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Statoil ASA (NYSE:STO)

Q2 2010 Earnings Call

July 29, 2010 02:30 pm ET

Executives

Lars Sørensen - Head of IR

Eldar Sætre - CFO

Analysts

Jason Kenny - ING

Oswald Clint - Sanford Bernstein

Jon Rigby - UBS

Irene Himona - Exane BNP Paribas

James Hubbard - Morgan Stanley

Lucy Haskins - Barclays Capital

Barry MacCarthy - Royal Bank of Scotland

Michael Alford

Kim Fustier - Credit Suisse

Lars Sørensen

Ladies and gentlemen welcome to Statiol's webcast and telephone conference on our second quarter 2010 earnings. I am Lars Sørensen; I'm the Head of Investor Relations. This presentation is a webcast presentation and is broadcasted live from our offices in Oslo. We can be followed on the web from statiol.com or by calling into the conference by phone. You will find dial-in numbers on our website.

This morning at 7.30 AM Central European Time we announced our results for the second quarter 2010 and press release on the results were set through wires and to the Oslo Stock Exchange. The quarterly report and today's presentation pack as usual can be downloaded from our website statiol.com. On the front page of statiol.com there is a link directly to the presentation pack.

Can I ask you please to take special notes on our usual forward-looking statements which are the slides on the last page of the presentation set? After the presentation, we will open to 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 procedure of asking questions over the phone immediately before the Q&A session starts after the presentation.

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

Eldar Sætre

Thank you, Lars. Good afternoon ladies and gentleman and welcome to this second quarter earnings and presentation for Statiol. 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 uncertainty still remains when it comes to the pace of the world economic recovery.

However Statiol 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 on stream on July 14. We are also getting closer to production start 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 non-cash 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 we see an overview of our key earnings dealers 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. And 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 use all our 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 kroner combined with a 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 and both of these were in natural gas and the impairment of the Mongstad refinery which I mentioned within manufacturing and marketing.

Reported tax rate this quarter was 88% after adjustments for the effects of tax are in frequent 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 1,957,000 barrels per day this quarter. And this implies 6% growth over last year. The growth primarily came from increase in 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 and 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, and the increase were mainly due to changes in profit tranches for some Angolan fees 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 off-take on our long term contracts, but also higher spot volumes due to higher MBT prices this summer.

Outside Norway, the 10% increase in gas production mainly came from higher volumes in solar in Algeria and the ramp back of production in the Marcellus area in US. We are now well into the final quarter of the European gas year. Traditionally the third quarter is relatively weak quarter in terms of off-take and we have no indications that this quarter will defer from this typical seasonal pattern we have previously. And neither should you forget that our gas production remains value-driven so we will continue to use the flexibility in our gas fields which is mainly Troll and Oseberg where this creates value.

So let me then move to the resource 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.

Depreciations increased by 9% in E&P Norway due to increased production and also higher depreciations 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 result. 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 Norwegian kroner compared to NOK1 billion last year, and the increase was to some extent explained by more costly and higher ownership shares in general. But, by far, the main course is related to the expensing of one individual well deemed to be non-commercial in Gulf of Mexico.

Natural gas, adjusted resource were NOK3.3 billion, which is down 21% from last year. The sub-segment processing and transports, adjusted earnings were flat year-on-year at NOK1.8 billion. Adjusted earnings in the marketing and trading sub-segment were at NOK1.5 billion, which is down 38% compared to last year. And this is mainly driven by normal variations in our gas trading business.

I will shortly come back to a further discussion on the natural gas business. Manufacturing and marketing, and 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 the forward curves flattened out and also for some losses related to the price drops, the price drops that we saw in June, 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 Urethane, mainly higher fuel margins cost the 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 tighter market and consequently higher price outlook for fuel oil and consequently lower margins on Mongstad. And this has led us to take an impairment of NOK2.9 billion this quarter.

And 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 months time lag in the pricing formulas.

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 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 volumes 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 non-cash 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 $3.4 billion Norwegian kroner in the gas business mainly related to this Felix strategy but also to other hedging strategies. While we in previous quarters and actually in the four quarters in row now have had a positive derivative effects from our gas trading business.

Finally, we have concluded to make a cost provision this quarter in connection with our commitments related to the curve point LNG, regas terminal of NOK$3.8 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 the lower expected utilization of the regasification capacity at core point.

So all-in-all and despite the negative haste value over 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 a 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 $1,925,000 to $1,975,000 barrels per day for 2010. Compared to first half of this year we expect equity production to fall due to extensive turnarounds in the third quarter, all around 120,000 barrels per day in quarterly effect.

Start up on new fields will mainly take place in the fourth quarter and there are new start ups internationally this year. In addition uncertainty related to the short-term gas markets still prevails with the third quarter typically as our weakest gas quarter.

CapEx guidance for 2010 is still at $13 billion. Exploration expenditures at NOK2.3 billion and unit production cost is expected in the range of 35 to 36 and it was at 35.2 of the last 12 months period.

Regarding 2012 we recently announced the firm down of 40% in the peregrine field in Brazil through the partnership with (inaudible). The direct implication was that we adjusted our 2012 activity 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.

Lars Sørensen

Thank you very much. We'll now start the Q&A session. In addition to Eldar Sætre and myself here in also we're joined in the studio by the head of Corporate Accounting Mr. [Carl Thomson]. In order to be able to ask questions, you have to dial into the phone conference. The dial-in numbers are available on our site. And operator would you please go through the procedure for asking questions in the conference call?

Question-and-Answer Session

Operator

(Operator Instructions). This first question comes from Jason Kenny from ING.

Jason Kenny - ING

Hi there and thanks for taking my question. Would you see the net debt 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?

Eldar Sætre

Okay, on the net debt to capital employed, that ratio was at 29% at the end of the third quarter and that included also the full payment of the dividend on NOK19 billion as we are paying dividends only once a year. So that is included in the net debt and the cash has impact on the cash position.

So just to give you a few comments to this. If for instance we have paid dividends twice a year which is not allowed in Norway, the net debt ratio would have been approximately 29% and they have also had a negative effect from US dollar, Norwegian kroner exchange rate in during the first half of the year and that has had an impact of approximately 2%. So we would have been at around 34% - 35% 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 profits on the gas resource and but obviously also on the oil price. But given sort of the current environment and the current type of exchange rates, we 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's the best estimate I can give you currently.

Then to the Gulf or Mexico and the cost related to that. Obviously there is a lot of discussion we can't come back to on the more long-term applications, but short-term this is really about managing the rig portfolio and we were in the process of drilling five wells, two of them were Statiol operated and we participated in three other wells 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 all these contracts and are paying lower rates but are still cost associated with this and there is no drilling being made. Obviously what we are doing is to look thoroughly into other ways of improving our rates but so far these rates are still in the Gulf or Mexico area. So the cost to us first of all, we have made no provisions in the accounts. There is no on risk contracts that should be provided for so we will take any cost that is coming as it terms out and the estimate we have given is around $100 million assumed that the moratorium will last for six months, $100 million, maybe slightly higher, but not significantly higher. So that's 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.

Jason Kenney - ING

Would you look to recover that cost in time?

Eldar Sætre

We have declared force majeure and that has regulated, the force majeure rate is regulated in the contract. So as long we are paying force majeure rate, that's 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 Gulf of Mexico and in other parts of the world.

Operator

Next question comes from Jack Moore from Harpswell Capital.

Jack Moore - Harpswell Capital

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?

Eldar Sætre

When it comes to taxes, there is no, I mean, we always see variations in the tax rate and the segment tax rate from quarter-to-quarter. And also just variations because of the fact that we have the US dollar functional currency and we still have this issue that we are paying 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 pre-tax 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, yes, there are no change to our guidance of around 70%-71% tax rate going forward. In the previous quarter that was at I think 69% and now it was at 71%. So we are sort of in that range and there are no reasons 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 barrels per day in this quarter and this is a very low one and 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 US$75 per barrel for the full year, we still indicate around 180,000-185,000 barrels per day in PSA effects. So, no change to that but what we have seen is that there are variations in this number.

Jack Moore - Harpswell Capital

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.

Eldar Sætre

I think for the first, where there is an operational or tactical change I don't know, but you know 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 up to higher sort of exploration activities outside of the US and lower exploration activities inside the US.

But that will not impact sort of the short-term CapEx program or production profiles as such. And beyond that, I am not prepared to sort of disc and we have taken no contribution and we had no reasons to make any (inaudible) or take any conclusions in a relation to changing our strategy I think what we will have to do is to simply wait, what would be the consequences in terms of regulations both in the US and potentially also in the other parts of the world. Coming from the incident and then we just have to be patient and we wait for that and the resource and what really caused this incident.

So far we have found no reason always to make any changes in our strategy to deep water activities is in Norway or in Gulf of Mexico and other parts of the world or make any reallocations of our investments. So we just have to wait to see to the extent there is common sort of things out of this which might course that kind of changes but at this stage I had no reason to expect that. This is still sort of the core of our competence. This is where we're coming from offshore operations and deep water operations. So I think we are still interested because (inaudible) and give them print operator in this type of environment and I think it will still be allowed to operate within this type of environment and how relative competitive position should still be being very good in this context.

Operator

Next question comes from Oswald Clint from Sanford Bernstein. Please go ahead.

Oswald Clint - Sanford Bernstein

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 or 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, do 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.

Eldar Sætre

When it comes to Marcellus, we are planning or Chesapeake is planning to increase their number of rigs. We at the start of this year had 19 rigs in operations. 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 continue to increase it to around 40 rigs by 2012. So, there is no change to the way we look at it. Its still sort of for us a small part of the portfolio. It's a rather small volume. We are talking about 10 plus thousand dials per day in gas production for Marcellus and we think its profitable business even in today's environment and we think its given this more scale with this is the right thing to do to build the capacity, to be prepared as we expect sort of gas prices to improve going forward.

When it comes to Shah Deniz, first of all I have said, we are very pleased that the Turkish and the Azerbaijan government has come to an agreement both on the existing contract on all the arrangements for the next phase of Shah Deniz, both the transit arrangements and the sales arrangements both to Turkey and as I said, the transit arrangements through Turkey into Europe. So for me to go into details, as to the pricing formulas, I'm not prepared to do that. But what I can see is that we are pleased with both the transit arrangements and with the sales arrangements that we have seen both in relation to the current agreement and with the next phase of Shah Deniz and we feel now that its quite realistic to have the next phase, Phase II in operations lets say by the end of 2016 and we are very optimistic about that.

Operator

Next question from Jon Rigby from UBS

Jon Rigby - UBS

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's 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 that 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 a little 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's related to spot or the degree to which the buyers are not lifting your gas contracts and you are selling directly onto the spot market? Thanks.

Eldar Sætre

When it comes to the derivatives, as I mentioned, 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. At the profit compared to the price that we locked it into. So we have realized it at even higher prices then 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 left this in last year. And during the second quarter gas prices, spot prices and the forward curve in parallel has moved very much in the same way as the spot prices during the second quarter. So we saw a steep increase in both the spot prices and the forward curve. So what happened with the forward curve was that all the volumes that you have locked in beyond the second quarter have to be valued at the new forward curve at the end of the quarter. So basically 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, seems to actually took those positions and mentioned four consecutive quarters where we have seen gains. I think its fair to say that these gains doesn't add up to $3.4 million as such but are getting quite close. So this is a theoretical, if you have sort of left the positions and went into the positions at the terrifically right time. So we could theoretically have made those kind of benefits, but we have made significant value for moving it and we have chosen to secure that and theoretically we could have made even more value, if you are in a mood in and out of forward curve up to exact direct time. So that's more sort of a loss of opportunities, but its significant values and I think also their hedging strategies looks much better then the 3.4 million that you see in this quarter when you combine it with the previous quarters.

Jon Rigby - UBS

And the mix effects in terms of NCS production?

Eldar Sætre

Yes, well transfer price is reflecting the actual mix of our volumes at any point between the what is long-term contracts, what is the spot portion of long-term contracts and what is straight forward spot market volumes. So, what has happened in this quarter is that you are right, we still have approximately [70%] because I haven't got the exact number but approximately 70% of this is still oil index volumes in the formula and then the rest is related to an increase in the sort of spot portion of the long-term contracts and also higher spot volumes in general compared to what they sold last summer when the prices were very long. So we have sold higher spot volumes. You have a higher portion of spot priced component over the long-term contracts but you still have a approximately 70% oil indexed in the pricing formula.

Jon Rigby - UBS

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

Eldar Sætre

I didn't get you.

Jon Rigby - UBS

I was just saying its 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 proportionate of total spot sales this quarter as well.

Eldar Sætre

Yes, you can say that but you know its higher than the spot prices. So it actually benefits from that.

Operator

Question comes from Irene, Exane BNP Paribas.

Irene Himona - Exane BNP Paribas

Good afternoon I have two questions please. First, 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.

Eldar Sætre

Okay, first of all on the Mongstad refinery I think we have simply have made it as a good practice not to disclose specific accounting and balance sheet numbers on individual asset, 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 2.9 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, you know obviously that we don't expect to see an image of high impact wells in Gulf of Mexico which is moratorium so we are moving outside of Gulf of Mexico. May be I should comment on 2010 and 2011 in combination. So basically I and just directly towards area. So and I think the main areas for us in exploration when it comes to impact stuff, I mean we will be drilling a lot in (inaudible) and so on but when it comes to impact stuff, I think the most important ones are in (inaudible).

In Egypt, where we are getting closer to actually drilling and in Indonesia, Brazil and in Brazil that also includes additional drilling in the Peregrino area as such. So I these are the most interesting. We are also preparing drilling in Tanzania, for instance as well but I haven't got the exact schedule for that, where that will be any drilling, not this year but maybe next year but I am not confident about that.

So I think that's the main comments that I can give you on the more impact stuff and continuous expression outside of Norway and hopefully we will get back to the high impact stuff that is we have lot of in the Gulf of Mexico as soon as we can.

Operator

Next question comes from James Hubbard from Morgan Stanley

James Hubbard - Morgan Stanley

Hi, two questions, please. The first is could you give us an update on (inaudible) in Iraq with West Qurna, what stage you are at and where you hope to be by year-end? And second, 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 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.

Eldar Sætre

Okay I think you started answering the last question I guess it is a fact that most is definitely I mean the value creation that we see from Mongstad goes actually beyond more there are fine we are such in isolation is highly integrated into the west process facility, its highly integrated into the oil production on the Norwegian continent through pipeline which gives a very efficient structure from Troll field and so it is highly integrated and there are values from this refinery outside of our refinery book value structuring in it self.

So basically the configuration that we see is that it takes (inaudible) refinery takes more fuel and this refinery has capacity to crack this type of heavy components and its also produces more gasoline versus diesel and I think that's really more 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 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 the various products.

So we are definitely looking at a lot of measures how to possibly reconfigure the refinery. Obviously, any cost associated with that would have to be robust and associated with robust adjustments, but obviously, we have to look at it and pursue cost reductions, quite ambitious plans on cost reductions on the most refineries.

And also look at integration possibilities with our, for instance, our Kalundborg refinery, which is actually producing fuel oil. And we will look at sort of how we can benefit from time these two. They outperformed in Kalundborg refinery into the most of the refinery and benefit, so tailor-made that feed as well. So we have a lot of perhaps to improve the profitability for most of it, going forward.

James Hubbard - Morgan Stanley

Okay and an update on West Qurna?

Eldar Saetre

Okay, yes. Well, first of all we have started the consortium in the contractor group. We are currently looking at towards the preliminary development plan with the 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. And the project will start production and achieve first commercial production we think now ahead of the deadline, and you're getting into the autumn of 2013. All 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's satisfied our internal requirements for profitability definitely.

Operator

Question comes from Lucy Haskins from Barclays Capital

Lucy Haskins - Barclays Capital

Hi, I'm 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. You signaled that 3Q is normally the seasonal low point. Would you suggest that the high uptick you saw in Q2 might suggest we get an even bigger sort of swing around 3Q? The customers have mopped up their capacity of appetite as far as your volumes are concerned for this gas year?

Eldar Saetre

Well, first on the gas question its very hard and I would be very relax to sort of try to guide on specify gas volumes for the third quarter. As you know there is a lot of flexibility on the contracts on an annual basis so they could get up to more than (inaudible) 10% and they could get below 90% ACQ [ph] and so there is a lot flexibility so there is a lot outcomes for the third quarter as well. So what I can do is point that sort of the typical pattern that we have seen and we are seeing reasons to sort of expect this quarter will look different.

Lucy Haskins - Barclays Capital

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?

Eldar Saetre

The second quarter it was, I would say, stronger than expected yes, but not stronger basically maybe slightly strong more empowered what we have seen in previous years but slightly stronger than expected.

Lucy Haskins - Barclays Capital

Okay.

Eldar Saetre

Okay, when it comes to booking of Iraq and I am looking at my chief accountant here so he is preparing an answer to that. Yes the Iraq booking, we are regulating and we are not to come so far in the process that we have made any conclusions yet. That's the best we have.

Lucy Haskins - Barclays Capital

Thank you so much.

Operator

Next question comes from [indiscernible].

Unidentified Analyst

Thank you the question in relation to and CCL leading up on the is it possible to say how much this is related to comment and remaining contract and the question when it comes to leave sanctioning of fields, what's coming up next now? Thank you.

Eldar Saetre

Okay, when it comes to the coal forum, all I can us that this adjustment and the value of the contract and I am not prepared to sort of what's the full value of the contract, but what I can say is that we have taken down quite significantly the legalization factor this quarter from where we had been so we think now we have utilization factor which is the basis domain sort of component of defining the cost professional here to a much lower level which we believe now is reflecting in the relevant way. The nature of the US gas market which you know we think were separate from the European gas markets and sort of the balance that we expect to see in the US gas market and the need for import, we still think there would be a need for input of LNG but not sort of on a permanent basis, it will be more sort of a cyclical basis and seasonal basis. So I think that's how far I can, as far as I can get to when it comes to add comments on the corporate.

When it comes to new sanctions, there is actually a lot of fees that we are working on in terms of new sanctions, so we are talking about around 20 new PDOs being worked on that could be sanctioned this year. When it comes to Norwegian continental shelf, for instance, we are working on these so-called fast-track projects, and I think the Pan/Pandora is the first one to be sanctioned and that means that was actually down to two year development time from discovery to production on the Pan/Pandora. And so that means that we are really, seems that we are successful on the fast-track where developments on the Norwegian continental shelf.

But in terms of specific fees and so on, I've got a list for you. Today there is a quite number both in the Norwegian continent shelf and internationally.

Operator

Next question comes from Barry MacCarthy from Royal Bank of Scotland

Barry MacCarthy - Royal Bank of Scotland

Could you clarify please the hedging effects for cash/non-cash 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?

Eldar Sætre

Okay. Hedge accounting is quite complicated. As I said, this is to a large extent relate to the flexible strategies that we introduced last year, where we started to move. It was a very weak market. And they moved quite significant volumes forward and we selected to put these on the former curve. What we have actually delivered in the second quarter that has been realized, that's not part of the hedge or the derivative accounting. So that's 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 the market price. So the main part of this is actually reflected in the E&P Norway business segment on the part which is realized. The major part of this has still not been realized by the second quarter so its still on the forward curve, its still commitments to feasible delivers at certain point in time gone forward. So it still has to be valued according to the forward curve.

Barry MacCarthy - Royal Bank of Scotland

Sure.

Eldar Sætre

So that's what explained in the derivate variations that we see. I don't know if I have answered your question but…

Barry MacCarthy - Royal Bank of Scotland

It does partly, but are you going to continue to do this? Will you be continuing to sell forward?

Eldar Sætre

Yes. First of all let's say we have, in terms of derivative effects, there are various, it's not only the flexible strategies, that's related to moving gas forward in time, so that's 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, took a bet on the market because our sort of insight into the market and took a position independently of the flexible volume strategies that I talked about. So that's something we are doing not massively but we are doing into some extent we have done that you know for many years.

So that will, of course, sort of this kind of derivative positions and we also have sort of storage positions that's on that, that goes into this. And we also have long term contracts for instance, in the US which is tied to oil, which is oil indexed, and which is also measured as derivative. 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 on this has been delivered now but we have also taken new positions. But what I could say is that I don't think sort of, we would have to see very sort of special market situation to revert to sort of the kind of significance that you 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 (inaudible) situation this time.

Barry MacCarthy - Royal Bank of Scotland

Okay. Thank you. And on the BP potential asset?

Eldar Sætre

I tried to avoid that one. What I can say, we would never, and that's a consistent strategy, we never comment on, if I were to, if I were not to work on specific opportunities, I would never mention that. So, what I say I repeat and what we have said previously suggest that its an obligation we have towards our shareholders to look at sort of also these kind of opportunities. We see actually a more comprehensive set of opportunities also beyond BP in this environment than we have seen for some time. So we are obviously looking at this kind of opportunities and considering what is it and does it fit into our portfolio, is there ways of creating values for us? So its something that we are considering.

But if we made a move, it would definitely be value creating and it will also fit nicely into our strategies. So, this is something we can't do all the time and we are definitely also doing in this environment, but beyond that I couldn't give any further or more specific comments.

Operator

Next question comes from Michael Alford.

Michael Alford

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.

Eldar Sætre

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-wise, that's the mode. So they us, they should look on their prepared results for specific drilling activities.

The SPSO is scheduled to arrive in Brazil towards the end, in the fourth quarter of 2010. So, in terms of startup, it will take some time to sort of build. This is heavy oil so it will take sometime to get into regular operations and bail the capacity and stable production, but we are still talking about early 2011, so that is not January, not February, but you know them we might start talking. So that's the kind of time spanning that we are talking about.

Barry MacCarthy - Royal Bank of Scotland

And so 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?

Eldar Sætre

100,000 is the plateau. So I think basically we expect to be more or lesser at plateau towards the end of 2011 in that range, but the exact sort of barrel uncertainties on this particular instant in, I started coal in that range, so it should be more or less at plateau by 2012.

Operator

Next question comes from Arif, Bank of America/Merrill lynch.

Unidentified Analyst

Just a couple of questions first of all, its been a while since you have talked about cost cutting and the progression of your unit costs within the business. Does that signal 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 that, any potential merger synergies there?

And 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 customer's production? I just wanted to get how you are thinking about M&A at the moment. Thank you.

Eldar Sætre

Well, we have certainly not forgot 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 expense is also lower than you saw in the same quarter of last year, quite significantly so.

SG&A cost is down and then we excluded inflation by 11%. So we are definitely working on the cost cutting program and basically, we are on track with the cost cutting program, that we have presented to you earlier and you see that. 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's something we have now. I think we are moving into measures now which will cost beyond the merger when it comes to cost reductions. We have more or less setting 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 then we have restructure and taken out the people that should be taken out of the organization and reshuffle the organization and unitize the working procedure for offshore.

So we are not talking about cost reductions that goes beyond that and we are on track with all these measure. When it comes to unit cost, unit cost per barrel is down when we adjust for merger restructuring cost, is down from NOK35.6 to NOK35.2 per barrel on a quarter-to-quarter basis. So gain we see impact on the unit cost in our guidance of NOK35 to NOK36 per barrel for this quarter, that stands. So, I simply have to pick issues to talk about, that is a good question thank you and we are on track with the cost reduction program that we have talking about earlier.

Michael Alford

And on M&A?

Eldar Sætre

Okay, I tend to forget the second questions. M&A, well I think, first of all, what we are looking at is a grilled strategic fit. Its value creation in the deal then preferably its growth going forward, so something where we can impact, there's an operator or where we can add values to it, and not the only sort of pickup something which is just exchanging money to put it that way. We want something where we can influence, it we are big operator have high technological base, high skill set and we want to use that in our acquisitions to demonstrate value creation in whatever kind of acquisitions we do. So that's basis of what we have done in Gulf of Mexico. That's 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 into that strategy and that's also, the way we would think forward, so it's basically growth, it's value and it's strategic fit.

Operator

Next question will come from Kim Fustier from Credit Suisse.

Eldar Sætre

Are you there Kim?

Operator

Kim Fustier, your line is now open. Please go ahead.

Kim Fustier - Credit Suisse

Just two questions if I could, please. Firstly, if you had any comments on trends that you are see 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 about 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.

Eldar Sætre

Okay, I'll 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. To a larger extent its demand-driven. It comes from higher demand. We have seen some stock building both in the US but also in Europe. We have seen some outages and from other energy sources. We have seen an increase in gasified power generation and gas demand in relation to power generation and we have also seen some positive developments when it comes to industrial demand and 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 that 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's good. How much of this is permanent? That's a big question. We think that when it comes to power generation, what we have seen now is that gases replace coal to some extent and those gas prices are increasing. We will get to a point where we might see switching back to coal.

So, we think that sort of might happen on the gas side, hopefully if the industrial demand is increasing and hopefully gas customers also will realize that gas is definitely a good feet 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 build up of energy capacity. So we think the situation we have seen in second quarter is temporary and that we will see as a significant increase in LNG capacity. With the pyramid starting in most attractive Asian market then in the European then US at the bottom of this pyramid. So we see some positive sign and I should also add obviously we see growing indigenous gas production in the US which is already coupling the US gas market to a larger extent.

So basically we expect some volatility short term of the gas side as we have seen now and we are uncertain as to sort of the short term outlooks but sort of medium turn. We are still slightly bearish or despite the positive signs because of the overall balance and the LNG that is coming in and sort of the coal gas we've shown on the power generation side. So we still have the same fundamental view there is an overhang when it comes to gas sort of medium but there are some positive signs, so that sort of gives hope for optimism.

When it comes to the longer terms, we still have the same from a multi-positive neon gas. So our long term view is better or best and there is no change to that. But what you have seen this adds optimism slightly to the gas market view going forward.

On the Gullfaks C, just complete the list of question. I think, first of all this is not a high pressure reservoir at all. That is a very complex reservoir and so Gullfaks C is one of the, most complex reservoir that you can think about but not in terms of pressures and tight reservoirs, so it's very conventional in many ways. So we have now this was a situation that we have controlled very well. We always had in place so there was no risk or any blowout or anything like that. We have controlled this situation all the way and I think to if you are seeing for similarities, so what sort of implications in relation to the Macondo and so I think there are very few similarities but obviously what we will do is to wait and see what comes out on the investigations in Gulf of Mexico and to the extent there are similarities. We will definitely take care of that in that context but its very different context. This is also a production well and another exploration well from a fixed platform with totally different Reservoirs. So the situation of very different. We are no [investion] it was so 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.

Operator

[Sebastian Siefert] from JPMorgan. Please go ahead your line is now open.

Eldar Sætre

Are you there Sebastian? No.

Operator

There are no further questions on the telephone

Eldar Sætre

That was apparently the last question that quarters had. So today's presentation and Q&A can be replayed from our website at 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 good bye.

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Source: Statoil ASA Q2 2010 Earnings Call Transcript
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