Good morning, ladies and gentlemen, and welcome to this Statoil US Investor Day here at the Four Seasons Hotel in New York. Also welcome to our viewers on the web. My name is Morten Sven Johannessen, and I'm the Vice President of Investor Relations for Statoil in North America and Canada. Before we start, I just want to go through briefly the security for this room. If the fire alarm goes off, we have to assume it's the real thing, so please then go through the door at the back, up the stairs, and out to the muster point in the front of the building. Also, as always, I'd like to point out our cautionary statement. Please read that. Then I would like to introduce today's speakers. First, Bill Maloney, Executive Vice President of Statoil North America, will start.
Followed by Jason Nye, Senior Vice President of our US Offshore Operations. Torstein Hole, who is Senior Vice President for our Onshore Operations in the United States. Lars Christian Bacher, who is Senior Vice President and President of Statoil Canada. Finally, Erik Finstad, who is Senior Vice President of our exploration efforts in the United States and Canada. After that, we're going to have a Q&A session. We expect the webcast portion to end at 12:00 noon, then followed by lunch for those who are here, and then we'll go over to the speed dating, and we'll come back to that afterwards. With no further delay, I'd like to welcome Bill Maloney.
Morning, everybody. It's really nice to be back in New York. I, as many of you know, I grew up here, and I was counting the blocks on my way to the hotel today. I went to school 14 blocks from where we're standing right now, so it's very nice to be back home. It's also nice to see lots of familiar faces out in the audience, as well as some new faces to Statoil, so welcome to all of you. I got a bunch to tell you, as well as my colleagues, so let me just get right to it.
Last year, at this time, my colleagues on the executive committee and myself gave a presentation down at the New York Stock Exchange talking about our new strategy, where we put forward that Statoil had a goal of reaching 2.5 million barrels a day equivalent production by 2020, and that the North American piece of that was 500,000 barrels a day by the end of 2020. Well, a lot has happened since that period of time. I'd have to tell you that some of us, myself included, were a little bit nervous about that 2.5 million barrels a day when we got up there. I think things have happened over this past year that make us feel a lot more comfortable with that number.
Our colleagues in exploration have delivered wonderful results with impact discoveries in Norway, in Johan Sverdrup, as well as Skrugard. Even this year, delivering discoveries at Havis and then discoveries in Tanzania, as well as in Brazil. A great start for the future for us. My friend and colleague, Øyvind Eriksen, and his teams in Norway have delivered good production in the first quarter and have a stream of projects that can boost production even more towards the future. Our gas machine, as you see, one of our goals here is realizing lots of profit from our gas division. We had wonderful first quarter results on sending gas to market in Europe. Having the ability to turn Troll and Oseberg up is an absolutely wonderful thing.
We were able to do that and secure good profits in the first quarter. We said that we wanted to streamline the portfolio through M&A, and we've indeed done that. You saw the divestments, some in upstream assets to Centrica in Norway, the Gassled pipeline system, and just recently our Statoil Fuel & Retail. That's on the sell side. On the buy side, of course, in the period since June of last year, we bought Brigham Exploration, and we'll talk more about that, which we feel quite happy with. We also acquired more acreage in the Eagle Ford play. Outside of Norway, we've been able to increase production at Peregrino field.
What you'll hear more of today, we've increased production at Leismer in the Bakken, in the Eagle Ford, as well as the Marcellus. Hopefully what you'll get, our aim from myself and my colleagues, is to walk you through North America in a bit more granularity, show you what our goals and objectives are, and where we're headed towards the future. This is a good story. If you look over the past decade, from 2002 to this year, we've increased production on a compounded growth rate of 20%. If you look from a year's time, we've increased production 75%. If you look from 4Q last year to 1Q this year, we've increased production by 38%.
All of that is a welcome story, especially when you think about production being somewhat of a proxy for cash flow. In the first quarter, we've shown that we were at 149,000 barrels equivalent a day. If you look just last week, we were at 171,000 barrels a day. We're feeling quite good at the moment about the trajectory of our production increase. Just a bit more. In the Gulf of Mexico, we added, and Jason will talk more about this. We added Tahiti and Thunder Hawk in 2009. Tahiti has already produced over 100 million barrels. In March of this year, Caesar Tonga came on stream, and that's already at plateau production. That's terrific.
The onshore, with both Lars Christian and Torstein will talk about, we're just over actually 100,000 barrels a day equivalently. In addition to the production increase, we are building a fairly robust resource base in North America. As you can see from the slide that Statoil's total is about 23 billion, and we in North America are about 30% of that. Last year, Statoil posted a Triple-R reserve replacement ratio of 1.17, and we in North America were a significant portion of that. Given this resource pace, we are well-positioned for future production growth here in North America and in Statoil as well. How are we gonna get to 500,000 barrels a day by the end of the decade?
This is our roadmap to do such a thing. At the bottom, you'll see a series of offshore projects, both in the U.S. as well as in Canada. Jason Nye and Lars Christian will take you through those in detail, but we're actively involved, spending a lot of CapEx on some very good projects to increase production toward the future in the offshore. In the onshore business, with our positions in the Marcellus, in the Eagle Ford, in the Bakken, as well as in KKD in Canada, we see a very large ramp up. In fact, the biggest piece of ramp up in our production towards 2020. We feel we have the assets in our hands to get to this growth.
Now, of course, we need some exploration help as well, and Erik will talk about exploration, but we feel we've got a strong portfolio there that can add more assets and more resources, and to turn to reserves on top of that. We're still in the investment phase in North America, very much so. There, the bar on the left-hand side is 100% of Statoil and how the CapEx is allocated out between the NCS, North America, the rest of the world and exploration. And then our piece is to the right of that, and you can see a lot of it is in the U.S. onshore, as well as non-sanctions projects. That gives us a lot of flexibility. An awful lot of flexibility.
In how we think about CapEx, we're fairly disciplined, but we're also fairly resilient in the sense that we can move things around as situations happens. I can give you an example. In the U.S. onshore, we've taken the CapEx down in the Marcellus, and you will have seen in the press that the rig count has gone down in the northern part of that play, while increasing CapEx in the Bakken in an oil-rich play. We look at value more so than volume, and we've got a lot of flexibility how we can adjust the CapEx through what could be fairly tumultuous times in the near term. Statoil has an awful lot of value chain experience that we can bring to the table from Europe.
In North America, we've invested in pipeline capacity, in storage, in processing, and even in rail systems. The whole goal, of course, is to enhance the upstream value of our assets. One example here, and Torstein will talk a bit more about this in detail, but if I can give one example is we very early on invested in capacity in pipelines up to Toronto and here to New York City, right? The first pipeline to be built across the under the Hudson will happen in 50 years, I think, and we will be a part of that. The idea, of course, is to get access to premium markets.
If we're able to bring access to markets to Toronto and here in New York City, you get a premium to Henry Hub helping the economics of our gas plays. We've got lots of experience in the midstream, and we can bring that to bear here in the US to enhance the value of our upstream assets. Okay, something quite near and dear to my heart. I'm a geologist by training, and something that Statoil is quite good at and has a history of is applying technology to everything that we do. The first slide there is a bit of a structure map. Sub-salt seismic imaging is key. It's key to the exploration phase of what we do. It's key in the development phase of what we do. Having the best seismic image allows us to do.
to de-risk prospects as well as to smartly develop our oil fields. It says cracking the Paleogene there. Jason will talk more about that. The Paleogene is the oldest part of the Tertiary. It's not the best rock in the world, meaning it doesn't have the best porosity and permeability characteristics. However, the Paleogene has an awful lot of hydrocarbons in it. If we can quote-unquote, "crack the Paleogene," or in other words, increase the recovery from that, say, single digits or in 10%, if you can get 3, 4, 5, 6%, we can then, billions of dollars can be unlocked in value by doing such a thing. Also shown on this is something from Canada. HOTC, we call it, the Heavy Oil Technology Center that we have in Calgary.
You know, what we're trying to do is improve the SAGD process, trying to use less steam. Increase production, decrease emissions. Lars Christian Bacher will talk a bit about this, but we're at least we've started well. We've If you look at what we've done relative to the rest of the industry, the production in our oil sands play has gone up in a very good way, and steam-oil ratio has been quite low. It's been a good start, but we still have a long way to go. On unconventionals, we well don't really like that word, but I'll say shale and tight oil plays here in the U.S. I think we're in the very, very early stages of those plays. Do we really, as an industry, understand the radius of frac in individual wells?
Do we understand where along that frack we're getting the best contribution from? The answer to that is no, we don't understand that 100%. With that understanding through technology, then we'll get better at it. We'll understand spacing, we'll drill smarter wells, we'll do better completions, and with that, enhance value of our plays. The University of Texas is shown there. We have entered a five-year agreement with UT in Austin, and I had the privilege just recently of giving out five Statoil fellowships. No, five, sorry, eight. Look at my notes. Five PhDs and three master's students. They're all working on thesis projects that affect our business and will help us move things along, which I think is great. Young minds on fresh problems and ideas is a wonderful way to solve problems.
It's a good thing for Statoil, and we think it's a good thing for UT. Our exploration department has a lot to be proud of. We've made a series of very big discoveries, as I mentioned in my opening remarks. The first and foremost, as it says here, as Tim always says, early access at scale. We've been doing this for quite some time. Let me give you an old example and a new one. In Tanzania, the recent discoveries that we've announced there, the two of them, that acreage was acquired in 2005. Early access, when not a lot of people were sniffing around, the East Coast of Africa. Statoil got in early, and we now today are seeing the fruits, the results of that. Eric and his...
Tim and their teams went in and got recent access in Angola, 5 blocks in the sub-salt play in the Kwanza Basin. We've seen competitors have had some recent discoveries there. We've got our fingers crossed, but we've entered early. At scale, it's quite a big chunk for us, but we have high hopes for that one. A bit later in the presentation, when Erik comes up, he'll tell you about the access that we've done in Canada, where we have indeed accessed a number of basins at quite a large scale. The second point on there is around impact wells. It's nice to have exploration acreage, but you need to find volumes. Statoil is a big company, so it needs to be of size.
An impact well in Statoil language is 100 million barrels net to Statoil. The discoveries I announced earlier, Johan Sverdrup, Skrugard, Havis, and then the ones in Tanzania and Brazil are all impact discoveries, which is terrific. We've got a series of core positions, exploration-wise, around the world, and here in the U.S. is one of them. Gulf of Mexico as well as East Coast Canada are core to our exploration effort. There's a lease sale today, so lots of us are on pins and needles wondering what's gonna happen there. Statoil did bid in that sale, so we'll all have to watch the results of that. Last year, we made a discovery in the Gulf called Logan, where...
Erik will speak to that one as well, where we hope for a lot of in-place oil. Can we crack the Paleogene and then get more hydrocarbons out of that one? HSE is our license to operate. It's part of absolutely everything that we do. If we get this wrong, we don't get to do anything else. It's something that is on the top of our head all the time. Every Monday morning, I go to the executive committee, and I have to say, I have to report on two things. The first one is HSE, and the second one is production. Every Monday morning, and sometimes it's at 6:00 A.M., given the Norwegian time difference.
It's something that's taken very seriously at the top of the company and all the way through, down to all of our operations on the ground. It's critical to what we do. Now, there's been lots of focus, especially in the deepwater Gulf on HSE, given the incidents that happened. We inside Statoil are one of the original members in MWCC, where we have a position on the board of that Marine Well Containment Company. We're also in Helix. We have a, I think, a fairly good relationship with the Department of the Interior. We see them on a regular basis. We're able to get our permits in a timely manner. While things have changed, I think from a Statoil perspective, we're kind of back in business.
We've been drilling a number of wells in the Gulf. The Department of the Interior has visited us on a number of occasions, but it's been overall, I'd say we're at a good place and moving forward. On the onshore, it's about getting the details right, about getting the well designs correct, about building pipelines, about handling water in a good way. If you do the basics right, then HSE results are just a natural conclusion. It's really around getting the basics correct. Another part of our onshore operations is being a good neighbor. In Canada, we've developed a local opportunity center, which we've actually gotten some awards for. In North Dakota, the Brigham Exploration started in a wonderful way of working in the community, and we at Statoil want to continue and build on that.
In fact, one of the things we just did is we had a whole bunch of folks out on the sides of roads, picking up all sorts of trash on the sides of the highways in and around Williston, North Dakota. It's being part of the community is also a way to ensure that we are paying attention to HSE in everywhere that we are. We think we can get to 500,000 barrels a day by 2020, mostly with the portfolio we have in our hand today. We also have an ambitious exploration program. We're one of the most active explorers in North America, and we think, given our success in other parts of the world, that we.
Our success in partner-operated wells in the Gulf, that we can continue to build more resources through exploration success. It's a volatile market at the moment. I just went through some press interviews where folks were asking me, "Well, Bill, what do you think about the price of oil? What do you think about the price of gas?" You know, things that we can do, we can't control the price of oil and gas as a company, but we can control what we do. We can control our operations. We can control our HSE results, and we can adjust our CapEx as time goes by. Given, as I mentioned earlier, the nature of our portfolio, our ability to do that is good.
Lastly, we don't get to do any of this unless we operate in a safe and efficient manner. As I said, about my tale of every Monday morning, it's at the top of our brain all the time. That's really the end of my remarks for the moment. I hope you're all, although it's hard to see with all these lights on my face, are as excited about what we're doing in North America as I am. Now to get a bit further down, I'm gonna introduce my colleague, Jason Nye, who will take you through the Deepwater Gulf of Mexico. Thank you all for listening.
Thank you, Bill. Good morning, everyone. Thank you for coming. It's my pleasure to, as Bill said, to talk about our operations in the U.S. offshore, which is primarily the Deepwater Gulf of Mexico. My intent today is to, I'm gonna give you an overview of our activities in the U.S. offshore, talk a bit about our growth ambitions, leading up to production targets, production ambitions for 2020. Also do a bit of a deep dive in terms of what we're doing in applying technology, particularly in the Deepwater Gulf of Mexico, to create value. So we may learn a few things here today. Bill showed this, we call this the honeycomb. This is the strategy we had that we lay.
Rolled out the strategy. It was a little over a year ago. Today we had our 10th-year anniversary of the IPO just down at Wall Street. I can assure you that the U.S. offshore, specifically deepwater Gulf of Mexico, is a very large part of what we're trying to achieve. It's what we call our core U.S. offshore business cluster, which means we'll be producing over 100,000, well over 100,000 barrels a day by 2020. We made a very deliberate approach to come back to go into the Gulf of Mexico in 2004.
A few of us were sitting in Stavanger looking at where we should enter, and we decided that the U.S. Gulf, the Deepwater Gulf of Mexico was potentially quite attractive area for us. It was actually Bill and I were integrally involved in those discussions nearly 10 years ago. What we saw was significant yet to find potential, again, specifically in Deepwater. We saw a relatively stable fiscal and regulatory regime, not as stable as we'd like sometimes, but in the grand scheme of things, it's fairly stable. Coming and being an offshore company, we saw that our experience and capabilities would apply well in the Deepwater Gulf of Mexico.
We also saw access was fairly easy through a fairly liquid asset market and farm-ins and the lease sales, with one of which is today. That's what we did. We had a program. Our tactics were come in through farm-ins, acquisitions, and lease sales, and we've done just that to the point where we're the sixth-largest leaseholder in the Deepwater. We're producing about 50,000 barrels a day from six fields. We have an asset base that's gonna project us well over 100,000 barrels a day by the end of the decade. We are strictly a Deepwater company, Deepwater-focused here in the Gulf of Mexico. We divested our shelf assets in 2008.
We had many achievements since we first entered. We've moved a lot of projects through the pipeline from discovery to development to production. We've proven that the Paleogene, which I'll talk about in detail, is commercial by sanctioning the Jack and St. Malo project. We've participated in several large discoveries, some of which you may have heard of, things like Julia, Vito, Heidelberg, and Logan, which Erik will talk about later. We've also had two deepwater state-of-the-art sixth-generation deepwater rigs under long-term contract to help us execute the strategy. The one thing that's, I would say is missing, is we don't yet have that satellite operator development.
We operate an exploration program, but we don't operate a development yet, but that will come, I'm sure. We have spent our time wisely. We've increased our subsurface understanding. We've built a very competent organization. We've put a fairly large technology program in place that I'll share with you as we gain experience for when we do take over that we become do have an operator development. The activity is increasing back in the Gulf of Mexico. Bill mentioned this. Post-Macondo, I think, both for the industry and for Statoil. For the industry, production in 2009 was about 1.6 million barrels a day from the deepwater. This year, we expect to produce about 1.2.
We've got some ways to go to get production back up. Got some big projects coming up, 2014, 2015, some of which we participate in and probably bring that level back up. Our scheduled production is steady. We're about 50,000 barrels a day now, and we'll be ramping up to, as I said, with the asset base, over 100,000 barrels a day by the end of the decade. The rig count is back up. We're approximately 30 rigs in the deepwater Gulf of Mexico today. We actually had 29 pre-Macondo, so the rig count has come back up.
We believe intelligence tells us there's gonna be another 4 rigs coming in this year and as many as 1 rig a month coming in next year. The activity is definitely coming back up. In terms of the MMS, this figure here shows you the permitting and how it changed pre and post Macondo. You can see that the permitting time is shortening. The restructuring is complete of the MMS, that we're getting more clarity in terms of the processes and the expectations. As Bill mentioned, we work very closely with them and we enjoy that relationship. To date, we've had 5 exploration plans approved and 4 drilling permits approved.
We just recently drilled a sidetrack on our Kiltern well, and the permit for that sidetrack was actually approved in 2 days. It gives you an indication of how things are improving in terms of the regulatory environment. Safety is number one priority for us. That's a main focus area, and all we have to do is consider the Macondo incident and what that meant for the industry and what that meant for the deepwater Gulf of Mexico to see why that's so important. We have a strong focus on it because really it's about a license to operate.
We bring a so strong offshore safety culture from the NCS, and we're applying that here in the Gulf of Mexico, and our performance to date supports that. This is our portfolio today. We have what I would call a very strong and balanced portfolio of high-quality assets. It's balanced both in terms of maturity and play areas. You can see highlighted in the clouds there, in the different colored clouds, those are some of the main major plays. We're fairly equally balanced in what we call the Paleogene, which is the outer, the more immature, more difficult reservoirs, and the Miocene, which is in the green there, which shows more of the, which is the more mature, higher, more prolific reservoirs.
Plus, we have a nice mix of some of these emerging plays, such as the Mesozoic and the Neogene that you see there. We're also balanced in terms of the asset lifecycle. As I mentioned, we're the sixth largest leaseholder in the exploration side. It's mostly this over 300 exploration block licenses. We hope to add to that today with today's lease sale that's going on concurrently. We also have a participation in several nice discoveries that are in the appraisal concept selection phase, things like Julia, Vito, Knotty Head, Heidelberg, and Logan. We are actively involved in 3 sanctioned projects, which you may have heard of some of these, some of the mega projects in the deepwater, that's Jack, St. Malo, and Bigfoot.
We're also producing from six fields as we speak, right now, that add up to about 50,000 barrels a day. The two biggest ones I'll mention are Tahiti and which you can see on the map, and Caesar Tonga. Tahiti is a fantastic field. It's produced 100 million barrels in the first 33 months, which gives you some indication how prolific these Miocene reservoirs are. We're now in phase two. We've got water in. We're injecting about 50,000 barrels a day of water. We're drilling another water injector. We're drilling a producer as we speak, and then we'll drill another producer, which will keep this field on plateau for years to come.
You know, we had a 30-year perspective on this field, and when it's all said and done, this, you know, this is a fantastic field and could produce up to half a billion barrels. The other field I mentioned, that just came on in March is Caesar Tonga. That's three wells producing great. It's actually at plateau already. Again, it's attesting to the quality of these Miocene reservoirs. We're in the process of planning a fourth well. It'll be drilled later this year, come on in early 2013. There will be further phases here like there are in these early days, but, like there are in Tahiti, where we'll ultimately look for that secondary recovery and additional producers.
The last thing I should mention is that we do continue to high-grade our portfolio. We will look for quality assets that fit our strategy we'd like to add to our portfolio, but we also will divest of assets that we deem as lower quartile, fourth quartile, and others see more value than we do. For instance, we just divested our interest in Loryan, which is a small producing field, to our partner Davis last month 'cause they saw more value than we did. To the production growth. This is the roadmap for production growth. You can see that right now the 37,000 barrels a day, that was the actual that was the total amount in the first quarter.
Caesar Tonga came up, we're producing about 50,000 barrels a day now. You can see the prospects, and Bill showed some of these, but these are just the prospects in the deepwater that are underpinning our growth to well over 100,000 barrels a day. On top of that, there's exploration upside. These are just things we have line of sight, but there's a huge significant exploration program that Eric will talk about that can add even further growth. Three projects I'd like to talk about in some detail. Jack and St. Malo, these are two fields. It's in Walker Ridge, it's in Paleogene play. It's deep, fairly deep, deep water, 7,000 feet of water, deep reservoirs.
These will be subsea tiebacks to a floating production unit. The capacity is 170,000 barrels a day that's being planned for. It's currently being built. This is a new area for the government. There's no other infrastructure here. We're building this as a hub. We've got capacity for additional processing modules, so we can expand it in the future. There's plenty of room for subsea tiebacks. In fact, Julia, which is another big field that we're participating in, is actually gonna be a tieback to this, to Jack/St. Malo. Significant large in-place volumes here, billions of barrels in place. But it's technically challenging.
This is older Paleogene Wilcox reservoirs that's been highly compacted, and it's still early days. There's not a lot. The first field in the Paleogene, the Wilcox just came on this year. So we have a large technology program in place to actually get these barrels out, and I'll talk about that in some detail. Things are going according to plan. Startup should be. We're development drilling as we speak on both St. Malo and Jack. We're building the facilities, and we should start up in late 2014. The other one I'll mention that's a bit less mature but equally exciting is a project called Vito.
You can see it in the outer years. It'll come on in the latter part of this decade. It's a sub-salt play, and it's in the Miocene. It's about 4,000 feet of water in the Mississippi Canyon. I can say it's probably the one. It's a big discovery. We're currently in appraisal mode. We just finished one appraisal well. We're gonna drill another appraisal well later this year. It's probably one of the biggest finds in the Deepwater Gulf of Mexico in the last 10 years. We're still sorting out exactly how big it is, but it's quite large. We have a 30% share in that.
We've just been approved with a 4-block unit from the MMS from the authorities. This is another project where technology is important, because this was sub-salt. It was difficult to see. It was proprietary sub-salt imaging and data acquisition that enabled us to see under it. You can expect that through time you'll see there'll be a lot of we'll see secondary recovery and so on to bring us on to a secondary drive to bring out to bring up barrels for many years to come. Let me switch over to our technology program now. We do have an extensive technology program. This is a typical profile from a Paleogene field.
The challenge here is that we have significant STOIIP, significant barrels in place. Again, 5 billion barrels, you know, for instance, in particular, typical field, but very low initial recovery, and it shows here less than 10%. The reason that is is the reservoir properties. We are looking at. These are tight reservoirs. There's a lot of heterogeneity. You drill one well, and then you offset by a few miles or so, and you get surprises. It's what we call, it's almost what we call dead oil. There's not a lot of gas. It's not completely dead oil. It'll flow, but there's not a lot of gas. There's not a lot of energy to bring.
Even under these high pressures, there's not a lot of energy to bring the oil up. Given our significant position in the Paleogene, we see the prize in having a large technology program to then increase these recovery factors. Our ambition, and if we succeed, is to have the recoveries go from less than 10% to over 20%. There's probably four dimensions around this. It's about increased recovery, which is really about secondary drive. It's about less expensive, it's about well design, particularly multilaterals. It's about improved seismic imaging, and it's also about reducing CapEx for facilities. We're halfway through a five-year program on Crack the Paleogene. We've seen a lot of progress.
We have over 20 projects in place. We're seeing a lot of technology transfer from the Norwegian Continental Shelf. We've had to deploy technology for years. We're actually running quite a few pilots in Norway, which then can be used back here. To me, this is the kinda thing that Statoil's good at. This is about. This is one of Statoil's strengths. It's about deploying new technology. It's about managing the risk of that technology, and we have a long history of doing that in Norway. You've probably heard that we have recovery factors on the NCS, in the Norwegian Continental Shelf, in excess of 50%. It took a lot of hard work, a lot of technology application.
We're not gonna get that far with the Wilcox. It's just different. Mother Nature's been different here. We certainly think with that experience and with this technology program, we can bring it well above the current expectations and bring it over 20%. This is a very busy slide, and I won't go into too much detail on it, but it's intentionally busy 'cause what we're doing is building a toolbox that we can use to Crack the Paleogene. This is not exhaustive. This is a lot of other things we're doing here. These are some of the different tools we're using, and it's not. There's no silver bullet here. It's not one.
You gotta look at different methodologies, different tools in our toolbox to apply to different fields and different combinations, and that's what we're working on. I should mention a few here. You can see up in the one in the upper portion there, our Dual Gradient Drilling. This is about taking the weight of the mud column in the riser and separating that from the mud column below the seabed. So essentially, we're virtually drilling from the seafloor. The reason that's important is we drill at very thin margins in the deepwater Gulf of Mexico, and this will allow us to control the wells much better and drill much more cost effectively and safer.
We're running a pilot in this year in Norway on this, and also there'll be a well, our partner Chevron is drilling a well in Bigfoot in 2013, we're using dual gradient drilling. Sub-salt imaging, Bill talked about, but most of these reservoirs are below salt. The size, again, the salt distorts the seismic imaging, so it takes a tremendous amount of computing power and quite a bit of skill to unravel what's below the salt. We're also talking about extreme drawdown, if you can see that there. The reservoir pressure is about 15,000 PSI. What we'd like to do is get that through production, get through various means, get it down to, like, 5,000 PSI, less than 5,000 PSI.
What that creates is a lot of differential stress. We're now looking at new materials to put in the well, new types of steel, for instance, that can handle those differential stresses, and we're working with various vendors to do that. Last but not least, I'll mention it. It's a mouthful. It's a single-trip multi-zone frac-pack, frac tool. This is a completion technique which allows us to go in and complete these wells with one trip as opposed to doing five or six. That could save months of time on the rig. These rigs, you know, they're quite expensive. We're deploying this right now in St.
Our operator Chevron is. We expect to use this on all our prospects, all our developments in the Paleogene. Let me give you a little more detail. I got limited time here, but a little more detail on some of these. This is about secondary recovery. This is about adding energy to the reservoir. This is where we're gonna see the greatest benefit, we think. The challenge here is we have low permeability reservoirs, very little gas. By adding energy, by injecting something into the reservoir, we can expect to get more, maybe double the recovery factor just from this one methodology. Different things we can inject. One is water. Water kinda acts like a piston.
You put the water in there, and then you push it through, and it pushes the oil through the system out to the production wells. Sometimes the reservoirs are so tight that it's very difficult to water in, so another technique we use is gas injection, which is shown here. That actually, the gas is miscible in the oil. It mixes with the oil, changes the property of the oil, makes it flow, makes it more mobile. There's a lot of different types of gas we could talk about. We can talk about methane and natural gas. We could talk about CO2, nitrogen, even air. There's a lot of sources of gas we can use here. We see this as being the one with the greatest potential.
We have a lot of experience as a company here in places like Gullfaks and Oseberg as early as the 1990s. Another technology that I'll give in some detail here is related to drilling. Drilling these wells are very expensive. We're talking $200 million-$250 million to drill and complete a well in the Paleogene, given that the water depth, given the reservoir depth, a well. One thing we can do, rather than drilling one well with a single wellbore, what we're looking at doing is drilling multiple, what we call multilaterals. You can see the demonstration here. You have one service hole, but then from that, you drill multiple wells from that and down deeper. You can get.
In essence, you'll end up getting two wells for the price of one and a half in this example, something which you have two multilaterals. More importantly, you get much greater reservoir contact. We're gonna have a lot more wellbore touching the reservoir. That's particularly important because in these reservoirs where we have faults and we have lateral heterogeneity, we just pass fluid right through them. These compartmentalized reservoirs, in the past, we need multiple wells. We can just do it with one well and go through and get all the things. We also, by getting more wellbore on the reservoir, we learn a lot more 'cause we'll see a lot more of the reservoir early on. Again, lots of experience here.
We've drilled, as a company, over 100 multilaterals in Norway. We even have some single wells in Troll that have up to 7 multilaterals to exploit the oil rim there, which is tremendous. We're just taking that technology and want to apply it here. The last one I'll mention is pumps. This is both. The intent here is to energize. We got oil down the system. How do we get that to the surface? We need to bring it to the sea bottom, then bring it to the surface. We do that through downhole pumps and subsea pumps.
ESPs, which are electrical submersible pumps, the traditional approach there, these have been used before, and they've been used all over the world. The traditional approach is to run those on tubing. The problem is that these things only last two or three years. Every time you wanna have to do a well intervention, you've gotta pick it up, you gotta bring a rig out, and you gotta pull the tubing and do a complete workover. What we're doing is we're gonna run these on wire. That's what we're working on. The wire will also supply power to these. When they do fail, which they inevitably do, we can just pull it up with the vessel and save us quite a bit of time and cost.
The other thing is what we'll do is working on improving the durability. We're looking at breaking down each of the individual components. We're taking this to much greater depths, the higher pressures we'll see here. We're breaking down each individual component, the seals, everything, and trying to get the durability that's greater than five years. Subsea pumps, technology we use in Norway. The key here is now we're bringing it down to 7,000-8,000 feet of water. Greater pressures, greater water pressures, and then we have to bring it up even further to the surface. Again, quite a bit of experience here. Let me wrap it up. In summary, I will say we have come a long way since we decided to reenter in 2004, and embarking on our new strategy.
We have a quality portfolio of assets, both in terms of the play types and its balance in terms of play types and maturity. We're participating in many of the big developments that you see today in the deep water Gulf of Mexico. Offshore is core to Statoil, so we bring a tremendous amount of development and operational expertise here from our long history working offshore. We also have a strong history of applying, developing and applying technology, and that's what we're doing, and I gave you a flavor of that today, to add value. From that, we're gonna deliver the production growth coming into the decade and beyond, and a significant amount of value to 2020 and beyond.
I would be back just to highlight once again that safe operations are key. HSE is key for us. It's a license to operate, and there really is no alternative. With that, I say thank you, and now I'd like to hand it over to my colleague, Torstein Hole, who heads up our U.S. onshore business.
Thank you, Jason. Thanks for coming, everybody. I hope that I will give you some insight in what we are doing short term and also what our long-term plans are for the U.S. onshore business. Bill told you earlier today about Statoil's, excuse me, ambition to produce 2.5 million oil equivalents per day in 2020. North America is part of it, which is 500,000 barrels a day. My responsibility U.S. Onshore will probably have the major part of that production when we come to 2020. I feel that the asset base we have is certainly good enough to achieve that. I think that we have seen a sharpening of Statoil's corporate strategy profile over the last few years, concentrating more on the upstream.
We've also seen an introduction of unconventionals in as one of the main elements in Statoil's strategy. I like that. I think that's necessary, both of it, to succeed in the future. With the development we are seeing now in the unconventional production, especially in the U.S., we will probably have to change the name of it going forward because this is on its way now to becoming the conventional way of producing. Let's see for the next version of the corporate strategy, if that's changed. Another part of the corporate strategy which is important for us, and I'll come back to, is create value from a superior gas position.
In the US, we have a good organization for midstream and marketing of gas and also oil. That's very important for me in the US onshore business, and we cooperate closely with that part of the organization. I'll come back to some of the priorities there. The ambition for US Onshore is to become a number one operator in the US going forward. We want to be best in class also in the onshore business. We think we are high worldwide in the offshore business. We also want to be an operator in most of the place where we are active. We have long-term positions. We are going towards operatorship also in Eagle Ford.
I think going forward, we'd like to do to play a major role in the areas where we are active. We will also continue the path Brigham Exploration have started, employing technology and being a leader in methods and technology to produce the resources onshore the U.S. I also speak a bit more about our priorities in that area. I would like also to mention that for us it's important to be a preferred employer and a preferred operator by the local communities where we operate, by landowners and all the people who have interests in our activity. I think that's important for us to gain trust and to be able to operate over a longer term in good cooperation with all the communities where we are.
Keeping HSE standards at the highest possible level is for us a key to earning that trust for long time, license to operate, and then to being a preferred operator. You know, in the onshore business, we are so close to people compared to the offshore business. We are in the neighborhood of many people. We are close to the farms. We are deep below people's houses. We have to take extra care, and we have to improve our practices all the way. We will use and develop technology, which is necessary to develop our, the best practices and to be a leading company in how to do this business.
In Statoil, we also believe in openness and dialogue in all dimensions of it, I would say, both internally between our colleagues and to other companies, to landowners, to local representatives, and also to governments at all levels. We think that's important for driving the business forward and for also being part of how to develop this business. Now I'll go a little bit more into our assets and how we are developing these assets and how we also are developing our ability to becoming a leading operator in the onshore business. I think it's interesting to draw a parallel between what we are doing in the onshore business now with what Statoil and Norway actually has been doing over the years developing the offshore business in Norway.
If you go back to the early days in Norway, there was no experience, and Norwegian authorities invited the international companies, the international experienced operator, to come into Norway and to start operations, start developing the fields, start exploration. In the first few years then, Norwegian companies participated together with the operators. We partnered with them, came in as partner in the licenses. We sent secondees, our own personnel, into their organizations, and we learned by doing this how to run the business. Then gradually we took over operatorship and Statoil of course developed to a major operator both in Norway and has taken that experience further out. The way we are doing it in the onshore business is quite similar actually.
We started up in 2008 partnering with Chesapeake, one of the most experienced operators in the US. We have put people into the Chesapeake organization to learn how to do this business. In 2010, we took it one step further, went into a 50/50 partnership with Talisman. Talisman is currently the operator of this acreage. We have people in the Talisman organization, and we will, according to the agreement with them, take over operatorship for half that acreage next year. Finally, so far, we acquired Brigham Exploration, a full-fledged operator in the Bakken last autumn. Now we have moved ourselves from being a partner learning this business into being an operator ourselves.
The ambition forward now is to put our sign on this business and to develop further, and to also becoming an operator in new place. That brings me to a small comment about the strategy going forward with regard to acquisitions. I know many of you ask me that when I speak one-on-one. I think you will basically see now that we will build further on the assets we have. My main responsibility is to deliver production and value from the assets we have. Going forward, we will basically look for acquisitions in or close to the current assets we have. We will prioritize liquids-rich positions with the current market outlook.
We will also look for emerging plays where we can build on the competence we now have, and also come in at an earlier stage where we have to perhaps both explore and appraise new areas before they are commercial. That will basically be the strategy for the acquisition going forward. Of course, on the other hand, we will also look for opportunities. If there is a very cheap and very attractive company or something elsewhere, we'll look for that as well. With regard to the current short-term priorities on production, we will in the Marcellus we have a twofold strategy nowadays. In the north of Marcellus, where we have mainly dry gas, we have very good well results.
What we see with the current market conditions, with the prices and the ability of the market to take limited volumes, we are drilling wells to hold the leases for the future. We're drilling enough wells, having enough rigs to hold the leases and not doing any infill drilling. We'll come back and do the infill drilling later in the north core, dry gas area. In the south, where we have seen liquids, it's been a pleasant surprise to see the development in the southwest of Marcellus, where we have liquids. We have reprioritized rigs to the south, so we are drilling more for continuous development of the south, where we have the liquids.
In Eagle Ford, we are prioritizing the liquids, the gas condensate areas where we have liquids adding to the value and producing profitably from with 12 rigs from Eagle Ford now. We are currently cooperating closely with Talisman, planning for our operations, which will start up in a small scale from early 2013, and then we'll build up to take half the acreage towards the end of 2013 in Eagle Ford. In the Bakken, we have built ourselves up over the last year. We have doubled the number of rigs. We are currently at 16 rigs in the Bakken. Production first quarter was 26,000 barrels a day. That's going up quite rapidly. All in all, I am close to 100,000 barrels a day now.
Production is going up compared also to the first quarter here. I wanted to show you this overview just for just to show you that even in a wide range of quality in the plays in the US, I think the assets we have compete very well in the totality here. What you see here is a chart provided by Tudor, Pickering, Holt on break-even prices for onshore plays. More precisely, it's the gas price it would take to get 10% single well internal rate of return, assuming a 22-to-1 oil and gas price ratio. You can see in red here, we have the major areas where we have current production and where we prioritize currently.
Southwest Marcellus, the Bakken Mountrail area, and also Marcellus Northeast to the lowest part of the curve, and also Bakken Rough Rider and Eagle Ford Condensate. All of these are well below $3 per Mcf or approximately $55 per barrel. We are very competitive also in low price environment where we prioritize the production currently. Bill said a few words about our priorities of midstream and downstream activities. As you probably know, today we experience local and regional diversities in prices for oil and gas on the American continent. We are building flexibility into our portfolio for the midstream to mitigate the bottlenecks and also to capture the highest possible margins, of course. In the Bakken, we have already an extensive gathering pipeline system.
We are approximately at 560 miles of pipelines now, and we are building towards more than 700 miles of pipeline in our contiguous area in the Bakken production fields. That is pipelines both for oil and gas and for fresh water and for produced water. By this system, we can reduce costs, we can reduce emissions, we gain flexibility to take our products in the direction where we need to to gain the highest possible prices. We also take out a lot of truckloads from the roads. It's been estimated that when we have finalized this pipeline system, we will reduce the number of truckloads per well by 4,000 altogether.
That's a major achievement, and it's very important for the local community, of course, with the heavy traffic we have on the roads. We are also taking positions out of the Bakken. We are about to finalize a rail position, 3- to 5-year rail contract, taking our crude down to the best paying part of the country, to the refineries on the Gulf Coast. We have also taken a pipeline expansion position towards the south. We will look for opportunities going forward to different parts of the country where we see with our analysis and our overview we have. We think we have quite a good overview of the current situation and the plans going forward.
We will look for new opportunities to be prepared for the future. In Marcellus, Bill mentioned what we are doing in the northeast to Toronto and New York. I will not go into that. We are also taking positions in the Southwest to have sufficient capacity to both process the liquids-rich gas and get the dry gas part of it to the markets. For Eagle Ford, we are marketing the natural gas locally to that market, and the liquids are going partly to Corpus Christi to be shipped to the best markets. I think we have good position, and I'm very happy also with the cooperation with the midstream, downstream organization of ours. They are closely working together with us.
We also see, after the acquisition of Brigham Exploration, that our organization on marketing midstream is really adding competence and value to that organization. Let me say a few words about technology as well. As Bill said, I think we feel it's there is a lot to do in the technology area. We see a big upside here going forward, and we will apply our big Statoil experience and organization to this area also going forward. But we will do it locally to a large degree. We will work closely together with between the operations organization and the people who will do the project for technical development. Let me give you a few example.
On the subsurface side, we are currently drilling per pad 4 wells in the Bakken Formation and 3 wells in the Three Forks Formation. We have set up a testing area in the Bakken where we have pilot wells. We will investigate whether that well number, the spacing of the wells, is the correct one. So we can optimize this going forward. We will evaluate alternatives both with more wells per pad and fewer wells per pad for the different benches here. We will also build a reservoir model. We have started that work, capturing all the information, both we have and what we can find from the market for the Bakken and history, and improve our understanding and prediction ability.
We have also moved in some of our most experienced people with model building and reservoir understanding from Norway and putting them together with the organization in Austin. I think will gain great result from that going forward. We will also look for technology to monitor development as we produce, for example, fiber optics. We will, as time goes by, also test other benches than the current two benches we are producing from, which is Bakken and Three Forks. Drilling and well area is even more core to this business than it is in the offshore business. We will look for better frac designs, such as a proppant concentration we are using, what rates we are using, the gel systems we are using, and so on. We will try to improve fluid management.
We will look for automation of the fluid monitoring to increase our knowledge of what the experience is and also to increase efficiency. We will also try to take experience from gas lift operations offshore, where we have a lot of experience, for example, in Norway, to use it here in the Bakken. Gas lift is an important technology, and I think we can gain a lot here, also here from cooperation between the offshore and onshore organizations. Last but not least, for example, fiber optics. We will, as time goes by, we'll also test other benches than the current two benches we are producing from, which is Bakken and Three Forks.
Drilling and well area is even more core to this business than it is in the offshore business. We will look for better frac designs, such as a proppant concentration we are using, what rates we are using, the gel systems we are using, and so on. We will try to improve fluid management. We will look for automation of the fluid monitoring to increase our knowledge of what the experience is and also to increase efficiency. We will also try to, for example, fiber optics, and we will, as time goes by, we'll also test other benches than the current two benches we are producing from, which is Bakken and Three Forks. Drilling and well area is even more core to this business than it is in the offshore business.
We will look for better frac designs, such as a proppant concentration we are using, what rates we are using, the gel systems we are using, and so on. We will try to improve fluid management. We will look for automation of the fluid monitoring to increase our knowledge of what the experience is and also to increase efficiency. We will also try to take experience from gas lift operations offshore, where we have a lot of experience, for example, in Norway, to use it here in the Bakken. Gas lift is an important technology. I think we can gain a lot here, also here from cooperation between the offshore and onshore organizations. Last but not least, we will run a lot of technology projects to reduce the footprint.
We are currently planning to test how to clean and reuse produced water from the fracking into new wells. We will try testing solutions for that this summer. It is being done already by Chesapeake in the Marcellus, but it's more challenging and it's a different way of doing it in the oil production, so we need to develop the technology to be able to do it there. We have started using gas instead of diesel for the rigs to save costs, but also to get the emissions down. We will develop that further, perhaps also to use that for powering the fracturing jobs, not only the rigs, and also for increasing the use of gas to 100%.
Currently, we have come up to about 60% use of gas in combination with diesel. We will also evaluate whether we can develop green fracturing fluids. In the Norwegian experience, we have done a lot to substitute environmental hazardous chemicals with other ones that are not so dangerous for the environment. We will see what we can do also in this area and draw the experience from the rest of Statoil. If we look at the activities and how it's taken locally, we generally experience that the local communities are very positive to our activities where we are the operator in the Bakken. The economic boom is definitely positive for most people, but of course, there are some pressure tendencies in these areas as well.
Everywhere we operate, we will work very closely with the local communities, their representatives, and the authorities, and landowners as well to reduce the footprint. In Williston, there is an example here, a picture here is our regional manager in Williston, Russell Rankin. They have taken the initiative to a special organization between the operators, some key operators, some key service companies, local communities, and landowners to work together to try to alleviate some of the stresses and tensions we see in that area. This has been taken as a very positive initiative up there in North Dakota, and we will continue to take a leading role in this. An example here is that road cleaning project, it was started by us and now a lot of other companies followed.
Now we have sort of together cleaned up all the area in Williston. Hopefully, everybody who participated in this will then take care and not throw things along the roads in the future as well. That's an example of a project that we will probably have more of. We will also work very closely so that the oil industry participates more in the voluntary work and not only behave like guests when they are in Williston. I think we need to mobilize the oil industry to a larger extent, and we'll take the initiative to make that happen in Williston. That's an example, I think, to the core of our values.
Statoil wants to be known for working together and cooperating and using best practices in all parts of our business. I come to the end now to sum it all up. Our production is increasing rapidly now, and US onshore will play a key role in Statoil and US and North America's growth towards 2020. We will prioritize value creation, so we will not have highest priority of volume growth in itself. I think I've commented on that on the Marcellus, what we are doing that. Bakken integration into the bigger Statoil organization is going very well. It's great feedback. We have basically not lost any people in that organization this first half year, so it's going very well.
We are well on our way to becoming an operator in Eagle Ford also from the beginning of 2013. Statoil is also looking for early phase opportunities elsewhere in the U.S. where we can access at a low price and build new profitable positions. Thanks a lot for your attention. Now I want to give the word to President and Senior Vice President of Canada, Lars Christian Bacher.
Thank you, Torstein. Good morning, everybody. I'm happy to have this opportunity to tell you about the activities that Statoil has in Canada. We entered into Canada in 1997, but our footprint, business footprint, really accelerated in 2007 and what we have delivered after 2007. We believe that we're very well positioned for growth in the oil sands, offshore outside Newfoundland, but also in the Arctic basins. All these assets play well to Statoil's core competencies when it comes to project execution, large projects, technology development, as well as operating in harsh environments. Our equity production in Q1 was around 10,000 barrels a day from the oil sands asset and also 15,000 barrels a day from the two producing fields that we are a partner in.
The Leismer startup, which I will cover in more detail in a couple of slides, the oil sands asset, we have shown industry-leading performance the first year of operation. East Coast Canada is a natural fit for Statoil. This is in the core of, our heritage, so to say. We are partnering Terra Nova as well as, Hibernia. With the two assets that will come on stream in 2014, 2017, Hibernia Southern Extension and Hebron respectively, we will not only fight the decline curve, but we will grow, the project, sort of the equity production, towards 2020, which is a good thing. The exploration acreage, we have a position of net, 6,700, square kilometers. That's around 1.6-1.7 million acres. The oil sands assets.
We entered into oil sands in 2007 when we acquired North American Oil Sands Corporation. As you see from the picture, we have four assets. Leismer, which is the first asset we put in production, and it will take more to develop it all. Corner is the second asset we will put on production, and then Thornbury, and then finally Hangingstone. This amounts to close to 280,000 acres and will have a potential of producing more than 200,000 barrels a day, 100% beyond 2030. We bought 2 billion barrels of recoverable reserves for $2 billion, and we farmed down 40%, and that was effective as of early last year with a capital gain of NOK 5.5 billion.
I think this is one of the takeaways, key takeaways from my presentation. I have been questioned earlier, you know, has Statoil acquired assets, you know, and paid too much. I think this is an illustration together with the Peregrino farm down that we are able to acquire asset, prove value, add value, and then partly farm down with a capital gain, okay. NOK 5.5 billion in capital gain from the farm down on Leismer and NOK 8 billion in farm down capital gain for Peregrino, the Brazilian asset. We started up Leismer one month ahead of plan. We delivered a project below budget, and we have had a very successful startup, which I will show you more in detail. We have regulatory approval for Leismer for 40,000.
The existing plant is built for 18,800 based on a steam-oil ratio of 3.0. We're looking at expansion, you know, delivering debottlenecking activities so that we can increase the production towards what we have the regulatory approval for, which is 40,000 barrels a day. Corner is also in the project execution phase up until sort of final decision whether we will build it or not, and I strongly believe we will. That project we also have a 40,000-barrel capacity regulatory approval for, and that will come on stream around 2016-2017. In this, we see that we have a lot of learnings from Leismer that we will apply and incorporate on the next assets.
The beauty about the oil sands assets, the way I look at it, is that we have way more questions than answers, which is a good thing. It shows me that we are early on the learning curve. We do not have all the answers. We have a lot of opportunities to improve this business going forward from all kind of angles. It can be the production recovery rate, environmental footprint, economics, everything. It's like a Kinder Surprise. This is a typical slide for an oil sands asset to sort of development. This is why we're in the oil sands. It's a huge cash cow in the future.
You see that you have a lot of capital expenditure in the beginning, and then you put it on the stream, and then you at the same time you build the next phase, and then gradually you will have a net positive cash position, and you will have that for 20, 30, 40 years. For the company, it's more a question in the future, what are we going to do with all this cash after tax, okay? This is why we're in the oil sands. Leismer, as I said, built for 18,800 barrels. The existing production record is 3,000 barrels higher, 21,800, with a very low steam-oil ratio on a daily basis. As I said, we started up one month early, which is good.
The equity production first quarter was 10,000 barrels a day. This is a demonstration plant. We are testing a lot of technologies that we see that will add value. We know from our history that you have to put together a technology program because if you know that it was just one project that will, you know, bring you where you want to go, then that's the only thing you would have sort of focused it on. We know that some of these technologies will not prove to be successful. Others will be successful according to what you believe, whereas others, again, will give you a higher improvement than you were looking for, and that's the beauty of this. It's a good program that we have put in place.
Let me walk you through this curve and slide before I go into the details. If you start on the bottom, the bottom curve line is Eagle Ford production per well, per stream day for the industry. The next above that's the Statoil production per well, per stream day. We have 47% higher production compared to industry first year. This is another key takeaway, okay? Is Statoil able to move from a Norwegian heritage, go international, and deliver activity? This is, I mean, as the Brits say, proof of the pudding is in the eating. I think this shows that we are able to do so, okay? The next slide is a sort of curve, is then the accumulated total production over time for the industry.
After 14 prod-months of production, that amounts to 135,000 barrels, whereas Statoil is at 250,000 barrels accumulated over the first 14 months, okay? There is a key message on top of this in my mind, and that is we know that we're standing on the shoulders of those starting up before us, okay? This, to me, is also an illustration that the learning curve works, and we know that we're early on the learning curve. There is more to come when it comes to improvements going forward within this business. We are not in the mining operation. Our reservoirs are 300-400 meters below the surface.
We need to drill and develop it with a kind of in situ technology, as I say, and this is steam-assisted gravity drainage that we are using as a technology. This is the equivalent kind of comparison, but then for the steam-oil ratio. The steam-oil ratio tells you how many units of steam you need to produce one unit of oil, okay? If you start on the bottom, this is what we have on a monthly basis as a steam-oil ratio, 2.35 it says, which is 25% lower than the industry at 2.54. This is well below the 3.0 design capacity. What this means then that we have excess steam capacity since we're operating so well.
That means that we can use that excess steam capacity to try to produce more oil, which we are doing, and that's why you have seen production above design capacity on specific days. The underlying trend is still that we are ramping up. The third line from below is then 2.94, which is then the cumulative steam-oil ratio from day one, okay? We're below 3 and then the industry at 3.74. This is based on official data that you can get from Energy Resources Conservation Board in Alberta. This picture shows you all the well pairs that we have, and this is based on last year's seismic program, or this year's actually, completed end of March.
The yellow-orange colors should tell you know, this tells you the steam chamber, the heat chamber, okay? For 60% of all the well pairs, we have a heat chamber along the whole well length of the well. We're drilling wells 300 meters down and then 800- to 1,000-meter horizontal section. This is unheard of that you have this in the industry. No one has seen 60% of the wells have a perfect heat chamber along the whole well bore, okay? There are different reasons why we have succeeded in this. If you ask me, are you willing to tell me? My answer is no. Why? Because I want to use that knowledge to get access to other company's knowledge, okay?
Now we are targeting different companies, and say, you know, we have this knowledge. You know something that I don't know. I want to learn from you, and you can learn from me. I move this business even further, okay? From an investor's point of view, it's also about asset protection. Are you able to move these assets forward? You read about some of the attention that oil sands have here in the U.S. too. I think that we are well positioned to be able to do so. We are a transparent company. We are not afraid of telling how we are doing it. We issue a report card every year. We started last year. This year was the second one.
In this one, we are talking about how we what we're doing when it comes to air emissions, water use, discharge, land use, the footprint, wildlife, how we're working with the local communities, the local bands, and then also about our technology program. We have a matrix with different KPIs, so that we tell people how we're doing. This has a lot to do with water and land use, that together with the wildlife is more an issue locally, in Alberta than emissions, whereas the emissions which is the only global issue related to the oil sands. We have set an ambitious target and an ambition. The target is to reduce our CO2 emissions by 25% by 2020 and 40% by 2025.
If you look at a couple of slides back, you see that our emissions is down 15%-60% already, based on just operational performance together with some of the technologies that we have implemented. This is also cash. Okay. A big part of my OPEX for the oil sands is buying gas to produce steam. Okay. You know, as you know, that the gas price is low, so that's favorable for oil sands. But still, it's a big part of my operating expenses. Improving and reducing the steam-oil ratio really reduces your emissions, but it also improves the economics related to this business. To wrap it up, we have a very diverse portfolio for long-term growth. This plays very well to our core competencies.
For me, the three years I've been in Calgary and running and heading up this business, it's the same four levers I have to pull regardless of assets. That is reservoir understanding, which we're good at. It has to do with drilling of wells, which we're good at. It has to do with technology development, which is in our DNA. It has to do with building an organizational capability, which I think that we have proved that we are able to do. So this is a beautiful place to be in Canada, as United States is a beautiful country to live in. The next one on stage is Erik Finnstrom.
He's Senior Vice President for Exploration North America, and he will also tell you a little bit more about the exploration acreage that we do have outside offshore Canada. Thank you.
Thank you, Lars. Good morning. I'm very happy to be here this morning to tell you about the exploration program that will help develop Statoil or help develop North America into Statoil's second core area. We have, in fact, assembled one of the most aggressive and wide-ranging exploration programs of any offshore operator in North America. Bill, Jason, and Lars have touched on a number of issues already. I will give you a bit more detail. One year ago, as Bill mentioned, at a similar gathering here in New York, Statoil announced its new corporate exploration strategy. Three of the main building blocks of the strategy were presented as early access at scale, applying technology and skills, and drilling impact wells. Statoil has certainly delivered on this strategy with a run of seven impact discoveries in Norway and internationally.
Access at scale has been delivered with major access projects in Angola, Canada, and Russia. North America has and will play a key element in Statoil's drive to develop a leading exploration company. Our footprint in North America has expanded dramatically and gives us a strong basis for growth. The deepwater Gulf of Mexico forms the core of our North America exploration portfolio. We have approximately 300 active leases in the exploration stage, making Statoil the fifth-largest exploration player in the Gulf. We've established a long-term drilling program employing our 2 sixth-generation drilling rigs, the Maersk Developer and the Discoverer Americas. The Chukchi Sea, offshore Alaska, positions us in the Arctic frontier. We have 16 operated leases there containing our Amundsen prospect and 15 non-operated leases containing the Devil's Paw prospect.
Currently, both of these are in the well-planning stage with 2014, the 2014 open water season as the target date for drilling. Now, the Arctic is clearly a challenging environment to operate in, remote and harsh. We are mitigating our exposure to this by cooperating with the other major players, major operators in this area. Specifically, we are looking for operational synergies and cost savings by working towards a coordination of drilling activities with ConocoPhillips in the upcoming open water seasons. Moving to Canada, we have a very strong operated position in the Grand Banks basins. In particular, our Flemish Pass position is characterized by multiple impact prospects, where success will allow us to capitalize on a dominant land position and our harsh environment skill set. Our land holdings in the Canadian offshore have increased greatly in the last two years.
We have roughly doubled our G&G staff in Calgary in the same time frame to match this asset success. In the United States, we run our business from Houston, where we have centralized our exploration staff for more focus, more efficiency, and direct contact with our partners and other stakeholders. Logan has been mentioned several times. This is our first operated discovery in the Gulf of Mexico, and it does carry a significant volume potential. We estimate the size range to be from 1 billion to 2.5 billion barrels of oil in place. We expect the discovery, the Logan discovery to be similar to the other Paleogene fields in the area where we have equity positions such as Jack, Julia, and St. Malo. The reservoir will be challenging in terms of recovery. We know that.
However, the Logan well does plot in the upper regions of reservoir quality for the Wilcox in general, and also has a lighter and thus more friendly oil than many other of the Wilcox discoveries, somewhat mitigating some of the factors that Jason spoke of in terms of reservoir drive. The implementation of technology developments from the Crack the Paleogene project will, though, be an important factor in maximizing the value of Logan. That is already being examined in a multidisciplinary project in conjunction with planning of the 2013 appraisal well. Now, here is the seismic that we've been speaking of, a depth image 3D seismic section.
A key component of being a competitive player in the deepwater Gulf of Mexico is to have the capacity and the resources to execute complicated seismic imaging projects. We have built an in-house center based on a very tight cooperation with Schlumberger WesternGeco that now gives us the flexibility and a powerful resource in this area. This particular seismic section illustrates the challenges we are addressing and solving. You note the complex salt formation that you see towards the top of the section with the rugose top and complicated base. This scatters the energy that we need to get through the salt down into the reservoir section below. You can see that we have, underneath the salt, imaged complex trapping structures under and against the salt body. This is what forms our reservoir targets.
We are employing our processing center with the most advanced seismic depth imaging algorithms available and the highest quality wide-azimuth 3D speculative data to achieve the results that you see here on this section. As we've said, several times, Statoil is conducting one of the most active exploration programs in the deepwater Gulf. We plan to participate in 6 exploration and appraisal wells per year in the short to medium term. We have been a leader in the post-Macondo permitting process and the first company to receive 4 exploration drilling permits. As you can see from the map, we have built a significant exploration portfolio covering all of the proven deepwater plays. You can see the plays outlined by the various symbols on the legend there.
Over the next two years, our drilling program will test impact prospects such as the Paleogene Bioko prospect, the Miocene Candy Bars prospect, and the Norphlet Formation Demon Star prospect. This will be supplemented by select high-quality non-operated opportunities and other of our operated prospects currently under maturation. We are currently drilling Bioko and also currently evaluating the results of the recently completed Kilchoman well. Now the deepwater Gulf is a prolific and highly rewarding basin, but also geologically very complex and challenging. We have chosen to prioritize an area we consider to be the most promising in order to focus our efforts and to build the highest possible quality seismic database within this area. It is roughly outlined by the wells shown on the map and our current license portfolio. Going forward, you will continue to see Statoil concentrating our resources and drilling program there.
Let me move to Canada. Our Canadian position represents a successful execution of the early access at scale strategy. Since 2010, we have increased our gross acreage position by a factor of 6 and built a dominant, excuse me, a dominant operated position in the promising Flemish Pass Basin, along with a strong position on the southern flank of the producing Jeanne d'Arc Basin, as well as a non-operated position in the Orphan Basin. We have now contracted for a three-slot program on the West Aquarius rig to drill three impact prospects starting at the end of this year. The Harpoon and Cupid wells will build on the Mizzen discovery in the Flemish. While Federation, the Federation well will test a high risk but high potential structure up dip of the producing areas in the Jeanne d'Arc Basin.
Yeah, a little more detail on the Flemish. We have drilled and appraised a discovery in the Flemish Pass Basin, and that is the Mizzen structure that you see illustrated on the cross section. Mizzen proves the hydrocarbon system in the Flemish Pass Basin and gives us significant follow-up potential, as you see illustrated by the prospects on the map and the developments on the cross section. We expect that surrounding structures can have access to more prolific oil generating source rocks and similar or thicker reservoir units. The evaluation of the appraisal results of Mizzen give us a range of 100-200 million barrels of recoverable oil, with an expected value of about 150 million barrels for Mizzen.
Further drilling on the surrounding structures will be done before any decisions on a possible development of Mizzen are made. Our license positions in the Chukchi Sea offshore Alaska and the Beaufort Sea offshore Canada gives Statoil exposure to the anticipated prolific oil potential of the Arctic basins. Exploiting these positions will be a long-term project requiring patience, persistence, technology development, and the utmost care for the environment and local stakeholders. Our work to date leads us to believe that we have very large oil-prone prospects in all of our licensed positions. Our first wells are in the early planning stages with a 2-3-year planning and permitting time horizon in the Chukchi Sea. The Beaufort license will have a longer time horizon with 3-D seismic currently being acquired this summer.
To summarize, Statoil has built operating capability, a strong portfolio, superior seismic databases, and not the least knowledge that will allow us to test a diverse and volume significant set of prospects over the next two years. This is an effort we intend to sustain over time as North America steps into the title of core area for Statoil. I thank you for your attention. That is the end of my presentation, and I think the end of our presentations this morning. Morten will take over from here for the Q&A session.
This is like a test. Those of us who have a few questions understand that we're going to be speeding the session along so we can take more questions. Do we have any questions for Tom?
Yeah. Thanks, Morten. My question really, I wanted to talk about the long term other than that role and target. How much is exploration success or risk exploration factor into that one? Secondly, I just had a question with respect to scale in North America right now. Do you feel that you have the organizational capability in place to achieve your targets? On the M&A front, I think you kind of emphasized emerging plays.
Could you talk a little bit about the M&A market right now a little bit, and also, appetite for corporate or larger size deals? Thank you.
Bill, I think, I'll let this to you.
I'll just take them in turn. On the exploration side, there is not a lot of exploration in that 500,000. Most of the portfolio that Erik showed is contributing post-2020. There is some in it, but the majority of it, as Lars Christian, Torstein, and Jason said, most of it comes from the portfolio that we already had. Appetite for acquisitions. You can never say never. In the onshore of the US, we continue to want to enhance our position both in the Bakken and the Eagle Ford, as well as the Marcellus. Will things change along the way that would allow Statoil or others to look at consolidation and then adding other groups? Perhaps. I mean, who knows where it's gonna go from here?
A year ago, did I think we were going to buy Brigham Exploration? Well, we were looking at lots of things, but it wasn't in. It took a while before we solidified that. Will we do something in the future? Perhaps. You know, never say never, but the plan at the moment is to do mostly things from organic ways, but we continue to look at opportunities. Did I miss any part of that?
Organizational
Organizational capabilities. Ah, sorry.
We've hired a lot of people. Brought lots of people in from different parts, from different countries, from different companies, excuse me, and we continue to build organizational capability. I feel we've come a very long way. We are gonna add more people in the Bakken and the onshore. We've added some more people in Canada. I think we're fairly stable in both exploration and in Jason's part of the world in Deepwater Gulf of Mexico. We've added in a good way. We're not 100% there of where we wanna be, but I think we in the medium term will be able to bring on the folks that we need to get the job done.
Can I add to that?
Yeah, sure.
Thanks, Bill. On the last part about building the organization, I think that you know, we've had a lot of people join our office, join our business the last year or two since we had the reorganization and launched the growth campaign here. I talk to those people that come in. I think the reason they come to us is because the company that we are and the values that we work by, but also the growth profile. They see where we are today.
You know, last year we produced less than 100,000 barrels a day, and they see where we're gonna be at the end of the decade, over, you know, half a million barrels a day here in North America. It's an exciting place to work. I talked to some of the old-timers, but some of the more experienced people in the organization that were in Statoil in the 1980s, when we were just launching as a company. They say, you know, the same feeling that they had back then in Norway is the same feeling that we have in the office now as we grow. It's a fun place to work.
Next, please.
There you go.
Thank you. Hi, it's Eliezer Palacios from Maxim Group. When you mentioned that you were interested in having around 6 exploration lease participation per year, could you comment about how many of those would you see operated and what kind of characteristics would you seek in participating in, you know, these wells? Do you plan to have a little bit of a bigger stake? I know some of your wells are 15, 20% working interest, some of them a little bit bigger. Just curious about your allocation of capital, what kind of wells in the Gulf of Mexico.
Okay. Six exploration and appraisal wells. I think what we're looking at would be approximately 4-5 exploration and 1-2 appraisal per year. In terms of the operated equity stake, we would like to be in the prospects we operate at least 50%. We're looking at 50%-60% equity in the best prospects that we have.
How many wells per year?
I think we're looking at trying to employ the full capability of our two operated rigs. We're looking at 4-5 operated wells per year.
More questions over here.
Thank you. Good morning. Richard Roberts from Howard Weil. My question is for Lars. You mentioned using some of your proprietary knowledge in the oil sands to try to leverage gaining knowledge from competitors. Is that implying that you're going to take on maybe another partner in your position on the oil sands or maybe farming into other projects out there? Could you elaborate on that somewhat?
I think we are very well positioned for growth based on what we do have. If you look sort of years ahead, it will, in my mind, be strange to say, you know, been there, done that, and just settle with what we have. We have a lot on the plate to work on over the next 5, 10 years, so there is no rush. I think that if you can really make a difference, since this is the third largest resource base in the world, if you can really do a difference from operational-wise and get the cost down, then the sky's the limit as to what you can acquire, I think, going forward.
We will use this knowledge that we are acquiring and also the technologies that we are developing to tap into what we see the other companies are doing so that we can create a win-win situation, so both companies can move forward at a positive pace. Yeah.
Do you anticipate any further sell down?
Anticipate any further sell down? No. Not in the short term, in the medium term, long term, I don't know. Whether we will acquire in short term, medium term, long term, I don't know. If I knew, I would not tell you, huh? A comment about the organizational capability if we have it for growth. If I look in the rearview mirror back to the first question, we can't say at any point of time that we have been missing an organizational capability, either skill or manning, to deliver on the plans historically, okay. If you ask us if we're manned up to deliver on the 2020, no.
That would have been sort of the wrong answer, too, if I had said yes, because then that just means that I acquire a higher cost level too early. I think the key message here is that we have been able to hire people, good people, as we've gone along. We also see that this market is picking up both in U.S. and in Canada. Some people choose to leave the company too for other companies. In Canada, we have also had a couple of examples that the people, you know, three months after they left us, knocked on our door, want to come back again because they see that Statoil is a very good company to work for.
Another question over there.
Hi, Peter McNally with Kingdon Capital. My question's on midstream and infrastructure. Besides the 160 or 140 miles of pipeline you talked about adding, how much capital has to go into North America to hit your targets? And do you think it's an advantage or of owning more infrastructure, or are you gonna rely on third parties to handle volumes?
Thorstein?
I think we are well-positioned now. We have mainly been taking positions and not ownership in the midstream. We can't rule out anything for the future. We are evaluating the options, and we are evaluating both the short, medium-term and long-term positions that we are taking then in the infrastructure towards the different markets. That might be to cover directly our own production, but it might also be to look for opportunities where we can trade and have the possibility for trading third-party volumes. I think we basically prioritize the same going forward, having our own production to as a basis for taking these positions and then probably look for trading opportunities as well.
With regard to CapEx, I don't want to comment directly on that. In North America, we are spending 20%-25% of Statoil's total CapEx. It's a big growth machine for Statoil, and I don't want to go further down in details on that one.
Just one comment from me. I think what you see is that, the onshore business in U.S. and Canada is going to be a business more and more for those with a strong balance sheet, to lift this potential and create value. Any further questions? No, I think people in the room want to wait with those questions for the roundtable discussions. I would like to thank the people in the room, and also the people who are on the web, for joining us this morning. This presentation can be taken off our website at statoil.com. Also the presentation on the web can also be rerun later. Thank you very much on the web.