Equinor ASA (EQNR) 2010 Q1 法說會逐字稿

Welcome to Statoil's First Quarter 2010 Earnings Presentation.

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

Today's presentation can be found on statoil.com and downloaded from this website.

Questions from viewers on the web can be, as usual, sent in using the Submit Question button on your screen.

Without further ado, it's my privilege to welcome today's speaker, Executive Vice President and Chief Financial Officer, Eldar Saetre.

Thank you, Lars and thank you to all of you for joining us at this First Quarter Earnings Presentation.

And not surprisingly, the first quarter has been like many quarters before, strongly influenced by the macro environment and this is illustrated by the positive signs of recovery that we have seen in the global economy, especially in the United States and in China; also by the issues that we have experienced within the euro zone and the prevailing volatility in the financial markets; and last but not least for our industry, the rising oil prices and demand which is mainly driven from Asia.

It's a pleasure for me once again to present a quarter with generally good operational performance for Statoil; a solid production, good trading results which I will refer to, and the continued strict cost discipline.

And they're all contributing to good financial performance in actually all of our business areas this quarter.

On top of this, we have also made good industrial progress.

We have enforced our gas value chain in the U.S., both through increasing the Marcellus acreage and strengthening the market access.

The exploration activity continues to deliver high value and we have matured the resource base further by approving and sanctioning six new projects this quarter.

So let me start by looking at the financial results for the quarter.

Statoil delivered a net income of NOK 11.1 billion, which is compared to NOK 4 billion in the same quarter last year.

And there are three main explanations to this positive development.

First of all, we have had much higher earnings from our international E&P business segment.

Secondly, the losses on net financial items have been lower this quarter compared to last year.

And finally, we have had a significantly lower reported tax rate in this quarter.

And the main drivers have been the continued recovery of the oil price of around 48% since the first quarter last year and this is measured in Norwegian kroner.

This was partially offset by a decrease in the gas price of 35%.

I should also mention that despite the lower gas price that we have seen, we have sustained solid earnings from our gas trading business which I will come back to.

Statoil's first quarter reported net operating income was NOK 39.6 billion, which is compared to NOK 35.5 billion last year.

The adjusted earnings were NOK 38.9 billion which implies adjustments this quarter of a moderate NOK 0.7 billion.

Adjusted earnings after tax were NOK 12.1 billion which is up 14% compared to last year.

And the effective tax rate on the adjusted earnings, that is excluding tax on net financial items, was 69%.

I will revert to the results for each of the business areas later in the presentation.

So let me now say a few words about the oil and gas production.

Total equity production reached 2,102,000 barrels per day in the quarter, which is up 28,000 barrels compared to the same quarter last year and this represents actually a record high production for the group, as such, on a quarterly basis.

And this record was driven by a 13% increase in the equity production outside the Norwegian continental shelf and partly offset by a 2% reduction in Norway.

The growing production outside Norway was mainly driven by the startup last year of the Tahiti and the Thunder Hawk fields in the Gulf of Mexico, the ramp up of Agbami in Nigeria and increased production from ACG in Azerbaijan and also from Marcellus in the U.S.

The decrease in the Norwegian liquids production was explained by the expected decline on the mature fields in Norway and again, this was partially offset by Kvitebjorn being back in full production last year and also new production from the Alve field and the Tyrihans field since last summer.

The customer off take on our long term gas contracts has been high in the first quarter and this is due to relatively cold weather, as you know, in most of our core markets.

The entitlement production was down 1% at 1,915,000 barrels per day and this implies PSA effects of 187,000 barrels per day between the equity and the entitlement volumes which is slightly above our guiding of 180,000 barrels per day at a $75 oil price which by the way is unchanged from what we had presented earlier.

I will now go into the results from each of the business areas briefly, starting with E&P Norway which reached adjusted earnings of NOK 29.1 billion this quarter which is 2% down from last year.

The main drivers for this change were a 46% increase in the liquids price which added NOK 9.5 billion to last year's result and a 41% lower transfer price of gas towards the natural gas business segment which contributed negatively with NOK 9.2 billion.

And the oil and gas production, the lower oil and gas production had a negative effect of NOK 1 billion.

Operating cost in Norway increased by 4% in nominal terms, mainly due to as I mentioned new capacity from Alve and Tyrihans and also combined with high-volume actually well maintenance and well related activities in this quarter.

The reduction in exploration activity from last year also led to that NOK 0.3 billion reduction in exploration expenses.

The international E&P segment had adjusted earnings of NOK 4.5 billion which is considerably up from the NOK 0.3 billion last year.

Most of this NOK 4 billion of the improvement is caused by the 54% increase in the liquids prices again in Norwegian kroner.

Entitlement; production increased by 5% while total equity production increased by 13% to 557,000 barrels per day, which again is a record high production of our production outside of Norway.

The increase in operating expenses of NOK 0.4 billion was driven by the higher production volume as such, and again driven by new capacity coming on stream.

In addition, we have had more fields in preparation phase; preparation for production; and this is mainly driven by the high impact activities we have from Leismer in Canada and Peregrino in Brazil.

I should also mention that royalty payments have also increased of relation to our offshore Canada operations by approximately NOK 200 million this quarter compared to last year.

From the first quarter last year, we also had a 23% reduction in the SG&A costs within the international segment of which 15% is explained by the currency development and the rest 8% is driven by cost saving on our cost-saving program.

Natural gas had adjusted earnings of NOK 4.6 billion this quarter compared against NOK 5 billion last year.

Net operating income from processing and transport; that part of the business was NOK 1.7 billion which is down from NOK 2 billion last year.

And this was mainly driven by lower tariff revenues from temporarily reduced capacity at Karsto which is by the way now back at full capacity.

Also in this quarter and despite lower gas prices in general, we have been able to sustain a high level of earnings from our flexible gas marketing and trading; the marketing and trading part of the business which is on par with last year at NOK 2.9 billion.

We have realized an average gas price in all our markets, volume weighted average during the first quarter was NOK 1.64 per standard cubic meter; and this equals $7.3 per million BTU.

So the good results from our gas business are due to the following reasons.

First of all, a solid long-term gas contract portfolio with a substantial component of oil indexation intact; combined with the high gas off take in the first quarter from our customers and also the very good opportunities that we have to move gas, both in time and in geography from the flexible infrastructure to capture arbitrage opportunities.

And finally, our last business segment, manufacturing and marketing delivered adjusted earnings of NOK 0.9 billion in the quarter compared to NOK 1.6 billion last year.

The adjusted earnings within our oil trading business were NOK 0.6 billion and this is compared to NOK 1.2 billion last year.

And then I should remind you that the first quarter of 2009 had an exceptionally steep contango curve ahead of them, and while trading results this quarter are driven by a flattened contango price structure compared with what we saw last year, one year ago.

Adjusted earnings within the manufacturing part of this business were zero; that is the methanol production and the refineries and this is compared to NOK 0.2 billion in the same quarter last year.

And this decrease is mainly due to lower refinery margins in Norwegian kroner which was partly offset by higher methanol prices.

Adjusted earnings in energy and retail were NOK 0.4 billion in the first quarter which is compared to NOK 0.2 billion in the same quarter last year.

And the increase was largely due to higher volumes and higher fuel margins.

So all in all, our adjusted earnings added up to NOK 38.9 billion, as I mentioned, which is 8% higher than we saw in the same quarter last year.

And the corresponding tax rate was 69% which is in line I think with the guiding that we had given you earlier.

Then a few comments also to our cash flow and our financial situation; this illustration shows our cash flow movements during the first quarter.

As you can see, Statoil generated again a strong cash flow from our operations of NOK 50 billion, approximately.

Taxes paid in the quarter amounted to NOK 13 billion.

And then I have to mention that we have paid only one tax payment this quarter and we pay six of them during the year.

So next quarter, we'll include two tax payments compared to this quarter's one single tax payment in Norway.

In addition, the dividends for 2009 of NOK 19 billion will be paid on the second of June; obviously subject to AGM approval.

Our investments are progressing according to plans with a net spending of around NOK 19 billion in the quarter.

And as you can see, our net debt to capital ratio at the end of the first quarter was at nearly 26% and we expect this ratio to be slightly reduced towards the end of the year, given the current level of oil and gas prices for the rest of 2010.

And now let me say a few words about how we continue to move new barrels through the value chain and the activities in that context for this quarter.

As highlighted at our strategy update in February in London, we have a substantial resource base of approximately 22 billion barrels.

And our main focus is now on maturing this portfolio, improving the overall capital efficiency and reducing breakeven prices through optimal scoping- technical scopes of these projects, leveraging our technology base and also sourcing and organizing the projects in the most cost-efficient manner.

In the first three months of this year, we have sanctioned five new projects on the Norwegian continental shelf.

Two of these projects, the Kristin Q template and the Njord Northwest flank, have been developed through the so-called fast-track capital efficiency program which we have talked about on the Norwegian continental shelf, which aims to reduce the cost and increase the speed of development in relation to our substantial portfolio of small to medium-sized projects on the Norwegian continental shelf.

So we have started on this program and these are the two first results that we have delivered and the focus is, as we talked about earlier, on standardization and industrialization as the main approach to enhance these developments.

In addition, we have sanctioned the Gudrun and the Marulk projects and as you might have noted, we have also now agreed the way forward with our partners on the Valemon project in the North Sea.

These projects are all important steps, important projects to maintain the production level on the Norwegian continental shelf.

Outside NCS, we also sanctioned Chirag oil project in Azerbaijan.

So that adds up to six projects.

In 2010, we will maintain a high level of exploration activity, although slightly lower than we have seen over the last couple of years.

And past year success on exploration continues so far in 2010.

So far we have announced seven discoveries; four on the Norwegian continental shelf and three outside of Norway.

And among those the sidetrack of the promising-- the Vito discovery in Mexico, I should mention that.

We consider that to be a promising development; and also the recent discovery close to the Nona field, the so-called Fossekall development which might support a longer life for our Norne field.

So let me then conclude the presentation by just confirming our guiding for 2009 and '12.

The short version is that there is no change to the guiding.

Our equity production is expected to be in the range of 1,925,000 to 1,975,000 barrels per day oil equivalent, in that range this year; and between 2.1 to 2.2 billion in 2012.

Our production in the first quarter has been more or less as expected.

However, significant uncertainties about the gas markets remain as we head into the summer season where off take; the seasonal off take is traditionally lower.

And on top of the seasonal variations, we also expect to see challenging gas markets in the near term due to the supply overhang situation that we see and we are prepared to defer gas volumes to the extent necessary, focusing on value creation more than volume targets as such.

In addition, second quarter marked the start of the comprehensive turnaround season on the Norwegian continental shelf and although the majority by far will be carried out in the third quarter, we expect around 30,000 barrels per day in quarterly effect in relation to maintenance activities in the second quarter.

And for the full year, we estimate an impact of around 50,000 barrels per day.

So that there will be a lot of maintenance in the third quarter.

There is no change to our guided unit production cost of NOK 35 to NOK 36 per barrel for this year.

And we also maintain our capex guiding of $13 billion.

And finally, on the exploration, we expect to drill and complete around 50 wells at a cost of $2.3 billion this year.

So with these remarks, I leave the word back to you, Lars.

Thank you very much, Eldar.

We'll now start the Q&A and let me just repeat for the audience on the Internet that you can send in a question to me by pressing the Submit Question button on your screen.

I'll start with a question from the Internet and then you can think about whether you've got any questions from Oslo here.

I'll take one- I'll take two questions; I'll take one question from two people, actually- Jason Kenney and Iain Reid both wonder-- what impact have you seen and what impact do you expect from the Transocean Deepwater Horizon incident in the Gulf of Mexico at the moment?

Well I think what we have seen no impact directly into our activities so far.

The only impact is basically that we have offered our services and advice to assist in the current situation.

In terms of our ongoing drilling activities, we are drilling on two wells in the Gulf of Mexico; two exploration wells and have two rigs in operation.

They are drilling as according to plans and we obviously have reviewed our activities one more to be sure that it's safe to proceed with the operations and that's the conclusion, so we are proceeding with the drilling activities and explorations as such.

So that's the short term.

Longer term, it's an industry question, really and I would be surprised if there were no consequences coming out of an event like this.

But I think the main-- before it's possible to say anything firm about that, I think it's necessary to get sort of deeper into and understand the causes that has led to the current situation and see the full consequences of that and I would be surprised if there were no consequences.

I think our future activities will be scrutinized based on what has happened, and I also think that obviously based on events like this, all kinds of requirements will be gone through by the authorities.

But that's just speculation, but that's the kind of consequences that you could imagine.

And potentially also that's sort of the process of opening up new possibilities for the industry as such might also be more-- take more time.

Thank you.

There are a couple of questions about maintenance.

I think you already told us that the effect was 50,000 barrels a day on an annual basis and the second quarter effect was 35,000 barrels in the quarter.

So let's just repeat that.

But then there's a question from [Elaine Donfe] who asks-- can you tell us what volumes were lost in the first quarter due to maintenance and I guess that's pretty--

Yes, it's very low volumes really.

So I think we're talking about 8,000 barrels per day and the split is around 50/50 within the Norwegian continental shelf and the international maintenance activity; so very low activity level in relation to maintenance this quarter.

And Elaine just wants to continue on that subject-- that wants to be sure that the 50,000 barrels estimated turnaround was included in our production guidance of 1,925,000 to 1,975,000.

That's included; yes.

Good.

Then there's a question from John Olaissen from Carnegie in Oslo here on gas.

Does the strong first quarter gas sales give some room for upside in the 2010 production guidance?

I think basically it has been a strong off take situation, but that's typically also what we see in the first quarter.

So basically in the first quarter, we are producing as much gas as we can because that's basically what the customers want.

So I don't think you should read what has happened in the first quarter as an indication in terms of where we will sort of come out in the range.

It's more or less as expected, slightly on the strong side but not very much different from what we typically see in the first quarters.

And I could just generally repeat the uncertainties that we are facing.

We are now moving into a different situation and the supply overhang and the supply and demand balance that we have talked about for is still there.

We don't see any fundamental changes to that and are prepared to more our volumes and focus on value creation in our gas marketing activities and also repeat what we said about the turnaround activities.

Okay, there's a question on gas again from Iain Reid.

How much NCS or gas from the Norwegian continental shelf was sold outside the long-term contracts this quarter?

Well, I haven't got that number to be honest.

But typically, the off take in relation to our long-term contracts has represented a much higher proportion in the first quarter.

But the exact split, I haven't got that split and I'm not able to sort of give you a number on that at present.

We can take the last question from Iain Reid.

Can you update us on the sale of 40% of Peregrino?

When should we expect this and how will it affect the 2012 production target?

You know in terms of a potential sale or whatever; I'm not prepared to give any comments.

If I started with the practice on that, it would take us in the wrong direction I think.

So I'm not prepared to give any comments other than to say that typically owning 100% of an asset is not necessarily an ideal situation, so divesting a part of this asset is an option for us.

But I'm not prepared to comment anything more specific than that.

Then there's a question from James Hubbard at Morgan Stanley.

Can you say what West Qurna 2 contracts are currently out for tender?

What other major contracts need to be tendered and what are the risks that the project delays occur due to ongoing Iraq political uncertainty?

In terms of contracts and specific details on contracts and tendering, I think what we have to do in that case is to refer to the Operator which is Lukoil.

In terms of implications from sort of the political situation and the election situation in Iraq and implications on the projects; it's impossible for me to speculate and I would never start speculating about anything like that.

But we are proceeding with the project as fast as we can and are now focusing on setting up the project and putting up the organization that can move this project forward as speedily as possible.

Thank you.

I'll take the last question from Elaine Dunphy from Deutsche Bank.

It's about the Norwegian continental shelf and the production volumes there.

Oil volumes on the NCS were down 55,000 barrels per day or 7% year on year on natural decline or measures to maintain reservoir pressure and operating issues.

Can you tell us how much was driven by operating issues and how should we be considering oil production on the NCS through the rest of the year?

First of all, the decline-- this represents approximately 6% to 6.5% year on year on the liquid side.

We have guided on an average decline rate of around 5%, not splitting between oil and gas, but we indicate that oil fields typically will have a higher decline rate than the gas fields, as such.

And the other component which goes more into sort of the portfolio considerations is when new capacity is coming in.

And in this case we have had two new fields coming in last summer who were ramping up; and they are combined oil and gas production.

So basically we have not had sufficient new capacity to compensate for the decline this year.

We've put a lot of measures into fighting the decline and both for utilizing sort of the existing infrastructure and that goes back to the fast track approach that I talked about.

We have a lot of smaller discoveries in Norway which now are speeding up, tying into existing infrastructure.

And it's obviously all the IOR measures that we are putting in to fight the decline.

So our approach and our ambition is to maintain the overall oil and gas production on the Norwegian continental shelf for the next 10 years at approximately the current levels.

There is no change and what we see this quarter has no implication whatsoever.

This is expected for that ambition and gradually, as we move forward, oil production will be replaced by gas production.

Thank you.

There's a question about tax rates from Irene Himona at Exane BNP Paribas.

The 69% tax rate in the first quarter was unexpectedly low.

Could you please provide guidance for the full year 2010 and the likely tax rate and discuss once again the reasons for the low first-quarter level?

Well basically I think our guiding is pretty much around 70%.

That's what we have said as an average.

We have indicated the Norwegian continental shelf at around 74% and that's exactly what it was this quarter.

We have indicated the gas business at around 70%, slightly lower this quarter.

So there were slightly more revenues on the gas business on onshore taxation this quarter that might be typical, but not significant; so that might explain why we are below 70%, to put it that way.

The international tax percent is around 43% and we have guided at 40% to 45% so it's right in the middle.

And the downstream is that 30% we should also spot on according to what we have indicated earlier.

So pretty much the tax rate this quarter is maybe slightly lower, but not much compared to what you should expect going forward.

But there will be significant variances on the reported tax rate because of the functional currency that is now in U.S.

dollars for the holding company while the tax is still in Norwegian kroner calculation.

So you will see differences for those reasons.

But based on the adjusted number and tax on adjusted numbers, this is the kind of tax rate-- the 70% to 72% that you should see going forward.

Thank you.

Then we have a question from Oswald Clint at Bernstein.

Can you quantify the impact of natural gas earnings in the first quarter 2010 from new long-term contracts and from the new structure incorporating the higher level of spot prices?

Well I'm not aware of any new contracts, actually coming into effect in the first quarter.

We have talked earlier about the renegotiations and discussions we have had with some of our customers regarding the price structures and how we split the volume of some of the long-term contracts between oil indexation and gas indexation.

And we have indicated that we have moved a tranch of some of these contracts from oil indexation to the spot market pricing.

And that has had effect from this quarter and that effect is included in the average gas price of 1.64 that we have reported.

And basically I think, Rune Bjornson, who is the Head of our Natural Gas division at the Capital Markets update in February-- he was clear that it was actually-- we basically took out volumes of the existing contracts as a temporary measure.

But the actual contract will not change.

So the terms and conditions on the contracts are the same and then we've taken out small volume charges that we have either let the customer decide-- either you can get it at spot prices or we can sell it in the spot market and you won't take the gas then.

So it's a measure of restructuring the volume a little bit in this market situation.

And we've been able to keep up earnings in the gas business quite handsomely this quarter.

There's a question from Hootan Yazhari at the Bank of America/Merrill Lynch.

Is the 7% decline in Norwegian oil production indicative of worsening decline rates in the portfolio?

Does it make you nervous of your longer-term aspirations to keep production flat in Norway?

Well I think the exact number is 6.5% and as I said, it's as expected.

So this has more to do with the decline on gas and oil field is higher than gas fields and higher than the average.

So this has more to do with sort of the sequencing and when new capacity is coming in.

But the underlying decline from the major fields that are declining is not behaving anything different than what we have expected them to do in this quarter.

A question from Rahim Karim at Barclays Capital.

Can you help us understand the finance charge?

With the net debt of 75.3 after adjustments, the finance charge is so low; any guidance for the full year?

Can you talk about the-- that's another question.

So-- can you help us understand the finance charge with net debt of 75.3 after adjustments-- why was the finance charge so low?

It's-- I think we have a table in the MD&A where we show-- try to explain what is happening with the finance charge.

And I agree; if you look at the net debt, the interest payment cost should be higher than what is reported.

The reason for this has to do with the interest rate derivatives because we are-- we are swapping some of our debt, some of our interest exposure into floating interest rates.

And that means that it's a swap which is accounted for in our accounts market to market.

And since the interest rate has gone down slightly in this quarter, that has given a market-to-market benefit of approximately NOK 1.1 billion in the quarter which goes into the interest rate calculation and presentation as you see it in the accounts.

So if you adjust for that, the interest rate is approximately-- or the interest cost is approximately NOK 1.2 billion and NOK 0.5 billion to NOK 0.6 billion of that is interest rates as such and NOK 0.67 is accretion which is basically related to the removal cost and the annual sort of appreciate of the removal cost.

So it's a good question, but there is an explanation and I think it's given in the MD&A documentation.

And then we'll just take Rahim's next question; you talked about the weather, improving the upside to the realizations.

Can you talk about how you expect this to evolve, assuming a stable Henry Hub price?

That must be the temperature on gas price I guess he's alluding to.

You talked about the weather improving upside to the realizations.

Can you talk about how you expect this to evolve, assuming a stable Henry Hub price?

Do you understand the question?

Not really.

I think we have to ask Rayim to repeat it and then I can take somebody else.

But basically obviously the temperatures as heating is an important sort of segment in the gas market-- so heating and residential demand represents approximately 50% of the gas demand.

So that has obviously a big impact and it's very much depending on the temperature.

And it has been a cold winter and we are moving into a different season, but to state explicitly sort of the effect of that single component on the gas price going forward; I think the gas market is something where we have to look at all of the components as such and it's hard to single out any specific effects.

A couple of more questions from Oswald Clint at Bernstein.

Can you provide some indication whether exploration activity within the disputed zone with Russia could be seen in the near term after the recent discussion?

Or is it still at a political level?

Well, first of all we are very pleased with this settlement that appears to be emerging.

But we also accept that it will take time.

It has to go through a ratification process and there might be details, for what we know, that need to be put in place and the ratification process which we are very optimistic will be dealt with quite soon.

And then there's a long process to mature these seismic activities and political processes supporting and leading up to sort of more type of drilling and licensing activities.

So it's a long journey ahead of us in this area but obviously it's extremely interesting for us to hopefully be given the opportunity to take a closer look at this acreage because everything we see from outside the acreage points in the direction that it's a very interesting and attractive (inaudible).

Next question from Oswald Clint; can you update us on the buyback program you talked about in the fourth quarter results?

Well the buyback program is something which we have said is part of our toolbox.

It's stated specifically in our dividend policy that buybacks are something that we might use.

And I think to avoid any speculation as to whether we will intend to use it or not, it's something that we intend to ask for the AGM and every AGM going forward so it's in place.

It's a part of the toolbox because we have typically an AGM and can do this only once a year.

And I think it's prudent to put the mandate in place so it's an effective part of the toolbox that can be activated in the case that that situation should emerge.

But it should not be seen as that there are specific plans to use a buyback program as such.

It's putting a mandate in place as an integrated part of the dividend policy.

(Inaudible) we don't have mandate right now, but we have applied to the AGM for a mandate on the 19th of May.

Yes, that's true, Lars.

Thank you.

The last question from Oswald; you talked about the quality of the oil in the Vito discovery.

Can you talk about the quality of the reservoir?

This is operated by Shell and typically in these kinds of instances we leave these kinds of sort of use flow on Vito to Shell.

So all I know expressed today was that we think it's interesting and we have a 25% stake in Vito and it's something that we hope can be--create the basis for a new development.

But it's early to say, but we are optimistic as far as we see.

But more specifics-- we leave to Shell to provide news on that.

And there's a question from a private shareholder; at least somebody who hasn't put in a company here Morten Fjaereide.

Is the future growth to come from internal growth in exploration-- both on the NCS and internationally-- or is that aiming more on M&A activities?

All the growth that we have talked about going into 2012 is based on organic activities coming from exploration assets that are in our portfolio for the time being.

And we are also-- in February after our strategy update, we also presented this comprehensive portfolio of assets which pointed at growth also beyond 2012, although we did not indicate any more specifics and try to quantify that growth.

So all these statements and these strategies are based on organic developments and the assets that we have and the prospects that we and exploration opportunities that we have in our portfolio.

That does not mean that the Company would stop looking at inorganic opportunities.

That wouldn't be prudent for management to do so.

We will always look at those kinds of opportunities as to the extent we find them attractive for creating shareholder value we would look into it.

But the strategy and the main focus is now to mature the strong resource base and all we have said on growth ambitions going forward is based on that.

Right.

There's a question from Kim Fustier at Credit Suisse.

Could you talk about the recent progress you've made on beefing up your gas trading capabilities in Europe and the U.S.

and can you give us some color on the gas arbitrage opportunities you're seeing currently?

I think we have gradually over time now, strengthened and built our organization on the gas trading side; both in Europe-- in Norway and the U.K.

but also in the U.S.

based on the gas resources through Cove point, from LNG, from the Gulf of Mexico and now also shale gas.

So we have also built the quite substantial gas trading business in the U.S.; built systems, competence, people, knowledge and a more comprehensive trading portfolio with more flexibility to it and we are also strengthening this through adding storage capacity and so on, Alborough in the U.K.

So gradually there will be a build of infrastructure, competence and our people resources to this business.

And we have also developed it further in terms of what's integrating our long-term business and the short-term trading business; so to optimize these two legs of our gas marketing business.

And the idea is basically to use the flexibility that we have in our trading system.

We have several landing points into the continental and the U.K.

gas markets.

We have also several sources into the U.S.

trading hubs, as I mentioned; and to move volumes in time and geography, arbitraging through utilizing this whenever we see opportunities.

And I should also mention that we have on the Norwegian continental shelf, substantial flexibility; in particular on the Troll field and the Oseberg field which is actually storage.

We can keep the gas in the reservoirs without paying for expensive storage to other places and use that volume flexibility as well and we also have LNG flexibility in the trading portfolio, as we now add Snohvit into the portfolio.

So these are gradually the components and how we have developed this business.

And I think we have proven over some quarters now that we have been able to sustain a reasonable robust level of earnings.

That doesn't mean that it's not going to be volatile.

You will see ups and downs but there are no major components of speculative mandates, to put it that way, in our gas trading.

This is base load trading.

There's a question from Orlando Finzi at M&G Investments.

Does the expected gas market weakness for the rest of 2010 impact the rate or the level of your CapEx plans in 2010 and beyond?

No.

The CapEx plans for '10 and '12 is going according to plan and our financial planning and capability to go on with the program from a financial perspective is robust in relation to whatever gas price development we might see.

So we don't see any developments in the gas market short term that might have any impact on our investment program as such.

A question from Christine Tiscareno at Standard & Poor's.

Should we expect more deals to deliver natural gas from Marcellus or are you covered for the moment on your upcoming Marcellus production?

That was the first question.

Should we expect more deals to deliver natural gas from Marcellus or are you covered for the moment on your upcoming Marcellus production?

Well, as I said, we have strength in this system.

We have added approximately 10% to the acreage, in line with the agreement that we have with Chesapeake.

So basically when Chesapeake adds acreage to Marsalis, we are given the opportunity to participate into that acreage and that's something we do on a regular basis with smaller chunks.

And what we did now was to pull some of this together into a bigger bite, so representing approximately 10% of the current acreage.

And as I said, this is an integrated part of the agreement with Chesapeake and we will pursue those kinds of opportunities to add high quality acreage to our current position, also going forward.

There's a further question from Christine which is about the Gulf of Mexico.

How will delays in the Gulf of Mexico drilling affect your production plans-- I guess for 2010?

But the for 2010 and the production for 2012 that we have guided on will not be affected by this drilling of course because there's no--

We don't see any effects on the production at least from what we have seen of impact so far.

A couple of more questions left; Barry McCarthy at the Royal of Scotland-- what were the reasons for the Board's preference for partial IPO of energy and retail over alternatives such as a full exit by a sale to a trade buyer or perhaps financial investor which might be less dependent upon market conditions?

I think it's a decision process in the Board concluding that there is a realistic outcome is the partial IPO.

This has to do with the capacity; lack of capacity in the market and the fact that we in any case will be tied very much to the E&R through support agreements and supply agreements before we sort of can cut all the ties.

And I think it's also important that Statoil shows support to the new company through that kind of ownership and make sure that sort of we have faith in the new company and also are willing to invest and keep a share in the new company going forward.

And then we take it from there going forward.

Another question from Trond Omdal at Arctic Securities in Oslo about Peregrino.

He asks about our considerations regarding maintaining 100% and I think you already said that-- that we always consider whether owning 100% for the lifetime of a project is right.

But then he asks about project status for Peregrino.

Well Peregrino is moving forward as planned.

We had some issues and had to wait for right weather conditions.

There are two jackets in place and we had to lift the modules on top of that; on both these platforms the A and B.

And eventually, weather conditions turned out positive and nice to us so now all the modules are in place on both the Peregrino A and the Peregrino B.

So now all activities are moving on and there is no change to the time schedules because obviously we cater for some flexibility in this respect, so we expect Peregrino to be in production early next year.

We've got two more questions left; one from Nadia Bendress at Focus Bank in Norway.

What is the share of gas sales linked to long-term contracts and what's the average duration of these contracts and what is the remaining average duration of the contracts?

The first one on the oil?

First of all, how much gas did we sell were linked to gas?

As I said, the main part of our gas volume is still linked to long-term contracts and of the long-term contacts, the main part is still linked to oil.

So approximately 25% to 30% of our total volume including what goes beyond the long-term contracts and typically on an annual basis its linked to oil.

It's linked to gas, and 75% linked to oil.

Sorry, thank you, Lars.

And so in terms of contract length, obviously some of these contracts have been in place for quite some time.

They are getting older.

So in the next decade we are getting into situations where some of these contracts are running out.

But to be specific in terms of averages, I haven't calculated it in that respect.

I think Rune Bjornson, the Head of Natural Gas, in February he said that the first contracts-- really long-term contract they were sort 25 to 35 years when they were entered into and the first one of those will start expiring in sort of 2017 and the last ones in 2029-ish; in that range.

But we haven't really quantified how much is where, but these are long-term contracts really.

Last question I have here is from John Rigby at UBS.

Obviously kroner/U.S.

dollar was less volatile in the first quarter.

But even so the FX/IFRS adjustments look very small.

Is it a net of many movements or is it explained by reduced FX only or have you changed some of your underlying interpretation of the accounting policy?

No, there are no changes to the accounting policy.

Basically the main part of this is related to the exchange that we have most of our revenues in U.S.

dollar, but we pay taxes and dividends in Norwegian kroner- a lot of it.

So basically we exchange into Norwegian kroner to the extent necessary and then we swap back into U.S.

dollar because we don't need the Norwegian currency on a running basis.

So this swap is accounted for on a market-to-market basis and what is in the accounts is the Norwegian kroner part of that swap compared to the U.S.

dollar functional currency that we have.

So that represents a loss of 2.5 billion, reflecting a currency difference of I think approximately 4%.

That's the main part.

There's also these kinds of components of functional currency, but the main component is related to the swap from U.S.

dollar to the Norwegian kroner and there's no change to the practices.

Okay.

I don't see any more questions from Oslo and there are no more questions on the Internet.

So for me there's only left to say thank you very much for participating and good bye.