilities that we've built and positioned in our company.
Last year, I showed a similar bar chart of key accomplishments. There was a difference though. It went all the way back to 2004, spanned 6.5 years and it showed last year 11 important events. Well, this year, we're showing 11 important events but they span only a period of only 16 months, and that really is an indicator of the huge changes that we've been experiencing in a very short period of time, and we'll touch on many of these as we go through the program today.
Similar to last year, we're providing a 5-year outlook. In some areas, we will be even talking about beyond the 5-year period because some of our projects carry on for more than a decade. It's a significantly different plan, it's driven by a number of initiatives. Certainly, exploration success is one important factor that change our plan versus last year. The Leviathan discovery, which was our largest in history, provided a major opportunity to grow the business and we have certainly allocated significant incremental capital on this year's plan over the plan period to move Leviathan forward, and of course, other big driver on this year plan is the Marcellus, the acquisition that we made earlier this year.
So we've raised our 5-year capital spending plan. The program now over 5 years is $24 billion. It's a big jump but it's not because of cost increases, it's because of opportunities. We have brought into our portfolio a numerous multiple high return opportunities that allow us to invest our cash flows.
And the results are impactful. As a result of this plan, our annual production growth rate on a compound basis over the 5 years has increased from the 10% we showed you last year to 17% per year this year. And there is a few wrinkles in that, that I know Dave will point out, but one of the most obvious is that 17% compound growth rate takes into account over 20,000 barrels a day of production we intend to divest of in the U.S. onshore takes into account the exit of Ecuador, takes into account the -- in terms of the base plan takes into account the fact that we have sold some non-core assets. But more importantly, going forward, it takes into account the additional onshore divestitures we've planned.
So the growth rate went from 10% to 17%. We've continued to improve the portfolio. I think it's a great picture going forward. And it doesn't end there. I'll tell you we now believe that we can average double-digit compound growth rate for the entire next decade. All the way out to 2021, we can expect as a company to average double-digit production growth rate over that period of time.
It's mostly driven by defined projects. In fact, when you look at year 2021 -- we won't take you there today, we don't have enough time. But when we look at year 2021, there's only 15% of the production in that year that comes from future exploration. 85% of it has got projects with a name by it. They're known projects, they're in the portfolio we're executing. I've never been in such a position. I've been in positions where I was looking for my meal the next year but never to the point where you could say, "I know where I'm going to get that meal 10 years out." And that's an incredible differentiating factor in our plan versus many others.
I mentioned previously how our risked resources have grown over the past 16 months and certainly how that impacts our proven reserves. We're going from a reserve replacement ratio, basically replacement of production on a 5-year period that previously was 177% in this plan, to something close to 400%.
Our portfolio today is better diversified, and now we see U.S. production keeping up with the rapidly growing international production over the next 5 years and our production gets stronger every day.
Last year, our plan showed some very strong projected annual growth rates for reserves production and cash flow. We didn't show debt adjusted numbers last year, but we have gone back to last year's plan and we've put them on a debt adjusted per share basis. This is something that we look at very closely internally. We believe we're strong believers in looking at debt adjusted per share when you're looking at growth. There is no free money when you look at it that way, and that is something that we think about all the time. You can't borrow your way to growth when you're looking at things on a debt-adjusted basis. You can't issue shares and just talk about growth and do it when you're looking at it on a per share basis.
So we put -- we took last year, so we put it on a debt-adjusted basis and you could see, just as a point out, the reserves are based on 5 years of projected reserve additions starting from '11 through '15, and then when I show the current year, it's '12 through '16, so it's a 5-year look ahead. That reserves production, cash flow -- cash flow production both at greater than 10% debt-adjusted growth rate per year. And of course, the cash flow, as we talked about last year, was growing faster because our margins are growing, some of it is because of the lower cost, large projects and also because of a switch to more liquids in the portfolio, which is helping as well.
When we entered into the Marcellus transaction, one of the comments that I made was that we look at our debt adjusted numbers and said, first of all, when we considered Marcellus, we did not want it to be dilutive and as a result, we looked at it very carefully and we said, in fact, that the Marcellus was accretive on all 3 of these metrics.
So when you roll it all off, the Marcellus, the new plan, everything going forward, you see a much different picture this year. That's what I mean about a dramatic change. You can see that all growth rates have increased significantly. They're strongly, they're deeply into the double-digit category. 18%, 15%, 22%, the average of those is 18%, 18% debt adjusted per share growth rate. As David mentioned, the price assumptions during the back behind these cash flow numbers and the economics, I think they're very realistic. In fact, if you look at oil, we use the WTI flat $90 for several years and then going up 2% a year, Brent $10 higher. So there -- I think we're not making this on price. We're making this in terms of true value creating projects.
As I look at the competitive space, I believe these debt adjusted growth rates should place Noble Energy as one of the best mid- to large-cap performing companies. Of course, we have to execute this and we have to deliver it. But clearly, I think we're in position to create a lot of value because we do believe debt adjusted numbers correlate highly with value creation. Our research report that was published earlier this year by one of you, I look at the debt adjusted metrics for 16 mid- to large-cap companies over the past 5 years. The median was 4% when you look at the average of the 3 metrics. The median was 4%. The best quartile started at 8% and we're selling here at 18% forward-looking. As I look at that report, there was only one other company, only one other company of the group looked at that had a higher average growth rate over the 5-year period, and that company started at a much, much smaller base than what we are starting as Noble Energy today. So again, I think this is not only are the numbers stunning but I think they're going to show to be extremely favorable compared with the competitive landscape.
And the other point I'd make is keep in mind that we're doing this with a diversified portfolio. Because it's not only about projected value and projected growth but it's also about risk. And we all know that if you can do it in a portfolio of 5 core areas and diversified it and deliver the performance, the overall risk landscape is much different than if you're doing it with a single play in a single commodity. There, you're just betting on everything turning out right for that one thing. We're not betting on everything turning out right. We have ways to manage and move and optimize capital among our diverse set of opportunities.
So where does all this lead? You'll see all the pieces as they add up. Similar to last year, we're providing a snapshot of what it looks like 5 years out on -- and again, these are on a none -- these are just going to an absolute non-debt adjusted basis. We expect production to grow 17% per year to just under 500,000 barrels equivalent per day. A big number.
The reserves are projected to be about 2.7 billion barrels or 2.5x our year ending 2010, and with the capital that we've plugged into this plans, that would result in an overall F&D cost average over the period of time of about $10 a barrel. I'll take that. I will take it, especially given the nature of the projects and the commodities that we're delivering. We will try to beat it but again, I think that is going to look very good in the competitive landscape that we have. Similar to last year, we're seeing cash margins grow, delivering very healthy returns. And again, while this year's program consumes more of our near-term cash flow than the last year's plans, we do see ourselves moving towards a period of free cash flow, as you can see there in last year, 2016, about $1 billion of free cash flow.
I think more importantly, though, as we move through today's program, we intend to show you a very clear and convincing case of why the reinvestment of these cash flows provide strong return and with this, hopefully, a rapid accretion of value.
So things to look out for, the themes that we'll be focusing on are highlighted here. Clearly, as I've talked about before, a deep and diverse portfolio of assets, high return investment opportunities. One that does provide us a lot flexibility as we go forward; second is an organization that is proving itself of being capable of exceptional execution. We said it several years ago that we wanted to match up what we viewed as the best-in-class exploration program with the best-in-class organization in terms of executing and developing these major projects. And I think we're making great progress here. And again, we don't want to forget how we got here. And so part of the theme is to show the sustainability of our exploration success and the depth and quality of that portfolio.
Our growth, I think, this year is more transparent than ever before. We'll certainly try to highlight that going forward. This is not a plan of prototypes or hopes or wishes. This is a plan of real projects, real discoveries. Many of them sanctioned and being built today and many of them underway. I've been at this a long time. And as I referred to earlier, I don't recall a plan #1 that is this transparent but also one that can show a decade of double-digit growth.
And finally, a theme of continued financial discipline. Risked and uncertainty are being managed as we go throughout our business every day. We're maximizing -- we are truly working to maximize the likelihood of taking what I think is a one-of-a-kind plan and turning it into reality for all of us.
So with that, I'm going to turn it over to Dave, who's going to start diving into the details.
David L. Stover
Thanks, Chuck. As you can see, why we're so excited to be here today and have a chance to review this with you this morning. It doesn't seem like it's been 16 months since we did this. As Chuck said, a lot has changed over that period of time. It is a tremendous time to stand here and talk about what's going on here at Noble. When you look at it -- I'll start off with an overview of our activity and outlook, and then the rest of the presenters will take a deep dive through each of the core areas and also talk about some new opportunities that are in earlier stages of development.
Looking at our strategy, as Chuck mentioned, they really haven't changed. We still believe that a diversified and balanced program and opportunity set of portfolios that's really set up to help mitigate risk and provide investment choices. With the recent addition of the Marcellus assets, we now have 5 core areas, each with rapid growth rates, strong returns and significant running room.
We've been fortunate over a period of time to have made a number of the large discoveries, and now we're focused on turning those discoveries into proved reserves and even more importantly, production and cash flow. At the same time, we've put a lot of effort into our major project execution, especially in the offshore arena with some of these new projects, at the same time while we're expanding our onshore portfolio in our 2 core areas.
We've had great success of our exploration program and we're continuing to build off that success. As Chuck mentioned, we believe in sustainability of the program, we'll continue on the build of that success with a number of opportunities in our core areas, while we're also expanding the program into some new areas, which Susan will dive into in a little further detail.
At the same time, we'll continue to manage the portfolio. At the time of the Marcellus JV, we mentioned we were set up to move in to some divestments of some onshore properties and I'll walk you through a little more detail what we're talking about there. And as Chuck mentioned, we have reflected that in our production growth outlook.
Before turning to some of the highlights of the operations, I first wanted to mention a few of our EH&S initiatives. One of the things we strongly believe in is that how you manage this portion of the business is a strong reflection on the company as a whole, and we do strive to take a leadership role in this arena in every area where we operate. Our operating practices are governed by a global EH&S management system that provides the framework for how we operate and our operating practice around the world. One of the things we have taken a lot of pride in is getting involved, and we have and we'll continue to get involved in local community awareness in the areas we operate. We also helped to lead the expansion and enhancement of the Deepwater containment system to return to work in the Gulf of Mexico.
One item I did want to mention just a little further is the water management strategy. This is an area that's becoming even more important as we go and expand in the onshore arena. It's an area we've dedicated more resources to over the last couple of years. And recently, we've just secured water rights, additional water rights, to help our operation in the DJ Basin while we continue to test new ways to recycle water for reuse in the areas that we operate.
When you look at the operational highlights, I'll just touch on just a few and provide just a quick overview here before the folks get into a lot more detail. In the DJ Basin, Ted will start of by giving you some new insight in the recent well results. I will say, I could not be more pleased with the progress that's been made in this arena and the momentum that we've continued to build, and I think you'll see that from Ted's presentation. John will then walk you into our new core area, the Marcellus, again, focusing on the rapid growth that we've seen in that already, kind of outline the outlook for the future and then talk a little bit about what both of us, both Noble and CONSOL bring to this unique joint venture as a set up for a great opportunity moving forward. After a short break, John will come back and talk about that Deepwater Gulf of Mexico. And we're right on the verge within 4 months of bringing on 13,000 barrels a day as net new production in this area, and we still have an extensive and deep and valuable portfolio of exploration opportunities to pursue in the Deepwater Gulf.
Turning to international, Rodney will start with West Africa. He's got a great time to come up and talk about West Africa story right on the heels of Aseng now being online. As Chuck mentioned, it's a extreme amount of pride that we have in the group that's pulled that project together. I'll actually show you a little more about that benchmarking that he referenced it as we look at how it stacks up to some external parameters. The other thing, it's a nice time that we'd be talking about is a significant and really sizable discovery in this Carla prospect that was recently drilled and we announced this morning out there, as we return to exploration in this part of the world, which still have a tremendous amount of running room.
In the Eastern Med, it's all about keeping Tamar on schedule. The group's doing a great job keeping it on schedule, set up for commissioning in fourth quarter, late next year, 2012. At the same time, we have 3 rigs in this part of the world, focused on a mix of exploration, appraisal and development activity.
And then Susan will wrap up the operations piece by pulling together the overall exploration program and then touching on some of these new areas that we think have the potential to be core areas for the future.
So let's turn to some of the information that Chuck alluded to. When you look at the net resources, net risked resources, there are now 6x our proved reserves at 7.4 billion barrels of oil equivalent. Almost half of that is made up in red there by the discovered unbooked resources. These resource have been discovered. It's not yet booked due to timing of sanctioning or timing of where they are in development phase. If you look at the unrisked resource to the right, it's up to 14 billion barrels of oil equivalent. Additions there are some of the core exploration activity and also some of the activity in some of the new areas that we'll talk a little bit more about. We talked about the diversified portfolio. You can see that in the pie chart in the upper left. That's the increase of mix between the offshore projects and offshore impact and the Deepwater Gulf, Eastern Med and West Africa and then the onshore programs in the Marcellus and the DJ Basin.
Here's how the growth has happened or the impact of the growth over the last few years. You can see from 2008 now to 2011 little over 150% growth in the risked resources, and as was alluded to earlier, that the most significant rate of change in that growth has been over the last 16 months as it's moved from 4.2 billion barrels of oil equivalent up to the 7.4 billion barrels of oil equivalent now.
Where did that increase in risked resource come from? Here, we depicted the main contributors for that. Obviously, the Leviathan discovery had a big impact. If you remember, when we visited with you last June, we were talking about the resource range on that. We're fortunate the resource range actually turned out to be -- would actually looks like now post discovery. They're right on target. The lat added about 0.6 billion barrels. The horizontal Niobrara play has continued to be derisked and the momentum that we built in that adding significant risked resources. I would say this is one area where I expect it'll continue to grow, and Ted will allude to that in some of his discussion. The Marcellus JV alone added risked resource of 1.3 billion barrels, slightly more than our total current proved reserve base of 1.2 million.
So the fourth piece and -- well, before moving off of Marcellus, I'd say similar to the horizontal Niobrara. Again, John will show you some things there. I expect this is an area that we have an opportunity to continue to expand that number and see it continue to grow.
And then the fourth component is the new ventures and other additions. These are things like Nicaragua risk-weighted, France, deeper drilling in the Eastern Med, some onshore new positions that we're building to test additional areas in the U.S.
So how this to translate into proved reserve outlook? Here, we show, when you look at the end of 2010, we are at 1.1 billion barrels of oil equivalent and you can see the mix between U.S. and international, and you see how that grows at roughly 20% compounded annual growth rate over the next 5 years, over 150% -- around 150% growth over that period of time, so about 2.7 billion barrels of oil equivalent expectation by year end 2015. On the right side, and Chuck alluded to this already some this morning, you'll see the rapid increase in reserve replacement rates over the next 5 years compared to the past 5 years. So from 177% through the last 5 years, to expected close to 400% over the next 5 years and again, at about $10 a barrel oil equivalent, as he mentioned.
So how's this translate into our production outlook? On the left side is everything included are production outlook from 2011 through 2016. One thing you'll notice, the slope in the curve is a little less in the early years and a little greater in late years. The biggest part of that is a reflection of the fact that, as Chuck mentioned, we have built in about a divestment of close to 20,000 barrels a day towards the end of 2012 beginning of 2013, that's reflected in the notes there. But the other thing to notice is the bar charts on the right. When you look at the stunning growth rates in each of those areas, whether it'd be from the DJ Basin in West Africa, 14% to 15%, building up to the Eastern Med at 20%, the Deepwater Gulf close to 30% and then the significant buildup in the Marcellus over 100%. All 5 of these rates for these areas are contributing to the underlying growth.
Here's just a snapshot or depiction of the divestment program. You can see what we're really talking about is focusing and concentrating on our core areas in the onshore U.S., essentially around the DJ Basin and right around that area, along with the Marcellus and divesting a number of positions that are, I'd say, more scattered, everything from the Rockies and the Mid-continent, Gulf Coast, the West Texas, contributing currently right around 10% of our production and under 10% of our reserve base. The expectation is we'll have this on the street, start to put these in the street here beginning of the year, beginning of 2012, with the plan to have this divested and out of the portfolio by the end of next year.
Looking at the volume profile. Over the next 5 years, you can see in comparison our liquid percentage, even with the addition of the Marcellus program, stays about the same. It's stays right at close to 40%, whether you're looking at 2011 or 2016. What you are trading off is you're trading off a portion of the percentage that the Alba LNG, lower value gas, contribute since 2011 for a bigger percentage of the Marcellus contributing in 2016. And again, as Chuck mentioned, our U.S. contribution from the mix of the DJ Basin increase, the Marcellus increase and the contributions from Deepwater Gulf of Mexico drives our U.S. contribution from closer to 50% currently to almost 2/3 by 2016 on a production basis.
Capital outlook. I want to show you the profile and how it built over time. The bars on the left show the billed from 2011, which is closer to about $3 billion this year to -- by getting the out years, you're closer to about $5 billion. Again, not only does this underpin the growth for the next 5 years, it sets up to growth for the next decade, as Chuck mentioned.
Again, on the balance and diversified look at this, we've got a few pie charts. The top one shows by area and the bottom one by type of development. The largest use of cash, of capital, over that period of time, you can see on the bottom, is our onshore horizontal developments, the combination of the horizontal Niobrara and the Marcellus programs which combined, are just around 40% of the capital use over that period of time.
And here is the capital changes, very similar to what we've showed you on the risked resources chart. It's the same things that are contributing to this program. The Marcellus JV highlighted here first as a new use of capital and you saw the growth rates, and John will dive in to some of the expectations for that program. We've also highlighted on there are the Keri [ph] portion assuming that Keri [ph] is in place through the whole period of that 5 years, and that's a little over $250 million per year. Then you see the horizontal Niobrara program. As we continue to expand that, as we continue to derisk and build momentum in that program, that set a way out for you. And then the Leviathan discovery in the other Eastern Med explorations you can see continue to build on from where we were last year and what we talked about last year.
I want to take a little different approach this year and layout our major project development lineup just a little differently than we did the last year. A couple of things are the same. We still show the starting point or the initial production of each of these major projects and programs, and we do show a predominant product mix whether it's oil, gas or in this case now, LNG as you can see out in the Leviathan and West Africa gas. But what we want to do is represent a relative impact to the company size, both on resource and after-tax net present value. What's nice to see here is that 2 of the larger components, the horizontal Niobrara and the Marcellus, are both projects that we're ramping up already. A third big component is the Tamar Project, which is almost a year away from commissioning, not that far ahead of us yet. The other thing I'll point out is when you look at the bottom line and you look at some of the oil projects in green down on the bottom, I think you'll hear more about each of those projects as we go through the presentation. And I think what you'll hear is an opportunity for each of those to continue to grow from some things that we can do both as the projects start up and as we get further into development of each of those.
Chuck mentioned it and an emphasis ever since we had some of these very large new discoveries was transferring our success and exploration to success in major project execution. And it's extremely exciting to be able to stand here today with Aseng online and up to 50,000 barrels a day already.
Now we've talked about the external benchmarking and we show that here on the right. The plot shows the benchmarking done by an independent project group that came in and actually took a look at Aseng and went through our project sanctioning [ph]. And at that point in time, they essentially indicated to us, we were right around the 50th percentile on cost for this type of project when they normalized everything. And now, they come back and take a look at it now that the project essentially started, and we've moved from that roughly 50th percentile up into the top 10%. Our big judge as far as major project execution, a major accomplishment for our folks, especially on the first the major offshore, big new project coming out of box.
So the challenge and the opportunity is how to transfer this learning to all our other projects, and some of the bullets on the left side indicate some of the things we're focusing on. One of the keys is the integrated front-end loading, that's everything from how we do appraisal work to how we expect to start off the project. Another big key is the partnership, and I mean truly a partnership with our contractors and suppliers from the very early stages of project implementation.
So where's all that lead on these major projects? Again, we wanted to highlight the impact of these in total over the next 5 years. When you look at it, this combination of projects by 2016, we expect to be contributing around 340,000 barrels of oil equivalent per day, generating operating cash flow, and this is cash flow after taxes, of around $5 billion per year by that point in time, which will also generate free cash flow of around $1.6 billion.
The project is self funding over that 5-year period. And as you look at it by 2014, its really starting to breakeven and composite on cash. We've also set it up, so you can see we've grouped the offshore projects together and then the 2 horizontal plays together, then you can see the relative impact on both those different sets of projects.
So in summary, I believe we do have a real exciting story and program to review with you today. We're positioned now to reap the benefits of the strategy that Chuck discussed and in just the last 16 months, we've seen tremendous growth in our risked resources, driven by new discoveries, success in each of the areas and the addition now of a fifth core area. The resource growth is driving reserves increase by 150% over the next 5 years and a doubling of production over that period of time. With all 5 areas showing substantial growth, the portfolio continues to maintain its balance and diversification, which we believe is so important to risk management and risk mitigation. And it's a great time to be sharing this story on the heels of the Aseng startup and now the sizable Carla discovery also in West Africa.
So with that, I'll turn the podium over to Ken to highlight the financial framework that we've built to support this growth.
Kenneth M. Fisher
Thanks, Dave. I think the takeaway on financial framework is confidence in our ability to fund and deliver. As Chuck laid out and Dave, you've seen a very visible growth profile. And since in early 2010, late 2009, we've had pretty good look out into the future here and are able to build a plan that enables us to fund the business and deliver the value. What's critical for us is, first of all, the ability to fund long cycle major projects over an extended period of time in the volatile commodity price markets. So we built that into the plan.
Secondly, as Chuck alluded, we want -- as the business sets up our growth, we want to be able to continue to fund material exploration program through time and keep the hydrocarbon funnel flow. So we built that into our thinking as well.
And lastly, we continue to want to have the financial flexibility to take advantage of business opportunities as they arise. So as we kept ourselves strong, we were able to act effectively on, for example, the Marcellus transaction this year. Also we spent a lot of time thinking about how do we manage the downside, how do we manage the tail risk and keep the business safe as well. So I'd like to take you through that today.
First of all, as you've seen, we have a significant step-up in the scale of the business moving forward versus the June 2010 analyst projections. And what underpins the step-up is the strong cash flow growth or DCF growth depicted here. It's a 22% annual compounded growth rate through 2016. This year, we stepped up from about $1.9 billion in 2010 this year, $2.5 billion. And as we bring the Galapagos and Aseng online, next year approaches $3 billion. So we have a strong, fundamental cash flow, which will really help with funding the capital plan that Dave has laid out. By 2014, $4 billion, which is reflecting the full year of Tamar and Alen online and well over $6.5 billion by 2016. So this plan is underpinned by strong operating cash flow growth and that will be a key component of the funding strategy.
In terms of the strategy, what is it? First of all, we spent a lot of time thinking about how do we ensure we can deliver through the commodity price cycle. And so we built very strong liquidity and intend to maintain that liquidity and in fact, scale that liquidity up over time as the business grows. I'll talk a little bit about that in a minute. Two, we continue to maintain conservative balance sheet and highly value the investment grade rating. As an example, we had the Marcellus transaction, before that, we met with both Moody's and S&P took them through essentially the plan you see here today and had our rating and outlooks reaffirmed. So we'll continue to manage that and guard that carefully.
In terms of funding. As we move forward, where will the funding come from? One, very strong cash on hand; two, the strong operating cash flows that I just showed you; three, on October, we renewed and upsized our credit facility substantially to ensure the liquidity as the company grows; and lastly, we will be active in the debt market. We have some funding needs in 2012 and through '15. We think that's very manageable, and we'll look to pre-fund some of that as we move through time as we demonstrated over the past couple of years. So we'll continue to be opportunistic as we move through time in that regard.
And then in terms of risk management, I would say we have a very robust and integrated approach to risk management across the business. And this is not something we show the board a heat map once a year, but this is something we try to live with and deal with daily to protect the downside. Specifically, we have a commodity hedging program, we have a robust ERM process in place, we have very robust insurance program actively, managed credit and counter-party exposures with our credit team, we do extensive cash flow and risk modeling to ensure we are robust through the cycle and we treat compliance and controllership very seriously, both in terms of some of the things Dave talked about in terms of environmental and regulatory compliance, and in terms of that just legal compliance and in business ethics. So we really spent a lot of time to manage the downside as well.
And lastly, we actively manage the portfolio in conjunction with Chuck and Dave, there's a lot of capital discipline here. And you can see that through time, we've continued to prune the portfolio and reinvest those proceeds in a more focused and higher returning manner. So that will also be a component of our funding strategy as we move through 2012.
We embarked from a position of strength, $1.3 million of cash on hand at the end of third quarter, $3 billion of liquidity before we upsized our credit facility. Strong metrics in terms of balance sheet debt metrics, very good position in terms of the peer group and good relationships with the rating agencies and a very well-managed maturity profile. Over the next couple of years, the maturities we have are the 2 installment payments remaining on our Marcellus transaction, and then we have a small public debt maturity at 2014, all very manageable.
As I said, liquidity is key to the thinking and we built a plan that maintains an essentially scales up our liquidity through time. On the left-hand, you'll see how we compare versus our investment grade peers on liquidity as a percent of total assets. And you can see that, that range in the 15% to 20% range puts you at a very strong position versus the peer group. And then on the right, the S&P liquidity metrics, which is sources and uses of liquidity, again, very strong position compared to our investment grade peers. And our thinking is integrated with our cash flow and risk modeling, and as we scale the company, we plan to scale our liquidity accordingly.
The key component of our liquidity, which we define as cash flow or cash on hand and available revolver capacity is our revolving credit facility. This year in December, we would have had the prior facility go current and step down from $2.1 billion to $1.8 billion level. And as we looked at that, we've been actively monitoring the market over the last 2 years. We're ready to act as we kind of started to see what we thought were attractive bottom of the market, and we gave a lot of thought to how to scale the facility for the future. So we upsized the facility to $3 billion with the market after the summer vacation season and got it done very successfully despite some headwinds from the European crisis and some of the fallout from the European banks.
So we have a 5-year new facility in place. It's attractive funding, it's very flexible and it's got a 5-year term, takes us through 2016. And additionally, we had a number of things that enable us to do more -- add more flexibility in terms of funding our international operations. And we have a few accommodations in the program also if we would like to do any project financed on the gas monetization project later in the decade. So well-positioned and supporting the strong liquidity.
As we look through 2012 and I think if you look over the past few years, we've continued to manage our financial position to stay strong. We would see this continuing into the future. So you see actually as we move through 2012, we have the available liquidity and we have the divestment proceeds. We'll see ourselves end up -- project to end up essentially in the same position maybe a little stronger as we move through 2012. And we'll, I think, continue to work to manage forward in that way and we have a lot of runway and flexibility to do that. So we feel quite confident.
In terms of the enterprise risk management, I would say this is a key differentiator for Noble from my past experience. We have a very much integrated program, we cover this topic every board meeting, we discuss it as an executive team and really think and plan that way. And I would say John Lewis will talk later today about how -- getting back to work in the Gulf of Mexico. But I would -- part of what our -- success there, I would attribute to the risk thinking, Chuck and the exec them had a risk -- well, essentially, a risk seminar the first Friday in May last year and addressed what could happen in the worst case for Macondo and what would we do about it. And I think that basically 8-hour session gave us a very good handle on what was probably going to play out and gave us a real head start in terms of what do we need to do to address that and how to get ahead of the power curve there. Because increasingly, you look and see in the world when the risk hits you, it's the velocity and the change that happens, so your ability to react, respond and proactively move out as an organization is a key differentiator.
And we've got this embedded deep in the organization. It's built in with our forward planning. And in fact, all the business areas, all the major projects have a risk register and manage this. So I think we feel very good about that. We also feel good about our disclosure and our 10-Q and 10-K. We lead the peer group in terms of filing and we also are very attended to our risk disclosures as well and get very good feedback about that. So we take it seriously.
Commodity hedging is a key component over the program as well. You can see here the next couple of years, hedge book laid out. We have the authorization from our board to do current year plus 2 up to 50% of our volumes. In 2010 and 2011, we had special authorization to do above the 75% on North American gas. These forward projections take in account the divestment and the growth in the Marcellus. You can see we're well hedged versus the peer group and maybe in particular, take a look at the position in terms of the gas compared to the current strip. So this is a tool that we use to ensure the predictability and reliability of the cash flows and de-risk our ability to fund and deliver over time. It's been a successful program and we'll continue to move it forward.
Cash flow at risk modeling. I mentioned, here's a conceptual slide of what we do. Basically, we look at our cash needs which are depicted on the X axis and then the distribution of potential cash flow at different commodity prices and different business scenarios, and then model this, test it and look at our liquidity level and ensure that we can fund all essentially all scenarios. So from our modeling work, we're confident even in a 5% worst case, we can deliver with our available liquidity level. And as before, we have to make any adjustment as you may do. So we remain robust and flexible there.
So as we look forward, liquidity level. We'll continue to scale our liquidity as the company grows, so we'll move from where we started in '09 at about $1.5 billion liquidity target or a minimum up to $2.5 billion for 2012 and then ultimately, to the $4 billion level by 2016. And as I said, the revolving credit facility is in place to essentially handle that growth that's out [ph]. And then you can see, we maintain strong projections through the time as well, which are represented by the blue bars.
And then in terms of financial projection on metrics, you can see last year, we showed a forward plan of about 33% debt-to-capital ratio, we're little more elevated this year as we move through time. But I think still very well within our rating agency metrics and a very manageable level. In fact, part of the -- if you look on the left, the blue portion of the bar is representative of the additional debt we carry to ensure we maintain the targeted liquidity levels. So I think we feel very robust on our metrics and as I said, we'll stay close to that rating agencies and make sure their comfortable through time.
In terms of funds from operations, the debt what are the CF [ph] and key metrics, you can see we maintain solidly BBB ratings or higher. So as I said, the takeaways are you will continue to see us work closely with Chuck and Dave to ensure we have capacity to deliver, expect us to remain very disciplined, expect us to keep our metrics and measures well in the investment grade range and we're confident that we have the capacity to deliver.
So with that, Ted Brown will now take us through the Niobrara DJ Basin.
Ted D. Brown
Thanks, Ken, and good morning to everyone. Today, I will be sharing our DJ Basin story with all of you, and a few key points that I'd like to message as the presentation unfolds. Today, first of all, you'll note that there are a number of technical and operational achievements that differentiates Noble from other companies. And that has allowed us to advance our confidence in the horizontal Niobrara play. And secondly, the DJ Basin will play a significant role in Noble's future growth. It's bigger, it's getting better and the results are exceeding expectations. And third, we have a very well thought out plan to execute this growth. It's all about continuous improvement while we accelerate our activity levels. And then finally, the northern portion of the play outside of Wattenberg continues to unfold as we expand the play to the north.
If you look at a list of some significant accomplishments or breakthroughs that Noble's been able to achieve over the past year and a half, it demonstrates that Noble is a leader in innovation and technology in the DJ Basin. I'll just point out a couple of these. Through the limited drainage from a vertical well, we can drill horizontal Niobrara wells in areas of high density, vertical wells that yield significant results similar to our Gemini well that we drilled back in 2010. No interference, solid, repeatable results and we'll demonstrate to everyone today that the horizontal Niobrara play in Wattenberg works, whether it's in a densely drilled area of the field or whether it's in some lesser developed modular areas as we continue to expand to the north and east.
And we've also been focusing on how to increase recovery from the Niobrara. We are currently conducting a pilot test with some very closely spaced horizontal wells. And I'll expand on more in a minute.
And then finally, no other company has collected more data and understand Niobrara better than our technical experts at Noble. We've been able to drill and complete more horizontal Niobrara wells than any other operator and we have a very integrated, technical operations team.
The DJ Basin is very impactful for Noble's future growth. We are expecting a 15% compounded annual growth rate over the next 5 years, essentially double the production. And 1.3 billion barrels of oil equivalent of net risked resource potential. We've dramatically increased the development side of the portfolio. And as you'll hear more in a minute, we think the price is even bigger.
Net production close to 70,000 barrels of oil equivalent per day and it's liquid rich. We're estimating that the liquid stream as a percent of production will grow over the next 5 years from 54% to 66% with an active program in both the horizontal and the vertical programs.
And then when you examine our knowledge of the basin and you couple that with the ability to execute in a responsible and prudent manner, we believe we have a superior recipe for success.
Over the last year and a half, our net risk resource potential in the DJ Basin has increased 60% to 1.3 billion barrels of oil equivalent. We've only been able to move a large portion of our resource base from exploration to discovered/unbooked and dramatically increased the development side of the portfolio and we're continuing to work every day to add to that number. If you break down the 1.3 billion barrels equivalent, we have proved reserves of 300 million barrels net to Noble at year-end 2010, which I need to point out, only includes but the handful of the horizontal wells. Our risk discovered/unbooked resources are located in that Wattenberg field and equates to over 800 million barrels of oil equivalent, 600 of that is Wattenberg, Niobrara horizontal potential. So the play holds tremendous upside and will drive growth for us obviously for many years to come and we plan to exploit this in a number of ways that you hear about today, whether it's pad drilling or extended reach laterals or the potential through increased density. And then finally, we have a very robust, integrated exploration effort, where our people have leveraged the vast amount of data to unlock areas where limited drilling has occurred while pursuing a number of horizons where we know the hydrocarbons exist and if you note later in the presentation, our exploration efforts are essentially driving the expansion of the Wattenberg field then to the north and to the east.
So let's focus now specifically on Wattenberg horizontal Niobrara play, where we believe Noble's entire position has been derisked and is essentially development mode and the map depicts -- we have divided up the field into 3 producing areas. The high GOR portion of the field is depicted inside the red band, the area within the green band referred to as the core area and then our ever-expanding area to the north and east are referred to as the extension area.
So over the past year, Noble has proved the horizontal Niobrara play in Wattenberg is working, it's repeatable even in these high vertical density areas of the field and then we continue to expand the economic limits as we go to the north and east by yielding vastly improved results over marginal vertical wells and the results continue to improve every day as I'll show you in a minute. We've ramped up drilling and completion activity from the recent addition of our fifth rig and we've more than doubled our frac capacity in the past couple of months. Our production play is up threefold in just the last 6 months alone. So tremendous potential in the play within the Wattenberg field with Noble with over 600 million barrels of oil equivalent of net risk resources across the field and, as you'll hear in the presentation, there's still considerable room to grow in the play.
So we've learned a great deal over the past several months, what this graph depicts is some of the outcome of these operational learnings. When you look at the last 18 wells that we've completed in the play versus our earlier wells almost a 25% improvement in EURs and initial 60 day averages. And I always like to point out that rather than just focusing on peak 24-hour rates we try to look at a wells performance, initial performance, anyway over a 1- or 2-month period.
Further evidence then of how the key learnings over the past year have yielded improved results and production growth, we have a combination of a couple of things here. Incorporating technology to unlock the play using everything from 3D seismic to well bore orientation to longer laterals, larger stimulation treatments, frac fluid design and then you combine those things and Noble's execution efficiency, which is now allowing the play to ramp up activity level, while what we think is transitioning into a very repeatable level process and operation, as you can see here, there's a dramatic improvement in production and well performance since inception of the play.
Our technical and operational learnings coupled with this execution efficiency then are yielding improved economics and as I mentioned to you earlier, we've segmented the basin into 3 areas. The higher GOR area of the field, where we witnessed liquid yields on the order of 45% plus; core area, where GORs are lower and liquid contents are averaging over 65%; and then the extension area of the field, where we've been able to successfully drill and complete very low GOR wells and witness over 75% liquid yield. So focusing on returns now, Noble has experienced a great deal of success over the past year improving our oil and gas recoveries. And as the graph illustrates here, we've been able to essentially double our after-tax rate of return in the extension area relative to our previous results and in tight curves. And if you look at the core area, then our returns have improved at least 50% from our previous estimate. So we believe this is really significant. When you examine our entire 400,000-acre position in the Niobrara across the Wattenberg field, across all 3 areas, we're averaging on the order of 45% to 50% rates of return and we're still very early in this stages of this play. So it's about applying those technical and operational learnings and now being able to focus the majority of our activity in the higher liquid yield areas of the field and delivering some very strong economics.
So just a couple of points on the improvements that we've made over the past few months on the drill site, we've cut drill times by a third and we've even witnessed a record 7-day spud to rig release on a 4,500-foot lateral. On stimulation side, since the drill times have improved, we've been able to focus on accelerating completions, improving our efficiencies, making sure that we have all of the resources in place to execute. And as you can see from the graph of the third quarter, we completed 25 wells, dramatic increase over the prior quarters and now we're at a pace of completing about 10 to 12 horizontal wells per month. Essentially, we'll deliver our 2012 plans.
So Noble is a company that the drives results through continuous improvement and the horizontal Niobrara play obviously is a testament of that for Noble. I've highlighted just a few of the key field tests that have yielded significant confidence in the project over the past year and a half and, again as I mentioned, it's early. There's still room for improvement in the play. So, let me expand on just a couple of these proof of concepts in the next couple of slides.
We've drilled about 33 wells in what we consider the high density, vertical development areas of Wattenberg field and because we're draining less than 10 acres with a Niobrara vertical well, we've can place horizontal wells in these densely drilled areas and we've proved that's repeatable beyond just our Gemini well. Our latest well, the Tamar well, a 5,300-foot lateral drilled between 10 existing vertical wells in Wattenberg field. And as you can see, we've got vertical wells as close as 366 feet. We've encountered virgin reservoir pressure and, again, it's all due to the limited drainage area of a vertical well. But as you can see, it's still early but Tamar well is performing and comparable to our Gemini well, and we've also noted here about a 15 to 20 fold increase over a typical vertical well recovery.
The Noble operated wells Ranch 29-68 [AE29-68HN] is the most prolific and the very first extended reach lateral on the DJ Basin. We drilled this well in the extension area of the field, where vertical wells have been marginally economic. We drilled a 9,100-foot lateral in 17 days. We've stimulated with 39 frac stages for a cost of about $7.5 million. Results are still early but we think that the wells should yield over 600,000 barrels of oil equivalent, improve the F&D cost versus a typical 4,500-foot lateral by about 20%. So right now our plans for -- call for in 2012 will drill on the order and this is where we can apply it but we'll drill on the order of 10 to 12 extended reach laterals across the basin. In areas where we have limited or no vertical well control, 3D seismic has really proved beneficial particularly in areas where faulting has occurred and please note the geologic setting is a little more complex. So applying this technology has opened up our thinking, if you will, on where to place the lateral. In the future, should we be considering targeting multiple zones, what are the implications of placing an extended reach lateral? And then essentially driving, if you will, a fully integrated development program. So if you think back just a couple of years, Noble had on the order of tens of square miles of seismic in Wattenberg and in the DJ Basin and now we own or have access to over 1,800 square miles and we'll of our entire position covered over the next 3 years.
So let's shift gears a minute. I want to talk about resources, the magnitude and recovery of the Niobrara resource and when you compare it to other liquid rich unconventional plays, the Niobrara has a tremendous amount of oil and gas place on the order of 25 to 40 million barrels of oil equivalent per square mile. So one needs to ask the question then, how do we address the recovery in the Niobrara? Especially when densely drilled vertical areas in the field will recover on the order of 2% or less of oil and gas in place and even with the combination of vertical drilling and horizontal development at 160-acre density, we're still only recovering on the order of about 6% of the oil and gas in place. So in order to help was out here visualize, in the next few minutes, we'll address the recovery question with the help of some animation that we've built to better visualize what's occurring and what's being planned for the Wattenberg field and so with that, let's roll this very short video.
So just a couple of things that I want to point out on that video, we're drilling this pilot project as we speak. It's a 9-well pilot that we've mentioned here. 4 wells on 1 pad, 5 wells on another and we're drilling it out in this extended area of the field, very low GOR areas of the field, and we're also doing it or I should say the area that we've located the pilot in is within a section that already has 18 vertical wells already drilled. So we're focusing on recovery, we're focusing on execution and we've identified close to 4,000 potential horizontal Niobrara locations in Wattenberg and plans are in place to double the activity levels in the next couple of years and here we've listed what will enable Noble to accelerate that program and differentiate ourselves. We've secured additional fit for purpose rigs, of which 2 of those will arrive in the fourth quarter of 2012, and then we have signed service agreements in place for dedicated frac crews. And as Dave mentioned earlier and as we mentioned in the video, water management is really key and we've been diligent over the past year in procuring water supplies to ensure our execution and we've focused looking at water resources, in what I call a holistic manner, from procurement to transportation to storage to disposal to the recycling of water. We have an entire team of people in place and that's been their only job, is to manage our water resources.
On the organizational side, we're hiring more personnel to support our efforts and then we have a new 65,000-square-foot field offices that's being built up in Greeley that we'll move into in the first quarter of 2012. And as the graph illustrates here, our planned horizontal activity levels will help drive our 15% compounded annual growth rate over the next 5 years and beyond for the DJ Basin. So with approximately 3,900 locations, what would Noble have to do in order to execute and reduce the inventory level from, let's say, 16 years to 20 years out to let's say 10 years? And if you reference the accelerated portion of this graph, we've attempted to further understand how to accelerate the play and essentially reach a 10-year inventory goal. So what does Noble need to start thinking about, concerning breakthrough levels of activity, to accelerate the monetization of the project and it's just something that we're thinking about. We're continuing to evaluate the scenario as we speak.
Takeaway capacity, if you look at the success of the play and all the accelerating activity levels then plans are in place to increase takeaway capacity. Natural gas processing in the DJ Basin will double over the next 5 years and on the oil side, we've secured markets with 5 separate outlets for our oil and, again, takeaway capacity will essentially double here year over the next 5 years to accommodate all this success and we've been working very closely with our marketing partners to stay ahead of our activity levels here in the basin.
So outside of Wattenberg, Noble has a significant acreage position that we continue to appraise and evaluate and as we've noted, we're testing and evaluating the play in a number of ways incorporating all the learnings from Wattenberg coupled with an aggressive 3D seismic program, and due to the fact that we have limited infrastructure in this area, the DJ Basin, and we are not faced with near-term expiring leases, Noble has been focusing on Wattenberg, where we can immediately monetize the play, but right now our plans call for operating one rig in the program in 2012 continuing to appraise, continuing to evaluate. But what's encouraging here is that we are continuing to understand and unfold the play, if you will, as we've witnessed a dramatic extension of the economic boundaries of the Wattenberg field and we're taking those learnings and applying a very integrated process and plan to those lands beyond just the Wattenberg field.
This is our production outlook over the next 5 years for the DJ Basin that will yield 15% compounded annual growth rate and the driver here is horizontal production, it increases nine fold. And then what's not evident here is that our liquid production from the basin doubles. And by 2016, then our liquid stream is at 66%. So let me sum it up then. Noble is positioned for dramatic growth in the DJ Basin. We've identified 1.3 billion barrels of oil equivalent of net risk-free sources, which could substantially grow as we focus on increasing recovery, whether it's through operational earnings whether it's through increased well density and even the potential of other horizons. So we've witnessed a notable increase in performance and recovery as you noted from those wells that was completed just in the last 6 months and there's really a bigger prize here, that's the message. And as our production doubles, the liquid stream continues to increase. And then finally, I'll mention that I've got a hand it to our technical and operational teams. They've been leading the effort here to deliver what Noble considers as a major project and that'll significantly impact Noble Energy, I think, for years to come.
So with that, I'll turn it over to John Lewis and he'll take us over to the other side of the U.S. to the Marcellus.
There's some really great learnings and results from the Niobrara. We're actually in the process right now taking those learnings and applying them over to the Marcellus and, in particular, we're taking the integrated subsurface approach that Ted and his group have used to have some of these great results, because we feel that's one of the real strengths of Noble. And we'll also be transferring some of the processes that they developed there to really have these great results in the Niobrara. So just last week, a group of CONSOL folks were actually up in Denver, reviewing how Noble does permitting and land work up there, in an effort to learn from that and be able to increase our cycle times or decrease our cycle times in the Marcellus.
So as David said, the Marcellus is really a great strategic fit for Noble. The lowest cost gas play in the United States. We've got a great deal structure and we got a great partner in CONSOL. The Marcellus is going to add significant value -- significant and predictable value as we move forward through very low risk, repeatable production growth.
So Noble now has a really large position. We've got about 324,000 net acreage across the Marcellus and this acreage has a really high net revenue interest, which really improves our economics. The fact that most of this acreage is actually HCP allows for great flexibility in our development as we move forward. And it results in pad drilling, which lowers the cost, not only of the drilling or the completions, but also the infrastructure development.
And with that drilling, we'll have a much smaller environmental and activity footprint. CONSOL is a wonderful partner. We couldn't be happier. Our values of safety first a net present value are completely aligned and the synergies and their experience that they have out here, they've been in this area about 150 plus years, is really going to help us in the start-up of our operations. And as we look at it more and more, the synergies we have of working with a company that owns the coal mines underneath what we'll be developing, it becomes more apparent every day the value that's going to add.
So initially, CONSOL and ourselves will be focusing this sweet spot of southwest PA, as you can see in this map. We have sufficient acreage in this area to keep our rigs busy for several years and doing so will let us be very systematic in our approach, which will greatly add to the efficiency. And the early results have been better than we originally expected. One example here is the Hutchinson pad, which was drilled on the far northeast of our acreage in the "sweet spot area." This is the first 10-well pad that the industry has drilled and completed in the Marcellus and the results are much better than we expected. It'll be interesting to see if these results extend to our large acreage position to the Northeast.
In fact, we need to congratulate CONSOL on the overall results we're seeing. This graph shows the comparison of 2 advantages of CONSOL wells with the competitors' wells in the area and Noble's original acquisition model. The blue line at the bottom is CONSOL's results from the 2008 and 2009 wells that had about a 1,600-foot lateral. The next line up, the red line, is actually what Noble's original acquisition model was adjusted for about a 2,680-foot lateral. The black line above that is a reported performance of a competitor in the area that has laterals on average of about 2,800 feet. And finally, the green line at the top is CONSOL's results from their 2010 and 2011 wells with an average lateral length of around 2,860 feet. As you can see, CONSOL's recent results have been above that of the competitor. And as we integrate the learnings we have from the Niobrara and the other horizontal shale plays we've been working on, we expect this improvement of results to continue.
So a quick aside here to talk about this $4 circuit breaker we have in the JV structure. The economics shown here for a flat gas price over the life of the well. As you can see below $4, the carry comes off, and we're heads up with CONSOL. This helps to maintain our economics even at a very low gas price and insures alignment with our partners will move forward.
CONSOL has also made great progress in reducing the costs and increasing the lateral length. And we feel that increasing the lateral length is going to become increasingly important because we're seeing about a 1:1 correlation between increased lateral length and increased reserves. So we and our partner are approaching the Marcellus as a major project. We're taking a long-term planning approach, which allows again for very systematic development, that gives us optimized timing on our permits, our well drilling, our completion and first production.
So and the building continues improvement, we have semiannual workshops planned with both operators, we'll share the learnings they have and we'll also challenge each other about why we're doing things the way we are, and ensure that we have best practices across Noble. Ted has most graciously volunteered and we'll have some of the people from the Niobrara will actually be on this joint committee to ensure that we're having these learnings shared across the company.
So with this systematic approach, it will become a steady ramp up of activity. We'll drill about 143 wells in 2012 and this will grow to about 380 wells per year in 2016 and beyond and Noble will operate about 40% of the wells.
The fact that 87% of the acreage is HCP will allow for very efficient development. This map shows the planned locations for Noble's wells through 2015. So knowing where we’re going to drill the wells over the next 4 years helps greatly with our permitting and with our infrastructure build-out.
This map illustrates that CONSOL is also drilling -- their drilling is also planned for the next several years. And if you look at the call out map here and compare it to previous slide, you'll see that both companies will both drill in basically the same general area. Again, this is very efficient for infrastructure build-out. We just have to build into one area, gather all that gas and then move forward.
And as I just mentioned, the pad drilling allows for really efficient installation and expansion of our gathering system out here, which will jointly owned by both companies 50-50. The covered line showed where major trunk lines are going to be running. And then for each pad, we'll run laterals from the trunk lines up to the pads to gather that gas. And once we gather the gas, we have processing and transportation contracts in place to be able to handle our production through mid-2014, ensuring that we can actually market our product and bring it online rapidly as soon it's ready to produce.
And we're currently working with CONSOL to develop other options for the post-2014 period to be able to move and process our gas. We believe that Noble will bring real partnership -- real value to this partnership and as what Ted has shown you, we've learned from Niobrara, we've learned from other horizontal plays as we integrate that in and one of the most important, I think, is this integrated, systematic subsea approach.
And then we'll also bring the other project management skills of just how do we treat and run this as a major project, which we believe, you're going to see continuous improvement in the results as we get in here and help CONSOL work on this.
And are going to be ready to operate January 1. We have feet on the ground. We've secured office space in Canonsburg, PA. We've incorporated Noble's experience at Wattenberg and organizational design and, as I mentioned, we'll be utilizing several of the processes that have already been developed there to have efficient operations. CONSOL has been a great help for us lining us up with service companies, we're ready to go. And as we showed you before, the integrated well results have been better than we have expected. And as a result, the production ramp is underway. We'll be exiting the year at about 80 million a day net to Noble.
This is our longer-term outlook of what we feel the Marcellus will deliver to Noble. Approximately 85% of our capital spend over the next 5 years is on the drilling and completing of wells and this results in a very rapid production growth. Followed by a long plateau of net production and the 900 million to Bcf a day range.
So in summary, the Marcellus is a unique opportunity for Noble. We've got a great partner and the lowest cost gas play in the U.S., and the low risk, predictable nature of the wells leads to rapid significant production growth and a fixed core area for Noble. As we continue to work with our partner and leverage our learnings from across the company, we anticipate improvement in the results will continue.
So thanks. Let's think about a 10-minute break. And be back here at 10:00. Thanks, everybody.
David R. Larson
Take your seats. We'll move on to the second half of today's presentations. Before I introduce and get John back up here, one logistical item, and that's lunch. The management team is going to hang around after we complete the presentation today. We're going to have some boxed lunches that people can bring back into the room and have some informal chats with the management team or if you guys have other arrangements or engagements later on this afternoon, you can just take a boxed lunch with you and head out the door. So it's your preference but we'll be around to answer any further questions at the end. So with that, I'm going to introduce back John Lewis, who will be covering the Gulf of Mexico.
All right, so thanks for coming back from the break. I really didn't have a choice,, but you all did. So thanks for coming back, we appreciate it. Now let's switch gears a little bit and let's move offshore.
So Noble's committed to the Deepwater Gulf of Mexico. And it's returning to a new normal and it is a new normal. We've made a lot of progress during the moratorium and Noble has been very instrumental in leading the industry back. We've got 2 development projects, Galapagos and South Raton, which will be coming on production in the next several months. We also have a very rich portfolio of prospects that we've been maturing and we'll begin testing in 2012.
Last year when we met in June, the Deepwater Gulf of Mexico was in turmoil. There was actually a great deal of uncertainty. Over the last year or so, much of that fog of uncertainty is lifted. We now have subsea containment systems that are ready to deploy and the path forward on permitting and operating while still evolving is becoming much clearer. And Noble has played a key role in returning the industry to this new normal. We have several firsts, including the first completion permit and the first drilling permit. We also took a lead in developing one of the subsea containment systems now in place for the industry.
This is a continuation of the work that Noble has done that won us the BOEM safe award for 2008 and 2009 and made us a finalist for 2010.
So now let's talk about a couple of our projects. First is Galapagos. Since the last time we've talked, we've drilled and had the discovery of Santiago. We've completed Santiago, Isabella and Santa Cruz. Our partner has laid a subsea gathering system and is finishing up top side work from Na Kika, the host platform we'll be flowing through. Galapagos is going to come on in 1Q of 2012 at 10,000 barrels of oil per day net to Noble. And it has significant upside, I'll talk about that in just a second. So initially this is a 3-well tieback, 3 subsea wells flow into subsea gathering system up in Na Kika. And as I just mentioned, we're modeling about 10,000 barrels of oil net to Noble for an initial rate. Now this assumes a certain deliverability from the wells and we feel that the wells actually have excess deliverability capacity on this, as much as 50% more deliverability. And we should know pretty soon, as production starts, within a month or so, whether this deliverability exists or not. It makes up part of this upside you're seeing here. In addition, the base case is modeled on a certain reservoir size. If you look at some seismic attributes we've seen, when you look at 3D across this area, it's quite possible that the reservoir is larger than we've modeled. And as such, if it is, we'll maintain this production plateau for a much longer period of time at a higher level. It will take several months to a year of production to understand what the real size of these reservoirs are and whether this upside exists.
This production will be greater than 80% oil. And with a sustained production, Galapagos will have very robust economics. We'll have a 41% rate of return after tax, all of this are on the base case and we'll have lifecycle NPV of just over $800 million net to Noble. And the after-tax cash flows will be in the $100 million to $200 million per year range for about 7-plus years. Should the upside recovery case, I just talk about come into play, it'll add about $600 million dollars of net after-tax NPV to Noble, and will increase those after-tax cash flows to $200 million to $400 million a year.
Chuck mentioned this before, but on this slide and several others to come, we'll be reporting 2 different NPVs. The first is the lifecycle case, which includes all the costs from the original exploration well onward. And then we'll also be reporting the point forward NPV, which only includes costs from November 1, 2011, forward. In addition to the discovered reservoirs and their potential, we also have about another 65 million barrels of oil equivalent in resources out here. Some of its included in shallow zones that have already been penetrated and we've seen the oil reservoirs in both the Santa Cruz and the Santiago wells. And in addition, we have offset, better, the same of [indiscernible] of 3 discoveries we've had that share a lot of the same stratigraphic and seismic attributes -- structural and seismic attributes. So overall, the growth potential of Galapagos is over 250 million barrels of oil equivalent and that again, that'll be greater than 80% oil.
Moving to Gunflint, we've made a lot of progress in the last year. We signed a unitization agreement and crossed a signed acreage with our partners across 5 blocks. All the plays will improve [ph] the first well, we've got a permit in hand, and the rig will be moving to Gunflint in less than a week. We've got to do some rig modifications and then we'll be spudding in December.
This slide shows the reservoirs we found at Gunflint. Overall, we found greater than 550 feet of very high quality Miocene play. The scale on this log is somewhat compressed, so we could get it all on one slide. But these are thick blocking sands. As an example, if you look at that in [ph] 50 sand, which is on the right part of the log presentation, about a third of the way down, that sand there is about 135 feet thick and is full at the base with oil.
One of the key accomplishments in the last year was to get this unitization across all the blocks that constitute Gunflint. This is going to add real value to Noble as we move forward. First, it establishes Noble as the operator and will probably save us a year at least, if not 2 years, of negotiations that would go on most appraisal if we didn't get this unitization done now, and it aligns our partners on the appraisal and development decisions to ensure that we're drilling appraisal wells that are really for the good of all parties, not equity type determination wells.
So first appraisal well spud in December, it will help to determine the size of the field both in the four-way to the south and also in the three-way up to the north against the salt. Subsequent appraisal wells will also confirm this potential, especially on the south side of the four-way and further potential up in the three-way.
As with Galapagos, the economics are very robust, and the cash flow generation here is going to be significant. We believe we can fast track this project and we're targeting 2016 for first production. Payout is going to occur about a year and a half after production starts and should the upside potential unfold, it's going to add about $1 billion of net NPV value to Noble.
Now a quick word on Deep Blue.
We have finished the well and we've found additional hydrocarbons in high-quality reservoirs. Additional analysis of the data from the sidetrack will be necessary before we finalize our future plans. As far as Noble's inventory, it doesn't change much in the last year. We have a good mix of amplitude and sub-salt plays. We have about 2 million barrels of net unrisked resources. This is primarily focused in Mississippi Canyon, Grand Canyon and nearing banks, where we've done a lot of work and build up quite a bit of expertise. All but one of our prospects are Miocene in age and younger and they're all in proven high-productive reservoirs. Value-wise, this portfolio adds about $4 billion net risk NPV after-tax to Noble and about 80% of this is associated with sub-salt Miocene prospects and about 90% of this total portfolio here is oil.
This slide shows the exploration prospects will be maturing for 2012 and 2013 exploration. It's got a good mix of relatively quick to produce amplitude play and generally, the more material sub-salt plays. It won't [ph] be maturing about 2x to 3x as many prospects that's why we're actually going to drill to ensure that we have quality through [ph] choice.
Longer-term, we see the Deepwater Gulf of Mexico production being essentially flat until the ramp starts in 2015 followed by the impact at Gunflint in 2016. The pie chart on capital is a little bit misleading because that big exploration works there also includes the costs of follow-on development. Actual exploration spending over this time period will be about $800 million or about a third of this total.
So in summary, Noble sees a bright future here in the Deepwater Gulf of Mexico. We have 2 projects, Galapagos and South Raton, they'll come on line in the next couple of months to add value. These 2 projects will grow and then maintain our production for the next several years. We have a great portfolio of projects that will begin testing here in 2012. And as we determine the size of Gunflint, we have other exploration success, we'll build execution excellence in our projects by leveraging off the great results we've seen in the international major projects.
With that, I'll turn it over to Rodney, who will discuss these great results with some other international stuff.
Rodney D. Cook
Thank you, John. And good morning, everybody. I know last year, about 16 months, we stood up here -- I stood up here and said it was an exciting time to be an International group and I'm happy to say, that it's all the excitement square [ph] this year as we move forward a lot of our projects. Today I'm just going to focus on a couple of areas, West Africa, Eastern Med and the gas monetization for both. Turning first to West Africa, we've been in this region since 1990, with the first well we drilled at the Alba field. 2001, the [indiscernible] came online as an effort to monetize the gas that we were flowing at that time. These 2 properties combined together provide a very strong cash flow from West Africa.
While [indiscernible] and Equatorial Guinea and our properties in Cameroon provide opportunity for significant growth beginning in 2011. As you've already heard today, with the same coming online. Our teams have worked diligently to bring our prospects on schedule and on budget and I believe you'll agree when you see our results to date that our project groups are best-in-class. But we're not through yet in adding value to this area, as we have a strong portfolio of exploration projects. I'll touch briefly on some of this, but Susan will go about much more detail in just a moment. And lastly, we're working very diligently with the governments of Equatorial Guinea and Cameroon to begin to develop the methods for which we'll monetize the gas, not what we've already discovered but, hopefully, will discover in future opportunities.
You see this map will remind you of where our positions are in West Africa. At the top, you see the Alba field, where we're currently producing about 20,000 barrels a day of liquids. We have a methanol plant in that area. Out to the right you see Block O with 45% working interest. Block I, where we have -- it shows here 38% interest, that's a diluted down interest, and then because of the government carry. And over in Cameroon we have our YoYo license in out Tilapia PSC. Outside the Alba field operate some 1.5 million acres of opportunity. Alba field, as I said, currently produces 20,000 barrels a day and 244 million cubic feet of gas and provides very strong base cash flow benefiting from low operating costs and the condensate being sold on a Brent basis. Amco, which has celebrated its 10th anniversary, is one of the lowest-cost producing methanol plants in the world that provides great cash flow to the company. These properties play a significant part of our overall value in Equatorial Guinea and allows us the opportunity to be here to get into Blocks O and I.
Now let's turn to the Noble operated properties. To date, we have 305 million barrels equivalent of net discovered resources, of which 111 million barrels are liquid. Due to exploration success we've had over the past few years, we have a great line of the projects in front of us. Aseng, which is now online, Alen, sanctioned and already planning to be online in the fourth quarter of 2013. Diega is an existing development opportunity and our Carla prospect, which we announce today, is a discovery as a tail to one of our Alen wells. As we drill through these properties on our development, we're always looking for the chance to drill deeper and look up and pick up some additional exploration success.
Looking forward to what the future holds, it's exciting. Because we have a great opportunity for additional exploration in area, as we're currently drilling those wells in Cameroon. As announced, Aseng is online, came online November 6, less than 5 years from discovery and less than 3 years from when we sanctioned the project. In less than 1 week, we were able to ramp up drill up to 50,000 barrels a day, our initial target for production from the field. Coming online 7 months early has a positive impact our after-tax, net present value of some $80 million. And not only did we come in ahead of time but we came in under budget, some 13%, which saved the company $70 million net.
Another key accomplishment came through the strategic placement of our development well. By working diligently with the geoscience and the reservoir engineering teams, we've been able to increase our resources 30% above the initial estimates. And last but certainly not least on this slide is our key -- we feel like one of the keys to our success is our best-in-class safety performance. This is emphasizing all of our operations and as you'll see in a moment, we had an outstanding performance in the FPSO in which Keppel, the shipyard builder received an award from the government of Singapore for its outstanding safety program. Just a reminder of what the Aseng field looks like, there's an FPSO with subsea tie backs. We have producing wells, we have 3 water injection wells and 2 gas injection wells.
So why was the Aseng project so successful? First, we have a proven management team. We looked throughout the company and brought in the most qualified individuals we had at that time to fill the leadership roles, we begin then to identify the gaps we had. We went out of the industry and brought in leading managers, project managers, throughout the group and placed those in the strategic positions. We looked for the right people with both confidence and character. I think this is very important as we move forward. This group provided the leadership and expertise for a fully integrated technical organization and it's not just engineering. It's the geosciences, the commercial and the operations readiness that which we feel is very important. If you look at -- as Chuck mentioned earlier, we went very quickly from the FPSO being on-site to first production in less than -- roughly 2 weeks. This is a result of having our operation readiness team in place that work right along with the project management team, so that when they turned over the keys, if you will, then we were ready to go. This is a philosophy we have on all of our major projects.
In addition to a strong technical team, we've selected top suppliers, who will work very, very diligently with them to look at opportunities where we can incentivize them and bring value to the project by enhancing the critical path.
Next, we placed played a significant emphasis on peer review, as David mentioned earlier, not just internal but third parties as well. On the internal process, we bring in members from our teams from throughout the company, not just the Gulf of Mexico but also from our Denver group and the Wattenberg and we work together to look through the project and look for opportunities to improve where we're at. It's not that it brings value to the team, that are working on a project specific, but it brings value to the teams that are part of the process as they can take back the learnings that we've seen and implement those, regardless of whether it's Gulf of Mexico or onshore U.S.
As mentioned, safety is one of the most critical things we've placed in front of our teams. This gives you an idea of the magnitude, the number of people that were working on the FPSO on any one given day. Every morning there was a safety program, where thousands of men will come to work and be -- we would stress our safety program. 10.5 million man-hours without a major accident. In total, where we have to [ph] -- complete period of time, just slightly over 400 man-hours were lost due to any type of incident, a great project and a great testimony to our teams.
Not only do we place great importance or what I would refer to as the visual side of the project, that is the drilling, the FPSO, but we emphasize the subsurface as well. We spent extensive time at modeling and gathering and analyzing the data to ensure we place our wells so as to minimize the number required to maximize the impact of the reservoir recovery. This aided in a definition and provides superior production as we move forward. Our wells are currently producing 10,000 to 13,000 barrels a day and have a pressure draw down on the reservoir of less than 50 PSI.
What does all this bring. 33 million barrels of net oil resources and 126 Bcf. As I've said earlier, this is 30% above our initial estimates. This is a photo of the Aseng FPSO on-site with the Alen and Bioko on the background, which remind [ph] we have the ability to produce and process 80,000 barrels a day through this facilities. We have 27 slots in the turik [ph] that allows production to come in to the facility. Of those 27, we've utilized 8 for the Aseng project. This allows for the development of satellite project such as Diega and Carla, enhancing the value of not only those projects but the Aseng project as well. As I've already mentioned, the Aseng project brings 50,000 barrels a day, at least 50,000 barrels a day for the foreseeable future. We do believe we have the potential for higher volumes. Our plan is now to watch the performance of the wells for a period of time. And as we begin to put the new data into the model, we will look and see if there's an opportunity to bring the rate up a little bit higher while at the same time maximizing our recoveries.
The tail off you see here in this curve is not necessarily because of the production, it's partly because -- but mostly because of a way the net backs we took are adjusted through the PSC as we progress through the payout period.
Aseng certainly has strong economics. Our current production of 17,000 barrels a day combined with a very attractive F&D cost provides a lifecycle after tax net present value of $1.1 billion. Go forward from today, that increases to $1.8 billion. And while we anticipate being able to further ramp up production, the economics here do not take that into account. Additionally, we do not include any value from any event that we might see in the future from gas sales or also from the sharing that facility's other projects such as Aseng or such as the Alen.
Question now is, can we duplicate the Aseng effort and success? And we certainly believe we can. With disciplined appraisal programs, building strong project teams and working hand in hand with our suppliers, we are positioned for success in all of our major projects, whether it's West Africa, the Eastern Mediterranean, the Gulf of Mexico Deepwater or our onshore projects in the Wattenberg and Marcellus.
Take a moment now, let us turn our attention towards Alen. To refresh your memory, Alen is being developed with 2 platforms, a central production platform, which is the larger one of the left and a smaller platform, the well protector platform, on which the jacket has already been installed. The facility has the capability of process 40,000 barrels a day of liquids and 440 million cubic feet of gas a day. Alen is being set up to be a central gas processing facility for the area, much the same way Aseng has been set up to be central for our oil production. Alen, which was sanctioned at 2010, is set to come to online in the fourth quarter of 2013 at a growth rate of 37,000 barrels a day. As we did with Aseng, we'll continue to look for opportunities to accelerate the production rate or accelerate the time when the production would come online. Through our modeling work, it became evident, we could take advantage of the thermal grade that we see in the field and we reversed our position of our wells and put our injection wells, especially the gas ones, down there to take advantage of the thermal grade and enhance our recoveries. So we're now estimating we'll produce 83 million barrels of oil equivalent of which 34 million barrels are liquids. All of our major projects are in place and the first rig is on-site to begin the development work. Our second rig will arrive in the next few weeks as it completes its work in Cameroon.
As with Aseng, Alen is a high-quality reservoir. As I mentioned already, we intend to produce 37,000 barrels a day from 3 wells. The initial net in this field is 20,000 barrels a day. This needs a little bit of explaining if you take into account our net interest. We carry the government's state-owned [ph] oil company for a percentage of their interest throughout the field development. We'll recover that back in our initial production rates pushing our net to 20,000 barrels a day. Once that's recovered, it will drop back as according to the PSC terms.
This will follow the well head jacket that's already been installed, as I've mentioned, and the rig will be in place in the next couple of weeks. We're certainly on schedule and on budget. The dotted line that goes vertical in this shows today gives you a good idea where we're at in the progress of this project. You can see there's been significant amount of work done today and we certainly have some more in front of us. But we certainly -- we believe we're on schedule to complete this and be online no later than fourth quarter of 2013.
This is a view of our production. If you'll note here, as I've said, this is not taking into account the incremental volumes we did associated with the carry of the government. This is purely our net working interest, royalty or [indiscernible] the royalty just for that PSC term. Alen, much like Aseng, has very strong economics. The initial rate of 37,000 barrels a day, a low LOE on a unit basis, we get an after-tax net present value, lifecycle value of $7 billion. Going forward from today, that increases to $1.1 billion. One thing to keep in mind, particularly on Alen, that there's no value shown here for the gas. The optimum recycle time according to our models we currently have in place is 3 to 6 years from first production.
With our past success including discoveries such as Diega and Carla, we look forward to what our future exploration will bring. The entire data set for Blocks O and I as well as Cameroon have been merged and taken to depth. We're already seeing some very exciting things that we haven't recognized in the past and our net risk on resources in this area are now 448 million barrels. Based on our current inventory, we plan to drill 1 to 2 wells per year for the foreseeable future. Susan will cover this in more detailed during the exploration section, but we're certainly excited about what we see in front of us.
So what comes after Aseng and Alen? As mentioned earlier, our next 2 projects are scheduled to be Diega and Carla. Diega is a 45 million to 110 million barrel opportunity with 60% liquids. Carla, as I said, was drilled as a tail to our Alen development wells, and it's a 35 million to 100 million barrel resource opportunity with 80% liquids. We're currently working through the various options for development and we anticipate that the first production for most of these properties will come online sometime in 2015.
We envision both of these fields taking advantage of the FPSO Aseng be on-site and we'll utilized it for not only storage but for processing and we'll certainly enhance the value as we go forward with Aseng as well.
With Aseng now on and a line set for production and Alen's separate production in 2013, we'll more than double our liquid production from West Africa by 2014. All the growth that we're seeing is from Noble-operated projects. What you don't see on this curve is anything for Carla as there was a life breaking discovery. We built the slide. We have Diega in here, as you can see that, but we would anticipate Carla coming online in a very similar timeframe as you see Diega.
Although our liquids production is growing, you can't forget about our gas. We currently have 4 Tcf of gross gas resources between Equatorial Guinea and Cameroon. We're working diligently with both governments of Equatorial Guinea and Cameroon as to what the development scenarios will be. And we're looking not only what we have today but what we hope to have in the future as well.
In summary, we anticipate producing 46,000 barrels a day in West Africa by 2014 generating approximately $1.2 billion of after-tax annual cash flow. If you just take the Aseng and Alen projects alone on a look forward basis, that's nearly $3 billion in net present value. We have delivered Aseng ahead of schedule and under budget with a best-in-class project management. But we're certainly looking forward to what exploration has for us in the future.
Now we'll turn our focus to the Eastern med. Noble and its original partners pioneered the natural gas industry in Israel. Production started for Mari-B in 2004. Seven years later, we have the Tamar field, the largest gas discovery in the world in 2009, is progressing on time and on budget, commissioning set for the fourth quarter of 2012.
Noble continues to lead the oil and gas effort in Israel and Cyprus by supplying deepwater expertise and technology from around the world where we operate. With the recognition that the gas discoveries due to date exceed the growing demand in Israel, we're actively working on options to monetize this gas through LNG solutions. We're in the process of engaging a leading EPC contractor to help us as we go through a pre-FEED process and look at the LNG options in the region.
Noble's currently discovered gross resources exceed 25 Tcf, of which 8.5 Tcf is net to Noble. At the moment, we have 3 drilling rigs in the area, with one drilling our exploration well in Cyprus, one drilling an appraisal well in Leviathan and one drilling an exploration well within Israel. And the 2.5 million acres operated by Noble in Levant basin, the majority is unexplored. Just to look a moment at the field that we currently have on production at Mari-B, as a sole producer in Israel, we're very proud of our operating position. Nearly 100% reliability since coming online in 2004. When I say nearly 100%, it is North of 99%. During the past summer, we experienced record sales and, at times, actually exceeding the main plate design of our facilities as the market demand continues to grow.
We're moving to next phase of gas development for Mari-B field will continue to play a key role not only to supplement some of the production but will provide us our opportunity for gas storage facility. As Mari-B natural gas is replaced expensive [ph] and less environmentally friendly fields that have resulted in over $7 billion of energy savings for the citizens of Israel and in addition to that, has reduced 17 million metric tons of CO2 from the environment. To put this in perspective, the CO2 emissions that we reduce is equivalent to shutting down all vehicles in Israel for 1.2 years, a great accomplishment for our teams over there.
The Mari-B field has been satisfying the vast majority of Israel's natural gas needs since 2004, as I said with exceptional reliability. Additionally, since 2009, we've invested in 2 new wells to put compression on the platform to aid us in maintaining that reliability as well as our deliverability. Just recently we've also drilled 2 wells at the Noa field to help bridge the transition time for when Mari-B begins to decline to when Tamar comes online and begin sales in April of 2013.
Turning our focus now to Tamar. Phase 1 at Tamar field consists 5 subsea wells; two 90-mile 16-inch pipelines, which will bring production to a platform near the Mari-B, that will allow us also to transfer of gas to the Mari-B for storage down the road. We'll utilize the existing 30-inch line that currently runs from Mari-B to the Ashdod facility. We're also in the process of expanding that property. So as I said, we'll use Mari-B for storage with the brightest opportunity for which [ph] we'll discuss a little bit future in the program.
Tamar is a $3 billion project and is being executed in a fast-track manner and quicker than other projects of this size. Discovered in 2009, it was sanctioned in 2010 and will start commissioning in late 2012 despite the fact that we had to change our development scenario mid-2010 to allow for us to come to Ashdod as opposed to northern shore beach. As I've said, the project is on schedule and on budget with all major contracts awarded and construction well underway. The resource estimate continues to grow as well now at 9 Tcf. Tamar is a world-class field that's being developed with top quartile performance.
Last year, we told you that the Tamar resources were going to grow by 34% to 8.4 Tcf. Well, I'm sitting here today, and tell you that they've grown again 7% to 9 Tcf. This resource increase has been supported by our appraisal drilling and our rigorous petrophysical analysis done by our geoscience team. Phase 1 of Tamar developed 6.5 Tcf out of the total 9. To date, Noble has only booked 5.4 Tcf or 1.7 net the company. The reservoir quality is world class with excellent connectivity, and we have designed the completion such that each well will have the capacity to deliver 250 million cubic feet of gas a day.
Even with a fast-track pace of development and significant progress made to date, the project is being executed with best-in-class safety with over 3.6 million man hours to date with no major incident.
Significant progress is being made with over 50% completion of all the major items. And in order to ensure fast-track project schedule stays online, we have purchased spare key equipment so that nothing becomes critical path as we move forward.
We are implementing the best practices we've seen based on our Aseng project in West Africa and this will certainly help as we move forward Tamar. Shown on this slide is the picture of the all sea Solitaire, one of the largest pod play vessels in the world. So location at present time installing the lines and we are over 50% complete with that.
You see here the schedule for Tamar, you look today day, as I said, this is the same way we see with Alen. There's a lot in front of us but there's a lot behind us as well, and we're very confident at this stage we'll meet our target of first production -- first sales in 2013. Certainly, domestic gas market in Israel has grown significantly since we first came online in 2004. This was a reminder when we brought Mari-B online, that was the first gas into [ph] the country and prior of the discovery, there was no utilization of natural gas anywhere. In addition to this the natural growth through the industry, [indiscernible] regulator company has already announced that they plan to convert some of the currently coal-powered generation plants to gas in the not-too-distant future. This, in addition, provides significant growth opportunities but there's also something beyond that. There is certainly a large number of people within the government that have indicated they would like to see 80% or more of the power generated in Israel to come from natural gas. They have the capacity if they convert the rest of their coal plants that have not been identified yet as candidates to increase demand in the country to 1 Bcf over where they're currently going to be at additional 1 Bcf a day.
Currently, we're in the final stages of negotiations with Israeli Electric on a gas sales contract for Tamar. At the present time, we have the most significant items agreed-upon and we anticipate closing this negotiations out in the very near future. But ISE [ph] it's not the only ones in the market.
It's important that Tamar gas is underpinned by the growing domestic market. It's already there. We're seeing the sales from Mari-B continue to grow. We believe the demand is there and the growth is there as well. We're currently also in active discussions with multiple customers such as independent power producers, cogeneration projects, industrial use such as cement [ph] plants, power plants and our existing customers at Mari-B.
As we look forward and see what we think where the scene is going to all go, the base demand currently is estimated to have a 10% compounded annual growth rate. This is not just Noble's viewpoint of the gas demand. It's outside parties as well as the Ministry of Infrastructure in Israel as well as Israel Electric. As I mentioned earlier, there's future growth beyond that, the top portion, the light blue of this is based on the already announced coal conversions.
Also shown in this graph you see the 4 bars that are going up and down vertically. We wanted to put those there so you can get an idea why we've built so much capacity into our system and now right at the present time are projecting that we'll have annual sales equal to them. There's a great amount of swing in Israel due to the seasonality and the demand for gas.
Just kind of focus on 2010 as an easy example. In that year, the natural gas consumption in Israel was around 500 million cubic feet a day. If you look at the swing, it's anywhere from 300 million a day to somewhere close to 750 million. We need to be in a position to deliver that. That's where Mari-B is being utilized and storage will come into play and the excess capacity it will bring into the system well as well.
The Tamar project will become a legacy asset for Noble once it comes online and providing strong cash flow for many years. The upper graph on the left-hand side here shows how gas prices have matured over the years, starting around $2.75 in 2004 when Mari-B came online for the first time. For the third quarter of 2011, we were a little bit north of $5 for our gas on a consolidated basis.
The lower graph shows the projections for the production for Mari-B. Just remember, this is Phase 1 only. We expect it to fill a plateau for some number of years exceeding the demand's quite conservatively for a while. Key metrics for the Tamar projects is shown in the summary economics box and are certainly world class in all that we -- in all aspects, a low operating cost and low F&D cost as well.
Let's take a minute now, we'll turn our attention to Leviathan. We were able to come here last year and tell you we have the world's largest natural gas discovery in 2009 with Tamar. As exciting to be here today and tell you in 2010, we also had the world's largest gas discovery in Leviathan. Current resources for Leviathan are estimated to be at 16 Tcf.
To put the size of this field into perspective, Leviathan recovers 24 U.S. Gulf of Mexico blocks, 3x3 and 3 miles by 3 miles in area. Leviathan was the third successful test we have, what we refer to as the Tamar sands in the Levant basin. It is a world-class field with corresponding reservoir quality. We're currently appraising the discovery with the drilling of the Leviathan 3 and hope to have results from that in the next month.
We're not sitting back or waiting for everything to happen. We have a commercialization team in place as well as a technical team that are working very diligently to look at how we monetize the gas from Leviathan. Given the scale of this field, it's apparent that we'll be able to help not only supply the domestic demand in Israel, but there's plenty of gas to support export options. Leviathan is our next major project in the queue, and we'll benefit from the success of not only Tamar and Aseng but other projects in between. We look forward to bringing those learnings to the project.
A large portion of the 2.5 million acres that we have -- that we operate in the Eastern Med is unexplored. We have discovered over 25 Tcf and we still think we have significant opportunity in front of us. We have identified 12 Tamar sand prospects with unrisked potential of 20 Tcf. We recently discovered the Dolphin field in Israel, and we're currently drilling the Cyprus A prospect and we anticipate having results by year end.
But although we're busily drilling appraisal wells, development wells and exploration wells, we haven't forgotten about the Leviathan #1 deep gas. We have plans to reenter this well shortly after the first of the year where the schedules allowed to complete our testing of the deeper horizon. As a reminder, this is an oil concept that has a potential to deliver with success over 3.7 billion barrels of oil across the Levant Basin on our acreage. We're very excited about the opportunity and Susan will talk a little bit more about this in a moment.
If you look at LNG demand worldwide, the consensus is that the demand is going to grow. Certainly, the Japan earthquake accelerated this beyond anybody's imagination. While there are many LNG projects underway particularly in Australia, it will not be enough to satisfy global demand in the future. The timing of our projects in the Eastern Med will fit with the anticipated supply needs very nicely as we begin to develop those and anticipate having those come online in the second half of the decade.
There's a very strong and compelling case to export gas from this region. Some of the obvious drivers are discovered resources greatly exceed projected domestic needs, the revenues to the government will be enhanced and exports will encourage additional exploration to realize the full potential of the basin.
As I mentioned earlier, we have engaged the services of a leading EPC contractor to conduct a pre-FEED study for LNG export options. The study is currently underway and we expect it to be completed by March of 2012. This will give us a good understanding of the cost and the constructibility of LNG plants in the region. In addition to that, we're also in another stuff. We have our teams working with financial advisors to assist us and begin the process as we look forward to find a strategic partner where we may feel as they will be necessary for the full development of LNG projects.
Well, Eastern Med, certainly Mari-B continues to be a very reliable producer. We have a world-class portfolio in this area with mature operations, development projects in Tamar and Leviathan and significant running room with our exploration opportunities. We have discovered over 8.5 Tcf to date net to the company. Tamar remains on track for commissioning this time next year and certainly, we see that gas demand continues to grow with great abundance. As we look forward, LNG has the opportunity to provide substantial growth in the second half of this decade. We have a significant number of prospects that with success will certainly play a key role in growing the Israeli ENP business.
Lastly, I just like to leave you this one picture here where we feel like the international group is headed over the next decade. If you look at this picture, you can see we have on average over that period of time a 15% compounded annual growth rate. We believe that the future is bright in the international region with significant exploration to come in the future.
And with that, I'd like to turn it now over to Susan and she'll cover our exploration opportunities.
Susan M. Cunningham
Thank you, Rodney. Good morning. You've heard several references to the exploration program and inventory at Noble Energy by my colleagues, and I will now try to pull it together for you. However, before I do, I would like to state what a privilege it is to be part of this great team. I would also like to acknowledge our amazing and dedicated employees that are making all this and will continue to make all this possible.
My intent is that when you leave here, you will have a sense of why our exploration programs had been successful over the past 5 years and you're confident we are only just beginning. To do this, I'll give you a high-level look at the drivers of our past success, a peak at the secret sauce. Many of you have heard it before, so won't belabor it. However, we are constantly evolving and learning, so I'll let you in a little bit more about what we -- our newest thinking is, and then I will illustrate results.
The bottom line exploration performance over the last 5 years, our performance relative to the super majors and exploration peer companies according to Wood Mackenzie, and then I will take you on a worldwide tour, illustrating what our understanding and situation was 6 years ago, what we have learned in the past 5 years -- 5 years ago and then what we've learned in the past 5 years and what we see going forward. And then finally, I'll put it all together, summarizing the future potential as we see it globally in the acreage that we have currently captured.
So the drivers of our exploration performance. First, it's about setting a strategy and staying focused on it. Second, it's about being disciplined in applying processes designed to help us assess every opportunity consistently and objectively everywhere around the world. As you have heard, Noble equals postmortems and learnings real time. And lastly, and this is the newer part, we pay attention to intuition and experience. We're learning about training our intuition and experience, learning and recognizing when something doesn't feel right and paying attention to it.
What do I mean by trained intuition? When an athlete is at the top of their game, they are constantly evaluating their past performance doing postmortems on the last game in real time, learning where they performed well and where they could improve. They are doing those postmortems constantly. This constant focus on learning translates into throwing the ball when it feels right. It's not an objective analysis and in the moment, it's when it feels right to throw it because they have trained their intuition.
We all have experience that if we're not analyzing our performance objectively in real time, that experience is not of the same value and connection to future performance. So at Noble, in addition to objective assessments, we're learning to pay attention with how things feel from those who have trained their intuition. We do all this so that we can constantly high-grade our opportunities for investments similar to an investment portfolio, such that not only are we objectively assessing risk and reward but we understand the impacts of each opportunity to the portfolio performance and our focus on could-be learnings from every success and failure.
Using these processes, great technology and leveraging talented, high-integrity and creative people, Noble discovered nearly 2 billion barrels of oil equivalent in the past 5 years. And based on Noble data, our planning cost dropped from around $4 per barrel of oil equivalent to about $0.50. Two core areas were created: the Douala Basin in Equatorial Guinea and Cameroon and the Levant Basin in Eastern Mediterranean.
According to data gathered by Wood Mackenzie, in the past 5 years, Noble outperformed the super majors and global exploration peers in exploration success rates and finding costs. We are quickly moving these discovered resources to production: Aseng, Alen, Galapagos, Tamar and in 10 years, approximately 35% of our production is expected to come from discoveries made from the 2006 to 2010 time frame.
And now we'll start the tour. Starting with onshore U.S. where we are focused on liquid-rich unconventional plays, we are leveraging our technical investments and learnings early to identify the sweet spots. As you heard, Ted earlier talked about applying technologies. We are really focused at leveraging these across every aspect of our business. We've acquired 1,800 square miles of 3D and our inventory has increased by 83% since 2006 to a current total of 1.6 billion barrel of oil equivalent.
Not shown on the map, we're actively leasing in 3 new emerging plays where we have leased about 200,000 acres so far and are targeting another 500,000 acres. We have estimated running room of 600 net unrisked million barrel of oil equivalent, above the currently held 480 million barrel of oil equivalent in these 3 emerging areas.
In the DJ Basin, Noble has been a key force in bringing speculative 3D to the area, resulting in the acquisition of over 1,700 square miles of 3D -- of exploration 3D and another 100 square miles of development 3D. Along with extensive oil evaluations including full sweep logs, FMI and microseismic, we have learned that rock properties are quite variable across the basin.
Due to that variability, both exploration and completion strategies are required to determine the sweet spot. And interestingly enough, as Ted mentioned earlier, learning from outside of Wattenberg have actually impacted Wattenberg and our understanding there, helping us to expand the sweet spot and our confidence and performance. The exploration potential outside greater Wattenberg is estimated to be approximately 380 million barrels of oil equivalent unrisked over multiple targets.
And now to the Deepwater Gulf of Mexico. Five years ago, approximately 50% of our inventory consisted of amplitude plays, and the industry and Noble were interpreting a narrow azimuth seismic. The graph illustrates our inventory portfolio at the time with risk versus mean volume.
Today, 25% of our inventory is made up of amplitude prospects and we have moved to wide azimuth 3D and our own reprocessing. Our knowledge of risk and opportunities has grown dramatically. We have found that proprietary imaging is a real key. As John mentioned, we made 2 significant discoveries recently, the Galapagos Project with 3 discoveries in it, with greater than 130 million barrels of oil equivalent gross and about 100 million barrels of oil equivalent of upside, and Gunflint with 70 million to 500 million barrels of oil equivalent potential.
We built our inventory by 150% since 2006 and our resource exposure by 2.5x in that time frame, as illustrated in the graph, to approximately 2 billion barrels of oil equivalent. We still continue to -- we plan to continue to participate in annual lease sales as the opportunities warrant.
In 2012, we are focused on appraising Gunflint. We plan to grow 2 amplitude prospects. Illustrated on this slide are examples of 2 prospects, both an amplitude and a subsalt prospect, which may be drilled in the 2012 to 2014 campaign. As you can see, the amplitude prospect has about a 55% probability of success, and the subsalt prospect is up to 4x the potential resources of 35% probability of success. Water depths are 7,200 feet and 6,600 feet, respectively.
And now the tour will take us away from the U.S. to the rest of the world, where we are focused on new prospects and tie-ins onto our developing infrastructure in our current core areas, as well as high-impact opportunities that have the potential to be game changers for Noble in the future. Consistent with our exploration strategy of planning for success and managing failure costs, our superior evaluation process enables us to make the right decisions for strategic needs even if that means exiting an area quickly.
Over the last 6 years, we have doubled our inventory and tripled our resources to 5.6 net unrisked billion barrels of oil equivalent. And as you can see on the inventory graph, our portfolio includes several high-risk prospects. As we learn and mature our opportunities, this risk distribution will change. This will give us high quality choices.
So first to the Levant Basin in the Eastern Mediterranean. Consistent with our theme of looking back 5 years and then looking forward, this slide illustrates the situation in 2006. Mari-B was online, and we have farmed into the acreage that held the Tamar and Dalit prospects. No wells have been drilled below salt in the deepwater.
And now in 2011, we have significantly expanded our acreage in Israel and picked up the first block in Cyprus. We shot 2,450 miles of 2D seismic and 2,500 square miles of 3D seismic. We've discovered 25 Tcf of gas in 3 prospects. This does not include the small Dolphin discovery.
We now know that the running room we thought was possible and planned for Israel, and that's evidenced of the deep petroleum system. As Rodney mentioned, we see more than 20 Tcf of Tamar sand potential in 12 prospects, as illustrated on the top map, with varying probabilities of success and oil potential of 3.7 billion barrels of oil equivalent gross unrisked in the Levant basin as illustrated in the bottom map and we are evaluating other plays.
Cyprus A, which is currently drilling at 5,500 feet of water is the largest ever of our remaining Tamar sand prospects as we currently understand them. For the first time, Noble is disclosing its predrilled predictions. We give the prospect a 60% probability of success, and if it does encounter hydrocarbons, we estimate that we will likely find between 3 to 9 Tcf of gas. As with any rank wildcat well the results will impact our analysis of other prospectivity in the area.
Tanin is a prospect we plan to drill soon in the Alon A lease offshore Israel. The prospect located in 5,800 feet of water is located north of Tamar and northeast of Leviathan. We give it a 55% chance of finding hydrocarbons and if successful, we estimate that we will likely find between 800 Bcf and 1.2 Tcf of gas. There is additional prospectivity in the area dependent upon our results.
Further to the west in the Mediterranean to offshore France, we are interpreting 2D seismic that we shot in late 2010. We have over 20 structural prospects in lease in the 2.8 million acre block, varying from 5,200 to 8,500 feet of water. We do see evidence of potential gas and are evaluating the commercial possibilities and risks as the final processing comes in. Depending on our interpretation, we may be shooting some 3D seismic in 2012.
And now to West Africa and the Douala Basin. In 2006, we had drilled our first exploration well, Belinda. Prior to 2006, we have seen the possibility of an impactful stratigraphic play, one with running room and had acquired the assets. Belinda was a gas discovery, and we were planning to drill our second exploration well, Adriana.
Flash forward 5 years to today and we have shot 825 square miles and reprocessed nearly 2,300 square miles of 3D seismic. As Rodney mentioned earlier, we've leveraged our early well results in the 305 net million barrel of oil equivalent in 6 significant discoveries to date, have started production and are currently developing Alen, formerly Belinda, at first discovery. And talk about activity and focus on results and executions, I am particularly proud of Aseng as the first of our large Noble exploration discoveries worldwide found in the last 5 years producing today.
We're very excited to have approximately 450 million barrels of oil equivalent of net unrisked resources and 13 prospects and leads in multiple plays, the largest portfolio we have ever had in the Douala Basin. Please note that the ranges of resource size are gross mean.
So a quick look at Carla, our first exploration well drilled in Douala Basin in 2011. Hidden under the Alen field in Equatorial Guinea as illustrated here, we saw the possibility of cheaply testing it by deepening in Alen development well. Our predrill probability of success was 60%. We are thrilled to have a really nice oil discovery at Carla, with a preliminary estimate of 35 million to 100 million barrel of oil equivalent as mentioned by Rodney. This discovery has liquid volumes similar to both Aseng and Alen. This is our first predominantly oil-content discovery. The successful result opens up the possibility of additional potential previously obscured near other discoveries.
In Cameroon, the high-risk Bwabe well is a dry hole. Here you see a perspective view of the base Bwabe canyon system with several canyons and ridges visible. The reservoir was the key risk. Information gained from this well has been very valuable and will be assimilated into future prospectivity of the area.
Bouma, our moderate risk, 35% probability of success. Exploration prospect to be drilled in 2012 is located in 1,600 feet of water. If successful, we expect to have between 95 million to 400 million barrel of oil equivalent of hydrocarbon, and we anticipate gas to be present. As with all exploration wells, results will be assimilated into other prospects in the area.
And now to offshore Nicaragua, where we have approximately 2 million gross acres in 2 blocks and we have shot 3,000 square miles of proprietary 3D seismic. We have identified greater than 1.3 billion barrel of oil equivalent of resources of inventory on multiple prospects, leads and play types. We are still working the data, which is why the number is open-ended right now.
The high risk Tyra bank prospect is our largest to date in this lot. It lies in 1,300 feet of water depth and if successful, is likely to contain between 100 million barrels of oil equivalent and 1 billion barrels of oil equivalent gross resources, a very wide range. It appears to be similar to the 500 million barrel of oil equivalent Malampaya field in the Philippines, a large carbonated reef buildup. You can see a modern day analog illustrated here. Carbonate reef buildups tend to contain greater variability [indiscernible] than classics. And so we have a wide range and it can take several wells to determine its real size.
So in summary, in the past 5 years, Noble has become a leading explorer in the industry, proportionately finding more hydrocarbons at lower costs than the competition according to Wood Mackenzie data. Noble started 2006 with an inventory of about 2.7 billion barrels of oil equivalent unrisked resources and found almost 2 billion barrels of oil equivalent in that time frame. We are rapidly developing our discovery, executing on time and on budget.
Today, we are entering the next 5 years of an inventory of 9.2 billion barrels of oil equivalent. We have purposely not stop exploring. We are growing and adding exploration capabilities and quality inventory all the time. So if there's one takeaway, it is this: we are focused, we are disciplined and we are committed to excellence for the present and the future.
Charles D. Davidson
Yes, definitely don't stop exploring, not with that kind of track record. Well, we're right on target and I appreciate everyone's patience as we've been going through this morning. We had a lot to cover. I'm going to have a few closing remarks, and then we've left some time for questions as well. So we'll jump right in.
I hope you'll agree that this is a great story. It's a result of a lot of hard work. I have to say right up front I appreciate the support of many of you in this room that have been behind Noble Energy, not just in the last year or 2, but for a decade. Some have kind of talked about it as being it was challenging back -- if you roll it back to 2000 and you look at the hand that we started with.
But different than Las Vegas, you can't just pitch it in and wait for a new deal. And so we spent a lot of work and it was this team as we've assembled in the company that continued to improve and improve and improve that hand, thus getting us to the portfolio that we have today with the kind of opportunities that we've been highlighting here this morning.
It's a pretty exceptional set of opportunities as we -- just think again about some of the themes we've been talking about, but we're talking about a business that over the next 5 years can show compound annual growth rate of production of 17% per year. And keeping in mind that we have factored in the divestitures of the program that Dave discussed, so if those were added back in, the growth and the ending production would be even higher. But our plan is to divest those properties, and so we felt it's very appropriate to take it off.
So we've got a plan, including divestitures, including portfolio improvement that can go at very high double-digit rates. And also, keep in mind the debt adjusted metrics. The average of debt adjusted reserve growth per share, production per share, cash flow per share, averaging 18% per year over the next 5 years and keeping in mind that, that is potentially best-in-class or close to best-in-class in the mid to large cap peer group. That's an astonishing growth rate.
And there are some things that we talked about that are really upsized that haven't been factored in. Rodney mentioned that Carla, which was a late-breaking discovery, hasn't been really rolled into our production forecast. And so we'll continue to see some things there. John talked about some of the upsides that we have potentially, as did Ted in talking about the Niobrara. So there's a lot of upside. But it's not about headline, it's about results. And that's what Noble is really all about is delivering results, not headlines but results. And I think this team is really well prepared for it.
Shown on the slide here the themes that we've talked about in the morning, and it is a pretty stunning picture. The changes over the past year has certainly been dramatic, but it's not a result of a changed strategy. It's definitely not the result of the changed strategy. Instead, it's the result of a strategy successfully executed. In fact, it was a strategy that our management team put together really on the closing of the merger with Patina Oil & Gas.
At that time when we look at our strategy, we said several things. Number one is we wanted to diversify. We believe that a diversified portfolio was the answer to success, especially in building the scale of business that we anticipated. We wanted to derisk development and near-term production growth in the company. We wanted to make sure that it was something that was repeatable, consistent, transparent, that we could foresee and we could depend on the development and the production in the near term.
Third was we wanted to move exploration to a more material program, move it away from the small things, the little -- the small, little amplitudes in the Gulf Coast onshore where, quite honestly, in the early years, Noble was far too dependent on that kind of program for near-term production. So it was important that we move the exploration into mature opportunities. We want to be financially disciplined in every aspect, every aspect, how we invest, how we manage our balance sheet, how we talk about risk. I think Ken did a great job covering that.
And we wanted to build an organization who is best-in-class in execution and everything we do. Well, we did that and we're willing to sacrifice some near-term growth in order to let that strategy unfold. Well, we don't have to wait any longer, because we're beyond that point now. We're seeing the growth and it's starting today, and it's going to move forward.
So we set a strategy, we executed and it worked. It's pretty much that simple, although we all know there's a huge difference between results and ideas. Performance versus strategy. There's a lot of great strategies that never turned out to be true because of a lack of execution, but we've executed.
It all started with the right organization. I will say that without a doubt, this is the best management team that I've had the privilege of working with. It's incredibly focused, incredibly aligned and they have then continued on to lead and build an outstanding organization.
So you think of where it's gone. Full cycle from my experience, others on the team such as Rodney have even deeper experience. But my experience dates back 11 years to where we've come today and to be able to stand here and say, "And oh, by the way, we believe we can grow this company at a double-digit growth rate for the next decade." And that's, I think, an incredible statement, but I think more importantly is we expect to deliver it. It's not about headlines and promises, it's about delivery. And so that's what we're all about.
At the bottom of this slide, you may have seen it at the closing slide as well is our purpose. We haven't done a lot to share it publicly, we've done a whole lot to share it internally. It's not a tagline. It's our purpose. Energizing the world, bettering people's lives and it's got a -- it's 2 pieces and those pieces are linked. They cannot be separated.
We believe as an energy company in today's world, you got to be a part of the solution. You can't be the problem. You have to be part of the solution, whether it's in developing U.S. energy supplies; delivering energy in Israel that is dramatically improving, not only the quality of the environment there but lowering their energy cost by billions of dollars; or working in West Africa where not only are we doing, I think, a great job of discovering additional resources but working with our partners there to help make life better for the people there and a number of programs such as in helping to greatly reduce, hopefully, eliminate malaria in the island of Malabo.
So it's all about making a difference. That's what that last part is really about. We want to make a difference. We want to make a difference for a lot of stakeholders. Number one, we want to make a difference with you, a positive difference, our shareholders, our investors. We want to better your lives.
We want to make a difference to our landowners, to our communities, our employees, every stakeholder you can manage. That is our purpose. So it's not only just about finding world-class reservoirs, developing them, generating certainly strong profits and returns for shareholders but it's making sure that in the end, we all can walk away and say we made a difference.
As I know that many of us with Noble Energy today can clearly say that over the last 10 or 11 years, we made a hell of a difference. And I'm hopeful that when we stand here in 10 years, all of us will be able to celebrate the difference that will happen and the changes that will happen in the course of the next 10 years. So I think we're in for a really exciting ride, a long ride, a very exciting ride. And I hope you'll join us because just to repeat, we intend to make your life better as well as we make a difference, as we move this company forward into a new era of growth over the coming decades.
I want to thank once again the teams that have just done a stellar job, I would say, in preparing for today. But I just want to say it's not -- I don't mean it in a way of preparing slides and books. I'm talking about all of the programs and results that have gotten us to this point. That's the real preparation, and they've done an astounding job.
We're ready for lots more breakthrough. I think there's a lot of upside in our programs. I think today, we again tried to give you a lot of transparency; certainly enough, information for you to go back and better understand our business. And I would just leave you once again, I'll keep saying it over and over because we say it internally all the time, it's all about delivering results. It's not about promises, it's not about big projections. It's about delivering it day after day after day, and that's what it's all about.
So again, thank you for many of you who have been with us for a number of years, and I hope you'll stick with the business because I think we can certainly deliver some very exciting results going forward.
So with that, I'd like to open it up for questions. We've got myself and our team here. We've got some microphones so that we can -- everybody can hear all the questions, and we'll open it up for some questions at this point.
Unknown Analyst -
It's a question for Chuck or for Susan, now you've highlighted the 3.7 billion barrel opportunity in oil resource potential in Israel. It felt at least to me that you've been a bit less vocal about that in the past. Can you talk about what you've seen so far that gives you the confidence, the level of risk associated with that and what if anything has changed since your last meeting?
Charles D. Davidson
Well, I'll let Susan take that one on.
Susan M. Cunningham
It's just in the results, in some of the drilling results we've had to date and analyzing the seismic and reprocessing and integrating the whole thing together that we see that there's a real possibility. It's still high risk. I do want to emphasize that, but it's a real possibility.
Charles D. Davidson
But the -- we continue to understand and learn the basin, understand how hydrocarbons and how all the systems work. It obviously takes a different system to generate oil versus the biogenic gas that we're seeing that we've been producing and what we're developing exploring and developing in the Tamar integral. So it's an evolving process, and it's no different than what happened with Carla. As the teams relook and found that little hidden gem, only it's not so little, they found that little gem that was tucked underneath the Alen field. So as you stay in a basin, you continue to work the basin, we just don't go and drill wells and then sit back and wait for the next well. The teams are constantly reworking the data, reworking the processes and looking at results. So anyway, stay tuned for that, we'll see. We'll get -- as Rodney said, we plan to get back on that well probably in the very early part of next year as we've got a slot identified in our rig schedule to finish that up and see what's there. We've got a lot of cheerleaders in Israel on that one.
Unknown Analyst -
Yes, just a quick question for you guys around CapEx. Just looking at your bar chart in your presentation kind of eyeballing it, if I'm reading this right it looks like somewhere around $3.7 billion in 2012 and around $4 billion in 2013. Just wanted to verify those are relatively accurate numbers. And then I guess a related question there, just trying to get a sense of whether or not those figures include the installment payments for the Marcellus JV.
Charles D. Davidson
The capital -- well, first of all, the capital program for next year -- Ken, do you want to talk about it? Because there's 2 things. There's a carry that's included in it as well as the acquisition cost.
Kenneth M. Fisher
Those are good estimates for '12 and '13. They include the carry on the Marcellus program, but the installment payments are taken into account in the debt maturity profile, which had been there about $325 million a year on the first and the second anniversaries.
Charles D. Davidson
What it gets serious is we accounted for all of that up front. Even though it's paid over time, our balance sheet today reflects the full amount of the initial purchase price because it's a commitment we've made. So it's basically accrual accounting, and so that will be reported all in our capital programs for this year. So as Ken said, we have to pay for it in cash, but it's already been booked as an investment and carried on our balance sheet.
Unknown Analyst -
Hey, Chuck, just a question as you think about your plans for 2012 and '13, and probably you don't want to give an asset sales proceed number. But is it kind of $1 billion, $1.5 billion set of bread box range? Or how would you characterize that in your plan?
Charles D. Davidson
Well, you're right. I won't -- since that is a process that we would expect there will be a number of competitors looking at that, I won't project on the proceeds. But you're as good as any to look at metrics such as dollars per barrel of oil equivalent per day, and we also noted what the reserves were that were being divested. So I think you can make as good an estimate as anyone. And we'll see again -- we're targeting for the end of the year to get that finished.
Unknown Analyst -
And probably another question you won't answer, but you're negotiating with Israel Electric around gas prices. You have a slide that shows where Mari-B prices have gone through the third quarter kind of indicating levels. You've also shown Tamar production. Should we just link those 2 together?
Charles D. Davidson
Well, I will give you an answer to that one. I think you should take the data on that slide and tie it all together. We're very careful about projecting gas prices in Israel because it's not just Israel Electric. We're working with a whole swap of customers including some, as we start thinking about exports, customers that are outside the country of Israel. So while we're in that environment and before we've got an ink contract with Israel Electric, we're being pretty careful about making projections there. But what we tried to do, and I think it was Rodney's intention, was to give enough information on that slide in terms of the sales forecast, what's been the history of gas and trends on gas pricing in Israel and the market and the cost of that project to give you an idea of how to put together the valuation of Tamar.
Unknown Analyst -
With your partners, you could really be a monopoly in the market. How does that affect your thinking and how does that affect the negotiations?
Charles D. Davidson
Well, first of all, we think that there's a broad market there. So we don't view ourselves as a monopoly at all. I know we've had hit or miss days with the production from Egypt. This is a period where it's off again after the pipeline was bombed again, but it's expected. The last I saw it, it was expected to be back on in a week or 2. Also, there are now other companies that are beginning to mature their exploration prospects in the basin. So I think in the end, there's going to be multiple sources of gas going to the market in Israel. This is a big basin and yes, we did a good job of identifying a lot of prospects and leads early on, but I would expect that others will find some things as well. So I think it's really about as we talked about gas pricing, it's all about making sure that we don't do anything to damage ourselves when we're in a negotiation by trying to lead our customer to a particular number. But instead, our goal is to achieve the best value that the market will deliver, knowing that this is a market that Noble has done a great job of supplying gas to and also knowing that Israel is a country that's going to have a lot of gas for a long time. And they're going to get tremendous benefits from that in terms of a reduction in energy costs, as well as some of the environmental benefits as well as the security of supply, which is a huge factor. So all those get factored into these types of arrangement. Different than here in the U.S., we sell on a very long-term basis in Israel. So when we're talking about contracts, we're talking about contracts that are various customers 10, 15 years in duration. So we have to be very careful about how we structure them, how those things adjust over time, how do we accommodate changes. So it's a very complicated discussion and one that when you have multiple partners, each of them has different levers that they're trying to deal with, with a particular contract. So it's a great problem to have, but we take it a step at a time.
Unknown Analyst -
Can you give us some idea, a little color on what you saw with your 3D seismic in Nicaragua, maybe how many structures you identified and when will you be drilling your first well?
Charles D. Davidson
Susan, you want to take that one?
Susan M. Cunningham
We've got at least 2 structures. We're seeing a couple of other different plays and possibilities, so that's why I left an open-ended number because we're still working on it. In terms of when we first drill, we need to get partners to get all the process going and so we're not going to predict that at this time.
Charles D. Davidson
One of the few that we went into at 100% partly because we felt it was such a great opportunity and we also felt that it would be more valuable to mature the exploration opportunities before bringing in a partner and leverage the value that we've generated, and I think that will hopefully play out to be true. But as Susan said, we need to get partners. We don't like to drill high-risk opportunities 100%. Probably the most unique one here recently is our drilling in Cyprus, which is actually hopefully will end up being at 70% pending an assignment of that, but we felt with the kind of risk we associate with it that we would go into that. But Nicaragua is a much higher risk opportunity, and we want to have a partner along.
Unknown Analyst -
A question on Carla in West Africa. I mean, this is a very interesting discovery. It's deeper, it's oilier. Presumably assuming that your amplitude probably works, I'm wondering what the implication could be. Do you actually have stacked plays in this area, and if yes, your 448 million barrel, is that sort of underestimated at this point?
Charles D. Davidson
Well, the numbers we have are the best estimates possible, but when you get late breaking news, perhaps it derisks something along the way. But there's always ins and outs on that. For instance, Bwabe, we didn't find commercial hydrocarbon there, so that probably was an offset. I mean, Susan, you want to talk a little bit about Carla and how that might have been identified? I'm not sure it's a classic amplitude play because the deeper oil plays have been more challenging, but it's probably been an evolution of how we interpret some of the deeper seismic.
Susan M. Cunningham
Yes, actually, it's been my experience around the world that when you get into new basins, the first thing you find are the easier stuff, which is the amplitude, the gas -- more gas on amplitude tends to be shallower. And then you learn about the system and about what you can see on the seismic and you go deeper, and hopefully you find liquids and I think that's what's happening here. And so as we evaluate the seismic, we're just learning what are the subtleties and this is just the normal process of what the subtleties are as you go deeper and understand how the rock properties work with the liquids and gas.
Charles D. Davidson
Remember that the way this all started out was seeing a little hint of oil in a zone in one of the early wells we drilled in the basin, and that really gave us that first hint that there was a system working that was -- there was perhaps a couple of different sources that were working in the basin. And that of course led to continued drilling and I think the great surprise at Aseng where we went and found an oil rig in there and that just sort of opened it up, opened our minds to looking for different things besides these fuming gas amplitudes that we're seeing occur. So hats off to the team that continue to work and understand these subtleties, and that's what it's all about as we move through because clearly, there is a huge prize in the liquids, the oil and liquid-related discoveries, a tremendous value and they can also be developed much more quickly without looking for export markets.
Unknown Analyst -
Chuck, looking across your whole portfolio of opportunities, can you guys rank or compare the political risk, environmental risk and operating risk between onshore North America, Deepwater Gulf of Mexico, Israel, West Africa, just so we have a sense of how we should be risking each one of those areas?
Charles D. Davidson
We do look at -- and I think a lot of your focus was on political risk rather than belowground risk. And so we do look at risks in all of our areas. They're difficult to rank because they come from different sources of risk -- there are completely different types of risk. When you look at the U.S. and U.S. onshore, probably while it may not -- it kind of falls in the category of political risk. You got the whole risk of access to development, access to acreage. Are you going to be allowed to carry out your programs. As we talk about additional regulation, I think that's what we have to factor in, is there's going to continue to be increased regulation on the unconventional development processes, probably along the lines of water, water disposal; perhaps on hydraulic fracturing, although I think the industry is doing a good job of increasing its disclosure in terms of hydraulic fracture. So those are all potential risks, and we work to mitigate it. John had a slide and talked about our water sourcing in Marcellus. We looked at that very carefully in the Marcellus because we know that if you get in a wrong spot in the Marcellus or you're not doing things properly, you can create your own risk. And in many instances in the U.S., you create your own risk through bad operations and you don't want to do that. Our Gulf of Mexico, we've been through the terrible incident of 2010. I think the industry has gotten a lot of improved standards there, but there's still residual risk in terms of what will be the pace that you'll be allowed to execute your program and I think that's still an open question today. West Africa and Equatorial Guinea, we've seen a very stable country in Equatorial Guinea. But always when you look at a country that's driven by a single leader, you know that you've got the uncertainty if there's a change in leadership. We factor that in, we look at that. We've had some good, I think, assessment to what scenarios and we think that's a very manageable risk. And in fact, you can look at other examples of countries that have had similar changes and worked through it. And in Israel, we probably experienced the first risk and that was finding a whole lot of something where it was never expected and seeing the terms revised on us. But I think at the same time, we ended up getting to the right answer for the country and for ourselves there and moved behind it. But when you look at Israel and you think about it, you think about how do you, for instance, source and export projects, thinking about security, about land access and that's why we've got this team looking at a number of sites throughout the Middle East. So every area has got risk. I would say that our portfolio, when we go to outsiders and look at it, actually the risk profile is pretty good. It's pretty good because we have stayed away from some of the more challenging areas that are down on the bottom end. You've all seen these rankings, and we've looked at a few of those countries and we've run from a few of those countries that tend to have really challenging risk profiles. So today we look and it's actually a pretty solid profile in terms of risk. There are different risks and that all goes back to a diversified portfolio. What you don't do is you build a portfolio that's completely tied to the same risk. So if we had a portfolio and all it was tied to was unconventional gas and the scale of this business, I would be very concerned because then you're exposing yourself to single commodity, single project risk. We don't have that. We've got it diversified.
Unknown Analyst -
Chuck, could you elaborate a little bit on what your liquids cut expectation going on in the Marcellus? And how do you and the industry optimize returns given the lack of processing capacity and related market and particularly for ethane in that region?
Charles D. Davidson
I'm going to ask John to take that on. I think really there's been some very nice -- one of the things we certainly looked at as we got in the transaction of how to handle the liquid piece of it. So there are some things already in place on that.
Yes, so if you think about the potential, I think it's about 30% of our acreage is actually in the wet gas window side there at the Marcellus. And we're starting to see -- and of course, the issue becomes -- the real issue is ethane, how do you move the ethane out of there. We're starting to see a lot of different people look at options to move that out of there, and I think it's kind of the old story if you build it, the market will come. Well, it's there and the market is coming to it, so we'll continue to work those options over time.
Charles D. Davidson
So we've recently had discussions with some -- with one company that's working on some delivery mechanisms for ethane. And Sal [ph] already has secured the process, some very significant processing capacity that will allow us to expand in the near term. So I think the pieces are coming together. The big challenge will be is how much the industry will be allowed to blend going forward. There's some near-term relief that's been granted for blending in this wet gas area, blending ethane back into the gas stream. But ultimately, you would believe that, that ethane, some of that ethane is going to get recovered and move into a petrochemical feedstock because it's just too valuable to keep putting into the gas stream on a BTU basis.
Let me correct one thing, I just thought about it. About 15% to 20% of our acreage is actually in the wet gas window, not as much as I originally said.
Unknown Analyst -
With respect to the strategic partners that you referenced in the LNG potential export side out of Israel, can you talk about what the ideal strategic partner, some of the characteristics that they would have?
Charles D. Davidson
Well, when we think of an ideal strategic partner, you kind of put them into a couple of different buckets, and the idea one would be that could bring as much of the -- all of that together. One is access to market. So a partner that is either providing a market or has access to market, a partner that has expertise in global LNG and a partner that has the financial capacity to help in executing on export projects. So those 3 components are what we're looking for. Either they bring a market or they have access to market, they've got the expertise and they've got the financial capacity to help move through because we're of a view that -- we love to explore and develop oil and gas fields, but the amount that we may invest in LNG would probably be less than what we've got in the upstream. We will see, but it's the concept that we're looking at. So those are kind of some of the attributes that we would look for coming forward. Now keeping in mind that we've got other partners in the upstream that have perhaps different needs or different priorities on those and we have to sort all that out. Rodney, do you want to add anything on that? I got it? Okay. All right. We'll let that one rest.
Unknown Analyst -
Just some questions on the unconventional programs, just trying to outline the NPV of the Marcellus and the Niobrara relative to resource size and that global chart. They stand out quite well relative to some of the other exploration opportunities. Just curious on kind of how sort of Brazilian unconventional opportunities is stacking up relative to the rest of your explorations. Obviously, you've talked about a couple hundred thousand acres. Are you pursuing that? Kind of heads up or are you more inclined to go via a buyer on the JV side? What kind of general reasons are you thinking of? [indiscernible] question.
Charles D. Davidson
Dave, do you want to just talk a little bit about that? Because that is a priority of ours, and I think you can probably talk a little bit more about what our strategy is as we pursue those.
Unknown Analyst -
Yes, and maybe the capital as well...
David L. Stover
Bob [ph], yes, it's a little early on the capital piece. But as far as the strategy, and Susan alluded to it [indiscernible], the focus on the onshore U.S. for the existing assets has been the DJ program and the Marcellus. On top of that, we're continuing to build new positions in areas, I'd say, they're kind of unconventional or tight reservoirs that we feel could potentially turn into core areas and that's where Susan alluded to, the program that we have in place. And a new venture group we have in the U.S. along with a new venture group we have focused internationally continuing to look at new opportunities. And that's where we're continuing to build out some acreage positions that we go through a stage gate process, the same thing we do on all our new venture opportunities. So look at how we invest capital in the different decision points as we go along these. Now the objective is to move these through inventory quickly, just into a point where there -- you've evaluated the seismic, get them to the point where they're drill-ready, past certain areas and a lot of these in the unconventional were really looking to be what we call pod concepts, where you're making sure you've tested enough of the area to understand what the opportunity is there. And then run through that process and decide it either has the potential to be a core area or doesn't, and either keep them in the system or move them out of the system.
Charles D. Davidson
So I think, and just to follow up a little on that, we tend to do those ourselves and we like to generate those. And obviously, the more you can keep it to yourself, it really lowers your acreage cost. So generally, we're looking at low acquisition costs there. The Marcellus was a unique -- something unique because there we really saw the opportunity to put a core area into our portfolio now. The ones that we are working on new ventures, they typically wouldn't have the potential to become a core area for several years. And so the Marcellus was a bit unique. It was, again, the right structure, right assets and we felt that it complemented our portfolio immediately so we took action on it. But we're generally, if you look at our business whether it's new ventures, which is exploration around, we're generating shock. We basically generate these opportunities and we mature them and we either toss them out when they don't look good or we move forward if we have success.
Unknown Analyst -
Going back to the Israeli LNG, it's obviously larger to export given how much you found. How is the Israeli government attitude towards exports? Where is it at now versus a 1.5 years ago? Are they more amenable to the concept now?
Charles D. Davidson
Well, Rodney, you want to talk about that? I mean, actually, we're over there in Israel a few weeks ago and we had some discussions on that. And it's -- I think it continues to get clarified, but maybe give what the latest thinking is.
Rodney D. Cook
You bet. As you may have seen, the government has put together a group of individuals from various ministries across the country to begin to look at their gas, not just exporting, but their overall natural gas policy with the expectation of future success as they go forward, not only ourselves but the others in the industry as well. All the indications we have from the Prime Minister's office through all the ministerial offices that we visited with, were constantly is [indiscernible] verify these is that the government recognizes that there needs to be an export opportunity when you have the resources that we discovered. We fully expect that to happen. They recognize, as said in the slides, that it brings value to them but also, it helps to grow the exploration industry into their country. Currently, they are looking toward a late February date to come together to finalize their gas policy, which we'll have the opportunity as we go forward to provide info on that as well. We certainly [indiscernible] expected there. The ruling will be -- the policy will be a certain portion of the gas in Israel will be no doubt be available for export.
Charles D. Davidson
I think this is -- and I'm really -- I look forward to the results of the committee because this is the first really that Israel had stepped back and said we need to really think about what the impact has happened. It happened so quickly from 2009, '10. You suddenly go from a country that has small gas resource to declining to suddenly be thrown into a global energy market. And so they're really trying to think through in their own minds. Some of these will get down to and I think will impact ultimately things like the demand as they look at other ways to use this domestic energy. And I've said over and over again, I love the domestic market. That's the fastest way to monetize the discovered resources. So besides working all these export options, we're working very hard, and Rodney alluded to some of that, we're working very hard to build the domestic market because it's got tremendous potential. And I'm hopeful that this committee will, in their broad, look at things also begin to recognize there is opportunities for demand growth in Israel that will help them meet a number of objectives both economic as well as environmental as well as security aspects of it.
Unknown Analyst -
And I guess just as a follow-on, the value of gas sales to the domestic market kind of the NPV of the gas is pretty visible to investors. It's a little harder to grasp the concept of the value of gas and the LNG exports. How should we think about the value of the gas under that scenario?
Charles D. Davidson
It is harder until you have a specific project, and we need to move that forward because as you're well aware, in an export situation, a lot of those are tied to unique contracts. And then once you execute those, you'll see what the net back is and you'll see it with all the pieces. We're seeing what the global market is for gas. We've talked about it some in the past, and that's about as granular as we can get right now without knowing whether, gee, is this project going to be based in Israel or Cyprus or Jordan. In one instance, it may have access more to the Asian markets versus European markets. So it's a little early. I'm just -- this is where we're probably able to give you less detail because what I don't want to do is mislead anybody as to what the answer is. We're defining it ourselves, and we're seeing that the global LNG market has been changing quite a bit. It changed after Japan, it changed after a number of countries. It started considering different views on nuclear power. It changed as a result of some of the projects in Australia and their progress and their costs. So it's a moving target, it's a moving target. So the best thing we can do is to point to where is the gas market today in Israel and knowing that we expect that any exports are going to have to be competitive with that or perhaps even better.
Okay. Well again, thank you so much for your attention and your support. Just a reminder, there are boxed lunches available. The management team will be around to visit and answer any additional questions. But again, appreciate your support, and thanks so much.
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