Equinor ASA (EQNR) 2008 Q3 法說會逐字稿

Welcome to the StatoilHydro third quarter 2008 earnings presentation. My name is Lars Sorensen, and I am the Head of Investor Relations.

This morning at 8 am Central European time, we put all the presentations and MD&A out on the web, both on our own website, statoilhydro.com, but also on the Oslo Stock Exchange website. The presentation that we use today can be downloaded from both the Oslo Stock Exchange page but also statoilhydro.com, of course.

I would like to direct your attention to the disclaimer and safe harbor statements that we have in the back of the presentation.

Eldar Saetre, StatoilHydro's Chief Financial Officer, will take us through today's earnings presentation. After the presentation, we will have a gas seminar, or after the presentation we will have a Q&A session first, sorry, where you can ask questions both from the floor here in London but also from the Internet.

After the earnings presentation and after the Q&A session of that session, we will have a gas seminar. We'd like to invite you to participate on that, of course, if you would like to, and it's Executive Vice President and Head of Natural Gas, Rune Bjornson, who will be the host of that presentation. I'll come back to presenting the presenters in that presentation later. The seminar will be webcast as well, so if you would like to follow that presentation on the web you can do that.

At this point I'd like to welcome or send my welcomes to the audience from the web. You can actually send in your questions and I will read them aloud to Mr. Saetre, or later at the gas presentation's Q&A. And if you can do that already now, you can use the submit questions button on your screen.

So after these short words of introduction, I'm quite privileged to welcome our Chief Financial Officer, Eldar Saetre.

Well thank you, Lars. Ladies and gentlemen, I would like to welcome you first of all to this third quarter presentation here in London.

It should come as no surprise to any of us that both financial markets and commodity markets are volatile. But, I have to say, that to see the volatility and the power of the financial crisis that we have experienced over the last two weeks, that has been quite an experience for all of us. Being in a business with very long-term horizons, I think it is our duty as management to make our investment decisions and really to plan our operations in such a way that we are able to create shareholder values through the cycles whatever are the situations and the cycles of the economy.

We expect that the world economy will see a downturn for some time derived from this financial crisis, and that this also will have an impact on the demand and supply for our core commodities. Fundamentally, however, we maintain the longer term perspective on our industry. There will be growing demand for oil and gas in the years to come, and it is our duty, and also our competence, to accommodate this.

So our strategy, therefore, remains firm. We have a strong portfolio of assets and we maintain our current plans, although taking into account the effects of the current markets and also fully understanding the optionality and the flexibility that we actually have in our portfolio.

So this is the background for my presentation today, and the main message that I will convey today is that, first of all, StatoilHydro has a solid underlying operations, and we have made some improvements also during this quarter that I will come back to. Secondly, that our financial position is fundamentally solid, and that we have a strong cash flow generation at the current price environment, which is sufficient to serve both our CapEx program and a dividend payout in line with our dividend policy.

So I will come back to all of these issues and I will start with the highlights of the quarter. Our underlying net operating income increased by almost 60% on a quarter-to-quarter basis. The main driver behind this increase is higher obviously, higher oil and gas prices. However, we also saw a 1% increase in equity oil production on the quarterly oil and gas production and on a year-to-date basis a 5% increase in oil and gas production.

At this point, I would also like to highlight our strong performance on the Norwegian Continental Shelf. We saw a high regularity this quarter, including the successful completion of a very comprehensive, actually, the most comprehensive turnaround maintenance program that we have ever seen. We saw continued good progress on drilling, improving our drilling operations. And also a continued high success rate on our exploration program on the Norwegian Continental Shelf. In addition, we also strengthened our position in the Goliath discovery in the Barents Sea.

Then, we also had this quarter a significant non-cash impact on our net financial items, and consequently, also on our net income. And this comes from a 15% weakening of the Norwegian krone versus the US dollar. Then, you have to remember, fundamentally, StatoilHydro benefits from strong US dollar. However, this quarter the foreign exchange accounting adjustments related to our US debt, and also some currency swaps, and I'll come back to this, is minus almost NOK14 billion, which is the main explanation for the negative net financials of NOK9.7 billion this quarter. And I underline that these are unrealized, and they are non-cash, as such, and accounting effects and adjustments.

Finally, I repeat that our financial position is strong, with a good cash generation from operations, and I will revert to all of these topics later in my presentation. But let me first just remind you of some changes, improvements that we have made to our disclosure practice just to make sure that you understand this and are able to benefit from them.

First of all, we will now discuss our results more consistently in the financial review on the basis of what we call adjusted or underlying net operating income. As you know, reporting according to IFRS introduces some volatility, we could say, in the profit and loss related to fair valuation of various assets, impairments and reversal also of impairment derivatives, accounting, etc. And also then we have the over/underlift situation from quarter-to-quarter, that also changes as the listing schedule impacts this, and so does accounting effects on inventories when oil prices change, etc. So in order for you investors and analysts to be better able to compare the underlying performance, we therefore adjust for these infrequent items.

With regards to costs, we now also provide a more detailed split of the operating cost development, including a breakdown from the total Group operating costs down to the upstream cash production costs. So you can see how you can reconcile these components, which is then relevant when you measure the unit production costs as we presented for the Group as a whole.

Finally on this issue, within the Natural Gas business segment, we now split the net operating income into Processing and Transportation and Marketing and Trading. And within Processing and Transportation, what you will find there is the income from our share of the in Gassled, the pipeline system in Norway, and also income generated from all our technical service provider related to the gas processing facilities at Karsto and Kollsnes. This is also on the Marketing and Trading sub-segment. Then, it's reflecting the value added from these activities on top of our upstream business.

So we trust these improvements to our reporting is appreciated, and that you will soon get acquainted with these. And then I will proceed to our most important value driver.

As already mentioned, we have delivered a 1% equity production growth compared to the same quarter last year reaching an equity production of 1,733,000 barrels per day. On the Norwegian Continental Shelf, production has developed more or less as planned except for the Kvitebjorn pipeline incident that you should be aware of.

Production outside of Norway has been slightly lower than expected due to some unplanned shutdowns. In the third quarter, as I've already mentioned, we had an extensive turnaround program on the Norwegian Continental Shelf. The negative impact from this turnaround program was approximately 70,000 barrels per day in the quarter compared to approximately 40,000 barrels per day in the same quarter last year.

The impact on planned maintenance on the outside of Norway was in the range of 10,000 barrels per day in this quarter. Unplanned shutdowns that I mentioned from our international operations outside of Norway accounted for approximately 25,000 barrels per day this quarter, and it was mainly related to our activities in Azerbaijan.

So in summary, we have delivered the 5% equity production growth on a year-to-date basis, and we maintain our guiding of 1.9 million barrels per day of equity production for the full year of 2008.

Entitlement production in the third quarter was 1,550,000 barrels per day compared to 1,596,000 in the third quarter of last year. And the main reasons for this reduction is new tranches in some production sharing agreements, and also including the unplanned shutdowns and repairs, as I have already mentioned.

So let me now turn to the key financials in more detail. As I have already mentioned, we now focus our discussion on the adjusted for the underlying net operating income. In the third quarter, our underlying net operating income was NOK52.1 billion compared to NOK32.8 billion last year. And this increase was due to 36% increase in the realized liquids prices measured in Norwegian krone, and a 55% increase in gas prices, also measured in Norwegian krone. This was partly offset by a 3% reduction in entitlement production, and also somewhat higher operating costs that I will come back to.

Infrequent items. Special items impacting our net operating income was a negative NOK5.1 billion, which I also will revert to later in the presentation. Net financial items amounted to minus NOK9.7 billion in the quarter, and this was caused by a weakening of the Norwegian krone versus US dollar. And I will discuss this actually on my next slide, but let me now explain the unusually high tax rate of 83% this quarter.

This is mainly related to two factors. First, it has to do with the net financial items, which is quite significant, as you have seen, and negative this quarter. And they are calculated at a tax rate of around 45%, and in this quarter it was more or less exactly 45%. So therefore, about 45% of the net unrealized financial costs, and it's costs this time, of NOK9.7 billion is deducted while the operating income typically have a tax rate of around 70%. So this impact, 45% on a big cost component, that drives up the average tax rate for the quarter.

The other main component is related to impairments of NOK3.1 billion, which mainly comes from our Gulf of Mexico portfolio. These assets in the Gulf of Mexico, which have been impaired, are without tax protection from an accounting, and I repeat, from an accounting perspective. Future income generated from these and some other assets are considered to come too far into the future to be recognized in an accounting perspective. But these losses, if they are maintained, are still, obviously, deductible from a tax cash payment perspective when revenues emerge.

So then to the net financial items. These amounted to a negative NOK9.7 billion, mainly caused by unrealized currency impacts on long-term debt and short-term liquidity swaps of almost NOK14 billion that I mentioned and that you can see here.

We manage StatoilHydro as a US dollar business and, as I mentioned already, long-term, StatoilHydro will benefit from a strong US dollar. However, our accounts are reported in Norwegian krone, which is also the basis for the main part of our tax payments and also our dividend payments. And that, this tax, gives some non-cash accounting volatility from quarter-to-quarter and the development this quarter is as expected.

The weakening of the Norwegian krone against the US dollar results in an unrealized currency loss related to our long-term debt. The weakening of NOK0.75 or 15% resulted in an unrealized accounting loss on long-term debt of NOK5.1 billion.

Then, to the liquidity part. As mentioned, our revenues are mainly in US dollar, with tax liabilities and dividend commitments continuously in Norwegian krone, accruing in Norwegian krone. To manage this currency exposure in Norwegian krone, related to future tax and dividend payments, we therefore fix the US dollar and NOK relationship on a daily basis, and hence remove the currency risk related to this future Norwegian krone commitments, as I mentioned, related to tax and dividends.

However, as most of our running OpEx and CapEx are still in US dollar, we therefore swap this Norwegian krone hedge position back into US dollar with a maturity matching the future tax and dividend payments. And these swaps are marked-to-market in our accounts and they result, therefore, in an unrealized gain or loss every quarter, and you have seen that in our accounts for many quarters now. And in this third quarter, these swaps generated, as I said, an unrealized still non-cash loss of approximately NOK8.7 billion.

Then I will give some comments to each of the business areas, starting with E&P Norway. The adjusted net operating income for E&P Norway was NOK43.8 billion, compared to NOK28.3 last year. The increase was mainly due to a 38% increase in liquid prices in Norwegian krone and a 38% increase in the transfer price of natural gas. The realized price for liquids, that is crude, condensate and NGL, was approximately $110 per barrel on average, against the Brent average of approximately $115 per barrel.

On the NCS, almost 15% of our liquid volumes is NGL, which have been priced at a lower price than the crude oil. And that explains, actually, the whole price differential of $5 compared to Brent Blend.

Average daily production of liquids increased from 770,000 barrels per day last year, in third quarter last year, to 780,000 barrels per day this quarter. And average gas production decreased from 537,000 barrels per day to 512,000 barrels per day in oil equivalents in the third quarter this year, and this is mainly driven by the Kvitebjorn pipeline incident that I already mentioned.

At our capital markets day in January, we also presented some plans for improving our drilling efficiency, both related to drilling of new production wells to fight the decline of the Norwegian Continental Shelf, and also to improve exploration activities. In 2007, we managed to drill around 70 meters per day on average, and in 2006, the performance was even worse, actually. Year-to-date in 2008, we have reached approximately 80 meters per day; that is a 15% improvement, and in line, actually, with what we indicated as an improvement in January at our capital markets day. So this is, really, a strong achievement for such a big portfolio within a short timeframe, and we will certainly do our utmost to sustain this performance and improve even further.

And I've mentioned, we have also completed the most extensive turnaround program ever on the Norwegian Continental Shelf, and this, which is really a portfolio big project, complex project, has been delivered on time, and with the consequences for production that we have guided on earlier.

Then to the International, outside of Norway, business. Again, adjusted for infrequent items, net operating income for our E&P outside Norway was NOK3.8 billion, compared to NOK3.4 billion in the same quarter last year. This increase was mainly due to a 29% increase in realized liquid prices, measured in Norwegian krone again, which contributed NOK2.1 billion to the improvement.

And in this context, I should also mention a particular feature of the quarter, that we actually had 63% of our lifted volumes on the international side taking place in September. And this is due to the predefined lifting schedules and procedures that are in place, and with the declining prices through the quarter, this led to lower average realized prices, again, compared to Brent Blend.

Adjusted exploration expenses were down NOK0.5 billion, when we adjust for NOK1.3 billion in impairments, which is allocated to exploration within the international E&P segment. And the reduction of NOK0.5 billion is related to increased capitalization of international exploration activities. And all of these increases were partly compensated by an 11% decrease in the average daily entitlement production.

So in addition to some unplanned shutdowns, as already mentioned, there was an average PSA effect on entitlement production of 183,000 barrels per day on a quarterly basis, and 178,000 barrels per day on a year-to-date basis, compared to 125,000 barrels per day in the same quarter last year.

Finally on this segment, a comment, start-up of new fields led to an increase of depreciations of NOK0.4 billion, ordinary depreciations, when we then adjust for NOK1.8 billion in impairments, which is allocated to depreciations.

Then to the Natural Gas business. The adjusted for infrequent items, which is basically derivatives in this segment, the income for Natural Gas business was NOK2.2 billion, compared to NOK1 billion in the same quarter last year.

The adjusted operating income within Processing and Transportation, and we now as I said have split this segment, was NOK1.6 billion, which is at the same level as it was last year, while the adjusted net income for the Marketing and Trading was NOK0.7 billion positive, compared to a loss of NOK0.6 billion last year.

The volume weighted average sales price was NOK2.37 per standard cubic meter in the quarter, compared to NOK1.53 in the same quarter last year. And as I mentioned, that is a 55% increase in Norwegian krone.

Natural Gas sales volumes were 9.9 billion standard cubic meter in the quarter, and that is approximately at the same level as we saw in the same quarter last year. And of the total gas sales in this quarter, 7.9 BCM was entitlement gas from the Norwegian Continental Shelf, and 2 BCM was third party gas.

Adjusted operating expenses increased by NOK0.6 billion, compared to third quarter last year, if you adjust these numbers. And this is due to increased transportation activities caused by start-up of new pipelines related to the the start-up of the Langeled pipeline. And also the Tampen Link pipeline, and also higher LNG transportation volumes and costs as these volumes are ramping up.

I would also mention one small item; sales, general and administration costs. You can see in the financial review that these have increased by NOK0.2 billion, and the underlying cost for StatoilHydro is unchanged. So this increase is entirely related to expenses covered by the SDFI, the state share of marketing activities in the US, so this is a grossing principle that has been applied.

Finally, to the Manufacturing and Marketing. The adjusted net operating income for this segment was NOK2.7 billion, compared to NOK0.4 billion in the same quarter last year, and I will comment this under each of the business sub-segments of this part of our business.

Oil sales, trading and supply had a net operating income of NOK2.3 billion, compared to a loss of NOK0.3 billion last year. The increase was due to positive currency impacts which we haven't adjusted for, on our commercial storage, and also positive development, in particular related to our crude trading activities.

The adjusted net operating income for Manufacturing was NOK0.2 billion, compared to NOK0.5 billion last year, and this reduction is due to the still ongoing, quite comprehensive, started early September, turnaround at our Mongstad refinery, quite extensive, leading to both reduced revenues on the refinery side, and also higher maintenance costs related to this turnaround, and it's all done in order to improve the operational robustness of this very important refinery for us.

Adjusted net operating income for Energy and Retail was NOK0.3 billion compared to NOK0.2 billion in last year.

So let me now summarize the adjustments that we have made in our reported numbers in order to arrive at our underlying net operating income.

As already mentioned in my introduction, our income is adjusted for certain items that are not reflective, to be precise, our underlying performance in the reporting period. And the following items have been adjusted for in this quarter. First of all, impairments had a negative impact of NOK3.1 billion before tax, and NOK2.9 billion after tax for the reasons that I mentioned to you earlier. This is mostly related to Gulf of Mexico assets, and mainly due to changes in forward prices because these are assets that have been impaired earlier, and they are following the markets out there every quarter.

This quarter, we also, I'll comment on derivatives, sorry. Derivatives had a positive impact of NOK0.9 billion before tax, and after tax NOK0.8 billion this quarter. And this comes from a negative impact on the E&P Norway business segment of NOK2 billion, which is related to the earn-out agreement that some of you have seen, following us for many quarters now, and this time it's because the forward prices and development evaluation is down. While we have positive impacts both on Natural Gas and in the Manufacturing and Marketing of approximately NOK1.5 billion in each of those segments from derivatives.

Turn to the underlift, and this quarter we had an underlift position of approximately 30,000 barrels per day on the Norwegian Continental Shelf, and there was no such position basically outside of Norway. And this amounted to NOK1.3 billion before tax and NOK0.3 billion after tax.

Finally, we had a provision that related to a take-or-pay contract within our Manufacturing and Marketing segment of NOK1.3 billion before tax, NOK0.9 billion after tax, and also some miscellaneous accruals of minus NOK0.3 billion.

So combined, all of these infrequent items represent a negative impact of NOK5.1 billion before tax, NOK3.4 billion after tax, and in the same quarter last year it was a positive impact of NOK3.1 billion before tax. I should also mention that you will find more details, including how these effects are broken down on each of the business segments, in our financial review statements.

Then I would like to give a few comments also to our operating expenses. And as I mentioned, we have added a more detailed split of these costs in our review this time, and we will continue to do so. The E&P upstream production cost in absolute numbers have shown an increasing trend, that you can see here, to the left.

From third quarter last year to third quarter this year, about two-thirds of this increase of NOK0.7 billion is related to activities. It's about start-up or new activities, both on the international operations and the Norwegian Continental Shelf. And the last third, that is the net effect of industry cost inflation of also increased maintenance on the mature fields on the Norwegian Continental Shelf, and obviously also compensating measures that we are doing to compensate for these increases. Based on equity volumes, the unit production cost was NOK33.3 per barrel for the last 12 months, compared to NOK29 per barrel in the same 12 months one year ago.

So overall, we had an upstream cost development, according to our expectations, and our guiding remains the same; a production unit cost of around NOK33 per barrel to NOK36 per barrel in the period from 2008 to 2012, with an upwards pressure in this period.

The operating costs within the Natural Gas and Manufacturing and Marketing have also increased compared to the third quarter last year, even if you exclude the infrequent items that you can see illustrated here. The higher operating costs, compared to the same quarter last year, was mainly due to the higher transportation cost, as I've already explained and that the Natural Gas segment. And also costs related to the comprehensive turnaround at Mongstad.

Then a few comments also to our financial position. Some of you might be concerned about how cash flows and financials are looking these days. And as already mentioned in my introduction, I can assure you that we are in good shape.

Our after-tax cash flow from operations was NOK113 billion in the first nine months of this year, and in addition, we had sale of assets generating NOK5 billion, so that was cash coming in to us. We invested, cash-wise, NOK46 billion, and we paid NOK27 billion in dividends related to 2007. And that leaves us with a cash flow of NOK72 billion, if you exclude the dividends, which are related to 2007.

As per the end of this quarter, September 30, our cash exceeded our debt with NOK13 billion. So in other words, we are generating a strong cash flow and we also have a strong balance sheet which gives us financial flexibility and capacity to continue with our high quality CapEx program, while staying fully committed to our dividend policy of paying 45% to 50% of our net income over time.

As we said at our capital markets day in January, we are cash flow neutral for this year, before dividends, at around $50 per barrel, that excludes acquisitions. And nothing at all has changed to this statement, it's still the same $50 per barrel.

I should also remind you that all our ongoing project developments that we are developing, in the process of developing now, have been sanctioned on the basis of lower oil prices than we currently see, and also that our portfolio producing assets these days have significantly lower break-even prices than you see today. Our non-sanctioned asset portfolio is also constructed in such a way that the projects with the highest assumed break-even prices are also the projects with the largest flexibility and optionality in our portfolio when it comes to timing and the strategy of developing these assets.

Finally, to summarize my presentation, let's have a look at the guiding for the full year of 2008. At the capital markets day in January, we guided an equity production of 1.9 million barrels per day, and our production performance during the first nine months of this year has been strong and supports the same guidance of 1.9 million barrels per day. Our 2012 guidance is also unchanged, at 2.2 million barrels per day.

At the second quarter presentation in August, we estimated organic capital expenditure for the Group as a whole at a level of NOK65 billion for the year, and that was based on an estimated NOK5.25 per $1, and that was reasonable at that time, for the rest of the year.

The estimated capital expenditure remains unchanged at these assumptions, although the current level of US dollar versus Norwegian krone will influence the final year-end figure. And remember that approximately 7% of our CapEx is exposed to US dollar.

Unit production costs for equity volumes is estimated, as I said, in the range of NOK33 per barrel to NOK36 per barrel in this period. We expect to continue our high exploration activity level throughout this year, and to complete around 75 to 80 wells this year. That is slightly more than we have guided you previously, but it still keeps our exploration cost estimate at below NOK18 billion.

Finally, I would like to remind you that a potential further strengthening of the US dollar versus Norwegian krone that we saw in the third quarter, will have, and as we have seen actually so far this quarter, will have a negative impact on the net financial items also in this quarter, so that's just to remind you. But then, you should also remember that, fundamentally, we will benefit from a strong US dollar.

And as my closing comment, I would just inform you that we will announce more details when it comes to 2009 at our capital markets update, as we call it, presentation on January 14 next year here in London. So I hope to see you then. Thank you for the attention and I leave the word back to Lars for some Q&As.

Well thank you, Eldar. I now invite you in London to ask questions, and also just repeat asking questions from the Internet; you can do that by pressing the submit questions buttons and I will receive them on my PC and ask the questions on your behalf. You can do that already, so please send in your questions now.

Then I would like to invite the Senior Vice President, the Head of Performance Management and Control, Torgrim Reitan to join us here in the panel, and also the Executive Vice President and Head of Natural Gas, Rune Bjornson who will also be available here next to me.

Yes, the first question. I'll take one from the Internet and then I'll go back to the floor here. The first question is from Jason Kinney, ING and it's about PSA effects. We have a guiding at page 25 in the presentation with some indications on what the PSA effects are on an annual basis. And Jason asks at a $40 per barrel shift it implies a 4,000 barrels per day impact between $80 and $100 per barrel in oil price. However, in the 2Q results, there was a $35 per barrel change between $150 and $115 and there, the impact was 15,000 barrels per day. Can we assume that StatoilHydro's portfolio is less sensitive at lower prices, or is that an S curve out here?

I think what you can assume is basically what we guide you on. It's hard to be precise and use this as a basis for making further assumption.

Basically we have a PSA effect of $178 per barrel so far this year, and at $100 that will remain the same. So I think during the third quarter, we have seen no assets coming into new tranches and basically we don't expect to see that in the fourth quarter, but maybe you Torgrim could add something to this?

Yes, thank you Eldar. I think it's important to recognize that during 2007 we had a large increase in the PSA effects as we saw oil prices increase steadily and we also saw that in the beginning of 2007.

We have come through a lot of tranches, so currently it looks stable. There are still a few which are in cost recovery phases and then will move into tranches later, but not assumed in 2008 as such. So we said at the capital market day that at $100 per barrel as an average oil price, the PSA effect could be approximately 180,000 barrels a day, and, as you see, it's the same message currently as well. So it's going along as we planned.

Thank you. Another question from Iain Reid from the floor here in London.

Hi, it's Iain Reid from Macquarie. Eldar, a couple of questions. Firstly, the discount to Brent you've now got at the moment, I understand your comments about the NGL pricing differentials, but about a year ago, you had about $1 per barrel differential. Now that oil prices have fallen to approximately where we were about a year ago, is it again going to be $1 or is this $6 or $7 locked in now?

And the second thing is, you talked about flexibility at some of the higher cost projects. I presume you mean oil sands etc.? Can you give an indication of what you mean by flexibility? Does this mean we should expect a delay for the implementation of the future phases of oil sands?

When it comes to the flexibility, what we are talking about is definitely that kind of project. We have underlined all the time, since the acquisition in Canada, that one important feature for us was actually the flexibility and the optionality in that portfolio. And so far, what we have done is to embark on the lifespan, the demonstration plan, which is progressing according to plan.

So still we have the same flexibility in that portfolio and obviously, we are following the cost developments, and potentially what happens to that if this environment continues, and obviously we also have other development opportunities in our portfolio, in particular related to the really deepwater stuff, for instance, in the Gulf of Mexico. And what I'm saying is that there is flexibility also there, if it's proper to delay some of these projects.

So again, the average picture is that we have more flexibility at the higher end, assumed higher end of the cost curve, illustrated, as you said, by the Canadian oil sands position.

On the first question Torgrim, maybe you would?

When it comes to the NGL and the whole debt effects, the realized price versus Brent Blend, what we saw during the last year is that as oil prices increased steadily and the prices of the NGLs didn't follow as much, so the contribution from the NGL didn't matter so much in the realized price as it has done the two last quarters. So I think that is the observation that we also have, yes.

So you see that differential closing up?

I think it's very hard to predict anything in these days.

If I could add, I mean NGL is going into totally different markets. It goes typically into the petrochemicals, into the refineries. And what we have seen this quarter is pretty much the spreads coming down, but they're still at I think something like $70 per barrel at an average of the NGLs, and while oil price has come down. So it's depending very much on where that market for NGLs as such is developing and it's not related very strongly to oil as such.

Okay, thank you. We'll take one question from the Internet. It's about the Canadian oil sands. It's from John Olaisen from Carnegie. Have you got any impairments to the Canadian oil sands, or is it still valued at $2 billion on the balance sheet? Or was it considered to make an impairment?

No impairments and we consider a lot of stuff, but this one was not considered, as far as I know.

James Hubbard, Morgan Stanley?

Thanks. James Hubbard from Morgan Stanley. Just two questions. On development drilling, you talked about a metric of meters per day, 80 meters per day. I think earlier in the year, you talked about a number of wells and that figure was 60 if I'm remembering correctly. Can you put that metric of meters per day in the context of how many of the 60 have been drilled? Because obviously this quarter is distorted by all the maintenance, it's hard to see what's really going on in the underlying NCS portfolio.

And then do you actually think internally of meters per day? Because it seems to me that's a metric that could incentivize people in the wrong way in the field.

And then secondly, the Gulf of Mexico impairments you mentioned in the presentation, what were they? Are they in line with the previous Gulf of Mexico impairments? And if so, is that the end of those impairments, or is it something completely different?

What I can say when it comes to the impairment is that these are assets that we have impaired earlier. So according to IFRS what happens then is that you get the volatility into these, if forward prices increased, we would have to reverse the impairments and if forward prices goes down, you have to take it down. So once you have started impairing these assets, you are into the elevator to put it that way. So there's no new assets related to the previous assets that we have been impaired in Gulf of Mexico.

When it comes to the number of wells, what we try to do is to present this in a way which is easily understandable and I can assure that we have metrics, which is more complicated than meter per well. And there are various types of wells to be drilled and so on, and so it doesn't really say something about the complexity of our program. So just a way of communicating in a simplistic way.

But fundamentally, we have improved by approximately 15%, adjusting for all these factors. And in terms of number of wells, I think we have drilled something like 80, 81 wells so far this year, and last year we drilled --85 to 86 for the full year. So we have pretty much drilled as many wells as we did for the full year last year by the end of the quarter.

Colin?

Thank you. It's Colin Smith from Dresdner Kleinwort. Two questions as well if I may. First one. Just in view of the pressure there is in growing volume in the international business, and with the change in equity and asset prices that appears to be going on, can you just make a comment about where you think things stand in view of your strong balance sheet as well with regard to further M&A activity?

And the second question was just on your dividend policy. Can you just remind us when you're thinking about the payout ratio, whether you're focusing on the reported net income, or whether you think about it more in terms of the adjusted net income? Because obviously last year, there was a pretty high payout ratio if you relate it back to the reported net income, and a little bit more clarity around that would be helpful. Thank you.

Well when it comes to the dividend, take that first, the dividend policy is related to our actual operating income or net income as it is reported. That being said, we obviously will take into consideration the elements creating that operating income. So all the elements that is being adjusted for in the numbers, the adjusted numbers, will obviously be things that will be taken into consideration when we conclude on our actual dividend payment as such in accordance with the dividend policy. But the starting point, that is the reported numbers.

When it comes to M&A activities, basically what I said was that we have to think long-term in this industry and something we do continuously is to evaluate M&A opportunities, both on an asset basis and portfolios of assets, put it that way, and we will continue to do so. And we have a strong financial position, as I illustrated, and we have access to funds, to put it that way, being rated the way we are. So we feel to be robust in this situation. This is actually a good place to be.

So we will continue to look at that kind of opportunities and they could even be cheaper than they were some time ago depending very much on the specifics here. So yes, we will have to think through the cycles also in respect of these activities.

So I think that being said, obviously, we are taking into account what is happening around us now in all aspects and both in terms of our own financials and the impact on commodities and supply and demand of our commodities, so that is definitely going to be part of the equation.

Okay, the dividend answer also answers a question from Michele Della Vigna, Goldman Sachs who asks what the dividend payout would be. So 45% to 50% is firm.

Next question from Neill Morton.

Hi there, it's Neill Morton from MF Global. I have a question on your accounting policy with the caveat that I'm not an accountant, this might be a very stupid question. I'm just continually intrigued by the very large currency swings from quarter-to-quarter. I appreciate that I understand the mechanics, I understand it's all non-cash, but I also note that the other large non-dollar reporter European companies with dollar debt, presumably also obviously reporting under IFRS, aren't reporting these big swings quarter-to-quarter. I guess the question is firstly have you benchmarked your policy versus your peers?

And secondly, are you concerned that these effects are perhaps diluting the transparency of your results?

I think we continuously have to make sure that we have a good feeling about our policies. When it comes to keeping our US dollar -- our debt in US dollar, I think that is a very logical policy in relation to the fact that most of our revenues come from the same currency. So I think that's a robust policy.

And also in terms of liquidity management to really make sure that we have the cash in Norwegian krone available in the amount that it's reflecting the underlying performing leading to these tax payments, and related to that period, I think that is a prudent policy as well.

We have made a lot of money on that when things have gone the other way, and now we see a loss and basically it's not a cash loss as such, it's simply making sure that we have the Norwegian krone available in the amount that we planned for and in the relation to the underlying income supporting it.

But your peers have these policies in place as well and yet they're not reporting the same quarter-to-quarter swings.

Yes, to my knowledge, this is a very common way of operating liquidity management as such, and, in particular, in our case, also to keep the long-term debt in US dollar. So we have, I think, for practical purposes, all our long-term debt in US dollar, and a significant part of our cash running expenses both on operations and on CapEx in US dollar. So we have to take it back, swap it back into US dollar. It's really this swap, it's not the fact that we hedge it. It's this swapping it back into US dollar which technically gives this volatility. But then when we actually pay this Norwegian krone, we get the Norwegian krone that we ask for and intend to hedge. So it's just an accounting thing that happens between creating the swap and the point in time where we actually take it back and use the Norwegian krone for paying tax and dividends.

Well actually that explains questions from both Jason Kenney, ING and Michele Della Vigna, Goldman Sachs, but there's another little add-on from Michele from Goldman Sachs. He says, can we expect a similar financial loss in the fourth quarter?

Well I tried to put a sentence about that into my presentation really to warn you. Yes, if you look at the long-term debt, that's quite mechanical, the relationship. We have a stable debt position and it's all US dollars, so you can just calculate that and it works in this quarter as assumed.

Then when it comes to the liquidity management, there is more risk to that. It has to do with the profile of the earnings and so on, when we do the exchanges and so on. So you cannot say exactly what is going to happen, but typically what you have seen, that has been in the same range as the effects on the long-term debt, maybe slightly higher. And that's also what happened this quarter, so that's what you can see if you look back into our numbers in previous quarters. So I think that's the best guidance we can give.

Thank you, I'll just take another one from the Internet before we give the word to Jon, and that is from Graydon Porter, Argus Group. Could you give us a decline rate for your Norwegian oil fields and your Norwegian gas fields please?

I think we have a good performance on the Norwegian Continental Shelf, the production has developed more or less exactly as we have planned. That means that we have fundamentally the same decline rate that we actually talked about back in January, of 4% on average between oil and gas. Then it's slightly higher on gas -- on oil, and typically slightly lower than 4% on oil. So that's what I can say, and I have no more specifics for you at this time.

Jon from UBS?

Hi, yes it's Jon Rigby from UBS. Two points of clarification on some questions that were brought up earlier, the first on the impairment charges. If it's swinging around, depending on prices, and we've seen a decline in prices, does that mean you originally impaired against the forward curve rather than a long-term view of prices? Because I can't believe your long-term view of prices was above where we are right now. That's the first question.

The second is when you come to look at the special element of any dividend you're going to pay, and you talked about 45% to 50% as your aspiration of a payout ratio, what year will be you looking at primarily when you're looking at that, let's say some time next year? Will you look back over 2008, or will you be looking at 2009, which presumably at current observation would be worse than 2008? Or will you look through and take some kind of view of where you see medium term oil prices trending? Thanks.

Okay. When it comes to impairments, what we do is to relate this to the market. We have our own assumptions and they could vary and as dynamic as the market is, what we typically do is to use the forward curve for the next five years automatically because we ask the market and they tell us and it's the best answer we can get. And then we have our own assumptions beyond the next five years which we then do a judgment on when something triggers the new judgment of those. So in these cases, it's the forward curve which has impacted the impairments mainly, mainly the forward curve.

When it comes to dividend, all I can say is that there are no specific years and what did you say, it's 45% to 50% over time? We have paid something like 51% since the IPO back in 2001 on average. So it's a demonstration that we actually have been able to honor this dividend policy and I think my main message is that, that is something we will continue to do.

I cannot promise any given year that could be things happen, special circumstances, so I cannot guarantee that in any given year, but long-term, that's the kind of level you should expect. And I think we have demonstrated our commitment to this.

Alright. John Olaisen from Carnegie has got two questions. One is about break-even cash flow after CapEx and I think you answered that already with $50 per barrel. The other one is how much is the remaining value of the Spinnaker acquisition?

To be honest, I don't have the answer because I haven't summarized it. It's a little bit all over the place in our accounts in the balance sheet, and it's not accounted for as one asset in our portfolio as such, it's all over the place. So I haven't got that number for you, but obviously it is much lower than it was at the time of the acquisition. I cannot say anything more than that.

More questions from the floor? There was one from Neill, yes.

Yes, it's Neill Morton again. At the start of the year, you talked about the reorganization of the NCS into different business units. Aside from Snohvit, since then you've had leaks at Oseberg you've had leaks at Statfjord, you probably made a mistake and continued to pump through the Kvitebjorn pipeline which caused a subsequent leak. You've had fairly damning safety reports from the authorities. Is this simply a function of your dominance on the NCS? Is it simply bad luck coincidence, or is it perhaps merger pains?

Well it's not merger things, because if you look at the underlying, and I've been through all of these reports in detail, and this has nothing to do with the merger, these are typical events that has caused this which goes a long back in time. And it's complex and it's a lot of causes which puts together and leads to this incident.

So I think the Statfjord incident was very unfortunate and we have definitely, I can assure you, a comprehensive program to make sure that we'll not do that kind of stuff again. But it's complex and it goes back in time and it has to do with being extremely cautious and understand the risks when you do operations out there. It's so complex and you have to understand that the whole organization down to the operations have to understand the risk picture. And it's also about complying with the procedures that we have in place to do this stuff. So -- both in terms of training, in terms of compliance, simplifying documentation and also understanding risk and doing risk assessments in a more efficient way, is part of the improvement program that we are embarking on to move on from these events.

Then I would like to mention that the Kvitebjorn has nothing to do with this, that does not come in the same category. The pipeline was brought out of its location and that was not done by us. And we had a very thorough calculation as to whether we should continue to operate it or not and we knew there was a risk and that hit us. But we knew it so therefore something calculated. We patrol it all the time so there was a very minor leakage. And in any case we couldn't have had it back in full operations by now because the repair system that we planned for didn't fail on some tests. So in any case we would have to spend more time on that.

So I think there isn't much I would have done differently on the Kvitebjorn pipeline as such.

We are actually a little bit on overtime according to the program but we will just allow this Q&A session to finish and then we'll go straight to the gas seminar. So if anybody's waiting out there on the Internet, you'll just have to give us five more minutes.

There's another question from Woodmack, Johnny Chalton. In January 2008 overall Norwegian production was revised down by some 10%. And I guess he's referring to the official NPD numbers. Do we expect further downward revisions for 2009/2010? And if so, by how much? And how much of this will be proportioned to StatoilHydro stakes?

And I think what I can show you is basically that when it comes to show the liquids production this quarter was at the same level and even higher. And even after an extensive turnaround program gas production was down. We have the Kvitebjorn field which is down. And fundamentally we are increasing our gas production on NCS. And then again I would just like to repeat our ambition to maintain the current level of production on the Norwegian Continental Shelf actually for quite a long time. So the numbers that you refer to, that is not something I think that you can apply directly to the spreadsheets for this Company.

Thank you. There's another question from the internet. We've seen a decreasing oil production in Norway at least in 2008. How are you going to maintain the production or even increase it?

Well there is a lot of measures and then I could start talking about all the operational improvements that we are now working on. I think one important I would have touched upon, improving the drilling efficiency and we have made good progress on that.

We are also working very systematically on the regularities issue and make sure that we actually produce as sufficiently as we can when the fields are in operation this quarter. We had big turnarounds which impacted the regularity that goes into that factor. But looking away from that we actually saw progress on regularity this quarter.

Then it's about extensive drilling and we have drilled something like 30 wells in the Norwegian Continental Shelf this year. We have 22 discoveries and some of that is discoveries which can be fast-tracked and really support our production also short-term. Some of that actually also gives us potential for new developments on a standalone basis. So I think it has been a very good exploration year for StatoilHydro so far this year. And so there is a whole range of measures which I think is supporting both the gas. And obviously not executing the whole development program that we are into on the new projects in our portfolio.

So I think we are attacking the whole range of measures that we can work on in order to at least maintain the current level of production on liquids as well.

Alright, this is the last question from the Internet here, Neil McMahon from Bernstein. He first asks about any color on paying out a special dividend in 2008 but I think you already said many times that we will maintain 45% to 50% of payout. So I'll just jump to the next one.

Please provide an update on whether you are renegotiating weak contracts given the fall in commodity prices and with the likelihood of a weakening oil service sector.

I think what I can say is that we are a big player in this market and we are following the situation closely. And we have an active relationship to all our contracts to put it that way. And to the extent that includes that kind of possibility as I am sure that we will be able to capitalize some benefit from that.

So we will follow the situation and I'll see what happens in this part of the market which typically tends to be the earliest part of the market, responding to changes in the activity levels out there.

Okay. Well I think we'll just end this Q&A session now. And just to give people a little bit of air here in London we will resume with the gas seminar 15 minutes late but at 2:45 London time. So seven minutes from now. Thank you.