Hilde Merete Nafstad - Senior Vice President of Investor Relations Torgrim Reitan - Chief Financial Officer, Executive Vice President, Chairman of Corporate Risk Committee and Member of Corporate Executive Committee Svein Skeie - Senior Vice President for Performance Management and Analysis Torstein Hole Kåre Thomsen - Former Chief Financial Officer

Lars-Henrik Roren - SEB Enskilda, Research Division Trond Frode Omdal - Arctic Securities ASA, Research Division Haythem Rashed - Morgan Stanley, Research Division Nitin Sharma - JP Morgan Chase & Co, Research Division Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division Peter Hutton - RBC Capital Markets, LLC, Research Division Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division Guy A. Baber - Simmons & Company International, Research Division Michael J. Alsford - Citigroup Inc, Research Division Michele della Vigna - Goldman Sachs Group Inc., Research Division Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division John A. Schj. Olaisen - Carnegie Investment Bank AB, Research Division Matthew Yates - BofA Merrill Lynch, Research Division Irene Himona - Societe Generale Cross Asset Research Teodor Sveen Nilsen - First Securities AS, Research Division Jon Rigby - UBS Investment Bank, Research Division Kim Fustier - Crédit Suisse AG, Research Division Brendan Warn - Jefferies & Company, Inc., Research Division

Ladies and gentlemen, welcome to Statoil's Third Quarter Earnings Presentation, both to the audience here in Oslo and to our audience -- and webcast audiences. My name is Hilde Nafstad, and I'm the Head of Statoil's Investor Relations group. This morning at 7:30 Central European Time, Statoil announced the results for the third quarter of 2012. The press release and presentations for today's event were distributed through the wires and through Oslo Stock Exchange. The quarterly report and the presentations can, as usual, be downloaded from our website, statoil.com. I would kindly ask you to make special note of the information regarding forward-looking statements, which can be found on the last page. Today's program will start with Statoil's CEO (sic) [CFO], Torgrim Reitan, going through the earnings and the outlook for the company. As usual, the presentations will be followed by a Q&A session. Please note that questions can be posted by means of telephone, but not directly from the web. The dial-in numbers for posting questions can be found on our website. It is now my privilege to introduce Statoil's Chief Financial Officer, Torgrim Reitan.

Thank you, Hilde, and good afternoon to all of you here in our new offices at Fornebu. And good morning, and good afternoon to those of you following us on the webcast. It is a pleasure to present our results for the third quarter this year, and once again, we present solid financial results and operational performance. We are delivering a 10% higher year-on-year production on the same period as last year and an 8% production growth if you compare it to the full 2011. We continue to add barrels from discoveries and increased recovery, and we sharpened our portfolio through value-creating transactions. On Monday, we signed an asset deal with Wintershall, exiting our operated Brage oilfield and farming down in Gjoa and Vega. We realized $1.45 billion in cash from non-core assets. And then we added 15% in Edvard Grieg, that was previously known as Luno, and that is adding growth assets close to Johan Sverdrup, which is a key asset. And the transaction demonstrates the underlying value of our NCS portfolio. Johan Sverdrup is one of the largest well-developed oilfields in the world, and it is one of our key assets for the future. And we now have secured working interest in all discoveries on the Utsira High, Johan Sverdrup, Ivar Rosin [ph], Dagny and Edvard Grieg. And as the largest player in that area, we take these positions to drive the development and capture additional potential in that area. So we do this to revitalize the Norwegian continental shelf, and we continue to create value through the management of our portfolio and to sharpen our portfolio further. We have added substantial new volumes from the Geitungen prospect, which is part of the ongoing appraisal program and development activity on the giant Johan Sverdrup. We will come back…

Thank you very much, Torgrim. We'll turn to the Q&A session, and for this session, Torgrim will be joined by Senior Vice President for Accounting and Financial Compliance, Kåre Thomsen; and Senior Vice President for Performance Management, Svein Skeie. We will take questions from the audience and over the telephone. I will first ask the operator to explain the procedure for asking questions over the telephone. Operator, please.

[Operator Instructions]

And then we'll start with questions from the audience here in Oslo first. So please push the button on your microphone if you would like to post a question. Yes, Alma [ph]?

I hoped you could give some comments about the renegotiation of gas contracts because I think it was last year or the beginning of this year was the comment that 50% -- I assume 50% of volumes is up for renegotiations. I assume you can't tell much, but how much is remaining when it comes to renegotiation now?

Thank you, Alma [ph] . Let me start with what's going on. And you're right, we are renegotiating our contracts and modernizing our gas contract portfolio, which is about taking back flexibility and changing the construction of some of those contracts. So that work is actually going well. We have concluded some half, 50% of the contracts. They have been renegotiated. And I think I'd have to say that we are well satisfied with the results. So quite a bit of the new contract regime is reflected in our gas price that we report today. And as you see, it's a healthy gas price. And it also enables us to use the flexibility in the portfolio that we have, Troll, Wusabari [ph] the transportation facilities and all the learning points and so on. So we are able to create value on that flexibility.

Next question, please.

Lars from SEB Enskilda. It relates to your 2013 guidance. It is what you say that the production will be lower than 2012. Can you explain -- or can you tell -- have you excluded the Wintershall-related volumes from 1st of January or actually from the second half of 2013? Of course, you have said that the transaction will take place due to regulatory work from second half. So from when have you excluded the 35,000 to 40,000 barrels a day?

So, I mean, when -- that transaction will have an effective date of 1st of January. So there will be earnings impact from the 1st of January. The way it will be -- have an economic impact from the effective dates. So the way this works is that when everything is closed, you have a settlement in cash for that period and so on and you count barrels until you have closed everything. So when the point of closure is, of course, uncertain because there needs to be approvals from the authorities on transactions like this, so that is uncertain. But you know what? The data points that I gave you is that, that portfolio produced 40,000 barrels per day in 2012. And they will produce approximately on similar level in 2013. And then, of course, when you count barrels you need to make an assumption on when this is closed.

Of course, okay. Just to clarify then, which means if this transaction takes place in the beginning of fourth quarter next year, you have produced 39,000 barrels for the first 3 quarters, so the full year effect is only 10,000 barrels for you next year. Is that right?

If that's when it's closed. We do expect it to close earlier.

So even with that affect, you will say that you are below in 2013 compared to 2012? Or have you excluded 40,000 barrels?

Well, we don't go into those details in the guiding, but based on that transaction and also on what we're doing in U.S. gas, we don't see that it will be lower than 2012. So those are 2 data points that I'm giving to you today.

Okay. One more question related to your CapEx for next year, so a kind of a soft guidance a little bit higher next year or some higher. Can you tell a little bit more about the split between -- in your CapEx growth between offshore, onshore, unconventional, what will grow, what will not grow in your budgets?

So typically, 45% of our investments will be related to Norwegian continental shelf. Some 50% will be within the international segments. The remainder will be related to midstream investments that is there to support the upstream business. Then, in general, 30% -- 70% of our investments goes into greenfield developments, 30% into brownfield. And that brownfield is split between IOR projects and drilling of wells. And then finally, maintenance and modifications on the platforms. This is mainly going into new developments. When it comes to the split within the international segment. We don't give that specific guidance, but due to the lower rig counts we do in Marcellus, it is sort of slightly lower than we anticipated in -- 1 year ago.

Next question. Can you please state your our name and the name of your company, and I think that's you Trond.

Trond Omdal, Arctic Securities. On your fourth quarter guiding of the same levels last year, is there some upside on gas or does that assume robust offtake? Because you've -- as you said, gas prices in U.K. are very high for the season, 65p per therm. So is that even assuming quite robust or is there still some upside? If you can give some color on that. The second question, I assume almost all of the lower drilling activity is on Marcellus. Or wouldn't some of it be on the gas part of Eagle Ford? And I think you've indicated you're drilling some more of the liquids-rich component of Marcellus. Will that have any effect on liquids for Marcellus next year? Or would that -- third on ACG, of course, you're not the operator, but is there anything you can say about the ongoing discussion between the government and BP on trying to maintain that production long term?

Okay. Thank you, Trond. When it comes to production in the fourth quarter and gas assumptions, I guess, healthy gas markets in the -- on the continent and in the U.K., currently. We see, going forward, somewhat more tightening on the LNG side, more to Asia. So we do expect a healthy market for the fourth quarter. The way that we've run or -- the gas machine is that, typically, in the fourth quarter and first quarter, it runs on full speed. And then there are some assets that have flexibility. For instance, the Usabell [ph] field. The Usabell [ph] field, we can produce the production permit in 80 days and pick the very best days and so on. So that, of course, is -- there is also always an uncertainty when you want to produce that field in a way. But it is less uncertainty related to the gas production and gas offtake in the first quarter and -- the fourth quarter and first quarter than during the summer months. When it comes to Marcellus or the U.S. gas, this will typically be in the northern part, in the dry gas area. And the liquid area in the South is less affected on what we are doing. A couple of reflections on the gas markets. In the U.S., currently, some $3.30 per MBtu, and we have the vicious [ph] -- an increase since December, so it is better. But in dealing with gas in the U.S., it is extremely important to take care of your gas and then add additional value through how you deal with your gas. So from 1st of November, we will start to sell -- transport and sell our gas in Toronto, increasing or putting in place quite generous uplift on our gas, and then we are working on a pipeline together with Spectra and Con Edison and Chesapeake to cross the Hudson River to the U.S. It will actually come up at Penn station and connect to the grid there. The gas prices on Manhattan is totally different than on the Jersey side of the river. So taking care of the gas is extremely important, and we do that. And we create quite a bit of additional value on top of that. When it comes to ACG, I cannot go into discussions that BP has with the government there. I think you know better asking them about that. I think on a general comment, we have the -- we have BP as operator several places in the portfolio. Skarv has been mentioned earlier; in Azerbaijan, ACG and Shah Deniz; PSVM in Angola; and Chalin [ph] in the U.K. Those are, sort of, I guess, the most notable assets for BP as an operator. So we have BP as an operator several places in the portfolio. But when it comes to ACG, I think you are better placed to ask a question to BP on that.

Next question, please.

Euago Soliks [ph] from Furnace [ph] Securities. You were mentioning you were reducing the activity in Marcellus. Do you have any plans on increasing activity in Bakken and Eagle Ford? And how many rigs are you planning to ramp in these different basins next year?

Okay. Yes, we have plans to increase production in Bakken and Eagle Ford. So for instance, Bakken is producing some 38,000 barrels per day in this quarter. When we acquired it a year ago, we produced 21,000 barrels per day. So it's almost doubled. We are continuing with the -- is it 15, Svein, 15 rigs now?

Yes, 14 to 15.

14 to 15 rigs in Bakken. Our operations actually runs very smoothly. In Eagle Ford that's gas and liquids, and so what is the number of rigs that we are running there? I can't recall the specific number. It's -- I think we're running 9 rigs there in the Eagle Ford currently, which is approximately on the level we have been.

And in Marcellus, how many rigs are running there next year?

The specific, I mean, that has not been concluded, the specific number, but it is on its way down in another part of Marcellus.

And one question related to East Africa. You have made very good discoveries there. When can we expect to see any production from that stake?

From Tanzania, It is too early to say. We are very encouraged by both the Zafarani and Lavani discoveries, 2 large discoveries. All in all, some 9 Tcf in discovered resources, which is significant. And that block is a very large one. There are several others very interesting prospects. So our first priority is to find out how much is actually available there and so on. And then we are thinking carefully about the progress and how to deal with this. It is promising, and we are looking forward to continue to work with that assets.

I can't see any further questions in Oslo, so we turn to the audience. And our first person to pose a question today is Haythem Rashed from Morgan Stanley.

Just wanted to ask 3 quick questions, if I could. First, just a point clarification about the gas contracts renegotiations, the question that you answered earlier on, Torgrim. I just wanted to understand, did you specifically say half of all the gas contracts that you have outstanding or half of the amount that you originally said was up for renegotiation? Just to clarify that would be great. Secondly, just on CapEx. And I know you may wish to reserve the right to answer this question with the strategy update early next year but I just -- given your comments around some growth in gross CapEx and given the sort of the recent acquisition of the stake in Edvard Grieg and some of the projects you have upcoming, I just wondered if we should be thinking about this as a step-change in CapEx over the coming 1, 2 years. Or is this sort of something more benign than that? Just would be great to get your thoughts on that. And then finally, just an update, if possible, on some of the key wells that are being drilled at the moment, and specifically, I'm thinking of Kilchurn, but also the Lavani and Zafarani appraisals, where we are on those 3, that would be great.

Okay, Haythem. On the gas contracts, this is 50% on the totality of the scope. So it is progressing well. When it comes to CapEx 2013 and whether you should expect a significant step-up on it, I use the word "some" increasing CapEx, which is certainly not a significant step-up as you say, but it is a direction on the number. Svein, can you give an update on the drilling program?

Yes. On the Zafarani and Lavani, we are in the progress of them -- evaluating them and looking at more appraisal wells in the block for Lavani and Zafarani. In addition to that, we are also done evaluating further prospects and then come up with a drilling campaign for that a little bit later. But the first, now we will done -- do the appraisal drilling for Lavani and Zafarani.

And Kilchurn, did you have any sort of update there?

Kilchurn is now in evaluation phase, looking at that one. So that, we'll need to come back to a little bit later when we have done our evaluation on it. Also, maybe then on others, on the breakdown, which is then ongoing, where we expect results in a couple months' time.

Our next question comes from Nitin Sharma from JP Morgan. Nitin Sharma - JP Morgan Chase & Co, Research Division: Three questions for me as well. First one, coming back to those gas contracts, average invoice [ph] gas price increase of $0.10 Q3 on Q3. I'm conscious of the commercial sensitivity, but could you tell us very broadly, following the recent round of contract renegotiations, for what percentage of your total portfolio gas sale price is tied to oil products versus spot indexation? Two, on Bakken, you mentioned higher realization because of gas capacity. What kind of realization price relating to the benchmark should we factor in? And finally, in an interview yesterday, the president of STL Canada operations expressed interest in LNG assets in the country. Is there something on the near term agenda of the company?

Okay. So 216 [ph] over there, the first 100 [ph] cubic meter in gas prices. A significant increase in that, and your question is about the exposure to oil products in there. Typically, 70% of our gas sales is related to long-term contracts. The rest is typically spot indexed. Of those 70%, half of the contracts have been renegotiated. That should give you a flavor of the impact. So we are -- when I talk about the renegotiations, it's much -- it, of course, comes down to price. But the long-term contracts, they -- we are not selling oil long-term contracts. That is not the spot product. You sell flexibility, and you sell energy security in those contracts, in addition to gas. So the long-term contracts should have a different price than a spot product. And we are allowing more gas indexations into the contracts. I mean the flexibility is taken back to the producers and also -- yes, and also access to the traded hubs and so on. So that flexibility is actually very valuable to us. And I'll give you one example, and that was in 2009, when the gas markets in the U.K, more or less fluxed from 70p per therm to 20p per therm in 2 or 3 months. We decided at that point in time that this was not a market that we would like to produce into. So we pulled back production and produced it the next year at twice the price, 100% return on that flexibility. So just an example of how much flexibility can be worth. Then on Bakken and realized prices, quite healthy. On average, in the mid-70s is what we realized for products there, so that is good. And then a more strategic question on LNG assets. There is one project, Sabine Pass, it's firm and coming onstream on LNG export, and there are several other projects that are evaluating what to do currently. I think, in going forward, I mean, it's hard to see any greenfield developments of LNG export facilities, especially in the U.S. So if that comes on, it's typically on current re-gasification plants and so on. I guess a big discussion over there to do such an investment, you actually have to be a strong believer as well. You need to believe in some $4 spreads between the U.S. market and other markets, and you need to believe in that for some 20 or 30 years to justify that investment. But those revelations are done, and we think about a lot of things in our company and sort of that is also part of what we think about from time to time. But there are no firm plans in any direction in our search.

Next question comes from Theepan Jothilingam from Nomura International.

I have 3 questions, actually. Just very quickly, coming back to 2013 production, can you just talk about perhaps just your assumptions on maintenance for next year relative to this year? Secondly, just exploration expense, clearly, very volatile. But again, I was just wondering what sort of assumptions we should make going forward in terms of the percentage that you sort of think is appropriate to expense as a forecast. And then thirdly, in terms of Tanzania, there have been some thoughts of discussions, consolidations with other players in Tanzania for a development. I was just hoping for an update there in terms of what you thought may be a solution for early development of gas in Tanzania.

When it comes to maintenance, I mean we have to revert to that in the -- in February. But in all the statements I made today, we take into account the expected maintenance. On exploration expense, we have earlier said that you should expect a capitalization of 33% or 1/3 of our expenditure. And my best advice is to do that going forward as well. It will fluctuate from quarter to quarter. It is sort of the nature of exploration. But so far this year, it is actually 33%. So I think that's an assumption that is fair to use going forward. When it comes to Tanzania and East Africa, I mean there's a lot of things going on there, and it's a quite a dynamic picture and a lot of activities and there's a lot of players as well. So it is -- no firm plans yet and so on. But it is natural, that sort of companies that operates in the same areas have discussions on how to deal with issues, but no firm things in any direction, Theepan.

Sorry just to be a pain, but coming back, are you saying that maintenance in 2013 will be of a similar level to 2012? Is that the message?

No. The message is that we are not going to be specific on that today. I think in February is more appropriate for us to lay that out in more detail. But it is sort of taken into account in the things that we have said today.

We'll take the next question from Peter Hutton of RBC.

Good news. Just 2 questions, [indiscernible] 2 parts. First one is in the international business and the cost, there was the higher-than-expected, well, higher than I expected, costs in DD&A and to some extent in exploration. You also mentioned increased royalty. Can you just sort of say where the sort of increase in DD&A versus last year is coming from? Is it fairly geographically spread? Or is it related to the Bakken or Pazflor or any particular areas driving that? On the exploration, is that -- nearly all the increase -- because it was 1.3 this quarter compared to 1 for the first half, is that all on the seismic and the royalties again, geographical split? The second question is simply on exploration. You mentioned the seismic on blocks 38 and 39 in Angola. Just an update on sort of the quality of that seismic and the status and how you're working with that. And also, is there any -- your partner on block 22, which is directly between the 2 discoveries made so far with [ph] the operator. Can you give us figures as to what the progress is on that block as well?

Okay, Peter, good and detailed questions. Svein, can you address the exploration and seismic questions? When it comes to the DD&A and when you compare it together with the third quarter last year, this is related to the Bakken acquisition we made last year. That was not part of the numbers last year, it is currently. That is quite the chunk of it. Then we have higher production, and higher production means higher DD&A because it's a unit of production depreciation. And then we have ramp-up of new fields, and those newer fields typically have much higher depreciation than older fields. And that is back to that 80s depreciated base on risk reserves. And when you start a field, you typically book some 40% of the reserves, then you keep booking as you produce. So in the early phase of a field, then the depreciation is typically much higher. And then the step we see particularly on the Peregrino and Pazflor. And when you have those elements. I think you have it all in the explanation on the increased DD&A on that quarter. And then Svein, on seismic.

On the seismic activity, so you saw that we are stepping our core seismic activity in the Corner [ph] basin quite significant so -- which is an important explanation of the increased exploration cost this quarter. What we are doing there is that we are collecting the seismic, and we are now going over there to process it. And what we will do with the seismic, we will do in terms processing of the seismic, we will developed tools for that internally, which we will then process in the seismic activity. That will make us ready then for drilling wells in 2014. Specific issues related then to the block around 22, I think that is too early to comment on. As a general note, we are excited about both the Corner [ph] Basins and we will come back to you for more details on that later.

Next question will come from Oswald Clint of Sanford Bernstein. Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division: A couple questions for you. The first one just on that value-to-volume strategy for the Marcellus. On the flip side of that, what gas price -- or what Henry Hub gas price do you need to see to bring back the sort of 25,000 barrels of oil equivalent next year that you tend to switch off next year? Secondly, just also on the Bakken kind of sequential growth there on the oil slowed to kind of sub double-digit levels in the 3Q versus 2Q. Is there anything going on there? Is that just rigs? Or you need to increase the rigs to keep that part of the production growing? Or I'm just curious about that growth level. And then actually, I was more curious on the European gas side. In terms of the sort of the sort of big increase in coal coming into kind of U.K., parts of Europe and displacing natural gas, are you seeing any of that start to impact your European Gas business?

All right. In Marcellus, I mean, we are earning money in the current price environment, but we would like to earn more. So this is based on the way we look at the price out of canceled ones [ph]. So we think these volumes are better produced later. So we will sort of, of course, monitor the situation in the markets closely and also, the way we look at it, and so on. But you should expect us to apply that strategy in the current price environment. When it comes to Bakken and the growth, I mean it is growing well. The rigs we are running are really efficient. And your question is 4 parts [ph]. There is a full value chain that needs to contemplate here, taking care of the volumes and also, that you have the right to be rig crew and all of that. I think we are comfortable with the rig counts that we currently are running. I'm sure we could have stepped it up further, but I think it's a balancing act, and I think we're fine with the levels that we have currently. When it comes to European gas and coal, sort of one of my favorite themes, and I think I can talk for a couple of hours on this one. But Europe actually needs gas. I mean, that is especially in Germany, I would say, and also U.K. I mean it is quite a lot of it and Europe is in the need of it, between Norway, LNG, North Africa, Azerbaijan and so on, and it is here to stay. Then it's rather affordable. It doesn't need subsidies. And a certain very important point, it is that is very clean. It is the cleanest fuel and so on. And this is not a political speech, but it is to give you some background of the discussions. In Germany, they have not been able to distinguish between various fossil fuels. They have very clear views on nuclear and clear views on renewables. And we think that German politicians needs to put a clear stance on the gas versus coal and so on. That will really solve CO2 emission issues, and it will actually make Germany even more competitive going forward. Both in the U.K. and Germany, we sense more positive signals to gas, and we very much appreciate that. And we do see that there are more realism coming into all the discussions, and it all points towards the direction of natural gas so we are welcoming that discussion. Okay.

The next question is from Guy Baber of Simmons. Guy A. Baber - Simmons & Company International, Research Division: I had a big picture strategic question here, but we've recently seen comments in the press noting that Statoil needs to become global, which is obviously the system or strategy you guys are undertaking. But there's also an increased willingness on your part to forge large strategic alliances. So just hoping you could elaborate on this comment. And are you referring to additional agreements similar to what you've done with the Rosneft or potentially something more significant? How do we think about that? And can you just reiterate what the primary objective there may or may not be?

Okay, thank you. Our international projection currently is becoming quite significant, and it is growing. And I think I have to say that we have positioned us well in the key basins in the world. And then we are working actively on accessing the basins for the future, what really can be the next big things. And Arctic is very important to us and both East Africa and West Africa as we have discussed today. Brazil, key elements, we have had some really nice discoveries there and the Gulf of Mexico as well, a large acreage holder and so on. And then working together with other companies internationally is a natural thing in this industry. I think the Rosneft deal is a good example of that. And then we actually see quite a bit of increased interest in working together with us going forward as well, and we take that as a compliment. So it's sort of a natural part of this business and so on. On the -- any bigger things, of course, I can never give any directions as such. I think it's fair to say that if you look at our project portfolio, I mean, it is there, it's high quality, it can deliver in 2020 above what we have guided at. So we know what to do. We know what to do all the way towards 2020. This is about execution, and then we will add and subtract from portfolio management. But it actually allow us time to explore. We are not in a situation where we feel that we have to do something to fix anything. We think it works well. We feel that the strategy is working, and we can do what we're best that. So that's sort of the thinking and so on. So I think that is a good starting point for any strategic discussion.

We'll take our next question today from Michael Alsfrod from Citi.

Two questions, if I can please. Firstly just on the financial framework. You've obviously -- you're seeing an increasing cash flow progression, as you mentioned in your presentation. But you're also seeing obviously an increasing CapEx burden to the group. I just wanted to know as you think about it into 2013 and beyond, it seems like breakeven is now [ph] $100 per barrel, and I was just wondering whether you have a view on whether there's an absolute level of disposal that you plan to do. I guess the easy wins -- well, not easy wins, but the more obvious divestments by Statoil within retail, et cetera, have been done. Can you maybe talk about your sort of disposal strategy in more depth? And also -- or is it simply that you're going to be increasing carrying levels over the next year? And then secondly, just on sort of costs in particular on the Mcf. Could you maybe talk a little bit about how you're managing, I guess, what is a tight services market? I mean, what the cost inflation is there and I guess how you're dealing with any bottlenecks that you're seeing in the services market on the Mcf.

Okay, good. Michael, thank you. On the financial framework, it is -- we have not said anything upfront on how much we want to divest and sort of acquire. And I think that is a deliberate choice and so on. So I think we need to look into history to see what has happened. And I dare to say that we have been pretty active over the last decade actually to sharpen our portfolio, to divest assets and then reinvest it into things that are much more strategic. So you should expect that to go forward. It is sort of 1 of the 6 elements in [indiscernible] that we use when we communicate our strategy. So it is close to our heart to use that actively and so on. So you shouldn't be surprised going forward if there are subtractions or additions to the portfolio, so that's there. And then when it comes to -- you touched upon CapEx going forward and what sort of dollar oil price we'd need to balance the portfolio. This is -- this tends to be a black-and-white discussion, I notice. So to me, it's important to put some context around that. I mean, we are running with a balance sheet -- solid balance sheet, AA- rating, 13% net debt, $15 billion in cash and cash equivalents. And that is worth to be able to follow through actively in a cyclical business. Then we are growing the cash flow and so on. And we have, I must say, a great project portfolio that we would like to realize. And then we have a firm dividend policy, and the dividend policy is very important for me, that is both predictable and trustworthy, and that you believe that this will come and that we are able to handle this in an uncertain world and so on. And we have the liquidity, we have the balance sheet, we have flexibility into the investment program, and we have also flexibility in other parts of the company. So this is -- a lot of things goes into this. And of all the things in the world to worry about, this is not one of them you should be worried about, to be honest.

Great. And just particularly, going through cost inflation on the Mcf, is there sort of anything you can talk to about sort of bottlenecks you're seeing in the services market there?

Well, there are certain elements in the market when there are scarcity. We all know that. And there are other areas that are -- that have capacity. The way we -- I mean, there will be some cost inflation typically. But it's all about how to position yourself and handle it. And I think the size of Statoil has actually enabled us to deal with that quite well, taking longer-term positions within rail capacity, frame agreements on the steps that we procure, working closely with the suppliers, knowing that we have capacity with them and also, working with standardizing the project portfolio and working more effectively then. I think the fast track portfolio is a great example of that. Where we have said that these fields should be developed in a quite similar way using this type of subsea templates, this type of risers, this type of walls and so on. And then we have reduced the cost by some 30% on those fields and the time from discovery to production by 50%. So that's the way we think about dealing with that. So it is a tight market in certain areas, and yes, we will be somewhat impacted on it over time. But it's really important to take some longer-term perspective and longer-term positions to handle that. And I do think we are dealing with that in a good manner.

We'll take the next question from Michele della Vigna from Goldman Sachs.

I have 2 quick questions. The first one is whether you could give us a guidance on the tax rate for next year. Are we still likely to be at the top of the 70% to 72% range or in a different place? And secondly, just going back for one moment to the question about cost inflation in the NCS. Your position clearly allows you to get some good frame agreements and some discounts, but overall, what is the level of percentage cost inflation that you're seeing in the market?

Okay. So Kåre, if you can take the tax question. And when it comes to the specific rates, I'm not ready to give that. There is a global market within certain elements so we are, to a larger extent, capitalizing on that and using that also to deal with that. So Kåre? Kåre Thomsen: The adjusted tax rate year-to-date, we are at 72.3%, in line with our guidance of 70% to 72%, maybe a little bit above. And we will revert to, if there are any changes to it, when we address it in February. But we don't see any signs of any major changes. But of course, we will reassess it when the year has passed and come back to that.

We'll take our next question from Robert Kessler from Tudor Pickering Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I know you've gotten a lot of questions on Marcellus already, but a couple more from me, if you don't mind. One is you've quantified the rate of change in the plan, but I haven't heard, I don't think, the new plan as far as how much growth you expect from U.S. gas, say next year versus this year. And then related to that, how much of a contribution might you receive from the liquidation of drilled but uncompleted wells or wells that have been completed but are still stuck behind pipe?

Okay. Robert. I mean what we have said that -- I mean, it will impact our outlook with some 25,000 barrels per day. So but -- that was quite a good growth trajections. There will be some growth in Marcellus next year, but it is, I would say, limited. That is as far as I can go on that one. When it comes to Marcellus and the well, that is ready, I mean, there are some 230 wells that we have drilled that is waiting for gathering systems and needs to be completed and so on. So it's quite an okay environment of -- or inventory of wells. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then an unrelated one, if you don't mind. Your Barents Sea exploration program for next year, do you have an aggregate un-risked resource size estimate you might be willing to share on that program?

Okay. No, I'm not. But I can say that we find the Barents very interesting. It is a huge area, so there are lots of different plays. And when we screw down [ph] on obvious discoveries, it opened up a totally new play in that area, and that is what we are pursuing now with quite a few of the 9-well program. Then we're going to test out something that is called a crude area that is further north, and that is a northernmost wells that have been drilled in Norwegian waters. And that is sort of a very virgin area. It has, of course, a lower probability for discoveries. But again, potential is absolutely there. So while I would've looked -- liked to give you all the details that I have, but I don't think it is prudent, Robert. But we are very encouraged by the development in the Barents area.

We'll take the next question from John Olaisen from AVG.

First, on the oil price breakeven levels. Is it possible to give some kind of -- some indication of where your oil price breakeven level is for 2012 after dividends. Maybe also, for 2013 with lower production, a higher CapEx, how much would that cash breakeven level increase in 2013?

Okay, John. Thank you. Svein, would you mind?

Yes, if you're looking at -- if you look at cash flow from the 3 first quarters of 2012, what Torgrim showed today, he showed a graph, with the cash flow from operations deducting CapEx, adding on what we have received in divestments and dividend, and then showing a surplus of NOK 35 billion based on what we see there. We have paid one more installment tax, as we said, in 1st of October, and we will pay one more. So far in 2012, we have cash surplus of NOK 35 billion and then with the prices that we have realized now. Going into 2013, I think that is too early to say. We will come back to that with an updated forecast for the CapEx and those things in February.

Okay. And my question -- second question goes to the sales of some U.S. assets that were acquired with the Brigham acquisition. Can you tell us how that is moving forward? Maybe like how big will those sales be like, in proportion of the Brigham acquisition, please?

Do you have the details for that, Svein?

I do not have the details that we are in the position to disclose that, no. But it's an optimized portfolio, it's not a big one.

No. So in general, John, it's a natural part of what we do within conventionals all the time. There are some acres that we divest and there are other acres that is acquired. It's sort of a natural part of optimizing the portfolio of assets.

If I read you correctly, it will be a small proportion of the Brigham acquisition that will actually result?

I think sort of -- I mean, it's a natural part of optimizing our own portfolio that is ongoing around all assets.

We'll take the next question from Matthew Yates of Bank of America.

We've heard you adjust your guidance on the gas production in light of market conditions. Could you elaborate a little bit more on the Canadian side with the oil sands? Have you seen any change in the environment there to affect some of your thinking?

Okay, Matthew. Thank you. On the Canadian side, we are exporting gas from Marcellus into the Toronto area. In the Toronto area, it is [indiscernible]. Historically, that area has been sourced by gas from the West. That now is used within the oil sands business, opening it and new markets from the South. So we are actually -- we will actually export gas out of the U.S., which is an interesting concept, but is actually working very well and we are earning on it in that respect. Was that answering your question, Matthew?

I'm sorry. I was referring more to the planned investments towards the back end of the decade in the oil sands, given that the realizations for the Canadian oil sands are pretty weak at the moment, whether you view that as just a temporary bottleneck issue or whether it's more structural and you may rethink your commitment there.

I think, I mean, you're touching upon a very important general theme in the U.S. and that is actually bottleneck issues, which is seen on many of the unconventional plays due to that sort of stock-up [ph] in production. And there is something about market forces that works, and they actually work pretty well in that part of the world. So over time, I do see that bottlenecks -- bottleneck issues will be -- gradually, be less and less as infrastructure is built and industry developed. But yes, you are right, there are bottlenecks issues currently that is -- we are actually handling well.

We'll take our next question from Irene Himona from Société Générale.

I had 3 short questions. So first of all, you're guiding for a lower 2013 production. Should we expect depreciation charges to also be lower due to that? Secondly, in Havis oil recovery and the 60% target, can you talk a little bit about the economics of these projects? Obviously, they work in a world of $110 oil, to what extent is the expected higher CapEx next year linked to that? And then finally, your third quarter exploration expense included NOK 1.6 billion from previous periods. I'm told that related to the Peon gas discovery. Can you talk a little bit about what that tells you concerning commercialization of discoveries, such as beyond shallow reservoirs, in other words?

Okay. Thank you, Irene. When it comes to DD&A in 2013, when it comes to the assets that we have divested, Gjoa and Vega and Brage, I mean that will lead to reduced DD&A related to those fields. So yes, it will have an impact in that respect. And on the gas side, it will also have some effect on the DD&A. When it comes to IOR, 60% and economics. IOR projects are normally very profitable. I think the average internal rate of return, we have seen across that portfolio lately is a 45% internal rate of return, so these projects compete very well. I know we have crossed the 50% limit and working hard going forward. This is very much about technology development within reservoir diagnostics, about drilling technologies and so on and how we can actually get the reservoirs to flow even better. We have recently opened a new IOR center in Trondheim, where we are going to use quite a bit of effort to address all of these opportunities and so on, and obviously, that's a few weeks back. I'm really fascinated on what you actually can do currently, both on reservoir characterization and also on the drilling technology. So I'm really looking forward to that, and I'm sure this is going to be highly valuable going forward as well. When it comes to whether this impacts CapEx, I mean, we -- next year, we will spend some NOK 2.8 billion on R&D, which is quite a significant step-up, and it is much linked to IOR efforts and so on. And then over time, it will feed into investments into profitable projects and so on. And this quarter, we have sanctioned some 4 IOR projects. So I mean, we are moving ahead on this one. And I'm really looking forward to that development. And then, Irene, had a question on expense of exploration from previous period in Peon. Kåre? Kåre Thomsen: Yes. I want to answer more in general terms, and that is for accounting purposes, there is also a time horizon you have to evaluate when you are looking at your capitalized expenditure. And if you -- and you need to have a firm plan in the near future to have it on your books. And of course, as you work with your portfolio, that could change. But the underlying business case doesn't change due to the timing of it. So you can say this is also a result of some prioritization in -- that you take into account when you make plans, and then we have to convert that into the accounting language, so to say, and sometimes, we get that result. But basically, no changes in the commerciality of those aberrations.

We'll take our next question from Teodor Nilsen from Sparebank -- First Securities.

Just a question on the 2013 production guidance. You obviously highlighted a couple of items that will lead to lower production in 2013. But have you seen any underlying decline on your current portfolio? And also, secondly, when it comes to Sverdrup, are you planning to come with unused resource estimate before year-end 2012? Or will it wait until Lundin has built the 2 appraisal wells on 501 before you disclose a new resource estimate?

Okay. Teodor, thank you. When it comes to the underlying decline, I mean this is developing healthy and as we have expected. So there are no indication that the decline rate is increasing. It is still 5%, as it has been over the last years. And that is developing just as it should. When it comes to Johan Sverdrup and the new resource estimate, we have said that next year, yes?...

Next year.

Next year, we have said. So we will not comment in 2012, Teodor. And of course, there are 2 licenses that needs to put their heads together in sort of agreeing around this. But it is next year, Teodor.

Okay. So just to clarify, you will not say anything for PL265 this year?

No, we don't intend to.

We'll take our next question from Jon Rigby with UBS.

Just 3 quick ones, actually. The first is on the balance sheet, I recognize that since Macondo, you've been generating a lot of free cash flow, both because of the oil price and the disposals. But is the shape of the balance sheet with such large amounts of cash sat on it something that you see as being appropriate going forward? Or are you just waiting for the right time to start paying down some of your debt facilities, the first question? The second, just on Bakken, can I confirm where you are in terms of realizing the better oil price realizations? Is the rail car work that you've been doing now in place? So is it sort of in the third quarter numbers? Or do you have more upside potentially both volume and price? And lastly, just on the last note you have in the release, can you just confirm that the deferred tax changes that you referenced, that's purely noncash, there won't be any go-forward effects in terms of actual cash taxes?

Okay. On the deferred taxes, Kåre, and I can take the other ones first. I mean yes, it's absolutely the right observation. The balance sheet is quite cash-rich, and that is by purpose. And having liquidity at hand is something that is important to us and so on. And I think the way you should read that is related to the uncertainty in the macro environment and so on. So to me, it's interest as a company. It is extremely important to be prepared for almost any outcome and any development in the macro environment. And what this industry and other industry learned, after 2008, what's the importance of cash. And that is managed diligently and actively, but quite conservatively. So we will continue to run with both a solid balance sheet and significant liquidity. When it comes to the liquidity, it is fluctuating. And the day after this quarter, we paid NOK 20 billion in taxes. So it goes on, as you understand. When it comes to rail in Bakken, we have a rail in place. It will grow over the next year. And we have -- when it comes through December, I think it is, then we will have 1,040 rail cars available, and that is sufficient to cover our needs. And you should look at these rail cars as an onshore LNG ship. You can actually get your oils to exactly where you get the best price of it. So this can go north and south and east and west. So part of that is the -- though a limited part, is part of the third quarter results, a very limited part. And then Kåre, deferred taxes? Kåre Thomsen: Yes, deferred taxes, you refer to the subsequent rate [ph] where in the national budget there is a rate pipe [ph]suggesting to a central income and cost related to petroleum activity. And we have a deferred tax there. And that's a noncash effect. But we had assumed to get that reduced from our future cash payments, that's why it's deferred. So it has no immediate cash effect. But we had assumed to get that deducted from the tax return in the years to come. When it comes to future effects with the present setup for our activity, then it will have an influence on the international tax rate.

Our next question comes from Kim Fustier with Credit Suisse. Kim Fustier - Crédit Suisse AG, Research Division: Torgrim, just 2 quick questions, if I may. Firstly, just on Snøhvit and Barents sea gas, you've recently stopped work on the possible second train at Snøhvit connected to the very [ph] pipeline. My question is when do you think you'll have firmed up enough gas resources in the broader area to be able to get back to the drawing table and look at options again? My second question is on the recontracting strategies, if you could go back to earlier question on cost inflation. Statoil is very active in the rig market lately. I think you've we recently contracted 3 new semi-subs at quite high rates. Just wondering if you could give us an update on sort of how many more rigs you need to contract in the next 6 to 12 months to be able to execute your drilling plans in the medium term?

Okay, Kim. Yes, second train at Snøhvit, so together with our partners there, we decided not take a decision on the second train on Snøhvit so -- and just to await the situation. It is partly linked to that there are more optionalities in the area and also, related to a strong competition for investment funds in -- within Statoil currently. And there are other projects that compete better than this project. So very systemed [ph] and there's an opportunity and going -- one time in the future, it will be revisited, I'm sure about that. But I can't give you more specific guidance on that. When it comes to the rig market, I mean we are active and it is by purpose. And we take a long-term view on our needs, and we know that our portfolio will need rig capacity for a long time going forward. I cannot, however, get into some specific comments on contracting strategy going forward. That is something that we would like to keep for ourselves.

Our last question today comes from Brendan Warn with Jefferies. Brendan Warn - Jefferies & Company, Inc., Research Division: Just, I'll limit myself to one question. I'll cut the questions off. Just can you remind us in terms of East Africa just your current rig capacity? And I guess the question more specifically, just timing around the drilling commitments in Mozambique and just whether this Total, Petronas well is going to influence positioning of the first well that you'll drill.

I mean, when it comes to -- we have a global rig presence [ph] and sort of we tend to move rigs around where they actually can be the best use for us. We have the capacity available for the appraisal programs that we want to put in place. And so that's sort of fine going forward on -- you asked about Mozambique, I mean, do you have that, Svein?

Yes. The plans for Mozambique is that we will spud the first well in the license, and it's scheduled for second quarter in 2013.

Thank you. And actually, we'll have to conclude our Q&A session for today. And as usual, you can download the presentation and this Q&A session from our website in a few days, and there will also be transcripts available. If you have any further questions, please don't hesitate to contact us in the IR Department. Thank you, all, very much, for participating, and have a good day.