Equinor ASA (EQNR) 2009 Q2 法說會逐字稿

Ladies and Gentlement welcome to the second quarter 2009 earnings presentation for StatoilHydro.

It takes place from our offices in Oslo.

My name's Lars Sorensen and I am the Head of Investor Relations.

This morning at 8am Central European Time, the material that we're going to go through in a minute was published on our website, and sent to wires and to the Oslo Stock Exchange.

The material can be downloaded from our website, statoilhydro.com.

I'll ask you please to take note of the forward looking statements on page 28 in the material, and read those carefully.

Today's event can be followed by webcast, and let me extend my welcome also to the webcast audience.

As you know, safety is of paramount importance to us, so let's just spend 30 seconds on your safety here in Oslo.

There are two exits at the back of the room, marked with green exit signs.

If the alarm goes, calmly walk out of those and downstairs, and out into the open on the left -- on my left hand side, and your right hand side, out there in the canteen.

There will be staff to tell you where to go and where to assemble.

Assembly point is just outside the building.

Today's presentation will be made by StatoilHydro's, Chief Financial Officer, Eldar Saetre.

And after the presentation there will be a Q&A session where you can, as usual, send in your questions via the Internet, or you can ask them from the floor here in Oslo.

If you want to send in questions via the Internet, use the submit question button on your screen and questions will be sent into my PC, and I'll read them aloud on your behalf.

Without any further ado, I'll just leave the words to our CFO, Eldar Saetre; Eldar please.

Well, thank you Lars.

Ladies and gentlemen thank you for joining us at this second quarter earning presentation.

Our results this quarter have been delivered in the middle of the deepest economic recession since the 1930s.

And although we now see some signs of optimism and recovery, we must remember that the uncertainty remains high and there are still some fundamental imbalances in the global economy, driven by a mainly unsustainable borrowing and spending, first in the private sector and now also, in the public sector, and these imbalances eventually have to be corrected.

Fundamentals for our industry have not changed materially during the second quarter as we see it.

And although we see some indications of an improved balance in the oil markets, we believe that a continued strong OPEC discipline, positive equity markets and sentiments, and also the latest weakening in the US dollar are the main drivers, the main contributors behind the recent rally in the oil price up to the current level.

And we believe that the oil price could, at short notice, return to lower levels unless the expectations to a tighter balance are confirmed through stronger fundamentals in the global -- and the global demand.

There is still a lot of inventories -- oil inventories, both at sea and on land and we therefore see good reasons to remain cautious in the short-term.

As a consequence of weak demand for refined products, and higher crude oil prices and, I would say, slow capacity and cost adjustments within this sector, the refining margins have weakened considerably.

And the short and medium-term outlook, as we see it, for refining seems rather gloomy, and this has also impacted our accounts, which I will come back to in a minute.

The gas market has experienced lower demand from -- mainly from the industrial sector, but also from power producers, which have been added to the typical seasonal pattern that we see in the second quarter.

But having said all this for the short and medium-term, we have not changed our long-term view -- fundamental view on the energy realities.

All the world global energy demand will continue to grow and the supply side, including oil and gas, will struggle to keep up the pace.

During the second quarter this year, we can look back at a quarter with strong deliveries, both when it comes to production, new capacity growth being added, exploration results, and also trading results.

We have seen several new fields come on stream, increasing our capacity during the third quarter and also during July, second quarter.

And our exploration activity is still high.

We have completed 48 wells during the first half of this year and 13 -- 30 of those have been successful, and we are still evaluating quite a number of those wells.

So let's now look at the financial results, the headlines, this quarter.

And this illustration gives you an overview of our key results compared to the second quarter and you can see on the bottom here last year.

And as you will see, our net income -- reported net income is very close to zero and this is due to an effective tax rate of 99.9%, while our reported net operating income is at NOK24.3 billion.

Then, however, and I would say not surprisingly, these numbers do not reflect our underlying results, nor our underlying tax rate.

And to provide you with useful analytical information, in addition to the IFRS numbers we have, therefore, introduced adjusted earnings, and adjusted earnings also after tax, as an additional way of presenting our numbers, both at Group level and at business segment level.

And the main difference between net income, as reported under IFRS, and adjusted earnings after tax, which is the phrase we use, is that we have adjusted for some infrequent items, which is not considered to reflect our underlying operations.

In addition to that, net financial items are not included in the adjusted earnings as these items are not considered an aggregate material when looking at the underlying factors.

To illustrate this last point, this quarter we had net negative financial items of NOK4.8 billion, NOK4 billion of those were due to a negative derivative -- non-cash derivative effect on interest rate, while NOK1.1 billion was due to an impairment of our 10% stake in the Pernis refinery, which is booked as the financial asset, and we shall revert to in a minute.

I should also mention that a full reconciliation of both reported -- between reported and adjusted numbers is given in our MD&A.

If we then look at our adjusted numbers, the earnings this quarter was NOK29.2 billion and that is a decrease of 48% compared to the same period last year.

The adjusted earning after tax fell from NOK16.7 billion to NOK9 billion this quarter, which is a 54% reduction.

And the reduction was mainly driven by the 40% reduction in liquids prices in Norwegian krone and an 18% reduction in gas prices, partly offset by higher income from our oil and gas trading activities.

We have seen good operational performance, as said through the quarter and our cost development is also kept under strict control, which I will come back to shortly.

But let us first look at the tax development and after that an overview of the adjustment that we have made to arrive at these adjusted earnings.

If we look at the adjusted earnings at the corporate level, tax cost is largely as expected at around -- well, actually slightly below, 70%.

The breakdown into individual segment taxes that you can see here is also largely as expected; however, slightly on the low side when it comes to the international E&P, and somewhat on the high side for manufacturing and market.

And there will typically be these kind of variances on a quarterly basis related to the composition of earnings as it is, and also changes in tax position.

So you will see these kind of variances, but on aggregate the 70% guidance is still valid.

So the question then is how do we get from a quite normal adjusted tax rate on adjusted earnings to 99% reported tax rate?

And there is basically two explanations to this.

As -- because we see a tax on net financial items of 35% is quite normal, so that's basically we are left with two explanations.

Firstly, we have the low 6%, as you can see, tax rate on the adjustment that we do, which is a net cost in this quarter.

And the reason for this low tax rate on the adjustment is that we have net impairment in the US with no tax protection, at least for accounting purposes, which is valid for accounting purposes.

And almost the same effect we see in Denmark related to an impairment of the Kalundborg refinery of NOK2.2 billion.

So this combined effect of -- from impairments, drives the tax rate on the adjustments down and the corporate tax rate up, as you see on this overview.

Secondly, we have a reported tax cost of NOK1.3 billion related to the NOK3.6 billion of non reported currency gains.

And we have informed about this in the Stock Exchange announcement on July 23.

And this NOK3.6 billion of currency gain is included in the basis for the tax cost, the tax calculation, as presented in the accounts, but not included in our IFRS accounts.

And this impact is due to the change in functional currency that we made from January 1 this year, and I will just refer to a more thorough explanation of this issue that you can find in connection with the reporting of the first quarter numbers for 2009.

So hopefully this gave you at least some assistance to understand what happened with the tax rate, and again you will find full explanation in the MD&A.

Then I will comment briefly on the adjustments that we make to arrive at the adjusted earnings.

We adjusted for a negative NOK4.9 billion this quarter, corresponding to a tax -- after tax number of NOK4.6 billion.

And the most important factors here are the impairments.

As seen in previous quarters we are into, what I would say is, the impairment elevator when it comes to some assets in Gulf of -- in the Gulf of Mexico portfolio.

And this quarter two assets have been further impaired, while one previous asset impairment has been reversed and this adds to a net negative impairment of NOK1.4 billion.

And the other major impairment I've already mentioned is related to the Kalundborg refinery in Denmark.

Our more pessimistic outlook for refinery margins is mainly driven by the low demand for refined products and an expected slow recovery from the current global economic situation.

We believe it will take time to implement sufficient capacity adjustments, structural adjustments and also cost adjustments in the industry and have, therefore, reduced the book value of this refinery with NOK2.2 billion.

The value of the Mongstad refinery has also been reduced as such, but has so far not triggered any impairment.

In addition to the impairments we have also adjusted for some negative derivative effects, mainly stemming from deferred gains on inventories within our oil trading and also the earnings consequences of an underlift of 49,000 barrels per day during this quarter.

So let me then also comment on the production volumes before I move on to a summary of the adjusted earnings.

There it is.

It's the wrong sequence here.

Total equity production of oil and gas was 1.845 million barrels per day of oil equivalent, which is down 3%.

Entitlement production was up 1% to 1.729 million barrels per day, driven mainly by an impressive 41% growth within the international segment, outside of Norwegian Continental Shelf.

And this implies PSA effects of 116,000 barrels per day in the second quarter and 128,000 barrels per day on a year-to-date basis, which is slightly lower than we have guided earlier and this is partly due to one-off effects adjustments that have been made in this quarter.

Our best estimate now is that you should expect PSA effect of around 130,000 barrels per day, at an average oil price of around $50 for the full year.

And this is compared to 140,000 barrels, which we have guided you earlier at the same oil price assumption.

The total production this quarter was obviously heavily impacted by maintenance activities of around 55,000 barrels per day compared with 44,000 barrels per day in the same quarter last year.

In addition to the normal decline, which is obviously there, we have also had some temporary capacity issues on Kvitebjorn -- mainly Kvitebjorn and Kristin fields.

Seasonal gas off-take is also typically lower in the second quarter.

And in addition, some gas volumes have been deferred beyond 2009.

New fields like Agbami in Nigeria and Saxi-Batuque in Angola have added significant new production volumes compared to the same quarter last year.

The volume from other new fields like Tahiti and Gimboa, outside of Norway, were however quite insignificant in the quarter as they came in late in the quarter.

And these fields will, together with the new start-ups in July, Tyrihans and Tune South and Thunder Hawk in the Gulf of Mexico, all came in in July, will increase our production capacity further when moving into the second half of this year.

So our production guidance of 1.950 million barrels of oil equivalent per day, equity barrels, is therefore maintained for the full year.

And now to the adjusted earnings; our operational performance has been good in the quarter.

Maintenance activities have so far been done according to plan.

New capacity has also been delivered, as planned, or even slightly ahead of schedule and we have not had any major incidents impacting our operations negatively.

Our overall trading business has been strong also during this quarter.

E&P Norway reached adjusted earnings of almost NOK21 billion this quarter, which is 56% lower than last year.

The main driver is the 41% lower liquids price in Norwegian krone and a 24% lower transfer price of natural gas.

In this quarter we have also seen a lower liquids price realization, compared to average Brent, than we typically see for NCS volumes.

We had large turnarounds, as mentioned, for this quarter; mainly in the latter part of the period.

And hence, we had high production at the low oil prices in the beginning of the period and lower production when the prices started to increase in June.

So that is part of the explanation.

And at the same time, and mostly actually because of the turnaround the content of NGL in the NCS liquids production was 18% in this quarter.

And that is higher than we typically see because of the turnarounds and the typical pattern is between 10% and 15%; so this quarter 18%.

And the market for LNG (sic) was also weak in the quarter and, hence, the prices were relatively low.

Oil and gas production on the Norwegian Continental Shelf is down 6%, which I have already discussed.

Overall cost developments in E&P Norway have been good and, as expected, partly also reflecting the high level of maintenance activity during the quarter.

International E&P had an adjusted earning of NOK2.8 billion, which is down 53% compared to last year and the main cause is the lower liquids price of 40% measured in Norwegian krone.

Equity production increased by 9% to almost 500,000 barrels per day, while total entitlement volumes increased by an impressive 41% to 386,000 barrels per day.

Depreciation charges increased by approximately NOK2 billion, mainly because of the increase in production, but also because of currency impact, the stronger US dollar versus Norwegian krone of almost 30% from -- on a quarter-to-quarter basis.

Operating cost in US dollar is largely unchanged, even though equity production has increased.

Operating cost in Norwegian krone has increased by 30%, which again is driven by the currency impacts.

SG&A cost was reduced by approximately one-third due to the ongoing cost reduction programs.

Natural Gas increased their adjusted earnings by -- from NOK1.9 billion last year to NOK4.2 billion this quarter.

Processing and Transport, that part of the segment, was NOK1.8 billion, which is at the same level as last year, which it should be; while Marketing and Trading increased their earnings by NOK2.3 billion to NOK2.4 billion, mainly stemming from stronger trading activities.

Manufacturing and Marketing, finally, delivered an adjusted earnings of NOK1.4 billion, which is slightly up compared to NOK1.2 billion last year.

Continued strong oil and products trading results and slightly improved earnings also within Retail was partly offset by a loss within Manufacturing.

As mentioned, Manufacturing continued to show a negative trend with weakening refinery margins.

This is reflected in a loss of NOK0.5 billion, NOK500 million, this quarter.

As already mentioned, the continued negative outlook for refinery margins has also led to impairment of two refineries, oil refinery positions; the Kalundborg refinery in Denmark of NOK2.2 billion and the Pernis 10% stake in the Pernis refinery of NOK1.1 billion.

And Pernis is accounted for not under this segment reporting, but at the financial investment at Group level.

Then I would like to give a few comments to our ongoing efforts to increase efficiency, reduce costs.

As already mentioned, we are continuing to attack the cost base throughout the organization.

In this context, I should also mention -- remind you that the merger and the realization of merger synergies actually gave us an opportunity to start the downsizing and start the cost reduction process slightly ahead, actually, of the current downturn.

As mentioned at our site visit, for those of you that were there at Melkoya in June, we have now increased our estimate for merger synergies from NOK6 billion to NOK7 billion net to StatoilHydro; and that means approximately they double if you look at this in gross terms.

In addition to the merger synergies, we have identified an additional NOK1.5 billion in annual savings during 2009, as set out at our Capital Markets update in January, and these savings are mainly within the SG&A area.

And we have now implemented basically all measures to realize these savings and you can already see visible evidence of these savings in the numbers this quarter.

We are now in the process of firming up the next phase of our cost savings program that will be targeted during 2010 and this adds up to a further NOK1 billion to NOK1.5 billion annually, and is broadly within the same cost categories that we have addressed during 2009.

And, finally, we will continue to high-grade our exploration portfolio moving into 2010, both on the Norwegian Continental Shelf and internationally.

A few comments also to our strong, I would say, cash-flow generation in the first half of 2009.

Even at significantly lower oil and gas prices, with an average liquids price of around $48 per barrel year-to-date, we have generated a strong NOK84 billion from our operations in cash.

And taxes paid amounted to almost NOK50 billion, which is to some extent actually also reflects taxes paid in relation to higher earnings that we made in 2008.

We spent NOK39 billion in CapEx in the first half and are on track to meet our CapEx guidance of NOK13.5 billion for 2009.

So altogether, this development supports our earlier statements on cash flow neutrality this year at around $55 per barrel before dividend.

Our net debt to capital ratio is at around 28% at the end of this quarter, having now paid the full dividend for 2008, and we expect this ratio to stay in this range, around this number, assuming an oil price level of around $70-ish per barrel.

Then I will conclude my presentation with a guiding summary and the short version is that there is no changes to our 2009 guiding.

Our expected equity production is still the same, at 1.950 million barrels per day; and this is, I would say, supported by another quarter with strong performance, strong delivery, strong production and increased -- and the increased capacity that I've already mentioned.

We maintain our CapEx guidance of $13.5 billion.

Exploration activity results have been good and we expect to complete around 70 wells at a cost of approximately $2.7 billion.

And, finally, there is no change to our guided unit production cost, which is expected to stay at the upper -- in the upper part of the range of NOK33 to NOK36 per barrel for this year.

Next quarter we expect a planned maintenance activity with a quarterly impact of around 55,000 to 60,000 barrels per day.

And the maintenance impact for the full year is still estimated to be approximately 30,000 barrels per day.

This includes both the Norwegian Continental Shelf and the international activities.

I should also remind you that seasonal gas off-take is, like for the second quarter, is typically low also for the third quarter.

So this concludes my presentation and I then leave the word back to Lars for the Q&A session.

Thank you Eldar.

We'll now start the Q&A session.

And, as I mentioned before we start the presentation, it's possible to send in questions from the Internet if you press the submit question button on your screen and I'll get the questions in here on my screen.

To answer questions now, together with Eldar Saetre is the Head of Corporate Accounting, Mr.

Kaare Thomsen, as well as myself.

So we'll take the first question from the floor here and then we'll take some from the Internet and John Olaisen is already marked, so could you please wait for the microphone and state your name and company please.

This is John Olaisen from Carnegie; a question regarding the cash break-even assumption of $55, or estimate of $55.

What gas price do you assume into that?

It's -- I can't give you an average sort of firm gas price.

It's -- you know we have a significant part of our gas volumes tied in to long-term contracts, which again is tied into oil and oil related products mainly and there is typically a six month delay in the pricing relating to oil.

So we have -- what I can say is that we have calculated this to the best of our knowledge the month from last year that we know and taken -- sort of based this on reasonable assumptions on the gas markets for this year.

So that's one of the uncertainties, so I would say an equivalent sort of gas to oil price to $55 per barrel.

Thank you.

And then to the expected increased production in the second half, you mentioned two fields in Norway which will contribute to production goals, Tune South and Tyrihans and two internationally, Tahiti and Thunder Hawk.

Are there any other fields which are about to start up who will -- which will contribute to the second half production?

Not significant.

There are smaller projects on the Norwegian Continental Shelf.

But of the new fields I think that Tyrihans is, obviously -- Tyrihans is the biggest new field being launched for production since the Ormen Lange, Snohvit.

So it's a significant contributor for us, mainly oil, but also some gas of almost 600,000 barrels per day at full capacity.

Tune South is slightly smaller, it's a gas development linked to Oseberg.

Internationally it's Thunder Hawk, it's Tahiti and it's also Gimboa, which is sort of test producing now, but we expect a ramp up during the second half of this year.

So, basically, that is the new capacity for this year.

Next year we will see new developments in -- on our Norwegian Continental Shelf, the Gja, the Morvin mainly oil developments and also Vega, which is basically gas field.

And internationally, we'll see the Leismer, the Peregrino come into production.

My final question is related to the gas sales going forward.

As most of your gas volume is contracted with a price linked to oil basically, with a six-month lag, your clients know that the gas price will be rather low in Q3 and then as the oil price has jumped up now in the spring and the summer, the gas price will be much higher in Q4 and Q1.

Could that have a positive effect on gas sales in Q3?

Or any chance they would impact gas off-take?

I will not speculate on sort of how the behavior pattern will be on our customers.

So, basically there are two markets here.

It's still -- it's sort of the long-term customers, which have -- it's related to our long-term gas contracts and then it's the spot market.

And, particularly, when it comes to the spot market it's very hard to see how that is going to develop.

There's a lot of uncertainty on that issue going forward, particularly on the supply side short-term.

On the long-term contracts it's depending very much on sort of how the customers look at the situation and -- but, typically sort of they take lower demand in the third quarter, for seasonal reasons and then there could be other commercial reasons why they sort of will take higher volumes.

Thank you.

Okay.

I'll take a question from the Internet, while we wait for more questions here from Oslo.

It's a question from Anne Gjoen from Handelsbanken.

There are two questions actually, one on PSAs and one on tax.

The first one is the effect of 116,000 barrels per day in PSA effect is much lower than assumed and lower than the guiding.

Why is that?

And the second question is will you give a new guidance on the PSA effect going forward?

And then the tax question; why is tax on natural gas adjusted EBIT almost 80% and on international E&P as low as 25%.

Can you give us any guidance on the tax rate going forward?

Okay on the PSA effect, I think I addressed that in my presentation actually, indicating that the main reason -- I say the main reason, for the low PSA effect this quarter is an adjustment on certain fields from previous year, from 2008.

And that is a one-off and should not be expected to be maintained, but there are also other impacts.

So we have added all this together and our best guidance is now 130,000 barrels per day for -- at a $50 oil price and we have also given, previously some guidance on $75 and $100 per barrel and you could take down those guidances also by approximately the same number for this year.

On the taxes, I think maybe you, Kaare, would like to give some comment to that.

Can do so.

The NG tax rate, at around 80% is a little bit high, as you say, compared to previous quarters.

It could fluctuate from quarter to quarter as it has done now.

And we keep the guidance we have given earlier for NG is around 75%; and 75% plus/minus it would probably be for quarters to come as well.

The tax rate for the international is low 25% and that -- the guidance we have given earlier there is around 40%, and I would still remain that guidance.

It's a little bit influenced on low oil prices.

We'll take it down where there are uplifts, but this quarter it's influenced by the weakening in the US dollar.

Some of you may recall in the latter part of 2008, in the fourth quarter, we had the very high tax rate in the international part, because of the rise -- the increase or the strengthening of the US dollar.

Now we get the opposite effect of the weakening of the US dollar.

As some of the -- as our companies are having functional currency US dollar, and the tax in Norwegian krone, and it has to have the value of the assets.

And we get those effects in quarters where the Norwegian krone is strengthening from the US dollar.

Okay, that's another question from the Internet, from Teodor Sveen Nilsen from Argo Securities.

It's on CapEx.

Several other E&P companies have guided CapEx down, particularly due to lower supply costs.

You repeat the CapEx guidance.

Can this be interpreted as you will increase activity level then?

I think when we gave the guidance for our CapEx level for this year, I'm going back to January this year, we had experienced quite some time with turmoil, lower oil prices.

And it was based on a fresh planning process, where we had incorporated all the assumptions in relation to our portfolio, which asset to develop, which asset to continue developing and also what could be expected recently from cost savings.

Short-term -- very short-term in this industry there is very little flexibility that you actually can.

You are into projects, and the flexibility becomes more visible when you move into next year and the year after that.

But short-term there is very little flexibility.

We've used the flexibility that we had, and we have also been quite aggressive on cost targets and on cost developments, and addressing the supplier industry.

And I think the guidance that we have given is reflecting the current plans and the cost savings that we can realistically expect from suppliers into our cost base for this year.

Therefore, there is no reason not to maintain for 2009 -- the guidance of NOK13.5 billion.

Okay, another question from Teodor Sveen Nilsen from Argo on the financial items.

What kind of financial derivative instrument is the financial loss of NOK3.4 billion related to?

Is the loss related to a market -- a mark to market effect, or what is it -- NOK3.4 billion loss, financial items?

Well, you might recall it's NOK4 billion and it's a non cash loss.

It's related to the -- you remember we have all our debt in US dollar bonds -- US dollar bonds, so are swapped into US dollar.

Long-term the US dollar interest rate has increased.

So this swap from fixed to floating interest rate has been revalued and led to a loss -- accounting loss for our whole portfolio of approximately $4 billion -- NOK4 billion, and that's what expense it.

And as well, it is a consequence when you have -- we have floating, and mainly floating financing, and long-term interest is moving we will get this kind of volatility.

Okay, we can talk a little bit more about the financial items.

Iain Reid, he's got a question.

Given the much clearer divisional clean earnings presentation, would it not be a good idea now to strip out specials, FX and write-downs from the net financial items?

I think that could be a good idea, but so far we don't fully support it.

I tried to indicate in my presentation that for all practical purposes, if you take out these items today, if you add together our normal interest cost that we have on our debt, and if you add normal interest revenues on our liquidity, and you add reasonable returns on our securities and our asset management you get practically to zero.

So if there is big differences beyond that the current -- for the time being, it has to do typically with other components, such as derivatives and financial instruments, and all sort of -- in this case also, the impairment of the Pernis refinery, which is defined as a financial investment.

So we have found it's reasonable at this stage to report in this way, because we feel that is reflecting the underlying activities and results in a good way.

But that could change.

But for the time being we feel it's a good reflection.

There's a little bit of a follow-up question to this, and then I'll leave the microphone to you, Gudmund.

It's from Colin Smith at ICAP.

He says is it reasonable to ignore the negative gains or losses on derivative financial instruments of NOK3.4 billion and the Pernis impairment?

Why would one not also strip out the positive derivative gain in net FX, which is plus NOK2.4 billion, and the positive gain loss on financial investments, which is NOK0.9 billion, when considering clean net financial items?

Well as I said, it's -- we are not ignoring anything, we are reporting everything.

So you'll find all the numbers, but for -- as we see it today, if we actually ignore all these elements, you are back to something which is not material, the net of the financial items.

Ignoring all these items, to put it that way, actually takes us to pretty much around something which is around zero, and we feel that this is a reasonable way of presenting the numbers.

And as I said, if and when things change we will definitely consider to do more of a normalization practice, to put it that way, on the financials.

But for the time being, we give you all the information so you can sort of do that kind of adjustment yourself.

And then to Gudmund?

Gudmund Halle Isfeldt with DnB NOR markets; a question regarding the cost base international or even unit costs.

Do you see the lower cost trickle through the value chain, due to you having a lot of international partners that are large and that are also cutting aggressively costs?

Well, I think the whole industry is addressing the cost issue and the operating cost issue and the supply cost issue in the same way.

So what I can say is on the SG&A this is quite significant cost reductions that we see.

We have reduced, office costs and administrative costs, and business development costs, quite significantly, throughout our business, streamlining this and it's very visible in the numbers.

And on operating costs, it's -- as I said, it's mainly now due to the currency impacts.

And so basically there has been no new fields, which in this quarter, has sort of had any -- made any step ups in the cost.

And as you know, we are sort of expensing costs also in the preparation phase of the operations, and we start doing that only from the start of production.

So yes, it's reflecting cost savings also from sort of our partners.

We'll take a question from the Internet, from Endre Storlokken at Danske Bank.

You reported low depreciation charge on a per barrel basis, in the E&P International in second quarter '09, especially relative to first quarter '09.

Is the second quarter '09 level one which can be expected to be maintained into 2010, or should we expect further increase as production rise and new fields are brought on-stream?

It's very hard for me to sort of give a specific guidance on that.

I think it's depending very much on which specific new fields, the costs levels or new capacity coming in, and also the booking profile.

And I would say the booking profile that we might do for next year, at the end of this year, is going to be very much of determining the depreciation that we will do, per barrel, on -- particularly on the new field developments.

So I'm not prepared to give -- to confirm or say that this level is sustainable going into 2010.

But what I can say is that it is new capacity, and may -- and also 30% currency impact has also a significant impact on the depreciation increase from the last quarter.

We stay in the international area, that's a question from James Hubbard at Morgan Stanley on -- that's on risk to volume guidance.

What's the impact in second quarter from the OPEC quotas?

And if you knew that OPEC quotas would remain unchanged for the remainder of the year, would you maintain today's volume guidance?

Well, the impact on -- from OPEC, was around -- the quota was around 2,000; very low, 2,000 barrels per day, in the second quarter.

It was higher, around 13,000 I think, in the first quarter.

When it comes to the impact in relation to production guidance, it has no impact, because we have stated quite clearly, as we did in January, that the guidance of 1,950 is excluding any impact from OPEC.

It's impossible for us to guide on OPEC cuts and what that could lead us to.

So we are focused on the performance that we can deliver and that is pre any OPEC impacts.

Okay, there's another question from the Internet.

It's from Lucy Haskins at Barcap -- Barclays Capital.

Has your view on the NCS decline rate moved?

Do you feel more or less optimistic about your long run aspiration to keep NCS volumes flat?

Yes, that was the question.

I'll take the other one later.

Well, first of all, when it comes to the production development as such this quarter and what we can see from that it's more or less exactly as expected.

There's no surprise there.

We see a decline, particularly on the liquids part.

It has to do with the timing of new capacity, and we did not see any significant new capacity at all compared to the last quarter -- same quarter last year.

But now new capacity is coming in on liquids, also mainly -- mainly from Tyrihans field.

So it's a maintenance issue, some operational issues and their natural decline as expected.

Talking about sort of what we can say about the future, first of all, on the decline rate as such we see no change in the guidance, we have not learned any new lessons this quarter, or changed our view on that 5% decline rate.

Then we have made a lot of discoveries, and we talked a lot about that at Melkoya, at the site visit, went through lots of these discoveries, which has strengthened our view in the -- on the medium-term outlook for the Norwegian Continental Shelf.

We have built a lot of knowledge and understood -- and understanding the geology, and have improved our sort of success rate on exploration, and also moved beyond only the small discoveries into what, I would say, is medium sized discoveries.

So it's quite good news on that, and some of this can be developed, quite fast track.

Other of these discoveries will need more standalone developments, and will take longer time.

So I would say medium-term it has strengthened, definitely, our outlook.

But we still have the same perspective, 10 year horizon, of the current production level on the Norwegian Continental Shelf.

And moving beyond the 10 year perspective, I think we are still talking about new acreage opportunities to sort of approach new exploration opportunities.

Lucy continues in that to that extent -- actually with a little bit with exploration as well.

So let's take that before we take Gudmund.

What is the balance in your recent exploration success of small, tie backs, relative to big new provinces?

And what is pace at which these discoveries can be translated into barrels of production?

Well, as I said, the reason it's related back -- it has an accumulated learning, basically, and new technology as well, which gives us these result.

So hopefully we'll continue that trend and do more discoveries based on these kind of learnings.

But eventually we will run out of options.

Basically we will now -- we have now put all these into the bank and we are running a prioritization process on these developments.

Some of them need more exploration drilling to be confirmed, or to determine more sort of the scale and the volume that we are talking about.

So I cannot give you any -- typically the developments which are very close to existing infrastructure will have a more -- a faster track development than the standalone.

But on some areas, for instance, on the -- in the Voring Basin, around the Luva -- in the Luva area, and also in the Sleipner area, we need some time to firm up the development solution, and particularly for the Norwegian Sea, we also need to discuss the final way of transporting the gas volumes out of that area.

Gudmund?

Are you prepared to share with us the exploration volume, the resource -- on the resource level that you have found in first half of this year?

It's just to try and find out approximately where you could be next year on the Capital Markets Day, when it comes to reserve replacements.

I think we gave you -- I think we'll wait until we have concluded the year.

But the processes around this, where we sort of need quality control and need to firm up that it's actually commercial volumes that they're talking about.

So to report this on a continuous basis, it doesn't give us the level of comfort that we would like to have.

So I think it's something that is more sort of you should expect at an annual setting, and I'll just repeat the 800 million that we added through this exploration last year.

And so far it looks very promising, I could say that.

Okay, there's a question from Paul Spedding at HSBC, or two questions rather.

First one is could you update us on your cash flow breakeven price?

At the Capital Markets Day it was $55 per barrel.

I showed you in the presentation, a cash flow chart, which basically said that we were more or less neutral so far this year.

If you adjust for the fact that we pay slightly more taxes than the payable tax for this year, I would say we are quite neutral, at an gas -- at oil price or average oil price year to date at around $48 per barrel.

Then obviously gas price, trading business, the oil trading, gas trading, gas prices, it has an impact.

It has been quite strong in this quarter.

So I would say overall, the guidance of $55 is still valid and it's supported by the numbers that we have seen so far this year.

The second question from Paul Spedding is given the risk in -- given the rise -- sorry, given the rise in gearing you've seen so far this year, have you begun to defer any of the flexible CapEx you indicated at the Capital Markets Day, which is around 35% of the 2010 CapEx on non sanctioned project at that time.

We are now in the process of firming up the activities for next year and also following years, based on the financial situation and the outlook as we see it, and the financial -- and the balance sheet as we see it.

I would say the balance sheet, the way it looks now, is not surprising at all.

It's exactly as it should be.

We have paid the dividend.

We take the new loans.

We have paid dividends, we've paid taxes.

So we are on track.

And I would say the -- of course, we gave you some guidance on the -- how we should look at this number going forward for the rest of this year.

And I think that is quite consistent with the $55 guidance that we maintain also on cash flow neutrality.

So basically we are -- that number doesn't give any additional new cost to look at the numbers and the planning process that we are deeply into now.

I'll just take a question here from the Internet, and then Arnstein.

It's Colin Smith from ICAP, that asks what level do you think the net debt to capital ratio would risk your A credit rating?

Well, definitely not the level that we see today.

Then I would say it's a lot of factors, which goes -- and you should ask the rating agency, but there is a lot of factors which goes into the evaluation that they typically would do, debt ratio is one of them.

But I would say cash flow is also definitely one of them, and maybe asset (inaudible) and cash flow, in relation to sort of the debt levels, is important to reserve developments and so on, but there is a lot of factors which goes into that.

And so beyond that I have no further comment, other than we are very comfortable with the current level.

Arnstein first, and then John?

Thank you.

Yes, just a question regarding dividend.

Should we expect the very, very weak reported net income for the second quarter to affect dividend for 2009 in any particular way?

Well, I think I should give a refresher here on the dividend policy.

It has a few statements, and that they're all valid -- still valid.

First of all the starting point is still the IFRS; has not changed, we haven't changed the dividend policy.

So that is the starting point.

45-50% of that, over time, not in any given year, but over time.

That's important.

The second one is that we also say that we will seek the increase the ordinary dividend, that's still valid, we will seek to do that.

And the third kind of statements, which you will find in the policy, is that we will also take into consideration other factors, such as cash flow, outlooks and so on.

And we will do that.

We have done so.

I think we have showed that.

Since 2006, we have a had payout ratio of over 50%, 53% to 63%, I think was the maximum, over the last three years, and 52% since the IPO back in 2001.

So we have demonstrated that.

So we will -- the starting point is the IFRS, and then we will take these other things into consideration, the ordinary dividend commitment and also the cash flow issues.

And that includes these issues that we've just talked about.

They will be taken into consideration, the fair valuation issues, the impairment, the derivative issues, and also the tax issue, which has been introduced now through new -- the new functional currency practice that we have introduced.

So all these elements will be put together into an holistic evaluation, but let me repeat, the starting point is still the IFRS as such.

Then it was John.

It's John Olaisen from Carnegie again.

Just house-holding question regarding the CapEx.

The acquisition of South Riding Point's, crude oil storage and trans shipment terminal, does that come on top of $13.5 billion?

Yes.

So I think we will just repeat it.

It's a good question, just reminded me that this is an organic number, it's not -- does not include any acquisitions that we might do, and this is basically just on top of that.

Thank you.

Got a couple of questions from the Internet.

It's from James Hubbard at Morgan Stanley.

The Pernis write-down, given the weak start to third quarter refining margins, will you need to take further write-downs either at Pernis or Mongstad?

Well, that's a good question, and I can't say yes or no.

It's an evaluation that we will have to -- as you know, as you have seen now, we are on the edge.

We have done write-downs on two oil refineries.

The Mongstad refinery is getting closer to an impairment, it's not triggered an impairment as such, but it's getting sort of closer, put it that way.

But this means also that when it comes to the Pernis, we are -- it's a financial asset, so in effect we will have to do a quarterly evaluation in any case, and so it has been going up and down actually for a long time and it will continue to do so.

So basically, with the current outlook it could move.

It could become worse.

But that's something -- I'll just say it's quarterly judgment that we do, and I cannot rule out that it might happen.

Got a couple of questions on the trading, both in M&M and natural gas.

The first one is from Aymeric de Villaret at Societe Generale in Paris.

Can you elaborate on trading profits, both in Marketing & Manufacturing, and in Natural Gas?

Both seem quite high in the second quarter.

Can we have a guidance for the next quarters?

Or can we expect, depending mainly for Marketing as forward prices continue to be higher than spot market prices?

Okay, I'll discuss first the oil side.

I'd say we have -- here is one situation that we have had out there for quite some time now; the contango market situation, which had been more visible, but it's still there.

So I would say that the storage strategy that we have derived from that situation.

And it's also the situation not only on crude, but also on products, has been the main driver behind these results, but are also other components, for instance arbitrage, gasoline; moving gasoline from the European market into US and so on has increased the revenues.

So we are doing, I would say, more sophisticated trading business.

And I think we can sort of continue to deliver good results on trading.

But it is trading and, as I said, the main situation on Contango has been the main driver, but -- and in a different situation you should not expect this -- that kind of earnings.

But still, I think we have got a good trading business on the oil and products side.

On the gas side, it's been quite consistent over some time now that we have delivered good results.

And again, I would say it's gradually developing and improving the quality of this business.

We are integrating; it's very much an arbitrage business, not very speculative.

It's arbitrage, moving volumes between the different markets.

And it's -- we are also integrating very much our long-term business with our short-term business, and that also has created sort of a better overview of our total volumes than -- and I'm basically talk about an integrated -- fully integrated sales and trading activity on the gas side.

So again, about sustainability; this is about trading and I can promise nothing.

We will see volatility on the trading results, also on the gas side.

And basically, I think this quarter has been a good one, as such.

That's a general comment.

And that was one question from Iain Reid at Macquarie that -- to elaborate a bit on the gas market area, which you just did.

But the second question he has -- Iain, is the realized oil and liquid price is weak.

Is this a result of low NGL prices?

And what do you expect from the NGL market for the rest of the year?

Also, what proportion of liquid volumes is NGL at present?

Well, I presented -- I gave you the second quarter number, which was 18% higher than what is typical.

It's mainly -- it's NGL.

But it also has to do with the skewed, say, production profile, due to the turnarounds and the maintenance season, which mainly started in June.

So I would say that's also add quite significant actually to the discount that we have seen this quarter on the oil price.

When it comes to the sustainability of NGL, it's -- that's very difficult to be very firm about.

It's actually quite a different market.

NGL, this is basically naphta and LPG and naphta goes into the petrochemical, which is the sector mainly also refinery petrochemical, which is driven mainly by industrial demand.

And it's very hard to say sort of how the recovery and how that's going to look going forward.

LPG is mainly into heating.

In the summer season there is low demand for that.

So it's coincidental with the summer season on heating is driving LPG demand.

So it's a totally different market than crude, but very hard to see -- to be very specific as to sort of how this relationship is going to look.

But typically we have some of the same situation in the -- actually in the same quarter last year, when we also had a quite big discount, compared to Brent.

Okay.

Barry MacCarthy from Royal Bank of Scotland, or ABN Royal Bank of Scotland, has a question about refining assets; back to what we talked about a minute ago.

Are you considering disposals for your international refining assets, given your bearish outlook?

I think our main issue is to run the refineries as efficiently as possible, to do necessary adjustments as such.

And to the extent, we had any such plans, I would not talk about it to put it that way.

So it's -- but there is basically no -- I can't give any sort of comment.

I would in principle not give any comment to that.

So I would say our main focus is to improve the efficiency, continue improve efficiency, take down costs, which is the first immediate response when you have lower margins.

And that's what we're trying to do.

And increase the turnout or the overall efficiency, also in terms of product yield on the refinery.

Arnstein has a question?

Yes.

Two actually.

It has to do with relatively soft natural gas markets in the US and in Europe particularly.

Does it impact your marketing strategy for Snohvit LNG?

And in what -- that's the first one.

The second one, is the current situation in the natural gas markets affecting developments on Shtokman?

Okay.

Well, when it comes to typically LNG, it's a big investment and -- upfront investment and that kind of facilities typically are being run at full capacity whenever capacity is available.

Now, we have a planned maintenance process on Snohvit for approximately 80 days, starting in the middle of August and that will be carried out as planned.

And then, we will produce as much LNG as possible.

Where the LNG is moving is depending very much on the markets and so on.

So we have commitments to the Spanish market, but whether the rest goes to the US or other markets, that's depending very much on how we look at the markets at any time.

So, that's my general comment to Snohvit.

When it comes to Shtokman, that's a long term project.

So, you're far beyond 2010 before you see any volumes from Snohvit (sic).

So I think a project of that nature -- long-term nature, really have to have a very strong, long-term fundamental view on gas, which is guiding you on the investment decisions.

Sorry, I just had to log on again.

I just got logged off.

Well, I'll take a question from MF Global, Neill Morton.

There have been conflicting comments recently about the sale of gas from Shah Deniz Phase 2.

Russia claimed to have bought the gas but the Azeris seem to have denied this.

Could you clarify how the marketing of Phase 2 from Shah Deniz works?

Is BP -- are the BP Statoil -- is BP Statoil still in charge as co-marketers?

Or does SOCAR have the final say?

Well, this is a consortium, so there are several partners which have a say in the gas -- in the marketing of the gas.

StatoilHydro is the operator for the commercial activities on Shah Deniz.

And then, there is no gas sold.

Not a single cubic meter has been sold related to the Phase 2 of this development.

That was a similar question from Jason Kenney at ING.

So let's take a question from Gudmund now.

Just a question on Kharyaga, where Russian interests are going to get 20% of this field.

And I was just wondering if this is interconnected with Shtokman in any way?

And how does this change -- possibly change your view on operating in Russia?

This is a totally separate issue from the Shtokman.

It's -- this is part -- the fact that the Russian company were supposed to enter into this field with 20%, had been part of the agreement -- part of the production sharing agreement all the time.

So this is nothing new for us.

It's supposed to happen and now we are with the operator Total in the process of discussing the commercial terms around this.

So I would say it's a totally different situation and has no -- as we see it today, has no relevance to the Shtokman issue.

There seems to be a number of questions around PSA effect for the rest of the year and so on.

I think I can just answer those questions by saying that we've guided 130,000 barrels per day.

Eldar said that in his presentation and we stick to that, going forward.

So 130,000 --

At $50.

At $50, yes.

And then, you can basically use the sensitivity that you already got from us to model that going forward, based on different oil prices.

We haven't got an update on 70 and 100 and so on, which people seem to ask for.

But we haven't got that.

So use the sensitivities that you already got, and that will give you a fair indication.

Okay.

Another question from Jason Kenney of ING; he asks about the Norwegian Sea and the Gro discovery.

What kind of development scenario is envisaged and when?

Well, it's far too early to say.

Gro discovery is -- well, it's a discovery.

What we can say about it, it's a challenging issue.

It's not an easy reservoir to address.

And there is a lot of uncertainty as to what could be the volumes from this discovery.

So, I think we still need a lot of work to firm up -- take a firm view on what is there and how it can be developed.

But like for the Luva area, this is a new area that would need a transportation solution to export the gas from the region.

There's a question from Geoffroy Stern at Cheuvreux in Paris.

It's about dividend policy again, so I think we need to repeat what we already said.

The dividend policy; do you plan to base your targeted payout ratio on adjusted net earnings?

If I were to comment this, I would say exactly what I said earlier.

So no, there is no new policy which replaces the adjusted earnings with IFRS net income.

The starting point is net income.

Then we have additional issues that we will take into consideration; first of all, the commitment to the ordinary dividend, which we have stated, to grow that hopefully.

And then also that we will take into consideration these non-cash components, which is influencing the reported numbers this quarter, and also the tax issue related to the change in functional currency.

So we will take that into consideration, which is also a reasonable thing to do in relation to our stated dividend policy.

And again, refer to our -- the practice that we have had, which gives confidence in this respect and to this practice.

There's a question from Michele Della Vigna.

Then we'll take one from Gudmund.

Michele Della Vigna at Goldman Sachs asks one question about OPEC volumes.

But I think you've already answered that earlier on.

The second question is, how much production do you expect the major new start ups in Q2, Tahiti and Thunder Hawk, Tyrihans and Gimboa, to add in the third quarter and the fourth quarter?

Could you give us an update on Peregrino, and what is the current percentage of completion of that project in Brazil?

Well, to do the Peregrino first; there's basically no update.

The progress is as planned and it's still production starts on Peregrino towards the very end of 2010 or very early 2011; so in that range.

So there's new information on the Peregrino.

And the first question was again, remind me on --?

It was how much production do you expect from Tahiti, Thunder Hawk, Tyrihans and Gimboa to add in the third and fourth quarter this year?

Yes.

I mentioned -- I was quite specific earlier on Tyrihans actually, that it was around 56 -- I think a plateau.

Then there is a ramp up period.

So I haven't got specific information on the profile of this ramp up.

And when it comes to Tahiti, it's also a ramp up situation; a very small contribution in the second quarter (Company corrected after the conference call).

It's ramping up gradually and total capacity is at around, I think, 140,000 -- 125,000 liquid and some gas.

and we have 25% stake in that.

Thunder Hawk is a total capacity of 36,000 something like that, and I think a plateau around 8,000, 9,000 barrels on our hand.

Well, at least gives an indication of the volumes from these specific fields.

But at least expect enough to reach our 1,950, so that's clear.

We've got a question from Gordon Gray at Collins Stewart.

Well, there's a question about PSAs and I think we've been there a couple of times.

So I'll just skip that one.

The second one is, how much NCS production do we expect to gain from a return to normal operations at Kristin, at Snorre and at Kvitebjorn, apart from the normal effects from summer maintenance?

Well, I can't recall exactly the production volumes on Kristin for the time being.

There is one well, which is not producing; has been out of production for some time.

We are working on that.

That represents approximately 25% of the production capacity currently on Kristin.

So when we get that back into production, we will increase the production of that.

It's going to have no impact on the Tyrihans production, which is tied back to Kristin because there's still capacity on the Kristin field to deal with, both the additional well of Kristin and the Tyrihan production.

Now Gudmund?

Just a question on oil sands, well, at Shell they delivered $50 million of net profits from their oil sands business.

And I was just wondering regarding your Leismer demonstration project, where do you see the breakeven level now, maybe especially with a background of low energy prices?

Well, this is -- the breakeven price is -- well, first of all, the Leismer demonstration plant is a demonstration plant.

So typically it has higher costs.

We have invested also some issues for the future.

So it has higher costs and was initiated also in a high cost environment.

But it's a small facility, compared to the whole scale of what you're dealing -- talking about.

Cost environment in Canada has been -- comes from very heated situation.

And we now see that cost is coming down.

And we think that is extremely important, in order to be able to move on with the development.

So I would say one X factor is sort of how the cost development is going to move on going forward.

The other one has to do with how -- what kind of value chain are we developing.

And so far, we have all options open to us in terms of everything which -- building an upgrader, which we have cancelled basically with the current plans at least.

And another is to sort of -- with the export with diluted crude or going into a refinery -- various kinds of refinery commitments and positions in the US.

So I would say we are considering all these ways of marketing the crude and enhancing the value from it.

Currently, if you do the full cost development and the focus on the upstream and upgrader version, I would say $70 to $80 per barrel at breakeven point.

But we need to take this down, basically.

And I think the whole industry is focusing on taking down the costs, so that we can take breakeven levels down to more reasonable levels.

So let me just remind you, when we did the acquisition in Canada originally, it's not that long ago, in that cost environment, we talked about breakeven prices of around $50 per barrel.

So the only thing which basically has changed since then is the cost environment.

Okay.

There's a question from Carl Christian Bachke at Fondsfinans, which I honestly don't understand.

So I would ask Carl Christian to repeat the question and ask it in a different way, because I just don't understand it.

But let's take the next one, Paul Spedding.

Given that you have already paid a dividend for 2008 and you have a breakeven of $55, why won't gearing fall from here, rather than stay at the current level, as Eldar says, if the oil price remains at $70?

And that's exactly the same question from Irene Himona at Exane.

Well, we will invest in our CapEx program of $13.5 billion.

And -- so basically, that would keep up the gearing level.

So -- and so far this year, we have had a slightly lower CapEx spend level than we expect to see in the second half of this year.

So if you look at the number so far, you will get to slightly lower than $13.5 billion; so a slightly higher spending level next year.

So overall, putting all this together, we still maintain the $55 breakeven -- cash breakeven level and the guidance that I gave you on the ratio, as such.

Okay.

There's another question from Irene Himona, which relates to the reporting currency.

You switched to US dollars as the functional currency to reduce currency effects.

By continuing to -- but you continue to report in Norwegian krone.

And by doing that, you've introduced translation effects.

Your competitors, who adopt -- sorry, who adopt -- your competitors who adopt the US dollar as the functional currency -- your competitors who adopt the US dollar as the functional currency also report in dollars, would you contemplate reporting in dollars to avoid translation effects and improve clarity?

Well, first of all, there was the argument why have you changed functional currency it was not to reduce currency impacts.

There was other reasons behind that.

If we now -- obviously, we could change currency reporting to US dollar, we still would be a Norwegian krone company in a tax sense and in a dividend sense.

So we'd still have currency impacts, but then -- from that kind of component.

And it would not change -- I think the functional currency issue and the fact that we are paying taxes calculated in Norwegian krone, the basis has to be transferred into Norwegian krone, and then you have a tax calculation and we pay taxes in Norwegian krone.

That is the reason why we have this tax accounting issue and not sort of -- that would not change if we moved into US dollar as a reporting currency at Group level.

At least, that's what our experts tell us.

And if I'm wrong now, Kaare, you will have to correct me.

You're quite right.

Okay.

A couple of questions left here on the Internet.

A question from Kim Fustier from JPMorgan.

Chesapeake has recently reported better than expected results from the Marcellus Shale production.

Can you give us more detail on your recent progress on the Marcellus?

Well, first of all, the current production from Marcellus is still at a rather low level.

We are drilling.

We have approximately 15 drilling rigs operating within our part of this business.

We intend to increase that to around 20 by the end of the year, and then it will increase to 40, and even higher as we move into the future.

So the drilling is going as planned, we think it's a good idea to do that in this cost environment, and prepare ourselves with a new capacity when we think gas prices will improve going forward.

So far we are very pleased with the development.

The initial production rates that we have seen have been at least as good as we have expected to see when we made the acquisition, and so obviously everything has pointed in a positive direction since we made the acquisition.

But again, to repeat, the contribution from -- into our revenues is very low; this is a very few barrels, we are talking about currently but that will increase going forward.

Okay, the second part of the question from Kim Fustier from JPMorgan is, your unit production costs fell by 13% year-on-year in dollar terms in the second quarter.

How much of this was self-helped and third party costs coming down?

That's impossible for me to answer.

I haven't got the analysis.

But basically this is short-term, this is not new contracts, basically taking costs down at lower rates and so on.

This is activities and cost efficiency that we are doing, and also being assisted by our operator internationally, who is also doing a good job in terms of reducing cost levels.

So I think I would not attribute this to external costs and rates as such, but mainly to the activities and the cost saving activities that have been done within the operations.

Okay I've got another question from Carl Christian Bachke which basically is the same question as I got before, but I will try to ask it then.

You have given adjusted net operating earnings after tax of NOK9 billion.

What is the equivalent figure for adjusted net income after tax?

Well, basically what I'd say is my comments to the financials that I talked about and touched upon earlier, if we take away the infrequent items which typically it's related to impairments, in this case to derivative effects and currency impact, then you are back to something which is very close to zero.

So I would say, I can't give you it would be exactly zero, but it's -- and something which is very close to zero.

So I would say I can't give you, say to be exactly zero, but it's a tax on something which is zero, is also quite low number, so it's, I would say around NOK9 billion would be a guidance, but I haven't developed that number for you so -- for the reasons that I've just mentioned, but it would be in that range.

And there are a couple of questions still on the gas and trading results, so I think we have to ask the question again, even if you have answered that question before.

It's from Jon Rigby and Iain Reid at UBS and Macquarie respectively.

Can you talk a little more about how structural the trading income in natural gas and M&M is, whether you consider this as a good quarter or is that the type of results that are going to come back at these levels?

What should we expect going forward?

Well, to give an answer to the first question is, this a good quarter?

Yes, it is.

It has been a good quarter in all and we have a good quarter, not only in the crude oil, but also in products, and all kinds of liquid related trading activities has actually supported the results this quarter.

And, fundamentally, behind that has been the contango situation of all these liquid markets, so that's the main driver.

And obviously the future of the market situation going forward is quite important in order to discuss the future.

And in the backwardation situation you could typically not expect the same kind of earnings on the liquid side.

On the gas side, again it has been a good quarter but which has underlined that we have -- I think we have developed a more sophisticated gas trading business.

And a general statement.

There have been more sustainable results from this business.

But, to repeat, this quarter has been a good quarter.

That was the same question from Nitin Sharma at Cazenove but he's got a second one which is back to the adjusted earnings after tax.

By excluding the net financial items does the metric therefore exclude the net interest charges in addition to mark to market adjustments; please clarify.

Well, the -- I said on the -- if you look at the net financial items and exclude these things that we would have adjusted for, if we -- if you had been through that exercise, you are left with the interest that we pay on our loans, and you are left with the income that we had from our cash and liquidity; and you are also left with the securities, our asset management basically from our captive insurance company, which are typically revenues.

So if you add together these revenues and these costs, history has shown, and I think it shows also this quarter, which I tried to show in my presentation, you are pretty much close to zero.

So if you have done this kind of exercise you are left with something which is close to zero.

And that includes interest rates paid, and also interest income from our ordinary business.

Okay, two last questions on production; first one from Colin Smith specifically on the Marcellus.

You comment on the progress on the Marcellus net production at 800 barrels per day have given you -- will give you at least 50,000 barrels per day by 2012.

Is that still a valid target from Marcellus, 50,000 barrels in 2012?

Well the 800 I can't recall anything like that.

But it was 50,000 that we said.

Well 50,000 barrels per day in 2012.

Yes, yes,

Yes, definitely; there's no change to that.

It's nothing at all, progress on drilling and so on it's as planned, and there's no change at all to that -- to those ambitions.

Okay.

And then there's a second question on overall production from Geoffroy Stern at Cheuvreux.

Are you more at ease with your 2009 production guidance than you were a few months ago?

I would say I'm more so because, simply, time has moved forward and we have one more quarter of good deliveries; and also July was -- at least not with the information we showed made me more concerned about the guidance.

So as I'm standing here I'm more comfortable, simply because we have taken away some uncertainty.

It's a risk but things can always happen, and it hasn't happened which has an impact so far, and so I'm more comfortable now but there is still operational issues.

We are still -- I repeat, we are focusing on value before volume on gas and that is still valid, and this is something that could have an influence on the volume as such.

But as I see it today, it's more comfort on the number.

Okay.

Well, I see no more questions here in Oslo.

There are no more questions from the Internet, so thereby we finalize today's session.

I'll just note that we already have the manuscript of Eldar there on the Internet, so you can read everything he said and then in a couple of days, you will have the actual transcript.

So somebody will write what he actually said, and also the additions that we got here at the Q&A session.

But that will all be on the Internet when we type it up basically in a couple of days.

So with all that, thank you very much and good bye.

And that will conclude today's conference call.

Thank you for your participation ladies and gentlemen.

You may now disconnect.