Equinor ASA (EQNR) 2008 Q2 法說會逐字稿

Thank you very much. Ladies and gentlemen, welcome to this StatoilHydro Second Quarter Earnings Conference Call. My name, as it was said, is Lars Sorensen and I am the Head of Investor Relations. This morning at 8 AM Central European Time, we announced our results for the second quarter 2008 and sent the release through wires and to the Oslo Stock Exchange. The report can be downloaded from our website statoilhydro.com together with presentation slides used in today's conference call.

I will ask you please to take special note of our use of forward-looking statements, which is described on Page 48 in the presentation with supplementary. Today's call is slightly different from our usual setup. We have chosen to use a more simplified setup of slides and a telephone conference, and the changed setup is to accommodate the fact that two of our peers also have their results out today and many of our investors and analysts would like to follow all three companies. For the next quarter we will back on our usual format with a webcast and Internet-based question handling.

In a minute, StatoilHydro's CFO will take us through the highlights from the second quarter. After the presentation, we will open for questions, and the operator on this call will give you a short instruction as to how you should operate your phone in order to ask questions.

And now it's my privilege to welcome our CFO, Eldar Saetre, who will take us through the second quarter presentation.

Thank you, Lars. Ladies and gentlemen, thank you for joining us on this Friday afternoon. It's a pleasure for me to present StatoilHydro's results for the second quarter of this year. And the results are in general very satisfactory. We are delivering record earnings and high production in a strong commodity market environment. However, I would like to emphasize that the most important result for us as the management are not the ones created by the high prices, but the ones created by the strong performance in our organization.

Our focus continues to be on delivering on the short term and longer term ambitions. Today, we are showing that we are on the right track to achieve what we have set out to do. Our focus areas are, first of all on production, at the capital markets stay in January, as you might recall we estimated our equity production for 2008 to 1.9 million barrels per day for 2008. Strong production and high gas offtake during the first half of this year have made this estimate more robust.

Then it is about synergies. We are progressing according to our plans, with respect to realizing the annual 6 million in synergies from the merger. And this process also includes the ongoing process to restructure our offshore organization into a more flexible and efficient operating model. We also have strong focus on continuous business development, launching new projects as planned, and continuing with a high exploration activity, and securing new acreage. And finally, we have to secure safe, reliable, and efficient operations where the trend so far this year has been positive, but we still acknowledge that there are too many unfortunate incidents like the gas leak on the Statfjord A platform this quarter.

Then, I would like to move to the highlights of the quarter, which is on Page 2, the next page. There are four main characteristics of our second quarter deliveries. Firstly, we are a delivering 6% equity production growth compared to second quarter of last year; reaching an equity production of 1,898,000 barrels per day. This growth is coming mainly from solid production on existing fields and ramp up of new fields. The quarterly production is negatively impacted by the maintenance season which will continue over the summer months and also impact our third quarter production even more than as seen in the second quarter.

In summary, strong production during the first half of '08 and the Kvitebjorn pipeline repair being postponed to 2008, which I will revert to, and the high gas offtake makes the 2008 production guiding more robust.

Secondly, we have started production from eight new fields on the Norwegian Continental Shelf. We started production on six fields the Gulltopp, Oseberg, Gamma Main Statfjord, Vigdis East, Theta Cook, and Oseberg Delta and as was announced this morning also the Vilje has started producing.

Outside Norway, production commenced at the Deep Water Gunashli in April and Agbami was also announced on the 29th of July this month.

Thirdly, we have sanctioned three new projects in the second quarter. These are the Troll Field projects, the Norne M template on the Norwegian shelf, and PVSM in block 31 offshore Angola.

And finally, our exploration activity continues at a high level and is delivering good results. 12 exploration and appraisal wells were completed in Norway and 12 outside of Norway this quarter and of these 24 wells we have announced 10 discoveries, most of them in Norway. Three wells have been dry and we are waiting final conclusion from 11 out of the 24 wells.

I will revert to some of these topics later in my presentation, but let me now first give an overview over the financials on the next page. The net operating income for the second quarter is NOK 62.6 billion. This is up 74% from the same quarter last year and 22% compared to the first quarter of this year. The increase from last year is mainly due to a 44% increase in average realized liquids prices measured in Norwegian kroner. This price increase is comprised of 48% oil price increase, including condensate, and 37% average price increase in natural gas liquids. This is due to the wider differentials for these products in their current environment.

NGLs constitute almost 15% of our total liquids production in this quarter. Natural gas prices increased by 49% in Norwegian kroner compared to the same quarter last year. Lifting of oil and gas was at 1,736,000 barrels per day, which is up 8% compared to the same period last year. Equity production is up 6%.

Then there was an overlift in the second quarter of this year of 42,000 barrels per day, compared to an underlift in the second quarter of last year of 66,000 barrels per day. Now, this shift in lifting positions has also impacted our operating cost negatively due to the cost accruals reflecting our lifting position, and I will also come back to this.

The net effect of derivatives contributed NOK 3.3 billion, and I will come back to both these and other infrequent items impacting our income statement this quarter later in the presentation.

The net income in the second quarter amounted to NOK 18.9 billion; which by the way is the highest net quarterly results in our history. It's up 36% from the same quarter last year and up 18% from the first quarter, and it is primarily driven by the same factors as our net operating income.

Net financial items amounted to an expense of NOK 0.5 million in the second quarter, compared to an income -- net income of NOK 2.6 billion in the second quarter of 2007. This reduction, adding up to NOK 3.1 billion was mainly caused by decreased net foreign exchange gains of NOK 2.3 billion related to our long term debt and liquidity management.

The average income tax in the quarter was at 69.6%, which is up from 63.9% in the same quarter last year and is slightly down from 71% in the first quarter this year. And the increase in the tax rate from last year was mainly related to a higher-- relatively higher income from the Norwegian Shelf, which is, as you know, is subject to higher taxation than the average corporate tax rate; and also reduced net financial items at the lower than average tax rate.

Let me then address more specifically our production volumes on the next page. As already mentioned, our equity production averaged 1,898,000 barrels per day in the second quarter. The entitlement production is up 2% to 1,710,000 barrels per day. Now this implies production sharing effect of 188,000 barrels per day in the quarter, compared to 115,000 barrels per day in the same quarter last year.

For the first half of 2008, equity production is up 7% to 1,973,000 barrels per day compared to 1,837,000 barrels per day in the same quarter last year -- in the first two quarters last year. Entitlement production year-to-date is up 3% to 1,799,000 implying a production sharing volume effect of 174,000 barrels per day.

Increases in production between the quarters as well as on a year-to-date basis caused mainly from new fields coming on stream, ramp ups, and also higher gas offtake, partly offset by declining production at our mature fields.

I would also like to mention in this context that the production at Snohvit field resumed on July 10 this summer following a two-month scheduled turnaround. Overall, the Snohvit project is progressing in line with what we communicated following our first quarter announcement in May. The turnaround was completed as planned, and the damaged sea water heat exchangers have been repaired. However, we may still encounter problems with the sea water heat exchangers, and are therefore continuously evaluating when and how permanent the replacements can take place. Replacements of two of the heat exchangers are expected to take place already in the fourth quarter this year, and are expected to require an approximately 30-day shutdown period.

In addition, several extra monitoring and metering instruments have been installed to provide more detailed understanding of what happens inside refrigeration or the tooling box. We expect this fall to have a clear picture of the magnitude of the changes necessary to increase the production to full capacity, and to establish a plan to implement these changes. And we will come back at a later stage with this plan.

On the Kvitebjorn pipeline issue, following recent analysis and testing of repair solutions, it has been decided to postpone the repair project until summer 2009. Turning out the repair next summer will give us better time for planning. It will also reduce the risk and possibly cut down on the repair period. The Kvitebjorn turnaround schedule for this year will consequently be reduced to around two weeks in August. Kvitebjorn will therefore continue to produce, as it has done, since production resumed in January. The impact of this decision on our production estimate for 2008 is not significant as it will mainly be relevant to the liquids production.

As already mentioned, strong production during the first half makes the estimate -- full year estimate more robust. So, I would, however, like to remind you that the production in the third quarter will be impacted by close to 100,000 barrels per day as a result of maintenance activities; as well it will be impacted by somewhat lower expected gas offtake compared to the second quarter offtake.

In addition, based on production forecasts and realized oil price year-to-date, production sharing effect for the full year are expected at approximately 200,000 barrels per day, assuming that the oil price stays at approximately $125 per barrel for the rest of this year.

Then, a brief look also at our costs development on the next page; our production unit cost measured, based on equity volumes and adjusted for one-off restructuring costs arising from the merger in the first quarter as well as gas injection costs, was at NOK 32.1 for the 12 months ended in the first half of this year. This is compared to NOK 27.3 for the 12 months -- same 12 months, which ended on the 30th June last year, and NOK 31.2 for last year as a whole.

The unit cost has increased due to startup of new fields, higher maintenance costs, and general industry cost pressure. As you can see from this slide, the cost increase has not been significant so far this year, but we do expect somewhat higher cost in the second half of this year, mainly resulting from the ongoing comprehensive maintenance activities. We maintain our guiding of a range of NOK 33 to NOK 36 per barrel for the period 2008 to 2012 as communicated at our capital markets day.

Well, let's now take a look at our explorations results on the next page. As already mentioned our exploration activity continues at a high level and is delivering good results. Overall, we are satisfied with our exploration results so far. This year we have completed, that's until today, in total 50 exploration wells, of which 17 have been communicated as discoveries, 7 wells have been concluded as dry, and 26 wells are still awaiting final conclusions.

On the Norwegian Continental Shelf, most of the 14 discoveries so far are located close to existing infrastructure, which means that the development solutions can be quite efficient and the time from discovery to production can be relatively short. We expect to continue our high level of exploration activities throughout this year. More than 70 exploration and appraisal wells are expected to be completed at a cost of less than NOK 18 billion. On the Norwegian Continental Shelf, a significant part of the drilling activity is expected to be in mature areas close to existing infrastructure, but we also plan to drill several wells in frontier areas of the Norwegian Sea and in the Barents Sea.

Internationally, we will continue to pursue a high level of exploration activity combined with targeted business development activities; which is consistent with our growth strategy.

Rig capacity has been secured for the 2008 drilling program, and we are well positioned for further exploration drilling beyond 2008 based on our current drilling program and our rig positions.

Let me now provide some comments to each of the business segments, and I would like to start with exploration and production in Norway on the next page. Net operating income for E&P Norway in the second quarter was NOK 53.8 billion. This is compared to NOK 27.8 billion in the same quarter last year. The increase was mainly due to 43% increase in the average segment liquid price measured in Norwegian kroner, which contributed NOK 13.2 billion to the increase and a 38% increase in the transfer price on natural gas, adding NOK 4.3 billion to the EBIT improvement.

Higher lifted volumes of oil and gas of 9% contributed NOK 3.6 billion to the net income increase. The realized liquids price is on average $114.3 per barrel this quarter. And this is comprised of realized price of crude and condensate slightly above the Brent Blend, slightly above $122 per barrel and an average NGL price in the range of $70 to $75 per barrel.

The increase in net operating income was partly offset by an increase in operating expenses of NOK 1.1 billion. This is mainly due to higher activity as we have already touched upon. It's due to somewhat higher gas injections cost related to Grane. It's also due to accruals related to the change in our lifting positions from an underlift to an overlift position and also to some extent general cost inflation.

Exploration expenses also increased by approximately NOK 1 billion on a quarter-over-quarter basis; and this is due to increased exploration activities and also increased expenditure of previously capitalized exploration cost compared to the same quarter last year.

Other income increased by NOK 7 billion and this is related to a positive effect from a change in the fair value of derivatives in connection with a burn-out agreement.

Then some comments to our E&P business outside Norway and as on the next slide, net operating income from international E&P in the second quarter was NOK 9.6 billion and this is compared to NOK 3.7 billion last year. The increase was mainly due to a 48% increase in realized liquids prices measured in Norwegian kroner and this contributed NOK 4.1 billion. It's due to the net gain of approximately NOK 0.4 billion from the sale of assets and reversal of impairments from previous quarters of NOK 2.1 billion and this is fixed approximately NOK 0.9 billion in a positive contribution to the DD&A, which is depreciation and approximately NOK 1.1 billion to the net exploration expenses.

These increases were partially offset by approximately a NOK 500-million change in cost accrual related to our lifting position. Total exploration expenses were NOK 0.5 billion in the second quarter of 2008 compared to NOK 1.4 billion last year. Now, this decrease was, as already mentioned due to a reverse impairment of NOK 1.1 billion related to acquired and unproved exploration assets in the Gulf of Mexico, partly offset by somewhat higher drilling and seismic costs.

Then to our natural gas business, on the next page; our natural Gas segment shows an accounting loss of approximately NOK 600 million in the second quarter. This is compared to an income of NOK 1.4 billion in the same quarter the year before. The average sales price increased by 49% contributing NOK 5.7 billion, and this is offset by higher cost of goods sold, which reduced income with NOK 4.3 billion.

The volume weighted average sales price in the second quarter was NOK 2.33 per standard cubic meters compared to NOK 1.50 per standard cubic meter in the second quarter last year. The gas transfer price was at NOK 1.73 and NOK 1.25 per cubic meter in the same mentioned quarters. There were also significant negative changes in the fair valuation of derivatives, which reduced net operating income with approximately NOK 2.2 billion on a quarter-to-quarter basis.

In addition, higher operating, selling, and administrative expenses reduced income by almost NOK 0.9 billion, mainly from higher transportation costs and also some other infrequent cost provisions.

Natural gas sales for the quarter were 10.1 billion bcm, compared to 10.2 billion standard cubic meters in the second quarter of last year. And the entitlement gas sales were up 13% to 9.4 bcm in the quarter.

And now finally to our last segment on the next page, the net operating income for manufacturing and marketing was NOK 1.2 billion compared to NOK 2.9 billion last year. The difference is mainly due to lower trading results and reduced refining margins again in Norwegian kroner.

Net operating income for the oil sales, trading, and supply business in the second quarter was approximately NOK 300 million compared to NOK 1.4 billion in the second quarter last year. The decrease was mainly due to losses on inventory hedge positions, which do not qualify for so-called hedge accounting and also somewhat lower trading results, partly offset by gains from higher prices on sales and on sales from our operational storage.

Net operating income from the manufacturing business was NOK 0.8 billion compared to NOK 1.1 billion in the second quarter last year. This decrease is caused largely by lower refining margins in Norwegian kroner and this is due to the strengthening of the Norwegian kroner versus U.S. dollar on a quarter-to-quarter basis.

Net operating income for energy and retail was NOK 0.1 billion in the second quarter compared to NOK 400 million last year. This decrease was mainly due to an accrual of NOK 200 million related to future restructuring costs in our Swedish operations.

So, let me now summarize the non-recurring items impacting our net operating income in this quarter, as you can see on the next slide. As you can see, I have already mentioned, the aggregate effect of these infrequent items in the second quarter had an overall positive effect on the corporate results. The result for E&P Norway of NOK 53.8 billion is positively impacted by NOK 7.2 billion from so called one-offs. Now this is due to an overlift impacting the result positively by approximately NOK 700 million and positive impact of NOK 6.5 billion related to change in the fair value of derivatives from again these earn-out agreements, which mainly is the Idemitsu agreement which was introduced quite a few years back actually.

Let me remind you that the impact of this derivative agreement can be significant both in a positive and in negative direction depending on future commodity price outlook at any time.

In the international E&P segment, the non-recurring items added up to a positive NOK 3.2 billion this quarter. We have already mentioned reversal of impairment in the Gulf of Mexico portfolio was NOK 2.1 billion. In addition, the change in the lifting positions had a net positive effect of NOK 1.1 billion.

Natural gas was impacted negatively with NOK 2.5 billion from infrequent items this quarter coming mainly from valuation of the various derivatives.

Within manufacturing and marketing, there was a net effect of zero due to a negative effect from inventory adjustment of 1.2, restructuring cost in Sweden of 0.2 as mentioned, and a positive operation and storage effect of 1.4; and it all adds up to zero in this illustration.

And finally, the eliminations had a negative impact of NOK 1.3 billion related to realization of values from reduced oil stocks.

So, adjusted for all of these non-recurring items, net operating income would have been NOK 55.8 billion for the quarter against NOK 36.5 billion last year, which is an increase of 53%.

So, let me now switch to the outlook for the third quarter, this quarter. Next page; as previously mentioned, the third quarter will be heavily impacted by our turnaround program. We have scheduled maintenance activities impacting quarterly production with close to 100,000 barrels per day. Further, we expect production in the third quarter to be impacted, as mentioned, by somewhat lower seasonal gas offtake compared to the second quarter. In addition, we are continuing our high level of exploration activity and plan to complete at least 70 wells for the year as a whole.

And finally, several new projects will be or have already been put on stream in the quarter like the Agbami in Nigeria and the Saxi-Batuque in Angola and the Vilje also having been put on stream today in Norway.

Then to my final slide, the guiding, next page; at the capital markets day in January we estimated our equity production for 2008 at 1.9 million barrels per day and it was mentioned that strong production and high gas offtake has made this estimate more robust.

Capex is estimated at around NOK 65 billion for the year and the main reason for the reduction from previous guidance is the strengthening of the Norwegian kroner versus the U.S. dollar, the exchange rate, which is now assumed in this estimate to be at the current level for the rest of the year.

Our exploration program is expected to cost less than NOK 18 billion mainly due for the same currency reason.

And finally, the production unit cost based on equity volumes is expected to be in a range of NOK 33 to NOK 36 per barrel for the period '08 to 2012.

And as mentioned, we anticipate somewhat higher cost in the second half of this year as a result of the comprehensive maintenance program as already mentioned, and for 2012 there are no changes for guidance.

So with these remarks I thank you for the attention so far and I return the microphone to Lars who I assume has a few questions from you.

Thank you very much, Eldar. We will start the Q&A session shortly. But in addition to Eldar Saetre and myself, we are joined in the studio by head of corporate accounting, Mr. Kare Thompson; and the head of performance management and control, Mr. Torgrim Reitan.

Before I leave the word to the operator, I would like to appeal to you not to bundle your questions, but try to ask one question at a time, with possible follow-up questions in connection to the answer.

Operator, could you please take us through the procedure for asking questions?

Thank you very much. (OPERATOR INSTRUCTIONS)

Our first question comes from Jason Kenney, ING. Please go ahead.

Hi there. It's Jason from ING. I just had a question on your sensitivity guidance. I notice in your supplementary slides, updated guidance on sensitivities for 2008. It does appear that since the first quarter going into the second quarter, you are likely to be less sensitive to the oil price, more sensitive to the gas price change, and more sensitive to FX. I just wondered if you could explain the moving parts there. Is it the base assumption, the starting levels, or is it just better modeling?

I think this is basically related to the modeling. This is not now statistically comparable deviations. So this is really a 10-US dollar practical number on the oil price. It's the gas price of 60 ore or NOK 0.5 per standard cubic meter and also 50 ore per USD.. So generally speaking, obviously I mean we are very sensitive to the oil price. So I would definitely say the oil price is relatively speaking where we have the higher sensitivity due to the -- that is the most important part of our portfolio and the commercial portfolio.

I notice for instance if the exchange rate moves 0.5 there I mean you used to look for a net operating income effect of NOK 13 billion but that's now NOK 19 billion. That's quite a significant change quarter on quarter to have that kind of sensitivity shift.

Well, that you know has to do with the production volume and the level of oil price that this is not modified by, so there's no other sort of impact than those factors.

I mean was that not in the last quarter then?

I haven't got the numbers for last quarter actually in front of me.

I don't think we can answer that more closely here, but let us try to come back to that and see whether there are any better answers for that here but I mean -- there are no big changes to the way that we have modeled it before. But it may actually have a different impact with the level of exchange rate and oil price we are in now. That's the best answer we can give right now.

Okay. Many thanks.

We have now our next question from Edward Westlake from Credit Suisse. Please go ahead.

Yes, good afternoon. You've had quite a number of discoveries this year. You mentioned quite a lot in Norway were close to existing infrastructure. Is it possible at this stage to give us a feeling for the rough scale of the total resource base that you have captured? Other companies such as Shell and ENI are starting to do this at the half year stage as well. And could you give us some guidance to which are the key wells that you are most excited about in the second half? Thank you.

Well, when it comes to your request, which I can understand for providing the resource base coming from exploration. We are not in a position to give any numbers on that. Obviously we are following that internally but we are not ready to announce it. That's something we will have to come back to in connection with a capital markets day type of event. So we are not prepared to talk about that but generally speaking I can say that the additions to our resource base from exploration so far as very much in line with our expectations.

When it comes to sort of individual wells, what I can say on the Norwegian Continental Shelf is that there are a lot of discoveries, 14 discoveries so far and really that's what you see on the Norwegian Continental Shelf that we see mainly sort of smaller types of discoveries and medium size discoveries and there are no sort of new big discoveries turning up and that's a fact also for this quarter. So this consists just of a lot of discoveries, so there are really no significant discoveries that I would be prepared to give any numbers on at this stage. So that's something that we would have to come back to.

We have our next question from Iain Reid, Macquarie. Please go ahead.

Hi there Eldar; it's Iain Reid from Macquarie.

Hi.

Could I; do you mind if I ask two questions? Firstly, international operating costs have gone up pretty significantly in this quarter. I understand there has been startups, etc. But could you perhaps point us to where do you think the kind of run rate of international operating cost is going, maybe by reference to previous quarters. And secondly, you are selling gas now in Europe, UK, and the US. I wonder whether you can give some sort of rough breakdown as to the various percentages and quantities going in each direction. Thanks.

Well on the international side, I don't think, I mean -- there is an increase compared to the same quarter on the operating cost in the range of 500 million and that can fully be explained actually by the change from the underlift to an overlift position. So what we do in the accounts is actually to provide, to make cost provisions for the full cost, the full unit costs of both the underlift if we are in that position, it's a negative and if there is an overlift, we have the full cost for the overlift there. That gives quite a bit of volatility in the accounts related to any given underlift or overlift situation. In this case we have an overlift situation and it explains actually all of the rise in the operating costs.

On the international side there were new activities but not significant activities and there is also a slight currency impact, which is positive taking the US dollar and the Norwegian kroner. But overall, there isn't any significant change in the operating cost on the international side.

When it comes to gas, actually I didn't quite get your question, Iain, so maybe you could sort of ask me a little bit.

Yes, the total amount of gas sales you are reporting this quarter, I just wondered whether you can give us some rough idea; how much you are selling into continental Europe versus the UK versus the US for LNG.

Well, as you know, LNG is not a significant portion due to the situation of a couple-of-month shutdown on Snohvit, so that there haven't been very much LNG in the portfolio. On the split between the different markets, the most I could say is that basically you know we have 9.2 bcm, coming from the Norwegian side and then there was a freight impact and it impacted (inaudible) into this, the main part of this going into the continental market. If you look at this on a sort of short term versus longer term basis, longer term contracts, I think long term contracts represent more than 90% of the overall portfolio but -- and that probably we should expect to see also going forward and short term contract obviously a much lower share. The more specific split between the UK and the continental volumes; I haven't got those volumes and I am not prepared to talk about that today.

Okay, Eldar; thanks a lot.

We have our next question from John Olaisen from Carnegie. Please go ahead.

Hi there. And thanks for taking the time to take a telephone conference. I wish you could have a presentation like you used to actually. It's somewhat difficult to hear you on the conference call. Anyway, my question goes to the -- or it is related to the production guidance for 2008. In the first half of the year your production was 7.6% up year-on-year and you are sticking to 1.9 million barrels for 2008; which implies that your production for the second half of this year is going to actually fall compared to the second half of last year. So, either there is a huge drop in production in the second half of the year or your guidance seems very conservative. Do you want to comment on any of that or I have I missed out on anything?

Well, your number; your counts are right. So what I can say is this is to repeat the statements that we have given. First of all, we have a very strong gas offtake, both in the first quarter and in the second quarter; stronger than we have been used, actually; quite much so. And we do not expect that situation to be maintained going into the second quarter at least. That's something we take into account when we guide you on this. Then there are quite a few comprehensive maintenance activities both actually on the international side and in Norway. So that's the most specific factors. On Snohvit we are now more firm that there will be a 30-day shutdown in the fourth quarter compared to what we have sort of seen before. So that's now more firm than we have seen before.

Then adding all of these up what we have said is that the -- even though the number is the same, it is a more robust number and we are more comfortable, a little more comfortable with 1.9 than we were previously; but we are not ready to give any new numbers, so as we say, it's a more comfortable number, more comfortable perspective, but we are not ready to give any new number.

And maybe you could comment or give a comment also to the gas takes which were very high in the first half of the year. Any reason to expect that would be different in the second half of the year? And also maybe related to the fact that you are postponing the repairment of the Kvitebjorn pipeline; is the high gas take in the first half of the year have anything to do with that? And do you need the gas from Kvitebjorn for the second half of this year or anything any thoughts like that behind the decision to delay the repair of the Kvitebjorn pipeline? Two questions really; and any reason to expect gas take or gas take to be lower in the second half; and secondly if Kvitebjorn is related to that?

Okay, when it comes to sort of our perspective on what the customers would do; that's simply based on typically what we see and actually have seen in previous years there is a seasonal pattern. So you have to know in second and the third quarter it's typically much lower than the third than the first and the fourth quarter. And the second quarter has been slightly higher actually than we have typically seen. And then there is a gap here which ends in the third quarter. So putting together gas here and the fact that we have seen closing in the third quarter and the fact that we have seen higher offtake so far that's excess in direction of lower offtake in the third quarter, but when it comes to the Kvitebjorn, I mentioned that the main implication should be expected to be on the liquid side. You should not expect us to simply -- I mean what our main concern is to create values in this and we are looking into the future and have sort of a perspective as to how markets would develop. And we also have flexibility as you know on the Troll and on the Oseberg. So you shouldn't expect us to -- the fact that these do not come into production, that gives us more flexibility to put it that way. But it's not necessarily a consequence that we will pull these volumes into the market at this time. So it gives us more flexibility but to conclude that this will come into market in this year, that's not something that we can sort of advise you on. But it gives us little more flexibility.

What is the reason behind the Kvitebjorn decision; that was definitely not sort of market perspective. That was pure safety, the technical aspect of that into that conclusion for sure.

Okay, thank you. And my final question is related to the exploration expenditure in Q2 in Norway. In Norway we had very high success rates in your drilling in the second quarter of the year. But still you expensed 1.5 billion out of 1.7 billion spend on exploration in Norway in the second quarter, and I would have thought that the exploration expenses were going to be somewhat lower due to the high success rate. Any reason why they expensed so much of the exploration costs in the quarter?

Well first of all, there are a lot of factors going in to the exploration cost and some of this is not; quite a bit actually is not related to exploration success. But there are a lot of cost elements in any case expensed. This quarter what happened is it's typically slightly higher exploration expenses than we have seen both compared to the same quarter last year and the previous quarter. That's what you see on the Norwegian Continental Shelf. Mainly it comes from two factors. It's higher exploration activity, driven both by activity and higher cost and higher seismic cost in particular. And it also is related to the fact that we have expensed slightly more from what has been capitalized in previous quarters; this quarter compared to earlier quarters.

So close to 500 million is actually expensed, and there are a lot of wells going into that from a consideration of the status of our wells, that have been capitalized previously. So it has to do with the activity level and the expensing of previously capitalized and if you look at what is being capitalized, that's pretty much around 50% and also as it has been also in the same quarter, now the capitalization portion. So overall there will be changes from quarter to quarter, but if you look at this on a more aggregate basis we had also overall activity levels at more than 70 wells, less than NOK 18 billion and we have a high success rate, so I think you should look at this at more perhaps on a quarter-to-quarter basis than any sort of indication or any sort of higher cost level.

Okay. Thank you.

Our next question comes from James Hubbard from Morgan Stanley. Please go ahead.

Hi; good afternoon. Just one question; you highlight upfront of your press release that you see prices for natural gas to be increasingly determined by the power industry; coal, nuclear, renewable; to set the price. I am wondering, given that you have put this near the front of your press release, what are you trying to tell us here? Are you -- how do you see your portfolio of current gas sales contracts which are predominantly oil-linked if I understand correctly, evolving given that outlook and what do you think impact on Statoil's averaged European realized gas price will be in that, given that outlook?

I am not prepared to go into sort of the more consequences; then I would have to extend my outlook here, because that's carefully prepared in the statement. This is what we can say; what you do see is that the power segment is gradually increasingly representing, being more and more important for the growth within the gas segment and the energy demand for gas. So this is simply reflecting that and I think that and I think that's a common point of view and given that is the case, the alternatives into the power sector to gas, that is also very much important in terms of determining the gas price level and increasingly so.

And that goes back to coal obviously and the cost of getting coal into this. And it also puts more emphasis on the climate issues and the alternatives and so the impact of the various alternatives on the relation to climate issues. This particular effect and these kinds of perspective; I will not be prepared to take this any further into consequences for the gas price.

Okay, could I ask a separate question then please? And that is the restructuring costs are clearly having a large effect on your current reported OpEx per barrel. When can we expect to see an end to these restructuring costs? Are we near the end of the program now?

We are at the end of the program. There is no additional restructuring cost now this quarter. So this goes back to the one-off that we had in the fourth quarter, as I mentioned, and there have been no additional restructuring costs in the first quarter or in this quarter. So the only restructuring cost that we talked about is related to the Swedish retail business and that has that has nothing to do with the merger, actually. That's something that we would have taken in any case.

And the only reason why we talk about restructuring cost at all is because the production cost per barrel are calculated on a 12-month average basically. So, in that sense, the fourth quarter in there with restructuring cost is distorting the picture a little bit. That's what we try to show, but there are no new restructuring costs as a result of mergers coming in now.

Okay. Thank you.

We have now the next question from Colin Smith from Dresdner. Please go ahead.

Good afternoon, gentlemen. I have got a request rather than a question. You provide quite helpful breakdown of equity production per field for international E&P on Page 34 of your presentation, but it would be most helpful still if you could provide the entitlement production since that's obviously what drives the results in international. So that would be my request that you produce that in the future.

Well thank you, Colin. The only problem is of course that we cannot talk about the individual PSAs and if we talk about entitlement production and equity production per field, you will be given the PSA per field, which we can't talk about because of the agreements we have. So it's a little big of a problem if we give both.

Well maybe the best thing to do would be not to publish the equity and to publish the entitlement then, if you can't publish them both together.

Could be a possibility but then we wouldn't really be able to focus on what we are controlling, i.e. the equity production. And I know that there are pros and cons with both and this is one of cons with showing the equity production, but we have to try to focus on what we can do something about, i.e. the equity production.

Unfortunately that's not what drives your results. So, from any analyst research point of view, it's the entitlement numbers that matter.

I totally agree. And that's what we try to give as comprehensive guiding on the PSA as possible. But anyway, we'll take your comments and take them into consideration.

Thank you.

The next question comes from Christine Tiscareno from Standard & Poor's. Please go ahead.

Thank you. I just wanted to find out if you have any plans for upgrading your refineries and if you don't, why? Wouldn't it be advantageous to have them being able to process heavy crude oil in this environment?

Well, you know, we are continuously working on modernizing and updating our refineries and we just sort have been through an investment process now in Kalundborg to increase the capacity to take on heavier crude into the refinery. And so the upgrading capacity on that refinery has been increased. Currently, there are no specific plans for doing that at the Mongstad refinery but that's something that we would continuously evaluate but we are always looking and we have lot of more immediate types of investment projects at all our refineries and now mainly at Mongstad which is designed at increasing the yield and the efficiency of the refinery.

Thank you. If I may just ask on final small question; do you have any derivatives in place that are fixed that might affect you in the second half of this year?

Derivatives that might affect us, yes, all derivatives basically might affect us. We have derivatives but there is lot of smaller stuff as well but the main thing is derivatives that we have on the E&P Norway side. I mentioned it; and I mentioned specifically the earn out agreement which is defined as a derivative. And that really can impact us quite significantly and that will be depending very much on the forward prices for the next five years, forward prices at any given time that would automatically go into the calculation and this time we have an impact.

And then on the gas side, the development in the UK gas market would have an impact to the extent that it differs from the development in the underlying components going into the other long-term contracts like oil products. On the downstream, again we would have derivative effects continuously related to our credit activities and also impacts from storage. So, I think this is a component that is there to stay, let's put it that way, and we will have to put a lot more effort into sort of making this a high quality and sound fair value considerations in every quarter. And we will continue to report this separately so that you can if you like adjust for these numbers in the quarterly announcements. But yes, we would definitely see this both in the third and fourth quarter.

Thank you very much.

Our next question comes from Neil McMahon from Sanford Bernstein. Please go ahead.

Hi, I have got a few questions. Maybe just going back on the natural gas price outlook and maybe leaving price to one side and focusing in on your comments on supply and demand; you seem to indicate that the supply situation will be rather tight as a number of new supply schemes are delayed, are you talking there from the power side of the market in terms of coal or gas-fired power-plants or indeed renewables, or new gas supplies coming into Europe that you see are being delayed?

Well, we have definitely seen new supply sources coming into Europe but also delays in this that has been going on for some time. We expect that situation to be sustainable for the rest of this year but then we should expect that this new capacity eventually will come into the European market, but it's available for the European market.

So, we think that it would still overall be a tight situation beyond the very short term or the medium term, but it is not as it has been over the last couple of years, to put it that way. On the demand side, generally we see a strong growing demand for energy and we believe that gas is going to represent a strong part of this picture going forward for various reasons, and one of them is related to the climate issues and concerns, and also general additions for instance related to both energy efficiency and renewable shift going forward and I think this is toward gas going forward.

But just in terms of that demand and supply outlook, when do you think that the proportion of your gas sales that are on current spot prices that are unlinked from the European long-term gas contracts, when do you think that will substantially increase? So, obviously your current gas sales growing from the new production going into the UK are based on UK prices, when do you feel that you will see some of your longer-term contracts rolling off?

This is a complex issue and I cannot -- I mean there are -- things like that support also the continued link to oil for quite a long time, and so I think you should not expect any sort of rapid or any dramatic change in this balance in the few years ahead of us. So, to speculate more precisely over this, I wouldn't do that.

Maybe just a very quick last one; given where we are at in the current commodity prices and the fact that even your CapEx has come down a bit due to currency admittedly, where are you in terms of giving us guidance on any potential special dividends for the year or indeed even discussing buybacks again?

Well, I think the short to answer that is we are not yet ready to give any guidance. We have a net debt ratio at the moment at 2%. The huge development of our balance sheet is obviously very much dependant on the commodity environment. We will just have to watch that going forward. But we are comfortable for the time being, our priority is to finance investment opportunities that are good for our shareholders. On share buybacks we have no mandate for the time being and there are no plans to go to the General Assembly and ask for any mandates neither on share buybacks nor on any special dividends for the time being, but the situation is simply that we will have to look at obviously going forward.

But you must admit that you didn't plan your budge on an average price for $115 oil price this year. So, I am just wondering at what point do you run out of near term investment opportunities and start looking towards the special dividend. Is that something that you've got the opportunity to do with the Board over the next six months?

I would not speculate any more on this. On the investment opportunities, we see definitely that to get access to new opportunities is something that you would have to do at a continuously higher cost and we are in that game even though if you see that our investment program is down due to the currency, we have a plan to address the investments program going forward and we also see that going into 2009. So, I think that's our priority, but to speculate anything about how this picture is going to look going forward, I am not prepared to do that.

Okay, thanks.

We have a question from Iain Armstrong at Brewin Dolphin. Please go ahead.

Good afternoon gentleman. I am sorry I have a very, very bad line here, I hope you can hear me because I didn't catch a lot of the stuff that was said, and so if the question has been answered already, I do apologize. In the E&P Norway, this comment about the change in fair value in certain earn-out agreements which accounted for NOK 7 billion; quite a big change. Is that a one-off, the use of taking off that's been just building up or are we going to have that on a basis quarter by quarter because of the very sharp increase in the oil and gas prices over the last 12 months?

Well it is, in many ways, a one-off. This is based on the future commodity prices. Actually this is seen by the forward markets and our own assumptions beyond that. So, depending on how the forward market is developing and how our own assumptions are developing; that might change the value of these derivatives from quarter to quarter. So, that will be --- might be quite significant as you have seen this quarter or both positive and negative from quarter to quarter.

This derivative specifically is something that we were carrying with us for quite a long time and this specific case. So, yes it is a one-off but not more one-off that you would probably see the effects of this in most quarters going forward because it will move up and down as I said, reflecting the forward current commodity environment.

So as long as the future price is above the spot price, there is going to be a little of an impact each quarterly report. Is that what you are trying to say?

If the forward price is higher than it was in the previous quarter.

In the previous quarter, yes, I understand that. Alright, okay. And it is just because the change has been so much larger in this quarter that NOK 7 billion is as high? Normally it would only be not even worth talking about, a little bit like what Shell said yesterday, that it's just something that has come up because it sort of mucks up the numbers a bit? Hello?

Sorry, I didn't get your question, Iain.

I am just saying that is this something that it's because you had a 47% increase in the oil price in quarter two, just the two in the first quarter and the second quarter; it's just because that increase has been so large, for example, if the prices are flat as you said, then there won't be an adjustment at all. Is that right?

You have two effects there. One is to realized effect and one is the future effect in the derivative. So it is reflecting the future potential earn-out from this contract. But you also have an effect in this which is realized in the quarter and that is depending on the oil prices in any given quarter; but the derivative effect; that is related to the future, beyond the quarter only. So this has nothing to do with today's oil price but it is the future oil price, in fact the future value of this derivative, of this contract, this earn out agreement; a change in the future value as defined by the forward market really.

Okay, and then in your operating, general and administrative expenses up 18%; again it might be asked before; it's up 18%. In the first quarter that number was only up 5%. Were there any extraordinary items in there, apart from maybe exchange rate or something, which affected the number so much? I think you made the point that the adjustments for the Hydro merger are virtually now coming out of the numbers. Is that the last effects of it?

The merger has nothing to do with these changes. The increase, which is slightly higher this time, is related mainly to three factors. One is the higher activity and volumes that keep coming into production like the Snohvit. But they are also delivering volume. So we don't see that in the unit cost but we see it on the actual cost, actual cost levels.

The second one had to do with the cost provision that we do, and I mentioned that previously, you maybe didn't hear that, but it had to do with the way we made cost provisions for overlifting. So this time we had a very significant switch from underlift to overlift. That is we took out more volumes, sold more volumes than our relative share of the production. And for this difference we accrue, we make cost provisions for the full unit cost. What you get is significant volatility and that volatility was much bigger this time than it was in the previous quarter. Actually for E&P Norway it was almost NOK 500 million, explained simply by the change in accruals, cost accruals.

And the last element I would mention had to do with the slightly higher cost related to the purchase of Grane gas injection. That is the reason. Unit cost is pretty much stable on the Norwegian Continental Shelf. This has nothing to do with that.

Right; because although the number you gave, the unit cost of barrel was virtually-- it's only about a kroner higher. If you look on page 4 of the press release, it says that production cost barrel of oil equivalent at a flat exchange rate is actually up 51% on the year?

Well that includes the full cost; that includes oil for the restructuring cost that was accrued, was a one-off in the fourth quarter last year. That was a one-off. So, that sort of goes into and explains that, we haven't seen any additional restructuring cost now in the first and second quarter and we don't expect any further restructuring costs. That was a one-off which explains that significant cost increase that you referred to.

I am sorry the line is very, very poor. I didn't catch-- was that one-off in the fourth quarter; is that what you said?

Yes, a significant one-off in the fourth quarter.

And remember the production unit cost is calculated on a 12-month basis. So when you compare the two numbers, you have to compare the last 12 months and you have to compare the last 12 months a year ago, basically and that has nothing to do with the one-off restructuring cost.

Okay just a final question again, do you expect a third quarter overlift of gas as well as you had in the second quarter or is it that -- I think you said something along the lines that because you've -- the third quarter near the end of the gas year that you are not likely to see that. Again, I am sorry the line has been so poor and I am afraid, I mean your webcast has been always very good but this has been very difficult.

Okay we will have to do something about that. When it comes to gas, typically we don't have the issue of overlift versus underlift. This has to do with oil where you have shipments, you take ships from the source, producing source which are now sort of on a quarterly basis equivalent with your ideal percentage of the production. So, this has to do with oil guiding on under or overlift that is possible. What I can't say in general is that if you have overlift in one quarter it is more likely that you will have an underlift in the next quarter but it is not necessarily like that. It is very hard to be precise on guiding on overlift versus underlift. But over time it will level out, you will lift what you are entitled to.

Yes, I expect that, yes. Okay, thank you very much.

Our next question is from Neill Morton from MF Global. Please go ahead.

Hi there, just the one question. Just intrigued that the move in the dollar assumption from NOK 6 to NOK 525 is the same in percentage terms as the move in your CapEx budget from NOK 75 billion to NOK 65 billion, I guess one could infer that all your CapEx is therefore in dollars, I am sure that is too simplistic, but could you tell us how much of your CapEx is in dollars and are there any other moving parts to that reduction phasing, for example. Thank you.

When you look at our investment standing and at the NOK 65 billion a year you will see that somewhat above 50% is related to the Norwegian Continental Shelf and the majority of the rest is from the international business. The international part is of course directly linked to the US dollar.

And on the Norwegian Continental Shelf, you will also see that a lot of the costs are implicitly related to the US dollar as well. So it will have significant impact on the Norwegian Continental Shelf. So, the majority of the reduced investment is related to the change in assumption for the US dollar and then for the first half we experienced a US dollar of 5.20 in average and for the rest of the year, for this purpose we have used 5.25.

And any other moving parts?

In the national program, I think it is worthwhile to mention that this investment guidance is organic investments as we call it, I mean it is from the development we have accessed in addition to that number we have acquired 50% of the Peregrino field from Anadarko earlier this year and that will also be part of the investment that is not part of this 65. So, any acquisitions and so on will come in addition to this 65 and that is, of course, a moving part.

Okay, fine. And if we assume 5.25 next year and in 2010, what CapEx number should we type into our models?

I think we will come back on at the year end on capital markets day.

Okay, great. Thank you very much.

Our next question comes from Gudmund Halle Isfeldt from DnB Nor. Please go ahead.

Hello. I have three questions for you. The first one is on your NGL realizations. They seem to be decoupled from the oil prices. Is this going to continue?

Well, that's a good question and I wish I could give you an answer, and a good answer. Generally speaking, we have been with -- we see NGL as much like a lower density than crude, so to the extent that you see prices, it's sort of crude-- stays at the same level. You shouldn't see for that reason any relative changes in NGL but if you see movements you will see more movements, upwards on NGL compared to crude for that reason, because there is lower energy content in these products.

Then the other component, very much depending on, on sort of the supply and demand for these products which is typically propane and naphta in our case. There are typically seasonal variations in this and then it's depending very much on the gasoline market and refinements would lead to the requirements on naphta and demand for naphta. And this has been quite soft recently. So there could be arguments that the gasoline market could sthrenghten a little bit going forward. And that would strengthen it.

Within the other main parts built into the petrochemical industry and they're obviously competing source with very much gas as such. Again, I would not speculate too much, but what you all know is that there is now additional petrochemical capacity coming into the market from the Middle East, and that could sort of support these products.

But what I would say is it's very difficult to be very specific on this; there is the debt position which technically is down. But there are also some other forces that could take it up, so how this is going to end going forward I couldn't say but what I would say is that even if we have this spread for the time being, it is actually the highest, it's also high for NGL -- this comes from gas really, and the alternative for us to be sort of leader with gas, and that sort of create less value for us then taking it out and making it into liquid. So, I think this is the best way for us to create value for our shareholder and where it will take us going forward, that's difficult to say.

Okay, and a question on the startup of Victoria in the Norwegian Sea; I guess it is going to be in 2012. If so, will you need a new pipeline and will it then take into account Stetind into potential new fields?

I think the old issue of pipeline capacity from this area of the Norwegian Continental Shelf will have to sort of be looked into very carefully and include obviously all the potential in the area so this will have to be looked upon in a holistic way. And now specifically to Victoria, we are not the operator and definitely there are no specific conclusions yet that that would have to require additional capacity and what can be done also in our expanding the current capacity in the existing pipeline. So, what is net of these considerations; that's too early to say. But obviously all development potential in this region would have to be factored into this equation.

Okay and the last question will have to do with Troll West Oil price; when you are going to start injecting gas into Troll in order to increase the recovery factor, etc?

Well, I mentioned the Troll project; that is our main project and gas injection is one of them. To develop that, I haven't got the exact date for the impact of the injection project but that is something that I will have to revert to this because I donat have the schedule for that, but this has already been approved and is going forward.

Okay. Thank you.

We have got a follow-up question from John Olaisen from Carnegie. Please go ahead.

Yes, thank you. Thanks a lot. It's regarding the international production. In Q2 this year the net entitlement production in percentage terms of the equity production was only 59%, down from 67% in Q1. Where should we expect this to go going forward? Will it continue to see that gap increasing and is there any chance that it will be reverted or is it only likely to be increased- that gap?

Thank you, John. When it comes to the PSA effect, we have given you guidance on the 2008 production and effect towards 2012 at the capital market day in January. So in generally speaking, yes, PSA effects are increasing and knowing that is the pure consequence of the commodity market that we see, that we earn a lot of only money from this license.

So this is all related to the agreements that we have. But what we see is also a large yield especially in Angola, and also of the tranches, so you see a diminishing effect for price increases. But with your specific question on the effect this year; you should take into account our Shelf production in the US Gulf, that is not part of the equation this year, and the production from Angola is very good and Angola is one of the areas still high with PSA effect currently. So I think that explains part of the change that you are seeing.

Yes. So for the second half, assuming oil prices stay where they are now, do you expect this ratio to be flattish for the second half or perhaps being even lower in potential of the equity production for the second half; given flat oil prices.

The guidance has -- actually my presentation was that given that you have the current price situation for the rest of the year, you will see the production share in fact, moving from or the difference between them moving from 188 in this quarter, to almost $200,000 at the in the of the year. So you can transfer this into percentages; I haven't got that number but you could--

Yes, excellent. Thank you very much.

Our next question comes from Michael Guy from Goldman Sachs. Please go ahead.

Mr. Scott Darling your line is open. Please go ahead.

Hi, it's Scott Darling here from Lehman Brothers. I've got two quick questions. I think in the past you've used the forward curve to partly justify acquisitions in the near term, obviously we've seen the curve coming off recently, and would you still be using that methodology if you looked at any further asset acquisitions? And the second question is you have been very kind enough to give PSA sensitivity for '08; forgive me if I have missed this but is there any chance of giving updates up to $150 for your production outlook to 2012. Thanks a lot.

I'll have to take the last one. I think when it comes to the 2012 issue that is something that we would have to add up as a whole when we get to the next, more capital market type of event and then surely we would be there to guide you on 2012. So in any case I am not prepared to guide on that kind of oil prices for the next four years.

Your first point on acquisitions, I don't think we have been specific on assumptions related to any acquisitions other than sort of -- longer term price decks in a couple of occasions and breakeven prices on a couple of occasions. So, what we do see is that there are definitely transactions made out there where presumably that kind of forward curve must have been used otherwise you wouldn't get to that kind of valuations.

But in our case, I have confirmed that we have used the forward curve in the some transactions. But obviously that it is the most important for us is to make sure that we actually have the right equation on top of this and that we have a prudent perspective of both oil prices and value creation opportunities. That's really what I can say.

Thank you.

As we have no further questions, I would like to turn the call back over to your host for any additional or closing remarks.

Well, thank you very much. Today's conference call can be replayed from our website, statoilhydro.com, and we will have a transcript available on today's call, including the Q&A session, in due course. For those of you who are on your way on holiday, I wish you a pleasant break, thank you for listening in and good-bye.