Good afternoon, ladies and gentlemen, and welcome to this exploration seminar arranged by Statoil. Before we start, let me say that there are no fire drills planned for today. In case the fire alarm goes off, you will need to exit through the market exits and gather on the outside. Today, Statoil's Executive Vice President, Tim Dodson, and his management team will present the exploration strategy for Statoil, recent results and regional work. Following a presentation from Tim Dodson, we will have presentations by the Senior Vice Presidents, Pål Eitrheim and Nick Maden. After a Q&A session, we will then take a short break. After the break, the Senior Vice Presidents, Erik Finstad and Gro Gunleiksrud Haatvedt will present, again, followed by another Q&A session. Erling Vågnes is unfortunately ill and will therefore not present today as previously announced.
Please note that questions can be posted by means of telephone only, not directly from the web. The dial-in numbers for posting questions can be found on the website. All the presentations are published on Statoil.com. I kindly ask you to make special note of the information regarding forward-looking statements which is attached to the presentations. It is now my privilege to introduce Statoil's Executive Vice President for Exploration, Mr. Tim Dodson. Please, Tim.
Thank you, Hilde, and good afternoon and good morning to everyone, wherever you might be. Welcome to Statoil's Exploration Seminar. I guess we couldn't have picked a much better day. A little bit fortunate with that, but that's how it is sometimes. Luck does play some part in exploration, but hopefully, as we'll be able to demonstrate to you, through the next three hours, it's not only about luck. Of course, what I'm thinking about is the updated information on the Pão de Açúcar discovery in the Campos Basin in Brazil. We issued a press release at 12 o'clock, as did the operator, Repsol, where we have communicated a significant upgrade in volumes for the pre-salt discovery in the Campos Basin.
As you've probably seen, we are now communicating volumes of more than 700 million barrels recoverable of light oil and three TCF of gas. For those of you who need a conversion factor, that's you can multiply that by 180 to get barrels of oil equivalents. This in itself is a giant discovery, more than one billion barrels. Very significant in itself, as stated also in the press release, very important for our position otherwise in Brazil, and we think also very important for the acreage which we picked up in Angola, the pre-salt acreage, which we picked up there at the end of 2011.
Our plan was and still is, with this seminar, to give you some more insight, to dig deeper behind the successful exploration program which we've run over the last year and a half. Try to explain to you what we do and why we do it, what things are important for us, so that hopefully through this afternoon you will understand more about our strategy, more about why we have had the success we had, and hopefully I can build even more trust and confidence in our ability to deliver a similar kind of success in the future.
You're all familiar with the updated corporate strategy, and hopefully you all recognize that one of the most important or one of the important building blocks on this is to develop a leading global exploration company. As I've mentioned to many of you before, that this part or this chapter of the exploration story really started about three years ago. When I was asked to take over the responsibility for the global exploration unit in Statoil, we quickly made a decision that we should revisit our strategy. We should thoroughly examine, you know, what we had been doing, what others were doing, and then make a conclusion as to whether we needed to change how we were doing things. That strategy was approved at the end of 2009 and subsequently implemented.
I'll come back to that. On first of January, 2011, a year and a half ago, there was a major reorganization of the company and the decision was made to for exploration to have a seat on the executive committee of Statoil. I was asked to take on that position, was very glad to accept. That was also one of the elements which we'd drawn up in the strategy that we, it would probably be beneficial for us to have one exploration unit rather than have three. Previously, we had a separate unit for Norway. We had a separate unit for the international exploration. We had a separate technical unit. I think what it has allowed us to do, it's allowed us at least to prioritize in a truly global fashion.
I think the third element is obviously, you know, the recent successes. It doesn't hurt to have early success. We've had quite a lot of that over the last few years, probably significantly more than we expected, i.e., more larger finds quicker than we expected. We now have six high impact discoveries, of which two are giant discoveries, i.e., more than a billion barrels of oil equivalent on a hundred percent basis, Johan Sverdrup and now Pow. We've also secured significant new acreage positions and I'll return specifically to the deal we did with Rosneft a little bit later in my talk.
I think we've strengthened our position, our core positions, i.e., in Norway and Gulf of Mexico quite substantially, over the last 18 months too. None of this is possible without strong HSE performance. We've had a good development when it comes to our HSE statistics. The one which is shown on the left here is our serious incident frequency, i.e., the number of serious incidents we have per million man-hours worked. I should say the level now is around about one, i.e., one incident per million man years worked on all of our operations, whether it be exploration, development, or production.
Having excellent HSE results, and I'm thinking about all of the aspects, but especially about the safety and the environmental aspects, they are a prerequisite, and our license to operate wherever it might be. It also helps us to become a preferred partner, and by that I mean maybe also an operator which others choose to work with. It definitely does give us a competitive advantage. Exploration is involved in many aspects and many areas of HSE, many types of operations, but in particular, seismic and exploration drilling operations. My exploration unit has responsibility or accountability for all seismic acquisition in Statoil, be it for exploration, development, or production purposes. When it comes to our well portfolio, of course, you know, sort of we are the first to test the different areas.
That means that we know typically less when we go into these areas than we do on the Norwegian Shelf or places like the Gulf of Mexico. We have to be able to take very good care, or we need to be prepared for all eventualities. I can say to you that the exploration statistics, these are the corporate statistics I showed, the exploration statistics for the last two years are equally as good as what we've done on the corporate. As you know, from our global footprint, we have different challenges we're facing. Physical challenges like ultra-deep water. I mentioned 2,800 meters of water depth off in Pão de Açúcar, similar in Tanzania, similar in Gulf of Mexico.
In other places, you can add to that the challenge of seasonal icebergs, things like the seasonal icebergs off the northeast coast of Canada. You can add small margins, high pressure, high temperature conditions. Gulf of Mexico, just about every well you drill is very challenging in that respect. King Lear, another, we all know about the King Lear well in the south of the North Sea. More recently, we also have to handle other issues, like the threat of piracy off the eastern coast of Africa. That threat is real.
I'm not going into all the details, but there are a lot of evidence that the piracy activity is, you know, it's there, it's real, and it's active all the way down through the East African coast. We don't only have to maintain, but we have to continue to focus and improve on this. The reason for that is that we have to be ready for even more demanding challenges going forward in the Arctic, especially. We have acreage in Alaska. We have acreage offshore Canada, Northeast Canada, but also off the Newfoundland now in the Beaufort Sea, and not least now with the position we've picked up with Rosneft offshore Russia, both in the Barents Sea and the Sea of Okhotsk, where ice is also a challenge.
This is our license to operate, and it's something that we have to have continual focus on day in, day out. I think I can safely say that we have delivered on our exploration strategy. Our exploration strategy is really quite simple. It's about three things. It's about early access at scale. It's about drilling more high impact wells. It's about exploiting our core positions. Early access at scale is. It kind of speaks for itself, but it's really enabling a larger acreage uptake at lower costs. Yes, maybe some more risk, but at the same time, potentially more reward. Ideally, if you get in early, you should be able to do this at lower cost. Although, as you're probably aware, there is a huge and maybe ever-increasing global competition for exploration acreage. Then high impact wells.
You know, when we did our strategy work in 2009, we kinda concluded that, you know, sort of we weren't making very many high impact discoveries, if any, over the last few years. When we started digging into this, we said, well, it wasn't really surprising because we weren't drilling hardly any high impact wells either. These are normally somewhat higher risk. You don't find high impact or don't make high impact discoveries on every other well. I guess we have the last 18 months, but that's not normal. You know, the chance of success here is more likely to be one in five or one in six. That doesn't mean if you drill five, you make one discovery, or if you drill six, you make discovery. Sometimes you have to drill 10 or more in order to do that.
Of course, the reason we do this is to find higher volumes, but also to be exposed for the outliers, the ones with the really high potential. If we think back over the last year, what kind of surprises have we had? I think the one big positive surprise for everyone was Johan Sverdrup. It was off scale compared to what we expected and what anyone else expected. It was a much better reservoir than we thought. Everything was better. You know, if you don't take that kind of risk then you don't get exposed for that kind of upside. Power is really the same. Better reservoir quality, a much larger hydrocarbon column than we envisaged, and in fact, a more favorable oil type, even though associated with gas, than we dared to envisage.
Then the third point about exploiting core positions. When I've talked to a lot of you before, you know, this is all about maintaining or establishing robust portfolios in highly prolific oil and gas basins. Norway is obviously one of those. The Gulf of Mexico is obviously another. I think we can safely say that we recognized from before that Angola is, and Brazil, I hadn't added to the list, but I think I could probably add Brazil as a core exploration position for us to the four which are noted here. Canada's, I guess, is already there. We have made a couple of discoveries, and we have, you know, established a very significant acreage portfolio here. That's what we mean by exploiting core positions.
The importance of this is, you know, so if you make a breakthrough discovery like we've done in Tanzania, Eni and Anadarko have done in Mozambique, not forgetting BG in Tanzania as well, I think we just see what often it can lead to. It doesn't lead to that single opportunities. It leads to a multitude of opportunities, not necessarily in the same size category, you know. Sort of opening up these new plays, you know, is one of the key things we do in exploration. Of course, results have been very good, six high-impact discoveries.
As we speak, we're drilling two or three more, where we expect to be able to announce the results by the end of the second quarter. I think we can say we successfully implemented our strategy, and we plan to stick with this. My team will tell you more and outline how we're positioned to deliver more. We think we're doing well. What do others think? They think we're doing pretty well as pretty good as well.
If we look back, this was part of the work we did with the exploration strategy. If we look back to the period of 2006-2008, we actually weren't doing too bad on volumes. Most of the volumes were Norwegian volumes. There's nothing wrong with that, of course. Most of them were also related to near field exploration. We drilled up a whole bunch of near field prospects, because our production hubs needed more oil and gas. Of course, these are also high-value barrels.
If you study this chart, basically what it's saying in different blue colors here, and just before I go too much further, just to point out that the two graphs here, the one on the left and the right, they are IHS statistics, and the one in the middle is from Rystad Energy, the one related to value creation. If I just go to the left-hand and the right-hand figures, then the blue colors here, it's probably a little bit difficult to read the legend. The darkest blue is discoveries greater than 500 million barrels.
As you can see in the period from 2006 to 2008, Statoil had no exposure to any discoveries greater than 500 million barrels, even though in that period we did find close to two billion barrels, and this is a three-year period just to point out that oil and gas. If we now then look at the equivalent numbers for the period of 2010 to 2012 year to date, we've moved up the league table and now in second place behind Eni. What we can see here that about 50% of the volumes which we've discovered in this period are now coming from discoveries greater than 500 million barrels. That is because we have drilled more high-impact prospects.
It's not as simple as that, but it's not far from it. It was, you know, a clear step in our strategy was to expose ourselves for more of these opportunities. We have, and we've succeeded, as you can see from this. It's not only about volume, it's also about value. At least according to Rystad, we were top of the pack in 2011. They have estimated that we created somewhere around $5 billion of value through exploration in 2011. I think based on this, we can say that we are on the way to become a leading exploration company.
Then some of you might say, "Well, it looks like you are the leading exploration company, or at least close to it." I'm not satisfied that we are there yet. I think we still have to prove that we can replicate the success which we've had over the last 18 months, then we can talk. We've definitely stepped up our exploration performance. Last year or on a fairly regular basis, I've shared with you the importance of having a robust resource base. I think going back a year and a half, we communicated that we had a risked resource base around six billion barrels of oil equivalent. For every year, we drill somewhere around 40 wells, then we will drill up a fairly large share of that resource base.
Last year, we drilled up 800 million barrels. It's the small box in red there. 800 million barrels of risked resource. Fortunately, we found 1.2. We actually found more than we expected to find from the wells we drilled last year. Notwithstanding, if we hadn't replenished our portfolio with new opportunities, then we would actually be closer to five billion barrels in risked resources than six. Again, we have replenished our portfolio, and we have added new prospects in 2011, which sum up to 900 million barrels. In essence, we found 1.2 billion barrels in 2011, and we still have the same risked resource base as we did prior to that drilling activity.
If we then try to look forward a little bit, I've already mentioned and go to the graph on the right. In 2011, we drilled 41 wells, and we proved up 1.17 billion barrels of oil equivalents. It says 1.2 on the chart, just to be exact here. In 2012, year to date, we've already proved up 600 million barrels of oil equivalents, and we expect to deliver at least, and there's a P90 number on here, and you can just translate it, of course, at least 800 million barrels in 2011. Maybe I dare to use the word probably, significantly more since the upgrade for Pow, which we got today, is not included in these numbers.
I think as we move forward and what we've tried to illustrate here is the uncertainty, but also the magnitude of the volumes you can expect from exploration in Statoil in the years going forward. There is a large degree of uncertainty, as shown from the P90 to P10 ranges on the columns here. On the other hand, I think you can see that the portfolio which we already have and plan to drill up in 2013 and 2014, both of those years, they have the potential to prove up somewhere between 1-1.5 billion barrels of new resources. When it comes to our activity this year, we drilled 41 wells this year. The latest I have on 2012 is approximately 45 wells.
The reason for that is that we drilled more wells this year due to the recent successes. Follow-up wells like Lavani-1 and sidetracks and King Lear, and where we have accessed and gone immediately to the drilling stage, like in Ghana and the Hickory prospect, which we're drilling there. Our guiding going forward is approximately 40 wells per year and an exploration spend of $3 billion per year. Let me turn to other recent events and the strategic cooperation agreement we entered into with Rosneft. This is obviously playing to the first point in our strategy, early access at scale.
More than 100,000 square kilometers of prospective frontier acreage. Split between Okhotsk Sea in the Far East, far eastern part of Russia and in the northern Barents Sea. On the middle slide here, you can see we've overlaid the three licenses, the Okhotsk Sea, the North Sea. Basically, this acreage, this combined acreage here, covers, you know, most of the North Sea. This is truly, you know, scale access. The other point I think about this is that, you know, it's this is about replenish the bucket, but this is about longer term replenishment. As it was already been announced, the first wells on this acreage won't be drilled until 2026.
2016, we will drill on a regular basis from 2016 up until 2021 when we expect to complete our 6-well commitment. It's also an important supplement to our Arctic portfolio. On the right-hand side, the illustration depicts the Arctic positions which we had from before. We can now see the blue dots, which represent the Rosneft deal. We are already in detailed negotiations with Rosneft. There are many side agreements which need to be put in place before we are finally signed off. We are now where Exxon were about a year ago on the Kara, and I guess they signed off finally on the whole deal in February or March.
As I say, we have already established a team to conduct the negotiations with Rosneft. We have about 25 people in place already, and we think it's gonna take something like that in order to land all these agreements. The intention is that we have landed all of these agreements at latest by March 2013. Watch that space. What do I think about the future? Well, I think we will continue to deliver on the exploration strategy. The exploration strategy has already given significant results. I've reviewed this with my team, and we're convinced that we have a robust exploration strategy, so we have no intentions on changing that.
That means that we will continue to access early and at scale, acreage in prioritized basins, and I'm not about to tell you where all our prioritized basins are, but you start to get a pretty good feel for that, I think. We will continue to drill more high-impact wells. On the right-hand side of this chart, we've depicted where we expect these high-impact wells to be drilled. We expect to drill around 20 of these over the next three years. Let's say the overall activity level to be around 40 wells per year. We will continue to deepen the NCS and the GOM positions. We have two really important lease sales coming up. The central lease sale in the Gulf of Mexico, I think it's 20th of June, Erik, or something like that.
The bids have to be in there. Then the 22nd round, which we expect to be announced before the summer with an application deadline in the autumn. We've already communicated new drilling campaigns in Skrugard. four wells there to be drilled, 2012, 2013. three wells in offshore Canada. As I've already explained to some of you before the meeting here, we are well on the way with a huge 3D seismic survey over our blocks in Angola. That's progressing according to plan. That means we're almost 50% complete on that. I'll say in addition to building on existing core positions, then you know sort of we intend to establish more. We feel we're already there on Angola and Canada.
It wouldn't surprise me that during 2012 that we can add both East Africa and Brazil to that list, and thereby lay the basis for future production clusters in Statoil. One of the most important things for us to do is the, and one of the most difficult things for us to do, that is to maintain a portfolio of high-impact wells. In order to do that, we must replace every one we drill. We must replenish our resource base and our acreage portfolio. With that, I'll leave the floor to Pål Eitrheim. He's our Senior Vice President for Global New Ventures, and he will tell you, he'll tell you more about his activities, which are primarily related to accessing large scale opportunities around the globe. Thank you very much.
Good afternoon. My mission today is to convince you on how and why Statoil works globally to secure access to new attractive acreage. As Tim pointed out in his introduction, early access at scale is one of the three main elements in Statoil's exploration strategy. I'll try to take you a bit into the geology and the subsurface first. How we identify new opportunities and then preferably before others. In Statoil, we have defined a very ambitious goal that we always will have the best geological maps in our priority thrust area, especially. By this, we think that we can identify the best opportunities before others, and that's a very big competitive advantage, of course.
The main element in this work is to work systematically, regionally, establish regional databases, and to produce sweet spots maps within the basin so that we can locate really the best part of the basins. Of course, it's not only about the subsurface. We have to show entrepreneurship in our work. That's a very important, also very important part of our work. Local presence is another keyword that we have worked a lot with lately. At present in my unit, we are present in seven other cities around the world, for instance, in Calgary, Houston, Venezuela, Moscow, Jakarta, Beijing. This is to be closer to where the business is ongoing and to the people that have the local knowledge.
We are stepping up activities like this to come closer to the opportunities and to establish relationships with the authorities, with partners, and competitors. Creativity and new idea generation is, of course, also a very important part of this systematic screening for opportunities. Last but not least, I will also mention the need for prioritization because there are a lot of opportunities out there and we really need to. Maybe the best tool we have to, especially when we go into the high-risk spaces, is to compare the basin in between each other. I picked out this map to illustrate how we work. This is what we call a thematic map, which is very global. What this shows is how we think that petroleum system the best petroleum systems are distributed globally.
This is one of our more fundamental maps. We really use it before we take decisions in which basin to enter. As you can see, the new entries we have done, they are located in Arctic, Western Arctic, and in the Russian Arctic, in West Africa and Ghana, in South America, in Suriname, and in Indonesia. In all these regions, we think we have a very strong petroleum system. I want to take you even a bit further. I want to use this opportunity to show another example on how we work super regionally and across continents to identify new opportunities. As you may know, the Earth consists of a set of relatively thin crustal plates that through geological time has moved horizontally. There are basically three types of such plate boundaries.
This divergent plates that go away from each other, it's convergent plates that come together, and it's plates that go alongside. This is a very important geological process. The maximum horizontal speed, for instance, in these plates is about three centimeters per year. That means about 30 kilometers in a million years. In the scale of 100 million years, what we can be talking about when we do business, in fact, we are kind of talking about 3,000 kilometers. Things move geologically a lot. This map shows the Southern Atlantic region, if you can recognize it here, about 280 million years ago. Here you can see the contours. You can recognize the contours of Africa to the right and South America to the left.
It's astonishing to see how easy recognizable the geo-geometries that you know from present day can be recognized in this map. This continent we can see here was called the Pangaea that exist we think it existed, or models tells us it existed about 280 million years ago. It what we call it a super continent because this was most of the landmass on the globe at that time. If you focus on in a bit on this border zone here, we can see that already at this stage, about 280 million years ago, there was a depression in this area, in the border zone between the later Africa and South America. We think this is a clue to prospectivity.
In these depressions here, we think it's ideal conditions for deposition of source rock and establishment of rich petroleum systems. When we do work systematically, regionally, we try to reconstruct the geological history in different basin and try to fit things together and understand how things develop, to locate the most interesting areas. If we now start the video again, we can observe that about 175 million years ago, Antarctica and North America started to move away from this super continent. At about 130 million years ago, Africa and South America started to move away from each other.
Then we have the Southern Atlantic opening during a period of 100 million years, where the areas that earlier was together now was separated with more than 3,000 kilometers. Just to end up the video, which is very fancy, I at least think. It's about understanding the geological history and to try to find analogies between the different basins and the link, as in this case, for instance, between the basins we have here in the Sierra Leone, Ghana area towards French Guiana and Suriname area on the South American side, and the same between the Brazilian side and the African side here in Angola. Of course then apply this into the business and where we pick up acreage.
I'll try to go a bit back to the business again. After trying to convince you on how much it is for explorationists to work systematically to understand the subsurface, I will focus more on the early access at scale again. The reason access to new acreage is so important in our exploration strategy is the realization that we for years were not able to replace our reserves. We need to step up our new venture activities, and we need to secure both high quality acreage that unfortunately often does not come very cheaply, but also on quick moves and early entry into frontier unexplored high-risk basins where the acreage is cheap and where there could be exit options before we have to take the major investments.
This map illustrates what we have achieved the last 18 months. Totally, the accessed acreage represents acreage addition of about 70,000 sq km net to Statoil. Most of it is in frontier basins. We have accessed nine new basins and seven countries, of which two represent new country entries for Statoil, and that is Suriname in Latin America and Ghana in West Africa. In the Arctic, we have accessed the Beaufort Sea and the Orphan Basin in Canada, the East Baffin Bay Basin in Greenland, and the Barents Sea and the Okhotsk Sea in Russia. In the Southern Atlantic, we have accessed the Guyana Basin in Suriname, the Kwanza Basin in Angola, and the Ivory Coast Basin in Ghana. In the Far East, we have accessed the Kutai Basin and the Bintuni Basin in Indonesia.
Establishment of new partnerships is, as I said, very important part of exploration strategy. At present, our preferred partnerships are companies that have strong local competence and have proven a strong exploration record in each of the regions we are working in. In Arctic Canada, Chevron is our chosen partner. In West Greenland, it's Cairn. In Russia, as you know, we have negotiated an agreement with Rosneft. In Suriname, Tullow is our preferred partner. In Ghana, it is Anadarko Hess. In Angola, the preferred partner is Sonangol. In Indonesia, we also have selected a small local company called Nico Petroleum as our preferred partner, and it's first of all based on the record in the different places.
My last slide shows Statoil has managed to grow our exploration portfolio in the last year and a half of about 20,000 square kilometers. The left column, blue column here, shows Statoil net acreage at the end of 2010, and it was about 130,000 square kilometers. The red column here shows that we have relinquished a lot of acreage that we have explored and have found less attractive, and that counts for about 50,000 square kilometers. The green column shows that we have accessed about 70,000 square kilometers of new prospective, mainly frontier acreage during the last eighteen months. The last column to the right here show the status as of today. We have exploration acreage of about 150,000 square kilometers.
The scale of access represent a major step up for Statoil. It is vital for us, for our ambition for resource, replacement and to become a leading exploration company. You can expect that this aggressive, access trend will continue also in the years to come. Thank you. I will give the word to Nick.
Great. Good afternoon. I'm gonna talk about Statoil's international portfolio and activities. By international, in Statoil, we mean everything outside of Norway and North America. North America being the U.S. and Canada. It's everything else, the rest of the world as such, the big bucket. I've got a picture up here at the front of the Ocean Rig Poseidon. This was the rig that we're using to drill in Tanzania at the moment. This is a picture taken while it was drilling the Zafarani well, which is our big gas discovery there. It's about five TCF of gas, and it's currently now drilling the Lavani-1 , and we're keeping our fingers crossed on that one. It represents, in some ways, a very important milestone for Statoil.
The Zafarani well is actually really our first big international operated discovery where we entered the license at the beginning of the exploration phase. We've had a big discovery, and it's of the size that hopefully should drive us towards commerciality. It really is proving ourselves as an international company. That really is the theme of my talk. This really has been quite a game-changing time for Statoil internationally from the exploration position. We're doing a lot more activity now, both operated and non-operated, and we're having success. Some of the impact discoveries that Tim talks about have been made into the international arena. We'll see how that translates over the years into a growing and developing international position. Lovely picture here. Beautiful day.
It was actually taken on the helicopter I was traveling out on, and nice flat, calm seas, which is good 'cause I do get seasick. Okay. A map of the world. We're gonna talk about our activity, and we're gonna fly around the world. We're gonna see an awful lot of dots dotted around, so put your seatbelts on. Exits are here and there, and get ready to take off, and let's go and have a good travel. Gonna start in the bottom right-hand corner, Indonesia. As Pål has already alluded to, we've been building a big position there. It's a massive area. Indonesia is the size of a continent. Lots of basins, lots of opportunities, and it's a very open licensing system. We've been building a big acreage position there. This year, we're actually participating in four wells.
We're doing three operated wells. We've completed the first two, and there'll be a third one later on this year, and then we're gonna drill a non-operated well. I think, Eni is gonna operate that towards the back end of the year. We're currently also shooting a lot of seismic. We've picked up a lot of blocks over the last year or so. We're shooting seismic, and these seismic will hopefully help us evaluate the blocks. Some we will relinquish because we don't like the prospectivity, but some of them, we hope to bring forward again. We think these are the sort of opportunities that will bring these big impact discoveries in. A lot of the basins we're going into in Indonesia are more frontier basins, haven't had a lot of exploration, so we're looking at big features, big potential.
We're hoping as we evaluate this will impact the drilling program that's gonna happen over the next couple of years. That's Indonesia. That's the starting point there. Jump across the Indian Ocean now, we're in Mozambique. We've had a license there for some time. We just completed a seismic program at the back end of last year. We're evaluating that seismic this year, and we're hoping that this will lead to a drilling program next year and the year afterwards. We're really excited about the block. It's to the south of the big gas discoveries there. It's not on the same place as those big gas discoveries there. We're actually targeting oil on this block. That's what we're out for, aiming for in this one. We're hoping that the work we're doing this year will help us drill next year.
That's an area that's gonna be of interest to us, and perhaps in a forum like this next year. Jumping over, Greenland. We took a position last year in Greenland with Shell, and then we farmed into the Cairn acreage in the same basin, in the P2 license. That was complete at the beginning of this year. We shot seismic on the P2 license last year, and we're shooting seismic on the Shell acreage this year. We're gonna evaluate that acreage, and we're hoping that will lead to a drilling program in 2014. Again, this is an area where we've picked a big basin, and we tried to pick the best acreage in the basin, the acreage that will really test whether it'll work. This is a basin that hasn't been drilled before in Greenland.
This is our chance to look at a big opportunity, and if we like it, go for it and test it where we think it's the best place to be. We're gonna drop south now. We're back in South America. We really are spinning around the world here, collecting air miles as we go. We're in Suriname now. This was a farm-in that we did again at the end of last year. This is with Tullow. We particularly picked Tullow because they've been successful on the African side. If you remember how the plates came together that Pål showed. They've picked up equivalent acreage there, and they've actually had a discovery in French Guiana, along trend from that. We've partnered with Tullow there. We're gonna shoot seismic this year.
We'll evaluate that seismic, and then we'll make a decision as to whether prospectivity is something we wanna drill later on, probably in about 2014, if that works out. Jumping across the other side of the margin. You know, these were next to each other at one stage. We're participating now with joint Amerada Hess, and we're actually drilling a well as we speak. Keeping our fingers crossed there. We're chasing a different play here in terms of a reservoir and a trap that has been drilled successfully on that, in that area, but it's a similar source rock system. So the oil and the gas has come out from the same basin, but we're aiming for a different reservoir and different play. That well's ongoing. Keep your fingers crossed, and hopefully we'll hear something in the next few weeks or month or so.
Gonna come across Africa now, and we're into the red dot areas. These are sort of purplish-colored ones are areas that I'm gonna talk a bit more detail on further into the program. We're just gonna introduce them here, and then we're gonna dive a little bit deeper as we go further into the presentation. This is Tanzania. We've had the Zafarani discovery at the beginning of this year. As we've already said, good discovery. Got us really up and running in the area. BG as well has been having success in the area. Tanzania is now discovering quite a lot of gas, and it's chasing its neighbors, Mozambique, as fast as it can. We recognize that in some ways, a lot of gas being found here, there's a race developing among the companies involved to get the gas commercialized and to market.
We set up a project team already covering all the disciplines from commercial to field development, to every sort of area of the process so that we can run quickly and fast to try and get this project commercialized as quickly as possible. To help in that process, we've gone straight on to drill another exploration well. That's the Lavani well, and that's drilling now. Again, hopefully in the next few weeks, we'll get the answer from that well, but we're optimistic. Every time in exploration you get optimistic and you think you know what you're doing, nature has a good way of coming back and teaching you otherwise. We're hopeful at this stage. Then leaping across Africa back into West Africa, I'm gonna talk a little bit about the Kwanza licenses in Angola.
The important bit of the aspect there is how they relate to what we found in Brazil. Again, close the Atlantic back up. We've had success on the Brazilian side. That's just been announced today. That was very, very close to the licenses we had or we've acquired on the Angolan side, so we can see how that relates, and that changes what we believe is the risk in this area quite considerably. I'm gonna talk a little bit about a well we're gonna drill later on this summer in the Faroes. This is a big play opening well. It's a relatively high-risk area. It's one of the probably more higher risk wells we're gonna drill this year, but it's an area where we dominate on acreage. As Pål would talk about early access to scale, we have the early access there. We have the scale.
We have the prospectivity. If this works, this will be substantial. Finally, the area that I'm finishing with here on this slide, which is what I'm gonna talk about next, is obviously Brazil, following the press announcement we had today. It's obviously something that's making all of us smile, and we're happy. Three discoveries on the block, and we're now having to work out how we're gonna take it forward, what appraisal we're gonna do. The challenge really for quite a few of these areas where we're looking forward to drilling programs is always gonna be rig access, and that is a challenge for the industry. The ultimate timing of when things will get drilled is always a little bit up in the air at the moment because it is a bit of a challenge.
The strength that we've got to in international is that previously we had smaller positions, so we were looking for single slots on weeks, which were hard to do. We're now getting to the point in East and West Africa where we can put together a big program. That putting together a big program enables us to go out and talk to contractors and sell them a project that they can get interested and involved in and gives us a better chance of securing the rig capacity that will enable us to complete our program. Straight away, let's get into what it actually means to us. This is a breakthrough position for Statoil. Three of the impact discoveries of the six that Tim talked about are internationally. The other three are in Norway. Three internationally.
Was the start of the process that will really transform the company over the coming decade. In Brazil, last year we had the Peregrino well. This effectively was a satellite or a step along from the original Peregrino field. A good discovery there, but it will tie in easily into our existing infrastructure there, extend the field life, extend the plateau life, and be readily developable. We've already passed that project through into the development and production group, and they're studying, looking at the ways to take it forward. We expect a very quick process there to get that project through to sanction. I'll jump to the bottom because we're doing it in sort of a time sequence. That's the Zafarani well that has been completed. Very good. Got us up and running there. Different position, something we can build from.
Obviously the press announcement that's gone out today on the Pão de Açúcar in Brazil says greater than 250 million barrels. When these slides went to press on Tuesday, we still hadn't got all the approvals in place to go out with the press announcement. As I say, it is updated. It's greater than one billion barrels across the three structures as oil equivalent and about 700 million barrels of liquid. Very good on that side. Remember, this slide is a couple of days old, and we're a bit more forward running now. We'll go into the next bit, Brazil itself. What does it actually mean? There's been a lot of big discoveries in Brazil over the last few years, and it's always been in essentially the Santos Basin, which is a little bit further south.
These are the big discoveries that you've heard about with Petrobras and people like BG. What's really good about this one here, this is the first time that a pre-salt, which is the same play that they've been drilling in the Campos Basin, in Santos Basin. This is the first time it's been discovered this far north and in a new basin at this sort of size and scale. It's taken us three real attempts, three wells we've drilled to actually start to unlock it. It's a classic exploration thing. You never quite get it right first time. You have to learn a little bit, come back. We drilled in 2009. We drilled the Seat well, which you can see on the cross-section. It's on the left-hand side.
We drilled the Seat well. We found oil, but we really didn't find reservoirs. We're a little bit disappointed with that. We looked and learned, and we went back, and we drilled the Gavéa well, and we found more reservoir this time and some oil. Finally, we got the whole thing right by the time we came back the third well, and we drilled the Pão well. We've built our learning up on this space, and the majority of the reserves that we've announced in the press release today come from the Pão well. The learning that we've developed along makes us realize that we probably haven't sited the original Gavéa wells and the Seat wells in the right location.
We're taking the data we've got back from Pão de Açúcar and the other two wells, and we're rebuilding our knowledge base on this and helping understand the those two previous wells, those two previous discoveries. We're looking at the appraisal options that will go forward. We will have to drill appraisal wells on both Seat, Gavéa and Pão de Açúcar. We're looking at 3 more appraisal wells, at least. The timing of that will depend on when we finalize our plans and our ability to secure a rig. It's really, really a positive impact that we've started to build our knowledge in this pre-salt area, because the importance is that when we close back up the Atlantic, this takes us into Angola, where we're gonna be exploring in a few years' time.
Building that knowledge in this one area will help us explore more efficiently in the other area. This is why it is, as Pål's already alluded to, when we close up the Atlantic, we see them side by side. On the left-hand side, on the Brazilian waters, as they are now, if you're in the left-hand picture, you see Gavéa, Seat and Pau. Then what you see to the right of that in orange is the acreage that we've just acquired in the Kwanza license. Then to the right of that, there's been two wells drilled already, Cameia Well and the Azul Well, which have again proven oil in that pre-salt play.
When we look at the acreage, this massive acreage position we've picked up in Kwanza, where the risk going into it, one of the risks we were looking at was, does this play actually work? We've now got three wells or actually five wells, actually, dotted all around it, north, south, east and west, that actually show this play does work. When we're looking at this area here, we've taken the play risk out. We know it works. Going forward, our challenge now is to look at the individual prospects and the risks associated with the prospects. The actual play itself has worked. Even in six months, without actually specifically doing any activity on these licenses since we awarded them, in terms of evaluating, the whole risk profile has already changed. That's really, really positive.
Just a couple of cross-sections to show how basically it all looks alike. That's the important thing, getting there. Taking the knowledge from Brazil, applying it to Angola, and repeating that success. What we've got there in Angola is a dominant acreage position. Moving forward with the next stage of the evaluation. We signed the license at the end of last year, and within a week, we actually had started the acquisition of the seismic program. This is a multi-client seismic program. It's in the area shown in red on the map to the right-hand side. It covers our blocks and some other companies' blocks.
We operate two of the licenses, the ones in the darker blue, 38 and 39, and then the one in the green in the stripes, 22, 40 and 25 are our non-operated licenses. The operator in those cases are Total and Repsol. We've already started shooting the seismic, and this will help us actually evaluate the prospects. We have previous prospects that we're showing on our operator licenses. These are big features. We don't really have any doubt they exist. The whole objective of the seismic here is to confirm the actual size, but more importantly, with what we've learned in Brazil, how to correctly place the wells. This is what will happen with this seismic as we start acquiring it. We're nearly 50% complete.
As we bring it in, we'll evaluate it, look at it, and really start to understand the individual prospects and how we can best exploit it. We're targeting our first well towards the end of next year, beginning 2014. It's subject to when we get a rig, but we're really excited about this and the risk profile here has really substantially changed. Gonna jump into the second area of success, and this is Tanzania. The left-hand map shows the individual licenses. The colors there, the red block, red blob is actually the Zafarani discovery. The orange blob is actually the Lavani prospect we're drilling. The yellow blobs are three other prospects that we see on the overall license. I've only shown the prospects that exist on the 3D data that we have on the license.
We can see here the white box is actually the area of the 3D. Following success of Zafarani, we're moving on to Lavani. We've also agreed with our partners here, Exxon. We're gonna go out and shoot additional seismic. The remaining license to the left of the site, of the current seismic grid, and to this right-hand block that I'm outlining here, which are all part of the same license, we're gonna shoot seismic on those. We believe the same prospectivity we've seen in our 3D will exist in the other areas as well. This is a great area for us to build a significant position, a significant inventory, and ultimately find a lot of reserves. You can see the relationship of our block in Tanzania.
BG have been drilling to the south, and they've got a number of discoveries here. They're drilling to the north, and they've got a number of discoveries here. Then there are the big Mozambique discoveries there. This is an area of really growing activity, really growing interest, and really growing opportunities. We're right in the middle of it, which is great. As I said, we've already got a team together to move things forward. We're drilling the Lavani well. We're evaluating our appraisal options. We're planning the new seismic. Great imagery to follow on. This is an area you're gonna see a lot of activity, a lot of aggression, a lot of movement in the coming year. This is for the site. These are for the geologists in the room.
This is where you can go to bed at night and dream about. This is what I dream about. This is what it's all about. These are three seismic images here. The one on the left-hand side is from the Zafarani structure. The top one is the Lavani structure that we're drilling, and then the bottom one is a seismic line that ties the two features. What's great about exploring in this area is the seismic actually starts to see the gas that you're drilling for. What particularly happens here is, and what makes this so really good is that, the structures themselves are almost a bit like a spirit level, and the gas in it is a bit like a bubble, and it always finds the horizontal, always finds the flat.
What we're seeing here, which makes it fairly unique, whoops, is you can see the flat events. Oh, if I get the right button. Do you see these flat events coming across? This is actually where the gas is sat on the water. This is the bubble in the spirit level. When you see this, it really starts to encourage you that your confidence should be high. We've drilled this on Zafarani and proved that it works. We're drilling this on Lavani now, and we can see these flat events. It gives us a lot of confidence we're gonna be successful. Every time you have a confident, nature comes back and bites. Let's not, in England, we say, let's not count the chickens before the eggs have hatched. We've got to drill this to find out.
We really are optimistic. The technology is working, and we've been able to calibrate it with the wells we've got. Fingers crossed, and we'll have a good discovery. Then the last sort of impact well that we're gonna drill this year within international is in the Faroe Islands. What's particularly interesting here is a two-stage or a three-stage thing, is that the map on the left-hand side shows our acreage position in the Faroe Islands. We're the blue. We really dominate here. We are the major license holder, and it is a great acreage position to be here. On the right-hand side, you can see the UK area of the Faroe Shetland Basin, and there's already a lot of hydrocarbons being discovered there.
There hasn't been a lot of hydrocarbons discovered on the Faroe East side, and there's only, I think, been seven wells drilled. The reason that there hasn't been a lot of wells drilled there is that this area is an area where it's under what was old volcanic basalts. The problem that made was that it meant that you really couldn't image in on the seismic. You just got a lot of noise on the seismic. We've been working this for years, working with the contractors, and we've now got to the point where we're getting a reasonable seismic image. Not the best, not comparable to, say, Tanzania, but we're getting a good enough seismic image. For the first time ever, we can really start to see structure.
We can really start to see what you're wanting to target. We're gonna go out and drill this well this year. We're waiting for the rig to finish up its current operations in Norway. Once that's finished, it'll transfer over to the Faroes, probably in about a month's time, and then we'll drill this well. We're drilling a really big structure. It's the first time that we've been drilled out here, we're really starting to get confident that we're seeing something that we can drill. If this works, 'cause the other risks come into play then, is the reservoir there, is the charge there. We know the reservoir and charge is on the UK side, so we've got a good chance of it coming here. Does it come together in the right mix?
Well, if it does, and we have a discovery here, we have the acreage position with probably six or seven other structures just like this to be drilled. In a success case, we can really get off and running here. We can really dominate. We see this play as being a dominantly gas play. That's the last impact well we're gonna drill this year. Looking forward a little bit, what are we trying to do? We're trying to create materiality. We're trying to create value through exploration. In international, that means big acreage positions, big structures, trying to get prospects that when you're successful, they really move the company's needle, will really implant you into the country. That's what we've got here.
The purple blobs are the basins that are the high basin areas with high, we believe, high potential. That's what we're evaluating, and hopefully, we'll be drilling wells on them in the coming years. The purple ones are where we see high impact exploration wells to be drilled over the next two or three years. We've got a good position, good set of acreage, good set of opportunities, three discoveries to our name already that make an impact to us, and I'm sure many more to come. You're gonna see a real transformation of Statoil over the next 10-15 years. Thank you.
Thanks, Nick. Now, Tim, Pål, and Nick will take questions from the audience and over the telephone. I'll first ask the operator to please explain the procedure for posing questions over the telephone. Operator, please go ahead.
Thank you. If you would like to ask a question on the telephone, please press star one.
We'll start out with the audience here in Oslo. There will be microphones passed, and I will ask you to please state your name and who you represent. I can see Trond over there.
First of all, congratulations on the announcement today. One question on this. Not only is it big oil resources, but it's probably one of the biggest gas discoveries you've done. Is it likely it will be a solution where it's sold domestically? That's question one. Second question, you're currently drilling a well offshore Cuba, and I noticed it wasn't on your map. Is that because it's a high-risk low probability? Depending on the result, will you plan further wells on that? The third question on Iraq, which of course has not only the third largest official proven reserves, but likely the highest yet to find potential. You recently pulled out on the service contracts.
There is exploration round in the south coming up. Of course, ExxonMobil have moved into Kurdistan. Does that mean that Iraq is not really on your map anymore?
I can take the Iraq one. You can take the wells.
Okay. I suggest that maybe Nick takes the Pão well and the Cuba, and I'll come back on Iraq at all. Nick.
The Pão well, yes, there's a large volume of gas. I'll say we're very early in the evaluation phase, and certainly from a development option side, it is a significant volume. The sort of initial feeling probably in the early stage of a development it would be used for reinjection and pressure support. But ultimately, we would be looking for some commercial solution to that. It is the size that we think you could generate a commercial solution. But as to whether it's domestic or export, it's really too early to say. Then the Cuba well, the operator has announced that the well is a dry hole. Part of the reason it's left off the map is, I'll say a North American influence off the map. It was the one well we were obligated to drill.
It has been a dry hole. We will take the results of that, look in it, and see whether that means we'll continue on or not. Again, no decision has been made on that, but it has been announced as a dry hole.
Okay. On Iraq, as you're aware, then we've decided to pull out of the venture with LUKOIL. We failed to see any significant upside on that, and that's also the reason for us to make a decision not to participate in the upcoming exploration round. I think as Pål alluded to, it's got nothing to do with the subsurface. It's got everything to do with what's above the surface, and in particular, the fiscal terms and conditions, the type of contract which we have there. Now, you mentioned Kurdistan as well, and of course, we're watching that space very closely.
We think that, you know, I think as we've seen the activity increase over Kurdistan, we believe it has, you know, a big yet to find potential as well. The interesting thing about Kurdistan is that it has completely different terms and conditions. There's a big government take. For that reason, it's something that we are considering, let's put it like that, but no more than that at this point in time.
Today, one question on this. Not only is it big oil resources, but it's probably one of the biggest gas discoveries you've done. Is it likely it will be a solution where it's sold domestically? That's question one. Second question, you're currently drilling a well offshore Cuba, and I noticed it wasn't on your map. Is that because it's a high-risk, low probability well? Depending on the result, will you plan further wells on that? The third question on Iraq, which of course has not only the third largest official proven reserves, but likely the highest yet to find potential. You recently pulled out on the service contracts.
There is exploration round in the south coming up, and of course, Exxon have moved into Kurdistan. Does that mean that Iraq is not really on your map anymore?
I can take the Iraq one. You can take the wells.
Okay. I suggest that maybe Nick takes the Powell and the Cuba, and then I'll come back on Iraq at all. Nick.
The Powell, yes, there's a large volume of gas. I'll say we're very early in the evaluation phase, and certainly from a development option side, it is a significant volume. The sort of initial feeling probably in the early stage of a development it would be used for reinjection and pressure support. But ultimately, we would be looking for some commercial solution to that. It is the size that we think you could generate a commercial solution. But as to whether it's domestic or export, it's really too early to say. The Cuba well, the operator has announced that the well is a dry hole. Part of the reason it's left off the dot is, I'll say a North American influence off the maps. It was the one well we were obligated to drill.
It has been a dry hole. We will take the results of that, look into it, and see whether that means we'll continue on or not. Again, no decision has been made on that, but it has been announced as a dry hole.
Okay. On Iraq, as you're aware, we've decided to pull out of the venture with LUKOIL. We failed to see any significant upside on that, and that's also the reason for us to make a decision not to participate in the upcoming exploration round. I think as Pål alluded to, it's got nothing to do with the subsurface. It's got everything to do with what's above the surface, and in particular the fiscal terms and conditions, the type of contract which we have there. Now, you mentioned Kurdistan as well, and of course, we're watching that space very closely.
We think that, you know, I think as we've seen the activity increase over Kurdistan, we believe it has, you know, a big yet to find potential as well. The interesting thing about Kurdistan is that it has completely different terms and conditions. There's a big government take. So for that reason, it's something that we are considering a split like that, but no more than that at this point in time.
Yes, Teodor?
Hi there.
Sorry.
It's Mark Coughlan from Macquarie. I just had a quick question or two questions. Firstly, on the overarching sort of exploration strategy, and just thinking about the key drivers of that over the coming few years. We've seen that the opportunity set is quite deep. I was just wondering now, particularly around the high impact wells, if you feel that rig capacity is potentially sort of one of the main issues perhaps driving that forward? Or indeed, if there is sufficient desire internally to raise the exploration budget from around that $3 billion number that you've given. Then secondly, just in terms of your positioning in Mozambique relative to the other areas where you are where you have early entry.
It feels as though you have quite a high equity interest there at this stage. I was wondering if there was any likelihood potentially of farming down that equity ahead of a drilling in 2013. Indeed, if there'd already been any interest. Thanks.
Okay. I'll take the last one first, then I think it's probably Nick to take the rig one. In Mozambique, we are, we have a farm down process ongoing. We are waiting for government approval for that. We can't announce, although several of you have asked already who we are, who we expect to have as a partner there. The answer is yes, that we will almost certainly farm down before we drill in Mozambique. Nick, you want to take the rig one?
I mean, the reality is, yes, the rig issue is gonna be a challenge, not just for us, for the whole industry. What I think is, where we're getting better in international is because we're building a sizable position, we can go out for a multi-year contract for rigs that we can use close together. The East Africa position, with success, we're gonna need to drill a lot of wells. With what we've taken in Angola on a success base there, you're gonna need to drill a lot of wells. For the first time ever, we've been able to put together a multi-year program. That multi-year program means that when we're talking to rig contractors, they want to talk. Rig contractors in the current market don't want to talk to you on single well opportunities. It is gonna be a challenge.
That success brings that challenge. You know, we've got the same challenge in Brazil where Repsol is the operator. We've now gotta try and secure a rig for the appraisal program. You know, I'm sure in certain areas we're gonna achieve the timelines we want to, and in other areas we're gonna struggle.
Next question, please.
Teodor Sveen-Nilsen, Swedbank First. As Nick correctly pointed out, you are focusing on pretty many areas globally and spread wide around. Could you say a little bit around the consideration why you don't focus on, let's say, two to three areas compared to like it's seven or six spaces you're now focusing on?
I think I can let Pål take that one.
Yeah. If you are thinking about the frontier, our strategy with the assets at scale, we think that we have a strategy that is in place today.
One question on this. Not only is it big oil resources, but it's probably one of the biggest gas discoveries you've done. Is it likely it will be a solution where it is sold domestically? That's question one. Second question, you're currently drilling a well offshore Cuba, and I noticed it wasn't on your map. Is that because it's a high-risk, low probability well? If the result is positive, will you plan further wells on that? The third question on Iraq, which of course has not only the third largest official proven reserves, but likely the highest yet to find potential. You recently pulled out on the service contracts. There is an exploration round in the south coming up.
Of course, ExxonMobil have moved into Kurdistan. Does that mean that Iraq is not really on your map anymore?
I can take the Iraq one. You can take the others. Okay, I suggest that maybe Nick takes the power and the Cuba, and then I'll come back on Iraq at all. Nick.
The power one, yes, there's a large volume of gas. I'll say we're very early in the evaluation phase and certainly from a development option side, it is a significant volume. The sort of initial feeling probably in the early stage of a development, it would be used for reinjection and pressure support. But ultimately, we would be looking for some commercial solution to that. It is the size that we think you could generate a commercial solution. But as to whether it is domestic or export, it really is too early to say. Then the Cuba well, the operator has announced that the well is a dry hole. Part of the reason it's left off the map is, I'll say a North American influence on the maps. It was the one well we were obligated to drill.
It has been a dry hole. We will take the results of that, look into it, and see whether that means we'll continue on or not. Again, no decision has been made on that, but it has been announced as a dry hole.
Okay, on Iraq, as you're aware, we've decided to pull out of the venture with LUKOIL. We failed to see any significant upside on that, and that's also the reason for us to make a decision not to participate in the upcoming exploration round. I think as Pål alluded to, it's got nothing to do with the subsurface. It's got everything to do with what's above the surface, and in particular the fiscal terms and conditions, the type of contract which we have there. Now, you mentioned Kurdistan as well, and of course, we're watching that space very closely.
We think that, you know, I think as we've seen the activity increase over Kurdistan, we believe it has, you know, a big yet to find potential as well. The interesting thing about Kurdistan is that it has completely different terms and conditions. There's a big government take. So for that reason, it's something that we are considering, let's put it like that, but no more than that at this point in time.
Yes, Teodor?
Hi there.
Oh, sorry.
It's Mark Coughlan from Macquarie. I just had a quick question, or two questions. Firstly, on the overarching sort of exploration strategy, and just thinking about the key drivers of that over the coming few years. We've seen that the opportunity set is quite deep. I was just wondering now, particularly around the high impact wells, if you feel that rig capacity is potentially sort of one of the main issues perhaps driving that forward? Or indeed, if there is sufficient desire internally to raise the exploration budget from around that $3 billion number that you've given.
Secondly, just in terms of your positioning in Mozambique relative to the other areas where you are, where you have early entry, it feels as though you have quite a high equity interest there at this stage. I was wondering if there was any likelihood potentially of farming down that equity ahead of a drilling in 2013. And indeed, if there'd already been any interest. Thanks.
Okay. I'll take the last one first. I think it's probably Nick to take the rig one. In Mozambique, we have a farm down process ongoing. We are waiting for government approval for that. We can't announce, although several of you have asked already who we are, who we expect to have as a partner there. The answer is yes, that we will almost certainly farm down before we drill in Mozambique. Nick, you want to take the rig one?
I mean, the reality is, yes, the rig issue is gonna be a challenge, not just for us, for the whole industry. What I think is, where we're getting better in international is because we're building a sizable position, we can go out for a multi-year contract for rigs that we can use close together. East Africa position with success, we're gonna need to drill a lot of wells. With what we've taken in Angola on a success basis there, you're gonna need to drill a lot of wells. For the first time ever, we've been able to put together a multi-year program. That multi-year program means that when we're talking to rig contractors, they want to talk. Rig contractors in the current market don't want to talk to you on single well opportunities. It is gonna be a challenge.
That success brings that challenge. You know, we've got the same challenge in Brazil, where Repsol's the operator. We've now gotta try and secure a rig for the appraisal program. You know, I'm sure in certain areas we're gonna achieve the timelines we want to, and in other areas we're gonna struggle.
Next question, please.
Teodor Sveen-Nilsen, Swedbank First Securities. As Nick correctly pointed out, you are focusing on pretty many areas globally and spread wide around. Could you say a little bit around the consideration why you don't focus on, let's say, two to three areas compared to like it's seven or six basins you now focus on?
I think I can let Pål take that one.
If you are thinking about the frontier or strategy with the assets at scale, we think that we have a strategy that we need to do this at scale. That means several areas because the risk is so high. Our expectation, in fact, is that you don't know where, but we expect to make only one or two high impact. To have success is only one or two of these basins. That's, in reality, it won't be that big spread, but it's so difficult to tell today where the success will come. That's why we go out very broadly into new basins. We don't think simply that our target can be reached by only focusing on our existing core basins.
Could I just add to that a little bit? Because sometimes this is a question that gets asked internally as well. It looks like we're everywhere. We're not. I don't know how many countries there are in the world. I guess that changes almost on a daily basis. You know, it's more than 200. I think we're represented in somewhere about 20 countries on an exploration basis. 15, is it? There you go. It's even less, including Norway, yeah. What we've actually done, although we're for obvious reasons, competitive reasons we don't share with you, we have a number of globally prioritized basins. We have 18. We have 18 basins.
If you remember the map that Pål showed you earlier on with all the different basin outlines, the green and that on there. I don't know how many there was on there, Pål, but I don't know.
That's close to 100.
Hundred, something like that. We've picked 18 of those, and that's where we will primarily, I say primarily, focus our efforts and try to gain material access. We might, and of course, that's a dynamic process as others drill wells, have failures, have successes. We may take one or two of those away, and add one or two more. That's how we work. We start all the way out here, close it down, and as I say, for the time being, 18 prioritized basins for us. Which is, you know, it's, and as Pål says, that's what we think it needs to be because not all of those will succeed, or we won't succeed in all of those.
Do we have any further questions in the audience in Oslo? No. Yes. One more from Trond.
Thank you. Trond Omdal, Arctic Securities again. There is an election in Mexico, and for many years a lot of companies have hoped that one day, ultimately, the Mexican side will be open. Statoil has a technical cooperation for years with Pemex. Do you see any likelihood that this will be opened and Statoil still has some activity together with Pemex?
You're right. You know, we have had this sort of technical cooperation. I think it's fair to say that Mexico is still on our radar screen. We are monitoring what's happening there. Unfortunately, it doesn't seem like they are opening up what we consider to be the best exploration opportunities so far. It's mostly been about proven resources. We have selected not to consider those.
We need to do this at scale. That means several areas because the risk is so high. Our expectation, in fact, is that you don't know where, but we expect to make only one or two high impact, to have successes only one or two of these basins. That's, in reality, it won't be that big spread. It's so difficult to tell today where the success will come. That's why we go out very broadly for new basins. We don't think simply that our target can be reached by only focusing on our existing core basins.
Could I just add to that a little bit because sometimes it's a question that gets asked internally as well. It looks like we're everywhere. We're not. I don't know how many countries there are in the world. I guess that changes almost on a daily basis, but you know, it's more than 200. I think we're represented in somewhere about 20 countries on an exploration basis. 15, is it? There you go. It's even less, including Norway, yeah. What we've actually done, although for risk reasons, competitive reasons we don't share with you, we have a number of globally prioritized basins. We have 18. We have 18 basins.
If you remember the map that Pål showed you earlier on with all the different basin outlines, the green and that on there. I don't know how many there was on there, Pål, but I don't know.
That's close to 100.
100, something like that. We've picked 18 of those, and that's where we will primarily, I say primarily, focus our efforts and try to gain material access. We might, and of course, that's a dynamic process as others drill wells, have failures, have successes. We may take one or two of those away, and add one or two more. That's how we work. We start all the way out here, close it down, and as I say, for the time being, 18 prioritized basins for us, which is, you know, it's, and as Pål says, that's what we think it needs to be because not all of those will succeed, or we won't succeed in all of those.
Do we have any further questions in the audience in Oslo? No. Yes. One more from Trond.
Thank you. Trond Omdal, Arctic Securities again. There is an election in Mexico, and for many years a lot of companies have hoped that one day, ultimately, the Mexican side will be open. Statoil has a technical cooperation for years with Pemex. Do you see any likelihood that this will be opened and Statoil is still having some activity together with Pemex?
You're right. You know, we have had this sort of technical cooperation. I think it's fair to say that Mexico is still on our radar screen. We are monitoring what's happening there. Unfortunately, it doesn't seem like they are opening up what we consider to be the best exploration opportunities so far. It's mostly been about proven resources. We have selected not to consider those. We would, if the right opportunity set opened up in Mexico, be interested in doing. It's part of the greater Gulf of Mexico, which is highly prolific. We expect that to extend into parts of the Mexican shelf as well.
All right. We will move on to the telephone audience. I will take the first question from Martijn Rats with Morgan Stanley. Please go ahead, Martijn.
Hi. Thank you, Hilde, and thank you, gentlemen, for the presentations. I have a couple of quick questions, if I may. Firstly, I just wanted to ask if you could provide a little more color about the forward plans on Pão de Açúcar. You previously indicated that you would be looking to drill a follow-up sort of appraisal later on in the year. I wondered if with the announcements today, whether you'd be looking to bring those drilling plans forward and are you restricted effectively by rig access? Is that sort of the limiting factor there, or is it sort of a conscious decision to wait until the end of the year?
The second question I had was just with regards to the steady state resource life that you sort of see as suitable for Statoil. What I mean by that is really just the sort of six billion barrels of risked resource that you talk about in the presentation, whether that's something that you would like to see sort of going forward, whether actually there's a sort of targets of a higher number in mind, or what your thinking is around there. That would be very helpful. Then just finally, a very quick one on slide five of Tim's presentation. Tim, just wanted to clarify the 2010 to 2012 discoveries.
Does that include Pão de Açúcar in any form or shape there? Thank you.
Okay. While I'm thinking about the two other ones, I'll let Nick go on to the Hoop and the appraisal part.
It's pretty much always, as I've already said, it really is gonna be the timing of it. It's gonna be rig driven. The partnership is very aligned as to what we see on the three structures and power in particular from a subsurface point of view. We're working together very closely on that. That size of discovery means we really want to get after it as quickly as possible. The limiting factor is gonna be rigs. You know, we'll keep working it in parallel, and we will start chasing rigs, and then it really is as fast as we can secure a rig for that program. We will be looking at a multi-slot program because we will see that we'll need multiple wells to confirm this. The exact timing as yet, we really can't answer.
Okay. Thank you.
Thank you.
Okay. I can on the just a clarification on the figure, the 2010 to 2012 year to date. It doesn't include the upgrade on PãL. As Nick pointed out, these slides were made two or three days ago, so that we weren't at liberty to include that. There is a fairly significant upside on that number already. On the resource life, Pål might want to fill me in a little bit on this, but you know, I think 6 billion barrels is not more than it needs to be. If we plan to drill up 40 wells a year, and let's say that somewhere between 15 and 20 million barrels a year of risk resource like it was in 2011.
I think it was 800, Pål? Yes.
Yes, Tailbird.
Hi there.
Sorry.
It's Mark Coughlan from Macquarie. I just had a quick question on the two questions. Firstly, on the overarching sort of exploration strategy, and just thinking about the key drivers of that over the coming few years. We've seen that the opportunity set is quite deep. I was just wondering now, particularly around the high impact wells, if you feel that rig capacity is potentially sort of one of the main issues perhaps driving that forward, or indeed, if there is a sufficient desire internally to raise the exploration budget from around that $3 billion number that you've given.
Secondly, just in terms of your positioning in Mozambique relative to the other areas where you are, where you have early entry, it feels as though you have quite a high equity interest there at this stage. I was wondering if there was any likelihood potentially of farming down that equity ahead of a drilling in 2013 and indeed if there'd already been any interest. Thanks.
Okay. I'll take the last one first. I think it's probably Nick to take the rig one. In Mozambique, we have a farm down process ongoing. We are waiting for government approval for that. We can't announce, although several of you have asked already who we expect to have as a partner there. The answer is yes, that we will almost certainly farm down before we drill in Mozambique. Nick, you wanna take the rig one?
I mean, the reality is, yes, the rig issue is gonna be a challenge, not just for us, for the whole industry. What I think is, where we're getting better in international is because we're building a sizable position, we can go out for a multi-year contract for rigs that we can use close together. East Africa position with success, we're gonna need to drill a lot of wells. With what we've taken in Angola on a success base there, you're gonna need to drill a lot of wells. For the first time ever, we've been able to put together a multi-year program. That multi-year program means that when we're talking to rig contractors, they want to talk. Rig contractors in the current market don't want to talk to you on single well opportunities. It is gonna be a challenge.
That success brings that challenge. You know, we've got the same challenge in Brazil where Repsol is the operator. We've now got to try and secure a rig for the appraisal program. You know, I'm sure in certain areas, we're gonna achieve the timelines we want to, and in other areas, we're gonna struggle.
Next question, please.
Teodor Sveen-Nilsen, Swedbank First Securities, first. As Nick correctly pointed out, you are focusing on pretty many areas globally and spread wide around. Could you say a little bit around the consideration of why you don't focus on, let's say, two to three areas compared to like it's seven or six spaces you're now focusing on?
I think I can let Pål take that one.
Yeah. If you are thinking about the frontier or strategy with the assets at scale, we think that we have a strategy that-
Like that. That gives us a lifetime of that resource base of about 8 years. 8 years is typically the time it takes from making a discovery to production for a big discovery. That every year, we're potentially drilling out about 15%. You know, 12%-15% of our resource base. That if you look forward, I'll sort of indicate some good numbers for 2013 and 2014. They're good from the point of view of having a lot of volume potential or a lot of potential to prove up new resources. For every 800 million barrels we drill out, we have to replace it because that's the stuff we're gonna be needing to drill in 2018, 2019, and 2020.
That kind of puts the Rosneft deal into perspective. That's why it's so important to just keep refilling, you know, just like, you know, sort of the bucket with a small hole in the bottom. It runs out the bottom, you know, and then you just have to keep filling up at the top. It's relentless. You just cannot stop. Any company who means anything serious about exploration must never stop replenishing their portfolio. That's why it's so incredibly important the work that Pål and his team do on the global new ventures and the securing these new medium to longer term opportunities.
Great. Thank you.
We'll take the next question from David Mercer with SG. Go ahead please, David.
Hi. A couple of questions on the next slides, please. First on Slide five, Angola pre-salt system. Would the key risks actually be the reservoir characteristics, given what you've discovered over in the Brazilian side and the different reservoir characteristics depending where you've drilled the well? How would you interpret the reservoir model throughout changes as you move away from those control points in the Angolan side? Just secondly, on the Tanzania seismic Slide eight, what would cause false positives on those flat events? Can you give us some idea of what could be causing them other than a gas effect? Thanks.
Okay. Reservoir is a key aspect. It is something that from the Brazilian side that we do find that it varies. The object here is to recognize where the rocks are de-developed as a reservoir and where they're not. From that, there is a reasonable correlation between the seismic pattern that it gives as to whether it is a reservoir rock or not. You get a correlation between the two. Once we've shot the seismic or on the Angolan side, what we'll be looking for within the closures is the relative seismic patterns. By trying to correlate the seismic pattern that works from a reservoir side and the seismic pattern that doesn't, will help us locate the well.
That's one of the learnings that we got out to see it, where we found the oil in the section, but it really wasn't developed in good enough quality reservoir. We found. When we drilled the follow-on well in Gavea, we started to find some of the reservoirs. We found some with oil in, but we also found reservoirs that are deeper in the section that had water in. We got a good correlation. But we would, if the right opportunity set opened up in Mexico, be interested in. It's part of the Greater Gulf of Mexico, which is highly prolific. We expect that to extend into parts of the Mexican shelf as well.
All right. We'll move on to the telephone audience. I will take the first question from Haythem Rashed with Morgan Stanley. Please go ahead, Haythem.
Hi. Thank you, Hilde. Thank you, gentlemen, for the presentations. I have a couple of quick questions, if I may. Firstly, I just wanted to ask if you could provide a little more color about the forward plans on Pão de Açúcar. You previously indicated that you would be looking to drill a follow-up sort of appraisal later on in the year. I wondered if with the announcements today, whether you'd be looking to bring those drilling plans forward. Are you restricted effectively by rig access? Is that sort of the limiting factor there, or is it sort of a conscious decision to wait until the end of the year?
The second question I had was just with regards to the steady state resource life that you sort of see as suitable for Statoil. What I mean by that is really just the sort of 6 billion barrels of risk resource that you talk about in the presentation, whether that's something that you would like to see sort of going forward, whether actually there's a sort of targets of a higher number in mind or what your thinking is around there. That would be very helpful. Then just finally, a very quick one on Slide 5 of Tim's presentation. Tim, just wanted to clarify the 2010-2012 discoveries.
Does that include Pão de Açúcar in any form or shape there? Thank you.
Okay. While I'm thinking about the two other ones, I'll let Nick go on to the Pau and the appraisal part.
It's pretty much always, as I've already said, it really is gonna be the timing of it. It's gonna be rig-driven. The partnership is very aligned as to what we see on the three structures, and Pau in particular from a subsurface point of view. We're working together very closely on that. That size of discovery means we really want to get after it as quickly as possible. The limiting factor is gonna be rigs. You know, we'll keep working it in parallel, and we will start chasing rigs, and then it really is as fast as we can secure a rig for that program. We will be looking at a multi-slot program because we will see that we'll need multiple wells to confirm this. The exact timing as yet, we really can't answer.
Okay. Thank you.
Okay.
Thank you. Just a clarification on the figure, the 2010 to 2012 year to date. It doesn't include the upgrade on Pow. As Nick pointed out, these slides were made two or three days ago, so that we weren't at liberty to include that. There is a fairly significant upside on that number already. On the resource life, Pål might want to fill me in a little bit on this, but you know, I think 6 billion barrels is not more than it needs to be. If we plan to drill up 40 wells a year, and let's say that somewhere between 15-20 million barrels a year of risk resource like it was in 2011.
I think it was 800, Pål?
Yes. It was the reservoir there and the seismic. When we finally came to drill now, we would drill it. You know, in the right position, understanding where the reservoir was, predicting it ahead of drilling it and found it. That knowledge that we've got there will transfer to Angola. That really was one of the risks that we started to unravel. When we get the seismic, we'll answer that.
In terms of the difference, should we be thinking about the primary reservoir characteristics, the diagenesis or secondary things like fracturing?
No-
that are making these changes in the reservoir, this variability?
No. It really is the main porosity. There was always some fracturing in the reservoirs, but that doesn't really give you the volume. It's identifying the reservoir with porosity, and that is giving you a different seismic signature. Now we're starting to unravel that seismic signature, we can predict the reservoir that has big porosity. We're looking at big numbers here in the porosity side.
Dude, can I just add to that?
Brilliant. Thanks.
Could I just add to that without sort of sharing too much information? I can at least confirm that the nature of the reservoir, the pre-salt reservoir on Pão de Açúcar is significantly different from the nature of the pre-salt reservoir in the Santos Basin, at least in the pre-salt. I don't think I'll go further than that, but you know, for those of you who you know sort of don't really understand what Nick might be talking about in terms of character, that on some places, you have a stripy seismic package, and it works. On other places, you can have a stripy seismic package, and it doesn't. On other places, you can have an almost transparent, chaotic seismic character that works. On other places, it doesn't. It's that simple, and it's that difficult.
If it was easy, we'd have all retired and gone home a long time ago. For the false positive on Tanzania is that when the structure fills up with gas, it gives a certain response. If it leaks off, you leave residual gas behind. The risk here is that we're seeing residual gas, not actual gas. That's the risk coming in.
Great. Thanks, gents.
The next question comes from Nick Coleman with Argus Media. Go ahead, please, Nick.
Hi. Thanks for the presentation. I'd like to just, if possible, draw your attention back to the Norwegian shelf, and the question of costs of exploration drilling, and particularly the Barents Sea. Are you able to say, give a cost of drilling a well in the Barents Sea and how it compares with the North Sea in terms of the numbers there? Of course, the question is kind of driven by the idea that, presumably costs exploring in these sort of far northern waters may be more costly for you, both in the Barents or elsewhere in the world. What are your thoughts on how Statoil copes with the rising costs, especially in an expensive country like Norway? Thanks.
I'll give you a quick answer to this one. Of course, we'll be coming back to Norway after the break. On the Norwegian Barents Sea, the part of the Barents Sea that's opened at the moment, then the costs are more or less the same as they are anywhere else on the Norwegian Shelf. I'd like to remind you that it's very cost efficient to explore in Norway because the tax man here is
To do this at scale, that means several areas. Because the risk is so high, our expectation, in fact, is that you don't know where, but we expect to make only one or two high impact. To have success is only one or two of these basins. That's in reality it won't be that big spread, but it's so difficult to tell today where the success will come. That's why we go out very broadly in new basins. We don't think simply that our target can be reached by only focusing on our existing core basins.
Could I just add to that a little bit? Because sometimes this is a question that gets asked internally as well. It looks like we're everywhere. We're not. I don't know how many countries there are in the world. I guess that changes almost on a daily basis. You know, it's more than 200. I think we're represented in somewhere about 20 countries on an exploration basis. 15, is it? There you go. It's even less, including Norway, yeah. What we've actually done, although we're for obvious reasons, competitive reasons we don't share with you, we have a number of globally prioritized basins, and we have 18. So we have 18 basins.
If you remember the map that Pål showed you earlier on with all the different basin outlines, the green on there. I don't know how many there was on there, Pål, but I don't know.
That's close to 100.
100, something like that. We've picked 18 of those, and that's where we will primarily focus our efforts and try to gain material access. We might, and of course, that's a dynamic process as others drill wells, have failures, have successes. We may take one or two of those away and add one or two more. That's how we work. We start all the way out here, close it down, and as I say, for the time being, 18 prioritized basins for us. Which is, you know, it's, and as Pål says, that's what we think it needs to be, because not all of those will succeed, or we won't succeed in all of those.
Do we have any further questions in the audience in Oslo? No. Yes. One more from Trond Omdal.
Thank you. Trond Omdal, Arctic Securities again. There is an election in Mexico, and for many years, a lot of companies have hoped that one day, ultimately, the Mexican side will be open and start technical cooperation for years with Pemex. Do you see any likelihood that this will be opened and start or still have some activity together with Pemex?
You're right. You know we have had this sort of technical cooperation. I think it's fair to say that Mexico is still on our radar screen. We are monitoring what's happening there. Unfortunately, it doesn't seem like they are opening up what we consider to be the best of exploration opportunities. So far, it's mostly been about proven resources. We've elected not to consider those to pay a sort of large part of the exploration bills. The wells in the Barents Sea are not particularly costly. You've seen the wells on Skrugard and Havis. We completed those in just over a month. They are relatively cheap.
There are no cheap exploration wells offshore, but so relatively inexpensive compared to a lot of other wells which are around the world.
Okay, thank you.
We have one more question from Neill Morton with Berenberg. Please go ahead, Morton.
Thank you, Hilde. Couple of questions, actually. The first was just trying to get my head around how you actually think about ranking your high-impact wells. Do you look at your sort of drill-ready portfolio and simply rank it, and some happen to be high impact and others aren't? Or do you actually sort of separate them out and say, "Well, these are the high-impact wells, we're going to prioritize those," you know, perhaps one in five of every wells we drill is going to be high impact. I just wanted to have a you know a clearer idea of how you think in terms of just a sort of risk profile. Just secondly, sticking again, I guess, on sort of HSE.
We have seen, in recent months, you know, very significant share price reactions with well incidents, whether that's Macondo, Frade in Brazil, Elgin in the North Sea. Has or have those incidents given you any pause for thought in sort of drilling, you know, technically difficult wells? King Lear, you mentioned, was high temperature, high pressure. Thank you.
Okay. What I'd like to suggest here is that, on this question here, that Pål very briefly talks about, you know, sort of our ranking process on the basins before we get to high-impact wells, and Nick can talk to that, and then I'll speak to the HSE part. Pål, if we can be brief, both all of us.
Yeah. We try to, as I said earlier, work very systematic, and it's very important with this prioritization. The start point, in a way, is that we start to rank basins. We look globally and try to rank all the basins. There are three elements in this ranking. Firstly, it's the subsurface quality. That means the POS, the probability for making discoveries and the volume potential for a typical prospect in these basins. But on top of that, we also combine with putting in commercial terms in the different basins and countries to see how competitive that, how we can rank that. At the end, we also include political issues, technology issues, strategic issues, so that it ends up in these 18 basins that Tim mentioned earlier.
These kind of prioritization we take with us when we then go into the well prioritization process, then we put after the basin prioritization process. That's linked. Nick, you can
On the well side, we look at this as a portfolio basis. In any one particular year, we try to have a mix of risks from low-risk wells to high-risk wells. When you're exploring on a portfolio, you're wanting to consistently find reserves at one end, but expose yourself to upside at the other end. You've got to take some high risk in, but you've got to balance that against low risk. Balance is what we're after here. Then down into any individual prospects, you're comparing it to other prospects, and it can be cost, it can be value, it can be the risk, it can be the reserves, it can be the upside. There isn't a simple mathematical equation.
It really is comparing and trying overall in the 40 wells you're exposing yourself, give yourself the best chance of achieving the reserves that you're looking for on an annual basis. Do you wanna add to that?
No, that's absolutely fine, I think. I think on the HSE side, yes, we are aware of the consequences, and that's why I deliberately included a slide on the HSE and how important it is for us, because it not only affects our share price, in a worst case scenario, it could be
Both are licensed to operate both in that country but also potentially as sort of the, you know, sort of substantial question to our ability to operate and even our existence as a company. I mean, that is the sort of worst case. Our focus on the HSE, there are a lot of elements, but priority number one is always to avoid major accidents. A major accident, you know, related to exploration drilling, is obviously a well that comes out of control. Then it's easy to think that the wells with the most risk are the ones in the deepest water and the ones with the highest pressure.
Intuitively, yes, but every single exploration well we drill, whether it be high pressure, high temperature, ultra deep water or shallow water, you know, sort of Johan Sverdrup or Skrugard or something like this, are treated in exactly the same way. You have to do that because you never know entirely, you know, sort of where you will get the surprise. You need to be able to handle, you know, sort of the unforeseen on every single well and every single well location which we drill. I think vigilance on this is extremely important, and it's one of the reasons why we can't rush into any single exploration well.
We have to convince ourselves before we start these wells that we have planned them as thoroughly as we need to in order to mitigate the risk to the extent which is possible before drilling. This is absolutely number one on our agenda. It's number one. Every time we discuss, every time we meet with my team, we're talking about HSE and, you know, what the main risks are going forward.
Okay, great. Thank you.
We have a couple more questions. The first one comes from Jason Kenney with Santander. Please go ahead, Jason.
Hi there. Just a point of clarification really on the Campos Basin resources. I think the numbers that are mentioned this morning are just that, resources, 700 million barrels of oil, three trillion cubic feet of resource. What kind of recovery rates are you anticipating there? How do the numbers that have been released by Repsol today compare to your greater than 250 million BOE guidance that you had as an announcement at your Q1 results?
I think I can do it fairly quickly. I think the recovery rate on the oil is 30%. I take a little bit, I don't need to qualify. I can probably check that in the break, but I think that's so. It's reasonable. It's not over-optimistic. I don't think we're giving the right quality to the oil, anything like that. That gives us a lifetime of that resource base of about eight years. Eight years is typically the time it takes from making a discovery to production for a big discovery, so every year we're potentially drilling out about 15%. You know, 12%-15% of our resource base.
That if you look forward, I'll sort of indicate some good numbers for 2013 and 2014. They're good from the point of view of having a lot of volume potential or a lot of potential to prove up new resources. But for every 800 million barrels we drill out, we have to replace it because that's the stuff we're gonna be needing to drill in 2018 and 2019 and 2020. That kind of puts the Rosneft deal into perspective. That's why it's so important to just keep refilling. You know, just like, you know, sort of the bucket with a small hole in the bottom. It runs out on the bottom, you know, and then you just have to keep filling up in the top. It's relentless.
You just cannot stop. Any company who means anything serious about exploration must never stop replenishing their portfolio. That's why it's so incredibly important the work that Pål and his team do on the global new ventures and the securing these new medium to longer term opportunities.
Great. Thank you.
We'll take the next question from David Mercer with SG. Go ahead please, David.
Hi. A couple of questions on the next slides, please. First on slide five, Angola trailing system. Would the key risks actually be the reservoir characteristics, given what you've discovered over in the Brazilian side and the different reservoir characteristics depending where you've drilled the well? And how would you interpret that the reservoir moves throughout changes as you move away from those control points in the Angolan side? And then just secondly, on the Tanzania seismic, slide eight, what would cause false positives on those flat events? Can you give us some idea of what could be causing them other than a gas effect? Thanks.
Okay. Reservoir is a key aspect. It is something that from the Brazilian side we do find that it varies. The objective here is to recognize where the rocks are developed as a reservoir and where they're not. From that, there is a reasonable correlation between the seismic pattern that it gives as to whether it is a reservoir rock or not. You get a correlation between the two. Once we've shot the seismic on the Angolan side, what we'll be looking for within the closures is the relative seismic patterns. By trying to correlate the seismic pattern that works from a reservoir side and the seismic pattern that doesn't, will help us locate the well.
That's one of the learnings that, say, we got out to Seat, where we found the oil in the section, but it really wasn't developed in good enough quality reservoir. When we drilled the follow-on well in Gavea, we started to find some of the reservoirs. We found some with oil in, but we also found reservoirs that are deeper in the section that had water in. We got a good correlation between what I don't know what the assumption is on the gas. It's probably somewhere 60%-70% for associated gas, I would think.
Relative to the 250, well, you know, at that point in time, what we were able and allowed to communicate was greater than 250 million barrels. As I say, that doesn't really tell you whether it's 251 or 400. You know, sort of going back a couple of months. It's first now, once we've done, you know, sort of we've worked all the data from the well, done the post-well analysis, that we are able to come up with a more specific estimate. I think, you know, sort of had we known initially right after the completion of the well, that it was these kind of numbers, then we would obviously communicated these numbers.
I think we've seen, you know, considerable upside as we've analyzed the data which we got from the well and from the test.
Okay, thanks.
Next question comes from Nitin Sharma with J.P. Morgan. Please, Nitin.
Hi. Afternoon. A couple of questions. First one, Tim, on your presentation, slide five, you compare the discoveries of 2006, 2008 with what you've delivered in the recent past, i.e. 2010, 2012. How do you compare value creation of 2011 versus what your previous results were delivering in terms of near-term field drilling versus higher risk, higher reward strategy that you're following now? Moving on to question number two, how has that impacted the results that you're targeting now, i.e. what sort of resource targets do you now have for your segment versus what you had when you started on this path? Thank you.
On the, I haven't got a very good answer for you, to be quite honest, on the value creation because, I'm not actually aware, apart from Wood Mackenzie, of anyone actually attempting to measure value. I don't think Rystad were. I'm not sure I even know whether they existed at that point in time. They may have done, but, I actually don't have those numbers. We've also just recently, I guess over the last couple of years, started to measure value creation. I think probably what you would find is that on a per barrel basis, the volumes in Norway come out quite favorably.
I think the overall number, you know, sort of the size or the value, the $5 billion, would be very difficult to achieve on the Norwegian portfolio alone. Of course, the other point being is that we couldn't possibly drill up the same type of portfolio, the same number of wells in Norway as we can from a combined Norwegian and global portfolio, at least for not very long period of time. I'm not quite sure what the second question was about, but I think one of the important things, and I think Nick has already alluded to, is that we've been drilling what I call a much more balanced portfolio of wells each year.
We now have a larger portion of high impact wells than we did before, but we have a very healthy spread between high impact, high risk wells, you know, typically frontier. We would, if the right opportunity set opened up in Mexico, be interested in doing it as part of the greater Gulf of Mexico, which is highly prolific. We expect that to extend into parts of the Mexican shelf as well.
All right. We'll move on to the telephone audience. I will take the first question from Martijn Rats with Morgan Stanley. Please go ahead, Martijn.
Hi. Thank you, Hilde. Thank you, gentlemen, for the presentations. I have a couple of quick questions, if I may. Firstly, I just wanted to ask if you could provide a little more color about the forward plans on Pão de Açúcar. You previously indicated that you would be looking to drill a follow-up sort of appraisal later on in the year. I wondered if with the announcements today, whether you'd be looking to bring those drilling plans forward. Are you restricted effectively by rig access? Is that sort of the limiting factor there, or is it sort of a conscious decision to wait until the end of the year?
The second question I had was just with regards to the steady-state resource life that you sort of see as suitable for Statoil. What I mean by that is really just sort of the 6 billion barrels of risked resources that you talk about in the presentation, whether that's something that you would like to see sort of going forward, whether actually there's a sort of target of a higher number in mind, or what your thinking is around there. That would be very helpful. Then just finally, a very quick one on slide five of Tim's presentation. Tim, just wanted to clarify at the 2010 to 2012 discoveries.
Does that include Pão de Açúcar in any form or shape there? Thank you.
Okay, while I'm thinking about the two other ones, I'll let Nick go on to the Pão and the appraisal part.
It's pretty much always, as I've already said, it really is gonna be the timing of it. It's gonna be rig-driven. The partnership is very aligned as to what we see on the three structures, and Pão de Açúcar in particular from a subsurface point of view.
We're working together very closely on that. That size of discovery means we really want to get after it as quickly as possible. The limiting factor is gonna be rigs. You know, we'll keep working it in parallel, and we will start chasing rigs. It really is as fast as we can secure a rig for that program. We will be looking at a multi-slot program, 'cause we will see that we'll need multiple wells to confirm this. The exact timing, as yet, we really can't answer.
Okay. Thank you.
Thank you.
Just a clarification on the figure, the 2010 to 2012 year to date. It doesn't include the upgrade on Pau. As Nick pointed out, these slides were made two or three days ago, so that we weren't at liberty to include that. So there is a fairly significant upside on that number already. On the resource life, Pål might want to fill me in a little bit on this. You know, I think 6 billion barrels is not more than it needs to be.
If we plan to drill out 40 wells a year, and let's say that somewhere between 15 and 20 million barrels a year of risk resource like it was in 2011, I think it was 800, Pål?
Yes.
Wells, then ILX wells. I think Nick's already alluded to it. That is the way we will be, you know, attempting to set up our portfolios going forward. That, you know, when we sit down every year and consider, you know, our yearly drilling programs, having a balanced portfolio is one of the important issues. It mitigates the risk of not proving up enough volumes. That's how we would address it going forward.
Thank you.
Just the last question before the break. Rutania Sari from Bank of America, Merrill Lynch.
Hi there, gentlemen. This is a really quick question regarding how you're thinking about exploration within the overall CapEx program going forward from here. Obviously, the company is in a ten-year ramp-up phase now with production, and you have pretty aggressive production targets out till the end of the decade. How do you see your exploration budget, maybe on a per barrel basis, going forward from here? Are you comfortable with the proportion that you have now? Would you like to see CapEx per BOE increasing for exploration? Is that something the company has guided? Or is this something you feel you can take a bit more of a rest on, given the significant successes that you've had over the last eighteen months?
I think the way we have been guiding, the way we continue to guide is around about $3 billion on the exploration. If you look at the activity level which we've prognosed for 2013 and 2014, it's about the same. Wells are typically about 60% of our exploration cost. If we continue to drill about the same amount of wells, we will continue to spend about the same amount of money on wells going forward. Now, I think in terms of spending even more, we are probably punching or have been punching a little bit above our weight, spending a little bit more than some of our competitors.
Although there are strong indications that many of the larger companies at least intend to spend even more on exploration than they have been recently. I think, you know, in order to spend significantly more than $3 billion, then you have to have the quality in the portfolio. I think what we've tried, we've demonstrated already today, it's already a huge challenge, you know, just to get to where we're at. Then to replenish and maintain that kind of portfolio, you know, I don't foresee us spending significantly more than $3 billion.
Because I just don't think, you know, we will be able to build and sustain a portfolio that's large enough and with the kind of quality, you know, so that will warrant that kind of larger spending. Then on the final element, you talked about CapEx per barrel of oil equivalent. We don't really think about it, but, you know, sort of one of the things we do measure on is, of course, finding cost. We do our benchmarking, and I guess you can do yours. Obviously last year and this year, we will come out very favorably on that. We do have specific targets on finding cost.
With the reservoir there and the seismic. When we finally came to drill Pão, we would drill it in, you know, in the right position, understanding where the reservoir was, predicting it ahead of drilling it, and found it. That knowledge that we've got there will transfer to Angola. That really was one of the risks that we started to unravel. When we get the seismic.
And-
We'll answer that.
In terms of the difference, should we be thinking about the primary reservoir characteristics, the diagenesis or secondary things like fracturing?
No-
that are making these changes in the reservoir, this variability?
No. It really is the main porosity. There was always some fracturing in the reservoirs. But that doesn't really give you the volume. It's identifying the reservoir with porosity, and that is giving you a different seismic signature. Now we're starting to unravel that seismic signature. We can predict the reservoir that has big porosity. We're looking at big numbers here in the porosity side.
Luke, could I just add to that?
Brilliant. Thanks.
Luke, could I just add to that without sort of sharing too much information? I can at least confirm that the nature of the reservoir, the pre-salt reservoir on Pau is significantly different from the nature of the pre-salt reservoir in the Santos Basin, at least in the pre-salt. I don't think I'll go further than that. You know, for those of you who, you know, sort of don't really understand what Nick might be talking about in terms of character, that on some places you have a stripy seismic package, and it works. On other places, you can have a stripy seismic package, and it doesn't. On other places, you can have an almost transparent, chaotic seismic character that works. On other places, it doesn't. It's that simple, and it's that difficult.
If it was easy, we'd have all retired and gone home a long time ago. For the false positive on Tanzania is that when the structure fills up with gas, it gives a certain response. If it leaks off, you leave residual gas behind. The risk here is that we're seeing residual gas, not actual gas. That's the risk coming in.
Great. Thanks, gents.
The next question comes from Nick Coleman with Argus Media. Go ahead, please, Nick.
Hi. Thanks for the presentation. I'd like to just, if possible, draw your attention back to the Norwegian shelf, and the question of costs of exploration drilling, and particularly the Barents Sea. Are you able to say, give a cost of drilling a well in the Barents Sea and how it compares with the North Sea in terms of the numbers there? And of course, the question is kind of driven by the idea that, presumably costs exploring in these sort of far northern waters may be more costly for you, both in the Barents or elsewhere in the world. What are your thoughts on how Statoil copes with the rising costs, especially in an expensive country like Norway? Thanks.
I'll give you a quick answer to this one. Of course, we'll be coming back to Norway after the break. On the Norwegian Barents Sea, the part of the Barents Sea that's opened at the moment, then the costs are more or less the same as they are anywhere else on the Norwegian shelf. I'd like to remind you that it's very cost efficient to explore in Norway because the tax man here is and as I say are delivering well on that. That's also a parameter which we'll use to constrain our spend.
Understood. Thank you very much.
Thank you.
Thank you. We'll take a 10-minute break. We'll reconvene at five minutes to three, Oslo time. Thank you.
Like that. That gives us a lifetime of that resource base of about eight years. Eight years is typically the time it takes to from making a discovery to production for a big discovery, so that every year, we're potentially drilling out about 15%, you know, 12%-15% of our resource base. If you look forward, I'll sort of indicate some good numbers for 2013 and 2014. They're good from the point of view of having a lot of volume potential, a lot of potential to prove up new resources. But for every 800 million barrels we drill out, we have to replace it because that's the stuff we're gonna be needing to drill in 2018, 2019, and 2020.
That kind of puts the Rosneft deal into perspective. That's why it's so important to just keep refilling. You know, it's like, you know, sort of the bucket with a small hole in the bottom. It runs out on the bottom, you know, and then you just have to keep filling up in the top. It's relentless. You just cannot stop. Any company who means anything serious about exploration must never stop replenishing their portfolio. That's why it's so incredibly important, the work that Pål and his team do on the global new ventures and the securing these new medium to longer term opportunities.
Great. Thank you.
We'll take the next question from David Mercer with SG. Go ahead please, David.
Hi. A couple of questions on the next slides, please. First on slide five, Angola Petroleum System. Would the key risks actually be the reservoir characteristics, given what you've discovered over in the Brazilian side and the different reservoir characteristics depending on where you've drilled the well? How would you interpret that the reservoir changes as you move away from those control points in the Angolan side? Just secondly, on the Tanzania seismic, slide eight, what would cause false positives on those flat events? Can you give us some idea of what could be causing them other than a gas effect? Thanks.
Okay. Reservoir is a key aspect. It is something that from the Brazilian side that we do find that it varies. The objective here is to recognize where the rocks are developed as a reservoir and where they're not. From that, there is a reasonable correlation between the seismic pattern that it gives as to whether it is a reservoir rock or not. You get a correlation between the two. Once we've shot the seismic on the Angolan side, what we'll be looking for within the closures is the relative seismic patterns. By trying to correlate the seismic pattern that works from a reservoir side and the seismic pattern that doesn't, will help us locate the well.
That's one of the learnings that, say, we got out to see it, where we found the oil in the section, but it really wasn't developed in good enough quality reservoir. When we drilled the follow-on well in Gavea, we started to find some of the reservoirs. We found some with oil in, but we also found reservoirs that are deeper in the section that had water in. We got a good correlation between what to pay. Yeah, sort of a large part of the exploration bills. The wells in the Barents Sea are not particularly costly. You've seen the wells on Skrugard and Havis. We've completed those in just over a month. They're relatively, I say, cheap.
There are no cheap exploration wells offshore, but so relatively inexpensive compared to a lot of other wells which are around the world.
Okay, thank you.
We have one more question, from Neill Morton with Berenberg. Please go ahead, Morton.
Thank you, Hilde. Couple of questions actually. The first was just trying to get my head around how you actually think about ranking your high impact wells. Do you look at your sort of drill-ready portfolio and simply rank it, and some happen to be high impact and others aren't? Or do you actually sort of separate them out and say, "Well, these are the high-impact wells, we're going to prioritize those." You know, perhaps one in five of every wells we drill is going to be high impact. I just wanted to have a you know, a clearer idea of how you think in terms of just the sort of risk profile. Just secondly, sticking again, I guess, on sort of HSE.
We have seen, in recent months, you know, very significant share price reactions with well incidents, whether that's Macondo, Frade in Brazil, Elgin in the North Sea. Have those incidents given you any pause for thought in sort of drilling, you know, technically difficult wells? King Lear, you mentioned, was high temperature, high pressure. Thank you.
What I'd like to suggest here is that on this question here, that Pål very briefly talks about, you know, sort of our ranking process on the basins before we get to high-impact wells, and Nick can talk to that, and then I'll speak to the HSE part. Pål, if we can be brief both all of us.
As I said earlier, we try to work very systematically, and it's very important with this prioritization. The starting point, in a way, is that we start to rank basins. We look globally and try to rank all the basins. There are three elements in this ranking. Firstly, it's the subsurface quality, and that means the POS, the probability for making discoveries and the volume potential for the typical prospect in these basins. On top of that, we also combine with putting in commercial terms in the different basins and countries to see how competitive that, how we can rank that. At the end, we also include political issues, technology issues, strategic issues, so that it ends up in these 18 basins that Tim mentioned earlier.
These kind of prioritization we take with us when we then go into the well prioritization process, then we put after the basin prioritization process. That's linked. Nick, you can
On the well side, we look at this as a portfolio basis. In any one particular year, we try to have a mix of risks from low-risk wells to high-risk wells. When you're exploring on a portfolio, you're wanting to consistently find reserves at one end, but expose yourself to upside at the other end. You gotta take some high risk in, but you gotta balance that against low risk. Balance is what we're after here. Then down into any individual prospects, you're comparing it to other prospects. It can be cost, it can be value, it can be the risk, it can be the reserves, it can be the upside. There isn't a simple mathematical equation.
It really is comparing and trying overall in the 40 wells you're exposing yourself, give yourself the best chance of achieving with the reservoir there and the seismic. When we finally came to drill Pow, we would drill it in you know, in the right position, understanding where the reservoir was, predicting it ahead of drilling it and found it. That knowledge that we've got there will transfer to Angola. That really was one of the risks that we started to unravel. When we get the seismic, it will answer that.
In terms of the difference, should we be thinking about the primary reservoir characteristics, the diagenesis or secondary things like fracturing that are making these changes in the reservoir, this variability?
No, it really is the main porosity. There was always some fracturing in the reservoirs, but that doesn't really give you the volume. It's identifying the reservoir with porosity, and that is giving you a different seismic signature. We're starting to unravel that seismic signature. We can predict the reservoir that has big porosity. We're looking at big numbers here in the porosity side.
Brilliant. Thanks.
Could I just add to that without sort of sharing too much information? I can at least confirm that the nature of the reservoir, the pre-salt reservoir on Pão is significantly different from the nature of the pre-salt reservoir in the Santos Basin, at least in the pre-salt. I don't think I'll go further than that. You know, for those of you who, you know, sort of don't really understand what Nick might be talking about in terms of character, that on some places you have a stripy seismic package, and it works. On other places, you can have a stripy seismic package, and it doesn't. On other places, you can have an almost transparent, chaotic seismic character that works. On other places, it doesn't. It's that simple, and it's that difficult.
If it was easy, we'd have all retired and gone home a long time ago. For the false positive on Tanzania, when the structure fills up with gas, it gives a certain response. If it leaks off, you leave residual gas behind. The risk here is that we're seeing residual gas, not actual gas. That's the risk coming in.
Great. Thanks, gents.
The next question comes from Nick Coleman with Argus Media. Go ahead, please, Nick.
Hi. Thanks for the presentation. I'd like to just, if possible, draw your attention back to the Norwegian shelf, and the question of costs of exploration drilling, and particularly the Barents Sea. Are you able to say, give a cost of drilling a well in the Barents Sea and how it compares with the North Sea in terms of the numbers there? Of course, the question is kind of driven by the idea that, presumably costs exploring in these sort of far northern waters may be more costly for you, both in the Barents or elsewhere in the world. What are your thoughts on how Statoil copes with the rising costs, especially in an expensive country like Norway? Thanks.
I'll give you a quick answer to this one. Of course, we'll be coming back to Norway after the break. On the Norwegian Barents Sea, the part of the Barents Sea that's opened at the moment, then the costs are more or less the same as they are anywhere else on the Norwegian Shelf. I'd like to remind you that it's very cost efficient to explore in Norway because the tax man here is
Welcome back, everybody. We will now start our second session. The first speaker out is Gro G. Haatvedt, who is the Senior Vice President for Exploration Norway. Please go ahead, Gro.
Thank you, Hilde, and good afternoon, everybody. As presented by Tim earlier today, Statoil's ambition is to be a leading exploration company by 2015. An important building block, of course, in this strategy is to optimize our core position on also the Norwegian Continental Shelf. I will now give a short status on how we are positioned to reach this ambition and in addition, to also contribute to the production ambition beyond 2020. I'll just show the team out on the rig when we made the Havis discovery. It's a great team, and this was a very good start of this year. First, to try to give you an overview of the main activities on the NCS this year. Our exploration activities is almost as high as it was last year.
This year, we will drill in total between 20 and 25 exploration appraisal wells, both as an operator, as a partner. We have earlier defined three prospects as high impact prospects, and we can start up in the Barents Sea and Havis, which I also alluded to, on the first slide. It resulted in a high impact discovery in the beginning of this year. We can go to the south, to the North Sea, and we drill the Crux well. This exploration well had two objectives. First one, to test a new play in the area, the Crux prospect, which was a high risk, high reward opportunity. Second, also to test the infrastructure near prospect called Crimp.
Unfortunately, we found no gas in the Crux prospect, but we are pleased with the oil discovery in the Crimp prospect. Even though our high impact opportunity has not materialized, we have delivered some valuable additional resources to the Oseberg area. We go to the south, and it's King Lear, and that is about 20 kilometer north of Ekofisk, and it's currently ongoing, and I will come back to this also in detail later in my presentation. Another well that I really want to name specifically is the Loven well. It's up on the Trøndelag platform. We do not define this as a high impact opportunity. It also has a high risk. That means that the probability of finding hydrocarbon is not very high, but it has an upside.
In addition, it's an important well because it, in case of a discovery, this could also open up an underexplored area in the Norwegian Sea. We have a 100% share in that license. It's also very important to secure new acreage, also, of course, quality acreage. We are now working hard on the 22nd concession round and also the APA round for 2012. In addition, we drill also appraisal well on Skrugard and Johan Sverdrup this year. I think also we can guide now and say that about this portfolio, about 40% is infrastructure and wells. These wells, of course, do not create the big headlines in the media, but they can give really valuable barrels and also extend the lifetime of the infrastructure. Now I will dive more into the Skrugard licenses.
In less than a year, in fact, we have made two substantial oil discoveries, Skrugard and Havis, and we were proving up between 400 and 600 million barrels of recoverable oil. Earlier this year, we also had a successful appraisal well on Skrugard, confirming our estimates and also collecting very important and critical data for development planning. The Skrugard and Havis discoveries have, of course, renewed the exploration optimism in the Barents Sea. I also have to say that we are expecting a high degree of competition in the 22nd concession round. At the same time, I'm very proud of Statoil stayed the course when others gave up. The Skrugard area has some really interesting also follow-up potential.
In the end of this year, we will launch a new ambition exploration campaign in the area, in these two production licenses which we hold to, of course, together with our partners. The drilling campaign comprise of four prospects. You can see three of them in white here. It's Iskrystall, Skagen, and Nunatak. The fourth one we will decide upon in the nearest future. These four prospects we will drill back to back, and we have secured rig capacity on West Hercules coming from Asia, and we are also doing winterization of that rig before it goes up, of course, and drill in the Barents Sea. Our ambition is to fulfill this drilling campaign by early summer 2013, and Nunatak is the first well to be drilled or the prospect to be drilled.
Let's dive into the Nunatak prospect. That is in a very.
Reserves that you're looking for on an annual basis. Do you wanna add to that?
No, that's absolutely fine, I think. Then I think on the HSE side, yes, we are aware of the consequences, and that's why I deliberately included a slide on the HSE and how important it is for us. Because it not only affects our share price, in a worst case scenario, it could be both our license to operate both in that country, but also potentially as sort of the you know sort of substantially sort of question to our ability to operate and even our existence as a company. I mean, that is the sort of worst case. Our focus on the HSE, there are a lot of elements, but priority number one is always to avoid major accidents. A major accident, you know, so related to exploration drilling is obviously a well that comes out of control.
It's easy to think that the wells with the most risk are the ones in the deepest water and the ones with the highest pressure. Intuitively, yes, but every single exploration well we drill, whether it be high pressure, high temperature, ultra-deep water or shallow water, you know, sort of Johan Sverdrup or Skrugard or something like this, are treated in exactly the same way. You have to do that because you never know entirely, you know, sort of where you will get a surprise, and you need to be able to handle, you know, sort of the unforeseen on every single well and every single well location which we drill. I think vigilance on this is extremely important, and it's one of the reasons why we can't rush into any single exploration well.
We have to convince ourselves before we start these wells that we have planned them as thoroughly as we need to in order to mitigate the risk to the extent which is possible before drilling. This is absolutely number one on our agenda. It's number one. Every time we discuss, every time we meet with my team, we're talking about HSE and, you know, what the main risks are going forward.
Okay, great. Thank you.
We have a couple more questions. The first one comes from Jason Kenney with Santander. Please go ahead, Jason.
Hi there. Just a point of clarification really on the Campos Basin, resources. I think the numbers that I mentioned this morning are just that, resources, 700 million barrels of oil, 3 trillion cubic feet of resource. What kind of recovery rates are you anticipating there? How does the numbers that have been released by Statoil today compare to your greater than 250 million BOE guidance that you had as an announcement at your Q1 resource?
I think I can do it fairly quickly. I think the recovery rate on the oil is 30%. I take a little bit, I don't need to qualify. I can probably check that in the break, but I think that's so. It's not over-optimistic, I don't think, given the light quality of the oil.
It's in the very immediate vicinity of the Skrugard discovery. In the Skrugard license or licenses, many of the prospects have these flat spots, as Nick has also alluded to, you know, from Tanzania. These are indications of presence of hydrocarbons. For this prospect, which is in white or the transparent white here in the map to the left, and you also see it on the seismic line on the right. It also has a double flat spot. This one could be in communication. If it's a discovery, it could be in communication with Skrugard discovery. That's why it's so important for us to test out and find if it's really holds hydrocarbons. With the observations we have seen, it's quite a high probability for finding hydrocarbons here.
We go to a really new or the next frontier area in the Barents Sea. No wells have yet been drilled up there, and that is in the Hoop area. You can see it here. It's the northernmost licenses which has been awarded in the Barents Sea so far. The main target here is a shallow reservoir located just 600 meter approximately below the subsurface. You have this shallow reservoir. It also enable us to have some excellent seismic imaging. In this particular opportunity, which we see up north there, we have some also direct indications of hydrocarbons in our seismic data. You can also see the map here to the right. This shows, no, sorry.
This shows also we call it an amplitude map, and this shows that it could be a good hydrocarbon indicator for this structure to be filled. We are going to drill two wells here, and we are doing that in an aggressive way because we will just do it after we have finalized on the Skrugard. I can say also the license obligation is to drill the well within 2015, and we will finalize this within 2013 and have a good position up there. License to the south, where we are a partner within also the same area, the Hoop area with the circle around there, we'll drill or participate together with OMV on the Wisting Well.
That will be drilled some or a couple of months before we go to up to Hoop and our license. Johan Sverdrup field. I think you all know that. It's about 140 kilometer west of Stavanger. I think making this discovery really also just remind us that the North Sea is a world-class hydrocarbon basin. This map I'll try to explain you. It shows you know a sub-regional topography map in the Utsira area. You can see the Viking-
To pay a sort of large part of the exploration bills. The wells in the Barents Sea are not particularly costly. You've seen the wells on Skrugard and Havis, we completed those in just over a month. They are, they're relatively, I say, relatively cheap. There are no cheap exploration wells offshore, but so relatively inexpensive compared to a lot of other wells which are around the world.
Okay, thank you.
We have one more question, from Neill Morton with Berenberg. Please go ahead, Morton.
Thank you, Hilde. A couple of questions actually. The first was just trying to get my head around how you actually think about ranking your high-impact wells. Do you look at your sort of drill-ready portfolio and simply rank it, and some happen to be high impact and others aren't? Or do you actually sort of separate them out and say, "Well, these are the high-impact wells, we're going to prioritize those," you know, perhaps one in five of every wells we drill is going to be high impact. I just wanted to have a you know, a clearer idea of how you think in terms of just the sort of risk profile. Just secondly, sticking again, I guess, on sort of HSE.
We have seen, in recent months, you know, very significant share price reactions with well incidents, whether that's Macondo, Frade in Brazil, Elgin in the North Sea. Have those incidents given you any pause for thought in sort of drilling, you know, technically difficult wells? King Lear, you mentioned, was high temperature, high pressure. Thank you.
Okay. What I'd like to suggest here is that on this question here, that Pål very briefly talks about, you know, sort of our ranking process on the basins before we get to high-impact wells, and Nick can talk to that, and then I'll speak to the HSE part. Pål, if we can be brief, both all of us.
Yeah. We try to, as I said earlier, we try to work very systematic, and it's very important with this prioritization. The start point, in a way, is that we start to rank basins. We look globally and try to rank all the basins. There are three elements in this ranking. Firstly, it's the subsurface quality. That means the POS, the probability for making discoveries and the volume potential for a typical prospect in these basins. But on top of that, we also combine with putting in commercial terms in the different basin and countries to see how competitive that, how we can rank that. At the end, we also include political issues, technology issues, strategic issues, so that it ends up in these 18 basins that Tim mentioned earlier.
These kind of prioritization we take with us when we then go into the well prioritization process, then we put after the basin prioritization process. That's linked. Nick, you can
On the well side, we look at this as a portfolio basis. In any one particular year, we try to have a mix of risks from low-risk wells to high-risk wells. So that when you're exploring on a portfolio, you're wanting to consistently find reserves at one end, but expose yourself to upside at the other end. You gotta take some high risk in, but you gotta balance that against low risk. Balance is what we're after here. Then down into any individual prospects, you're comparing it to other prospects. It can be cost, it can be value, it can be the risk, it can be the reserves, it can be the upside. There isn't a simple mathematical equation. It really is comparing and trying overall in the 40 wells you're exposing yourself, give yourself the best chance of achieving the-
To the west there, and also East Shetland Platform. You see how the discovery is placed upon the Utsira Southern part high. The reservoir here is superimposed on the map. It's kind of 3D view. It almost show the container, the reservoir here, where the hydrocarbon is held. It also show the wells that has been drilled and also some of the new wells to be planned for. It's a kind of subtle trap, but this is what we are working on these days. To visualize this way, it also gives a better overview of the setting. I can also say that the warm colors here is high areas and the cold colors are the basins.
That goes also for the map, which represents the reservoir level here. This is a discovery made in shallow water. It's a shallow reservoir, and it's also close to shore and close to existing infrastructure, and with very good reservoir parameters. We are now going on with the drilling campaign in the license 265, which we are operating. We will start drilling this summer. The first one is Gjeitungen, and that is up north here. You can also see the wells here on the seismic line. Of course, if we make a discovery here, this could also add additional upside to Johan Sverdrup volumes. The two other wells, Espevær and Krossøy, they are appraisal wells.
You also see how they plot then on the structural map here to the left. I can also tell you that the reservoir here is between the yellow one that's close to the reservoir and the green one here is close to the base of the reservoir. Being in a position like us here with a giant, or with the discovery of a giant oil field, it's of course also very important to have access and to get access to the most important acreage around it. I think we secured two new attractive acreage in the APA last year, and that is PL 642 to the North and PL 628 to the South.
If you look at the map here, you also see that we have a very good position both as an operator, as a partner in this area. Of course, that is important in an area where we know so much hydrocarbon has, or oil and gas has been generated through this period. We are running also a number of projects because what you see, this trap is a kind of subtle. It's not an easy trap. When I say trap, it's where hydrocarbons or oil and gas is being trapped. It's very important for us also to work more on the seismic data, the quality of the data, so that we can also use those data at the maximum, also to find new opportunities in this area and also to understand better the development of the area.
We are also then merging together 3D seismic data to try to have the same kind of quality on all the data. We are doing that from the Barents area and including then the Utsira Southern area. We shall have a very good data set looking into other opportunities here because we know that they are. It's not easy to find, so we have to use all the data and all the knowledge we have in order to really map those opportunities out. I think you have already alluded to King Lear, and it is a high impact prospect in the Central Graben in Block 24.
The history here, as you are aware of, is of course that the presence of hydrocarbons in the structures has been proved back to 1989, when Saga was drilling this well 24/14, which unfortunately resulted in a subsurface blowout. The objective of this well now is to check out if, or how big are the volumes and are the volumes commercial. This is the main target with this well. King Lear is a high pressure, high temperature well, and it requires, of course, HSE focus as also Tim has alluded to. I think also we have got better experience in handling high pressure, high temperature wells, both from exploration wells and field development wells like in Kristin, Huldra, Kvitebjørn, Morvin, and Gudrun.
It's also important, I think, to notice that an appraisal well 24/18 R, which you can also see here on the seismic line. It was drilled in 1994 without any HSE incident. Of course, we are monitoring the well very closely, and we are doing this also as a routine on all of our exploration wells. I go to the Gullfaks area, and that is in fact a really fantastic area when it comes to doing infrastructure-led exploration. It's, I can say, the magenta color here means condensate. The green and red means oil and gas, and the green is oil.
The Gullfaks field, the big field was made so far back that in 1978, and it was, at that time, approximately, 2.5 billion barrels. Then we had some really interesting growth prospects in the areas which of course was proven up. Then we found an additional 1 billion barrels. In the 1990s, we found new discoveries there, adding up another 800 million barrels. I think the importance here is.
Delivers that you're looking for on an annual basis. Do you wanna add to that? No, that's absolutely fine, I think. I think on the HSE side, yes, we are aware of the consequences, and that's why I deliberately included a slide on the HSE and how important it is for us, because it not only affects our share price, in a worst case scenario, it could be both our license to operate both in that country, but also potentially sort of the you know sort of substantial question to our ability to operate and even our existence as a company. I mean, that is the sort of worst case. Our focus on the HSE, there are a lot of elements, but priority number one is always to avoid major accidents.
A major accident, you know, so related to exploration drilling is obviously a well that comes out of control. Then it's easy to think that the wells with the most risk are the ones in the deepest water and the ones with the highest pressure. Intuitively, yes, but every single exploration well we drill, whether it be high pressure, high temperature, ultra-deep water or shallow water, you know, sort of Johan Sverdrup or Skrugard or something like this, are treated in exactly the same way. You have to do that because you never know entirely, you know, sort of where you will get the surprise. You need to be able to handle, you know, sort of the unforeseen on every single well and every single well location which we drill.
I think vigilance on this is extremely important, and it's one of the reasons why we can't rush into any single exploration well. We have to convince ourselves before we start these wells that we have planned them as thoroughly as we need to in order to mitigate the risk to the extent which is possible before drilling. This is absolutely number one on our agenda. It's number one. Every time we discuss, every time we meet with my team, we're talking about de-risking, and you know, what the main risks are going forward.
Okay, great. Thank you.
We have a couple more questions. The first one comes from Jason Kenney with Santander. Please go ahead, Jason.
Hi there. Just a point of clarification really on the Campos Basin resources. I think the numbers that I mentioned this morning are just that, resources, 700 million barrels of oil, three trillion cubic feet of resource. What kind of recovery rates are you anticipating there? And how does the numbers that have been released by Rystad today compared to your greater than 250 million BOE guidance that you had as an announcement at your Q1 results?
I think I can do it fairly quickly. I think the recovery rate on the oil is 30%. I don't need to qualify. I can probably check that in the break, but I think that's so. It's not over-optimistic. I don't think we're giving the right quality to the oil. I don't know what the assumption is on the gas. It's probably somewhere 60%-70% for associated gas, I would think. Relative to the 250, well, you know, at that point in time, what we were able and allowed to communicate was greater than 250 million barrels.
As I say, that doesn't really tell you whether it's 251 or 400. You know, sort of going back a couple of months. It's first now, once we've done, you know, sort of we've worked all the data from the well, done the post-well analysis, that we're able to come up with a more specific estimate. I think, you know, sort of had we known initially right after the completion of the well that it was these kind of numbers, then we would obviously communicated these numbers. I think we've seen, you know, considerable upside as we've analyzed the data which we got from the well and from the test.
Okay, thanks.
Next question comes from Nitin Sharma with J.P. Morgan. Please, Nitin.
Hi. Afternoon. A couple of questions. First one, Tim, on your presentation, slide five. You compare the discoveries 2006, 2008 with what you've delivered in the recent past, i.e., 2010, 2012. How do you compare value creation of 2011 versus what your previous results were delivering in terms of near-term field drilling versus higher risk, higher reward strategy that you're following now? Moving on to question number two, how has that impacted the results that you're targeting now? I.e., what sort of resource targets do you now have for your segment versus what you had when you started on this path? Thank you.
Okay. On the, I haven't got a very good answer for you, to be quite honest, on the value creation because, I'm not actually aware, apart from Woodmac, of anyone actually attempting to measure value. I don't think Rystad were. I'm not sure you know where they existed at that point in time. They may have done, but, I actually don't have those numbers. We've also just recently, I guess over the last couple of years, started to measure value creation. I think probably what you would find is that on a per barrel basis, the volumes in Norway come out quite favorably.
I think the overall number, sort of the kind of the size or the value, the $5 billion, would be very difficult to achieve on the Norwegian portfolio alone. Of course, the other point being is that we couldn't possibly drill up the same type of portfolio, the same number of wells in Norway as we can from a combined Norwegian and global portfolio, at least for not very long period of time. Then I'm not quite sure what the second question was about, but I think one of the important things, and I think Nick has already alluded to, is that we've been drilling what I call a much more balanced portfolio of wells each year.
We now have a larger portion of high impact wells than we did before, but we have a very healthy spread between high impact, high risk wells, you know, typically frontier.
During the last 10 years, we have also had quite a high activity here, and it has added up 150-200 million barrels of oil. Only last year and early this year, we made four new discoveries here, and those are mentioned here on the map in this area, all. When you are thinking about the value then, it's about 100, between 150 and 200 million barrels of those more smaller discoveries. Then we can look to Skrugard, Havis, which has between 400 and 600 million barrels. If you just use a simple, what should I say, calculation here, and we can think Skrugard, Havis, and it's 100%, but then it has a value of NOK 300-400 billion.
Then you can go here, see between 150 to 200 million. It has a value of about maybe between NOK 100 billion and NOK 150 billion. In addition, these barrels, they will also very quickly be put into the infrastructure because there are available capacity. It's really high-value barrels to Statoil and to our partners and to the society. Okay, I try to sum up our outlook for 2012 to 2014. Of course, our aim is to create materiality and value through the NCS exploration. Also thereby, of course, contribute to the production target for Statoil beyond 2020.
To achieve this, it's very important for us to rebalance our activities and portfolio to focus also much more on material growth opportunities, both in traditional but also looking into new place. In more detail, our strategy really includes strong prioritization, clearly defined top areas in which we want to accelerate activity level. We will focus on growth in proven basin. With proven basin, I mean, the North Sea and the Halten-Dønna, where we know that the petroleum system is working. We will accelerate the maturation of prospects here in these established rich provinces for more short-term means. We have also a strategy not only to drill timely infrastructure-led wells. That means from discovery to it is in production, it should be around 2 years lead time. Because then we will add value and not erode value.
Of course, it's also important to continue to explore selectively in frontier region. We are taking selective tests in frontier place like the Hoop area, which I have gone through. Of course, it's still very important for us, even with all the successes we have had, to get acreage or get access to new quality acreage. Still it's really important for us to push on to open up the Barents Sea, the Lofoten, Vesterålen, Tromsø area. We have a guidance that we will drill between 60 and 80 wells, both exploration and appraisal wells, during this two-year period. As I also said, we have changed our footprint.
We are guiding now 10%, around 10% frontier, 50% for growth, and then 40% for the infrastructure-led wells. Thank you. I will introduce my good colleague, Erik Finnstrøm.
Thank you, Gro. Good afternoon, everybody. North America, last but not least, I hope. I'd like to give you an overview of our North America position and our exploration program that we have for the next two years going forward. We have, in fact, in North America, assembled one of the most aggressive and wide-ranging exploration programs of any offshore operator in North America. Positioned for success? Yes, I think so, and I hope I can convince you that that is the case. Picture I have here is the Discoverer Americas. That is one of our two long-term contracted deepwater operated rigs in the Gulf of Mexico. Let me start with a map of North America as a way to give you an overview. On the legend, we have the. I'm sorry.
I knew I was gonna do that. We have the, in magenta, the assets, the exploration assets that I'd like to begin with. The Gulf of Mexico here, deepwater forms the core of our U.S. portfolio with about 300 exploration leases, gross, and a very large, prospect portfolio with long-term drilling plans. We have, in the north, in the Chukchi Sea, off the coast of Alaska, an operated position with, sixteen operated licenses and a non-op position with ConocoPhillips and where we have fifty-fifty position and 50 licenses there. I'd like to point out that the Chukchi Sea is shallow water.
Moving on, in Canada, we have our position, our main and core position is in the Grand Banks area, where we have licenses in the two main or three main basins there, the Flemish Pass, the Orphan, and the Jeanne d'Arc basins. We recently did as was referred to by Pål, I think, a deal with Chevron, where we farmed into their position in the Beaufort Sea, giving us a long-term frontier position in the Canadian Arctic. We also entered their license in the Orphan, which will be tested by a well later this year. Just quickly go to the offices. Basically, our exploration offices are in Houston, which is the center of our operations and work in the United States. Anchorage is an operational office for our coming operations offshore Alaska.
In Canada, we operate our exploration from Calgary with support in St. John's. In 2011 reorganization that was done by Statoil, we streamlined our Gulf of Mexico organization and brought together three teams that were previously working in London, Oslo, and Houston into Houston to make a much more efficient work environment. In Calgary, we have also built the capacity of the Canadian team and roughly double its size over the last 18 months. Logan, Statoil's first, and hopefully not last, operated discovery in the Gulf of Mexico. We have previously announced this discovery with not too much detail.
I will take that a little bit further today and say that we've worked it very hard and can verify that we do have significant oil in place or STOIIP volumes. I would like to go a little bit further than that and give you some more numbers, but I can't at this point in time, but I think we'll be able to do that relatively soon. If we look at the cross-section on the right, which gives you an overview of the discovery, we have our discovery well, we're not really on the crest, but a little bit down the flank into the Paleogene Wilcox Formation. The Wilcox is a complicated reservoir in the Gulf of Mexico.
It has as much variability in this type of scale as it does, if we look at the map, on a scale across the basin. It is complicated. We need time to work it, and analyze the data. The data that we have worked, we've done carefully, and that we do see that we have superior oil quality and a very good reservoir in our pay zone that are, in fact, some of the best, if not the best, that have been seen in the Gulf of Mexico in the Paleogene to date. This gives us confidence to go ahead and plan and propose a down-dip appraisal well, which we expect to be able to drill in early 2013.
If I look over at the map on the left, just to put this in a little bit of context, you see Logan over here, down in the southeast corner of Walker Ridge protraction area. We have large Paleogene discoveries that are being developed that we are partners in, Jack and St. Malo in the area, and our Julia discovery with Exxon also in the same area. We have other discoveries, both Paleogene here by Chevron and Neogene discoveries in the near vicinity of Logan. This is a very prolific area where we have made the Logan discovery and we are actually now drilling the Bioko prospect, also a Paleogene prospect.
What we have here with Logan is significant proven STOIIP and the possibility for volumes together, potentially with our Bioko, if this comes in, to create a hub area for Statoil in the future.
I don't know what the assumption is on the gas. It's probably somewhere 60%-70% for associated gas, I would think. Relative to the 250, well, you know, at that point in time, what we were able and allowed to communicate was greater than 250 million barrels. As I say, that doesn't really tell you whether it's 251 or 400. You know, sort of going back a couple of months. It's first now, once we've done, you know, sort of we've worked all the data from the well, done the post-well analysis, that we're able to come up with a more specific estimate.
I think, you know, had we known initially right after the completion of the well, there was that it was these kind of numbers, then we would've obviously communicated these numbers. I think we've seen, you know, considerable upside as we've analyzed the data which we got from the well and from the test.
Okay, thanks.
Next question comes from Nitin Sharma with J.P. Morgan. Please, Nitin.
Hi, afternoon. A couple of questions. First one, Tim, on your presentation, slide five, you compare the discoveries 2006, 2008 with what you've delivered recent past, i.e., 2010, 2012. How do you compare value creation of 2011 versus what your previous results were delivering in terms of near-term field drilling versus higher risk, higher reward strategy that you're following now? Moving on to question number two, how has that impacted the results that you're targeting now, i.e., what sort of resource targets do you now have for your segment versus what you had when you started on this path? Thank you.
Okay. On the I haven't got a very good answer for you, to be quite honest, on the value creation, because I'm not actually aware, apart from Wood Mackenzie, of anyone actually attempting to measure value. I don't think Rystad were. I'm not sure you knew where they existed at that point in time. They may have done, but I actually don't have those numbers. We've also just recently, I guess, over the last couple of years, started to measure value creation. I think probably what you would find is that on a per barrel basis, the volumes in Norway come out quite favorably.
I think the overall number, you know, sort of the size or the value, $5 billion, would be very difficult to achieve on the Norwegian portfolio alone. Of course, the other point being is that we couldn't possibly drill up the same type of portfolio, the same number of wells in Norway as we can from a combined Norwegian and global portfolio, at least not for very long period of time. Then I'm not quite sure what the second question was about, but I think one of the important things, and I think Nick has already alluded to, is that we've been drilling what I call a much more balanced portfolio of wells each year.
We now have a larger portion of high-impact wells than we did before, but we have a very healthy spread between high impact, high risk wells, you know, typically frontier growth wells and then ILX wells. I think Nick's already alluded to it. That is the way we will be, you know, attempting to set up our portfolios going forward so that, you know, when we sit down every year and consider, you know, our yearly drilling programs, having a balanced portfolio is one of the important issues. It mitigates the risk of not proving up enough volumes. That's how we address it going forward.
Thank you.
Just the last question before the break, Rutania Sari from Bank of America, Merrill Lynch.
Hi there, gentlemen. This is a really quick question regarding how you're thinking about exploration within the overall CapEx program, going forward from here. Obviously, the company is in a ten-year ramp-up phase now with production, and you have pretty aggressive production targets out till the end of the decade. How do you see your exploration budget, maybe on a per barrel basis, going forward from here? Are you comfortable with the proportion that you have now? Would you like to see CapEx per BOE increasing for exploration? Is that something the company has guided? Or is this something you feel you can take a bit more of a rest on given the significant successes that you've had over the last 18 months?
I think the way you've been guiding, the way we have been guiding, the way we continue to guide is around about $3 billion on the exploration. If you look at the activity level, which we prognosed for 2013 and 2014, it's about the same. Wells are typically about 60% of our exploration cost. If we continue to drill about the same amount of wells, we will continue to spend about the same amount of money on wells going forward.
I think in terms of spending even more, we are probably punching or have been punching a little bit above our weight, spending a little bit more than some of our competitors, although there are strong indications that many of the larger companies at least intend to spend even more on an exploration than they have been recently. I think, you know, in order to spend significantly more than $3 billion, then you have to have the quality in the portfolio. I think what we tried, we've demonstrated already today is already a huge challenge, you know, just to get to where we're at and then to replenish and maintain that kind of portfolio.
You know, I don't foresee us spending significantly more than $3 billion, because I just don't think, you know, we will be able to build and sustain a portfolio that's large enough and with the kind of quality, you know, so that will warrant that kind of larger spending. On the final element, you talked about CapEx per barrel oil equivalent. We don't really think about it, but just one of the things we do measure on is, of course, finding cost. We do our benchmarking, and I guess you can do yours. Obviously last year and this year, we will come out very favorably on that. We do have specific targets on finding cost.
Again, summarizing, we target 2013 for an appraisal of Logan. We also have already kicked off a fast-track development or pre-development project on Logan, working with our development group, where we are using technology, targeted technology for the Wilcox Paleogene reservoirs that is being developed in our research center and has the code name Crack the Paleogene. This would be a direct application of that research work over the next couple of years on the Logan. Here is a map view of our Gulf of Mexico exploration plans for the next 2-3 years, or say 2 years. We will, over the next 2 years, be drilling up a high-graded portfolio of quality impact prospects.
If we again go to the legend, you can see that our wells, the operated wells, are denoted in magenta, partner in yellow, and then the symbols give you the stratigraphic reservoir targets that we will be going after. Now if you look at this, you also see the blue are our license positions, our exploration license positions, which I mentioned we have about 300 of. If you know, you look at the pattern that we have here, this forms what we call our Gulf of Mexico focus area. We've worked hard over the last 18 months to focus our work and to define the best areas for exploration in the Gulf of Mexico as we see it.
This has actually allowed us to build a seismic database of depth image 3D data, which is as competitive as any in the Gulf of Mexico, given that we were able to focus our efforts and resources into specific areas. We've also complemented this seismic database by establishing a new in-house depth imaging center. We have capabilities now in-house to do seismic depth imaging on targeted projects. This imaging center has been set up with WesternGeco and is a pilot and prestige project for WesternGeco and very unique in their portfolio as well. It is personally actually followed up by the president of WesternGeco. Let me just walk you through the wells. We have now currently drilling 2 operated wells.
We have the Kilchurn well being drilled up here in northeastern Green Canyon. This is a Miocene test. We also have drilling just recently spudded the Bioko well that I just mentioned, which is a Paleogene also impact size prospect. We have also completed in 2012 two non-op partner wells, the Heidelberg appraisal and Kakuna. I think that we have talked about the results of these wells, but I'll just quickly summarize those. The Heidelberg appraisal was a success in that it has verified the volumes that we thought were there on that particular structure. Anadarko's the operator. They did use our rig, the Discoverer Americas, to drill this. Anadarko is confident enough on Heidelberg that they're probably moving ahead with a development.
Kakuna, operated by Nexen, was unfortunately a dry hole. We have coming up in our program three very exciting and high volume prospects. We have Candy Bars up here in northern Green Canyon, followed by Coral, sort of an outlier of our focus area, really outside of our focus area, but still an interesting prospect nevertheless on the Paleogene. Over in the east, the Demon Star on a Jurassic age sandstone testing the same play that's been very successful for Shell in that same area. In addition to the operated wells that we have coming up, we do have a good, I would say very good, non-op program, where we have actually done a trade with Marathon between Kilchurn and Innsbrook. We traded some equity between those.
Marathon will be operating that well. That's a Miocene test in a very prolific area of discoveries of similar prospects. We are a high equity partner in this prospect here called Hummer Shallow. That's operated by ExxonMobil, and Exxon has that on their drill schedule, we understand, for late 2012. Hummer Shallow is a structural closure, which is becoming more rare in the Gulf of Mexico these days. We're very anticipating that, and that's a structural closure on the Neogene type of reservoir, which has been successful in the same general area with the discoveries I showed you at Lucius and Hadrian.
To summarize the program here, we are testing a very strong portfolio of impact prospects the next couple of years, and we are actually balanced across all of the type of plays that have been successful in the Gulf of Mexico to date or that are being currently tested. We have the Miocene in Candy Bars, we have the upper Miocene, Neogene, Pliocene play in Hummer Shallow, we have the Jurassic sandstones in Demon Star, and we have the Paleogene Wilcox in Bioko and Coral. This gives us a very, very nice balance and test of all of the plays going on in the Gulf today. Moving on to Canada.
This is a variation of a map I think that was shown earlier, looking down from the North Pole, and it gives a nice representation of how Canada and the work we're doing in Canada is tied to the rest of the Arctic efforts in the company. You can see here potentially you can see it in the white, our yet to find or oil potential as classified by the USGS. You can see that the Arctic basins and sub-Arctic basins have very high oil potential as classified by the USGS. We have taken positions in those basins in Canada. You can see them denoted by the stars. The Beaufort Sea, which I mentioned, the far-
Wells and then ILX wells. I think Nick's already alluded to it. That is the way we will be, you know, attempting to set up our portfolios going forward, so that, you know, when we sit down every year and consider, you know, our yearly drilling programs, having a balanced portfolio is one of the important issues. It mitigates the risk of not proving up enough volumes. That's how we address it going forward.
Thank you.
Just the last question before the break, Rutania Sari from Bank of America, Merrill Lynch.
Hi there, gentlemen. This is a really quick question regarding how you're thinking about exploration within the overall CapEx program going forward from here. Obviously, the company is in a 10-year ramp-up phase now with production, and you have pretty aggressive production targets out till the end of the decade. How do you see your exploration budget, maybe on a per barrel basis, going forward from here? Are you comfortable with the proportion that you have now? Would you like to see CapEx per BOE increasing for exploration? Is that something the company has guided? Or is this something you feel you can take a bit more of a rest on given the significant successes that you've had over the last 18 months?
Okay. I think the way we have been guiding, the way we continue to guide is around $3 billion on the exploration. If you look at the activity level, which we've prognosed for 2013 and 2014, it's about the same. Wells are typically about 60% of our exploration cost. So if we continue to drill about the same amount of wells, we will continue to spend about the same amount of money on wells going forward. Now, I think in terms of spending even more, we are probably punching or have been punching a little bit above our weight, spending a little bit more than some of our competitors.
Although there are strong indications that many of the larger companies at least intend to spend even more on an exploration than they have been recently. I think, you know, in order to spend significantly more than $3 billion, then you have to have the quality in the portfolio. I think what we've demonstrated already today is already a huge challenge, you know, just to get to where we're at and then to replenish and maintain that kind of portfolio.
You know, I don't foresee us spending significantly more than $3 billion because I just don't think, you know, we will be able to build and sustain a portfolio that's large enough and with the kind of quality, you know, so that will warrant that kind of larger spending. On the final element, you talked about CapEx per barrel oil equivalent. We don't really think about it, but, you know, sort of one of the things we do measure on is, of course, finding cost. We do our benchmarking, and I guess you can do yours. Obviously last year and this year, we will come out very favorably on that. We do have specific targets on the finding cost.
As I say are delivering well on that. That's also a parameter which we'll use to constrain our spend.
Understood. Thank you very much.
Thank you.
Thank you. We'll take a 10-minute break. We'll reconvene at five minutes to three Oslo time. Thank you.
I'm in with Chevron. We have and have been building a significant portfolio in the Grand Banks area focused on the Flemish Pass basin. Our strategy has followed those outlined by both Tim and Pål, early access at scale, getting us into these large prospects with upside potential. We are working within the Arctic initiative that's been kicked off in the company to take synergies out of the work that's being done in the other basins along the lines of environmental and stakeholder work, technology development, and operational experiences. Let me focus a little bit on what I would call our dominant operated position in the Flemish Pass. We have, on the left, a map showing our position and basically.
Well, this is the blue color here denotes our operated position. We operate every licensed piece of land in the basin. We have complete control of it. We recently won in the 2011 land sale these blocks here, together with our partners, Chevron and Repsol. We've held for some time these blocks over here containing the Mizzen discovery. This one, this block here, I think, was won in the 2010 land sale by us. A very strong frontier type of position with encouragement. If I move from the map now over to the cross section, we have encouragement from our Mizzen discovery, where we've drilled a discovery well and an appraisal.
The wells on Mizzen, this is very schematic, but they've given us the information to develop what Pål was talking about and maybe in some more detail in this basin, the sweet spot maps and the understanding of the play, which is represented by this prospect down dip from Mizzen, which is actually a prospect out here that we would like to develop for future drilling. We've established both reservoir and source rock and an effective hydrocarbon system in this basin, and we see that other areas away from Mizzen could have even better developments.
If I return to the map, what you see is Mizzen here, and then we have our next well, Harpoon, is scheduled for spud at the end of 2012. Harpoon is an impact size prospect. We own 65%, currently 65% of that license. Then we have follow-up potential. In fact, all of these prospects are impact size, and all of them are structural closures. This is a really very unique position for us and for any company in the world to have large impact size structural closures in a basin that has a proven hydrocarbon system. To test this portfolio, we have contracted a rig, the West Aquarius, where we have 3 slots that'll be kicking off with the Harpoon well in late 2012.
Moving on from Canada and to Alaska, you can see that Alaska is yet another component of our Arctic buildup. We have an operated position here in these in a set of blue blocks. These blocks are actually the same size as the Gulf of Mexico blocks. You could hope that maybe they would be a little bit bigger in the Arctic, but they are the same and are actually operated under the same sort of rules and regulations. We have a shot at a 3D program around these blocks and actually acquired very high-quality 3D data there.
We have developed a prospect, Amundsen, here, which we are maturing towards drilling, and we're targeting drilling of Amundsen in 2014, but we have not yet taken the decision on that as a final decision. We also have a very interesting position to the south. This is a set of licenses operated by ConocoPhillips, where we have 25% in each of those 50 licenses. Excuse me. Now, they also have shot a 3D of good quality and developed an impact-size prospect called Devil's Paw. Devil's Paw is also scheduled to be drilled in 2014. Let me just also mention that you can see on the map a number of other wells. These were wells drilled mainly by Shell in the late 1980s and early 1990s.
Especially this well, Burger, here is a well that gives encouragement in this basin in that it proved gas, it proved potentially a very large accumulation of gas. What we hope for ourselves is oil, and we have put together the data and the evidence that do point to that our prospect up here could be a very good oil prospect. The same thing at this one, Devil's Paw. Shell will actually be kicking off their exploration program on Burger, drilling an appraisal well on this this year. That will be a very interesting test for us to follow along.
We are, again, have not made the final decision on our drilling, but if we move ahead, we'll be kicking off our permitting campaign in a few months and beginning to do the heavy preparations that we know have to be done in this environmentally sensitive area. It is thus important for us to work with the other operators in an environment like this, and we are. We're working with both ConocoPhillips and Shell on developing drilling logistics and oil spill response systems for this Arctic basin. Summary. To We are executing a very aggressive program.
I must say are delivering well on that. That's also a parameter which we'll use to constrain our spend.
Understood. Thank you very much.
Thank you.
Thank you. We'll take a 10-minute break. We'll reconvene at five minutes to three Oslo time. Thank you.
These couple of years in North America, we if you look at the keywords for Gulf of Mexico here, streamlined quality seismic database, proprietary imaging, drilling capacity. We've set ourselves up. That's the title of the talk. We've set ourselves up for success. We hope we will get it. Grand Banks, keywords, dominant operated position, and we will be drilling some of these impact prospects. They're on our drill schedule, we have capacity. In the Chukchi in Alaska, we're moving forward, and maturing the prospect for drilling the Amundsen prospect. Again, to summarize, we've built an operating capability, a very strong prospect 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 couple of years.
This is an effort we intend to sustain over time as North America steps into the title of core area for Statoil. Thanks.
Thank you, Erik. We are now ready for the second Q&A session, and Tim, Gro, and Erik will answer questions related to their presentations. Should there be any questions relating to Arctic exploration, we also have Rúni M. Hansen here, who's the head of Arctic Exploration, who can answer those questions. Should there be questions on technology, as Erling Vågnes unfortunately got sick and couldn't attend, the panel will also answer questions related to his presentations. We'll start out taking questions from the audience here in Oslo and yes.
Hi, it's Anders Holte from ABG Sundal Collier. It's just a few questions for Gro. On the Johan Sverdrup discovery, Lundin, they made an unsuccessful appraisal south of the discovery, and I see that on the Det Norske's plan, they plan to drill a well in 502. Is that something, I mean, considering that the appraisal that Lundin drills showed water, is that something you will be taking a part in, or, you know, how do you view that well in terms of it being oil field or do you perceive that as being water-filled as with the appraisal? And second one is if you can just reiterate those numbers from Gullfaks about how many barrels found and also the value for those barrels. Thank you.
First, on Johan Sverdrup, as I understand your question, you're asking about if you're going to drill a well in 502 this year, and we are discussing the opportunities there. We haven't finalized yet the evaluation of the prospectivity there. We are still discussing at least where we should drill it, so I cannot be specific, more specific on that. But we are working on it and looking upon the potential there. Then can you just, yeah, evaluation of Gullfaks? Yeah. I just, the evaluation of Gullfaks, I was just thinking about, it's done in a simple way. I just used the number of barrels, and I think I used an oil price of 60 USD at 6 NOK per dollar.
I just calculated up compared to the Skrugard-Havis, and then I just used the same principle on those 150-200 million barrels in Gullfaks area. It was 100% to total it, and it's not including the CapEx or the costs. It's more as a hun-
Revenue.
Yeah, yeah. Revenues. Sorry. Yeah.
Yeah, yeah. It's revenue barrels.
Yeah. Mm-hmm. Yes, Teodor.
Just first one on King Lear. The well has been drilling for quite a while. Could you please give some indication of when we can expect a result? Second one is on EM. You have previously communicated that EM data was crucial when discovered both Skrugard and Havis. Could you give some color on which prospects you applied EM on now and how you will apply EM going forward?
Yeah, when it comes to King Lear, we are drilling on that still, and I think we will come back early summer with the result on that well. That's what I can say on that well. When it comes to EM data and how we use that in the Barents Sea, I can say that the EM data is quite excellent data set to use in that area. For us, it's really important also to integrate those data with all the other data, also the geophysical data. Because you have to put all data together and then with the geological knowledge that we have, it's very important to use this as a combined data evaluation.
From this combined data evaluation, we can draw the consequences and see the potential. We don't use EM data alone, but we use it together with all the other geological and geophysical data to come up with the result of our evaluation. Another question, please.
Hi there. It's Mark Coughlan from Macquarie again. Just two quick questions. I was hoping you could remind me again on that minimum commercial threshold at King Lear. Just secondly, if we think about an overall CapEx in exploration this year of $3 billion, just the allocation of that within the NCS and North America, that'd be great. Thanks.
Yeah. I think when it comes to King Lear and this, I think I will come back to that and when it comes to the break, yeah. I'll come back to that. I'll check that out. The other question?
Just on the CapEx, was it?
Yeah, just the split.
On the CapEx for King Lear?
No, no, just,
On the split between Norway and the rest of the.
Okay.
the portfolio.
On the split.
I think, it's a little bit difficult. I don't have the exact numbers, but I guess somewhere close to half the wells here. Did you know?
Yeah. Spent around one third of the exploration spend in terms of Norwegian Continental Shelf, and the rest in the rest of the world.
Yeah.
Okay. Did you hear that on the website? About one third in Norway.
Yeah.
On the exploration wells, and then two thirds otherwise. As I said, that's about 60% of our spend. I think seismic and, you know, the other costs are relatively the same as well. Yeah.
Yeah.
Somewhere between one third and 40%. Yeah.
We have another question over here from Trond.
Trond Omdal, Arctic Securities. It hasn't been that focused today, but could you say a little bit, there has been some reports that you might also have farmed into other shale opportunities. Could you talk a little bit of where you see. Do you see any potential in both more shale opportunities both in the U.S. and even in Canada? The second question on Aldous or previously called Aldous. You still consider Aldous North a high impact well after the first disappointment?
I can, we are talking about Gjeitungen. I will not confirm any volumes, but it has an interesting potential. That's what I can say.
On the shale stuff, Trond, not quite sure what you're alluding to, but I guess my statement is we haven't farmed in until we have, and we'll announce that at the appropriate time. We are continued to consider further probably more immature shale opportunities in the US, but also globally, select opportunities there. In that case, we've run a similar process. We have a number of basins or countries which we prioritize, and in fact it's Pål's group who's actually done all that subsurface work. We've done it in the same way for the unconventional hydrocarbons as we've done with the conventional.
We've chosen a few areas, and it's not anywhere close to 18 where we are considering entering into what I would call exploration unconventional opportunities. But more than that I can't confirm at this point in time.
You've just gone on two areas you previously were early in China and then Argentina. I see of course, given the nationalization has increased the risk. Do you have a couple of comments on these two areas, as well?
Yes.
Just to follow up, China of course you were an early entrant, but then, due to some political issues seem to maybe have stopped up there. The other area, Argentina, where there is a lot of focus among some of the majors and of course due the YPF nationalization may have increased the risk. Do you see any opportunities in those two geographies?
Okay. I'll try and keep this short and I don't know how sweet it will be. Anyway, I think the situation in China is unchanged, i.e., status quo. When it comes to Argentina, well, I'll let you speculate as to whether Argentina is one of our prioritized basins or not. The fact that a lot of other companies going there might give you a good indication.
Yes, I see one more question in Oslo.
Tom Erik Kristiansen, Pareto Securities.
Mm-hmm.
I see you plan to drill 8-10 exploration wells in the Greater Utsira High over the next three years. Could you maybe tell a bit more about those prospects? Have you found anyone that are high impact potential or
Yeah, I can.
Is it smaller prospects?
I can tell you because I think there are some interesting prospects both in the licenses we hold as an operator, but also in the partner licenses. There is absolutely a potential for high-impact prospects in those licenses. We will come back to it when we are more clear and when we have fully evaluated the area. We see absolutely a potential for some interesting prospects to be drilled in that area. Of course, based on the history here, it's not that easy either to map and to interpret. You have to use some time. We are now doing this, what should I say, improving all the seismic data for imaging and also trying to use different kind of acquisition methods.
We will use the time and really think through and understand also better, what should I say, the whole migration history in that area. Before we take any final decision. All right. We'll then turn to our audio conference audience. The first question comes from Peter Hutton with RBC. Please go ahead, Peter.
You either need to speak or speak up.
Are you there, Peter?
Yeah, sorry. Good afternoon. Sorry for the slightly late there. Two questions for Erik, if I may. You mentioned in your presentation that you'd like to be able to give more information on the figures on Logan. Just given that you're the operator, what's the holdup there? Why aren't you able to provide that? And the second one is on the Chukchi. You were saying that sort of the target 2014 as you move towards decision. Is it fair to say that one of the key factors in that decision-making process is likely to be sort of contingent on the approvals for Shell as one of the other operators and seeing how that goes? And on that basis, what's your reading of how that's progressing at the moment? Yes.
On Logan, I just have to apologize really that I didn't run the traps before this presentation, that we haven't run it through our partners. We will be able to say something more about Logan pretty quickly, and we'll be having another presentation in the United States in about three weeks, where we most certainly give a more specific number on Logan.
I apologize for that. On the Chukchi-
No.
Yeah. The Chukchi, yes, 2014, we'll certainly be watching what happens to Shell very closely. We will be running our own process independent of that, but clearly it does give us information in terms of how long it takes to get permits, what are the issues, in terms of also potential lawsuits, such things. We'll be watching what happens with Shell.
Okay, thank you.
Our next question comes from Nick Coleman with Argus Media. Please go ahead, Nick.
Hi, thank you. Question about Lofoten- Vesterålen. If I've got the pronunciation right, the closed areas offshore Norway. How confident are you that that is gonna be fully opened up for the industry? I think you've got a general election coming up fairly soon in Norway. Do you have a feeling? Are you optimistic about the opportunities there opening up for you?
Okay. I'll again short, but not necessarily sweet. I think it's not a question about if, it's more a question about when. I think that's about as much as we can say. As you know, then, the Norwegian Petroleum Directorate have acquired new seismic in both areas. That's been made available for the industry. We have to assume they've done that with a purpose and that these areas will be opened up. That or parts of these areas will be opened up for exploration, further exploration activity, i.e., drilling at some stage in the not too distant future.
Okay, thanks.
Thank you. I can't see any more questions on my list. Is that correct, operator? Are there no more questions from the audio conference?
We have a question from Neill Morton from Berenberg.
Please go ahead, Neill Morton.
Yeah, it was two questions, actually. The first is going back to the Rosneft deal. We've seen a number of offshore deals in the last month or so with Eni, with Exxon, and now with Statoil. Just as background, was the acreage offered done on a sort of set menu basis, or was it sort of a la carte? Could you sort of pick and choose the areas, discuss what you'd like to explore? And just following on from that, the one block you've got up in the Barents, is there any sort of read across from your existing knowledge on the Norwegian side? And then just secondly, just a question on clarification. There was lots of talk in the last presentation about impact prospects. Could you just maybe define, is that different?
Is it a lower number from high impact? A little bit confused there. Thank you.
Okay. Let me start out on the Rosneft issue, and then Eric can follow up on the impact question. On the Rosneft, a little bit of both, if you like. When we got to the negotiation table, we were presented with a greater number of opportunities than we picked. It wasn't a set menu, but it wasn't necessarily à la carte either. I think the way we like to look at this is that we are the third of three very large companies to do very large, significant strategic deals with Rosneft in Russia. We're very pleased to be one of those three.
We're satisfied with the acreage which we've got. In terms of sort of the bleed across, I'm not quite sure what you're alluding to up in the Northern Barents Sea. You know, this is rank frontier acreage. The more north you go in the Barents Sea, both the Norwegian part and the Russian part, the less data there is. It is a fact that there is only one seismic line through the block which we've acquired up in the north. None that I'm aware of on the Norwegian side.
Of course, you know, we have used our regional understanding of the Barents Sea, both the Norwegian and the Russian, in order to have some kind of view on this acreage. I think, you know, contrary maybe to common perception, then all of the three Rosneft licenses in the Central Barents Sea, which were part of the previous disputed zone, have to be considered to be rank frontier, high risk opportunities with a very uncertain oil and gas potential. That has to do with the amount of data available, which is very, very limited and limited to 2D seismic. On the impact question, I'll leave that to Erik.
Yeah. Again, apologize, that's kind of a language gap developing across continents. I guess, it's exactly the same thing, impact and high impact. I didn't mean to imply anything different than the definition that was shown by Tim or Pål in the beginning.
Okay, that's great. Very clear. Thank you.
Thank you. I can't see any further questions, so this will conclude our Q&A session and our event for today. The presentations and the Q&A sessions can be replayed from our website. If you have any further questions, please don't hesitate to contact us in the investor relations department. Thank you all very much for participating today, and have a good day. Welcome back, everybody. We will now start our second session, and the first speaker out is Gro G. Haatvedt, who is the Senior Vice President for Exploration Norway. Please go ahead, Gro.
Thank you, Hilde, and good afternoon, everybody. As presented by Tim earlier today, Statoil's ambition is to be a leading exploration company by 2015. An important building block, of course, in this strategy is to optimize our core position on also the Norwegian Continental Shelf. I will now give a short status on how we are positioned to reach this ambition and in addition, to also contribute to the production ambition beyond 2020. I'll just show the team out on the rig when we made the Havis discovery. It's a great team, and this was a very good start of this year. First, to try to give you an overview of the main activities on the NCS this year. Our exploration activities is almost as high as it was last year.
This year we will drill in total between 20 and 25 exploration appraisal wells, both as an operator, as a partner. We have earlier defined three prospects as high-impact prospects, and we can start up in the Barents Sea and Havis, which I also alluded to on the first slide. It resulted in a high-impact discovery in the beginning of this year. We can go to the south, to the North Sea, and we drill the Crux well. This exploration well had two objectives. First one, to test the new play in the area, the Crux prospect, which was a high risk, high reward opportunity. Second, also to test the infrastructure near prospect called Crimp. Unfortunately, we found no gas in the Crux prospect, but we are pleased with the oil discovery in the Crimp prospect.
Even though our high impact opportunity has not materialized, we have delivered some valuable additional resources to the Oseberg area. We go to the South, and it's King Lear, and that is about 20 kilometers north of Ekofisk, and it's currently ongoing, and I will come back to this also in detail later. Welcome back, everybody. We will now start our second session. The first speaker out is Gro Haatvedt, who is the Senior Vice President, Exploration Norway. Please go ahead, Gro. Thank you, Hilde, and good afternoon, everybody. As presented by team earlier today, Statoil's ambition is to be a leading exploration company by 2015. An important building block, of course, in this strategy is to optimize our core position on also the Norwegian Continental Shelf.
I will now give a short status on how we are positioned to reach this ambition and in addition, to also contribute, to the production ambition beyond 2020. I'll just show the team out on the rig when we made the Havis discovery. It's a great team, and this was a very good start of this year. First, to try to give you an overview of the main activities on the NCS this year. Our exploration activities is almost as high as it was last year. This year we will drill in total between 20 and 25 exploration appraisal wells, both as an operator, as a partner. We have earlier defined three prospects as high-impact prospects, and we can start up in the Barents Sea and Havis, which I also alluded to on the first slide.
It resulted in a high-impact discovery in the beginning of this year. We can go to the South, to the North Sea, and we drill the Crux well. This exploration well had two objectives. First one, to test the new play in the area, the Crux prospect, which was a high risk, high reward opportunity. Second, also to test the infrastructure near prospect called Crim. Unfortunately, we found no gas in the Crux prospect, but we are pleased with the oil discovery in the Crim prospect. Even though our high impact opportunity has not materialized, we have delivered some valuable additional resources to the Oseberg area.
We go to the South, and it's King Lear, and that is about 20 kilometers north of Ekofisk, and it's currently ongoing, and I will come back to this also in detail later in my presentation. Another well that I really want to name specifically is the Loven well. It's up on the Trøndelag platform. We do not define this as a high impact opportunity. It also has a high risk that means that the probability of finding hydrocarbon is not very high, but it has an upside. In addition, it's an important well because it in case of a discovery, this could also open up an underexplored area in the Norwegian Sea. We have a 100% share in that license. It's also very important to secure new acreage, also, of course, quality acreage.
We are now working hard on the 22nd concession round and also the APA round for 2012. In addition, we drill also appraisal well on Skrugard and Johan Sverdrup this year. I think also we can guide now and say that about this portfolio, about 40% is infrastructure and wells. These wells, of course, do not create the big headlines in the media, but they can give really valuable barrels and also extend the lifetime of the infrastructure. Now I will dive more into the Skrugard licenses. In less than a year, in fact, we have made two substantial oil discoveries, Skrugard and Havis. We were proving up between 400-600 million barrels of recoverable oil.
Earlier this year, we also had a successful appraisal on Skrugard, confirming our estimates and also collecting very important and critical data for development planning. The Skrugard and Havis discoveries have, of course, renewed the exploration optimism in the Barents Sea. I also have to say that we are expecting a high degree of competition in the 22nd concession round. At the same time, I'm very proud of Statoil stayed the course when others gave up. The Skrugard area has some really interesting also follow-up potential. In the end of this year, we will launch a new ambition exploration campaign in the area, in these two production licenses which we held, to, of course, together with our partners. The drilling campaign comprised of four prospects. You can see three of them in white here is Iskrysta l, Skagul, and Nunatak.
The fourth one we will decide upon in the nearest future. These four prospects we will drill back to back, and we have secured rig capacity on West Hercules coming from Asia, and we are also doing winterization of that rig before it goes up, of course, and drill in the Barents Sea. Our ambition is to fulfill this drilling campaign by early summer 2013, and Nunatak is the first well to be drilled or the prospect to be drilled. Let's dive into the Nunatak prospect. That is in a very early in my presentation. Other well that I really want to name specifically is the Loven well. It's up on the Trøndelag platform. We do not define this as a high-impact opportunity.
It also has a high risk, that means that the probability of finding hydrocarbon is not very high, but it has an upside. In addition, it's an important well because in case of a discovery, this could also open up an underexplored area in the Norwegian Sea, and we have a 100% share in that license. It's also very important to secure new acreage and also, of course, quality acreage. We are now working hard on the 22nd concession round and also the APA round for 2012. In addition, we drill also appraisal well on Skrugard and Johan Sverdrup this year. I think also we can guide now and say that about this portfolio, about 40% is infrastructure and wells.
These wells, of course, do not create the big headlines in the media, but they can give really valuable barrels and also extend the lifetime of the infrastructure. Now I will dive more into the Skrugard licenses. In less than a year, in fact, we have made two substantial oil discoveries, Skrugard and Havis, and we were proving up between 400 and 600 million barrels of recoverable oil. Earlier this year, we also had a successful appraisal well on Skrugard, confirming up our estimates and also collecting very important and critical data for development planning. The Skrugard and Havis discoveries have, of course, renewed the exploration optimism in the Barents Sea. I also have to say that we are expecting a high degree of competition in the 22nd concession round.
At the same time, I'm very proud of Statoil stayed the course when others gave up. The Skrugard area has some really interesting also follow-up potential. In the end of this year, we will launch a new ambition exploration campaign in the area, in these two production licenses which we held to, of course, together with our partners. The drilling campaign comprised of four prospects. You can see three of them in white here is East Krystal, Skagul, and Nunatak. The fourth one we will decide upon in the nearest future. These four prospects we will drill back to back, and we have secured rig capacity on West Hercules coming from Asia, and we are also doing winterization of that rig before it goes up, of course, and drill in the Barents Sea.
Our ambition is to fulfill this drilling campaign by early summer 2013, and Nunatak is the first well to be drilled or the prospect to be drilled. Let's dive into the Nunatak prospect. That is in a very immediate vicinity to the Skrugard discovery. In the Skrugard license or licenses, many of the prospects have these flat spots, as also Nick have alluded to now from Tanzania. These are indications of presence of hydrocarbons. For this prospect, which is in white or at the transparent white here in the map to the left, and you also see on the seismic line on the right, it also have a double flat spot.
This one could be in communication, if it's a discovery, could be in communication with Skrugard discovery. That's why it's so important for us to test out and find if it's really holds hydrocarbons. With the observations we have seen, it's quite a high probability for finding hydrocarbons here. We go to a really new or the next frontier area in the Barents Sea. No wells have yet been drilled up there, and that is in the Hoop area. You can see it here. It's the northernmost licenses which has been awarded in the Barents Sea so far. The main target here is a shallow reservoir located just 600 meters approximately below the surface. You have this shallow reservoir. It also enables us to have some excellent seismic imaging.
In this particular opportunity, which we see up north there, we also have some direct indications of hydrocarbons in our seismic data. You can also see the map here to the right. This shows, also, we call it an amplitude map, and it, this shows that it could be a good hydrocarbon indicator for this structure to be held. We are going to drill two wells here, and we are doing that in an aggressive way because we will just do it after we have finalized on the Skrugard. I can say also the license obligation is to drill the well within 2015, and we will finalize this within 2013 and have a good position up there.
License to the south, where we are a partner, within also the same area, the Hoop area with the circle around there, we'll drill or participate together with OMV on the Wisting well. That will be drilled some or a couple of months before we go up to Hoop and our license. Johan Sverdrup field, I think you all know that. It's about 140 kilometers west of Stavanger, and I think making this discovery really also just remind us that the North Sea is a world-class hydrocarbon basin. This map I'll try to explain to you. It shows, you know, a subregional topography map in the Utsira area, and you can see the Viking Graben. It's very immediate vicinity to the Skrugard discovery.
In the Skrugard license or licenses, many of the prospects have these flat spots, as also Nick have alluded to, you know, from Tanzania. These are indications of presence of hydrocarbons. For this prospect, which is in white or at the transparent white here in the map to the left, and you also see the on the seismic line on the right, it also have a double flat spot. This one could be in communication, if it's a discovery, could be in communication with Skrugard discovery. That's why it's so important for us to test out and find if it's really held hydrocarbons. With the observations we have seen, it's quite a high probability for finding hydrocarbons here. We go to a really new or the next frontier area in the Barents Sea.
No wells have yet been drilled up there, and that is in the Hoop area. You can see it here. It's the northernmost licenses which has been awarded in the Barents Sea so far. The main target here is a shallow reservoir located just 600 meter approximately below the surface. Then you have this shallow reservoir. It also enable us to have some excellent seismic imaging. In this particular opportunity, which we see up north there, we also have some direct indications of hydrocarbons in our seismic data. You can also see the map here to the right. This shows also, we call it an amplitude map, and this shows that it could be a good hydrocarbon indicators for this structure to be filled.
We are going to drill two wells here, and we are doing that in an aggressive way because we will just do it after we have finalized on the Skrugard. I can say also the obligation, license obligation is to drill the well within 2015, and we will finalize this within 2013 and have a good position up there. License to the South, where we are a partner, within also the same area, the Hoop area with the circle around there, we will drill or participate together with OMV on the Wisting Well. That will be drilled some or a couple of months before we go up to Hoop and our license. Johan Sverdrup field, I think you all know that.
It's about 140 kilometers west of Stavanger, and I think making this discovery really also just remind us that the North Sea is a world-class hydrocarbon basin. This map I'll try to explain you. It shows, you know, a subregional topography map in the Utsira area, and you can see the Viking Graben to the west there and also East Shetland Platform. Then you see how the discovery is placed upon the Utsira Southern Part High. The reservoir here is superimposed on the map. It's kind of 3D view, and it almost show the container, the reservoir here, where the hydrocarbon is held. It also show the wells that has been drilled and also some of the new wells to be planned for.
It's a kind of subtle trap, but this is what we are working on these days. To visualize this way, it also gives a better overview of the setting. I can also say that the warm colors here is high areas, and the cold colors are the basins. That goes also for the map, which represent the reservoir level here. This is a discovery made in shallow water. It's a shallow reservoir, and it's also close to shore and close to existing infrastructure, with a very good reservoir parameters. We are now going on with the drilling campaign in the license 265, which we are operating. We will start drilling this summer. The first one is Gjeitungen, and that is up north here.
Also see the wells here on the seismic line. Of course, if we make a discovery here, this could also add additional upside to Johan Sverdrup volumes. The two other wells, Espevær and Krossøy, they are appraisal wells. You also see how they plot them on the structural map here to the left. I can also tell you that the reservoir here is between the yellow one that's close to the reservoir and the green one here is close to the base of the reservoir. Being in a position like us here with a giant or with the discovery of a giant oil field, it's of course also very important to have access and to get access to the most important acreage around it.
I think we secured two new attractive acreage in the APA last year, and that is PL 624 to the north and PL 628 to the south. If you look at the map here, you also see that we have a very good position both as an operator, as a partner in this area. Of course, that is important in an area where we know so much hydrocarbon has, or oil and gas has been generated through this period. We are running also a number of projects because what we see, this trap is a kind of subtle. It's not an easy trap. When I say trap, it's where the hydrocarbons or oil and gas is being trapped.
It's very important for us also to work more on the seismic data, the quality of the data, so that we can also use those data at Rubben to the west there, and also East Shetland Platform. Then you see how the discovery is placed upon the Utsira Southern Part High. The reservoir here is superimposed on the map. It's kind of 3D view. It almost show the container, the reservoir here, where the hydrocarbon is held. It also show the wells that has been drilled and also some of the new wells to be planned for. It's a kind of subtle trap, but this is what we are working on these days.
To visualize this way, it also gives a better overview of the setting. This is, I can also say that the warm colors here is high areas and the cold colors are the basins. That goes also for the map, which represent the reservoir level here. This is a discovery made in shallow water. It's a shallow reservoir, and it's also close to shore and close to existing infrastructure, and with a very good reservoir parameters. We are now going on with the drilling campaign in the license 265, which we are operating. We will start drilling this summer. The first one is Gjeitungen, and that is up north here. You can show. Also see the wells here on the seismic line.
Of course, if we make a discovery here, this could also add additional upside to Johan Sverdrup volumes. The two other wells, Espevær and Krossøy, they are appraisal wells. You also see how they plot them on the structural map here to the left. I can also tell you that the reservoir here is between the yellow one that's close to the reservoir and the green one here is close to the base of the reservoir. Being in a position like us here with a giant or with the discovery of a giant oil field, it's of course also very important to have access and to get access to the most important acreage around it.
I think we secured two new attractive acreage in the APA last year. That is PL 624 to the north and PL 628 to the south. If you look at the map here, you also see that we have a very good position both as an operator, as a partner in this area. Of course, that is important in an area where we know so much hydrocarbon has or oil and gas has been generated through this period. We are running also a number of projects because what you see, this trap is a kind of subtle. It's not an easy trap. When I say trap, it's where the hydrocarbons or oil and gas is being trapped.
It's very important for us also to work more on the seismic data, the quality of the data, so that we can also use those data at the maximum, also to find new opportunities in this area and also to understand better the development of the area. We are also then merging together 3D seismic data to try to have the same kind of quality on all the data. We are doing that from the Oseberg area and including then the Utsira southern area. We shall have a very good data set looking into other opportunities here because we know that they are. It's not easy to find, so we have to use all the data and all the knowledge we have in order to really to map those opportunities out.
I think you have already alluded to King Lear, and it is a high impact prospect in the Central Graben in Block 24. The history here, as you are aware of, is of course that the presence of hydrocarbons in the structures has been proved back to 1989, when Saga was drilling this well 24/14, which unfortunately resulted in a subsurface blowout. The objective of this well now is to check out how big are the volumes and are the volumes commercial. This is the main target with this well. King Lear is a high pressure, high temperature well, and it requires of course HSE focus as also Tim has alluded to.
I think also we have got better experience in handling high pressure, high temperature wells both from exploration wells and field development wells like in Kristin, Huldra, Kvitebjørn, Morvin and Gudrun. It's also important, I think, to notice that an appraisal well 2418 R, you can see it here on the seismic line. It was drilled in 1994 without any HSE incident. Of course we are monitoring the well very closely and we are doing this also as a routine on all of our exploration wells. I go to the Gullfaks area, and that is in fact a really fantastic area when it comes to doing infrastructure-led exploration.
It's, I can say, the magenta color here means condensate, the green and red means oil and gas, and the green is oil. The Gullfaks field, the big field was made so far back that in 1978, and it was at that time approximately 2.5 billion barrels. Then we had some really interesting growth prospects in the areas which of course was proven up. Then we found an additional 1 billion barrels. In the 1990s, we found new discoveries there, adding up another 800 million barrels. I think the importance here is the maximum also to find new opportunities in this area and also to understand better the development of the area.
We are also then merging together 3D seismic data to try to have the same kind of quality on all the data. We are doing that from the Oseberg area and including then the Utsira southern area. We shall have a very good data set looking into other opportunities here because we know that they are. It's not easy to find. We have to use all the data and all the knowledge we have in order to really map those opportunities out. I think you have already alluded to King Lear, and it is a high impact prospect in the Central Graben in Block 24.
The history here, as you are aware of, is of course that the presence of hydrocarbons in the structures has been proved back to 1989, when Saga was drilling this well 24/14, which unfortunately resulted in a subsurface blowout. The objective of this well now is to check out if or how big are the volumes and are the volumes commercial. This is the main target with this well. King Lear is a high pressure, high temperature well, and it requires of course, HSE focus as also Tim has alluded to. I think also we have got better experience in handling high pressure, high temperature wells, both from exploration wells and field development wells, like in Kristin, Huldra, Kvitebjørn, Morvin, and Gudrun.
It's also important, I think, to notice that an appraisal well 2418 R, which you can see here on the seismic line. It was drilled in 1994 without any HSE incident. Of course, we are monitoring the well very closely, and we are doing this also as a routine on all of our exploration wells. I go to the Gullfaks area, and that is in fact a really fantastic area when it comes to doing infrastructure-led exploration. It's, I can say, yeah, the magenta color here means condensate. The green and red means oil and gas, and the green is oil. The Gullfaks field, the big field was made so far back that in 1978.
It was, at that time, approximately, 2.5 billion barrels. Then we had some really interesting growth prospects in the areas, which of course was proven up. Then we found an additional 1 billion barrels. In the 1990s, we found new discoveries there, adding up another 800 million barrels. I think the importance here is that during the last ten years, we have also had quite high activity here, and it has added up 150-200 million barrels of oil. Only last year and early this year, we made 4 new discoveries here, and those are mentioned here on the map in this area all. When we are thinking about the value then, it's about 100, between 150 and 200 million barrels of those more smaller discoveries.
We can look to Skrugard Havis, which has between 400 and 600 million barrels. If you just use a simple, what should I say, calculation here and we can think Skrugard, the Havis, and it's 100%, but then it has a value of NOK 300-NOK 400 billion. You can go here, see between 150 and 200 million. It has a value of about maybe between 100 and 150 billion Norwegian crowns. In addition, these barrels, they will also very quick be put into the infrastructure because there are available capacity. It's really high value barrels to Statoil and to our partners and to the society.
Okay, I try to sum up our outlook for 2012 to 2014. Of course our aim is to create materiality and value through the NCS exploration. Also thereby, of course, contribute to the production target for Statoil beyond 2020. To achieve this, it's very important for us to rebalance our activities and portfolio to focus also much more on material growth opportunities, both in traditional, but also looking into new plays. In more detail, our strategy really includes strong prioritization, clearly defined top areas in which we want to accelerate activity level. We will focus on growth in proven basin. With proven basin, I mean the North Sea and the Halten-Dønna, where we know that the petroleum system is working.
We will accelerate then the maturational prospects here in these established rich provinces for more short-term means. We have also a strategy not only to drill timely infrastructure-led wells. That means from discovery to it is in production, it should be around two years lead time. Because then we will add value and not erode value. Of course, it's also important to continue to explore selectively in frontier regions. We are taking selective bets in frontier places, like the Hoop area, which I have gone through. Of course, it's still very important for us, even with all the successes we have had, to get acreage or get access to new quality acreage.
Still it's really important for us to push on to open up the Barents Sea east and of course the Lofoten Vesterålen Tromsø area. We will, or we have a guidance that we will drill between 60 and 80 wells, both exploration and appraisal wells, during this two-year period. As I also said, we have changed our footprint. We are guiding now 10, around 10% frontier, 50% for growth and then 40% for the infrastructure-led wells. Thank you. I will introduce my good colleague, Erik Finnstrøm.
Thank you, Gro. Good afternoon, everybody. North America, last but not least, I hope. I'd like to give you an overview of our North America position and our exploration program that we have for the next two years going forward. We have, in fact, in North America, assembled one of the most aggressive and wide-ranging exploration programs of any offshore operator in North America. Positioned for success? Yes, I think so, and I hope I can convince you that that is the case. Picture I have here is the Discoverer Americas. That is one of our two long-term contracted deepwater operated rigs in the Gulf of Mexico. Let me start with a map of North America as a way to give you an overview. On the legend, we have the. I'm sorry.
I knew I was gonna do that. We have the, in magenta, the assets, the exploration assets that I'd like to begin with. The Gulf of Mexico here, deepwater, forms the core of our U.S. portfolio with about 300 exploration leases, gross, and a very large prospect portfolio with long-term drilling plans. We have, in the north, in the Chukchi Sea, off the coast of Alaska, an operated position with 16 operated licenses and a non-op position with ConocoPhillips where we have 50% position and 50 licenses there. I'd like to point out that the Chukchi Sea is shallow water.
Moving on in Canada, we have our position, our main and core position is in the Grand Banks area, where we have licenses in the two main or three main basins there, the Flemish Pass, the Orphan, and the Jeanne d'Arc basins. We recently did, as was referred to by Pål, I think, a deal with Chevron, where we farmed into their position in the Beaufort Sea, giving us a long-term frontier position in the Canadian Arctic. We also entered their license in the Orphan, which will be tested by a well later this year. Just quickly go to the offices. Basically, our exploration offices are in Houston, which is the center of our operations and work in the United States. Anchorage is an operational office-
During the last 10 years, we have also had quite high activity here, and it has added up 150-200 million barrels of oil. Only last year and early this year, we made four new discoveries here, and those are mentioned here on the map in this area, all. When you are thinking about the value then, it's about 100, between 150 and 200 million barrels of those more smaller discoveries. Then we can look to Skrugard Havis, which has between 400 and 600 million barrels. If you just use a simple calculation here and we can think Skrugard Havis, and it's hundreds of %, but then it has a value of NOK 300-400 billion.
You can go here, see 150-200 million. It has a value of about maybe NOK 100 billion-NOK 150 billion. In addition, these barrels, they will also very quick be put into the infrastructure because there are available capacity. It's really high-value barrels to Statoil and to our partners and to the society. Okay, I try to sum up our outlook for 2012-2014. Of course, our aim is to create materiality and value through the NCS exploration. Also thereby, of course, contribute to the production target for Statoil beyond 2020.
To achieve this, it's very important for us to rebalance our activities and portfolio to focus also much more on material growth opportunities, both in traditional but also looking into new plays. In more detail, our strategy includes strong prioritization, clearly defining the top areas in which we want to accelerate activity level. We will focus on growth in proven basins. With proven basins, I mean the North Sea and the Halten-Dønna, where we know that the petroleum system is working. We will accelerate the maturation of prospects here in these established rich provinces for more short-term wins. We have also a strategy not only to drill tie-ins to infrastructure. This means from discovery to it being in production, it should be around 2 years lead time because then we will add value and not erode value.
Of course, it's also important to continue to explore selectively in frontier region. We are taking selective tests in frontier place like the Hoop area, which I have gone through. Of course, it's still very important for us, even with all the successes we have had, to get acreage or get access to new quality acreage. It's really important for us to push on to open up the Barents Sea, the Lofoten, Vesterålen, Tromsø area. We have a guidance that we will
Coming operations offshore Alaska. In Canada, we operate our exploration from Calgary with support in the St. John's. In the 2011 reorganization that was done by Statoil, we streamlined our Gulf of Mexico organization and brought together three teams that were previously working in London, Oslo, and Houston into Houston to make a much more efficient work environment. In Calgary, we have also built the capacity of the Canadian team and roughly double its size over the last 18 months. Logan, Statoil's first, and hopefully not last, operated discovery in the Gulf of Mexico. We have previously announced this discovery with not too much detail.
I will take that a little bit further today and say that we've worked it very hard and can verify that we do have significant oil in place or STOIIP volumes. I would like to go a little bit further than that and give you some more numbers, but I can't at this point in time, but I think we'll be able to do that relatively soon. If we look at the cross-section on the right, which gives you an overview of the discovery, we have our discovery well, we're not really on the crest, but a little bit down the flank into the Paleogene Wilcox formation. The Wilcox is a complicated reservoir in the Gulf of Mexico.
It has as much variability in this type of scale as it does, if we look at the map, on a scale across the basin. It is complicated. We need time to work it, and analyze the data. The data that we have worked, we've done carefully, and that we do see that we have superior oil quality and a very, very good reservoir in our pay zone that are, in fact, some of the best, if not the best, that have been seen in the Gulf of Mexico in the Paleogene to date. This gives us confidence to go ahead and plan and propose a down-dip appraisal well, which we expect to be able to drill in early 2013.
If I look over at the map on the left, just to put this in a little bit of context, you see Logan over here, down in the southeast corner of Walker Ridge protraction area. We have large Paleogene discoveries that are being developed, that we are partners in Jack and St. Malo in the area, and our Julia discovery with Exxon, also in the same area. We have other discoveries, both Paleogene here by Chevron and Neogene discoveries in the near vicinity of Logan. This is a very prolific area, where we have made the Logan discovery and where in the future, or we are actually now drilling the Bioko prospect, also a Paleogene prospect.
What we have here with Logan is significant proven STOIIP and the possibility for volumes together, potentially with our Bioko, if this comes in, to create a hub area for Statoil in the future.
Drill between 60 and 80 wells, both exploration and appraisal wells during this 2-year period. As I also said, we have changed our footprint. We are guiding now around 10% frontier, 50% for growth, and then 40% for the infrastructure-led wells. Thank you. Then I will introduce my good colleague, Erik Finnstrom.
Thank you, Gro. Good afternoon, everybody. North America, last but not least, I hope. I'd like to give you an overview of our North America position and our exploration program that we have for the next two years going forward. We have, in fact, in North America, assembled one of the most aggressive and wide-ranging exploration programs of any offshore operator in North America. Positioned for success? Yes, I think so, and I hope I can convince you that that is the case. Picture I have here is the Discoverer Americas. That is one of our two long-term contracted deepwater operated rigs in the Gulf of Mexico. Let me start with a map of North America as a way to give you an overview. On the legend, we have. I'm sorry.
I knew I was gonna do that. We have the, in magenta, the assets, the exploration assets that I'd like to begin with. The Gulf of Mexico here, deepwater, forms the core of our U.S. portfolio with about 300 exploration leases, gross, and a very large, prospect portfolio with, long-term drilling plans. We have, in the north, in the Chukchi Sea off the coast of Alaska, an operated position with, sixteen operated licenses and a non-op position with ConocoPhillips and where we have 50, position and 50 licenses there. I'd like to point out that the Chukchi Sea is shallow water.
Moving on, in Canada, we have our position, our main and core position is in the Grand Banks area, where we have licenses in the two main or three main basins there, the Flemish Pass, the Orphan, and the Jeanne d'Arc basins. We recently did, as was referred to, by Pål, I think, a deal with Chevron where we farmed into their position in the Beaufort Sea, giving us a long-term frontier position in the Canadian Arctic, and we also entered their license in the Orphan, which will be tested by a well later this year. I'll just quickly go to the offices. Basically, our exploration offices are in Houston, which is the center of our operations and work in the United States. Anchorage is an operational office.
Again, summarizing, we target 2013 for an appraisal of Logan. We also have already kicked off a fast-track development or pre-development project on Logan, working with our development group, where we are using technology, targeted technology for the Wilcox Paleogene reservoirs that is being developed in our research center and has the code name, Crack the Paleogene. This would be a direct application of that research work over the next couple of years on the Logan. Here is a map view of our Gulf of Mexico exploration plans, for the next two-three years or, say, two years. We will, over the next two years, be drilling up a high-graded portfolio of quality impact prospects.
If we again go to the legend, you can see that our wells, the operated wells, are denoted in magenta, partner in yellow, and then the symbols give you the stratigraphic reservoir targets that we will be going after. Now, if you look at this well, you also see the blue are our license positions, our exploration license positions, which I mentioned we have about 300 of. If you look at the pattern that we have here, this forms what we call our Gulf of Mexico focus area. We've worked hard over the last 18 months to focus our work and to define the best areas for exploration in the Gulf of Mexico as we see it.
This has actually allowed us to build a seismic database of depth-imaged 3D data, which is as competitive as any in the Gulf of Mexico, given that we were able to focus our efforts and resources into specific areas. We've also complemented this seismic database by establishing a new in-house depth imaging center. We have capabilities now in-house to do seismic depth imaging on targeted projects. This imaging center has been set up with WesternGeco and is a pilot and prestigious project for WesternGeco and very unique in their portfolio as well. It is personally actually followed up by the president of WesternGeco. Let me just walk you through the wells. We have now currently drilling two operated wells.
We have the Kilchurn well being drilled up here in northeastern Green Canyon. This is a Miocene test. We have also drilling just recently spudded the Bioko well that I just mentioned, which is a Paleogene also impact size prospect. We have also completed in 2012, 2 non-op partner wells, the Heidelberg appraisal and Kakuna. I think that we have talked about the results of these wells previously, but I'll just quickly summarize those. The Heidelberg appraisal was a success in that it has verified the volumes that we thought were there on that particular structure. Anadarko's the operator. They did use our rig, the Discoverer Americas, to drill this. Our coming operations offshore Alaska.
In Canada, we operate our exploration from Calgary with support in the St. John's. In 2011 reorganization that was done by Statoil, we streamlined our Gulf of Mexico organization and brought together three teams that were previously working in London, Oslo, and Houston into Houston to make a much more efficient work environment. In Calgary, we have also built the capacity of the Canadian team and roughly double its size over the last 18 months. Logan, Statoil's first, and hopefully not last, operated discovery in the Gulf of Mexico. We have previously announced this discovery with not too much detail.
I will take that a little bit further today and say that we've worked it very hard and can verify that we do have significant oil in place or STOIIP volumes. I would like to go a little bit further than that and give you some more numbers, but I can't at this point in time, but I think we'll be able to do that relatively soon. If we look at the cross-section on the right, which gives you an overview of the discovery, we have our discovery well, we're not really on the crest, but a little bit down the flank into the Paleogene Wilcox formation. The Wilcox is a complicated reservoir in the Gulf of Mexico.
It has as much variability in this type of scale as it does, if we look at the map, on a scale across the basin. It is complicated. We need time to work it, and analyze the data. The data that we have worked, we've done carefully and that we do see that we have superior oil quality and a very, very good reservoir in our pay zone that are in fact some of the best, if not the best, that have been seen in the Gulf of Mexico in the Paleogene to date. This gives us confidence to go ahead and plan and propose a down dip appraisal well, which we expect to be able to drill in early 2013.
If I look over at the map on the left, just to put this in a little bit of context, you see Logan over here down in the southeast corner of Walker Ridge protraction area. We have large Paleogene discoveries that are being developed that we are partners in Jack and St. Malo in the area, and our Julia discovery with Exxon also in the same area. We have other discoveries, both Paleogene here by Chevron and Neogene discoveries in the near vicinity of Logan. This is a very prolific area where we have made the Logan discovery and where or we are actually now drilling the Bioko prospect, also a Paleogene prospect.
What we have here with Logan is significant proven STOIIP and the possibility for volumes together potentially with our Bioko if this comes in to create a hub area for Statoil in the future. Anadarko is confident enough on Heidelberg that they're probably moving ahead with a development. Kakuna operated by Nexen was unfortunately a dry hole. We have coming up in our program three very exciting and high-volume prospects. We have Candy Bars up here in northern Green Canyon, followed by Coral sort of an outlier of our focus area really outside of our focus area, but still an interesting prospect nevertheless on the Paleogene.
Over in the east, the Demon Star, on a Jurassic-age sandstone, testing the same play that's been very successful for Shell in that same area. In addition to the operated wells that we have coming up, we do have a good, I would say very good non-op program where we have actually done a trade with Marathon between Kilchurn and Innsbrook. We traded some equity between those. Marathon will be operating that well. That's a Miocene test in a very prolific area of discoveries of similar prospects. We are a high equity partner in this prospect here called Hummer Shallow. That's operated by ExxonMobil, and Exxon has that on their drill schedule we understand for late 2012.
Hummer Shallow is a structural closure which is becoming more rare in the Gulf of Mexico these days. We're very anticipating that, and that's its structural closure on the Neogene type of reservoir which has been successful in the same general area with the discoveries I showed you at Lucius and Hadrian. To summarize the program here, we are testing a very strong portfolio of impact prospects the next couple of years. We are actually balanced across all of the type of plays that have been successful in the Gulf of Mexico to date or that are being currently tested. We have the Miocene in Candy Bars. We have the upper Miocene, Neogene, Pliocene play in Hummer Shallow.
We have the Jurassic sandstones in Demon Star, and we have the Paleogene Wilcox in Bioko and Coral. This gives us a very, very nice balance and test of all of the plays going on in the Gulf today. Moving on to Canada, this is a variation of a map I think that was shown earlier looking down from the North Pole, and it gives a nice representation of how Canada and the work we're doing in Canada is tied to the rest of the Arctic efforts in the company. You can see here, and potentially you can see it in the white area yet to find or oil potential as classified by the USGS.
You can see that the Arctic basins and sub-Arctic basins have very high oil potential, as classified by the USGS. We have taken positions in those basins in Canada. You can see them denoted by the stars. The Beaufort Sea, which I mentioned. Again, summarizing, we target 2013 for an appraisal of Logan. We also have already kicked off a fast-track development or pre-development project on Logan, working with our development group, where we are using technology, targeted technology for the Wilcox Paleogene reservoirs that is being developed in our research center and has the code name Crack the Paleogene.
This would be a direct application of that research work over the next couple of years on the Logan. Here is a map view of our Gulf of Mexico exploration plans for the next two to three years or, say, two years. We will, over the next two years, be drilling up a high-graded portfolio of quality impact prospects. If we again go to the legend, you can see that our wells, the operated wells, are denoted in magenta, partners in yellow, and then the symbols give you the stratigraphic reservoir targets that we will be going after. Now, if you look at this well, you also see the blue are our license positions, our exploration license positions, which I mentioned we have about 300 of.
If you know you look at the pattern that we have here, this forms what we call our Gulf of Mexico focus area. We've worked hard over the last 18 months to focus our work and to define the best areas for exploration in the Gulf of Mexico as we see it. This has actually allowed us to build a seismic database of depth-imaged 3D data, which is as competitive as any in the Gulf of Mexico, given that we were able to focus our efforts and resources into specific areas. We've also complemented this seismic database by establishing a new in-house depth imaging center. We have capabilities now in-house to do seismic depth imaging on targeted projects.
This imaging center has been set up with WesternGeco and is a pilot and prestige project for WesternGeco and very unique in their portfolio as well. It is personally actually followed up by the president of WesternGeco. Let me just walk you through the wells. We have currently drilling two operated wells. We have the Kilchurn well being drilled up here in northeastern Green Canyon. This is a Miocene test. We have also drilling just recently spudded the Bioko well that I just mentioned, which is a Paleogene also impact size prospect. We have also completed in 2012 two non-op partner wells, the Heidelberg appraisal and Kakuna.
I think that we have talked about the results of these wells previously, but I'll just quickly summarize those. The Heidelberg appraisal was a success in that it has verified the volumes that we thought were there on that particular structure. Anadarko's the operator. They did use our rig, the Discoverer Americas, to drill this with Chevron. We have been building a significant portfolio in the Grand Banks area focused on the Flemish Pass basin. Our strategy has followed those outlined by both Tim and Pål, early access at scale, getting us into these large prospects with upside potential.
We are working within the Arctic initiative that's been kicked off in the company to take synergies out of the work that's being done in the other basins along the lines of environmental and stakeholder work, technology development and operational experiences. Let me focus a little bit on what I would call our dominant operated position in the Flemish Pass. We have on the left a map showing our position, and basically, well, this is the blue color here denotes our operated position. We operate every licensed piece of land in the basin, so we have complete control of it. We recently won, in the 2011 land sale, these blocks here, together with our partners, Chevron and Repsol.
We've held for some time these blocks over here containing the Mizzen discovery. This one, this block here, I think was won in the 2010 land sale by us. A very, very strong frontier type of position with encouragement. If I move from the map now over to the cross section, we have encouragement from our Mizzen discovery, where we've drilled a discovery well and an appraisal.
The wells on Mizzen, this is very schematic, but they've given us the information to develop what Pål was talking about, and maybe in some more detail in this basin, the sweet spot maps and the understanding of the play, which is represented by this prospect down dip from Mizzen, excuse me, which is actually a prospect out here that we would like to develop for future drilling. We see that we've established both reservoir and source rock, an effective hydrocarbon system in this basin, and we see that other areas away from Mizzen could have even better developments.
If I return to the map, what you see is Mizzen here, and then we have our next well, Harpoon, scheduled for spud at the end of 2012. Harpoon is an impact size prospect. We own 65, currently 65% of that license. We have follow-up potential of. In fact, all of these prospects are impact size, and all of them are structural closures. This is a really very unique position for us and for any company in the world to have large impact size structural closures in a basin that has a proven hydrocarbon system. To test this portfolio, we have contracted a rig, the West Aquarius, and Anadarko is confident enough on Heidelberg that they're probably be moving ahead with a development.
Kakuna, operated by Nexen, was unfortunately a dry hole. We have coming up in our program, three very, exciting and high volume prospects. We have Candy Bars up here in Northern Green Canyon, followed by Coral, sort of an outlier of our focus area, really outside of our focus area, but, still an interesting, prospect nevertheless, on the Paleogene. Over in the east, the Demon Star, on a Jurassic Age, sandstone, testing the same play that's been very successful for Shell in that same area. In addition to the operated, wells that we have coming up, we do have a good, I would say very good non-op program, where we have actually done a trade with, Marathon between, Kilchurn and Innsbrook. We traded some equity between those.
Marathon will be operating that well. That's a Miocene test in a very prolific area of discoveries of similar prospects. We are a high equity partner in this prospect here called Hummer Shallow. That's operated by ExxonMobil, and Exxon has that on their drill schedule, we understand, for late 2012. Hummer Shallow is a structural closure, which is becoming more rare in the Gulf of Mexico these days. We're very anticipating that. That's a structural closure on the Neogene type of reservoir, which has been successful in the same general area with the discoveries I showed you at Lucius and Hadrian. To summarize the program here, we are testing a very strong portfolio of impact prospects the next couple of years.
We are actually balanced across all of the type of plays that have been successful in the Gulf of Mexico to date, or that are being currently tested. We have the Miocene in Candy Bars. We have the upper Miocene, Neogene, Pliocene play in Hummer Shallow. We have the Jurassic sandstones in Demon Star, and we have the Paleogene Wilcox in Vioco and Coral. This gives us a very, very nice balance and test of all of the plays going on in the Gulf today. Moving on to Canada. This is a variation of a map I think that was shown earlier, looking down from the North Pole, and it gives a nice representation of how Canada and the work we're doing in Canada is tied to the rest of the Arctic efforts in the company.
You can see it in the white areas, our yet-to-find oil potential as classified by the USGS. You can see that the Arctic basins and sub-Arctic basins have very high oil potential as classified by the USGS. We have taken positions in those basins in Canada. You can see them denoted by the stars. The Beaufort Sea, which I mentioned, where we have three slots that'll be kicking off with the Harpoon well in late 2012. Moving on from Canada and to Alaska. You can see that Alaska is yet another component of our Arctic buildup. We have an operated position here in these in a set of blue blocks.
These blocks are actually the same size as the Gulf of Mexico blocks. You could hope that maybe they would be a little bit bigger in the Arctic, but they are the same and are actually operated under the same sort of rules and regulations. We have a shot at a 3D program around these blocks and actually acquired very high-quality 3D data there. We have developed a prospect, Amundsen, here, which we are maturing towards drilling, and we're targeting drilling of Amundsen in 2014. We have not yet taken the decision on that as a final decision. We also have a very interesting position to the south. This is a set of licenses operated by ConocoPhillips, where we have 25% in each of those 50 licenses.
They also have shot a 3D of good quality and developed an elephant-sized prospect called Devil's Paw. Devil's Paw is also scheduled to be drilled in 2014. Let me just also mention that you can see on the map a number of other wells. These were wells drilled mainly by Shell in the late 1980s and early 1990s. Especially this well, Burger, here is a well that gives encouragement in this basin in that it proved gas. It proved potentially a very large accumulation of gas. What we hope for ourselves is oil, and we have put together the data and the evidence that do point to that our prospect up here could be a very good oil prospect.
The same thing at this one, Devil's Paw. Shell will actually be kicking off their exploration program on Burger, drilling an appraisal well on this year. That will be a very interesting test for us to follow along. We again have not made the final decision on our drilling, but if we move ahead, we'll be kicking off our permitting campaign in a few months and beginning to do the heavy preparations that we know have to be done in this environmentally sensitive area. It is thus important for us to work with the other operators in an environment like this, and we are. We're working with both ConocoPhillips and Shell on developing drilling logistics and oil spill response systems for this Arctic basin. Summary. To
We are executing a very aggressive program, I mean, with Chevron. We have been building a significant portfolio in the Grand Banks area focused on the Flemish Pass Basin. Our strategy has followed those outlined by both Tim and Pål, early access at scale, getting us into these large prospects with upside potential. We are working within the Arctic initiative that's been kicked off in the company to take synergies out of the work that's being done in the other basins along the lines of environmental and stakeholder work, technology development, and operational experiences. Let me focus a little bit on what I would call our dominant operated position in the Flemish Pass.
We have, on the left, a map showing our position, and basically, this is the blue color here denotes our operated position. We operate every licensed piece of land in the basin, so we have complete control of it. We recently won in the 2011 land sale, these blocks here, together with our partners, Chevron and Repsol. We've held, for some time, these blocks over here, containing the Mizzen discovery. This one, this block here, I think, was won in the 2010 land sale by us. A very strong frontier type of position with encouragement.
If I move from the map now over to the cross-section, we have encouragement from our Mizzen discovery, where we've drilled a discovery well and an appraisal. The wells on Mizzen, this is very schematic, but they've given us the information to develop what Pål was talking about and maybe in some more detail in this basin, the sweet spot maps and the understanding of the play, which is represented by this prospect down dip from Mizzen, excuse me, which is actually a prospect out here that we would like to develop for future drilling. We see that we have the. We've established both reservoir and source rock, an effective hydrocarbon system in this basin, and we see that other areas away from Mizzen could have even better developments.
If I return to the map, what you see is Mizzen here, and then we have our next well, Harpoon, scheduled for spud at the end of 2012. Harpoon is an impact size prospect. We own 65%, currently 65% of that license. Then we have follow-up potential of. In fact, all of these prospects are impact size, and all of them are structural closures. This is a really very unique position for us and for any company in the world to have large impact size structural closures in a basin that has a proven hydrocarbon system. To test this portfolio, we have contracted a rig, the West Aquarius, couple of years in North America.
If you look at the keywords for Gulf of Mexico here, streamlined, quality seismic database, proprietary imaging, drilling capacity. We've set ourselves up. That's the title of the talk. We've set ourselves up for success. We hope we will get it. Grand Banks, keywords, dominant operated position, and we will be drilling some of these impact prospects. They're on our drill schedule. We have capacity. In the Chukchi in Alaska, we're moving forward, and maturing the prospect for drilling that, the Amundsen prospect. Again, to summarize, we've built an operating capability, a very strong prospect 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 couple of years.
This is an effort we intend to sustain over time as North America steps into the title of core area for Statoil. Thanks.
Thank you, Erik. We are now ready for the second Q&A session, and Tim, Gro, and Erik will answer questions related to their presentations. Should there be any questions relating to Arctic exploration, we also have Rúni M. Hansen here, who's the head of Arctic exploration, who can answer those questions. Should there be questions on technology, as Erling Vågnes unfortunately got sick and couldn't attend, the panel will also answer questions related to his presentation. We'll start out taking questions from the audience here in Oslo. Yes.
Hi, it's Anders Holter from ABG Sundal Collier. It's just a few questions for Gro. On the Johan Sverdrup discovery, Lundin, they made an unsuccessful appraisal south of the discovery. I see that on the Det norske's plan, they plan to drill a well in 502. Is that something I mean, considering that the appraisal that Lundin drilled showed water, is that something you will be taking a part in? Or you know, how do you view that well in terms of it being oil-filled or do you perceive that as being water-filled aspect of appraisal? Second one is if you can just reiterate those numbers from Gullfaks about how many barrels found and also the value for those barrels. Thank you.
First, on Johan Sverdrup, as I understand your question, you're asking about if you're going to drill a well in 502 this year, and we are discussing the opportunities there. We haven't finalized yet the evaluation of the prospectivity there. We are still discussing at least where we should drill it, so I cannot be specific, more specific on that. We are working on it and looking upon the potential there. Evaluation of Gullfaks. The evaluation of Gullfaks, I was just thinking about, it's done in a-
Where we have three slots that'll be kicking off with the Harpoon well in Q2, late 2012. Moving on from Ala, from Canada and to Alaska, you can see that Alaska is yet another component of our Arctic buildup. We have an operated position here in a set of blue blocks. These blocks are actually the same size as the Gulf of Mexico blocks. You could hope that maybe they would be a little bit bigger in the Arctic, but they are the same and are actually operated under the same sort of rules and regulations. We have a shot at a 3D program around these blocks and actually acquired very high-quality 3D data there.
We have developed a prospect, Amundsen, here, which we are maturing towards drilling, and we're targeting drilling of Amundsen in 2014, but we have not yet taken the decision on that as a final decision. We also have a very interesting position to the south. This is a set of licenses operated by ConocoPhillips, where we have 25% in each of those 50 licenses. Excuse me. Now, they also have shot a 3D of good quality and developed an elephant-sized prospect called Devil's Paw. Devil's Paw is also scheduled to be drilled in 2014. Let me just also mention that you can see on the map a number of other wells. These were wells drilled mainly by Shell in the late 1980s and early 1990s.
Especially this well Burger here is a well that gives encouragement in this basin in that it proved gas, potentially a very large accumulation of gas. What we hope for ourselves is oil, and we have put together the data and the evidence that do point to that our prospect up here could be a very good oil prospect. The same thing at this one, Devil's Paw. Shell will actually be kicking off their exploration program on Burger, drilling an appraisal well on this this year. That will be a very interesting test for us to follow along.
We have not made the final decision on our drilling, but if we move ahead, we'll be kicking off our permitting campaign in a few months and beginning to do the heavy preparations that we know have to be done in this environmentally sensitive area. It is thus important for us to work with the other operators in an environment like this, and we are. We're working with both ConocoPhillips and Shell on developing drilling logistics and oil spill response systems for this Arctic basin. Summary. We are executing a very aggressive program-
Simple way. I just used the number of barrels, and I think I used an oil price of 6 USD or 6 kroner per dollar. I just calculated up compared to the Skrugard Havis, and I just used the same principle on those 150-200 million barrels in Gullfaks area. It was 100% to note it, and it's not including the CapEx or the costs. It's more as a Revenues. Sorry.
Yeah, it's revenue.
Yeah. Mm-hmm.
Yes, Teodor?
Thank you. Just first one on King Lear. The well has been drilling for quite a while now. Could you please give some indication of when we can expect a result? Second one is on EM. You have previously communicated that EM data was crucial when discovered both Skrugard and Havis. Could you give some color on which prospects you applied EM on now and how you will apply EM going forward?
Yeah, when it comes to King Lear, we are drilling on that still, and I think we will come back early summer with the result on that well. That's what I can say on that well. When it comes to EM data and how we use that in the Barents Sea, I can say that the EM data is quite what to say, excellent data set to use in that area. For us, it's really important also to integrate those data with all the other data, also the geophysical data. Because you have to put all data together, and then with the geological knowledge that we have, it's very important to use this as a combined data evaluation.
From this combined data evaluation, we can draw the consequences and see the potential. We don't use EM data alone, but we use it together with all the other geological and geophysical data to come up with the result of our evaluation.
Another question, please.
Hi there. It's Mark Coughlan from Macquarie again. Just two quick questions. I was hoping you could remind me again on that minimum commercial threshold at King Lear. Just secondly, if we think about an overall CapEx in exploration this year of $3 billion, just the allocation of that within the NCS and North America, that'd be great. Thanks.
Yeah. I think when it comes to King Lear and this, I think I will come back to that and when it comes to the break, yeah. I'll come back to that, check that out. The other question?
Just on the CapEx, was it?
Yeah, just the split.
On the CapEx for King Lear?
No, no, just.
On the split between Norway and the rest of the portfolio.
Okay, on the split.
I think, it's a little bit difficult to, I don't have the exact numbers, but I guess somewhere close to half the wells, you know?
Yeah. We spend around one third of the exploration spend in the Norwegian Continental Shelf and the rest in the rest of the world.
Okay. Did you hear that on the website? About one third in Norway.
Yeah
on the exploration wells, then two thirds otherwise. As I said, that's about 60% of our spend. I think seismic and, you know, the other costs are relatively the same as well. Yeah.
Yeah.
Somewhere between 1/3 and 40% I would think.
Of the well costs are used in Norway.
Yeah.
Mm-hmm.
We have another question over here from Trond.
Yeah. Trond Omdal, Arctic Securities. It hasn't been that focused today, but could you say a little bit. There has been some reports that you might also have farmed into other shale opportunities. Could you talk a little bit of where you see, do you see any potential in both more shale opportunities both in the U.S. and even in Canada? The second question on Aldous or previously called Aldous. You still consider Aldous North a high impact well after the first disappointment?
I can, we are talking about Gjeitungen. I will not confirm any volumes, but it has an interesting potential. That's what I can say.
On the shale stuff, Trond, not quite sure what you're alluding to, but I guess my statement is we haven't farmed in until we have, and we'll announce that at the appropriate time. We are continuing to consider further probably more immature shale opportunities in the U.S., but also globally, select opportunities there. In that case, we've run a similar process. We have a number of basins or countries which we prioritize, and in fact, it's Pål's group who's actually done all that subsurface work. We've done it in the same way for the unconventional hydrocarbons as we've done with the conventional.
We've chosen a few areas, and it's not anywhere close to 18, where we are considering entering into what I would call exploration unconventional opportunities. That, but more than that, I can't confirm at this point in time.
You used to comment on two areas you previously were early in China and then Argentina as well, of course, given the nationalization has increased the risk. Do you have a couple of comments on these two areas as well?
Yeah.
Just to follow up, China, of course, you were an early entrant, but then, due to some political issues seem to maybe have stopped up there. The other area, Argentina, where there is a lot of focus among some of the majors and of course due to the YPF nationalization may have increased the risk. Do you see any opportunities in those two geographies?
Okay. I'll try and keep this short, and I don't know how sweet it will be, but.
Couple of years in North America. We, if you look at the keywords for Gulf of Mexico here, streamlined, quality seismic database, proprietary imaging, drilling capacity. We've set ourselves up. That's the title of the talk. We've set ourselves up for success. We hope we will get it. Grand Banks, keywords, dominant operated position, and we will be drilling some of these impact prospects. They're on our drill schedule, we have capacity. In the Chukchi in Alaska, we're moving forward, and maturing the prospect for drilling the Amundsen prospect. Again, to summarize, we've built an operating capability, a very strong prospect 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 couple of years.
This is an effort we intend to sustain over time as North America steps into the title of core area for Statoil. Thanks.
Thank you, Erik. We are now ready for the second Q&A session, and Tim, Gro, and Erik will answer questions related to their presentations. Should there be any questions relating to Arctic exploration, we also have Rúni M. Hansen here, who's the head of Arctic exploration, who can answer those questions. Should there be questions on technology, as Erling Vågnes unfortunately got sick and couldn't attend, the panel will also answer questions related to his presentation. We'll start out taking questions from the audience here in Oslo and yes.
Hi, it's Anders Holte from ABG Sundal Collier. It's just a few questions for Gro. On the Johan Sverdrup discovery, Lundin they made an unsuccessful appraisal south of the discovery. I see that on the Det norske's plan, they plan to drill a well in 502. Is that something, I mean, considering that the appraisal that Lundin drilled showed water, is that something you will take part in? Or, you know, how do you view that well in terms of it being oil field, or do you perceive that as being water-filled as with the appraisal? Second one is if you could just reiterate those numbers from Gullfaks about how many barrels found and also the value for those barrels. Thank you.
Yeah, first, on Johan Sverdrup, as I understand your question, you're asking about if you're going to drill a well in 502 this year, and we are discussing the opportunities there. We haven't finalized yet the evaluation of the prospectivity there. We are still discussing at least where we should drill it. I cannot be specific, more specific on that, but we are working on it and looking upon the potential there. Can you just, yeah, evaluation of Gullfaks? Yeah. I just, the evaluation of Gullfaks, I was just thinking about, it's done in a-
Anyway, I think the situation in China is unchanged, status quo. When it comes to Argentina, well, I'll let you speculate as to whether Argentina is one of our prioritized basins or not. The fact that a lot of other companies going there might give you a good indication.
I can see, yes, I see one more question in Oslo.
Tom Eric Kristiansen, Pareto.
Mm-hmm.
To Gro, I see you plan to drill 8-10 exploration wells in the Greater Utsira High over the next three years. Could you maybe tell a bit more about those prospects? Have you found anyone that are high impact potential or
Yeah.
Is it smaller prospects?
I can tell you because I think there are some interesting prospects both in the licenses we held as an operator, but also in the partner licenses. There is absolutely a potential for impact prospects in those licenses. We will come back to it when we are more clear and when we have fully evaluated the area. We see absolutely a potential for some interesting prospects to be drilled in that area. Of course, based on the history here, it's not that easy either to map and to interpret, so you have to use some time. We are now doing this, improving all the seismic data for imaging and also trying to use different kind of acquisition methods.
We will use the time and really think through and understand also better, what should I say, the whole migration history in that area, so before we take any final decision.
All right, we'll then turn to our audio conference audience. The first question comes from Peter Hutton with RBC. Please go ahead, Peter.
You either need to speak or speak up.
Are you there, Peter?
Yeah, sorry. Good afternoon. Sorry, I was slightly late there. Two questions for Erik, if I may. You mentioned in your presentation that you'd like to be able to give more information on the figures on Logan.
Just given that you are the operator, what's the holdup there? Why aren't you able to provide that? The second one is on the Chukchi. You were saying that sort of target 2014 as you move towards the season. Is it fair to say that one of the key factors in that decision-making process is likely to be sort of contingent on the approvals for Shell as one of the other operators and seeing how that goes? On that basis, what's your reading of how that's progressing at the moment?
Yes. On Logan, I just have to apologize really that I didn't run the traps before this presentation, that we haven't run it through our partners. We will be able to say something more about Logan pretty quickly, and we'll be having another presentation in the United States in about three weeks, where we most certainly give a more specific number on Logan.
A simple way. I just used the number of barrels. I think I used an oil price of $6 or US dollar at 6 NOK per dollar. I just calculated up compared to the Skrugard, Havis, and I just used the same principle on those 150-200 million barrels in Gullfaks area. It was 100% to total. It's not including the CapEx or the costs. It's more as revenues. Sorry.
Yeah, it's revenue.
Yeah. Mm-hmm.
Yes, Teodor?
Thank you. Just first one on King Lear. The well has been drilling for quite a while now. Could you please give some indication of when we can expect a result? Second one is on EM. You have previously communicated that the EM data was crucial when you discovered both Skrugard and Havis. Could you give some color on which prospects you applied EM on now and how you will apply EM going forward?
Yeah, when it comes to King Lear, we are drilling on that still, and I think we will come back early summer with the result on that well. That's what I can say on that well. When it comes to EM data and how we use that in the Barents Sea, I can say that the EM data is quite, what should I say, excellent data set to use in that area. It's really important also to integrate those data with all the other data, also the geophysical data. Because you have to put all data together, and then, with the geological knowledge that we have, it's very important to use this as a combined data evaluation.
From this combined data evaluation, we can draw the consequences and see the potential. We don't use EM data alone, but we use it together with all the other geological and geophysical data to come up with the result of our evaluation.
Another question, please.
Hi there. It's Mark Coughlan from Macquarie again. Just two quick questions. I was hoping you could remind me again on that minimum commercial threshold at King Lear. Just secondly, just if we think about an overall CapEx in exploration this year of $3 billion, just the allocation of that within the NCS and North America, that'd be great. Thanks.
Yeah. I think when it comes to King Lear and this, I think I will come back to that and when it comes to the break. Yeah. I will come back to that and check that out. The other question?
It was on the CapEx, was it?
Yeah, just the split.
On the CapEx for King Lear?
No, no, just.
I apologize for that. On the Chukchi-
No.
Yeah. The Chukchi, yes, 2014. We'll certainly be watching what happens to Shell very closely. We will be running our own process independent of that, but clearly it does give us information in terms of how long it takes to get permits, what are the issues, in terms of also, potential lawsuits, such things. We'll be watching what happens with Shell.
Okay, thank you.
Our next question comes from Nick Coleman with Argus Media. Please go ahead, Nick.
Hi, thank you. Question about Lofoten Vesterålen, if I've got the pronunciation right, the closed areas offshore Norway. How confident are you that that is gonna be fully opened up for the industry? I think you've got a general election coming up fairly soon in Norway. Do you have a feeling, are you optimistic about the opportunities there opening up for you?
Okay. I'll again, short but not necessarily sweet. I think it's not a question about if, it's more a question about when. I think that's about as much as we can say. As you know, the Norwegian Petroleum Directorate have acquired new seismic in both areas. That's been made available for the industry. We have to assume they've done that with a purpose, and that these areas will be opened up. Or parts of these areas will be opened up for exploration, further exploration activity, i.e. drilling at some stage in the not too distant future.
Okay, thanks.
Thank you. I can't see any more questions on my list. Is that correct, operator? Are there no more questions from the audio conference?
We have a question from Teodor Sveen-Nilsen from Swedbank.
Please go ahead, Teodor Sveen-Nilsen.
It was two questions, actually. The first is going back to the Rosneft deal. We've seen a number of offshore deals in the last month or so with Eni, with Exxon, and now with Statoil. Just as background, was the acreage offered done on a sort of set menu basis, or was it sort of à la carte? Could you sort of pick and choose the areas, discuss what you'd like to explore? Just following on from that, the one block you've got up in the Barents, is there any sort of read across from your existing knowledge in the Norwegian side? Just secondly, just a question on clarification. There was lots of talk in the last presentation about impact prospects. Could you just maybe define, is that different?
Is it a lower number from high impact? A little bit confused there. Thank you.
Okay. Let me start out on the Rosneft issue, and then Eric can follow up on the impact question. On the Rosneft, a little bit of both, if you like, on the split between Norway and the rest of the portfolio.
Okay. On the split.
I think it's a little bit difficult. I don't have the exact numbers, but I guess somewhere close to half the wells, Hilde, you know?
Yeah. Spent around one third of the exploration spend in terms of Norwegian Continental Shelf, and the rest in the rest of the world.
Yeah.
Okay. Did you hear that on the website? About one-third in Norway.
Yeah.
On the exploration wells, and then two-thirds otherwise. As I said, that's about 60% of our spend. I think seismic and, you know, the other costs are relatively the same as well. Yeah.
Yeah.
Somewhere between one-third and 40% of it all.
Half of the well costs are used in Norway.
Yeah.
We have another question over here from Trond.
It hasn't been that focused today, but could you say a little bit. There has been some reports that you might also have farmed into other shale opportunities. Could you talk a little bit. Do you see any potential in more shale opportunities in the U.S. and even in Canada? The second question on Aldous or previously called Aldous. You still consider the Aldous North a high impact well after the first disappointment?
I can, then we are talking about Gjeitungen. I will not confirm any volumes, but it has an interesting potential. That's what I can say.
On the shale stuff, Trond, not quite sure what you're alluding to, but I guess my statement is we haven't farmed in until we have, and we'll announce that at the appropriate time. We continue to consider further probably more immature shale opportunities in the US, but also globally, select opportunities there. In that case, we've run a similar process. We have a number of basins or countries which we prioritize, and in fact it's Pål's group who's actually done all that subsurface work. We've done it in the same way for the unconventional hydrocarbons as we've done with the conventional.
We've chosen a few areas, and it's not anywhere close to 18, where we are considering entering into what I would call exploration unconventional opportunities. That, but more than that, I can't confirm at this point in time.
Can you just comment on two areas you previously were early in China and then Argentina? I see of course, given the nationalization has increased risk. Do you have a couple of comments on these two areas as well?
Yes.
Just to follow up, China of course you were an early entrant, but then due to some political issues seem to maybe have stopped up there. The other area, Argentina, where there is a lot of focus among some of the majors and of course due to the YPF nationalization may have increased the risk. Do you see any opportunities in those two geographies?
Okay. I'll try and keep this short and I don't know how sweet it will be. When we got to the negotiation table, we were presented with a greater number of opportunities than we picked. It wasn't a question that, you know, it wasn't a set menu, but it wasn't necessarily à la carte either. I think the way we like to look at this is that we are the third of three very large companies to do very large, significant strategic deals with Rosneft in Russia. We're very pleased to be one of those three. We're satisfied with the acreage which we've got.
In terms of sort of the bleed across, I'm not quite sure what you're alluding to up in the Northern Barents Sea, but you know, this is rank frontier acreage. The more north you go in the Barents Sea, both the Norwegian part and the Russian part, the less data there is. It is a fact that there is only one seismic line through the block which we've acquired up in the north, and none that I'm aware of on the Norwegian side. Of course, you know, we have used our regional understanding of the Barents Sea, both the Norwegian and the Russian, in order to have some kind of view on this acreage.
I think, you know, contrary maybe to common perception, then all of the three Rosneft licenses in the central Barents Sea, which were part of the previous disputed zone, have to be considered to be rank frontier, high risk opportunities with a very uncertain oil and gas potential. That has to do with the amount of data available, which is very, very limited, and limited to 2D seismic. On the impact question, leave that to Erik.
Yeah. Again, apologize, that's kind of a language gap developing across continents, I guess. It's exactly the same thing, impact and high impact. I didn't mean to imply anything different than the definition that was shown by Tim or Pål in the beginning.
Okay, that's great. Very clear. Thank you.
Thank you. I can't see any further questions, so, this will conclude our Q&A session and our event for today. The presentations and the Q&A sessions can be replayed from our website. If you have any further questions, please don't hesitate to contact us in the investor relations department. Thank you all very much for participating today, and have a good day.
Anyway, I think the situation in China is unchanged by status quo. When it comes to Argentina, well, I'll let you speculate as to whether Argentina is one of our prioritized basins or not. The fact that a lot of other companies going there might give you a good indication.
I can't see. Yes, I see one more question in Oslo.
Tom Erik Kristiansen, Pareto. I have to go. I see you plan to drill 8-12 exploration wells in the greater Utsira High over the next three years. Could you maybe tell a bit more about those prospects? Have you found anyone that are high impact potential or
Yeah, I can.
Is it smaller prospects?
I can tell you because I think there are some interesting prospects both in the licenses we hold as an operator, but also in the partner licenses. There is absolutely a potential for impact prospects in those licenses. We'll come back to it when we are more clear and when we have fully evaluated the area. We see absolutely a potential for some interesting prospect to be drilled in that area. Of course, based on the history here, it's not that easy either to map and to interpret. You have to use some time, and we are now doing this, improving all the seismic data for imaging and also trying to use different kind of acquisition methods.
We will use the time and really think through and understand also better, what should I say, the whole migration history in that area, so before we take any final decision.
All right. We'll then turn to our audio conference audience. The first question comes from Peter Hutton with RBC. Please go ahead, Peter.
You need to speak or speak up.
Are you there, Peter?
Yeah, sorry. Good afternoon. Sorry for the slightly late there. Two questions for Erik, if I may. You mentioned in your presentation that you'd like to be able to give more information on the figures on Logan. Just given that you're the operator, what's the hold up there? Why aren't you able to provide that? And the second one is on the Chukchi. You were saying this was a target 2014. As you move towards decision, is it fair to say that one of the key factors in that decision-making process is likely to be sort of contingent on the approvals for Shell as one of the other operators and seeing how that goes? And on that basis, what's your reading of how that's progressing at the moment?
Yes. On Logan, I just have to apologize really that I didn't run the traps before this presentation that we haven't run it through our partners. We'll be able to say something more about Logan pretty quickly, and we'll be having another presentation in the United States in about three weeks, where we most certainly give a more specific number on Logan.
Okay.
I do, I apologize for that. On the Chukchi-
No worries.
The Chukchi, yes, 2014, we'll certainly be watching what happens to Shell very closely. We will be running our own process independent of that, but clearly it does give us information in terms of how long it takes to get permits, what are the issues, in terms of also potential lawsuits, such things. We'll be watching what happens with Shell.
Okay, thank you.
Our next question comes from Nick Coleman with Argus Media. Please go ahead, Nick.
Hi, thank you. Question about Lofoten Vesterålen. If I've got the pronunciation right, the closed areas offshore Norway. How confident are you that that is gonna be fully opened up for the industry? I think you've got a general election coming up fairly soon in Norway. Do you have a feeling? Are you optimistic about the opportunities there opening up for you?
Okay. I'll again short, but not necessarily sweet. I think it's not a question about if, it's more a question about when. I think that's about as much as we can say. As you know, then, the Norwegian Petroleum Directorate have acquired new seismic in both areas. That's been made available for the industry. We have to assume they've done that with a purpose, and that these areas will be opened up. Parts of these areas will be opened up for exploration, further exploration activity, i.e., drilling, at some stage in not too distant future.
Okay, thanks.
Thank you. I can't see any more questions on my list. Is that correct, operator? Are there no more questions from the audio conference?
We have a question from Teodor Sveen-Nilsen from Berenberg.
Please go ahead, Teodor Sveen-Nilsen.
Yeah. It was two questions, actually. The first is going back to the Rosneft deal. We see a number of offshore deals in the last month or so with Eni, with Exxon, and now with Statoil. Just as background, was the acreage offered done on a sort of set menu basis, or was it sort of à la carte? Could you sort of pick and choose the areas, discuss what you'd like to explore? Just following on from that, the one block you've got up in the Barents, is there any sort of read across from your existing knowledge on the Norwegian side? Then just secondly, just a question on clarification. There was a lot of talk in the last presentation about impact prospects.
Could you just maybe define, is that different? Is it a lower number from high impact? A little bit confused there. Thank you.
Okay. Let me start out on the Rosneft issue, and then Eric can follow up on the impact question. On the Rosneft, a little bit of both, if you like. When we got to the negotiation table, we were presented with a greater number of opportunities than we picked. It wasn't a set menu, but it wasn't necessarily à la carte either. I think the way we like to look at this is that we are the third of three very large companies to do very large, significant strategic deals with Rosneft in Russia. We're very pleased to be one of those three.
We're satisfied with the acreage which we've got. In terms of sort of the bleed across, I'm not quite sure what you're alluding to up in the northern Barents Sea, but you know, this is rank frontier acreage. The more north you go in the Barents Sea, both the Norwegian part and the Russian part, the less data there is. It is a fact that there is only one seismic line through the block, which we've acquired up in the north, and none that I'm aware of on the Norwegian side.
Of course, you know, we have used our regional understanding of the Barents Sea, both the Norwegian and the Russian, in order to have some kind of view on this acreage. I think, you know, contrary maybe to common perception, then all of the three Rosneft licenses in the central Barents Sea, which were part of the previous disputed zone, have to be considered to be rank frontier, high risk opportunities with a very uncertain oil and gas potential. That has to do with the amount of data available, which is very, very limited and limited to 2D seismic. Then on the impact question, I'll leave that to Eric.
Yeah. Again, I apologize, that's kind of a language gap developing across continents. I guess, it's exactly the same thing, impact and high impact. I didn't mean to imply anything different than the definition that was shown by Tim or Pål in the beginning.
Okay, that's great. Very clear. Thank you.
Thank you. I can't see any further questions. This will conclude our Q&A session and our event for today. The presentations and the Q&A sessions can be replayed from our website. If you have any further questions, please don't hesitate to contact us in the investor relations department. Thank you all very much for participating today, and have a good day.