Equinor ASA (EQNR) 2009 Q3 法說會逐字稿

Welcome to Statoil's third quarter 2009 earnings presentation.

It takes place from our offices in Oslo.

My name is Lars Sorensen and I'm the Head of Investor Relations.

This morning at 8.00 am Central European time, the third quarter earnings report was published through wires and through the Oslo Stock Exchange.

The report can be downloaded from our website, statoil.com, together with the presentation that will be used in this presentation call.

I'll ask you to please take notice of page 22 in the presentation pack which contains forward looking statement and our disclosure note.

Today's event can be followed by webcast, and that gives me an opportunity to say welcome to our webcast audience.

As you know, safety's paramount to us and therefore I'm just going to take 30 seconds of your time to instruct the audience here in Oslo about safety.

We've got two emergency exits in the back of the room, and either you go on the left downstairs and out through the glass doors where you came in.

Or you can use the right-hand side door and go down the stairs and through the reception -- the main reception.

And the meeting point is close to the main road, the A18 for those -- or E18 for those who are resident in Oslo.

Today's earnings presentation will be made by Statoil's Chief Financial Officer, Mr.

Eldar Saetre.

After the presentation we'll open for questions, both here from Oslo and also via the Internet.

And if you are following the presentation on the Internet, you can use the submit question button on your screen and send in questions to my PC here, and I'll read them out for you, and Eldar Saetre will answer.

Now it's my privilege to leave the microphone to Eldar Saetre.

Thank you Lars.

Ladies and gentlemen, thank you for joining us at this Statoil third quarter earnings presentation.

Since our last presentation in August the global economy has been picking up additional speed.

And this has mainly been led by emerging economies and I would say also enhanced by positive market sentiments.

However, as we see it the fundamentals of the global economy related to corporate investments, to employment and to private consumption has not -- still not turned positive with a robust trend and we think this calls for a continued cautiousness.

There are still fundamental imbalances in the global economy, driven by unsustainable public borrowing and spending.

And the stimulus packages that we had -- have been implemented by governments across the world, they are seemingly working, but at one point they will have to be retracted.

Further monetary policies also seem to be more or less exhausted as an instrument in this situation.

The fundamentals for our industry, for the oil and gas industry have not changed materially as we see it this quarter.

Industrial demand from the western world has remained weak.

Oil prices have rebounced based on expectations that the physical demand eventually will pick up.

But so far we have seen only seen small signs actually of that happening.

The current situation in the world economy implies also weak demand for refined products.

And as a consequence, we have made an impairment this quarter related to our refinery at Mongstad on the west coast of Norway.

The gas spot market has also this quarter been influenced by the rather weak industrial demand and a supply overhang.

And this comes in addition to the normal seasonal off-take pattern.

However, we believe that the fundamental realities -- energy realities of the world are the same as before the downturn, and we have not changed our long-term fundamental view on -- and outlook for oil and gas.

Global energy demand will continue to grow in the longer-term and that includes oil and gas, and its supply side will struggle to keep up.

The third quarter is another quarter for us with strong deliveries, both when it comes to production, cost reductions and cash flows.

Production outside Norway this quarter exceeded 500,000 barrels per day, which represents approximately 27% of our total equity production.

Our exploration activity is still high and also with the continued high success rate We have completed 58 wells so far this year, with 33 discoveries.

And a number of wells is also still pending under evaluation.

In this context I should also mention that we, now also have two Statoil operated ultra-deepwater rigs on location in Gulf of Mexico.

So let me now take a look at the financial results for the quarter.

This illustration gives an overview of our key components, result components this quarter, compared with the third quarter at the bottom here last year.

And as you will see our reported net income is NOK6.6 billion against NOK6.3 billion last year -- the same quarter last year, and that is an increase of 6%.

The reported net operating income is NOK28.3 billion against NOK47 billion in the previous quarter or in the same quarter last year.

And that is a decline of 40%.

The underlying or adjusted, as we call it, earnings from operations with NOK31.2 billion, which adjusted -- while adjusted earnings after tax stands at NOK9.3 billion, again which is down approximately 40%, 41%.

And the main reason for this decline is, of course, a 31% reduction in liquid prices in Norwegian kroner and 32% reduction in gas prices also in Norwegian kroner compared to the same quarter last year.

This decrease is to some extent countered by higher production volumes.

Equity production is up 8% since the same quarter last year and entitlement production is up 10% quarter-to-quarter.

Gas trading and arbitrage has again contributed positively to the result this quarter.

Our unit production costs have been reduced around 5% on a quarter-to-quarter basis.

And our SG&A costs -- cost saving program are NOK1.5 billion that we have presented earlier for 2009 is now fully implemented.

The reported tax rate this quarter is 79%, while the underlying tax rate is around 70% which is in line with what we have guided you on.

I will come back to both the tax rate and the financials later in my presentation.

But let me now say a few words about the adjusted earnings.

This quarter net operating income is adjusted with NOK2.9 billion from the reported NOK28.3 billion to the adjusted NOK31.2 billion.

The most important adjustment factors are the total impairments of NOK5.3 billion.

As seen in previous quarters we are into the -- what I call the impairment elevator, when it comes to assets in Gulf of Mexico -- in our Gulf of Mexico portfolio.

Assets that are increasing in value are kept in the accounts at maximum, the acquisition costs plus additional CapEx that we have spent, while assets decreasing below the full value will have to be impaired.

The impairments in Gulf of Mexico this quarter is at NOK1.8 billion.

And that derives only from assets within the Spinnaker portfolio, where reservoir characteristics from more than one asset has been poorer than earlier anticipated.

However, the largest part of the NOK5.3 billion impairments is -- comes from our Mongstad refinery as I have already mentioned.

This reflects our more pessimistic outlook for refinery margins at least medium-term, which also led to the impairment of their Kalundborg refinery in Denmark in the previous quarter.

As we mentioned at that point, in August, the value of the Mongstad refinery was also reduced for the same reason.

The stronger Norwegian kroner versus US dollar, or the opposite, has deteriorated the value Mongstad even further, and that has triggered an impairment as mentioned.

Changes in fair value of derivatives, underlift position amounts to negative total adjustments of NOK2.4 billion, and that leads to a net overall adjustment -- adjusted earnings -- adjustments on the earnings from operations of NOK2.9 billion, as I mentioned.

Let's then take a closer look at the production and our volumes for this quarter.

Total equity productions of oil and gas was 1,874,000 barrels per day this quarter and that's up 8%, as I mentioned.

The growth in equity production was driven by a 5% increase on the Norwegian portfolio in total, and a 17% increase on the portfolio outside of the Norwegian Continental Shelf.

Entitlement production was up 10% to 1,712,000 barrels per day.

And this implies production sharing effect -- PSA effect of 163,000 barrels per day this quarter and 139,000 year-to-date.

And this PSA effect this quarter is slightly higher than we have guided.

And that is mainly due to one-off adjustments or a one-off adjustment this quarter as we also had in the previous quarter in the opposite direction.

Our guiding for the PSA effects is however unchanged, at around 140,000 barrels per day at an average oil price of $50 per barrel.

And we have had $53.5 so far this year.

And the sensitivity to higher and lower oil prices is as we have guided before.

The total liquids production was effected by maintenance activities of around 50,000 barrels per day during the quarter.

The third quarter was also the last quarter of the gas year 2008.

Total off-take for gas year 2008 has been more or less in line with what we have seen in previous years, and close to the off-take commitments.

Now with three quarters behind us, we maintain our production guidance of 1,950,000 barrels per day for the full year, although there is still some uncertainty related to gas markets regarding off-take and value optimization.

We will continue to be value driven in our gas business -- in all our business, but definitely also on the gas business.

And that means that our full production capacity might not be utilized at all times.

Our flexible gas production capacity related to Troll and Oseberg is the main tools for us in this context.

Production in 2010 might also be affected by uncertainties related to gas demand.

And also, as earlier communicated, from the fact that new projects are planned to start up rather late in the year.

The production guiding for 2010 will be communicated at the strategy update on February 11 next year.

And now to the adjusted earnings overview.

Our operational performance has been good.

Also in the third quarter maintenance activities have been according to plan and we have had very few incidents which have impacted production in a negative way.

E&P Norway reached adjusted earnings of NOK25.3 billion in the quarter and that is 42% lower than last year.

And the main drivers is 33% in liquids prices in Norwegian kroner and 37% reduction in the gas transfer price towards the Natural Gas business segment.

Oil and Gas production is up 5% while the unit production cost has decreased accordingly.

International E&P had an adjusted earnings of NOK2.8 billion this quarter, which is down 30% compared to last year and the main driver is obviously the lower liquids prices of 22% in Norwegian kroner.

Equity production increased by 17% to 515,000 barrels per day while total entitlement volumes increased by 37% from last year.

Depreciation charges increased within this segment by NOK2 billion and that is due to increased production mainly, combined also with relatively small initial reserve volumes that have been booked from these new fields and also a 14% stronger Norwegian kroner versus US dollar on a quarter-to-quarter basis.

Operating costs within International E&P are increasing somewhat, mainly due to currency impact and increased production.

Natural Gas increased their adjusted earnings from NOK2.2 billion to NOK3.3 billion this quarter.

Processing and Transport was at NOK1.7 billion, which is at approximately the same level as last year.

Marketing and Trading increased their earnings from NOK0.7 billion last year to NOK1.6 billion this quarter, mainly from stronger trading results.

And this demonstrates that we are able and we are in a good position to earn margins from moving volumes both in time and geography also in the current environment.

Manufacturing and Marketing delivered adjusted earnings of NOK0.1 billion compared to NOK2.7 billion last year.

The Oil and Products trading results have been weaker this quarter, mainly because of a more flat forward curve, but also from some specific market positions of use that created some losses.

In addition, the third quarter results was positively influenced last year by a currency gain of approximately NOK1.7 billion, which would not be there any more because we now are running this business in our accounts at the US dollar functional currency.

We didn't do that last year.

Energy and Retail are again showing good progress in a tough environment with their contribution of approximately NOK500 million to the corporate this quarter.

The Manufacturing business continued to show a negative trend with weakening refinery margins and also methanol prices and this is reflected in a loss of NOK0.4 billion this quarter.

And, as already mentioned, the continued negative outlook on the balance between refinery margins and demand also led to the impairment of the Mongstad refinery, as already mentioned.

So all in all, this, our adjusted earnings, added up to NOK31.2 billion this quarter with a corresponding tax cost of NOK21.8 billion, which is equivalent to a tax rate of 70%.

And that takes me to the next illustration, to reconcile the tax costs and also discuss the financial items.

Our reported net operating income had a tax rate of around 72% this quarter.

This can be explained from the starting point of 70%, as I mentioned on the adjusted earnings and 54% on the net adjustment that we have made.

And the low tax rate on the adjustment is explained by the tax rate and the tax position mainly related to the impairments.

Then to the net financial items and the related tax cost; we have earlier on our web site presented this quarter's difference between net financial items according to IFRS and the net financial items used for calculation of tax.

The net financial items for tax purposes this quarter is NOK10.9 billion higher than the reported net financial items under IFRS.

In other words, we have NOK10.9 billion taxable currency gain, mainly from our long-term debt in US dollar this quarter which is not recognized, not reported, as a gain under IFRS.

But we had a corresponding tax cost, as you can see here, of NOK2.9 billion, is recognized and is reported.

We have calculated a 49% tax rate on the reported net income, as you can see, from foreign exchange and interest rate derivatives of aggregate NOK3.5 billion.

And that means that the typical financial items that you can see at the bottom here, such as interest income, paying interest cost, and gain and loss on financial assets has a tax rate of approximately 32%, which is more or less a typical tax rate for these kinds of cost components.

You can also see that when excluding the accounting volatility from the net financials we are left with a result which is very close to zero that you can see at the bottom here.

All in all, this explains the rather high tax rate at first glance of 79% of the reported income before tax this quarter.

I should also mention that the split of the financial items and the corresponding tax on financials, as you see here, is now also reported and will be reported regularly in our MD&A.

Then I would like to talk a little bit about our cash generation as it has been during the three first quarters of this year, year-to-date; it's been quite strong.

This illustration shows you the cash flows from operations before tax during the first nine months, and how this cash flow generation compares with our tax payments and also the CapEx program spending, cash to the CapEx program.

We have indicated earlier cash neutrality before dividend at around $55 per barrel for this year.

And as the average price has been $53.5 so far we are, in fact, slightly on the positive side so far of this guidance.

Net debt to capital employed was at 27% this quarter, which is also in line with the guidance that we have given you.

We have raised around $7 billion of new debt so far this year to withstand the downturn and the volatility that we have seen in the commodity market to maintain high CapEx and exploration program and, at the same time, be able to pay dividend in accordance with our policy.

So let me round up my presentation by taking a quick look at the guidance for 2009.

Production guiding is unchanged at 1,950,000 barrels per day.

The annual CapEx guidance of $13.5 billion, excluding acquisitions and capital leases, to be precise, is also maintained.

The exploration activity for 2009 has been in line with our guidance so far.

The exploration activities in the fourth quarter will bring us up to around 70 wells for the full year and we expect to stay at approximately $2.7 billion in total spending for the full year, also as guided.

The unit production costs are at NOK35.3 per barrel on a 12-month basis and this is consistent with our guidance of staying within the range of NOK33 to NOK36 and we also indicated that we would stay at the upper part of this range for 2009.

So it's as guided.

Guiding for 2010 and beyond will be further addressed at our strategy update on February 11.

And this concludes my presentation and I'll then leave the word to Lars to take us through the Q&A session.

Well, thank you very much, Eldar.

I should just say to the webcast audience we had some problems with the sound in the beginning.

It should be solved now.

If, however, some who haven't got sound still try to refresh your screen and it should be okay.

We'll now start the Q&A session and if you are on the webcast you can ask questions, as I said in the beginning, by using the submit question button and I will get it on my screen here and ask the questions for you.

Here in Oslo, please wait for the microphone and then say your name and state your question.

All right, let's take the first question from Gudmund Isfeldt over there.

Gudman Halle Isfeldt, DnB Nor Markets.

A question regarding cost reductions over the last nine months and as a year-on-year comparison, how much have you reduced your costs in dollar terms, including and excluding ForEx effects?

If you look at this on a quarter-quarter basis, I don't recall the year-to-date numbers, so then on a quarter-quarter basis -- because this is also related to a seasonal activity.

On a quarter-to-quarter basis the operating cost is reduced by approximately NOK800 million.

That's 6% reduction and then I have not adjusted for any currency on that.

But that goes in many parts of the business and it's not all related to the upstream part of the business.

So that also goes into the downstream part of the business.

If you look at the downstream business, our operating costs within the Norwegian Continental Shelf, if you look at the cash operating costs they're approximately at the same level as they were -- nominal level as they were one year ago.

And, in addition, we have increased the production by 5%.

So it's down -- on a unit basis down 5%.

On the International, the operating cost is slightly up for the reasons that I explained.

On SG&A, last year we have changed some accounting policies related to how we consolidate our capital insurance company.

If you adjust for that we are approximately down NOK400 million from a basis of NOK3 billion, so that's more than 10% on a comparable basis compared to last year.

So all in all, this is just to tell you that we have implemented and we see effects from the targets and the efforts that we are doing on the Norwegian Continental Shelf.

It is a challenge to fight a mature province, to put it that way, more water production and you need to really work with the wells.

And maintenance activities, you are fighting that.

And we are through a comprehensive process on the Norwegian Continental Shelf to keep the costs down and we have managed to do that so far.

And we are also on track with our SG&A cost savings program that I talked about of at least NOK1.5 billion annually for this year.

Then we have an additional ambition of NOK1 billion to NOK1.5 billion that we will take into next year's business planning activities.

But we are on track.

Okay.

On my part of the stage here I've been joined the Head of Corporate Accounting, Mr.

Kaare Thomsen, who will join Eldar Saetre in answering the questions.

Let me just take one question from the Internet before I leave the microphone to Trond Omdal and that is from Handelsbanken, from Anne Gjoen.

It's about debt and she talks about if the net debt now is NOK72 billion what is the financial flexibility and risk of change in a credit rating?

Well, we just had a new updated report from both Moody's and Standard & Poor's and they maintain their credit rating based on all the available information that we gave them.

So their view is that we deserve the rating that we have had for some time now.

Our debt ratio is approximately the same level as it was in the previous quarter, although we have actually capitalized the lease in between here, so it's actually down but in accounting terms it's at the same level.

And I think that gives us a robustness and they also obviously look into other factors like cash flows and so on, and they also tell us that we should be able to at least maintain the A rating in the environment that we see ahead of us and we still feel there is uncertainty related to the macro and the commodity environment going forward.

So we are taking that all the time into our account and into the way we plan our business.

And that means that we are not looking at one way of running the business, but we are looking at upside approaches and downside approaches to protect us if things become worse.

I'll finalize the question from Anne and then I'll come back to Trond Omdal in Oslo.

There's so far this year a significant deviation between reported and adjusted EPS with reported EPS as low as NOK3.5 after nine months.

Is it unlikely that you'll pay a special dividend for 2009?

I will not comment special dividends or anything like that.

All I can do in this context is to repeat what we have said.

The dividend policy says 45% to 50% of IFRS as it is reported.

The dividend's policy also says that we can deviate from this starting point if there are good reasons to do that, referring to cash flows and so on.

We have also said that we will take into consideration non-mathematical adjustments, but we will take into consideration that there is the kind of accounting volatility in our numbers that you're referring to and which explains the EPS.

We will take that into consideration.

And the dividend policy says also that we have an ambition to grow ordinary dividend year-on-year.

That's what I can give you for guidance.

Boring, but that's what I can give you on guidance.

So we will take those accounting volatility, as I mentioned, also into due consideration.

Lars Sorensen.

Then it's Trond Omdal.

A couple of questions on project.

In Azerbaijan I see that ACG still not back at the pre-gas leak level and Shah Deniz is lower.

But can you comment on is the Shah Deniz gas level, is that more related to weak gas market?

Or can you not comment on that?

And can you say anything about ACG, that plateau level, will that be back to 1 million very soon?

And then the other is really on Marcellus.

Can you say anything?

How many rigs are currently producing and do you see any ramp up of production over the next six to nine months?

Okay.

When it comes to ACG I think the operator has been doing a very good job in dealing with the gas leakage.

It was shut down and gradually building up.

So I think we will probably -- we still don't have a full understanding of what is going on down there, but it has been dealt with in a good way.

But whether we will get back to 1 million barrels per day on this field, I don't feel confident about that with the given uncertainty that I just talked about.

But there are plans to also pursue further developments on the Chiraq part of this project, for instance.

On Shah Deniz I will not comment.

I will not comment on the arrangement of gas marketing that is going -- [that is formal] reasons on that.

I wouldn't be surprised if it was related to gas market conditions, but I can't comment on that.

On Marcellus we have currently 18 rigs, I think.

18, 20 rigs; I think it's that range, that is operating.

And the plan is to increase the number of rigs to around 40 rigs by 2012.

Current production at Marcellus is around 3,000 barrels per day, I think.

And it will gradually increase as we continue to drill the wells.

So yes, it will definitely increase.

That's the basic idea behind the deal that we have made and our positioning in this market.

But more -- still our guidance is 50,000 barrels per day by 2012, as we have indicated earlier.

Is that following -- are you scaling back probably your operational plans, because of the weak gas market?

Or are you progressing more or less according to plans?

We are progressing as expected.

This is still very early days.

It's very low volumes.

So our view is that we build capacity, build experience, learn our lessons from operating in this environment and also these type of reservoirs and our firm conviction is that also the gas market in the US eventually will pick up and that we should be in a position then with volumes to benefit from that position.

So we don't see the current environment as an indicator that we should reduce our drilling activities.

Okay.

I'll take a couple of questions from the Internet.

There's a lot here on the gas market and on gas as such, so we can just continue where Trond left, basically.

Lucy Haskins from Barclays Capital asks, given the robustness of gas volumes this quarter, why are you nervous about the gas demand impact on next year's volumes?

Well, first of all it's -- in a way we have two different types of gas business.

It's the long-term contracts, which is regulated through contractual arrangements and take-or-pay commitments.

And then it's the -- but there is a lot of flexibility in those contracts during the year as such and that also was why I commented on the fourth quarter this year; how is that flexibility going to be realigned by the customers.

So there is definitely questions in that respect.

When it comes to the more flexible part of our business, which is the short-term, the ones where we sell spot, obviously we are in a position where we have the flexibility to move volumes.

We have seen very weak markets.

We don't see that situation change significantly in the short-term.

We expect actually a continuous situation of weak markets.

For how long, we don't know; but definitely into 2010 and at least a lot of uncertainty around those assumptions.

So with a weak market and if we were to see a market going into the future that looked stronger and more attractive for us, we would like to use the ability to move volumes to the extent we feel comfortable with out in time and move it out of the period where the market is mostly depressed.

So that's why I indicated that it will have volume impacts on the way we run our business, which is a value-driven way of running our business.

That was partly answer to the first question from Oswald Clint also from Bernstein.

But the second question he has is, what are your plans for Troll gas production which seems to be at a five-year low upward level in the third quarter?

Well, the Troll gas production is a wonderful tool for us.

It's in a way what we use to regulate our production and also create confidence that we actually can deliver to our long-term customers on their volumes.

But it also gives us flexibility in terms of the spot gas market and that's basically what we are -- there's no -- the field is as it has been and it's going to be there for many, many years.

So it's basically a way of operating other fields and it's basically the same answer as to the previous question; it depends on the market outlook and the way we look at the markets and how we will operate the gas business.

And that basically also answers the question from James Hubbard here about gas volumes, whether we will continue the strong volumes when Ormen Lange ramps up.

Well, basically Ormen Lange will produce and they will use Troll and also work as swing produces going forward.

There's a question from Iain Reid at Macquarie.

Can you comment on how sustainable you think your gas volume growth is in Europe?

It has been 15% year-on-year in the third quarter.

And when we look at it going into the fourth quarter of the year?

You've partly answered some of it but --

Yes, well the 15% - what they should remember is that there has been -- there is actually an underlying growth in our gas business from last year to this year.

Ormen Lange has been ramping up and so on, so there is an underlying growth in the business as such.

And then you have the seasonal and the take or pay commitments, which also has impacted the third quarter off-takes as such.

And that has given the 15% -- combined the 15% on a quarter-to-quarter basis; the way the commitment has been dealt with by customers and the underlying growing gas business.

Going forward, I think I've touched upon it.

In the fourth quarter, the main uncertainty is related to how the -- our long-term customers will utilize the flexibility that they actually have.

And it's quite a big flexibility on a daily basis.

And then the next level is the annual basis.

So there's a lot of flexibility for how they will utilize that flexibility and also how we will respond to the market environment and the way we look at gas market going forward.

Because Iain actually continues here that gas -- the off-take volumes from Gazprom apparently have gone down, or deliveries from Gazprom have gone down so far and our volumes have gone up, so whether we have expectations to that turning in the fourth quarter.

And I guess you partly --

Yes, what I can say is the underlying gas business it's grown definitely from '08 to '09, but there will not be the same growth from '09 and beyond on the underlying gas business.

And comment on how the Russian gas volumes might impact our business I'm not prepared to do that.

Then there's a question from Mark Bloomfield at Citigroup.

It's about depreciation in the International E&P.

So we're leaving gas for a moment, but I've got more gas questions later.

Could you offer some guidance on the outlook for the depreciation charge in the International E&P segment for 2010?

I cannot give any specific outlooks for 2010.

But the -- it's quite obvious that the direction of DD&A is going to reflect the fact that the cost has increased quite significantly throughout the industry for quite a few years now.

And as those fields who have been hurt by the growing costs is gradually coming into the portfolio that will change the cost profile in terms of depreciations of the overall average portfolio.

So for instance, the Agbami field, the Tahiti field has typically a higher cost per barrel and implicitly also DD&A per barrel than the old fields, the Statfjord, Gullfaks and the Norwegian Continental Shelf, the first development in Angola and so on, so that -- you will see that gradually coming in and into the DD&A.

He asked whether you could use the third quarter depreciation charge as a guideline.

I guess guideline is good, but we can't say --

I cannot -- I can just give you an overall trend-type of guidance here.

Okay.

Next question also from Mark Bloomfield; could you provide some more color on the prospect that will be drilled with your operating rigs in the Gulf of Mexico over the forthcoming six months?

Well, the -- we have two rigs now.

The first one is the Maersk Developer, drilling at the Tucker well, which is --that is operating well these days.

And it will take quite -- this is long, deep, complex well and it takes time.

So over the next six months, I guess, they will not do very much more than that.

And also when it comes to Discoverer Americas, the next rig, other rig, that is now preparing drilling activities at the Krakatoa acreage and that -- so that will be the first drilling target for that rig.

And beyond that, no, we still have time to firm up and have flexibility in terms of priorities as it's a few months ahead until they are moving into other new locations.

Then a question from Argus Media from Roderick Bruce.

It's about PSAs, our production sharing agreements in the International business segment.

Your international production has been impacted by PSA effects.

You are still -- why are you still so high on PSAs when the oil price has fallen?

Okay, then I should -- I just have to repeat the 163,000 barrels per day that we saw this quarter is not reflecting the underlying; it was an adjustment related to assets.

It's difficult calculations to make and to be precise on, so it was an adjustment; actually an adjustment, which was related to the adjustment that we made in the second quarter, which was the other way.

So, on average, forget all of that.

What you could look at is what has been our number for year-to-date, which is 139,000 barrels per day, and that is more a guidance going forward also at -- for this year at least for -- at the oil price of $50.

Then we are given a guidance at an oil price of $75, and that increases from 140,000 on annualized basis, to 165,000 barrels per day on an annualized basis.

So that's also some -- the sensitivity you can also take, it's the same as we have given you before, also apply going forward.

That's the best judgment and guidance that we can give you.

There's a question from Lucy Haskins at Barclay Capital about volumes from the Norwegian Continental Shelf.

Would your drilling program this year give you more or less confidence that you can maintain the NCS volumes out of the end of the next decade?

Well, the drilling program that we have made is -- has been extremely successful.

We have had, at least in terms of discoveries, we have had a discover rate of approximately 80% so far on the Norwegian Continental Shelf, and since the merger, around 70%.

So we have drilled and made a lot of discoveries and we believe almost all of this actually can be developed.

So what is happening now -- and we have also high program for the rest of this year on the Norwegian Continental Shelf.

Next year, the activities will be slightly lower and then we will have to see what happens for 2011.

It's a combination of both infrastructure led exploration and more growth exploration and more frontier exploration.

But it's -- the main focus is on the two first categories.

I think what happened is that we made a lot of discoveries, no big elephants.

Most of this is tied -- can be tied back to existing infrastructure with high-value -- very high-value.

Some of this can justify separate new developments, and we are proceeding now this quarter, for instance, with the new gas development in -- at the Luva area, where there are four discoveries, including the Luva in the deeper parts -- water parts of the Norwegian Sea.

So we will proceed with that, no decision -- no investment decisions made, but we are proceeding with that, meaning that we actually believe it can be a new stand-alone gas development, with new infrastructure actually.

The challenge that we have on the Norwegian Continental Shelf, together with our suppliers, is really to deal with a new type of situation where we do not have the high volume of -- no large stand-along projects that have to be addressed and developed in such a way.

It's a much more smaller development with high value that we have to look at and develop in a different way, with a different approach from what we have been doing; more standardized approach, industrialized approach and also different type of work processes internally in our organization.

So it's a whole new set of challenges.

We have to find new ways of addressing this and I'm confident that we will and if we succeed on that, I think we have actually a very strong resource base, sufficient resource base.

Remember that we have at least 20 years of current production level in our resource base, on the Norwegian Continental Shelf and that that is sufficient to maintain the level going forward.

But it doesn't come by itself, we have to crack the code and find new ways of addressing these new type of challenges.

Okay, we are heading back for the Gulf of Mexico.

There's a question from Oswald Clint of Bernstein's.

Should we expect further farm downs within the Gulf of Mexico acreage positions?

And is there strong appetite for acreage?

And could you update us on development plans for some of your discoveries in the region?

Okay.

When it comes to farm downs, this is the nature of the business in Gulf of Mexico basically.

That you go through lease rounds, you get 100% of a lease and you want to go forward, but you don't -- might not want to take it 100% forward.

So you basically want to share the risk, add also -- add competence from strong partners -- good partners.

This is a very typical way, and this is also the way -- what we have used to get into the Gulf of Mexico to farm into other companies leases.

And now we are in the same situation -- we are more mature situation, so we are basic now farming down from the assets that we would like to see slightly lower exposure on.

So that's what we have been doing.

So we had a deal with Ecopetrol, one deal with CNOOC now and that's -- I think that will continue as part of natural way of doing business in Gulf of Mexico.

Whether we have appetite for more?

Well, we will always -- we are big guys now in Gulf of Mexico and we will always look at opportunities -- good opportunities to leverage, to enhance the position that we have and the competence and organization that we have in the Gulf of Mexico and the technology that we're gradually also developing.

So yes, we will look for further opportunities, but now we have at least a strong, very strong starting point from -- going forward.

When it comes to status on projects, I think we are now drilling.

We have a lot of drilling activities -- Statoil-operated drilling activities going forward.

We -- Tahiti is producing, more or less, at full capacity now, performing very well.

We have had the issues that I mentioned on the Spinnaker portfolio.

When it comes to Caesar Tonga that was approved earlier this year.

so that's proceeding as planned.

And then there are other projects that we are maturing going forward.

But they are not -- and they are getting closer to a point of decision-making, but they are not there yet, but they are being matured.

All the projects that we are involved with in the Paleogene, the Jack, St Malo, Tucker, Julia and so on is progressing as planned, and Bigfoot and so on is also progressing as planned.

So that's more general comment to the other assets.

We have another question from Mark -- or last question from Mark Bloomfield here, also about the Gulf of Mexico.

Could you update us on whether you've got plans to participate in any exploration wells in the De Soto Canyon region in the Gulf of Mexico during 2010?

Well, we have I think, 50 leases through the farming and additional 14 leases, I think, from the lease round.

So we have a quite substantial position in this area now and we think it's quite exciting actually to go into this area.

The detailed drilling plans, I am not -- I could guess but I won't, so I have no specific information as to the exact timing of the first well in this area.

It is probably a little early to expect that in 2010, so.

I think it's a little early, but that would be a guess, but I think it's early.

We have a number of questions on gas.

We take gas field first on Ormen Lange; Paul Spedding, HSBC.

Could you update us on the reserve position at Ormen Lange and comment on whether the recent NPD comments could mean an increased depreciation charge for Statoil, i.e.

are the reserves you used to calculate depreciation still below the level that NPD envisages?

No, the well that has been referred to was obviously a disappointment.

It's related to a segment -- a sub-segment, which is not the ones that we are producing for now, which actually was presented, which is upside to the Ormen Lange.

So basically, what has happened is that it seems to be more challenging than we thought to capture this upside.

It has nothing to do with the reserves that have been booked.

They're not related to this part of the reservoir at all, so it will have no impact on the reserve booking and the depreciations as such.

But it has -- it might be more challenging to get from that the upside that we have hoped for, but it's too early to conclude on that as well.

So additional activities and additional drilling will have to be performed before there's a final conclusion on that.

Okay, we have another question from James Hubbard, also about gas; James from Morgan Stanley.

What are the drivers and risks surrounding the gas customers' decision on off-take from Statoil over the next six months?

Well, I think they have their customers and I would assume they are looking at the same picture that we are looking at where the demand for the gas is quite strong within the residential area.

On the power side, we see that the gas is -- has -- the -- some of the base load has turned into gas from coal.

But that there is this quite weak, 10% to 15%, lower off-take within the industrial segment, which represent approximately 20% of the overall gas market as such.

So I would assume they're listening carefully to what their off-takes are and storage positions and then what their customers want.

And then obviously, they -- the way the contracts are decided, you have a lot of flexibility within the gas year, but at the end of the gas year, flexibility becomes much less.

And it might be that they through the gas year might use some of that flexibility to source gas cheaper in the short-term in spot market.

But that's a situation which they can utilize, but at the end of the gas year, we're still left with a contract as such.

Maybe we should just spend a little time on explaining the gas machine a little bit more, because there's a question here from James Hubbard at Morgan Stanley.

I'm sorry, Jon Rigby at UBS, which goes, can you perhaps discuss why your off-take versus ACQ annual contracted quantity is apparently unaffected by the steep fall in Continental European gas demand?

How should we understand the moving parts that impact this volume, or presumably there's partly a reflection of the very strong first quarter, which was due to weather and the Ukrainian crisis.

A big question.

Well, as I said, the off-take, this has to do with the contractual arrangement and it's not unaffected by the off-take.

At the end of the third quarter this year, that was the end of the 2008 gas year, and basically they have to fulfill their commitments in relation to the contracts.

And that -- what we ended up with at the end of that period was pretty much in line with what we have seen.

There have been just a couple of years, and I recall long time, with these type of contracts where they have significantly taken much more than the commitment volumes.

It varies on temperatures and so on, but -- and it's hard to meet exactly targeted volumes, but it's typically around 90% plus, minus and so on in terms of the ACQ.

And typically, contracts would vary between 85%, 90% of the ACQ as -- depending on which contract you were looking at.

So typically, they would take at the lower 90s.

And this year it's the same pattern that we have seen, so they have not taken substantially more than they had to; they're taking basically what they have to.

Okay.

There's one on the gas market, but let's just leave that for a moment and take a question from John Olaisen at Carnegie in Oslo.

The unit depreciation for the International business was very high in the third quarter.

Is there any particular reason for that, and where will it be going forward?

Well, we discussed that a little bit from the question from Mark, but we can't give any guidance there, but can you give a guidance on the (multiple speakers) --

This is on the unit depreciation?

Sorry, unit production costs.

Okay, I also just touched a little bit on that in the presentation.

It's partly around about 14% depreciation of the US dollar, so most all of it is US dollar, so you take that into Norwegian kroner, you have automatically approximately 14% increase.

Then it's a little bit like you see on the depreciation that it's a portfolio of more expensive fields to run.

So it's basically a depreciation issue and a cost issue on -- depending on the assets that goes into production and goes into the portfolio and the compositional portfolio.

I think that's what I can add to it.

Teodor Nilsen at Argo asks, do you consider any divestments of international assets?

We always do that.

It's natural thing for us to consider.

We have a huge portfolio and to say that that is firm and fixed forever that is not a way of dealing with our portfolio.

So we are always looking -- constantly looking for opportunities to improve, maybe if we have a too higher risk we want to reduce the risk, or we want partners into a project to combine the competence base, to develop another project, that could be a good argument.

It could be doing swap opportunities and so on; so all of them high-grading our portfolio, both our exploration portfolio and our production portfolio that's something that we are looking at.

And so I will definitely not exclude that we will divest.

We could also do acquisition that's the same approach; that we might -- always looking into good opportunities, value-creating opportunities.

But what I can say to the extent that we do divestments it would definitely have to provide more value for us than to hold on to the asset or the ownership in the asset.

So it's not something that we do because we would be desperate for any reasons.

It would be a value-creating to the extent that we do it.

Okay.

Gudmund has a question.

Question regarding Iraq if I may, and southern Iraq.

Do you have any -- are you in a position to get a new field in Iraq, given the situation with BP, Royal Dutch Shell, Exxon and the Chinese companies?

Well, we have been in Iraq, positioning ourselves and working together with the Iraqis for quite a few years now; five, six years we've been there.

We see Iraq as a very exciting, huge, enormous hydrocarbon province.

And the country actually invites companies like us to come and help them to develop these resources, and that's extremely good starting point for any kind of involvement.

So to us with that starting point and with a huge resource base, to exclude Iraq from our way of thinking and our type of Company that would not be wise.

So we entered into the first round of Brownfield developments, and we lost by a margin.

And then we could talk a lot about what are the bidding parameters, and understanding the bidding terms, and how it works and so on.

And we might definitely not have done a good enough job on that.

So I think now, we're into a learning process -- fundamental learning process, to see what have others done, what might we have done wrong, is there anything that we can learn from this.

And we are also looking at potential partnerships that we could proceed with going into the second round, which will be a Greenfield round.

So yes, definitely we are very interested, very much interested in getting a position, and hopefully with an operating position in Iraq.

And we are proceeding, based on that assumption.

I'll take a question from the Internet and then leave the question to Trond afterwards.

It is from Cygnus Asset Management, Luis Amusategui.

You mentioned European gas market as a potential risk.

Could you elaborate on that?

And could you discuss the impact on your Company of the low gas prices in the traded market, and compare this with the long-term contracts?

Do you expect those contracts to be renegotiated?

And what will the overall impact be of that?

Okay.

The low -- the gas market is -- as I said, it's basically now -- we have seen the spot market now and we have all seen variations between the long-term prices and the spot gas prices, that's not very untypical.

But basically, what you see is volatility.

And longer-term, has been a quite strong link between oil related contracts and oil as such and the gas market.

So this is a rather new situation that we, for such a long time, have seen a disconnect between the long-term and the short-term.

And we think this will get back to a more normal situation, but there will still be an oil link in the gas market.

But how long it will take, we don't know.

But we'll definitely address the uncertainty.

Then on this -- on the long-term and our customers, and we hear and see that they express views on their relationship to companies like us.

And I think we'll just have to wait and see.

All I can say is that we have a very good relationship and have discussions quite regularly with all our customers.

So we'll just have to wait and see what will happen on this issue going forward -- potential issue.

There's a follow-up question to this, and then I'll leave it to Trond.

But James Hubbard follows up.

How concerned is Statoil over the threat of increased LNG supplies into Europe next year?

Well, that -- in a way, it doesn't matter.

It's there.

It's coming.

And it's also this quarter additional LNG coming in into the UK, a new capacity.

And there has been some maintenance activities, including our own Snohvit LNG.

So we see this is coming into the global LNG market.

Some of this -- most of it is on long-term contract, but there will be definitely a spillover into the Atlantic basin.

And we see that happening.

And it's quite a substantial volume in total.

So we're talking about 100 bcm, 120 bcm of LNG over the next couple -- two or three years coming into the market.

We see also that this will -- this is a development that will go on until, let's say, around 2012.

And beyond 2012, it will -- there has been no new LNG projects which will push the LNG volumes much more beyond -- and around 2012.

But it's there and it's going to -- so this is one of the factors.

And I would say the other one has to do with the unconventional gas resources and volumes.

That also represents quite a huge capacity, particularly in the US and also the low demand.

So that -- these are the main factors why I talk about the uncertainty and a continued soft gas market at least for the short-term and certainly also to some extent beyond that.

But I don't want to be more time specific as to how long this situation might last.

But it is -- there will be an add to that and there will be a better balance in this market.

We are confident about that.

Now we'll take Trond from Arctic.

Just a follow-up on the Iraq question.

There has been some uncertainty relative to the BP deal on Rumaila.

But yesterday the press release from BP seemed to indicate it's a cost plus or cost plus $2.

Of course, BP had the advantage of doing reservoir studies on that field, and they even discovered it in the '50s; '53.

The fact that you are bidding on fields where you haven't done, as far as being reported at least, these extensive field studies.

Is that a disadvantage?

The other thing is, last time you were only allowed to bid on one -- all of the companies were allowed to bid on one, and you bid on West Qurna.

Now, you can bid on several of them.

Is it -- could you see a scenario where you're actually bidding in different consortias and on different -- on several fields?

Well, I don't think we were not allowed to bid on several fields the previous time, but we bid on one, as you say.

In terms of -- these were Brownfield developments.

And I think it's fair to say that they have been in place and some companies have been looking at this for many years.

And it might be part of the explanation why we didn't -- we were more focusing maybe on the risk elements, going into Brownfield development, than feeling confident about the upside.

So the characteristic, the Brownfield characteristic of these fields in the first round might have been part of the explanation why we missed the way we did.

Now, we are going into a Greenfield round, and that is, I think -- we have been looking at several of these opportunities for some time.

So the most attractive to us are not new to us now.

And I think we were better prepared to address this Greenfield round, as such.

And that should also indicate that we might not be as disadvantaged, if that is what has happened, on a Greenfield situation, compared to a Brownfield situation.

And we might bid on more than one field.

But since you called that Greenfield, it's there like a maximum that's currently producing like 100,000 barrels, it's like 15 billion.

Do you consider that a Greenfield --?

I said it's mainly Greenfields.

There are 10 fields, I think.

That's mainly Greenfields; green development.

Okay.

There is a question here from Bank of America-Merrill Lynch, from Hootan Yazhari.

Can you please comment on the rationale behind farming down the Peregrino asset, as has been highlighted recently?

What other assets are you looking to farm down?

Would you be looking to purchase other assets to replace?

If so, where?

Well, to the extent that we do it, it would have to be value.

There's no other rationale for us than value.

And I think the starting point on Peregrino, and we've been open on this since we acquired the remaining 50% of that, might not be the ideal thing for us to have 100% of a quite substantial and complex project and development like that.

We have a very good understanding of what is going on.

That's going to be there for a long time and 100% might not be the correct one.

It might be other ways of spending some of that value that could create an even stronger portfolio for us.

So I think that is the starting point.

It's no magic to it.

It's just risk and whether we -- and competence.

Is there anybody who can -- to make -- give us combined even better competence to develop around this field?

That would be good and it could take down some of the exposure, and it would give flexibility in the financials to also attract other parts of our portfolio made more aggressively.

So it's not very dramatic and quite straightforward thing for us to do.

And we will do it also in other parts of our portfolio, if it makes sense and adds value.

On other opportunities, I cannot -- I can just give you general comment, but we will always look at portfolio high grading opportunities.

We have a question from Jon Rigby.

Can you remind us what your assumptions are around the refinery impairments?

How does your view on the future compare to history?

And have you created an impairment elevator in the downstream, like you did in the upstream?

Well, basically on the last one, once you have started to impair, you are in -- then you can also take it up to the starting point of the book value.

And you, Kaare, will have to correct me if that is not the case.

So you will probably have more volatility now, as we have started to take it down from the historic cost.

On the reasons why, this has to do with the outlook for refinery margin and it's all -- it's related basically to the economic environment that we see and the demand for those kinds of products, in particular distillates and the configurations of our refineries, and how soon we think that there will be a recovery.

And then there are two types of recoveries; first is to do with the global economy and the demand.

And we think that will come back, at least for the distillates and diesel, gas oil and so on.

I think gasoline might be more permanent situation.

And the other thing that needs to happen is that we need to see something happen with the capacity in the overall refinery industry.

And short-term, actually new capacity is coming in from India and so on.

So it's -- there has to take -- be a restructuring that is going to take place, and it's going to take time before this finds a new equilibrium.

And again, we think it's beyond the short-term; that we are definitely moving into the medium-term before we will find a better balance.

And a couple of questions on projection and project status, from Elizabeth Adams at Dow Jones.

Can you specify which NCS fields you expect to start up in in 2010, and when?

And before you answer that, on our website, from the capital markets update this year and also in the business update that we have updated frequently, there is a list of all the projects that will come into production and also when they will come into production.

So instead of listing all that now, we can just --

We could answer it very briefly.

There are three fields, it's Morvin in the third quarter basically, and Gjoa and Vega in the fourth quarter.

So, of course, Leismer is at the very end of next year in Canada.

But you will find it, as you said.

We've got a question from Elaine Dunphy from Deutsche.

We've got a number of questions from her actually.

Some of them have been answered already.

So I'll just -- just give me a tick here.

Can you -- yes.

To rephrase an earlier question, of the NOK7 billion synergy savings from the merger, what percentage have you achieved to date?

And what percentage of the additional NOK1.5 billion cost savings program for 2009 have you achieved to date?

I think when it comes to the merger, it's -- we promise to come back to that once a year.

And we will do that at our capital markets update in February.

But we are on track, definitely on track.

When it comes to the NOK1.5 billion, we have implemented all measures.

So this spend that you see now is at the rate reflecting the measures that we have taken and it measures on a lot of type of activities, which adds up to this.

And I think you can see it in the SG&A for this quarter.

There's a question on shale gas here, from Rolf Haakensen in Handelsbanken.

Are you happy with your acreage position in the Appalachian or are you looking at increasing your Marcellus position?

Well, it's actually part of the agreement with Chesapeake, to look at expansions of the acreage.

So that is something we are not in big steps but in small steps to continuously look at good acreage and add to the existing portfolio.

So that's something we are doing.

But it has to be of the quality that we would like to see.

So I think that's what I can say.

Our main focus now here is to develop the asset, which is quite substantial.

It's quite a big bite and new business for us, and to learn about this business and also, gradually based on that, to organically further joint venture with Chesapeake to grow the acreage base in this region.

There's a follow-up from Teodor Nilsen.

It's a very specific question -- or very specific questions.

But which initial flow rate have you achieved in the latest wells?

And how much of the 2012 guided position do you expect to come from Marcellus?

Well, when it comes to 2012 we have indicated around 50,000 barrels per day from Marcellus.

On flow rate, we estimated at the acquisition around [3.2 UR].

And I think what we have seen so far is 3.2 plus.

But I will not be more specific on that.

A couple of questions from James Hubbard at Morgan Stanley.

The first one is on NGLs.

It seems like NGL suppressed NGL liquid realization in third quarter.

Do you believe this is a structural issue that will remain the feature of NCS EBIT on a temporary headwind?

Well, the NGLs represent -- in this quarter represented approximately 15% of the total liquid.

And I think that is quite representative actually of what you could expect, at least short-term, going forward.

I think the NGLs had a problem with following the high peaks of the oil price, definitely.

And we also saw that at the lower oil price in the previous quarter that NGL prices were quite weak.

What we have seen this quarter that there is a better link between the oil prices and NGL.

But basically, NGL goes into a totally different segment.

So it's for refineries and for petrochemical industry, so it's totally different customers and users for NGL.

So it has a separate life and so it's very hard to relate it to oil as such.

But it is a component of our liquid on the Norwegian Continental Shelf that will be there for the foreseeable future.

Another question from James Hubbard about E&P.

Can you give us an update of the major growth projects in E&P 2010, and what are their current status?

Are they on schedule?

Are they ahead of schedule or are they slipping?

I mentioned the three projects basically for 2010 as far as I know, and I think I know them.

They're on schedule.

There's no new information on these projects.

The same goes for the Leismer project in Canada.

A question on financing charge from Barclays Capital.

Why do financing charges not seem to be moving up, while gearing relative to year ago levels -- with gearing, sorry, relative to year ago levels?

We've increased debt, but presumably our financing charges don't increase?

Well, the interest rate is -- might not -- but an interest payment might not have increased, now interest rates have been down.

And we have floating interest rates, basically.

So -- and then also, some of our interest cost is being capitalized.

And I don't know the exact proportion.

But what we have said is that the typical interest cost and interest income and asset management typically adds up to zero.

We have guided for some time on that.

And you've seen that on the year-to-date basis, it adds up to 0.1 I think.

So it's almost zero, and 0.3 on a quarterly basis.

So -- but Kaare you might have some additional information, but then I think that's the answer.

We have a question from Matthew Thomas from Morgan Stanley.

And there's a lot of questions basically over the same theme here, which is back to gas and gas customers, and Oftec and so on.

We've answered a lot of that, but let's just take another one, which has a little bit of a different angle, but mainly is the same question that has been answered many times now.

What are your thoughts on the outlook for oil indexation for European gas contracts?

What are the issues of greatest concern among your gas customers?

Are they the price formulas?

Are they the take or pay volume commitments?

Well to the extent they have concerns, they will have to come and talk to us, and we'll just have to wait and see.

But I guess it would -- I wouldn't be surprised if that adds up to the fact that they see a spot market.

And in one way or the other, would like to benefit from what can come out of the spot market.

And that could be a -- various ways for them to approach that issue, but we'll just have to wait and see if that is becoming an issue.

When one talks on oil indexation, I think that question could also be taken into what I addressed earlier, the oil link in more general terms, and whether the spot market will be linked to oil.

And I think you have seen that moving apart now and I think gradually, we will see that there is still a strong case for a strong relationship between oil and gas.

But it's probably weaker than we have seen historically.

There's another question from Cygnus Asset Management, Luis Amusategui.

Do you have any views about the development of unconventional gas in Europe?

Well first of all, it will never be like the US, I think, in terms of resources, but they are definitely there.

And we are looking into these kind of opportunities now.

Some companies have taken positions in these type of resources.

And it's mainly shale resources.

So we are looking in a joint venture with Chesapeake team from -- with Statoil and Chesapeake people, who have been looking for some time now at opportunities in Europe and other places also, outside of the US.

And so far, we haven't concluded on any specific targets that we would -- it's more at the screening stage at this level.

Okay.

I still have some questions on gas, but I think we'll just leave those because they all go on the same theme that you have answered already.

But there's one question from Colin Smith which is about dividend, you've also addressed that but I think we'll take that one more time.

IFRS has got NOK9 billion earnings, or -- sorry, IFRS the first nine months have earnings of NOK10.6 billion, ordinary dividend cost of NOK14 billion to NOK15 billion, payout ratio of 45 to 50 over time.

And it has been above recently.

Gearing is at 27.1.

Would you expect to pay at least the NOK4.4 you paid as ordinary dividend in 2008?

Do you want me to repeat exactly what I said?

To the extent I recall it, but I think this is -- I'll do it just to be precise on this.

As I said we have a dividend policy which is referred to here of 45 to 50 according to IFRS.

There's no change to that it's IFRS.

Then we also have in the policy that we might deviate.

We have a strong record.

We have paid 52% since the merger.

We might deviate based on other factors, such as cash flows, stated clearly in the dividend policy.

We might also, and we will also take into consideration, which we also have said, it's not said in the dividend policy but we have said explicitly, that we will take into consideration the type of accounting volatility that we have seen, the currency impact, which is not reflected in the account as I mentioned in my presentation and other accounting volatility.

We will take that into account but not create a new type of IFRS, to put it that way, which was not an IFRS.

But we will take it into account when we make our judgment.

And we have an ambition, as is also stated, to grow the ordinary dividend year-on-year.

So that's what I can say.

Those components is what we will put together when we make our final decision on the dividend.

And with that ladies and gentlemen we will finalize today's presentation.

Just to remind you that this presentation will be available for replay on the website, statoil.com.

And we will have a transcript of today's presentation also, including the Q&A session also on the website.

With that, thank you very much and goodbye.

This now concludes this conference call.

You may now disconnect your line.