Equinor ASA (EQNR) 2010 Q2 法說會逐字稿

This morning at 7.30 a.m.

Central European time, we announced our results for the second quarter 2010.

A press release on the results was sent through wires and to the Oslo Stock Exchange.

The quarterly report and today's presentation can, as usual, be downloaded from our website, Statoil.com.

On the front page of Statoil.com, there is a link directly to the presentation pack.

Can I ask you please to take special note of our use of forward-looking statements, which are described on the last page of the presentation set?

After the presentation, we will open for questions.

Please observe that you will have to use a phone line to ask questions.

Questions cannot be asked directly from the Web.

The dial-in number is on the website.

The operator of this conference call will revert to a procedure of asking questions over the phone immediately before the Q&A session starts after the presentation.

It is then my privilege to welcome Statoil's Chief Financial Officer, Eldar Saetre, who will now take us through the second-quarter earnings presentation.

Thank you, Lars.

Good afternoon, ladies and gentlemen and welcome to the second-quarter earnings presentation for Statoil.

After a promising start of 2010, we have now seen yet another challenging quarter regarding both the global economy and financial markets.

And we have been reminded that great uncertainties still remain when it comes to the pace of the world economic recovery.

However, Statoil has delivered another set of good results this quarter.

Operationally, we have had a strong quarter with high production despite the shutdown of the production on the Gullfaks C platform, which, by the way, came back onstream on July 14.

We are also getting closer to production starts on a number of new fields.

Amongst them is the Gjoa field, which you can see being towed out to the field on the front page of this presentation.

We continued our exploration efforts and have made several new discoveries also in this quarter.

Our flexible gas strategy has created significant values by moving volumes from last summer and mainly placing them on the forward curve at considerably higher prices.

Finally, we have had higher than usual impact from noncash provisions this quarter, which is seen as infrequent and outside of our underlying operations.

We have made a cost provision in connection with an onerous contract related to the Cove Point LNG regasification terminal in the US of NOK3.8 billion this quarter.

In addition, the market outlooks for our Mongstad refinery have worsened and we have decided to take an impairment of NOK2.9 billion in the quarter.

And now some words about our second-quarter earnings.

Here, you see an overview of our key earnings figures compared with the same quarter last year, which is illustrated at the bottom here.

Our reported net income amounted to NOK3.1 billion compared to zero in the second quarter of last year.

I should then remind you that the reported second-quarter results last year was quite exceptional due to a 99% tax rate deriving from the change that we made to USD as functional currency while the tax basis is still being calculated in Norwegian kroner.

The reported net operating income is NOK26.6 billion against NOK24.3 billion last year, which is a 10% increase year on year.

When focusing on the underlying business performance, we derive at the net-adjusted result of NOK36.4 billion in the quarter and this is a 25% increase over last year's NOK29.2 billion.

The main contributors were the 32% higher liquids price in Norwegian kronercombined with the 2% increase in entitlement production and this was partly offset by a 12% decrease in average natural gas prices.

The adjustments of NOK9.8 billion were mainly caused by natural gas derivative losses, by the provision related to the Cove Point.

Both of these were in natural gas and the impairment of the Mongstad refinery, which I mentioned within manufacturing and marketing.

The reported tax rate this quarter was 88%.

After adjustments for the effects of tax on infrequent items and net financial items, our effective tax rate on adjusted earnings amounts to 71%, which is in line with our guidance.

Now let's turn to the production numbers for the quarter.

Total equity production was 1.957 million barrels per day this quarter.

This implies 6% growth over last year.

The growth primarily came from increasing gas production, which was up 14% while the overall liquids production was up 1%.

Volumes from the Norwegian Continental Shelf increased by 6% while equity volumes from outside of Norway grew by 5% this quarter.

Entitlement volumes increased by 2% to 1,765,000 barrels per day.

This means that PSA effects, so-called PSA effects were 192,000 barrels per day in the second quarter and this is compared to 116,000 barrels per day the year before.

The increase was mainly due to changes in profit tranches for some Angolan fields and also some one-off positive PSA adjustments that we made in the second quarter of last year.

Gas equity volumes increased by 14%.

On the Norwegian Continental Shelf, the 15% decrease was related mainly to higher gas offtake on our long-term contracts and also higher spot volumes due to higher NBP prices this summer.

Outside Norway, the 10% increase in gas production mainly came from higher volumes from In Salah in Algeria and the ramp-up of production in the Marcellus area in the US.

We are now well into the final quarter of the European gas year.

Traditionally, the third quarter is a relatively weak quarter in terms of offtake and we have no indications that this quarter will differ from this typical seasonal pattern we have seen previously.

And neither should you forget that our gas production remains value-driven, so we will continue to use the flexibility in our gas field, which is mainly Troll and Oseberg where this creates value.

So let me then move to the results per each of our business areas.

High activity, strong operations and higher oil prices have been the main characteristics of this quarter.

This has been translated into adjusted earnings, as mentioned, that are 25% higher than last year.

E&P Norway had adjusted earnings of NOK29.1 billion in the quarter, which is 40% up year on year.

The main reasons were higher liquids prices up 32% measured in Norwegian kroner, as well as a 6% higher production volume.

And this increase was partly offset by a lower gas transfer price.

Depreciation has increased by 9% in E&P Norway due to increased production and also higher depreciation from the new fields.

Both operating expenses, SG&A expenses and exploration expenses were lower than last year in this business segment.

International E&P's adjusted earnings grew by 3.5% to NOK2.9 billion in this quarter.

Higher liquids prices contributed positively to the results.

This was partly offset by lower entitlement volumes due to the relatively large variations that we saw in PSA effects.

Adjusted exploration expenses outside NCS were NOK2.4 billion compared to NOK1 billion last year.

The increase was, to some extent, explained by more costly and higher ownership shares in general, but, by far, the main cause is related to the expensing of one individual well deemed to be noncommercial in the Gulf of Mexico.

Natural gas adjusted results were NOK3.3 billion, which is down 21% from last year.

The subsegment Processing and Transport's adjusted earnings were flat year on year at NOK1.8 billion.

Adjusted earnings in the Marketing and Trading subsegment were at NOK1.5 billion, which is down 38% compared to last year.

This is mainly driven by normal variations in our gas trading business.

I will shortly come back to a further discussion of the Natural Gas business.

Manufacturing and Marketing, their adjusted earnings were at NOK0.7 billion, which is down 47% compared to the second quarter last year.

The trading results were significantly lower this quarter as forward curves flattened out and also from some losses related to the price drops, the price drops that we saw during May.

Within Manufacturing, an increase in both refining margins and methanol prices contributed to the earnings of NOK0.1 billion compared to last year's loss of NOK0.5 billion.

Within Energy and Retail, mainly higher fuel margins caused a 50% increase in adjusted earnings to NOK0.6 billion.

Despite the improving refinery margins that we saw in the second quarter, the outlook for our Mongstad refinery has not improved.

This refinery is a net importer of fuel oil combined with a relatively lower share of diesel output compared to a standard FCC refinery.

And all of this configuration has been beneficial for the refinery for many years.

We now see a situation where it's a tighter market and consequently higher price outlook for fuel oil and consequently lower margins at Mongstad.

This has led us to take an impairment on the refinery of NOK2.9 billion this quarter.

As promised, I will now address our Natural Gas business in slightly more detail.

Both short-term and forward European gas prices have increased significantly during this quarter.

Spot prices are also significantly higher than we saw last summer when we decided to move gas volumes beyond 2009.

On the other hand, our long-term oil index gas contracts are showing slightly lower prices this quarter compared to the same quarter last year due to the approximately six-month time lag in the pricing formula.

So my first point in this context is to remind you that any changes in gas market prices are reflected in the E&P Norway business segment and not in the natural gas business segment as the mix of all these market prices is the foundation for the transfer price between these two business areas.

My second point is that our flexible and value-driven gas strategy is still highly valid and has created significant value to us.

Last summer, we observed prices of around 20 pence to 25 pence per therm while the summer of 2010, at that time, was priced up to 40 pence per therm.

By using the flexibility that I mentioned in the upstream portfolio, we decided not to produce some of this flexibility last year, but instead sell the volume this summer or in later years.

And also placing most of these volumes on the much higher forward curve.

Through this strategy, we have increased the value significantly from these volumes.

Thirdly and as a consequence of using the forward curve, we are also accepting noncash mark-to-market, or derivative effects, in our accounts as the forward curve is moving up or down.

In the second quarter, we have had a negative derivative impact of NOK3.4 billion in the gas business, mainly related to this flex strategy, but also to other hedging strategies.

While we, in previous quarters and actually in the four quarters in a row now, have had positive derivative effects from our gas trading business.

Finally, we have concluded to make a cost provision this quarter in connection with our commitment related to the Cove Point LNG regas terminal of NOK3.8 billion.

This was a position that we entered into in 2004 when it was anticipated that the US would need to import significant gas volumes in the years to come.

The rapid development of unconventional gas production in the US has reduced the need for import of LNG significantly and the consequence is a lower expected utilization of the regasification capacity at Cove Point.

So all in all and despite the negative face value of our natural gas business segment this quarter, we are still creating considerable values from our gas trading business with a major part of it reflected in the E&P Norway business segment.

And we will maintain our value over volume strategy also going forward.

And then finally some words on our guiding.

We maintain our production guidance for 2010 at the range between 1.925 million to 1.975 million barrels per day for 2010 compared to the first half of this year.

We expect equity production to fall due to extensive turnarounds in the third quarter of around 120,000 barrels per day in quarterly effects.

Startup of new fields will mainly take place in the fourth quarter and there are no new startups internationally this year.

In addition, uncertainty related to the short-term gas market still prevails with the third quarter typically as our weakest gas quarter.

CapEx guidance for 2010 is still at $13 billion.

Exploration expenditures are $2.3 billion and unit production cost is expected in the range of NOK35 to NOK36 and it was at NOK35.2 over the last 12 months period.

Regarding 2012, we recently announced a farmdown of 40% in the Peregrino field in Brazil through the partnership with Sinochem.

The direct implication was that we adjusted our 2012 equity production accordingly.

So with these words, I am ready to take your questions and I leave the word back to Lars to manage this sequence.

Thank you very much, Eldar.

We will now start the Q&A session.

In addition to Eldar Saetre and myself here in Oslo, we are joined in the studio by the head of Corporate Accounting, Mr.

Kaare Thomsen.

In order to be able to ask questions, you will have to dial into the phone conference.

The dial-in numbers are available on our website.

And operator, would you please go through the procedure for asking questions in the conference call?

(Operator Instructions).

Jason Kenney, ING.

Hi there and thanks for taking my question.

Where do you see the net debt to capital employed figure going through the next two quarters and essentially by the year-end?

And secondly, could you give us an indication of the cost of the drilling moratorium in the US Gulf of Mexico.

You do note it, in text form at least, in your quarterly release.

And I was wondering if Statoil will be looking to recover that cost in time and if so, who from?

Okay.

On the net debt to capital employed, that was -- that ratio was at 29% at the end of the third quarter.

And that included also the full payment of the dividend of NOK19 billion as we are paying dividends only once a year.

So that is included in the net debt and has an impact on the cash position.

So just to give you a few comments.

If for instance we had paid dividends twice a year, which is not allowed in Norway, the net debt ratio would have been approximately 29%.

And we have also had a negative effect from US dollar/Norwegian kroner exchange rate during the first half of the year and that has had an impact of approximately 2%.

So it would have been around 24%, 25% if we had adjusted for these components.

Now still, this is a fact.

We have seen these changes in the currency exchange rate, the US dollar/Norwegian kroner and obviously to estimate the impact and how this ratio will develop for the rest of the year is quite difficult.

It will depend on these factors.

It will depend on the downstream profit on the gas results, but obviously also on the oil price.

But given sort of the current environment, we expect to see -- and the current type of exchange rate, we would expect to see a ratio quite close to 25%, maybe slightly higher than that, but not significantly higher than that.

So 25% plus something, in that range, that is the best estimate I can give you currently.

Then to the Gulf of Mexico and the costs related to that.

Obviously, there is a lot of discussion we can come back to on the more long-term implications, but short term, this is really about managing the rig portfolio and we have -- we were in the process of drilling five wells.

Two of them were Statoil-operated and we participated in three other wells.

So -- and these were exploration wells.

So the activities on these drilling activities have been closed down.

So in our case, we have declared force majeure on these contracts and are paying lower rates, but there are still costs associated with this and there is no drilling being made.

Obviously, what we are doing is to look thoroughly into other ways of employing our rigs, but so far, these rigs are still in the Gulf of Mexico, in the area.

So the cost to us -- first of all, we have made no provision in the accounts.

There is no onerous contracts that should be provided for.

So we will take any costs that are coming as it turns out.

And the estimate we have given is around $100 million assuming that the moratorium will last for six months.

$100 million, maybe slightly higher, but not significantly higher.

So that is the best estimate we have given.

As I said, we are working together with our contractors to deal with this issue and also together with our contractors to see how these rigs can be employed in other parts of the world to the extent that that can be done to mitigate the situation to the benefit both for Statoil and our contractors.

Would you look to recover that cost in time?

Well, we have declared force majeure and that is regulated.

The force majeure rate is regulated in the contract.

So as long as we are paying force majeure rate.

That is the rate that we are obliged to pay according to the contract.

So the way to mitigate that is basically to make sure that these rigs eventually can get back into business, either in the Gulf of Mexico or in other parts of the world.

Okay, thanks.

Jack Moore, Harpswell Capital.

Good morning.

I was wondering if you could talk a bit about just tax rate going forward and what you anticipate for taxes and I guess production sharing as well.

Okay.

Well, when it comes to taxes, there is no -- I mean we always see variations in the tax rate and segment tax rate from quarter to quarter.

But when we get to the bottom of -- and also just variations because of the tax that we have and US dollar as functional currency and we still have this issue that we are paying taxes, calculated taxes in Norwegian kroner, which is also included in the tax cost in the accounts.

But the accounts is not reflecting the Norwegian kroner pretax basis.

So we will have variations due to that, but if you sort of take away that impact and get down to the underlying operations, the normal operations, we are still -- there is no change to our guidance of around 70%, 71% tax rate going forward.

In the previous quarter, that was I think 69%.

Now it was at 71%.

So we are sort of in that range and there is no reason for us to change the guidance on tax based on what we have seen in this quarter.

When it comes to PSA effects, we have a PSA effect of 190,000 per day in this quarter and we saw a very low one in the same quarter last year.

So there will be variances on a quarter-to-quarter basis.

There will be adjustments, but overall we maintain our guiding.

So for the full year at around $75 per barrel for the full year, we still indicate around 180-185,000 barrels per day in PSA effects.

So no change to that, but what we have seen is that there are variations in this number.

Great.

And then just one follow-up question.

I was wondering if you could discuss any potential kind of tactical changes you might make in your CapEx in the medium to near term to perhaps reallocate resources either away from the Gulf or oil versus gas or any other strategic moves that you might make.

I think the first, whether it is an operational or tactical change, I don't know, but as I mentioned, we will have to make sure that we employ our rig fleet in the most efficient way.

So that could lead sort of to higher exploration activities outside of the US and lower exploration activities inside the US.

That will not impact sort of the short-term CapEx program or production profile as such.

And beyond that, I am not prepared to sort of -- we have taken no conclusions and we have had no reason to make any judgment or take any conclusions in relation to changing our strategy.

I think what we -- what we will have to do is to simply wait what will be the consequences in terms of regulations both in the US and potentially also in other parts of the world coming from the incident and then we just have to be patient and wait for that and the result and what really caused this incident.

So far, we have found no reason to make any changes in our strategy to deepwater activities either in Norway or in the Gulf of Mexico and other parts of the world or make any reallocations of our investments.

So we will just have to wait and see to the extent there are coming sort of things out of this which might cause that kind of changes, but at this stage, I have no reason to expect that.

This is still sort of the core of our competence.

This is where we are coming from, offshore operations and deepwater operations.

So I think we should still be considered to be a good and prudent operator in this type of environment.

I think it will still be allowed to operate within this type of environment and our relative competitive position should still be very good in this context.

I agree.

And thanks for taking my questions.

Oswald Clint, Sanford Bernstein.

Yes, hi.

Thank you.

The first question I guess may be linked to that last one about capital allocation and just back in the Marcellus, is there anything differently going on at the moment in terms of your drilling pattern there?

Are you still expecting to increase rigs and wells per quarter going forward and any slowdown in activity and still economically viable at the gas price you are receiving in that particular area?

And then secondly, I'm just curious on the Shah Deniz renegotiations on that contract, what the new gas price is that you are receiving for that gas and is that the same formula or gas price available for the second phase of Shah Deniz.

And if you could, you talked about the transit through Turkey, what type of tariff the Turkish -- that the Turkish were looking for for transit across Turkey?

Thank you.

Okay, when it comes to Marcellus, we are planning or Chesapeake is planning to increase the number of rigs.

We, at the start of this year, we had 19 rigs in operation.

Currently, we have 26 rigs, 25-26 rigs in operation and the plan is to increase this number towards the end of the year and continues to increase it to around 40 rigs by 2012.

So there is no change to the way we look at it.

It is still sort of a, for us, a small part of the portfolio.

It is rather small volume.

We are talking about 10,000 plus barrels per day in gas production from Marcellus.

We think it is still -- it is a profitable business even in today's environment.

And we think, given the small scale of it, it is the right thing to do to build the capacity, be prepared so that we expect sort of gas prices to improve going forward.

When it comes to Shah Deniz, I am not -- first of all, I'd say we are very pleased that the Turkish and the Azerbaijan government have come to an agreement both on the existing contract and on the arrangement for the next phase of Shah Deniz, both the transit arrangements and the sales arrangement both to Turkey and as I said, the transit arrangement through Turkey into Europe.

So for me to go into details as to the pricing formula, I am not prepared to do that.

All I can say is that we are pleased with both the transit arrangement and with the sales arrangement that we are seeing both in relation to the current agreement and with the next phase of Shah Deniz.

And we feel now that it is quite realistic to have the next phase 2 in operation let's say by the end of 2016 and we are very optimistic about that.

Okay, thank you.

Jon Rigby, UBS.

Oh, yes, hi.

Two questions, both gas-related.

The first is you mentioned about taking some unrealized losses on derivative contracts in the second quarter.

Can you give a little bit more visibility on what that might be, sort of what is moving that has created that and maybe some kind of indication of the kind of gains you have been booking in the last few quarters so we get some idea of what underlying performance has been?

The second is just in terms of the transfer price being achieved by the NCS at the moment.

Are you able to just give us a bit of insight into the degree to which the sort of low transfer price is a result of the changed mix, pricing mix of your long-term contracts, i.e.

the increased proportion that is related to spot or the degree to which the buyers are not lifting your cost gas contracts and you are selling directly onto the spot market?

Thanks.

Okay.

When it comes to the derivatives, we have, as I mentioned, we have -- we locked in the main part of the volumes that we deferred from last year on the forward curve.

Some of this has been realized during the second quarter as the profit compared to the price that we locked it into.

So we have realized it at even higher prices than we actually locked it into in the second quarter.

But the main part of this is still on the forward curve, partly for this summer, this winter, next summer.

And what has happened during the second quarter was that gas prices -- we locked this in last year and during the second quarter, gas prices, spot prices and the forward curve in parallel, it moved very much in the same way as the spot prices during the second quarter and we saw a steep increase in both the spot prices and the forward curve.

So what has happened with the forward curve was that all the volumes that we have locked in beyond the second quarter had to be valued at the new forward curve at the end of the quarter.

Basically at the -- as the forward curve has moved, we have taken sort of an unrealized loss.

Now as you indicated, this has to be seen in relation also to gains that we have seen since we actually took those positions and I mentioned four consecutive quarters where we have seen gains.

I think it is fair to say that these gains does not add up to NOK3.4 billion as such, but they are getting quite close.

So this is a theoretical.

If we have sort of left the positions and went into the positions at the perfectly right time, we could theoretically have made those kind of benefits.

But we have made significant value from moving it and we have chosen to secure that and theoretically, we could have made even more value if we moved in and out of the forward curve at the exact right time.

So that is more sort of a loss of opportunities.

But it is significant values and I think also the hedging strategy looks much better than the NOK3.4 billion that we see in this quarter when you combine it with the previous quarter.

And the mix effects in terms of NCS production?

Yes.

Well, the transfer price is reflecting the actual mix of our volumes at any point between what is long-term contracts, what is the spot portion of long-term contracts and what is straightforward spot market volumes.

So what has happened in this quarter is that, you are right, we still have approximately 70% -- I haven't got the exact number -- but approximately 70% of this is still oil index volume in the formula.

And then the rest is related to an increase in the sort of spot portion of the long-term contract and also higher spot volumes in general compared to what we sold last summer when the prices were very low.

So we have sold higher spot volumes.

You have a higher portion of sort of spot price component of the long-term contracts, but you still have approximately 70% oil index in the pricing formula.

Right.

So there's a bit of a double whammy this quarter?

I didn't --

I was just saying it is a bit of a double whammy this quarter, so you are taking the components of spot-related pricing in the long-term contracts plus a higher proportion of actual spot sales this quarter as well.

Yes, you could say that, but it is higher spot prices, so actually a benefit from that.

Okay.

Thank you.

Irene Himona, Exane BNP Paribas.

Good afternoon.

I had two questions please.

For the Mongstad refinery, you have taken I believe several impairments on that.

Are you prepared to disclose where the current net book value of that asset is?

Secondly, if you could update us on international exploration in light of the US moratorium?

In the second half this year, what high-impact wells should we be watching out for?

Thank you.

Okay, first of all, on the Mongstad refinery, I think we simply have made it a good practice not to disclose the specific accounting and balance sheet numbers on individual assets.

But what I can say is that we are far above zero.

There is still a significant book value left on the refinery, which is justified by the value that we see in this.

But it is -- NOK2.9 billion is definitely a big bite into the book value, but there is a significant portion left there.

When it comes to the international exploration, obviously, we don't expect to see any major high-impact wells in the Gulf of Mexico due to the moratorium, so we are moving outside of Gulf of Mexico.

Maybe I should comment on 2010 and 2011 in combination.

So based -- and just directly towards the area.

And I think the main areas for us in exploration when it comes to impact stuff, we will be drilling a lot in the Angola and so on, but when it comes to impact stuff, I think the most important ones are in Faroes, in Egypt where we are getting closer to actually drilling, in Indonesia, Brazil and in Brazil, that also includes additional drilling in the Peregrino area.

So I think these are the most interesting.

We are also preparing drilling in Tanzania, for instance, but I haven't got the exact schedule for that, whether that will be -- there will be any drilling, not this year, but maybe next year, but I am not confident about that.

So that is the main comments I can give you on the more impact stuff when it comes to the exploration outside of Norway.

And hopefully, we will get back to the high-impact stuff that we have a lot of in the Gulf of Mexico as soon as we can.

Thank you.

James Hubbard, Morgan Stanley.

Hi, two questions, please.

The first is could you give us an update on progress in Iraq with West Qurna, what stage you are at and where you hope to be by by year-end?

And secondly, back to Mongstad, you are obviously spinning off the retail, or planning to spin off the retail side of the business.

Given your gloomy outlook for Mongstad, would you consider something more -- some strategic restructuring there, potentially selling your stake or even converting the assets to some alternative use or is it just something you are going to live with because it is tightly integrated to your oil production?

Thank you.

Okay, I think you started answering the last question yourself.

It is a fact that Mongstad is definitely -- I mean the value creation that we see from Mongstad goes actually beyond their refinery as such in isolation.

It is highly integrated into the Vestproses facility.

It is highly integrated into the oil production on the Norwegian Continental Shelf through pipelines, which gives a very efficient structure from the Troll field and so on and so on.

It is highly integrated and there are values from this refinery outside of the refinery book value as such in itself.

So basically, the configuration that we see is that it takes -- an FCC refinery takes no fuel (inaudible), this refinery has the capacity to crack these type of heavy components and it also produces more gasoline versus diesel.

And I think that is really more or less addressing the issues that we might be looking at going forward.

Hopefully not closing the refinery or doing anything else, but simply looking at how, first of all, we can continue to reduce costs in the refinery, improve the energy efficiency where we are doing a lot in terms of the CHP development, in terms of looking at sort of the feed mix that is going into it.

Is there anything we could do about that?

And look at the yield that comes out of it in terms of how the markets are looking for gasoline and diesel and so on and the various products.

So we are definitely looking at a lot of measures how to possibly reconfigure the refinery.

Obviously, any costs associated with that would have to be robust and associated with the robust judgement, but obviously, we have to look at it and pursue cost reductions, quite ambitious plan on cost reductions on the Mongstad refinery.

And also look at integration possibilities with our, for instance, our Kalundborg refinery, which is actually producing fuel oil.

We will look at how we can benefit from tying these two -- the output from the Kalundborg refinery into the Mongstad refinery and benefit -- so tailor that feed as well.

So we have a lot of plans to improve the profitability for Mongstad going forward.

Okay, and an update on West Qurna?

Okay, yes.

Well, first of all, we have established a consortium in the contractor group.

We are currently looking at towards the preliminary development plan with a deadline in August, which is actually the first deliverable under the service contract.

The first tenders have been sent to the market and the responses are expected soon.

The project will start production and achieve first production, first commercial production we think now ahead of the deadline and we are getting into the autumn of 2013.

What I can say in general is that this project is actually looking better and now having worked on it, than it looked at the time of the award and it satisfied our internal requirements for profitability definitely.

Okay, thank you.

Lucy Haskins, Barclays Capital.

Hi, I am going to ask a few questions, please.

Firstly, just a follow-on on Iraq.

How are you planning to book the resources there?

And the second question was actually on the gas sales during the course of 2Q.

I mean you have signaled that 3Q is normally the seasonal low point.

Would you suggest that the high offtake you saw in Q2 might suggest we get an even bigger sort of swing around 3Q?

The customers have mopped up their sort of appetite as far as your volumes are concerned for this gas year?

Well, first, on the gas question, it is very hard and I would be very reluctant to sort of try to guide on specific gas volumes for the third quarter.

As you know, there is a lot of flexibility in the contracts on an annual basis, so they could get up to more the ACQ 110% and they could get below 90% ACQ.

So there is a lot of annual flexibility.

So there are a lot of outcomes for the third quarter as well.

So what I can do is to point at sort of the typical pattern that we are seeing, and we are seeing no reason to expect that this quarter will look differently, but it is still two months left of the quarter.

Could I perhaps put it a different way?

Was there more than normal seasonal sort of -- was 2Q seasonally stronger than you would have expected I guess this year?

Second quarter?

Yes.

It was -- I would say it was stronger than expected, yes.

But not stronger than basically -- maybe slightly stronger, not -- more on par with what we have seen in previous years, but slightly stronger than expected.

Okay.

When it comes to booking of Iraq, I am looking at my Chief Accountant here, so he is preparing an answer to that.

The Iraq booking we are evaluating and we have not come so far in the process that we have made any conclusions yet.

Okay, thank you.

Anne Gjoen, Handelsbanken.

Thank you.

I have a question in relation to Cove Point since you have made the write-down there.

Is it possible to say how much this is related to the total?

And could you also comment on the remaining contract length?

And I have another question, when it comes to new sanctioning of fields, what is coming up next?

Thank you.

Okay.

When it comes to the Cove Point, all I can say is this is a judgment on the value of the contract and I am not prepared to sort of say what is the full value of the contract.

But what I can say is that we have taken down quite significantly the utilization factor this quarter from where we have been.

So we think now we have a utilization factor, which is the basis, the main sort of component of defining the cost provision here to a much lower level, which we believe now is reflecting in a relevant way the nature of the US gas market, which we think will separate from the European gas market, and sort of the balance that we expect to see in the US gas market and the need for import.

We still think there will be a need for import of LNG, but not sort of on a permanent basis.

It will be more sort of a cyclical basis and a seasonal basis.

So I think that is how far I can get when it comes to add comments on the Cove Point.

When it comes to new sanctions, there is actually a lot of fields that we are working on in terms of new sanctions, so we are talking about between around 20 new PDOs being worked on that could be sanctioned this year.

And when it comes to Norwegian Continental Shelf, for instance, we are working on these so-called fast-track projects and I think the PanPandora is the first one to be sanctioned.

And that means that it is actually down to a two-year development time from discovery to production on the PanPandora.

So it means that we had really -- means that we are successful on the fast-track development on the Norwegian Continental Shelf.

But in terms of specific fields and so on, I haven't got a list for you today, but it is quite a big number both from the Norwegian Continental Shelf and internationally.

Thank you very much.

Barry McCarthy, Royal Bank of Scotland.

Good afternoon.

Could you clarify please the hedging effects, the cash/noncash effects?

To the extent that hedges made last year in the spot gas market matured in the second quarter, won't those be reflected in the realized price on the gas sales?

And is this going to be an ongoing activity where you will be selling forward, for example in 2011 or was that a particular action you took in the weak market in 2009?

And I have a separate follow-up question.

You are a partner with BP and have been for a considerable time in a lot of international assets.

Some of these may come up for sale.

Would you be interested in acquiring some of those assets?

Okay.

Now hedge accounting is quite complicated.

What we -- as I said, this is to a large extent related to the flexible trading strategies that we introduced last year where we started to move for the very weak market and we moved quite significant volumes forward.

And we selected to put these on the forward curve.

What we have actually delivered in the second quarter, that has been realized.

That is not part of the hedge -- or the derivative accounting.

That, in the adjusted numbers for the natural gas segment, that means -- what is in the adjusted number is actually what these hedges gave us above their market price.

So the main part of this is actually reflected in the E&P Norway business segment, on the part which is realized.

Now the major part of this has still not been realized by the second quarter.

So it is still on the forward curve.

It is still a commitment to the physical deliveries at certain points in time going forward.

We still have to be valued according to the forward curve.

Oh sure.

So that is what is explaining the derivatives variations in that.

I don't know if I actually answered your question, but --

It does partly, but are you going to continue to do this?

Will you be continuing to sell forward?

First of all, I would say we have -- in terms of derivatives effect, there are various -- not only the flexible strategies that is related to moving the gas forward in time, so that is one strategy.

We also have other strategies.

We could hedge -- we could lock in volumes outside of sort of the physical flex strategies.

So we have mandates in place to do that as well so that could be part of the strategy.

If we took a market view, we took a bet on the market because of our sort of insight into the market and took a position independently of the flexible volume strategies that I talked about.

That is something we are doing, not massively, but we are doing it to some extent and have done it for many years.

That will, of course, sort of this kind of derivative position.

Then we also have sort of storage positions of our own that goes into this.

And we also have long-term contracts, for instance, in the US, which is tied to oil, the oil index, which is also measured as derivatives.

So there is sort of a mix of things, which goes into this overall derivative effect, but the main part is coming from what we did last year and moved into this year into the forward curve.

So some of this has been delivered now, but they are also taking new positions.

But what I could say is that sort of -- I don't think sort of -- we would have to see a very sort of special market situation to revert to sort of the kind of significance that we saw in terms of volumes from last year.

So I don't think this year, this summer that we will see the same magnitude that we saw last summer because then we saw a very big spread between the spot price and the forward curve.

And we are not looking at the same contango situation this time.

Okay.

Thank you.

And on the BP potential asset disposals?

I tried to avoid that one.

What I can say -- we would never -- that is a consistent strategy, we never comment on --- if I were not to speculate -- to work on specific opportunities, I would never mention that.

So what I will say is I repeated what we have said previously is it is an obligation we have to our shareholders to look at sort of also these kind of opportunities.

And we see a more comprehensive set of opportunities also beyond BP in this environment that we have seen for some time.

So we are obviously looking at this kind of opportunity and considering what is it and does it fit into our portfolio as a way of creating value for us.

So it is something we are considering, but if it made a move, it would definitely be value-creating and it will also fit nicely into our strategy.

So this is something we do all the time and we are definitely also doing it in this environment.

But beyond that, I couldn't give any further or more specific comment.

Well, thanks very much.

Michael Alsford.

Good afternoon.

A quick question actually and I might have missed this, but on Peregrino.

Could you maybe give an update on the project, where you are as a percentage say of work done, how comfortable you feel of delivering volumes early 2011 and maybe the key risks to that sort of deadline?

Thank you.

Okay.

The Peregrino project is a major, very important project for us.

So the two wellhead platforms, they are now fully assembled and are preparing to start drilling as we speak.

So the exact timing of when we can start drilling production wells, I haven't got, but that is the most.

So they look as they should look and they are preparing themselves for specific drilling activities.

The FPSO is scheduled to arrive in Brazil towards the end, in the fourth quarter of 2010.

So in terms of startup, we are -- it will take some time to sort of build -- this is heavy oil, so it will take some time to get into regular operations and build the capacity and stable production.

But we are still talking about early 2011, so that is not January, not February, but now then we might start talking.

So that is the kind of time schedule that we are talking about.

Great.

And sorry, maybe a quick follow-up on your point around the ramp-up.

Could you maybe give a bit more color as to sort of how long you expect the ramp-up to take to say to get to plateau, which I think I believe was about 80,000 barrels per day, was that right, for the gross production?

100,000 is the plateau.

So I think basically we expect to be at more or less the plateau towards the end of 2011, in that range.

But the exact sort of, there are uncertainties on this, it's in, as I recall, in that range.

It should be at -- could be more or less at plateau by 2012.

Great.

Thank you very much.

(technical difficulty), Bank of America-Merrill Lynch.

Hi, there, gentlemen.

Just a couple of questions.

First of all, it has been awhile since you have talked about cost-cutting and the progression of your unit costs within the business.

Does that signal an end to any hopes of getting your costs lower?

Are you beginning to see cost pressures reentering into the industry or is there more to come?

As well as if you could make some comments on any potential merger synergies there.

The second question I had was largely around M&A, how you are thinking about M&A.

Are you looking more on the exploration side or are you looking to recycle the proceeds, for example, from Peregrino into assets on the cusp of production.

I just wanted to get how you are thinking about M&A at the moment.

Thank you.

Well, we have certainly not forgotten cost-cutting and I think you will see it in the numbers this quarter as well.

I mentioned it in relation to the E&P business segment.

Our operating expenses is also lower than you saw in the same quarter last year, quite significantly so.

SG&A cost is down and then we exclude inflation by 11%.

But we are definitely working on the cost-cutting program and basically what I -- we are on track with the cost-cutting program that we have presented to you earlier.

And I think you have seen the reduction in our cost base quite consistent in some quarters compared to what we have seen earlier.

But in terms of the merger, I think when it comes to the merger synergies, that is something we have -- I think we are moving into measures now, which goes beyond the merger when it comes to cost reduction.

We have more or less settled now the new organization and a new operating structure offshore, which was the last measure I would say which comes out of the merger.

So that process took approximately one year.

So we now have one integrated offshore organization and by July this summer, that process has been finalized and we have restructured and taken out the people that should be taken out of the organization, and reshuffled the organization and unitized the working procedures offshore.

So we are now talking about cost reductions that goes beyond that and we are on track with all these measures and when it comes to unit costs, unit cost per barrel is down.

When we adjust for merger restructuring costs, it is down from NOK35.6 to NOK35.2 per barrel on a quarter-to-quarter basis.

So again, we see the impact on the unit costs and our guidance of NOK35 to NOK36 per barrel for this quarter, that stands.

So I simply have to pick issues to talk about, but it is a good question, thank you and we are on track with the cost reduction program that we were talking about earlier.

And on M&A?

Okay.

I tend to forget these second questions.

M&A, well, I think it is -- first of all, what you are looking at is a good strategic fit.

It is value creation in the deal.

Then preferably, it is growth going forward.

Something where we can impact either as an operator or where we can add values to not only sort of pick up something, which is just exchanging money to put it that way.

We want something where we can influence it.

We are a big operator, have a high technological base, a high skill set and we want to use that in our acquisition to demonstrate value creation in whatever kind of acquisitions we do.

So that is basically what we have done in the Gulf of Mexico.

That is also the basis for what we did in the Peregrino case for instance and I think we have demonstrated that through the divestment that we did on Peregrino that we have actually created values through that strategy.

And that is also the way we would think going forward.

So it is basically growth, it is value and it is strategic fit.

Okay, thank you.

Kim Fustier, Credit Suisse.

Kim Fustier, your line is now open.

Please go ahead.

Yes, hi, sorry.

Just two questions if I could, please.

Firstly, if you have any comments on trends that you are seeing in European gas demand, that would be very helpful.

And also could you tell us whether you are currently renegotiating any gas contracts with your customers?

And secondly, are you just able to talk about what happened at the Gullfaks C platform in May with the well incident?

I believe that was a high-pressure well.

So just wondering if that was a precaution linked to Macondo, which you would not have taken otherwise?

Thank you.

Okay.

I will try to remember these three questions this time.

First of all, when it comes to the gas demand, what we -- obviously we have talked about gas prices increasing quite significantly in the second quarter.

So that comes mainly from -- to a large extent, it is demand-driven.

It comes from higher demand.

We have seen some stock building, both in the US and also in Europe.

We have seen some outages from other energy sources.

We have seen an increase in gas-fired power generation and gas demand in relation to power generation.

And we have also seen some positive developments when it comes to industrial demand.

But mainly this is driven by the power segment.

And on the supply side, basically, we think -- we have seen a situation where there has been, as we understand it, a lot of maintenance activities, mainly in Qatar related to the LNG development.

So this is basically what we think explains the second quarter.

What about going forward?

Definitely this is positive signs.

We see a higher demand; that is good.

How much of this is permanent?

That is a big question.

We think that when it comes to power generation that what you have seen now is that gas has replaced coal to some extent and as gas prices are increasing, we will get to a point where we might see switching back to coal.

We think that sort of might happen on the gas.

Hopefully, industrial demand is increasing and hopefully gas customers will also realize that gas is definitely a good feedstock for power generation from many perspectives and we see that sort of emerging.

When it comes to the supply side, we definitely think there will be no change to sort of the buildup of LNG capacity.

So we think the situation we have seen in the second quarter is temporary and that we will see a significant increase in LNG capacity with a pyramid starting with the most attractive Asian markets, then Europe and then US at the bottom of this pyramid.

So we see some positive -- and I should also add obviously we see a growing indigenous gas production in the US, which is sort of decoupling the US gas market to a larger extent.

So basically it is -- we expect some volatility short term on the gas side, as we have seen now and we are uncertain as to sort of the short-term outlooks, but sort of medium-term, we are still slightly bearish despite the positive signs because of the overall balance on the LNG that is coming in and sort of the coal gas we have shown on the gas power -- on the power generation side.

So we still have the same fundamental view that there is an overhang when it comes to gas sort of medium term.

But there are some positive signs, so that sort of gives hope for optimism.

When it comes to longer term, we still have the same fundamental positive view on gas.

So our long-term view is very robust and there is no change to that.

But we'll just see in this quarter that it adds optimism slightly to the gas market view going forward.

On the Gullfaks C, to complete the list of questions, I think, first of all, this is not a high-pressure reservoir at all.

This is -- but it is a very complex reservoir and so Gullfaks is one of the most complex reservoirs that you can think of, but not in terms of pressure and tight reservoirs.

So it is very conventional in many ways.

So we are now -- I mean this is a situation that we have controlled very well.

We have always had barriers in place, so there was no risk of any blowout or anything like that.

We have controlled the situation all the way and I think if you are asking for similarities, what sort of implications in relation to the Macondo and so on, I think there are very few similarities.

But obviously, what we will do is to wait and see what comes out on the investigation in the Gulf of Mexico and to the extent there are similarities, we will definitely take care of that in that context.

But it is a very different context.

This is also a production well and not an exploration well from a fixed platform with totally different reservoirs.

So far, the situation is very different.

We are now investigating what happened on the Gullfaks C and obviously, want to make every lesson that we can learn from that available to us.

[Sebastian Siefert], JPMorgan.

There are no further questions on the telephone.

Okay.

That was apparently the last question that callers' asked.

So today's presentation and Q&A can be replayed from our website, Statoil.com.

The transcript of today's presentation, including the Q&A session, will be available in a matter of days on our website.

Thank you very much for participating and goodbye.