Equinor ASA (EQNR) 2009 Q1 法說會逐字稿

Welcome to StatoilHydro's first quarter 2009 earnings presentation.

It takes place from the Presentation Center, The Brewery, in London and my name is Lars Sorensen, I'm the Head of Investor Relations.

This morning, just before 9 am, we published our results and presentation pack that will be used for this presentation this afternoon.

It can be downloaded from our website statoilhydro.com.

Today's event is followed by, first, the presentation and then a Q&A as usual, and questions can be asked via the Internet which gives me a good moment to say welcome to our webcast audience on the Internet.

You can already now press the submit question button on your screen and your question will be sent in to my PC here in London and I will ask the questions on your behalf.

As you know, safety is of paramount concern to us and I just need to spend a minute on the emergency procedures here at The Brewery in London.

There are two emergency exits here, the one where you came in here will also be used in an emergency; you follow the signs downstairs and outside in the road.

This emergency exit will lead you through a big room and out into the road on the other side.

There are no fire drills planned for today so if the alarm goes off, it is real.

So, today's presentation will be performed by StatoilHydro's Chief Financial Officer, Mr.

Eldar Saetre and with no further ado I'll just give the word to Eldar, please Eldar.

Well, thank you Lars.

Ladies and gentlemen, thank you for joining us at this first quarter presentation.

So my first key, and very important, message today is that the operational performance for StatoilHydro in this first quarter has been very good, like it was in the fourth quarter.

And although the financial results obviously have been significantly impacted by the lower oil price, we have at the same time strengthened the production capacity for the Company quite significantly and this has related both to improved regularities, drilling operations, also improvements.

We have added new fields to our portfolio coming on-stream and we have continued with a strong success rate on exploration.

So, as you know, the current financial and economic crisis has had a significant impact on the oil and gas prices in recent months and despite some recent signals lately, positive signals, indicating a slowdown in the negative trends for the global economy, we are preparing ourselves for a quite slow recovery, and I would say with many ups and downs during this journey.

And consequently we believe also the oil prices could stay relatively low for quite some time, and with some significant temporary setbacks compared to the levels that we see today.

So accepting this rather fundamental uncertainty, it is therefore very key, very important for us, to take this into account in all our business activities and into our planning.

And in this context we also recognize that safe and efficient operations are crucial to our value creation, in particular in the kind of times that we are experiencing currently.

We continue to mature projects, turn them into production.

The Alve and Yttergryta on the Norwegian Continental Shelf have come into production this quarter.

In addition, the Tahiti project in Gulf of Mexico started production last week.

We delivered a plan for development of the Caesar Tonga field in Gulf of Mexico.

And also last week the Norwegian Government approved, at least decided to submit, the PDO to the Norwegian Parliament for final approval of the Goliat development in the northern parts of Norway.

As mentioned, we have delivered a high success rate on exploration and so far this year we have drilled 31 wells and 16 of these have been discoveries; and there are also a substantial number of wells which haven't been concluded yet.

And finally, we have changed the Company structure from January 1 this year and consequently we have to switch to US dollar as the so-called functional currency for three companies in the Group.

That also includes the parent company, StatoilHydro ASA.

And I will cover the accounting effects from these changes later on in my presentation.

Then I will comment on the financial results.

Our reported net operating income was NOK35.5 billion this quarter and this is a decrease of approximately 30% compared to last year.

Income from operations in the first quarter was, of course, affected by more than 50% reduction in the liquids price as much as in the US dollar.

And due to the significant depreciation of the Norwegian krone versus US dollar on a quarter-to-quarter basis, the average price reductions in Norwegian krone for the liquids price was around 40%.

This was partly offset by a 23% increase in average gas prices compared to last year, again in Norwegian krone.

In addition, lifted volumes of oil and gas combined increased by 7% quarter-to-quarter.

And the results from both our gas trading and arbitrage business and our oil trading business have also been very good this quarter.

Then to the net income which was reduced from NOK16 billion to NOK4 billion this quarter.

Negative financial items of NOK3.9 billion contributed obviously to this compared to a positive same number, NOK3.9 billion in the same quarter last year.

The income tax rate which is calculated from the accounts, from the income before taxes in the accounts, was 87% compared to a tax rate of 71% in the first quarter last year.

And I will revert to both of these issues, the financials and the tax rate later in my presentation.

And then I will offer a few comments to the oil and gas production.

Our equity production grew by 26,000 barrels per day from first quarter last year to 2.074 million barrels per day this quarter.

This actually is the highest quarterly production ever for the Group, both on the Norwegian Continental Shelf and outside of Norway.

Entitlement production of liquids was largely unchanged compared to last year at 1.104 million barrels per day.

And gas volumes increased by approximately 4%.

The production guidance that we have given you for 2009 excludes impacts from production quotas imposed by OPEC, and so far this year these impacts have been approximately 13,000 barrels per day for the first quarter.

So we maintain our production guidance for 2009 at an average daily equity production of 1.95 million barrels per day.

However, there are some uncertainties which I would like to mention related to the gas market in the short term.

The gas demand in Europe has already slowed down considerably, which is impacting the volumes sold on long-term take or pay contracts.

Now this is the typical seasonal pattern for the second and for the third quarter of the year but we expect a slowdown in off-take to be somewhat more distinct this summer due to the current recession.

Also, the year liquid gas market seems to be more challenging in the short term, leading to a downward pressure on gas prices in Europe.

And although we are very confident about the role of gas and the potential for gas growth in the longer term, we will definitely at any time seek to maximize value over any kind of volume targets.

And as you know, our oil and gas export systems and our gas fields are flexible and excellently located towards the gas market, which gives us a very good starting position in terms of creating value, even in this environment.

So to conclude, this has been a good quarter with solid operation performance and a high gas off-take.

There are some uncertainties, as mentioned, related to the gas markets but we are on track to meet our 2009 production guidance.

Then I will comment briefly on the adjusted earnings for each of the business areas.

In general, the operational trading activities in all parts of our business has been very good this quarter and this has provided good support also to the adjusted earnings which is at NOK36 billion this quarter, which is 30% down compared to last year.

Before I comment on each of the business areas I would like to summarize the adjustments that we have made to arrive at the underlying earnings of that NOK36 billion as you can see.

The largest component here is coming from net impairments of NOK2.4 billion and it's mainly related to Gulf of Mexico assets.

Derivatives adds up to a negative NOK0.1 billion which consists of minus NOK1.1 billion from the Norwegian E&P Norway portfolio, and a positive effect of NOK0.8 billion related to the Gas business, and NOK0.2 billion related to the oil trading activities.

The net overlift represents NOK0.6 billion and then there are various other effects, adding up to a positive NOK1.4 billion.

And then I should just mention that you will find more details on these adjustments, both in the MD&A and also in the supplementary presentation material that we are providing you with.

Now to each of the business areas, a few comments: E&P Norway reached an adjusted earnings of almost NOK30 billion which is 30% down compared to last year.

And the main driver is obviously the lower oil price, while the internal transfer price for gas from E&P Norway to natural gas, this segment, increased by 23%.

Oil and gas production combined is up 1% while lifted volumes is up 6% and this represents an overlift in the quarter of 46,000 barrels per day for E&P Norway.

The cost development in E&P Norway has been good overall but we do expect the somewhat higher costs related to repairs and a high maintenance activity during this summer.

International E&P had an adjusted earning of NOK0.3 billion this quarter, and that's compared to NOK6.1 billion in the same quarter last year.

And the main reason for this decline is the lower liquids price of 43% in Norwegian krone.

In addition we have seen cost increases and that is mainly coming from the depreciation of the Norwegian krone versus the US dollar of actually 30% on a quarter-to-quarter basis.

So that has impacted the Norwegian krone accounts negatively.

Exploration activities are still maintained at a high level with a NOK2.7 billion in total in the quarter, and NOK1.7 billion has been allocated to the profit and loss statement.

Natural Gas showed an increase in their adjusted earnings from NOK3 billion to NOK5 billion this quarter.

Processing and Transport, that part of the business, increased from NOK1.4 to NOK2 billion, mainly related to higher volumes, and also slightly higher tariff revenues.

While the Marketing and Trading part of the business increased their earnings by NOK1.4 billion to NOK3 billion and this is mainly due to a strong performance within the trading arbitrage activities that we are doing, but also a 4% growth in volumes in this part of the business.

Finally, Manufacturing and Marketing had also a positive development in the quarter from NOK0.2 billion last year, same quarter, to NOK1.6 billion this quarter.

And this improvement comes from our Oil Sales, Trading and Supply business and is entirely related to our crude oil trading activities.

And then I will explain the changes that we have made in the functional currencies before I go into the financial items in more detail.

As we reported at the fourth quarter presentation, and also in the annual report for 2008, StatoilHydro changed the Company structure, the legal structure, from January 1.

Following the merger, StatoilHydro and their ownership to all, or at least all licenses, for both Statoil and Hydro [had] ownership was split into different companies.

That was not sustainable so we had to align that, had to change the legal structure into a more rational set-up.

So as a result of this clean-up and this change process, the parent company, StatoilHydro ASA, and two subsidiaries, now became companies with the underlying business predominantly in the US dollar.

And according to IFRS, the functional currency, the functional accounting currency, of each of these individual companies in the Group has to reflect their underlying business related activity.

And as a consequence we had to change the functional currency for all these three companies but the reporting currency at the Group level, that remains Norwegian krone.

Again, according to IFRS, income tax in the P&L, in the profit and loss reported statement, must be calculated based on the relevant payable tax currency.

For StatoilHydro ASA, the parent company, where the whole financing of the Group external financing also takes place, the tax currency that we pay taxes in, is still Norwegian krone.

And this means that the adjustments we have introduced in functional currency represents no change to the nominal tax rate or the nominal tax calculation and the payment or the way taxes are presented in the profit and loss statement.

So that means that the taxes of NOK27.6 billion that you can see in the accounts, they would have been exactly the same if we hadn't done this change, because Norwegian krone, there's no change in the tax currency as such.

Exactly the same.

However, the relevant basis for the tax calculation, calculating tax cost, is no longer fully reflected in the accounts and specifically in the net financial items.

So the Company's changing functional currency will no longer have currency exchange effects, which is deriving from US dollar denominated monetary assets or liabilities.

And conversely, monetary assets and liabilities, which is still nominated now in other currencies than US dollar, may now generate this type of currency fluctuations in the net financial items.

So according to our announcement last week, approximately NOK10 billion of positive currency impact, which would have been there in the previous case, no longer there.

But still a basis for the cash tax calculation, which is mainly derived from the strengthening of the Norwegian krone versus US dollar in relation to our long term funding of the Group.

This is now included in the basis for the tax calculation but not included in the net financial items, as reported.

In other words, if we hadn't changed the functional currency, this impact of NOK10 billion would have been recorded in the net financial items, with no additional tax to it because the tax is already there.

And this would have led to a reduction in the calculated tax rate, based on the reported income before tax, from 87%, that you can find now, to approximately 66-67%, if this amount had been included.

So to conclude, this change will decrease the volatility of the net financial items.

However, it's important to understand that we do not pay either more or less taxes as a result of this change.

The nominal tax calculation is exactly -- is unaffected, exactly the same as it was before.

And this comment also goes for the financial items.

There are no cash impact on the financial items.

So the only change is actually in the accounting presentation of these numbers.

So that leaves me with the presentation of the net financial items.

So as already mentioned, these are negative.

Loss of NOK3.9 billion this quarter, compared to the same amount positive in the same quarter last year.

And as mentioned, and as a result of this change, the US dollar monetary assets and liabilities, including the long-term debt for the Group, that used to impact this currency component, does not impact this any more.

We see less volatility and we see this already in this quarter, where the net currency effects amounts to a loss of NOK1.5 billion that you can see here.

This item would have been plus NOK8.5 billion, a difference of NOK10 billion, without the changes in the functional currency.

And the NOK1.5 (company corrected after presentation) billion remaining, that you can see here, of currency loss, is now only related to monetary assets and liabilities, denominated in other currencies than US dollar.

Our liquidity swaps that we are doing will still have the same accounting impact as before.

They're in here.

But they will now be derived from the Norwegian krone receivable part of the swap and not from the US dollar liability side of the swap.

The impact will be the same because they've changed currency.

Other factors explaining this NOK1.5 (company corrected after presentation) billion negative currency effect is mainly related to internal monetary assets and liabilities, with no cash impact for the Group.

Then interest and other financial expenses, that you can see here, were NOK2.9 billion in the first quarter.

And this is mainly related -- NOK2 billion of this is related to unrealized derivative loss from our long-term interest rate swaps, where we are swapping into floating interest rates.

Then to conclude my presentation, our guiding for 2009 and 2012 remains the same.

We expect to deliver 1,950,000 barrels per day of equity production this year.

And then, I've already reminded you of the typical seasonal pattern for the Gas business over the next two quarters, and some additional uncertainties that I also mentioned.

I should also mention that we are planning an extensive maintenance activity also this summer, with an impact of around 80,000 barrels per day for the second quarter, for the whole portfolio.

But this is mainly the Norwegian part of the portfolio.

Our Capex and Exploration guidance is unchanged for 2009.

And we also expect to see our unit production costs for 2009 in the higher end of the range of NOK33 to NOK36 that we have indicated for the period up until 2012.

So this concludes my presentation.

Then I should also mention that the next event that we will be hosting is the investor analyst site visit that we will do at the Snohvit LNG facility in the northern part of Norway, on June 15 and 16.

And we hope to see as many of you as possible taking part in that event.

And if you have any questions, we have IR staff, Investor Relations staff, who are ready to answer questions you might have on that event.

So by that, I conclude my presentation and leave the word to Lars, for the Q&A.

Thank you very much.

As usual, we can take questions from both the floor here in London and the Internet.

And that's, as I told in the beginning, you just press the submit question button on your screen and you'll get the question directly into my PC and I'll ask it on your behalf.

Apart from Eldar who's still standing there, we have Kaare Thomsen, who's the Head of Corporate Accounting, with us to answer questions.

And with that, I think we'll just start with our first question.

And HSBC is there.

Paul?

Paul Spedding from HSBC.

Is there anything that prevents you from putting a normalized net income figure in, such that you neutralize some of the quite substantial tax effects that are coming through the P&L?

Well I think what we have done this quarter is actually to provide you with a number for the financials and the impact on the financials from this significant component.

That will be a part of the tax calculation and not included in the statement.

So I think we will have to find one way or another to provide that kind of information and then you might yourself normalize for it, as I've indicated in this.

There are other complexities in going further into the financials and normalizing for that, but at least for this component, I think it's -- we fully recognize the complexity of seeing it from your side and it's in our interest also to find a way of providing you with the relevant information, so that you can see the nature of this impact.

So we will find a way and we'll come back to you on the practical ways of doing that, going forward.

Well, thank you very much.

Just take a question from the Internet and then Ian afterwards.

It's from Anne Gjoen at Handelsbanken in Norway.

Has StatoilHydro considered or is it possible to report in US dollars with all subsidiaries in the same currency as functional currency, and also tax and dividend payments in US dollars?

Well first of all, as I said in my presentation, when it comes to which functional currencies you actually are using, that is depending on the underlying operations, what kind of activities that's actually involved.

So we cannot decide on that and we will have to change the legal structure once more or move the business, to put it that way.

Obviously, the issue of reporting in US dollar, that is something which we have discussed from time to time.

But we still have -- that wouldn't -- I think the short version is that wouldn't have resolved this issue, because that has to do with tax and the basis for tax calculation.

So the only way to -- so how to put it, to resolve this issue is actually to be allowed to pay taxes in the functional currency.

And that's still an issue which -- well, we have discussed it with the tax authorities on a couple of occasions but this is the situation that we have to relate to Norwegian krone tax calculation, tax payment and take that into the accounts.

And this currency impact would not have been included.

It's missing in the parent company and we wouldn't be -- there's no way of taking that into the Group reporting as long as missing there.

It's Iain Reid?

Hello.

Yes, it's Iain Reid from Macquarie.

Two things, Eldar.

Firstly, unlike most of your peers, you haven't made very much about cost cutting so far this year, and certainly not in what you've reported today.

Do you want to say something about your internal targets for this and what you're seeing in terms of the key parts of the operating and development costs?

In particular, the high-end part of the contracting cost, particularly things like deepwater rigs etc?

And the second thing is, I noticed a couple of weeks ago, there was quite a lot said about Shakh Deniz in terms of what looked like a fairly significant delay to first production of Phase II.

Can you say what's going on there?

There's been various comments about the difficulty with getting transportation agreed with the Turks etc.

Is it all bad or is there other issues going on?

And where do you see the volumes actually likely to end up now?

Are they going to come to Western Europe or are they going to go north into the Russian system?

Well first, on the cost side.

I can assure you that there is extensive cost cutting going on in the Company.

We guided on an exploration cost of NOK2.7 billion, which is significantly down compared to the previous year.

NOK13.5 billion of Capex is down.

Then we also underlined that there is limited flexibility in the short-term on the Capex side.

On the operational cost, the targets that we presented you, they include a significant portion of cost cutting.

And in addition to that, we also launched a NOK1.5 billion program on top of the merger synergies that we have communicated a little bit.

Then I should also mention that we are in the process of actually completing the merger synergies where the cost component is a significant part of that.

So I would say there is, in all parts of our business, an extensive cost cutting going on.

When it comes to what we are doing, this has a lot to do with external costs, which is the biggest cost component coming into our cost base.

And we are addressing this, I would say, quite aggressively in terms of development costs, rig costs, we have -- we are renegotiating contracts whenever that is possible.

We are delaying tenders, contract processes, that is in the process.

We have started on a new start and to make sure that the bids are really reflecting the current environment.

We have a dialog with all our suppliers.

Frame contracts are being addressed aggressively.

So I would say we use all kinds of tools at our hand to make sure that the cost base which goes into our Capex and exploration is actually coming into this base and talking this through with all our suppliers.

So -- and we see some signs of this actually happening now in various ways, depending on which kind of suppliers you are talking about.

To the Shah Deniz, I would say the -- I will not comment on any delays.

I would say the timing of this is very much related to the extent that we are able to resolve the issues on export and the transit issues.

And in terms of where this gas might be heading, I think my only comment is that we are -- the most important thing for us is actually to get the highest possible value out of this gas.

And that leaves many options into the opportunity set.

So beyond this, I have no further specific comment to timing and what we believe is realistic now.

It's, I would say the most X factor in this is really the export solutions that we can achieve and the timing of when they are resolved.

Let me just take a couple of questions from the Internet and then James afterwards.

There are a number of questions on tax actually.

And Geoffroy Stern from Cheuvreux and Jason Kenney from ING, and Gordon Gray from Collins Stewart, and Nitin Sharmar from Cazenove all have questions on tax.

So we start with the first one.

Could you please give us a guidance for the reported tax rate in 2009 if oil price was to average $50 a barrel, and assuming stable US dollar Norwegian krone versus first quarter '09?

Well I think the tax rate, the big component that we've talked about this quarter, if we take away that factor, we are still talking about tax rates in the range of 70% for the Group as a whole.

It will depend on a lot of factors.

Oil prices is one of them.

The allocation of revenues between the international part and the Norwegian Continental Shelf results -- earnings from trading activities, both on oil and gas, and so on.

So a lot of components going into this but a typical tax rate excluding these currency impacts, would be in the range of 70%.

But as I said, we will see significant volatility in the way it's reported on the net income before tax going forward.

And there's a follow-up question on that from Nitin Sharma at Cazenove.

Can you explain the very high tax rate of above 90% in the NG segment, Natural Gas segment?

Well I think it is still not 90% but it's a high tax rate.

So maybe you, Kaare, would comment on this?

It's, the tax rate, according to my memory, it's approximately 80%.

And that's -- the main part of that taxed income is from the Norwegian Continental Shelf.

So that takes it up to the marginal tax of 78% and then you get some adjustments which makes it, for this quarter, 80%.

Yes.

There are also some adjustments from previous quarters, which takes it a little bit higher than it typically would be.

Then it is James's turn.

Hi.

James Hubbard from Morgan Stanley.

Just two questions.

International; off higher production and obviously substantially lower pricing environment, the result was much lower than Q1 last year.

But was there anything holding that result back or is there some issues in there that we should think about forecasting that number going forward?

Or was it purely just a pricing effect that brought the figure down to a clean figure of NOK300 million EBIT?

And then secondly, Gulf of Mexico impairments.

Could you say which assets these impairments are related to and whether it was purely because of the low US gas price or is there a reservoir, geologic issue going on here that's causing another impairment?

Okay.

I will say in terms of the International, it's really two components which is explaining all of this.

It has to do with the oil price and the cost increase, which is related to currency.

If you adjusted for this, you would get, on the cost side actually, to approximately the same level as you saw in the same quarter last year.

So it can be explained actually by these two -- obviously, a lot of components, but these are really the two components explaining it.

When it comes to the impairment, I think now we have this situation that once you start to impair an asset, you are in the elevator, to put it that way.

And you simply have to accept what markets and other evaluations as well, where they take you.

So unfortunately, I'm not in a position to be specific as to which asset.

I don't think that would be good for the assets or from a commercial aspect.

But what can I say is that it's a combination.

It's mainly assets which is categorized as exploration assets.

It's a combination of oil prices and also geological reserve issues related to this.

But what I can say, this is -- we have developed a quite significant portfolio in Gulf of Mexico and what happens here is that we do not write up to a higher level of where that was or the historic cost for any assets.

So you get into the elevator but the maximum is still the historic cost in the accounts.

And if you were allowed to put the real value, market value, on this asset in the portfolios into our accounts, I think you would have seen a significant higher value than what can be interpreted from the way the accounts is presented.

Thanks.

We'll take Louise.

Hi.

Can I ask a question on gas pricing?

What percentage of your volumes are sold on spot versus contract in the summer months versus in the winter months in a normal year for weather?

And how did that differ in the first quarter of this year and therefore how did that affect your realizations?

Well I think we tend to say approximately 90% of our portfolio is long-term contracts and approximately 10% -- it might vary, is short-term.

And then, as I indicated, in this situation, in my presentation, there are downward pressures on volumes, on prices, in the current environment, and that might have an impact on the short-term part and the liquid part of the volumes.

So, typically, I would say it's value driven, and I would not be prepared to give any percentages, because then I would go a little bit too far in relation to our actually being an active trader in the market.

But typically, average, year round, talking about that kind of -- 10%, in that range -- and it would be value driven, what kind of volumes that we are taking into the liquid part of the market at any time, whether it's winter or summer.

When you say -- sorry, 10% is value driven, so 10% of your gas sales by value, not by volume?

Well, on the long-term contracts, it's really take or pay contracts.

So the customer decides which volumes they want to take.

There are limitations.

Within those limitations, the customer decides.

So the customer is obviously -- if the customer takes lower volumes, there will be more volumes available for us to sell into the short-term market.

But that goes into the same type of considerations that I had just talked about, in terms of being value driven.

So the 90/10 would be taking the mid-point of your take or pay volume --?

That's -- yes, in that range.

So, typically now you're in the 90 plus/minus take or -- percentage that is taken at any given time, that has been the range that we typically have seen.

But it can vary, to some extent.

And can you give us the figures for the first quarter?

On the take --?

Yes.

Well, the gas off-take has been quite high in the first quarter.

That's what I kept saying.

Okay.

Thanks.

Yes, I'll just follow up with that.

We just need one more question on taxes, then I think we have answered all the questions on tax here.

Can you please quantify if there are any tax effects from the non-operating items in the first Q results?

I have to admit, that didn't -- the only thing which is not included in the accounts, there are minor things which could be included in the tax calculations that are not in the accounts.

But the main component here is the currency impact coming from these US dollar subsidiaries, so it's the currency which is now into the tax calculation.

And beyond that, there's no major issues that I can recall as I speak.

It's Jon Rigby, from UBS.

A couple of things, I do have a question on tax, I'm afraid.

The first one, though, is on gas.

As I understand it, the way your contracts are structured, there's clearly -- your buyers have flexibility around an annual contract quantity, and presumably, given it was a cold winter and Gazprom off-take, or Gazprom supply, was down, you're pretty high up in your pro-rated ACQ for the year.

So what is the downside risk, do you think, as you model a recession through Europe on your contract gas for the rest of the year?

It doesn't need to be precise, but some kind of percentage would be quite useful?

Second is on this whole FX and tax issue.

If it's on a consolidation adjustment, essentially, can't you deal with that through reserves, as opposed to the profit and loss account?

And if it is a timing difference, can't you deal with that through deferred tax, things that are going to come back and forward, and therefore get the profit and loss, and the tax related to that profit and loss, more in line on an on-going basis?

Thanks.

Maybe you, Kaare, will reflect on the last one?

When it comes to the Gas business, I think, as I said, the off-take has been quite high, which they typically are in the fourth quarter and the first quarter of the year, and they have been so also in this quarter.

And, typically the customers will take lower volumes in the second quarter and the third quarter this year, like in any, for seasonal temperature reasons, and so on.

I think the flexibility on the downside to this; obviously, gas prices in the long-term contracts, they will be adjusted according to the oil, the oil prices, three to six months ahead of that.

So, the customers, they will behave accordingly, there is some transparency in terms of what the prices will be in the long-term contracts, going forward.

So they will behave according to their needs and the expected developments in the gas prices, according to these contracts.

So again, that leaves flexibility in our trading activities, and I don't think I can add any further comment to that, except for that we will focus on value, and obviously also a little bit to the future, and see what kind of gas prices the market is offering for the future, and whether it makes sense to do time arbitrage in this context.

But, to the extent that is actually going to happen, I have no further comment except that we do see this pressure, that creates that kind of reflections, and this is business judgment that we have to do in this environment.

And then the second part of the question was --?

We have certainly evaluated all possible alternatives to the treatment which we have landed on.

The treatment which we have landed on is what we view the correct treatment, according to the IFRS accounting principles.

I think to understand it, you might just say that the parent company is a US dollar based company.

The US dollar based company has a liability to pay taxes in Norwegian kroner.

The US dollar has weakened against Norwegian krone, therefore the US dollar company had to pay more US dollar for the same Norwegian krone tax amount, and it comes as a tax cost in the US dollar based company.

That's from the US dollar company's perspective.

That's where you get the discrepancy.

And, to such effects, sometimes it's allowed to take it through the comprehensive income.

That means it doesn't go through the P&L, but straight to the equity.

This is not possible here.

It's a cost for the US dollar company, and they have, as I said, they need more US dollar to pay that liability in Norwegian kroner.

And then, when you consolidate the Group, then I think the questions you raise is reasonable, but the answer is no, we can't do it.

We have to look at it from the parent company and the single company.

I have a couple of questions from the Internet on the natural gas result.

First it's from Oswald Clint from Sanford Bernstein.

Can we assume from the strong natural gas trading result that there were unique opportunities during the first quarter, perhaps related to the Ukraine, which the Company was able to benefit from?

The trading results, as we call it, might give a wrong association, because this is not speculative paper-based trading at all.

It's really based on our physical positions.

It's based on arbitrage, moving volumes between the different geographies.

There are also some bets on the price cuts, we took some fixed price position a couple of years ago.

They are now being realized.

It's not derivatives any more, it's realization of those.

That's the main component which goes into this.

I would say in -- as I said, we have a flexible infrastructure, flexible Gas business, also flexible fields from the Norwegian Continental Shelf, mainly the Troll and Oseberg fields in Norway.

And that gives us an opportunity to grade these values.

But to give any guidance as to whether this was an extreme opportunity or not, I'm not prepared to do that.

But what I can say, basically, the profits that we have made in this quarter, and we also made good profits in the previous quarter, are not due to the Ukraine situation.

It has nothing to do with that at all.

And there's a question a little bit related to this from Jason Kenney at ING.

I note that the high gas sales realization of NOK2.54 per standard cubic meter, the realized price is down only 15% from fourth quarter '08, and it's up from third quarter '08.

What's the expectation for the second quarter, and what's the average lag if the gas price -- sorry, what's the average lag to the gas price contracts?

Well, the average lag is three to six months, and it varies from contract to contract.

Then included in this -- this is an average gas price -- so included in this, we also have the resource of the trading activities that I just talked about.

They are also included in the average gas price of NOK2.54.

And then another question on gas from Hootan Yazhari at Bank of America Merrill Lynch.

To what degree are you seeing impact from lower gas demand in Europe?

Does this pose a risk to your 1.95 million barrels a day production guidance for the year?

Well, it is a component that I talked about in connection with the production guidance.

We said we are still on track to meet our production target, but it is an additional risk to the target.

We will always give priority to values before the target, and to the extent we do that, with a negative impact on volumes, that could -- that increases the risk in relation to the target as such.

But just to repeat, we are on track, as we see it today, we are on track to meet this, but there is uncertainty which is bigger than we typically see, due to the downward pressure that I just mentioned on the Gas business.

Okay, then we move to a question on Capex from Aymeric de Villaret at Societe Generale in Paris.

Capex guidance for 2009 is at $13.5 billion.

Can you tell us at which exchange rate this guidance is made?

Well, as I said first, this guidance is based on the assumption and the fact that most of our Capex is actually coming from US dollar.

As for the exploration costs and the guidance that we gave on exploration, I would say on exploration even more, almost 100% of the cost base is actually coming from US dollar.

So what kind of exchange rate we're using doesn't matter in a way.

And I would say it's such a big component, regarding the CapEx guidance as well, that we haven't put a lot of emphasis to normalize, or make any complex mechanics on the exchange rate assumption as such.

It's based on a reasonable assumption in a range of NOK6 to NOK7 per $1, in that range, and I think we should be able to hold on to the guidance at whatever currency rate we see in that range.

Then he's got two follow up questions.

Does that include any acquisitions?

So I think I can answer no?

No.

No?

Thank you.

And then the last question is, can it be lower due to cost cuttings?

We -- there's always -- there's a lot of projects in our portfolio, and there are cost developments, ups and downs on all of these projects.

And obviously, there are always uncertainties also as to the impact of potential cost reductions in the portfolio as such, although we don't see a lot of that kind of impact coming in this year.

So, I will say it could be higher, it could be lower, but not a major -- I wouldn't expect a major risk associated with that number, to put it that way.

Okay.

Then there are a couple of questions on DD&A and impairments.

The first one is from Oswald Clint from Bernstein.

When can we expect impairments associated with the US Gulf of Mexico assets to stop?

Well, as I said, once you have come into the elevator, we can't stop it in a way.

So then you are exposed to this kind of volatility.

And then there's value enhancements in this portfolio which is quite significant, which is not recorded in the accounts as such.

So, obviously, I cannot give a time as to when this will stop.

It will probably never stop.

We will see some volatility on the assets that we have started the impairments on.

I think you actually answered the next question as well, but we'll take it anyway.

Are these impairments related to shallow waters or deep waters?

Well, we have no shallow waters, that was divested last year so it's all deepwater assets.

Then there is a question from Rahim Karim at Barclay Capital.

Can you please provide some color around the evolution in DD&A charts in the upstream, in particular in the International business?

Well, we have seen a development compared to the previous first quarter last year.

We have seen an increase in the DD&A, that is mainly -- there's a couple of components.

The biggest one I've already mentioned, which is actually the currency.

That almost explains the whole increase.

Then there's also additional volumes, so that increases the DD&A, and also we have a couple of fields, like the Agbami, for instance, where there is initially very low reserves being booked, and then you have to depreciate the whole asset base, based on a very low reserve volume, so that has an impact.

Compared to the previous, the fourth quarter, we see approximately one plus down on the DD&A, and that is also currency, mainly, and also the fact that we are also adding reserves to the basis for the depreciation of assets.

We're actually drilling wells, going forward.

So that has happened in the first quarter, so I think that is the main comments to the International.

Okay, and there's a question about DD&A from Gudmund Isfeldt from DnB NOR in Oslo.

Could you please provide us with some flavor on the depreciation level in the E&P International going forward?

In absolute terms and in dollar per barrel terms?

I think we should be prepared, the fact that there is a lot of new fields coming on-stream, with not the full bookings of the resource base, initially.

That will lead to -- will tend to keep up the certain level of depreciation going forward.

Eventually, the reserves will be booked, and that will take it down again.

But as there are more coming in, and this is the growth part of our portfolio, I think that tends to bring -- keep the depreciation at a certain level.

But to be honest, I haven't prepared any firm directional guidance on DD&A, but that is the main component.

And then obviously currency, which is a big component, since most of this is US dollar, so how this is translated into Norwegian kroner is obviously also an important component.

And finally also production volumes, but that tends to increase going forward, in accordance with our guidance for 2012.

Yes, there's a question from Jon here.

Yes, thanks, just to follow up.

On the cash flow statement, the balance sheet, I was a little surprised about the rise in net debt, and it appears to be a fairly big pull on your cash for working capital this quarter, which given the conditions, seems a bit curious.

So, I just wanted to know, whether there's anything notable in working capital movements this quarter, which is unusual for the quarter, and that we should be aware of?

In fact, I particularly note, the change in the current financial derivative instruments, which I think are NOK12 billion kroner, thanks.

Well, when it comes to the debt position, I can say that we have raised some debt during the first quarter, in March we raised approximately $4 billion, in the European market, in new debt.

Now a lot of that is still cash, by the first quarter, so it's, so there hasn't been a significant movement in the net debt position.

When it comes to working capital, Kaare, I don't know if you're prepared to give anything to that?

You're pointing at derivatives, and there is an NOK11 billion change there, and that's the unrealized part of it.

So, it's not the non-cash part of it, and that of course varies.

It's not derivatives as such, it also consists of realized and unrealized and this is the unrealized part of it.

But the non cash --?

Yes.

And maybe one thing we should state, is that there is actually NOK12 billion, that is, in short-term investments, which means that all deposits, cash deposits, that are tied more than three months, are classified as a short-term investment as well.

And investments in bonds and certificates and so on, which are actually liquid assets, but they are classified as short-term investments.

Under cash flowing from operating activities.

Yes.

And commercially, that's part of our liquidity, and cash management.

Then we had a tax payment on April 1.

James.

Just a very quick question.

Back to this tax issue.

In future presentations are you going to include on perhaps, near the slide that gives all the other one-off adjustments, how much of the reported tax is actually due to the movements in US dollar debts?

This whole situation that you have discussed already.

Yes, obviously we will have to find one way or another, of both communicated, when we get to the actual numbers.

But, also to guide you ahead of that, because there is no way you can see that.

So, whether that will be a calculator, providing you with the opportunity to calculate it yourself, or whether it will be the actual number --

Just the number will be fine.

Okay, I can see that.

Well we will definitely consider that, but in any case we will find an appropriate way of dealing with it, which I hope you will be satisfied with.

Thanks.

And there's a short question on tax again from Neill Morton from MF Global.

The cash flow statement taxes paid on normally very low in the first quarter.

Can you please explain why this is not the case in the first quarter this year?

Is it an early payment, or is it a late payment from a prior period?

It's basically because we've changed the tax payment structure that was changed from August last year.

We now pay taxes every second month, whereas earlier we paid taxes twice a year.

Okay.

We have a couple of questions on Opex from Teodor Sveen Nilsen at Argo Securities and from Neill Morton as well.

The Opex per barrel in the E&P Norway division, declined significantly this quarter.

What are the major drivers for this decline, and how do you expect the Opex per barrel on the NCS to develop over the next quarter?

Well, I think when it comes to the Opex as reported; there are some certain items, which is included in there, like the gas injection cost and also some reversal of -- the partners on the Norwegian Continental Shelf in the fourth quarter last year actually paid back some of the costs, the restructuring costs related to the merger.

So, there are some special items, which we adjust for when we report the total corporate NOK34.1 per barrel production cost.

So I think if you adjust for this, it's still a good development, but it's actually an increase.

So we have seen an increase compared to the previous quarter, and that can mainly be explained by the activity level and also the fact that there is still a cost inflation component getting into the numbers on the operational side.

We haven't been able to take the cost curve down because it takes time to renegotiate contracts and get a lower cost base into the operating costs.

But, as I said, high activity level and high maintenance activities, that's something we should expect also this summer.

There's a short question from John Olaisen from Carnegie in Oslo.

What do you see as your most important high impact exploration wells this summer?

Well, on the Norwegian Continental Shelf, we are drilling around 30-35 wells this year.

We have had a high activity level so far, we have done quite a lot of discoveries, so we mention maybe the most significant one is the Asterix discoveries in the Norwegian Sea, so far.

We will drill more wells, and some of these are -- depends on how you define high impact, but at least they are more than small potential.

So, I would say in particular in the Central Graben area in the North Sea, we have a couple of interesting wells.

And also in the Voring Basin in the Norwegian Sea, there is also a couple of interesting wells being drilled for this summer and during the second half of the year.

And John Olaisen has got another question on production.

The net entitlement in percent of the equity production was at its highest level since 2007.

What's the main reason for that, and how can we expect this ratio to develop going forward?

Well I think the PSA effects that we saw this quarter, at around 140,000 barrels per day is more or less exactly in line with the guidance that we gave at the Capital Markets day.

So, assuming it is USD50 per barrel oil price, this is the kind of level that we should expect to see for this year, so it's exactly as guided.

It's slightly lower, compared to what it has been, that has to do with the level of the oil price.

It also has to do with the fact that some new field is coming in with cost recovery, initially, and also that some of the old fields is actually moving into decline phase.

So, the equity is getting down, so the difference between equity entitlement is getting smaller.

So, and then there is the big portfolio, so there is various types of contract into this, but these are the main components.

I would just repeat the guidance that we gave at the Capital Markets day and I think that is still a valid guidance going into 2012.

Ian has a question here, on the floor.

Yes, Eldar.

In Manufacturing and Marketing, you said, I think, that most of the increase we saw from last year was in trading.

So can we take it that the increase which we saw there, was due to the first quarter contango effect and it's not likely to reoccur?

Well, it's, you're right.

This has a lot to do with the contango effects that we have been able to benefit from, we have possibilities to keep physical volumes out there in the sea, in various locations, and we have benefited from that.

So this is a physical contango play and we have made values from that.

So, I would say in another environment we could see different types of results, but I think historically, we have seen some volatility on the oil trading results.

So, I've said this quarter tends to be maybe on the higher side, at least compared to what we typically have seen.

I'm sorry, one follow-up.

At the last few quarters, you talked about the NGL market in particular being rather weak, relative to Brent, and it depressed your average realized liquids price.

Has there been some recovery in that, in terms of the --?

Yes relatively speaking, there has been some recovery.

So the impact relatively speaking is, the impact is there, and it's still sort of close to 50% of the NCS volumes.

On the liquids volume, it's related to NGL.

So the NGL price is an important part of the average liquid price for us.

But, relatively speaking at this kind of oil price levels, there isn't such a spread that there was at higher levels, down to the NGL prices.

Okay, thanks.

There is a question from Hootan Yazhari at Bank of America-Merrill Lynch which I think we partly have answered, but will just take it one more time.

Your debt and cash levels increased sharply in the first quarter of '09, that was Jon's question as well.

Why have you raised debt, given the strong balance sheet?

Is it indicative of further acquisitions in the near-term?

I just mentioned that we actually on April 1, we have paid a lot of taxes as well, so we pay taxes now six times a year.

And in the second quarter, we actually pay taxes two terms of taxes, and we paid one in the first quarter.

And then we are also getting into a significant dividend payment in the second quarter, so I think you have to take these into account also, when you look specifically at the cash position as it was by the end of the first quarter.

Okay, we're moving to US and US gas prices; we've got a couple of questions on the Marcellus shale gas from Oswald Clint and from Hootan Yazhari.

The first question is since operational regularities instrumental to meeting your production forecast, can you talk about progress at the Marcellus shale assets, and what sort of flow rates per well are you seeing?

Well, I think in terms of the activities and so on, I think we are involved now in around 25 wells, partly horizontal and partly vertical wells.

There are some 10, 11 drill rigs which is now operating in this environment and we expect that to increase to around 20 rigs by the end of this year.

And that is actually slightly higher than we expected at the time we did the acquisition.

When it comes to the performance of the wells, each well is very individual, so I can just give an average type of statement, that they are performing at least as good as we expected at the time we made the acquisition.

So I hope you are pleased with that comment.

Directionally it's positive.

And there is a follow-up question from Hootan on that.

Has the development of the Marcellus acquisition from Chesapeake been delayed, and at what US gas price do you see these assets being profitable now?

Well first of all we mentioned about the activity level, and we are where we should be at least in terms of the activity.

When it comes to the oil price, there are many ways of measuring that, but obviously we see gas price, excuse me, we see an environment now which still makes sense for us to do the drilling activities, it is cheaper than it used to be.

And the location of these assets is also very attractive compared to the demand side and the markets.

So, we still find it justified to continue with the drilling activities, it's still at a very low level, and for us it's important actually to drill wells and increase the capacity as we expect gas prices to increase going forward.

And we want to be able to benefit from that situation.

A couple of questions from the Internet again.

Helge Andre Martinsen from Nordea Markets in Oslo.

Do you see any negative effect of the OPEC production cuts?

Do you see them increasing from the levels seen in the first quarter '09?

I mentioned 13,000 barrels per day which is the average impact in the first quarter production.

And based on what we have heard and noted, so far, we expect this impact to increase somewhat going forward.

But to be more specific about that, I think that is, I haven't got sufficient relevant information to do that.

But the direction again, is an increase compared to the current level.

And there is a very, very specific question from Gordon Gray at Collins Stewart, about the Langeled Pipeline.

The Langeled Pipeline was down last week, can you confirm this was just for routine maintenance and that the pipeline is now back in full operation?

Can you help me on that Lars yourself?

I can't actually.

I know it's back into full operation, but I don't know why it went down to be honest.

I don't know either, so we'll just have to come back to that.

The last question on the Internet I have now is from Helge Andre Martinsen at Nordea again.

Can you quantify the effect of exchange rates on the value of commercial inventories for M&M Oil Trading, Sales and Supply?

Was that on the currency?

On the exchange rate effect on the value of commercial inventories?

Well I think the -- there is a component of that included in the numbers.

But it's not a very significant component.

It's included in the -- I haven't got an exact number, but it's not a very significant component of the results earnings from the Oil Trading business.

But I haven't got the exact numbers on that.

No and also the conversion to US dollar as a functional currency, reduced that effect which we have seen previously.

So that the trading is -- have now functional currency, US dollar trading in the parent company.

So it's just commerce or storage in other than the parent company which have a currency impact, so that's very much reduced, I think it's in the level of a couple of hundred million.

This was the last question from the Internet, and apparently there are no more questions from the floor.

I just want to remind you that this webcast can be replayed from our Internet site, statoilhydro.com and there will be a transcript available on the same website in due course, in a couple of days.

Then I would like again to remind you again about the site visit in June, June 15 and 16, where we are seeing our Snohvit field in Northern Norway, and you are very welcome, and we have invitations if somebody hasn't got that already.

And with those words, I will just say thank you very much and goodbye.