Equinor ASA (EQNR) 2012 Q3 法說會逐字稿

Ladies and gentlemen, welcome to Statoil's third-quarter earnings presentation, both to the audience here in Oslo and to our audience -- and the webcast audiences.

My name is Hilde Nafstad and I'm the Head of Statoil's Investor Relations Group.

This morning, at 07.30 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), 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 posing questions can be found on our website.

It is now a 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 than last year and an 8% production growth if you compare it to the full 2011.

We continue to add barrels form discoveries and increased recovery, and we sharpen our portfolio through value-creating transactions.

On Monday we signed an asset deal with Wintershall, exiting our operated Brage field and farming down in Gjoa and Vega.

We realized $1.45b 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 undeveloped oilfields in the world, and it is one of our key assets for the future.

And we now have secured working interests in all discoveries on the Utsira High, Johan Sverdrup, Ivar Aasen, 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 with a total resource estimate for that field early next year.

We have also proved oil in the basement rock, and that's a possible upside.

In the quarter, we have stepped up our activities in the Arctic.

We signed agreements with Rosneft to establish joint ventures for four offshore licenses in Russia, and we will drill nine wells in the Norwegian Barents Sea next year.

And I'm eager to see what Tim and his team can deliver on that one.

We have added new barrels through increased oil recovery.

In the third quarter, we increased the average recovery rate from our fields on NCS from around 49% to 50%.

That is setting a new world record within increased oil recoveries.

And you know, 1 percentage point, that equals 327m barrels, and if you use the oil price of today that is actually some NOK200b in revenues.

And this creates significant value to Statoil and to our shareholders.

And if you look back at the point of sanction, the average recovery rate was around 30% on these fields, and we have actually added some 7.5b barrels from increased oil recovery.

And to put that in perspective, that is similar to two Statfjord fields.

So, based on this success, we have launched a new ambition earlier this quarter of getting to a 60% recovery rate on our operated fields on the Shelf.

And then we continue to mature our project portfolio.

We have been sanctioning four new IOR projects in the quarter and we continue to ramp up productions from our new fields.

In the third quarter, we delivered solid operational performance.

I have said before that I had been looking forward to 2012, and this year we see significant growth and we deliver as planned.

So this -- so far this year, we have increased production by 8% compared to last year's average, and I will come back to our production outlook in a few minutes.

We have increased our gas production by 18% in the quarter, and this is due to strong gas markets in Europe with good prices.

So, at high value, we increased our volumes and that is in line with our flexibility strategy.

At the same time, our liquid production is slightly down in the quarter, and that is as I told you last quarter.

And we are very pleased with execution of the large turnaround program, and that has been a great job done by our teams and our suppliers.

The decline rate on our mature field is also stable, and that's in line with what we have discussed earlier; it's around 5%.

And as you know, we are adjusting the production related to the Heidrun redetermination, which means that we will not book any production volumes from this field in the second half of 2012.

Additionally, we see the effect of the divestment of the Centrica last year, so that is impacting their second -- the production in the second half.

And even with a significant higher turnaround in the third quarter and the point mentioned, we delivered production growth in Norway.

We are also progressing well on Gullfaks, now at more than 100,000 barrels per day.

And internationally, we increased our production by 24% quarter on quarter, and year to date we stand at an even stronger 27%.

And we continue to build up our production outside Norway.

Pazflor in Angola that is operated by Total continues to deliver, and that field contributed with 47,000 barrels per day for us in the quarter.

Then we produced 38,000 barrels per day from Bakken, the asset that we acquired a year ago.

And we have added rail capacity to that asset, and bypassing the pipeline bottlenecks that is currently -- that we are currently experiencing in that area.

And that is to ensure that we get oil to the market at the highest price possible and reducing the differentials, and we see that it works.

And our trading organization in Stamford creates a lot of value from these barrels.

Marcellus also delivers strong production, at over 63,000 barrels per day in the quarter.

On Eagle Ford, we will take up operatorship of the acreage in the eastern part next year, stepping up for our second operatorship in US onshore.

So we produce as planned.

In the third quarter, our net operating income was NOK40.9b.

That is up NOK1.6b from last year, or 4%.

Our net income is NOK14.5b, which is up 47% from last year.

And we see a lower effective tax rate this quarter, and I will come back to the tax a little bit later.

The adjusted earnings before tax were NOK40b.

That's a slight decrease over the last year.

And that is due to higher exploration expenses, partly offset by higher gas production and prices.

And then we continue with high exploration activity, with drilling ongoing in several exciting prospects.

Operational costs and SG&A are at the same level as last year, at NOK19b.

If we adjust for the SFR divestment, we see a flat cost development over the last quarters, despite the high activity levels and the production growth.

And we will continue to attack here our cost base.

After tax, we made NOK11.9b a quarter on an adjusted basis.

That's an increase of 4% from the same period last year.

We deliver NOK31.1b in adjusted earnings from Development & Production Norway.

That's a decrease of 13%.

And as discussed, our liquid production is down and that is impacting earnings by some NOK7.7b.

And this is from the planned turnaround activity, the Heidrun redetermination and our divestment of producing assets to Centrica.

We saw lower depreciation in this segment, and that is due to higher reserves and lower production this quarter.

Then we produced a lot of gas and that is increasing by 11%.

And we realized a 14% higher gas price this quarter than the same period last year.

In International Development & Production, the adjusted earnings was NOK4.4b.

That is up 7% from NOK4.1b in the third quarter last year.

And we are growing our international production significantly, and this increase was partly offset by increased exploration and depreciation expenses, some lower prices and increased royalties.

The higher exploration charges are partly due to a significantly increased seismic activity, including the activity in the Kwanza Basin in Angola, where we are preparing for siting, I must say, pre-salt wells to be drilled in 2014.

Then we see a very strong quarter in Marketing, Processing & Renewables, delivering earnings of NOK4.1b, which is a 67% increase over the same period last year.

For natural gas, earnings were NOK2.7b compared to NOK2.8b one year ago, and that is despite the lower Gassled stake this year, and normally that contributed with NOK1b per quarter.

The strong result was due to higher refinery -- excuse me, higher margins from our gas sales and higher volumes and higher prices, and good trading and end-user sales.

For the crude part and marketing and trading, earnings were NOK1.5b in the quarter, compared to a loss last year of NOK0.2b.

The increase came from strong refining margins and continued strong results from trading activities, and another good quarter from our trading floors.

But there is still a demanding outlook for the refinery business, and we must be prepared for lower margins than we have seen in the quarter.

And we will continue our improvement program with full force, and we actually see the impact and effect of the improvement program in our earnings.

And then just a reminder that the result from MPR, that will fluctuate from quarter to quarter.

The reported tax rate was 66.9% in the quarter, and based on adjusted earnings it was 70.4%.

This is in the lower part of our guided range of 70% to 72%.

And I have said earlier that you should expect our tax rate for the full year to be in the upper part of that range, or slightly above, and this is unchanged.

The decrease in the tax rate is mainly related to relatively higher adjusted earnings outside the Norwegian Continental Shelf.

Over to the cash flows.

The cash flow from our underlying operations year to date is NOK188b.

We have invested for NOK84b.

We have freed up NOK29b from value-creating portfolio management, and NOK29b amounts to the market cap of a top 10 company on the Oslo Stock Exchange.

Such transactions are and will continue to be an important and integrated part of our strategy going forward, and I will come back to that shortly.

We paid NOK77b in tax and NOK21b in dividends.

And please note that the paid taxes of NOK77b is significantly lower than the reported income tax in the accounts of NOK104b, so far this year.

And as you know, we pay tax in Norway six times per year.

We have already paid one installment in the fourth quarter and we will pay another one on December 1 of around NOK20b.

We are increasing our cash flow.

Operating cash flow has grown by 10% the first nine months, based on stable prices, and this is in line with our production growth.

And this contributes to our strong balance sheet.

We have now close to NOK85b or $15b in cash and current papers, and we have taken down our adjusted net debt to 12.6% this quarter.

So, financial robustness is still very important to us and a very important strategic issue.

Our project portfolio is capable of producing more than 2.5m barrels per day in 2020, and it is an attractive portfolio, as you know.

However, we will continue to optimize the portfolio, to sharpen the growth further and putting our money where our strategy is.

And I think the recent transactions illustrate this in a pretty good way.

We realize value from non-core assets, like in Gassled and Statoil Fuel & Retail.

We balance risk by taking in new partners in Peregrino and KKD.

And we focus our portfolio by deploying resources into core areas and divesting non-core assets, like we did with Centrica and Wintershall.

And these transactions brings more than $15b in proceeds to the Company, in addition to our new stake in Edvard Grieg.

And we have realized accounting gains of more than $6b based on these transactions, and we will continue our strategy of targeted investments, in addition, like our Bakken acquisition last year.

So we will add and we will subtract, and thereby creating significant value for our shareholders.

And then, our growth towards 2020 will be of even higher quality.

So we will balance our investment program going forward, with an active portfolio management.

And we maintain our policy of a predictable and growing dividend, and we will continue to maintain a strong and solid balance sheet.

So, we are progressing as planned.

We are delivering a 10% growth in production year to date, compared to same period last year, and an 8% growth if you compare it to the average of the full year last year.

And this is an industry leading performance and it is in line with our guiding.

Then, looking ahead, we will have organic investments of around $18b in 2012.

Given the solid production growth we see for the next year, it is likely that we will see some growth in the gross CapEx next year, and I will revert more closely to this in February.

However, we are investing for growth, with a low breakeven price across the portfolio and industry leading rates of returns on the projects.

So we are spending money to make even more money.

We will explore for around $3.5b.

We will drill 45 wells in total this year.

And we have already added more resources this year than the full 2011, which was a record year for us since the IPO.

And then we will drill some 20 to 25 high-impact wells from 2012 to 2014.

We will run, I must say, a very interesting drilling campaign in Barents starting next year, or starting in this winter, of nine wells.

We'll start with spudding the Nunatak Prospect next month, and this is close to the Skrugard and Havis discoveries.

We are on track for our 2012 production outlook.

We are delivering growth as planned, and then we expect our fourth-quarter production to be around the level of fourth quarter last year.

And let me give some color to this.

We are currently ramping up production from Peregrino, Pazflor, Marcellus, Bakken, Eagle Ford, and then we plan to bring three fast-track projects on stream during the next -- during the fourth quarter.

But you should remember that you have to adjust for the Heidrun redetermination and our reduced ownership share on Kvitebjorn, as well as the delayed Skarv startup, and that will counter the new production expected in the quarter.

In the longer term, we are steadily heading towards 2020 and our ambition to product more than 2.5m barrels per day.

And we are on track for an average growth of 2% to 3% from 2012 to 2016.

But production will fluctuate from year to year, and we see 2013 production lower than 2012 production, and I would like to give some color on the reasoning for that.

First, the Wintershall transaction will reduce production in 2013.

The divested fields produced around 40,000 barrels per day in 2012 and a similar level is expected in 2013.

Furthermore, we will reduce the rig count in the US, responding to the low US gas prices.

And you know the beauty of that asset is the ability to react to prices to create more value.

So growth in the US will be slow next year and the impact may be in the order of 25,000 barrels per day, compared to plan.

So the reduced production from our US gas position will, however, have limited impact on earnings, which is the whole point.

So, both of these things are deliberate actions by ourselves to create value through our divestment and through a value-over-volume strategy in the US.

So, in summary, we are significantly growing both our production and our earnings, 8% production growth compared to the full 2011.

Adjusted earnings year to date grows also with 8%, and our operating cash flow is growing with 10% so far this year.

And then we are continuing to invest into a very profitable project portfolio.

So, thank you very much for your attention.

And then I'll leave the word to you, Hilde, to lead us through the Q&A session.

Thank you.

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, Kare 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).

Thank you.

And then we'll start with the questions from the audience here in Oslo first, so please push the button on your microphone if you would like to pose a question.

Yes, Anne.

Thank you.

I hope you could give some comments about the renegotiations with 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, Anne.

Let me start with what's going on.

And you are right, we are renegotiating our contracts and modernizing our gas contract portfolio, which is about taking back visibility and changing the structure 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 dare 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, Oseberg, the transportation facilities and all the landing points and so on.

So we are able to create value on that flexibility.

Next question, please.

It's me.

Oh, is it you.

Yes.

Push the button?

No, you can just talk.

Okay.

Thank you.

Lars from SEB Enskilda.

It relates to your 2013 guidance, or at least what you say, that the production will be lower than 2012.

Can you explain or can you tell, have you excluded the Troll related volumes from January 1, or actually from the second half of 2013, because you have said that the transaction will take place, due to regulatory work, from second half?

So for when have you excluded 35,000 to 40,000 barrels per day?

So when that transaction -- that transaction will have an effective date of January 1. So there will be earnings impact from January 1, in a way, or it will be -- have an economic impact from the effective date.

So the way this works is that when everything is closed you have a settlement in cash for that period, and so on.

And then you count barrels until you have closed everything.

Exactly.

But you have --

So, when the point of closure is is of course uncertain, because there needs to be approvals from the authorities on transactions like this, so that is uncertain.

But the data points that I give you is that that portfolio produced 40,000 barrels per day in 2012 and they will produce approximately on a similar level in 2013.

And then so of course, when you count barrels, you need to make an assumption on when this is closed.

Of course.

So -- okay.

Just to clarify, which means if this transaction takes place in the beginning of fourth quarter next year, you have produced 39,000 barrels for the first three 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 effect, you have -- 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 what we are doing in US gas, we now see that it will be lower than 2012.

So those are two data points that I'm giving to you today.

Okay.

One more question related to your CapEx for next year, so kind of a soft guidance a little bit higher next year, or some higher.

Can you tell a little bit more about the split in your CapEx growth between offshore, onshore, unconventional, what will grow, what will not grow --

Yes.

-- in your budgets?

Thank you.

So, typically 45% of our investments will be related to Norwegian Continental Shelf.

Some 50% will be within the International segment.

The remainder will be related to mid-stream 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.

But 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 count we do in Marcellus, it is sort of slightly lower than we anticipated a year ago.

Next question.

And can you please state the name of -- your own 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 level as last year, is there some upside on gas, or does that assume a robust off-take because, as you've said, gas prices in the UK are very high for the season, 65p per therm?

So is that even assuming quite robust then, or is there still some upside, if you can give some color on that?

Second question, I assume almost all of the lower drilling activity is on Marcellus, or will some of it be on the gas part of Eagle Ford?

And you've -- I think you've indicated that you are drilling some more of the liquid rich component of Marcellus.

Will that have any effect on liquid for Marcellus next year, or will that be negligible?

And the third on ACG.

Of course you're not 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, yes, a healthy gas market in the -- on the Continent and in the UK 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 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 Oseberg field.

The Oseberg 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 off-take in the first quarter and -- the fourth quarter and first quarter than during the summer months.

When it comes to Marcellus, or the US 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 market in the US, currently some $3.3 per MMbtu Henry Hub, which is an increase since the summer, so it is better.

But in dealing with gas in the US, it is extremely important to take care of your gas and add additional value through how you deal with your gas.

So from November 1 we will start to sell -- transport and sell our gas in Toronto, increasing -- putting in place quite a generous uplift on the gas.

And then we are working on a pipeline, together with Spectra and Con Edison, Chesapeake, across the Hudson River to the US, and it will actually come up at Penn Station and connect to the grid there.

And you know 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 we have with the government there.

I think you are better asking them about that.

I think on a general comment, we have BP as operator, several places in the portfolio.

[Skaru] has been mentioned earlier in Azerbaijan, ACG and Shah Deniz, PSVM in Angola and [Shialin] in the UK.

Those are, I guess, the most notable assets where BP is 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 how they look at that.

Next question, please.

[Ole Jakob Solekkson, First] Securities.

You were mentioning you are 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 run in these different basins next year?

Yes.

Okay.

Ole Jakob, thank you.

Yes, we have plans to increase the 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 it produced 21,000, so it's almost doubled.

We are continuing with -- is it 15, [Ben], 15 rigs, no?

14 to 15.

14 to 15 rigs in Bakken.

Operations actually runs very smoothly.

In Eagle Ford, that's gas and liquids and so on.

The number of rigs that we are running there, I can't recall the specific number.

It's -- I think we are running nine rigs there in Eagle Ford currently, which is approximately on the level we have in.

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

The specific has not been concluded, the specific number, but it is on its way down in the northern 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 region?

From Tanzania, it is too early to say.

We are very encouraged by both the Zafarani and Lavani discoveries, two large discoveries, all in all some 9 tcf in discovered resources, which is significant.

And you know 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.

And it is promising and we are looking forward to continue to work with that asset.

I can't see any further questions in Oslo, so we turn to the audio audience.

And our first person to pose a question today is Haythem Rashed from Morgan Stanley.

Please go ahead, Haythem.

Thank you, Hilde.

Good morning, all, or good afternoon.

I just wanted to ask three quick questions, if I could.

Firstly, just a point of clarification about the gas contracts renegotiations, just the question 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.

Thanks.

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 just given your comment around some growth in gross CapEx and given the recent acquisition of the stake in Edvard Grieg and some of the projects you have coming, I just wondered if we should be thinking about a step change in CapEx over the coming one to two years, or is it 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, so -- and specifically I am thinking of Kilchurn but also the Lavani and Zafarani appraisals, where we are on those three.

That would be great.

Thanks.

Okay.

Haythem, thank you.

On the gas contracts, this is 50% of 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 used the word some increase in 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 Zafarani and Lavani, we are in 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 then evaluating further prospects and then come up with a drilling campaign for that a little bit later.

But first now we will then do the appraisal drilling for Lavani and Zafarani.

Great.

Thanks.

And Kilchurn, did you have any update there?

Kilchurn, it's in an evaluation phase, looking at that one, so that we 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 of months' time.

Great.

Thanks.

Your next question comes from Nitin Sharma from JPMorgan.

Please go ahead, Nitin.

Hi.

Afternoon.

Three questions from me as well.

First one, coming back to those gas contracts, average invoiced gas price increase of 10% Q3 on Q3, I am conscious of the commercial sensitivities, 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 product versus spot indexation?

Two, on Bakken, you mentioned higher realization because of gas capacity.

What kind of realization price related to the benchmark should we factor in?

And finally, in an interview yesterday President of STL Canada operations expressed interest in LNG assets in the country.

Is this something on near-term agenda for the Company?

Thank you.

Okay.

Thank you.

So NOK2.16 per standard cubic meter in the invoiced gas prices is 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.

And 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 -- all long-term contracts, that is not a 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.

When we are allowing more gas indexations into the contracts, 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 UK more or less collapsed from 70p per tonne to 20p per tonne in two or three 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 realize for products there, so that is good.

And then more a strategic question on LNG assets.

There is one project, Sabine Pass, is firm and coming on stream on LNG export.

And there are several other projects that are evaluating what to do currently.

I think, when going forward, it's hard to see any greenfield developments of LNG export facilities, especially in the US.

So if there comes some, it is typically on current regasification plants and so on.

I just had 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 US market and other markets, and you need to believe in that for some 20 or 30 years to justify that investment.

But those tabulations are done and if -- we think about a lot of things in our Company and then that is also part of what we think about from time to time, but there are no firm plans in any direction as such.

Thanks.

Next question comes from Theepan Jothilingam from Nomura International.

Please go ahead, Theepan.

Yes.

Thank you, Hilde.

Good afternoon.

Another three 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 think is appropriate to expense as a forecast?

And then thirdly, in terms of Tanzania, there had 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.

Thank you.

Okay.

Thank you.

When it comes to maintenance, we have to revert to that in February.

But you know in the statements I made today, you know we take into account the expected maintenance.

On exploration expense, we have earlier said that you should expect a capitalization of 33% or one-third of our expenditure, and my best advice is to do that going forward as well.

It will fluctuate from quarter to quarter; it is 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, there's a lot of things going on there.

And it's 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 companies that operate in the same areas have discussions on how to deal with issues.

But there are no firm things in any direction, Theepan.

Okay.

Thank you.

Just -- 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 prudent for us to lay that out in more detail.

But it is taken into account in the things that we have said today.

Okay.

Fantastic.

Thank you.

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

Please go ahead, Peter.

Morning, everybody.

Good news is just two questions; bad news is they're each in two parts.

First one is in the International business and the costs.

They were higher than expected, or higher than I expected, costs in DD&A and to some extent in exploration.

You also mentioned increased royalties.

Can you just say where the 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 NOK1.3b this quarter compared to NOK1b for the first half.

Is that all on the -- on seismic?

And the royalties, again, geographical split.

The second question is simple, on exploration.

You mentioned the seismic on blocks 38 and 39 in Angola.

It was just an update on the quality of that seismic and the status and how you're working with that.

And also, is there any -- you're a partner on Block 22, which is directly between the two discoveries made so far with Repsol the operator.

Can you give a feel as to what the progress is on that block as well?

Okay, Peter.

Thank you.

Good and detailed questions.

Svein, can you address the exploration, seismic 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 a chunk of it.

Then we have higher production, and higher production means higher DD&A because it's a unit of production, depreciation.

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 it is depreciated based on booked reserves.

And when you start a field, you typically book some 40% of the reserves and then you keep booking as you produce.

So in the early phase of a field, then the depreciation is typically much higher.

And then that we see particularly on the Peregrino and the Pazflor.

And when you have those elements, I think you have it all in explanation of the increased DD&A on that one.

Yes.

And then Svein on seismic.

Yes.

On the seismic activity, as Torgrim said, we are stepping up our seismic activity in the Kwanza Basin, quite significant, so which is an important explanation of the increased exploration costs this quarter.

What we are doing there is that we are collecting the seismic and we are now going over then to process it.

And what we will do with the seismic, we will do internal processing of the seismic.

We have developed tools for that internally, and 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 the Kwanza Basin, and we will come back to more details on that later.

Okay.

Great.

Thanks very much.

Next question will come from Oswald Clint of Sanford Bernstein.

Please go ahead, Oswald.

Yes.

Thank you very much, Hilde.

Yes, a couple of questions, please.

The first one, just on that value-to-volume strategy for the Marcellus.

On the flip side of that, what gas price, what Henry Hub gas price do you need to see to bring back the 25,000 barrels oil equivalent next year that you intend to switch off next year?

Secondly, just also on the Bakken sequential growth there on the oil, slow to sub-double-digit levels in 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?

I'm just curious about that growth level.

And then, actually, I was more curious on the European gas side.

In terms of the big increase in coal coming into UK, parts of Europe and displacing natural gas, are you seeing any of that start to impact your European gas business?

Thank you.

All right.

Thank you.

In Marcellus, 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 outlook and so on.

So we think these volumes are better produced later, so we will 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, it is growing well.

The rigs we are running are really efficient.

And your question is how fast.

There is a full value chain that needs to come to play here, taking care of the volumes and also that you have the right rig crew and all of that.

I think we are comfortable with the rig contracts 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 are fine with the levels that we have currently.

When it comes to European gas and coal, one of my favorite themes, and I think I can talk for a couple of hours on this one, but Europe actually needs gas.

That is especially Germany, I would say, and also UK.

It is quite a lot of it, and Europe is in the middle 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 third and very important point, it is that it 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 on the discussions.

In Germany, they have not been able to distinguish between various fossil fuels.

They are very -- they have clear views on nuclear and clear views on renewables.

And we think that German politicians need to put a clear stance on gas versus coal and so on.

That would really -- it would really solve CO2 emission issues, and it will actually make Germany even more competitive going forward.

Both in the UK 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.

Thank you, Oswald.

That's good.

Thank you.

We'll take the next question from Guy Baber of Simmons.

Please go ahead, Guy.

Yes.

Thank you, guys.

I have a big picture strategic question here.

We've recently seen comments in the press noting that Statoil needs to become more global, which is obviously consistent with the strategy you guys are undertaking, but that there's also an increased willingness on your part to forge large strategic alliances.

So just hoping you can elaborate on this comment.

And are you referring to additional agreements similar to what you've done with 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?

Thanks.

Okay, Guy.

Thank you.

Our international production currently is becoming quite significant and it is growing, and I think I dare 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 a natural part of this business and so on.

On 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, it is there; it is 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 are best at.

So that's the thinking and so on.

So I think that is a good starting point for any strategic discussion.

Okay.

Great.

Very helpful.

Thank you.

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

Please go ahead, Michael.

Good afternoon.

(Technical difficulty) 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.

And I just wanted to know, as you think about it into 2013 and beyond, it seems like breakeven is north of $100 per barrel, and I was just wondering whether you have a view on whether there's an absolute level of disposals that you plan to do.

I guess the easy wins of -- well, not easy wins, but the more obvious divestments like Statoil Fuel & Retail, etc., have been done.

Could you maybe talk about your disposal strategy in more depth?

And also -- yes, or is it simply that you're going to be increasing gearing levels over the next year?

And then secondly, just on costs in particular on the NCS, could you maybe talk a little bit about how you're managing what is I guess a tight services market, 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 NCS?

Thanks.

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 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 one of the six elements in the (inaudible) 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 touch upon CapEx going forward.

And you know what sort of dollar oil price we 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.

We're running with a balance sheet, a solid balance sheet, AA minus rating, 13% net debt, $15b in cash and cash equivalents.

And that is for us 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 you know 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.

Thank you.

And specifically on cost inflation on the NCS, is there anything you can talk to about bottlenecks you're seeing in the services market there?

Well, there are certain elements in the market where there are scarcity; we all know that.

And there are other areas that are -- that have capacity.

The way we -- 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 rig capacity, frame agreements on the stuff 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 template, this type of risers, this type of wells, and so on.

And then we have reduced the costs 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.

Okay.

Thank you, Torgrim.

That's great.

We'll take our next question from Michele Della Vigna from Goldman Sachs.

Please go ahead, Michele.

Hi.

Thank you for the presentation.

I have two 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.

Thank you.

So, Kare, 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, Kare?

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.

Thank you.

We'll take our next question from Robert Kessler from Tudor Pickering Holt.

Please go ahead, Robert.

Hi.

Thanks.

Good afternoon.

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 US 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 that are still stuck behind pipe?

Okay.

Thank you, Robert.

What we have said, that it will impact our outlook with some 25,000 barrels per day.

So -- but that was on quite a good growth projections.

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, there are some 230 wells that we have drilled that is waiting for getting systems and needs to be completed and so on.

So it's quite an okay environment of -- or inventory of wells.

Yes.

Okay.

Thanks for that.

And then an unrelated one, if you don't mind.

Your Barents Sea exploration program for next year, do you have an aggregate unrisked resource size estimate you might be willing to share on that program?

Okay.

Thank you.

No, I'm not.

But I can say that we find the Barents very interesting.

It is a huge area, so there are a lot of different places.

And you know when we -- Skrugard and Havis discoveries opened up a totally new play in that area, and that is what we are pursuing now with quite a few of the nine well program.

Then we're going to test out something that is called a hoop area that is further north, and that is the northernmost wells that have been drilled in Norwegian waters.

But that is sort of a very virgin area.

It has of course a lower probability for discoveries but, again, the potential is absolutely there.

So I would like to give you all the details that I have, but I don't think it's prudent, Robert.

But we are very encouraged by the development in the Barents area.

Well, thanks for the color, and good luck.

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

Please, John.

Yes.

Hi there.

Firstly 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 and higher CapEx?

How much will that cash breakeven level increase in 2013?

Okay, John.

Thank you.

Svein, would you mind?

Yes.

What we are looking at, if you look at the cash flow from the three first quarters of 2012, what Torgrim showed today, he showed a graph then with the cash flow from operations, deducting CapEx, adding on what we have received in divestments and dividend, and then showing a surplus of 35b based on what we see there.

We have paid one more installment of tax, as he said, in October 1, and we will pay one more.

So, so far in 2012, we are in a cash surplus of 35b, and then with the prices that we have realized now.

Going into 2013, I think that 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 US assets that were acquired with the Brigham acquisition.

Could you tell us how that is moving forward, and maybe to look -- how big were those sales been, like in proportion of the Brigham acquisition, please?

Do you have the details on that, Svein?

I do not have the details that we are in a position to disclose that, no.

But it's then optimizing the portfolio; it's not a big one.

No, it's -- so, in general, John, it's a natural part of what we do within unconventionals all the time.

There are some acreage that we divest and there are other acreage that is acquired.

It's a natural part of optimizing the portfolio, as such.

If I read you correctly, it will be a small proportion of the Brigham acquisition (inaudible) result?

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

Okay.

Okay.

Thank you.

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

Please go ahead, Matthew.

Hi.

Good afternoon.

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, whether you've seen any change in environment there to affect some of your thinking?

Thanks a lot.

Okay, Matthew.

Thank you.

On the Canadian side, we are exporting gas from Marcellus into the Toronto area, so the -- in the Toronto area it is healthy demand.

Historically, that area has been sourced by gas from the west that now is used within the oil sands business, opening up a new market from the south.

So we are actually -- we will actually export gas out of the US, which is an interesting concept but it's actually working very well.

We are earning money, 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 a -- just a temporary bottleneck issue, or whether it's more structural and you may rethink your commitment there.

I think -- you're touching upon a very important general theme in the US, and that is actually bottleneck issues, which is seen on many of the unconventional plays, due to that structural step in production.

And there is something about market forces that work and they actually work pretty well in that part of the world.

So, over time, I do see that bottleneck issues will be gradually -- be less and less as infrastructure is built and industry developed.

But yes, you're right, there are bottleneck issues currently that we're actually handling well.

Right.

Thanks very much.

We'll take our next question from Irene Himona from Societe Generale.

Please go ahead, Irene.

Thank you.

Good afternoon.

I had three 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, enhanced 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 NOK1.6b 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 the shallow reservoirs, in other words?

Thank you.

Okay.

Thank you.

Thank you, Irene.

When it comes to DD&A and 2013, when it comes to the assets that we have divested, Gjoa and Vega and Brage, 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.

Now 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 I visited that a few weeks back.

And 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, next year we will spend some NOK2.8b 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 investment into profitable projects and so on, and this quarter we have sanctioned some four IOR projects.

So we are moving ahead on this one and I'm really looking forward to that development.

Then, Irene, you had a question on expensive -- expense of exploration from previous period and Peon.

Kare?

Yes, I want to answer more in general terms, and that is for accounting purposes there was 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 -- 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 averages.

Yes, thank you very much.

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

Please go ahead, Teodor.

Good afternoon.

Just a question on the 2013 production guidance.

You've already highlighted a couple of items that will lead to lower production in 2013, but have you seen an underlying decline on your current portfolio?

And also, secondly, when it comes to Sverdrup, are you planning to come with a new resource estimate before yearend 2012, or will it wait until Lundin has drilled the two appraisals well on 501 before you discuss a new resource estimate?

Thank you.

Okay, Teodor.

Thank you.

When it comes to the underlying decline, this is developing healthy and as we have expected, so there are no indications that the decline 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 next year.

Yes?

Next year.

Next year we have said.

So it will not come in in 2012, Teodor, unless, of course, there are two licensees that need to put their heads together and 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.

Okay.

Thank you.

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

Please go ahead, Jon.

Hi.

Thanks for the questions.

I admire your stamina.

Just three quick ones, actually.

The first is, on the balance sheet, now 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 a large amount 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?

That's 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 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 reference, that's purely non-cash, there won't be any go forward effects in terms of actual taxes and cash taxes?

Thanks.

Okay.

Thank you.

On the deferred taxes, Kare, and I can take the other ones first.

Yes, it's absolutely the right observation, that the balance sheet is quite cash rich, and that is by purpose.

And you know 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, and for us 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 industries learned after 2008 was 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, you know it is fluctuating.

And a day after this quarter, we paid NOK20b in taxes.

So it goes up and down, as you understand.

When it comes to rail in Bakken, we have rail in place.

It will grow over the next year.

And we have -- when it comes to December, I think it is, then we will have some 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 oil to exactly where you get the price of it.

So this can go north and south and east and west.

So part of that is -- but though a limited part, is part of the third-quarter result, a very limited part.

And then, Kare, deferred taxes.

Yes, deferred taxes.

You referred to the subsequent direct, where in the national budget there's a white paper suggesting to accept all income and costs related to foreign petroleum activity, and we have deferred tax there.

And that's a non-cash 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.

Right.

Good.

Thank you.

Our next question comes from Kim Fustier with Credit Suisse.

Please go ahead, Kim.

Hi, Torgrim.

Just two quick questions, if I may.

Firstly, just on Snohvit and Barents Sea gas, you've recently stopped work on a possible train at Snohvit, or alternatively 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 rig contracting strategy, just going back to earlier questions on cost inflation.

Statoil's been very active in the rig market lately.

I think you've recently contracted three new semi-subs at quite high rates.

I'm just wondering if you could give us an update on how many more rigs you need to contract in the next six to 12 months to be able to execute your drilling plans in the medium term.

Thank you.

Okay, Kim.

Thank you.

Yes, second train at Snohvit, so together with our partners there we decided to not take a decision on the second train on Snohvit 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 within Statoil currently, and there are other projects that compete better than this project.

But it sits there 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, 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, give into some specific comments on contracting strategy going forward.

That is something that we would like to keep for ourselves.

So thank you, Kim.

Thank you.

Our last question today comes from Brendan Warn with Jefferies.

Please go ahead, Brendan.

Yes.

Thanks for that, Hilde.

And I agree with the stem of the comments.

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 a 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.

When it comes to -- we have a global rig [presence] and we tend to move rigs around where they actually can be for the best use for us.

We have capacity available for the appraisal programs that we want to put in place, and so that's fine.

Going forward, you asked about Mozambique.

Do you have that, Svein, on rigs?

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

Thank you.

Okay.

Thanks, Torgrim.

Thank you.

And actually, I will have to conclude our Q&A session for today.

And as usual, you can download the presentation and the 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.