Equinor ASA (EQNR) 2008 Q4 法說會逐字稿

Welcome to this StatoilHydro fourth quarter and 2008 earnings presentation. My name is Lars Sorensen and I'm the Head of Investor Relations.

This morning at 8.00 a.m. Central European time, we announced our results for the fourth quarter and the full year 2008. We sent the release through wires and to the Oslo Stock Exchange, and you can look at all the material on our website www.statoilhydro.com. It can be downloaded from that website, together with the presentation set and the presentation pack that we're going to use in this webcast.

I'll ask you please to take note of the forward-looking statement which is at the back of the presentation slide where we talk about using non-GAAP measures and forward-looking statements in the presentation. Today's events can be followed by webcast, and let me extend my warm welcome to the audience on the webcast.

Safety is still of paramount importance, but we took the safety briefing before we went live on the webcast. So we've done that for the audience here in Oslo.

Today, StatoilHydro's President and CEO Helge Lund, and our Chief Financial Officer Eldar Saetre, will go through the presentation for the fourth quarter and full year. After the two presentations, we'll open for questions, and they can be asked from the floor here in Oslo, but they can also be asked via the Internet if you use the submit question button on your screen, and I'll get them up on my PC here and read them aloud on your behalf. You can send in questions already now or during the presentations, and also during the Q&A sessions.

So now it's my privilege to welcome our President and Chief Executive, Helge Lund.

Thank you, Lars. Ladies and gentlemen, welcome to the presentation of our fourth quarter 2008 results for StatoilHydro, as well as the full year result for 2008. And I think it is fair to open by saying that last time we met, one year back, I think some of you raised doubt as to our ability to deliver on our guidance. I think one year after, we can conclude that the Organization has raised to the challenge as we have delivered on most of our operational matrixes.

I don't think we can blame the Organization for the volatility in the currency markets as well as the oil market, but on those parameters that they can impact, they have delivered.

We have delivered record financial results from our operations. We are growing equity production and are meeting our target for the year, good exploration success at the high activity level, and also we are capturing merger synergies according to plan.

I am pleased with these deliveries, particularly as I believe that good operational performance is the best protection against the current turmoil that we see around in the industry.

We are still facing weak markets, and we regard the oil price development in the short term as highly uncertain. It will to a large extent be determined, the development of our product prices, by first of all the length and the depth of the current economic downturn, but I guess also to a large extent on OPEC compliance and the effects of the reductions that they have already decided.

For our planning purposes, we assume in our planning process that the prices will be around current levels, but we are prepared for additional uncertainty and volatility and also prices at lower level than we see today.

However, having said that, the current turmoil does not change our long-term outlook for the energy market, and our analysis does not suggest any change in StatoilHydro's long-term strategy. And we believe that once the world economy recuperates, we will easily find ourselves again in a situation where the supply side is struggling to meet the increasing energy demand.

Let me comment a bit more in detail on our deliveries in 2008. We met the production target we communicated to you for 2008, and also at highly competitive production costs. We have captured half of the synergy potential identified in the merger, and most of the remaining we will capture in 2009. And we have added 800 million barrels through exploration, exceeding the production for the year, and also through targeted business development on top of the exploration program. We now have a total resource base of about 20 billion barrels.

Our large resource base is a strong platform for future growth. Over the last two years, we have added roughly 7 billion barrels of new resources in Gulf of Mexico, in Brazil, in Russia, as well as in Canada. And our main priority, as we underlined also during our Capital Markets Day in London, is to mature these resources into profitable production. Technically, however, our reserve replacement rate is at 60% for the three last year, and 34% for the year 2008.

Moving to the financial results for the year and StatoilHydro's earnings from operations, very closely NOK200 billion, and the adjusted earnings even exceeded a record NOK200 billion in 2008.

Net income was almost on the same level as last year, around NOK43 billion, or NOK13.6 per share. This is mainly because of unrealized currency loss on the debt, and consequently, a high tax rate for 2008. And Eldar will come back to this in more detail later in his presentation.

Earnings for the fourth quarter last year were, of course, affected by lower oil price, partly offset by higher gas volumes and also high gas prices for the quarter.

Looking at production, we grew by a healthy 5% from 2007 to 2008, and we now produce at the highest level ever for StatoilHydro. Equity production of liquids grew 3%, and on gas almost 8% from 2007 to 2008. Liquids entitlement production declined 1% while gas entitlement production increased 7% from 2007.

In the fourth quarter of 2008, we had an equity production record when we exceeded more than 2 million barrels per day, and we maintained the production guiding both for the year 2009, and also for 2012 at 2.2 million barrels per day in equity production.

It is encouraging to note an improvement in the HSE statistics for 2008, particularly at the Norwegian Continental Shelf and in our international upstream operation. And the fourth quarter result is an inspiration going forward, and I think also signals that the quality of our operations is improving.

For the Group, we experienced a slight increase in the serious incident frequency from 2.1 in 2007 to 2.2 in 2008. And robberies at our service stations in the Nordic countries constitute the largest part of the incidents in 2008, and we are now implementing a safe cash handling system on all our service stations in Scandinavia in order to limit these type of incidents.

There were also during 2008 in this area experienced some incidents with large potential, and we are working extremely hard to limit such incidents into the future. That is in developing a program to attempt to comply in the Company with our own procedures, improving our people's ability to assess risk in the right way and understand risk, and also simplifying our procedures and also putting high priority on strengthening the technical integrity on our facilities and doing that in a very, very systematic way.

I would, however, like to stress that the most important initiative that we are taking in order to improve quality of our operations, including HSE, is to fully implement the integration process where we offshore are trying to organize our activities in the same principled way, and also harmonize our working procedures so they are similar across all our installations at the Norwegian Continental Shelf.

One important part of our strategy is to capture the full potential on the Norwegian Continental Shelf, and I think 2008 has been a year of improvement and strong deliveries at the Norwegian Continental Shelf. We have set a new production record. Drilling efficiency is up by 15%. We have implemented the largest maintenance program ever on schedule, and we have drilled almost 40 exploration wells in 2008 with a success rate close to 70%. So basically, we find resources in most of the areas where we are drilling. On top of that, we have put seven new projects on stream at the Norwegian Continental Shelf.

We are, as I already said, in the process of implementing a big integration project at the Norwegian Continental Shelf. and we are in the final stages of that process. NOK1.6 billion of integration costs are distributed to the partners, and this has a positive effect on the fourth quarter results for 2008.

And the benefit from the merger process will continue to flow through StatoilHydro, but also to our partners at the Norwegian Continental Shelf. I would like to compliment our Organization for good work in a very hectic environment during 2008.

Moving to our international operations, again, we have delivered strong growth and equity production has increased fivefold since 2001, and new international hubs are established in Gulf of Mexico, in Canada, in Russia and in Brazil. And in 2008, the equity production was up by roughly 10% and equity production in fourth quarter of 2008 was at the 480,000 barrels per day level.

This year, we put five new fields on stream in Nigeria, in Angola, in Iran, and also in Azerbaijan. Our international business is still in a build-up phase, and we're continuously looking for new opportunities within the defined strategic framework.

In 2008, we have, as I said, added 3.5 billion barrels through business development and exploration, and we have strengthened our heavy oil position through the acquisition of the remaining 50% of the Peregrino field offshore, and also improved our gas position in the biggest gas market in the world, the US, through the Marcellus joint venture that we entered into with Chesapeake late last year. These are important building blocks for further developing StatoilHydro's international part of our portfolio.

I'm pleased to note that the development for 2008 is exactly in line with our strategy, taking out the full potential of Norwegian Continental Shelf, and step-by-step, deliver bigger international growth potential and production capacity.

Dividend; we are delivering an attractive dividend for 2008 in accordance with our dividend policy. The proposed dividend for 2008 is NOK7.25 per share, representing NOK4.4 in ordinary dividend, and NOK2.85 in special dividend (Company corrected after the conference call). Our dividend policy is to deliver 45% to 50% of net earnings over time, and the proposed dividend represents a payout ratio for 2008 of 53% and brings our capital distribution ratio for 2001 through 2008 to above 50%. The exact amount on percentage is 52% over that period.

Let me conclude. I am pleased to say that I conclude that 2008 marks a very strong year of operational deliveries for StatoilHydro. We have improved our operational performance. We continue to deliver production growth, and we have proposed a competitive dividend in line with our dividend policy.

And before leaving the word to Eldar Saetre, let me close by saying that our plans moving forward are robust, both financially and operationally, despite the current low point in the global economy. and the balance we would like to strike and that I think we have identified is to make sure that we keep financial flexibility but stick to the long term firm strategy that we have developed for StatoilHydro and that have served the Company well.

So, by those words I leave the floor to Mr. Eldar Saetre, the CFO of StatoilHydro.

Thank you, Helge. Good afternoon, everybody. Thank you for joining us, and I will start my presentation today with no further introductions and go straight to the reported numbers for the full year of 2008.

Our net operating income increased by 45% in 2008, and that amounts to NOK198.8 billion, compared to NOK137.2 in the previous year.

The net financial items; in those items we had an accounting loss of NOK18.4 billion compared to a gain of NOK9.6 billion in 2007, and this significant negative change in the net financials was due to unrealized currency losses caused by an almost 30% weakening of the Norwegian kroner versus US dollar during the quarter, or during the year.

Income taxes were NOK137.2 billion in 2008, which is equivalent to a tax rate of 76%, and this is compared to a tax rate of 69.6% in 2007. The increase in tax rate for the full year was mainly related to unrealized losses, as I just mentioned, on the financial items, which is then subject to a lower than average tax rate for the corporate as a whole.

Finally, the net income for 2008 amounted to NOK43.3 billion reported, which is compared to NOK44.6 billion in 2007.

I will revert to the full year adjusted earnings discussion later in my presentation, so let us now take a look at the adjusted earnings for the fourth quarter.

And then let me first remind you briefly of the meaning of what we call adjusted earnings. As you know, reporting according to IFRS in capital intensive industries like ours, that introduces some volatility in the P&L accounts, and this is related mainly to fair valuation of assets, including storage, impairments, and also the reversal of impairments, derivatives, etc. And these are all examples of items that we do not consider to reflect the underlying operations in our business.

So in order for investors and analysts to be better able to compare both the operations and the financial performance of the Company from quarter-to-quarter, we therefore adjust for these items into what we call adjusted earnings.

These adjusted earnings in the fourth quarter amounted to NOK43.7 billion, which is compared to NOK45.1 billion in the same quarter the year before. And the decrease was mainly due to a 26% reduction in the liquids price in Norwegian kroner, an increase in operating expenses due to higher activity levels, also new fields coming on stream and, as you know, general costs inflation, and an increase in depreciations due to increased equity production from currency effects, and also new and more expensive fields coming on stream. These negative factors were partly offset by increased revenues from higher volumes and higher prices of natural gas.

Then, as you can see, the net operating income was affected by NOK5.9 billion which was related to items which are not reflecting, as I mentioned, the underlying operational performance. And these items were, on the negative side first, a lower fair value of derivatives amounting to NOK2.1 billion, increased net impairment charges of NOK1.3 billion. There was a negative value of net underlift in the quarter of NOK1.3 billion. We had lower values of product in operational storage amounting to NOK3.6 billion. Also, an accrued loss on an earn-out agreement accounted for NOK0.8 billion; and finally, some other accruals and eliminations of NOK2.2 billion.

And all these were negative developments. Then, on the positive side, we had, as mentioned by Helge, the reversal of merger restructuring costs of NOK1.6 billion in the quarter.

Net financial items amounted to a loss of NOK12.1 billion in the quarter compared to a loss of NOK0.7 billion in the same quarter in 2007, and I will come back to the details on the financials quite shortly.

Income taxes were NOK23.7 billion in the fourth quarter, and this is equivalent to a tax rate of 92.1%, quite impressive. This is compared to a 79.4% tax rate in the fourth quarter in the previous year.

The increase in the tax rate was mainly related to the net loss on the net financial items, which is tax deductible at a lower rate than the average, which I mentioned was relevant also for the full year development.

In addition, the tax rate was increased by accounting losses, mainly in the US, with no effected short term tax protection, and also by deferred tax expenses, which is caused by currency changes in the valuation of certain companies that are taxable in currencies other than Norwegian kroner.

Now the positive changes in the valuation of these companies are recorded directly against the equity in our balance sheet. While the changes in the corresponding deferred tax expenses has to be taken via the P&L, and that increases the tax rate quite significantly this quarter because of the big movements in currency rates.

And finally, adding it all together, the net income in the fourth quarter was, as you can see, NOK2 billion which is compared to NOK6.2 billion in the same quarter one year ago.

Let me now walk you through the financial items as I promised. As already mentioned, the net financials amounted to a loss of NOK2.1 billion in the quarter. This accounting loss was mostly caused by unrealized currency losses from a 20% weakening of the Norwegian kroner versus US dollar in the quarter. And, as you know, we have all our debt in US dollar.

Currency losses amounted to NOK22.9 billion, of which NOK14.4 billion was related to currency swaps which is an integrated part of our liquidity management activities, and NOK8.5 billion was related to unrealized currency losses on our long-term debt in US dollar.

So our financial strategies, which is related to both the liquidity management and having our long term debt in US dollar, that introduces some non cash accounting volatility as our accounts are reported in Norwegian kroner. However, we do manage our Company as a US dollar business, and in the long term, StatoilHydro will definitely benefit from a strong US dollar.

As you can see, financial expenses had a positive effect of NOK3.9 billion in the quarter, and this mainly comes from positive, non cash adjustments on financial derivatives of NOK5.1 billion.

On securities, we had mostly unrealized gains of NOK4 billion, and some of these gains came from positive currency impacts, especially related to US dollar securities.

Then I would like to give some comments to each of the business areas.

The adjusted earnings for E&P Norway were NOK35.2 billion in the fourth quarter, and this is compared to NOK37.3 billion previous year. An increase in the transfer price of natural gas of 52% had a positive impact on E&P Norway this quarter of NOK8 billion. In addition, an increase in the production of natural gas added NOK0.9 billion, and an increase in the production of liquids contributed NOK0.4 billion.

Average daily production of liquids increased by 1% to 854,000 barrels per day this quarter, while the average daily gas production increased 6% to 691,000 barrels of oil equivalent per day, and this was mainly driven by the ramp up of the Ormen Lange field.

So these positive impacts, they were partly offset by a 26% decrease in the realized price of liquids measured in Norwegian kroner, as you are all aware. And this price impact on liquids was around NOK10 billion for the segment. Depreciations increased by NOK0.5 billion mainly due to increased production, and exploration expenses increased by NOK0.4 billion.

The realized price of liquids was lower than Brent Blend in the fourth quarter, and that is mostly because of the mix of 10% to 15% of NGLs in the liquids volumes from the Norwegian Continental Shelf which have been priced lower than Brent Blend also during this quarter. And in addition, there are some smaller negative effects on the nature of the lifting schedules in this quarter.

Then I should also mention that our earnings in the fourth quarter was adjusted for a negative NOK4.7 billion from items that do not reflect the underlying operations which I have talked about earlier, and these adjustments for E&P Norway, they include unrealized loss on derivatives of NOK4.7 billion, an underlift of NOK0.8 billion, 21,000 barrels, a cost provision for an earn-out agreement, as I mentioned, related to a previous sale of a asset on the Norwegian Continental Shelf that added up to NOK0.8 billion, and finally, in the fourth quarter, we concluded the discussions with our joint venture partners on the Norwegian Continental Shelf about the distribution of the merger restructuring costs, and as a result, we were reimbursed NOK1.5 billion of the costs taken in the fourth quarter of 2007.

Then to our international E&P business. The adjusted earnings from E&P outside of Norway were NOK0.3 billion in the quarter, and this is compared to NOK5.6 billion in the same quarter of the year before. This decrease was mainly due to a 3% reduction in the entitlement production, representing NOK2 billion.

Then a 24% decrease in realized liquids and gas prices, measured in Norwegian kroner which amounted to NOK1.7 billion, and increased depreciations of NOK1.5 billion, mainly due to currency impacts from the weaker Norwegian kroner, but also due to more expensive fields with a lower initial SEC booking which came on stream in 2008.

Equity production increased by 3% to 479,000 barrels per day of oil equivalents, while entitlement production decreased, as I mentioned, due to increased PSA effects. And the PSA effect in the fourth quarter last year was 166,000 barrels per day compared to 140,000 barrels in the same quarter one year ago.

Finally, the reported net operating income for this segment was negatively affected by NOK1.9 billion from some items which were not reflecting the underlying operations.

Impairment charges of NOK1.3 billion was mainly related to changes in short-term market conditions, and we had a negative value of underlift in the quarter representing NOK0.5 billion.

Our Natural Gas business segment had adjusted earnings of NOK4.8 billion in the fourth quarter compared to NOK1.4 billion in the same quarter one year ago.

The Marketing and Trading part of the business had adjusted earnings of NOK3.3 billion, compared to a loss of NOK0.3 billion one year ago. And this increase of NOK3.6 billion was mainly due to increased average sales prices and higher volumes sold.

Adjusted earnings in the processing and transportation sub-segment were NOK1.4 billion, which is compared to NOK1.6 billion the year before. Revenues increased slightly, while operating expenses and depreciation charges increased also by NOK0.3 billion combined.

As you can see, the volume weighted average gas price increased by 66% from quarter-to-quarter, and this increase comes mainly from our long-term contractual arrangements and general market conditions, but also from stronger trading performance in general.

This performance is reflected in our average gas price of NOK2.99 per standard cubic meter, which is compared to NOK1.80 in the same quarter one year ago.

The internal transfer price increased by 52% to NOK2.32 per standard cubic meter, and natural gas sales volumes were 12.1 bcm, which is an increase of 6% compared to the year before.

The main so-called infrequent items impacted the reported net operating income in the quarter by NOK2.5 billion gain on derivatives, and a reversal of an impairment of NOK0.2 billion.

Then to our last segment, Manufacturing and Marketing, which had adjusted earnings of NOK4.2 billion in the period. This is compared to NOK0.9 billion in the previous year. This improved result was mainly due to increased trading results and some positive currency effects on the value of inventory in commercial storage.

I will comment on this development under each of the three sub-segments starting with adjusted earnings in our Oil Sales, Trading and Supply business which were NOK3.9 billion in the quarter compared to a loss of NOK0.2 billion one year ago. And this increase was, as I just mentioned, mainly due to positive trading result and currency effects on the value of inventories in our commercial storage.

The Manufacturing business had adjusted earnings of NOK0.5 billion in the quarter compared to NOK0.7 billion one year ago, and this decrease was largely due to a comprehensive turnaround at our Mongstad refinery.

Energy and Retail had a loss in adjusted earnings of NOK0.2 billion in the fourth quarter compared to a positive NOK0.1 billion a year ago, and this reduction was mainly due to lower margins and volumes, non-fuel margins and volume.

Finally, I have to mention that also in this segment there was an impact from infrequent items in the quarter, which is not reflecting the underlying operations. The most important one is related to losses from lower prices on our operational storage of NOK3.6 billion. In addition, we had an accrual of NOK0.3 billion related to the restructuring of our Scandinavian Energy and Retail business.

So having now commented on the adjusted quarterly earnings segment-by-segment, I would like also to give you a brief overview of the full year adjusted earnings and how this compares with 2007. And as you can see, we had a significant adjusted earnings growth from 2007 of 37%. E&P Norway came out approximately at the corporate level in terms of growth.

Our mid and downstream businesses had growth of more than 50%, while the international business was approximately at the same level as the year before. And the main driving factors were increased liquid prices in Norwegian kroner of 24%, increased gas prices 45%, and then a growth in both oil and gas production. And these factors were partly offset by some increases in operating expenses, depreciations and exploration costs.

So let me now give some comments to our unit production costs. Our reported cash production cost per barrel of oil equivalent in equity terms for 2008 was NOK33.5, and this is compared to NOK41.4 in 2007. And then I would like to remind you that the merger restructuring costs in the fourth quarter last year are, as you can see, at the light blue on the top of these columns. That caused a high level of unit production cost in the fourth quarter 2007.

Adjusted for the reversal of some of these restructuring costs that you can see on the bottom part of the column to the right here, and costs related to gas injection into the Grane field on the top, the unit production cost for 2008 was NOK33.3 per barrel. And we believe this is a highly competitive number within the industry.

The comparable adjusted figure for 2007 was NOK31.2, meaning that we have had an underlying increase in unit cost of almost 7%. And this increase is mainly related to more fields in the startup phase, increased maintenance costs and general cost inflation. Our 2008 unit production cost is in the lower end of the range of NOK33 to NOK36 per barrel that we have guided for the period 2008 to 2012.

And then I would like to offer a few comments also to the Capex and the exploration numbers. Overall, Capex in 2008 amounted to NOK95 billion, including acquisitions of NOK27 billion, and this is compared to NOK75 billion, including acquisitions in 2007. Organic, excluding acquisitions, Capex in 2008 was NOK68 billion, which is in line with our guidance when adjusting for the currency developments in the second half of the year.

Exploration expenditures were NOK17.8 billion compared to NOK14.2 billion in 2007, and the increase was mainly due to higher activity, and also, more expensive drilling activities and drilling costs.

In the fourth quarter, a total of 19 exploration and appraisal wells, and three extensions were completed, 15 on the NCS and seven internationally.

And nine exploration wells, appraisal wells, and two extensions have been declared as discoveries in the quarter. In 2008 as a whole, we have had a very high exploration activity with a total of 79 exploration appraisal wells, and nine extensions completed. 48 of these were on the Norwegian Continental Shelf, and 40 outside of the Norwegian Shelf.

We have so far announced 41 discoveries, including the extensions, from our 2008 program. 15 wells have been concluded as dry, while 32 wells are awaiting final conclusions from the 2008 drilling program by year-end. In addition, 11 wells have been completed after year-end, and six of these have been declared as discoveries, and they were all on the Norwegian Continental Shelf.

Then to the financials; our cash flow from operations was NOK109 billion in 2008. In addition, we had sale of assets generating NOK5 billion. So in 2008, cash flow to investments was NOK91 billion, and this is split between NOK66 billion in organic, cash flow to organic investment, and NOK25 billion to acquisitions.

In addition, we paid NOK27 billion in dividends from 2007. Our net debt to capital employed ratio was 17.5% at December 31, and I should remind you that we closed and paid for four transactions in the fourth quarter, and also had two tax payments, which did actually not reflect the lower oil price in the quarter as such.

As you can see, we are generating a strong cash flow, even in today's environment, and we have a robust balance sheet to take us through the current downturn. This solid starting point gives us financially flexibility to progress with our long-term strategy and the high quality Capex program that we have presented to you, and at the same time, staying fully committed to our dividend policy.

Proved reserves as defined by the SEC at the end of 2008, was 5.6 billion barrels compared to six billion at the end of 2007. Approved reserves consist of 39% oil and 61% gas. Three year average was 60% at the end of the year compared to 81% at the end of 2007. And the annual reserve replacement rate was a low, as mentioned by Helge, at 34% of the 2008 production.

As you know, during the period 1998 I would say to 2004, the exploration activity within StatoilHydro was quite low, and we also had much lower success rates compared to what we have seen over the last three to four years.

Discoveries need to be matured and projects need to be sanctioned before booking our reserves can start at all, and within our industry this takes typically, six to 10 years.

So, therefore, the low exploration activity levels that I just mentioned have put a pressure on the SEC reserve bookings during the last years, and consequently, we also had few sanctions of new projects during 2008.

I should also mention that we were not able to add reserves from any of our unconventional oil or gas resources this year. In addition, our new projects in West Africa did not add much 1p reserves this year, as the breakeven oil price for these projects is higher than the $36 per barrel that is used in this year's reserve evaluation.

The transfer of Sincor in Venezuela to Petrocedeno into the mixed company structure also reduced the booked reserves in 2008. But one thing is the booked proven reserves, another is the resources needed to support production growth over time. The low reserve replacement that you've just seen is no surprise to us, and has no impact on the robustness of our guidance that we have given you for 2012.

We have sanctioned almost all projects needed for production growth until 2012, and based on our large resource base, we are also -- we have robust growth conditions beyond 2012.

As you can see, and as mentioned by Helge, we have resource base of around 20 billion barrels, approximately 7 billion barrels have been added to this base during the last two years, '07 and '08, and almost none of these additional resources have been booked, according to SEC so far, while we will start seeing quite visible production from these assets already next year.

Finally, to summarize my presentation, let's look at the guidance where there is no change at all from what you saw in January. Our presented forecast for this year is 1.950 million barrels per day, and 2.2 million barrels in 2012 in equity terms.

Then changed maintenance activities is not expected to have any major impact on the equity production in the first quarter of 2009. Organic Capex is estimated at $13.5 billion. Exploration drilling is, as you know, our primary tool for growing our business, and we will continue to do high grading of our portfolio and expect to maintain a high level of exploration activity in 2009. That's slightly lower than this year, 65 to 70 exploration and appraisal wells, and NOK2.7 billion in exploration costs.

Unit production costs for equity volumes is estimated in the range of NOK33 to NOK36 in the period '09 to 2012, while we for 2009 expect to be in the upper end of this range, and this will exclude purchase of gas for injection purposes.

And finally, our ambition is to deliver a competitive return on average capital employed compared with our peer group. So that concludes my presentation. Thank you for your attention, and then I leave the word back to Lars.

Thank you very much, Eldar. So I'll start the Q&A session, and in addition to Helge Lund, Eldar Saetre and myself, we are joined by the Head of Corporate Accounting, Kaare Thomsen. As I said before the presentation started, it's possible to send in questions via the web. I already received a number of questions on my PC here, and I'll ask them on your behalf. You can still send in questions to me and I'll make sure that I ask them to management on your behalf.

So we'll just start with taking a question from the Internet, and then we'll open for questions from Oslo. There's a question from Christine Tiscareno from Standard & Poor's and a private investor called [Ahmed] Osman, and Oswald Clint at Bernstein. Could you please comment on the 2008 reserve replacement rate and your objectives for RRR in 2009 and in the future?

Well, the comment on the figures for 2008 is clearly, this is a lower figure. We are not forecasting year-by-year how our RRR will develop, but we have stated that over time, we would like to see, and have an ambition of having a RRR above one.

I would like to underline again that what we look at primarily in developing our business is, of course, the resources that we expect that we can develop into profitable production over time, and we have focused during our presentation that we have had very strong year, the last year, the last two years, in developing the resource base. And the total base now is about 20 billion barrels of resources. That I think speaks well for the short-term, as well as the longer term growth potential of StatoilHydro.

A follow-up question to that, from Teodor Nilsen at Argo Securities. Considering StatoilHydro has drilled in rather mature areas over the last year, how can the low RRR be explained?

Well, the RRR in this case, is explained in 2008 with the stable and high production ratio, and that we have been able to sanction fewer projects in this particular calendar year. Partly this is explained by the fact that at the latter part of the last decade and also earlier part of this decade, we had a relatively lower investment into exploration, and we're partly paying the price for that right now.

John Olaisen, Carnegie.

Yes, a follow-up on the reserves. Did the weakening of the oil price during last year have an impact on reserves or on the resources? And also in the same line, how about the effect of the PSAs last year?

Well, obviously, the oil price had an impact, and I mentioned that in my presentation in relation to the West African fields which came in and were sanctioned. And then we have to look at the year-end price which was the lowest price of the year actually on that given day, $36 per barrel. So that had some -- an impact. And also in general, on cut-off, on tail-ends and earlier cut-offs from that kind of oil price level.

That is the negative. Then there is also a positive, on the PSA effect that you alluded to. So it goes both ways, so I will not take it in any special direction. It's an impact that goes both ways. And I think the main issue, to put it that way, is not the oil price as such. The main issue is that there was not enough fields that were sanctioned for various reasons, and that was explained by Helge and in my presentation for this year. That's the main driver behind this year's low RRR, and then obviously, we have a strong resource base, as Helge mentioned. And as I mentioned in my presentation, some of these resources, even though they are not booked according to the SEC, they are actually more or less producing as we speak, Marcellus for instance.

But you don't want to quantify how much the oil price and PSA effect?

As I said, the net effect is not significant; it does not explain the low level as such.

Okay, there are two quick questions regarding the adjusted numbers for the various sub-sectors. Within Manufacturing and Marketing, you say you've had a NOK3.9 billion gain from Oil Sales Trading and Supply, and you say that some of this comes from exchange rate and valuation of the storage or the inventories. Could you say how much was the effect from the commercial storage and the currency effect?

We have established a practice long time ago where we defined currency effects related to our operational storage. That is something that we correct for, we adjust for it. And we have had a consistent practice of doing that. When it comes to the commercial storage, we consider that to be currency exposure in line with all kind of trading and marketing activities that we are doing in water and oil and gas and so on. So I think we have just made a conclusion that we don't adjust for that number, and I don't think we should.

How high was that number out of those 3.9?

Well, I could give a lot of numbers on these and on our trading activities, but that is an integrated part of our trading activities and our commercial activities, and I'm not prepared to disclose that. But what I can say is that it does definitely not explain the improved result from the Oil segment. Trading is part of it.

It's just that within Natural Gas you also had a trading gain of roughly NOK3.3 billion. So total trading gain in the quarter, was almost NOK7 billion. What would you say is a normalized trading gain? What shall we use as normalized trading gain going forward? Historically, it's been less NOK1 billion per quarter.

I would be very reluctant to give any normalization of trading this quarter, and actually both in the Natural Gas and in the Oil side it has been good quarters. And I think you can see that in the gas price that we have presented as an average included in the gas price. It has been good quarter, good trading results, and that is the same also for Oil and also products related -- product on the Oil side.

So it just happened to be good this year, and other quarters it might not be that good, but to give you an average guidance, I couldn't do that.

I'll take a question from the Internet first, and then there's Trond Omdal afterwards. Helge Andre Martinsen from Nordea, could you please give us some insight into the gas prices of the international volumes?

I think we know we are into contracts on the international side, and so few contracts, basically Shah Deniz and the In Salah, and so I don't think I'm prepared to -- if I started to discuss that, I would disclose -- discuss issues which was related to either of those two contracts, so I think you will just have to accept the numbers that I shared. So for commercial reasons, I don't think we should dive further into that.

Speaking more generally about the gas prices, of course, you are aware of the basically six months lag on our long term contracts from Norway as they are linked to different fuel products. Generally on the gas market, I think also in this segment, we need to be prepared for a volatile and fluctuating market moving forward given the uncertainty related to the economic activity, both in Europe as well as in the US and Asia. And this will come at the same time that there will be additional volumes coming out of new energy plants that are now in the process of being finalized, several places in the world.

Trond Omdal.

Back to the booking of reserves, is there anything more you could share with us about the mechanics of when Marcellus could be booked, or the Oil Sands, and what are the main headline issues?

Okay, when it comes to the Oil Sands, it's pretty much that we have to prove the reservoir that we are drilling in. We cannot use analogs as such. That is something which will be introduced now in the new SEC rules, the possibility to use analog formations as such.

with On shales it's related to the drilling of individual wells going forward.

You will know that SEC is also in the process of changing its rules. That will take effect from January 1 next year. And also explained in 2009, we are in the process of analyzing the details of that. But I think already now we can say that it's a step in the right direction as far as we can see it in terms of aligning the view of the investors and the basis on which the management teams and boards are making their commercial decisions. So there will be some -- or closer to 2p visibility on the resources.

And James Hubbard from Morgan Stanley has just a follow-up question on that, and that means, do we hope to mature some of the NOK7 billion resources we have added in the last two years during the next couple of years? Yes.

Next question is from Adam Porter of Argus Media. What is the lowest price you test projects on and is it lower than the current $40 oil price?

We are typically running a base case, and then a high case and the low case to test robustness in volatile markets. And I can confirm that we are running scenarios at a lower price than we have today. We believe there is so much uncertainty related to economic activity and other factors that can impact the oil prices. So we are also prepared for periods with lower prices than we see in the market today.

But this is not our long term view, as we displayed to the Capital Markets -- at the Capital Markets Day in January in London. We are still of the opinion that once the economy recuperates or is more into normal shape, we will most likely have a situation where the supply side is struggling to meet the demand of increased energy demand.

I have a question related to the transaction market. In the fall, it seemed to hold off quite well on transactions like Goliat and Ume. Do you now see a softening on that and is that an opportunity for Statoil?

Well, I think most investors and I guess management team are mostly focused on capital discipline and getting control of the cash situation. I guess that is a common topic in the oil and gas industry as well. But typically I would say that in a cyclical industry, typical downturns is also periods where we should continue to look for value adding activities. And I guess that in terms of more volatility, if this lasts for a while, I would expect that you would see an increased M&A activity generally in the oil and gas space, simply because people would look at the world differently. And that is always I guess an opportunity for making transactions.

I just wanted to reiterate that the key focus of StatoilHydro right now is to mature the already significant resource base that we have.

Okay, I'll just take a question from David MacKenzie at Silverfleet Capital. How many exploration and extension wells are you going to drill on the NCS in 2009?

We have indicated that we will drill for the corporates between 65 and 70 wells, and roughly 50% of those will be in the Norwegian Continental Shelf for next year as well. So still we are planning at a very high level compared to the historic data, both in Norway and internationally.

A little bit more on exploration, I'll take you on afterwards. But do you see the lower tertiary Gulf of Mexico prospects -- It's a question from Oswald Clint at Bernstein, sorry. Do you see the lower tertiary Gulf of Mexico prospects challenging in terms of economics at today's oil prices and at the current forward curve?

These projects and prospects have always been technically challenging. That is one of the reasons why we have attacked them. But we are convinced and we are still convinced that these resources will be developed. How quickly will to a large extent be also dependant on how the costs are developing in the oil and gas industry, as will be the case for other tougher resources like arctic LNG or even heavy oil and Oil Sands resources. So we cannot only look at the oil price and the forward curve, but also how the cost level is developing.

Yes, a couple of questions regarding cash flow and net debt. Are there any acquisition payments outstanding after the Q4 report?

No, as I said we have paid NOK25 billion out of NOK27 billion in acquisitions. And theoretically -- it's accounting-wise, so theoretically there could be additional cash out but not significant.

Okay and when it comes to the cash breakeven oil price for 2009, you said that was 55 before dividends at the Capital Markets Day. Does that include high gas price for the first half of the year, which we will actually have since the oil price was high in the second half last year?

That includes all of the relevant information we had at the time. We gave that information before. To some extent, yes, it includes the higher gas price.

And if you normalize the gas price, what oil price will we then be talking? Higher than $60 oil price, and do we cash breakeven if we normalize for the effect on the gas price with a lag on oil the price?

I think we have been very conservative in the gas price approach that I just talked about.

Okay, there are a couple of questions on dividends and dividend policy. We start with Aymeric de Villaret from Societe Generale in Paris.

Can we say if oil price remains at these levels that the ordinary dividend of NOK4.40 per share is a floor for future dividend payments?

Well, there are two elements of our dividend policy that we have conveyed very clearly that we have a strong commitment to. And I think we have shown that since the listing of the company 2001. The first one is that we would like to net back to our shareholders 45% to 50% of the net income. And the second part is a growing ordinary dividend, and it is only under extraordinary circumstances we will change that. So there is a strong commitment on our part to deliver on that, as I think now we have done for many years.

And there's an extension on that question from Nitin Sharma from Cazenove. Could you please comment on management's view on the special dividends 2009 if the oil price remains at $40 per barrel?

Well I will not speculate on that over and above reconfirming what we said at the Capital Markets Day in London that we're committed to the policy. I think once again we have shown that that is the case. And we try to find a balance between funding a profitable growth strategy and having adequate financial flexibility to act on good opportunities, and having a firm view and focus, and also returning competitively cash to our shareholders. I think based on the year-end price, we had a dividend yield of 6.4%, and based on yesterdays share price it's 6%. And that should be very competitive in our industry.

And the last question I have on dividend here is from John Rigby at UBS. As you acknowledge, visibility on energy markets is difficult. Why have you chosen to pay out a special dividend when we could be faced with difficult trading and debt conditions in 2009, and when you've cut back on investments activity as discussed on the CMD in January?

Well, generally, I think it is important that we as a Company can -- and realizing that we're working in a cyclical industry that we can manage this Company through cycles, which I think we have shown. And part of the commitment we have in our all value creation is to be competitive on the dividend. We have run our balance sheet for many years also in a prudent way. And our best judgment is what we have done to find the right balance of funding at very high activity level, Capex-wise, exploration-wise, because we believe in those projects, but at the same time return directly to our shareholders.

I would also underline that in an historic context, we are running a, I would say, a very active investment program, a very active exploration program, clearly underlying our long-term view on where the energy market will head moving forward.

Okay we move production. Barry MacCarthy from Royal Bank of Scotland and James Hubbard from Morgan Stanley basically have the same question about OPEC quotas. What is the effect of the OPEC quotas on the international E&P production in 2009 and in first quarter '09 specifically?

Well, we cannot comment specifically on that. What we have said is that the guiding for 2009 does not encompass potential OPEC cuts. How this will be sliced between the different operators is a discussion between the relevant OPEC country and the operator, so it is hard for us to speculate in any specific number. But there is a relatively limited part of our total production that is covered, or that is coming from OPEC countries.

Jason Kenney from ING had a question about the trading profit which was answered I think from John's question a couple of minutes ago. But he also asked a question about Norwegian production. Why was StatoilHydro's oil output from Norway so strong even compared to the NPD numbers?

Well, it is hard for us to comment specifically on the NPD numbers. What we have conveyed the last two years, it's the way we look at it in terms of decline rates where we take all the fields that is on plateau or beyond. At the start of the period, we used the same fields at the end of the period. We calculate oil and gas and the final decline rate. And so far we have been relatively close to doing the right estimates. And I think 2008 is only a confirmation that we focus strongly on delivering IOR and that we are in a position to deliver on our promises.

I would also underline that the numbers from the NPD is basically as I have understood them, they have focused specifically on oil, and is therefore typically will have a different number than we have.

Also one year back we focused a lot on one area where we needed to improve, and that was on drilling efficiency. And we talked about and had an ambition of improving the drilling efficiency by 15%, which we have achieved this year. And this is also helping in terms of delivering on the liquid volumes that we have seen for 2008.

All right, we have a couple of gas questions. The first one is from Iain Reid at Macquarie. Why is the EBIT of the processing transport business lower in the fourth quarter compared to the third quarter when gas volumes on the NCS are 20% higher? And that is, of course, a Natural Gas question.

Well, as I said, volumes were slightly higher and that took us up marginally, but operating costs were slightly up as well, and they were more up than the gas price, so they more than compensated for this. It's not big numbers. It's 0.3 on the cost side and 0.1 on the revenue side. So there was a negative development. And in general, this should be quite stable earnings as alluded to in the question. But there are no detailed explanations beyond this cost explanation.

There is a question from Barry MacCarthy. Has the decline in industry production in Europe had an effect on current demand of Natural Gas?

I think as I mentioned already that we see some softening of some of the gas markets due to the current economic turmoil. And we can see some signs of weaknesses also in the industrial sector. I just repeat that I think we should expect that the gas market is being volatile in the short medium term due to the uncertainty in the economic environment.

Then there's a question from Teodor Nilsen at Argo Securities about impairments. Could you explain the impairments in more detail, and have you considered the potential write-down of the Oil Sands in Canada?

As I said there's a net of NOK1.3 billion for the corporate and also for the international segment as such on impairments. It consists of several assets actually, so there's not one single asset to explain it. It's, as Helge said, we are maintaining basically our long-term view of fundamentals. So this is more related to short-term developments in the market out there. And it's also to some extend related to assets which had been also impaired before.

So it's mainly related to the short-term market issues. Some other issues also goes into goes into evaluation once they start doing that. But that's the main explanation. To go into detail and list these assets asset-by-asset, I don't think I'm prepared to do that for commercial reasons. But as I said, the bulk of this is in the E&P international segment, and the bulk of that is actually in the Gulf of Mexico.

Trond Omdal at the back there.

There have been comments in the press that you and Total might farm down on Kharyaga. Can you say anything about that? And the second thing is about in Russia, and there have been reports that you might be interested in Yamal. Do you think there will a role for foreign companies there?

Well, on the first question I cannot comment specifically on any specific business transaction on Kharyaga. On the general interest long term for Russia, and arctic opportunities including Yamal, I can just say what I've said related to Shtokman, that we feel that StatoilHydro could be a good partner in the challenging arctic developments also in the area that you were focusing on. So I can just confirm that longer term, we have an interest there, yes.

There's a couple more questions on reserve replacement from Paul Spedding at HSBC and from Hootan Yazhari at Merrill Lynch. And basically, they both want to know how the price affects the reserve booking. So do you have indication to what the proven reserve and replacement rate would have been if the oil price had been, say, $60 at the year-end?

I think that I will have to ask the people go back and do that calculation. I'm not ready to do that. But there are factors which goes both directions. And I think that would happen also whether it was $30 or $36 or $60 or $90. So you would have the PFA effect moving in one direction and you would have the cut-offs, the tail-ends, and so simply the breakeven level of some fields which have a higher breakeven to go the other way. And as I said, I do not put any major emphasis on the net effect of that when oil prices end at $36 at the end of this quarter. So my guess is that I would say the same if oil prices were at $60, but that would remain to be seen.

We'll just take a last question on RRR then from Tony Eccles at Citadel. RRR gain, he says, you now have a oil and liquid reserve life of 4.6 years on the NCS. Could you comment on this very low figure? I think we've commented quite a lot, but just give us a last comment then.

Well, I think the R/P figures overall is around 9. It was 10 last year. This is a point assessment of all the situation and I think the most relevant figure to look at when we look at the long-term and the medium-term development of StatoilHydro is to look at the resource base that we think we can develop profitably, and that is best explained by the resource base that we have talked about, that is roughly at 20 billion barrels.

There's a question from [Randy Woods] at BN Americas. What are your specific development plans this year for Peregrino in Brazil and what is your Capex there?

We do not go into specific Capex figures on each project, but we are under full development on the Peregrino project. We have teams in Brazil, in Houston, in Copenhagen to develop the project. We have indicated earlier that the project would be up and running at the end of 2010, beginning of 2011, and there are no change in those plans.

A couple of gas questions again. Start with Iain Reid. You mentioned substantial additional EBIT from gas trading in fourth quarter. Can you say what the underlying profitability was?

I think basically this is more less the same question that was on previously. So it's related to what the long-term contract gives us; the formula in the long term contracts. It's given by the market conditions, and then by what we can add to it in relation to our trading activities. And that has varied from quarter-to-quarter and specifically in this quarter it has been very strong. And you see actually some of this in the Natural Gas segment, but you see also some of that strength in the E&P Norway numbers.

So to normalize and give some further typical guidance on this, I'm not able do that.

But just to clarify, there's a question from Paul Spedding here where he just elaborates a little bit on this. Is it because -- it's just taking advantage of the shape, or the future curve, or have you taken much more positions this quarter than you usually do? What's behind it?

There are some fixed price positions that we have. That have been excluded. So this has nothing to do with fixed price position. That has been excluded as an infrequent item.

So this is the normalized trading activities, the arbitrage activities, making use of the flexibility we have in terms of moving volumes between locations. And there are several locations and pipelines that we are talking about and also moving volumes in time.

So we have quite a comprehensive business which is only doing that, trying to add volumes on top of whatever the market would give you if you just landed the gas on whatever beach. So this is, as I said, values on top of that business.

And the last question on Natural Gas. This time it's from Oswald Clint. He again said that we appear to have a strong performance on the Natural Gas division. But what about 2009? Have you hedged any volumes in 2009? Or what performing trends do you expect from Natural Gas trading division in 2009?

Well, we discussed a bit the market. General market outlook; volatility is to be expected and maybe softening of the market throughout 2009 due to the economic circumstances. But, of course, we will continue to benefit and exploit the very strong position that StatoilHydro has built in terms of gas market competence, in terms of storage, in terms of liquid hubs and participating in the market in Europe in the best possible way, so I am not prepared to give any specific forecast but that we continue to benefit from the investments and the positions that we have built up throughout many, many years.

Thank you. There's a couple of questions on dividends from Neil Morton, M F Global. Of the major oil companies, you are one of the remaining few that still pays an annual dividend. Given the current investor focus on yield, do you have any thoughts on moving to semi-annual or even quarterly dividend payouts?

We have a clear dividend policy that has been with the Company for many years, and I am not prepared at this stage to speculate on any changes in that policy. We are focused, as I said earlier today and on earlier occasions, to be competitive, and we still want to be that. And I think in terms of yield we have been competitive also this year at 6.4% and 6% respectively relative to the share price at the end of the year and the share price of yesterday.

So basically, the last question from Neil here is more or less answered in the answers we have given here. Do you have any thoughts about phasing out the special dividends - we keep the 45% to 50%, and if that gives a special, it gives a special.

We are in close dialogue with our shareholders all the time and we try to take in as much input as we can on this topic. Generally, my impression so far, you might want to confirm that, Eldar, is that today the way we have dealt with this since the Company was listed is respected and competitive but, of course, we continue to have dialogue on this issue.

So we move to tax -- international tax rate actually. International E&P is a question from Nitin Sharma at Cazenove. International E&P's effective tax rate looks high versus the historical tax rate. Could you please comment on if we should expect any changes in the tax rate for this segment going forward?

This quarter there are special circumstances which Eldar touched upon making the tax rate in excess of 100%, but there is no change in the guidance we have had before that we should expect a tax rate from the International segment of 40% plus.

Thank you. There is a question from Kim Fustier at JP Morgan. Can you give us an update on Kvitebjorn. Gas exports resumed in January, but is it running at full capacity?

The pipeline repair is concluded successfully. It is the first time we have repaired a pipeline with remote equipment at deep water. That is closed. There is certainly issues with one of the valves that was identified prior to the repair, but that could not be worked on before now and we are not running at full capacity at Kvitebjorn, but this is unrelated to the pipeline.

Thank you. And there's a relatively technical question from Nitin Sharma about accounts, but he asks about the change in reporting currency. We can correct that in a minute, but could you please comment if this will impact the reporting of the mark-to-market gains and losses on currency swaps?

Can I leave that to Kaare?

What we are doing from January 2009, as described in the MD&A, we are changing the functional currency in the mother Company to US dollars following restructuring of the Company; legally restructuring, and that -- but we keep Norwegian kroner as the reporting currency. We will expect -- we expect less currency fluctuations also in the reporting of the Norwegian kroner Group figures in 2009 based on this change.

But it is fair to say that we still -- currency swaps usually have a Norwegian leg and a US dollar leg, and if you change from US dollar or -- there will still be a mark-to-market revaluation on especially that, so that's still going to be in there.

Okay, there is a question from Kim Fustier at JP Morgan. Your unit production costs guidance is NOK33 to NOK36 per barrel, and it implies a decline in the US dollar denominated Opex per barrel of 4% to 12%. Do you expect this reduction to come from industry cost inflation, or can you talk more generally about how you are going to reduce oil service costs?

A starting point that I have is that the oil and gas industry is no different from any other industry. So when there is demand going away and you have the same capacity, there will over time be a reduction also in the service costs. This will happen this time as well.

I think that it is a benefit for the operators as well as the service companies as it will give a longer prospective on how to develop the business. We saw little impact on this in 2008; maybe at the end of 2008, maybe some flattening out. We have started to see that there is some impact on this, and if the current oil market prevails, I think we will see increasing accelerating effect as we move throughout 2009.

We have been very firm on that, that we are attacking our own cost base internally in StatoilHydro the way we operate our business. We will look at the crisis as an opportunity to improve efficiency and quality, but we have been equally clear that we expect good co-operation and collaboration also in the service sector to address the cost base wherever they are operating in the world.

We are close to the last question here, but there is a question from Randy Woods at B N Americas. How would you rate your level of interest in the Carabobo Round in Venezuela's Orinoco? Have you had -- that is the first question. And the second question is have you had to reduce your output from the country due to OPEC costs? Second question.

I will not comment specifically on OPEC. We have to come back to that when we have a clearer, fuller picture. We have taken the view that the long-term resource base in Venezuela is interesting. We have good technical experience from that area for many years related to the Sincor project and now the Petrocedeno project. We are interested to look at how we can continue to develop our business, but there are no decisions into the near term in terms of committing additional capital. And if we are to do that, we have to feel confident that there is a good investment climate for ourselves.

Then there is a question from Ian Reid, and then one from Teodor Nilsen, and then we don't have any more here.

The one from Ian Reid is about Shah Deniz phase II. Is it your preference to transport the gas via your joint venture with EGL. or is it possible that you would join the Nobuco consortium?

So far we have not viewed the Nobuco as particularly attractive in the sense that it is a huge project with relatively limited resources to support it, and very difficult to execute. So we have been looking at alternatives, and one of them is the TAP where we have taken an ownership position as well. But we are primarily a gas producer and a gas marketer, and we are quite pragmatic as to how our gas comes to the market.

Currently, we view perhaps that the TAP is more likely than Nobuco, but some of the projects, or most of the projects are meeting the same challenges, i.e. transit from Azerbaijan to the European markets, so we would have to continue to work on this with the other partners and the Azeri government.

And now the last question on the Internet from Teodor Nilsen at Argo. Given an oil price of $45 per barrel and an unchanged cost level over the next years, how will this affect the Peregrino development?

Well, the Peregrino project is a very competitive one with a breakeven rate of less than $50, and I don't feel it is particularly relevant to compare an oil price environment for many years of $40 with the current cost level; then we will have to attack both. But for us, Peregrino is a very important long-term project with a long-term production profile, and we continue to execute that project efficiently.

Well, thank you very much. This was actually the last question I have on the Internet, and it doesn't appear that we have any more questions in -- for the floor here in Oslo.

This presentation and the Q&A can be replayed from our web page, Statoilhydro.com, and there will be a transcript for the whole session available during next week when it's ready. So thank you very much for the participation and good bye.

Thank you. That will conclude today's conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.