Equinor ASA (EQNR) 2007 Q4 法說會逐字稿

(Audio starts in progress) and other expressions used in the presentations here. Today's presentation will be split in two. First we have the Chief Executive Officer of StatoilHydro, Helge Lund, and then the Chief Financial Officer, Eldar Saetre. And then we have a Q&A session.

So without much further ado again I will give the word to our Chief Invest -- Chief Executive Officer, sorry, Helge Lund.

Thank you, Lars. Good afternoon and good morning wherever you are in the world. It's a pleasure for me to present for the first time the results of the new Company, StatoilHydro. And I wanted to start by saying that the results and the underlying performance of our Group is solid and in line with our guiding.

We see however that this quarter, the quarterly results, are impacted by, as we also said in January, one-off costs related particularly to the merger. And these costs are of course an investment in future benefits. And they confirm today that the synergies resulting from the merger will be around NOK6b in annual synergies moving forward. It is also in line with what we indicated earlier to you at the Capital Markets Day in London in January.

In addition to that, the results are also impacted by tax issues and other infrequent items that will be covered in detail either by me or, I think even better by Eldar Saetre a little bit later in the presentation.

I think it's fair to conclude, at least as we see it, that 2007 was a year with many highlights for StatoilHydro. Of course the biggest one was the share factor. We combined the two companies. And in addition to that, we have strengthened our Group in several other areas around the world. We have established new positions in Canada, and also in Russia, through the participation in the Shtokman project. And we have further strengthened our long-term position in Gulf of Mexico deep water through an active participation in the lease rounds there.

In addition to that, we have among other won new exploration licenses in Norway, in Brazil, and also a few weeks back in Alaska. On top of that we have added production capacity, new production capacity, from new quality projects in Norway, as well as internationally.

I believed since my first day in Statoil back in 2004 that the very logical way to take the Company forward was to merge with Hydro. Having worked with this merger for a year, I'm even more convinced that this was the right move to make in light of the changes in the industry environment as we see around us. Our key focus now is to deliver on the roadmap that we presented to you in January in London.

It is no surprise for you that I start by concluding that the oil price development since 2003 significantly has changed and reconfigured the oil and gas industry. The supply side is tight and is affected by very tight supply markets, increasing costs and also lead times on a global basis. I think still it holds to say that the industry continues to work at almost maximum capacity level in terms of hardware, but even more I think profound, in terms of the human competence.

We still expect a relatively tight supply market and highly-priced input factors. But we start to see, and I think we can confirm that message also since we met last time in London, some flattening out and maybe a better balance between demand and supply partly affecting the, or impacted by the fact that new capacity has been built in the supply industry. But also, I think, impacted by some more uncertainly around the economic climate and the development globally.

But to me increasing complexity is, or continues to be, the key feature of our industry, in the sense that technically we are attacking more and more complex project developments, deeper water, harsher environment, heavier oils and more and more tough projects. Commercially we see that (inaudible) resources are tougher and tougher and so to negotiating it and therefore access, I think for all of us, is more difficult.

And I guess it's close to natural law that when rewards below ground increases, as we have seen now recently, risk migrates above ground. And this is making an impact on terms and conditions generally in our industry. In this environment some companies defied the -- or have chosen to wait it out. Others continue to be active in exploration, active in business development, in terms of building the future reserve and production base.

To me an obvious response to these challenges has been to execute the merger that we have already talked about. And I believe it has strengthened significantly the new Company's competitive position in Norway, but more importantly outside Norway in terms of capacity, financial resources, technical resources and competence generally.

At our Capital Markets Day in January we set out the strategic roadmap for value capture and growth towards 2012 and beyond. The strategy is simple. We will take out the full potential, the full profitable potential, of the NCS while growing our international production. We focus strongly by fighting decline and add on new production capacity to grow production from 1.9m barrels per day in equity production to 2.2m barrels per day in equity production in 2012. We will deliver on the merger synergies, estimated to be NOK6b per year in annual benefit. We will continue to maintain capital discipline and continue to deliver competitive shareholder return.

A key to this, to all of these factors, is that we are successful in driving the operational improvement program at the Norwegian Continental Shelf, particularly related to production drilling and the uptime on our installations, particularly offshore. I think the development since the merger has sort of confirmed this picture.

The organization is now fully operational and working exactly on the roadmap that we have presented. It is important I think for you, as investors, and for us that the merger has released new capacity to work on the high-quality resource base and projects that we have in our pipeline. And I think also that it is important that these cost savings will make us more competitive and strong, therefore strengthen our long-term competitiveness.

In terms of deliveries over and above the merger, it has been a very active year in the sense that we have put 14 new projects in production and sanctioned another eight. We have completed 71 wells with 34 discoveries, including the important discoveries in Shah Deniz in Azerbaijan and the Julia well with ExxonMobil in Gulf of Mexico. We have accessed 22 new licenses and 77 new leases. And we have a growth in our reserve replacement ratio of 86%. This is less than our long-term goal of 100%, but competitive with many peers.

I think also it is significant to underline also at this occasion that we have a very attractive portfolio of new projects, which is also reflected in our high CapEx program going forward. And we confirm the guidance that we gave in January that roughly one-third of this investment program will go to secure existing production, while two-thirds will be used to further grow production.

Statoil has been, and Statoil will be in the future, committed to pay a competitive shareholder, direct shareholder return. And the Board of Directors of StatoilHydro will propose to the General Assembly that the dividend, the NOK1.5 -- sorry, NOK8.5 per share in a combination of ordinary dividend and special dividend that I will come back to later. This is a payout ratio of 61% for the year. And it gives an average payout ratio of [around] 51% since the IPO of Statoil in 2001.

In our industry the safety of our people is our first priority. And HSE is our most important performance indicator as we are running an industry with a high degree of risk. We focus on both the integrity and robustness of our installations, as well as improving behavior of the leadership and our employees throughout the Company. And it is very clear to me and, I think, to you, that the good HSE performance has very much to do with quality and therefore is directly impacting our bottom line.

We try to approach this and other areas through a holistic performance platform that is defined by very strict regulations when it comes to HSE, ethics, business integrity, and also related to clear leadership principles and requirements. And we are progressing in many areas, including serious incident frequency, as you see here on the chart. We were able to move our performances just another step in 2007.

But we feel that we have not been able to break the curve and really make a significant additional improvement on this and other factors. And this is very much in line with the industry trend that an extraordinary effort needs to be done now in order to be even better. Our recipe there is to capture or utilize the best practice from the two companies in order to have a catalyst for further improvements.

Also in 2007 we had some undesirable events in our operation. This is not acceptable. And our investigation of the large oil spill we had in December from the Statfjord A platform found technical and organizational weaknesses that we now have dealt with and put up a very forceful action plan. And we hope and assume that this will prevent similar incidents from happening in the future.

We work hard and will continue to work hard to improve our performance. I think we are on the right track. And I think that is also confirmed by the fact that we, for the fourth consecutive year, is ranked as the best oil and gas company in the world when it comes to sustainability. This is not proving that we're doing everything right, but I think it clearly proves that we are on the right track.

The net operating income for the fourth quarter was close to NOK31b. The result is significantly influenced by one-off merger related costs, as I already discussed, and also some other infrequent operating items not related to the activities of this period. These pre-tax restructuring and other merger-related costs of NOK10.7b corresponds to the after-tax cost of NOK3b to NOK4b that we presented in January, and should therefore not come as a surprise.

Adjusted for total non-recurring items of NOK13.6b, the net operating income was NOK44.4b for the quarter. This is an increase of 24% from adjusted income last year in 2006. Adjusted for the after-tax effect of the same items, net income for the quarter is NOK12.1b. And as I've already mentioned the financial items and tax are also impacting the net income negatively and more than we usually see. And Eldar will give you a very detailed explanation of that later in his presentation.

On the full year, both the net operating income and the net income fell. This was mainly because of merger-related and other infrequent items in 2007, together with higher operating costs because of new fields in production, i.e. with the full cost base but not full production, higher start up costs on fields with start-up problems and higher exploration costs and higher activity levels in general.

Adjusted for the merger cost of NOK10.7b before tax, we delivered a return on average capital employed of approximately 20%, and this compares well with our peer group.

Moving then to the production part, average daily entitlement production for 2007 came in at 1.70 -- 1.724m barrels per day and this is in line with the guiding for the year if you adjust for the PSA effects. We assumed at the Capital Markets Day at $60 level, the level was $70 instead, if you adjust for that we are more or less exactly on the target that we communicated to the market in December, and more subsequently in January, of 1.735m barrels per day.

The net debt as per year-end 2007 is around NOK25b. This constitutes of around NOK50b in gross debt and roughly NOK25b in cash. And the net debt to capital employed was 12% at the year-end.

Our strong CapEx program in combination with high return to shareholders is strongly linked to our current cash generating capacity. We anticipate our cash flows from operations also to be substantial moving forward, and as reported in January, we expect to be cash-neutral at an oil price of around $50 per barrel before the dividend.

As I mentioned already, an important goal is to deliver a competitive direct shareholder return. And we have to balance between capital distribution and necessary financial flexibility in support of our growth strategy within sound financial targets.

And our first priority is definitely to invest in profitable and strategic industrial opportunities, but if such opportunities do not exist, or the Company retains too much financial flexibility over time, then our priority is to distribute cash to our shareholders in line with our dividend policy. And that policy is unchanged. We will distribute 45% to 50% of net income to shareholders and we're committed to nominally grow the ordinary dividend year on year.

I mentioned already that we're proposing NOK8.50 per share. The ordinary dividend is proposed at NOK4.20 compared to NOK4 last year, and the special dividend is proposed at the NOK4.30 per share. The dividend is equivalent to a direct yield of approximately 5.5%. And as I mentioned earlier the proposal means that we will distribute 61% of this year's net income and 51% since the Company was listed in 2001.

Before leaving the floor to Eldar, let me briefly summarize 2007. We have in less than a year completed an enormously complex merger and it's truly operational. We have had a very high activity level in the organization, building new growth capacity. And we have delivered solid returns and production on top of that. I believe we are proposing to pay an attractive dividend for 2007.

And by that I invite Eldar to -- on stage to see whether he can speak louder than this voice that we heard. So the floor is yours, Eldar.

Thank you, Helge, and good afternoon to all of you. As you probably, most likely, already have noticed this quarter's results are I would say heavily, quite heavily influenced both from merger-related costs and some other, as mentioned by Helge, other infrequent items to this year's activities. But also from a loss on financial items, and I would say a higher tax rate than we typically would see in this Company.

None of these factors or special development for this quarter are in any way directly linked to the performance of the Company or the business activity as such. So I will now go through all of these elements in a logical sequence, and I will also add a few comments to our proven reserves and the capital expenditure, and also the exploration expenditures.

So this illustration, or call it a roadmap, that takes us all the way from the net operating income to the net income is highlighting in a separate color the items which I believe need some further elaboration in order for you to fully understand our reported numbers for this quarter. As I said already, adjusted for the non-recurring cost items of NOK13.6b, which mainly is related to the merger, the net operating income would have been NOK44.4b.

The after-tax effect for the same items is calculated at minus NOK5.9b which implies that the, again, the net income would have been NOK12.1b without the impact from these non-recurring or infrequent items. Financial items, I'll come back to that, is negative with approximately NOK700m this quarter. Tax rate is also exceptionally high.

So let me know first take you through some of the -- or all of the business areas and show you how they contribute to the net operating income. The net operating income for E&P Norway in this quarter was NOK32.6b. That is 4% higher than in the same quarter of 2006. The total infrequent items that you can see here for the quarter was a negative NOK4.6b for this business segment. Oil prices in Norwegian kroner increased by 24% on a quarter-to-quarter basis. And the gas transfer price increase by 3%, i.e. the transfer price between E&P Norway and natural gas.

Other income increased by NOK2.3b and this is mainly due to positive changes in the fair value of derivatives on the E&P segment, which is basically linked to some earn-out agreements. Operating expense were NOK7.5b higher than the same quarter last year. And again this is mostly due to NOK5.5b, which is related directly to the merger, but also somewhat higher operating and maintenance costs, well maintenance activities and also NOX fees on the Norwegian continental shelf.

Furthermore, the exploration expenses increased by NOK600m and also the depreciations increased due to higher impairment or asset retirement costs.

For the international E&P segment, the net operating income was NOK2.2b in the quarter compared to a loss of NOK3.4b last year. And the negative, the total negative impact on the non-recurring items on this segment was NOK2.8b. There was an increase in the lifted volumes of 37% and a 32% increase in the realized oil price and these were basically the main reasons behind the improved results.

In addition there was a NOK2.4b decrease in deprecations and impairment expenses between the two quarters. We have in this quarter had impairments of the Lufeng in China, Front Runner, Thunder Hawk and also the Gulf of Mexico shallow water assets that we have now sold, down to the market value of those assets. And all of this added up to approximately NOK800m in impairment for this business segment in the period. And this is compared to impairments of NOK3.1b in the same quarter last year for the combined Company.

The total increase in the net operating income for the international E&P was partly offset by merger-related costs, like for all the other business areas, of approximately NOK1.3b. And in additional there was the decrease in realized gas prices which contributed negatively to the results development.

Then to the natural gas, where we saw a net operating income in the quarter of a loss of NOK1.8b, compared to a gain of NOK6.6b last year, a huge negative development. This quite significant decrease was mainly due to an 11% reduction in the price of piped natural gas from the Norwegian continental shelf, the external price, combined with a 3% increase in the internal transit price between E&P Norway and natural gas.

And this combination led to a reduction of the internal margin from NOK0.57 in this fourth quarter of 2006 to NOK0.30 per standard cubic meter this quarter, that's almost a 100% reduction -- a 50% reduction. And consequently, as a consequence of this a NOK2.7b due to the margins EBIT reduction from fourth quarter last year.

So in addition to this NOK2.7b impact from he margins we have a negative change in the fair value of derivative of NOK4.6b from positive development last year, fourth quarter last year, of NOK3b to a negative development this quarter of NOK1.6b. So the difference is NOK4.6b on derivatives.

Merger-related cost was NOK1.3b in this quarter, and obviously none of that in the fourth quarter of 2006. And we also had an impairment of one asset, the Naturkraft asset at Karsto of NOK0.3b. So total infrequent items as you can see on this list for the natural gas added up to a negative impact of NOK3.2b for this quarter.

And finally the net operating income for the manufacturing and marketing in this quarter was a loss of NOK600m compared to a gain of NOK400m in the same quarter last year. Again restructuring costs in connection with the merger contributed NOK1.2b to this difference, partly from the related retail business in Sweden of approximately NOK500m, and early retirement cost allocated to this business segment of NOK700m.

Then we also had an impairment related to the Swedish retail business of approximately NOK600m due to weak market condition in Sweden and a need to restructure this part of our downstream business. Then I should also mention that the fourth quarter results last year, in the fourth quarter of 2006, was impacted by a gain of NOK600 related to the sale of our retail assets in Ireland.

So let me now summarize the non-recurring one-offs, or whatever you call it, items for this quarter. As earlier mentioned restructuring costs and other merger-related cost added up to NOK10.7b. Most of these costs came from the 58 plus as we call it, the early retirement scheme. But we also had additional costs related to transfer on multi-client seismic data, and as I already mentioned related to the restructuring of the Swedish retail business.

And we also had some alignment of the accounting practices, to use the right word for it, between the two companies. Obviously we have had some differences in the way we have practiced this and we had to align that and it led to some adjustments, which is also related to the merger. And as mentioned by Helge and as you can see the after-tax estimate of this merger-related cost is NOK3.9b, which is in line with the NOK3b to NOK4b range we then had guided on earlier.

And in this context I should also mention that a claim or a receivable on our joint venture partner, related to the restructuring of approximately NOK2b has not been booked, it's not in the books, so NOK2b in potential revenues is not in the books. And the same goes for additional claims related to the Phase II of this restructuring process, which is going on this year in relation to the offshore, mainly the offshore, activities for our business.

Then in the fourth quarter we had total impairment, and I think I've talked about most of them, of NOK1.7b, which is related to the Lufeng field in China. It has to do with the increased cost of removing this asset, and there is basically not very many barrels to finance that so we have to expense that cost increase.

An impairment of Front Runner, Thunder Hawk and the shelf assets in Gulf of Mexico. And the Naturkraft, as I mentioned, cost there and also some related to the Swedish retail business. And the total after-tax impacts of these impairment is approximately NOK1.2b.

Net derivative effects amounted to a total gain of NOK0.1b in the quarter, compared to a gain of NOK3.7b in the same quarter last year. And again the after-tax was not a gain that was a minus, and that has to do with, the minus NOK0.8b, and that has to do with the underlying composition of these different derivative effects.

Under-lifting of oil and gas of 32,000 barrels per day in the quarter amounted to a negative effect of NOK1.8b compared to the value of the actually produced volumes for the same -- entitlement volumes for the same period. And then finally, in addition we had some other more minor infrequent item also with a positive net impact of NOK400m

So all in all this adds up to as already mentioned total impact of NOK13.6b, negative impact, to which has an impact on the accounting and the numbers reported, but which is not directly related to the operating activities of the Company in this quarter.

So let me know continue with the roadmap and I will add some comments firstly to financial items and then the tax issue that has already been slightly introduced. Net financial items showed a loss of NOK0.7b in the quarter and this is compared to an income of NOK3.1b in the same quarter last year. So a huge change from last year when it comes to the financials.

For the full year we had an income of NOK9.6b compared to an income of NOK5.1 in 2006 full year. The financial loss in the fourth quarter was basically related to unrealized currency losses of NOK1.3b, and this is related to internal loans that we do from euro functional currency subsidiary outside of Norway into U.S. dollar functional currency subsidiaries.

And basically what we have seen is -- this underlying is due to weakening of the U.S. dollar versus euro. And this NOK1.3b is booked in the profit and loss as a loss on financial items. While there is actually a corresponding gain from the increased value of these U.S. dollar subsidiaries in Norwegian kroner, which is booked directly, not through the P&L, but directly through the equity in the balance sheet. So basically there is no, if you look at the balance sheet, there is no effect to value lost from this negative profit and loss movement as such.

The increase for the full year was mainly due to currency gains related to the normal hedging transactions that we do in order to secure Norwegian kroner for payment of tax and dividend, which you heard about today. And due to unrealized currency gains related to long-term funding and from the strengthening of the Norwegian kroner that we have seen versus U.S. dollar.

Then to the tax. The tax rate for the quarter is an impressive 79 -- best word I could find, a 79.4%. And obviously that's quite exceptional by any means, and I will try to shed some light to this issue. Firstly, the distribution of taxable income in accounting terms between the business areas, that is basically what is driving high tax rate this quarter.

The net operational income related to the Norwegian continental shelf tax regime represents more than 100% of taxable income this quarter, and this is all due to the special circumstances that I have already been through in some quite detail. And then the marginal tax rate on the Norwegian continental shelf, as you know, is 78%, while the tax rate in most of other -- all other tax regimes typically is lower at least if you look at the cash net income tax only.

And this means that a positive net income is taxed in the highest tax bracket while the aggregate negative results from other businesses areas, which has been impacted, as I mentioned, by special issues, is taxed in a lower bracket. The cost in a lower bracket, the income in a high bracket, that gives a high tax rate that pushed up the average tax rate significantly.

Secondly, the net financial items are a negative, as we have seen, this quarter of NOK700m. And tax on financial items, whether income or a loss, is typically lower than the average tax rate. And do arithmetic here, that's a lower tax on net financial loss that also contributes to take up the average tax rate for the quarter. So this is really what explains the little bit atypical tax, high tax rate that you have seen this quarter.

And this comment also actually concludes my analysis of the net income.

So now I was planning to say a few words about the proved reserves development. The StatoilHydro reserve replacement rate for 2008 was 86%, and that is how it looks according to the SPC definition of proved reserves. The three-year average as already mentioned was, from 2005, was 81%.

As you all know we need to deliver an RRR above 100% over time in order to be able to grow the production consistently over time. And we believe, with our large resource base and the continued high-quality exploration program that we have in place, we are confident that we will be able to deliver the necessary reserves and resource growth in the future to support our production growth addition.

The oil price has increased from $59 per barrel, at the end of 2006, the very last day of 2006, to approximately $96 per barrel at the last day of 2007, and that goes into the calculation of our reserves.

So given that the oil price had not moved during 2007, but has stayed at $59, the reserve replacement for the year would have been 94%, so the difference is mainly due to production sharing agreement. But also to some extent due to positive effects from a longer tail end of some of our deals.

StatoilHydro now holds 40% of oil reserve, and 60% gas reserve, adds to our total of 6b, approximately 6b, barrels of proven reserves. And 83% of the total proven reserves is located on the Norwegian continental shelf.

The production, or the unit production costs, are calculated this quarter again at an impressive NOK44.1 per barrel this quarter. And not surprisingly, and again as we have guided previously, this is significantly, this is much higher than the corresponding quarter last year. And the main reason is obviously the increase related to the one-off restructuring costs related to the merger.

Adjusted for these costs, as you can see on this slide, and also, there was a show on the impact of gas purchase for injection purposes, at the Grane field. Our unit production costs for 2007 are NOK33.2 per barrel. And again if you translate this into equity volumes, the unit production costs would have been NOK31.2 per barrel. And this again the NOK31.2 that is consistent with our guidance of the range of NOK33 to NOK36, that we have guided on for the period between 2008 and 2012.

Then if you come to our 2007 CapEx and the exploration costs. A total of 18 explorations and appraisal wells were completed in the fourth quarter. 71 wells were completed for the full year of 2007. 34 of these 71 wells were discoveries, concurrent. And 16 of the 34 that were discovered are on the Norwegian Continental shelf and 18 are outside of the NCS.

And we actually consider this to be a good exploration year for StatoilHydro, adding significant, and I would underline valuable, volumes to our resource base which has grown by approximately 1.7b barrels since -- over the last three years since 2005.

The total costs for our 2007 drilling program was NOK14.2b, which is slightly lower than the arranged NOK15 to NOK16 which we have indicated earlier. On the gap is mainly related to currency effects, as our guidance was based on 6 NOK per US$, and then there are variances in the activity, combination of activities as well.

Our capital expenditure for 2007 was NOK75b, compared with NOK64.3 of 2006. Approximately 40% of this was related to the activities on the Norwegian Continental Shelf, and almost 50% was related to the international E&P activities.

Excluding total acquisitions for 2007 of NOK18b, our 2007 CapEx was NOK57b. Again this number is somewhat lower than our guidance of around NOK65b. This is again partly due to the currency effect as already mentioned, but I would also add somewhat related to some uncertainties arising from the fact that we had not established our first set of consolidated accounts for the new Company at the point in time where we actually established this forecast.

I should also mention that none of these developments that we have seen in connection with the first closing of our accounts have any impact on the CapEx nor on the exploration guiding that we have given you for 2008. And again I would just like to remind you that the guidance for CapEx on exploration is based on 6 NOK per US$.

That comment takes me to my last comment, which is basically to remind you of our overall future guidance, and the very short version of this is that we maintain the guidance that we gave you at our Capital Markets Day in January. This means that our production is expected at 1.9m barrels per day this year, increasing to 2.2m in 2012.

CapEx program, as I already mentioned, at 75b, at NOK6 per US$.

We plan to drill approximately the same level of wells, 70 wells at a cost of NOK18b. And finally the unit production cost is estimated in the range of NOK33 to NOK36 going forward, based on equity volumes.

So with this point, I thank you very much for the attention. And I guess I leave word to you, Lars, to take us through the next session.

Thank you very much, Eldar. Now I have the q-and-a session, I'll just remind the audience on the internet that you can send in questions to me here, and I will read them aloud on your behalf to Management. Just use the submit question button on your screen.

In addition to our CEO and CFO, updates now we also have the Head of Corporate Accounting, Mr. Kare Thomsen to answer questions.

Can I take a question from the floor here in Oslo.

It's a lot of special items included this time. But if we exclude the special items for example from E & P Norway, still we see that it's unusually high operating costs per barrel. Is it some other special explanation behind that? And on the opposite side, if you do the same exclude special items in E & P International, operating costs per barrel is actually rather low, compared to the normal level.

Well I shall be very careful not to comment on what you have made out of the assumption of calculations. What I can report is basically what we have said. I think for a long time now, we have indicated that the unit production cost for 2007 would increase gradually. We have been through a period where we have seen impacts from the cost inflation board, so getting into our cost base, our operating cost base, as we have seen on exploration and CapEx numbers for some time. These are now gradually, over the last couple of years, coming into our operating costs numbers, and in addition to that, as I said we have seen an increase related to some of our activities. Slight increase in maintenance costs, and in particular to see the decline on some deals from the Norwegian Continental Shelf, we are also investing more in well-related activities to maintain the production capacity of our wells.

And in addition this year, we also had, last year we had an impact of the NOX fee.

So as I said, these are the elements basically. We also per barrel, like I also mentioned that we have you know several of our fields have operating costs included in this calculation. While we haven't seen this full effect of the volumes yet in 2007. Like the Ormen Lange, like the Snohvit and so on. We pretty much have full operating costs going for the whole of 2007, but the full barrels fund has not been in place. So there is an upside when we get to put these assets in, and Kvitebjorn, in full production capacity. So these are the elements, and we have warned you that we would climb above NOK30 per barrel, and we did that. We came out at approximately NOK31 on our own equity terms, and so for us this is more or less exactly as we have expected, and as we have tried to guide you on.

When it comes to the international there are no particular, it just goes to the, well there is a currency, there might be a currency impact. You know taking the NOK per barrel cost down, but there are no special items or anything additional that I would like to mention or can come up with that would explain whatever you are after on the international production costs.

I'll take a question from the internet from Oswald Clint, Sanford Bernstein. Could you tell us what your total hydro carbon resources are now, including contingent resources or risked exploration?

Well I think the best guidance we can give is the one we gave at the Capital Markets Day, and I don't think we will go any further than that. We have added that you know the commercial resources we have, that we anticipate to develop, in the closest we can get to 2P approach. We have indicated that we have 15b barrels of oil equivalent resources, in addition to the oil sands and the resources that we might access at the Stockman field, you can add roughly, if you include both of those assets you can include additional of 3b barrels of oil equivalent. So 18bn altogether.

John Olaissen from Carnegie.

Thank you. Given the high oil price we have at the moment, are you considering any more tail end production from the key field, or some of the fields which have both come off production over the next couple of years. Like for instance the Glitne field, use that as example. The current oil prices it would be profitable to do one more production well and expand production for a year or two.

I will not comment on individual fields, but of course there are two factors that have led to the fact that you know most of our oil fields have had a longer lifetime than we anticipated. The first one is of course that we have been more effective in living resource management, and the second is of course the oil price level that you have seen the last few years.

That is also partly what Eldar covered earlier related to the cost base that of course in such a circumstance you have to invest more into the fields. You had planned for them to be retired but you continue for more years because you see that there is a profitable production, and therefore we have had to invest more into this. And this is probably a future that you will see moving forward also. If the prices stay at the high level.

Any follow up question from John

Yes, just to follow up on that. In your portfolio do you have any fields in particular where you are now discussing potentially extending the lifetime of those fields? Don't have to be specific on the field, but do you have examples where it currently, due to the high oil price are considering expanding the lifetime of the field, which was supposed to close down next year.

Well we do that all the time. And I think most of the, also the biggest fields you will see similar project like we are executing now on Statoil late life, where you see that there are new opportunities both in terms of reservoir strategy as well as you know opportunities driven by the oil and gas prices. You will probably see the same at Snorre, the same at Gullfaks, the same at Oseberg and so on and so forth, and also of course some of the smaller fields have the same opportunities.

Yes actually a follow up on that. Do you consider hedging, i.e. puts or anything, in connection with considering longer life on some of these fields?

Generally I think our approach as you know Arnstein, is that we feel that our Investors Day investing in StatoilHydro due to the oil and gas risk, and they can diversify their portfolio in a different way, so we have only done this in a very small scale, and more related to a sort of a production from the downside. And there are no changing in our thinking related to, so the bigger design on how we are running the company.

Before we take on here, let me just ask a question from the internet. Actually at least three analysts here that would like an update on Snohvit, so could you please provide us with an update on Snohvit. This is Barry Macarthy from ABN, Iain Reid from UBS and Christine Tiscareno from Standard and Poors.

I will do that. We are more or less exactly where we indicated we would be at the Capital Markets Day. We started our production again on January 25, we are roughly running at 60% capacity as we indicated in London, and subsequently we have also been able to learn from the last time in terms of having a more efficient start-up procedure so that we can flare less gas and therefore emit less Co2 which is commercially important, but also in terms of environmental protection. We will be dependent on running the plant for a while in order to get data, information, in order to determine what is the best way of bringing the plant up to 100% capacity.

There will still be uncertainty around the production for Snohvit for 2008 and into 2009, but I'm pleased to say that those actions that we have taken so far have had the impact and effect that we anticipated. And it is of course unnecessary to say that there is a full focus on this from the teams at Snohvit, but also on Corporate Management Team.

Trond Omdal from Arctic. Could you also elaborate on Kvitebjorn. The fact that you've put it on-stream again. You said that that would be offset by some lower production on other fields and is it still the plan to fix the pipeline in the second quarter?

That is still the plan. We had a very, very careful evaluation on whether to do the repair immediately or do it later. We decided to do it later and the plan is still to do it within the time frame that we have communicated. And also within the production impact that we have indicated. We indicated to you that it will have a roughly 30,000 barrels per day in impact, of which 18,000 of those are gas volumes. This is of course included in the 1.9m forecast for 2008 on the equity level.

A question from the internet now. A question from Iain Reid at UBS. Can you give us any guidance for the unit depreciation rates for the NCS and International E&P business?

Well basically we have seen very little development. There is obviously variations in the unit depreciation rate depending on listing volumes. But if you look at this in terms of our unit production costs, there is very little development going forward. So we have seen some impact from the increased asset retirement costs, which has influenced the depriciations. But beyond that I think this is pretty much stable, longer term. As I said, valuation is on a quarter to quarter basis and it will gradually increase, obviously over time as we are replacing lower cost asset base, with a gradually higher cost asset base. But I cannot give any more numerical specific guidance than this.

Okay, but before we take Gudmund Halle Isfeldt, a follow up question from Christine Tiscareno. What is your guidance for the 2008 and 2009 retirement asset costs? Do we have any guidance for that?

The retirement asset cost, we had an increase now in 2007 based on the valuation we did end of 2006. But we see that for 2008 with the evaluation we have done now, it's more or less stable as we had it one year ago. So no increased depreciation due to the evaluation of the asset retirement end of 2007.

Gudmund Halle Isfeldt from DnB. Can you please give us some flavor to, or roughly indicate the base level for stage 1 of Shtokman. And two, what would you feel is a robust startup date on Shtokman? And three, how should we calculate the income from the field? How should we calculate the income that you get produced standard cubic meter of gas.

First, on the investment or CapEx forecast. I will not give any guidance at this point in time. Because this is exactly the purpose of the field base, the first phase of the project to determine a robust project execution plan and a robust budget. We have to come back to that. But clearly given the magnitude of the first phase of the Shtokman project and the environment, this is a big potential investment. As you know, and I think most of you know, we have not exposed at this stage more than the costs of our planning phase. Our share of that cost until 2009. The plan is to make an investment decision based on the figures at the end of 2009. Gazprom, as the main owner, has indicated that the plan for the first pipe gas production will be in 2013 and LNG one year after. I have no other update than that to provide at this stage. In terms of the ownership structure, or the access to the underlying resources and the economics, I think it is clear for all of you that we will not physically own the resources. The Shtokman Development Company will be responsible for planning, executing and running and owning the assets related to the Shtokman project for the first 25 years of the project. And we will then get our share of the costs and the income from that field, and we have a 24% share. I think the best way at this stage you can think about it, is that we will take the risks of our efficiency in developing the project compared to the budget that we are establishing in 2009. And secondly we will be exposed as in all upstream projects to the future development of the gas prices. So I cannot go any further than this at this stage.

A question from Colin Smith at Dresdner Kleinwort. Can you comment on how the Norwegian Government increase in its holding to 67 is being or will be implemented?

I can only say what I have read in the papers. That they have said that they are planning to increase their investment up to 67 according to the Parliamentary decision taken in connection with the acceptance of the merger. I don't know how they will do it, when they will do it and within which timeframe, so I take the view that as the Management of the Board of the company we have to run the company, we have to inform about our activities and then each shareholder has to decide for themselves whether they want to buy or sell. And they have to also determine themselves how they want to do it, and I'm not expecting to be informed about that, I don't want to be it either.

A question from three people here on the internet. James Hubbard at Deutsche, Huw Williams at Bear Stearns and James Batty at Energy Intelligence. Can you tell us the amounts of reserves debooked from your reserve figures as a result of the adoption in your Sincor equity stake in Venezuela?

Well, as you know the migration into the mixed company hadn't formally taken place by the end of 2007. So we haven't booked any impact from the reduction in ownership relating to Sincor into these numbers.

Another question from Marius Richter(?) at Carnegie. With respect to reserve replacement rate goal of 100%. What is the increase in your exploration drilling and the split between exploration and development costs in 2008 and forward?

Well in terms of exploration drilling we have said that roughly 30% of the 18b that we have indicated for 2008 will flow into the CapEx numbers. And exploration will be roughly as I've indicated 70 wells, 50% of those in Norway, 50% outside Norway.

A quick one on unconventional oil sands and reserves. When could we potentially see the first bookings from the oil sands reserves or resources you have in Canada? You say you are going to start in 2010 with some small scale test production, but when do you think we could see some of those bookings?

I think you are correctly implying that we haven't booked anything so far, even though we actually have approved the first demonstration plant, the Leismer plant, but that was approved before the year end. But we concluded that we could not book that one and this is related to the fact that this is the demonstration plant. But for these types of resources we need to actually demonstrate that it works. So we have to go through that and make sure that it really works. So I think basically you are into a positive conclusion on the first demonstration from this plant by 2010. I think that's the best indication of when we will be able to book the first reserves from this project. But the resources are still there.

Two weeks ago you signed an agreement on this Trans Adriatic Pipeline (TAP). Could you say something about your equity share and the CapEx, and is the investment decision linked to Shah Deniz Phase II, and will it allow you to market your own equity gas into Italy?

The background for this, at this stage rather small investment and involvement, is that we together with BP, and the other partners have discovered significant additional resources in Shah Deniz, in a deeper reservoir. So we believe that there are sufficient resources to develop a second phase of the project. Therefore we need access to markets and we have determined that Western Europe is an attractive market. We feel that the investment that we took in TAP, will sort of be a catalyst for moving this project forward and as you all know we have extensive experience in building gas value chains and we are the commercial operator of Shah Deniz and Shah Deniz II. So therefore this is our responsibility as well. At this first stage it is a relatively small investment. It's more like a project to develop it. I think the first, at the final investment decision must be linked to the fact that we have a market and that we have clients in Europe and that we have sold the commercial arrangement in Azerbaijan as well as you know transit arrangement, that we need to get in place among others through Turkey in order to make it happen. So I guess the investment decision will not be taken eventually before --- at the end of 2009 perhaps could be a good guidance. Of course our share in that investment will ultimately depend on the commercial model with our partners at the project.

Actually a follow up question here from Mark Hume at Credit Suisse. BP is suggesting that the Shah Deniz field could be the largest gas find in the world for many years. Can you give us an indication of the potential resource size and what this might mean for your capital investment program in Azerbaijan going forward?

I can only say that, as we said earlier today at our press conference, that this was one of the most interesting discoveries that we made last year. I cannot comment on the statement from BP other than saying that BP is a very reputable company.

There is a question from Christine Tiscareno of Standard and Poors. Can you provide us with cost guidance on the latest modifications needed at Statfjord Late Life and Snohvit?

Let me say first of all on Statfjord late life. This was a project that was decided in 2004, and it's a resource management project, where the idea is to turn a big oil producer into a predominantly gas producer over many many many years. There are modifications being done on the platforms, but the most important part of the project is that you have to do a lot of drilling many years into the future. As you know, all of you that are working in this industry on a global basis, high oil prices incentivize increased activity, increasing demand and you see higher costs and then they're looking at this for the long term, taking into effect the impact of the current market circumstances, and we will drill a lot of wells over the next years. Of course the cost will be impacted if we continue to see the same pattern. But you know the wells we are drilling, we are making decisions all the time whether these are profitable or not. I can only confirm that this project is much more profitable today than it was when we approved it in 2004 due to the changes in the market prices. On Snohvit, you know the costs associated with the modifications that we have to do eventually, I cannot speculate at this point in time as we do not know exactly what we have to do. We have to come back to that later.

We will take a few more questions before we end this q-and-a session. There's a couple of questions from Oswald Clint from Sanford Bernstein, and Huw Williams at Bear Stearns. They both want to know updates on the Gulf of Mexico portfolio. Oswald Clint wants to know if we've got any more updates on the Julia discovery, and Huw Williams wants to know more general, what are the updates and when do we expect more information about the discoveries there?

Well we are pleased with the portfolio that we have built up over the last three to three and a half years. It is very much focused on the deep water areas. That is the reason why we sold the shallow water business. As we felt that others had more capabilities of taking the full value out of that. I think we have a good balance in the portfolio in the sense that we are working with Chevron on the Tahiti development. We have a number of other discoveries including Jack, Julia, West Tonga that was released right before Christmas, and a number of other discoveries and a quite active plan to develop these resources further. I cannot comment on the resource potential beyond what the operators have done already. We have been active also in the lease rounds recently, and we see how we can, through these lease rounds, also complement our portfolio even further.

More questions before we end. Kjetil Bakken at Fondsfinans wants to know; You've been very busy building your portfolio, and continue to acquire licenses in existing and new areas. Is there a limit to how many business development activities a company can handle? And what is your view on potential asset sales?

First of all our ability to mature more business development options and doing more exploration were one of the key drivers of the merger - that we will be more effective in combining the forces of Hydro and Statoil. I think there is clearly a limit to how many projects we can involve ourselves in. We are not taking on more responsibility than what we can execute and we are extremely determined to try to balance the importance of industrially develop the company profitability grow it while we are returning direct cash to our shareholders. And I think based on the track record we have in the last few years I think there's a certain performance standard in that. Final comment, I think right now, I think the industry in general and also StatoilHydro is more constrained by people and human resources than we are related to cash and physical equipment. And you know you need all of these parameters in place in order to do a safe, secure and more profitable development.

Today's last question from Iain Reid at UBS. Is the TAP pipeline a competitor to the Nabucco and Gazprom's south stream. And if so, how does this affect your relationship with Gazprom in Russia?

Well I think that we have an excellent relationship with Gazprom. They know that we are a big gas supplier. They know our gas positions. We cooperate on Shtokman. We compete elsewhere. What we are not taking part in any other sort of involvement than trying to make the most value out of those resources we have. And we feel that that is also the approach that we have to take and will take together with our partners at the Shah Deniz II project. And a key to making a value out of a gas discovery is of course, to attach the resources to market place.

Well ladies and gentlemen this was the end of today's session. We have got a couple more questions on the internet that we haven't answered yet, because we didn't have time, but we will make sure that you get an answer via email after this presentation. Thank you very much. Goodbye.