Equinor ASA (EQNR) 2007 Q3 法說會逐字稿

Ladies and gentlemen, welcome to this StatoilHydro Third Quarter 2007 Results Presentation. My name is Lars Sorensen and I am the Head of Investor Relations. This morning at 8'O clock, Central European Time, the press release, stock market announcement, and presentation material were published both through the Oslo Stock Exchange and via our website, statoilhydro.com.

The presentation used in today's webcast could be downloaded from statoilhydro.com and that's the material that will be used in this presentation.

Please note that the report that we have here is excluding the oil and gas activities of Norsk Hydro as the merger was effective on the 1st October, i.e., the fourth quarter.

Then I would like to turn your attention to the disclaimer as usual, which describes the non-GAAP elements used in the presentation and the forward-looking statements.

A couple of words on safety as usual, for us here at the auditorium in Oslo, if the fire alarm goes off, there are two fire exits in this room. There's one there, which leads us straight out into the open. And there's one there, which leads us through the reception where you came in. Meeting point is just across the road outside the main entrance.

With us here today to take us through the third quarter presentation is StatoilHydro's Chief Financial Officer, Eldar Saetre and with no further ado, I'll just leave the work to Eldar. Please, Eldar.

Thank you, Lars, and good afternoon to all of you. Now, as a consequence of the merger, Statoil ASA changed its name from the 1st of October this year to StatoilHydro ASA. And as the merger with Norsk Hydro's oil and gas business was effective from the 1st of October. As Lars said, today's third quarter numbers, they are then excluding StatoilHydro's oil and gas activities.

Tomorrow, Norsk Hydro will present their third quarter results including the oil and gas business.

Furthermore on the 12th of November, we will issue the consolidated third quarter pro forma accounts, together with relevant guiding for the full year of 2007 on CapEx and on expected production volumes.

During the third quarter of this year, parts of the organization, I would say, have been quite extensively involved in the merger process and this, I have to say, has been both a quite complex, but also comprehensive and I would add successful effort, which has been performed according to plans all the way until completion as I said on the 1st of October.

The completion of the integration process and further work on capturing the full potential of synergies will obviously also continue beyond day one and with full force.

So, let's now look at the main highlights for the first quarters -- for the third quarter, excuse me. As already mentioned, the merger process has been successful all the way until completion on the 1st of October. We continue to deliver solid financial results during the third quarter, mainly driven by strong oil and gas prices.

During the third quarter, we started producing from three new world-class gas projects on the Norwegian Continental Shelf, the Ormen Lange, the Snohvit and also the Statfjord Late Life project, while Kristin at the same time came into full production.

In the third quarter, we also added important positions for longer-term growth through an opportunity to participate in the phase one of Shtokman development project and also adding new acreage position in the deepwater part of the Gulf of Mexico.

On the NCS, we have delivered some of the most complicated offshore projects and at the same time driving technology implementation through these projects. And we have continued to deliver safe and efficient production at a competitive production unit cost despite the industry cost pressure that we are seeing.

Our combined experience and position as a merged company is obviously also interesting and attractive to others. We are quite convinced that StatoilHydro's position as the world's largest offshore operator, pipeline operator and our Arctic LNG experience are important reasons why we have been awarded the opportunity to participate in the Shtokman -- development of the Shtokman project in the Barents Sea.

Then to the financials, StatoilHydro again excluding Hydro oil and gas had a net operating income in the third quarter of NOK24.4 billion compared to NOK30.2 billion in the same quarter last year. This 19% decrease was mainly due to lower downstream results, a 15% decrease in gas prices measured in Norwegian Kroner, and also increasing cost, both related to operational activities, depreciations and increased exploration activities.

The net income was 26% higher than last year, and this is primarily due to significantly higher income from financial items. In addition, we had a lower tax rate of 64.3% compared to 69.5% in the same quarter last year, and the lower tax rate is mainly related to the financial items.

The income on net financial items is mostly due to the lower US dollar exchange rate to Norwegian kroner. The US dollar fell from NOK5.90 per dollar at the beginning of the third quarter to NOK5.44 at the end of the quarter, that's a difference of almost 8%, generating a positive P&L effect, both from the long-term debt, which is all kept in US dollar, and also the short-term debt and liquidity positions.

This quarter the net financial items provided an income of NOK5.5 billion, while we had a cost of NOK2.3 billion in the same quarter last year. Earnings per share increased by 29%, as a result of the growth in net earnings and the reduced number of shares due to the share buyback program.

Total production -- oil and gas production in the third quarter was 1,056,000 barrels a day, which is down 2% from last year -- the same quarter last year. Oil production was down 4%, while gas production was up 2%. The international production grew by 19% on a quarter-to-quarter basis. And as you can see, total oil and gas liftings was up 2%, compared to last year indicating an overlift in this quarter of approximately 22,000 barrels a day.

Turnaround activities had an impact in this quarter, both from the international and the Norwegian activities of approximately 45,000 barrels a day, which is exactly in line of what we guided on in the previous quarter.

Based on the total oil and gas production and then again excluding the Hydro oil and gas portfolio, we maintain the guiding of an average full-year production for 2007 of between 1,150,000 and 1.2 million barrels a day. However, we expect to end in the low end of this range. I would like to add moving gas in [time] to create value is contributing to this development. And as already mentioned, we would provide further guidance on the combined Statoil and Hydro 2007 volumes on the 12th of November.

Let me then run you briefly through each of the business segments. Starting with the E&P Norway, net operating income from E&P Norway was NOK21.9 billion, which is unchanged from the same quarter of last year. There was a decrease in the transfer price of gas -- natural gas by 4% and also a minor decrease in lifted volumes of oil and gas. These decreases were partly offset by increase in other income of NOK1.8 billion mainly due to change in fair value of some derivatives.

Operating income expenses increased by NOK0.6 billion, mainly due to the overall industry cost inflation that we see, but also new fields and increased general -- increased maintenance activities and also well related activities.

Depreciation also increased with approximately NOK500 million, which [are currently] due to higher asset retirement costs from 2007.

Net operating income from the International E&P was at NOK2.8 billion in the quarter, compared to NOK2.5 billion in the same quarter last year. And this was mainly due to a 23% growth in the lifted volumes, which contributed to the improvement by NOK1.2 billion. On the negative side, we had an effect of approximately NOK1.4 billion from a decrease in the realized gas price.

In addition, the realized oil price was down 2% and we also had an increase in exploration and operating expenses, mainly driven by higher activity levels. Exploration expenses was at NOK1.3 billion compared to NOK1 billion in the same quarter last year.

Net operating income within the natural gas segment was slightly negative at NOK0.1 billion -- NOK100 million this quarter, compared to an income of NOK2.4 billion last year. This decrease of NOK2.5 billion was mainly due to a 15% reduction in the sales price of piped natural gas reducing income by NOK2 billion.

At the same time, the internal transfer price was reduced as I have already mentioned by only 4%, due to the simplified and rather mechanical way of calculating the internal transfer price directly linked to the [Brimm] plant. And this is leaving a significantly reduced internal margin of 23 [order] per standard cubic meter for the natural gas business.

The fair value of derivatives was reduced by approximately NOK300 million this quarter compared to a gain of NOK0.9 billion last year in the same quarter. So that explains NOK1.2 billion of the EBIT reduction from the third quarter of last year.

Natural gas sales for the third quarter was at 7.3 bcm compared to 6.6 bcm in the third quarter last year, this is an increase of 11%. Of the total gas sales in the third quarter 5.8 bcm was equity gas compared to 5.9 bcm equity gas last year.

The sale of natural gas from the InSalah field and the Shah Deniz fields are reported separately by the international E&P segment.

Net operating income for manufacturing and marketing in the third quarter was a negative NOK0.1 billion compared to NOK2.1 billion last year. The decrease was mainly due to currency losses on inventories, combined with lower refinery margins.

The net operating income within oil sales, trading and supply was negative NOK0.6 billion, compared to a positive contribution of 0.5 last year. This was, as I just mentioned, mainly due to currency losses on inventories of approximately NOK700 million and also slightly lower results from trading activities this quarter.

Net operating income for the manufacturing part of this business segment was NOK0.4 billion, compared to NOK1.2 billion in the same quarter last year. Now, this reduction is again mainly due to the lower realized refinery margins and combined with a lower US dollar exchange rate. And in addition, we had a somewhat lower throughput and [regularity] factor at the methanol plant at Tjeldbergodden.

Net operating income for the energy and retail was approximately NOK200 million this quarter compared to approximately NOK400 million last year. And this reduction is due to one-off costs only.

And now to some of the larger project deliveries that we have seen this quarter, and they are quite impressive. The Ormen Lange gas field started producing on the 13th of September, adding new volumes to the already opened Langeled pipeline to the UK and via this Sleipner hub this field can supply gas both to the Continental Europe and the UK.

The Snohvit LNG facility outside of Hammerfest in the northern Norway also started production in this quarter, actually on the same date, and the first cargo of 145,000 standard cubic meters was shipped on board the Artic Princess just little over a week ago.

The opening of the Tampen Link pipeline also marked the start up of the Statfjord Late life project, gradually converting one of the most profitable I would say and largest oil fields on the Norwegian Continental Shelf into a gas producer, that will produce gas for more than two decades ahead of us.

And finally the issues at the Kristin, high-temperature, high-pressure field have now been solved, and the field is producing with a full capacity of 9 wells. I would also like to mention that the drilling progress at the Kvitebjorn field which is temporarily shutdown is also good, and the field is expected to be back in production during fourth quarter as we have guided earlier.

On the exploration side, we had -- have had an extensive exploration program also this quarter, both on the NCS and internationally, participating in 47 explorations wells so far, up until today in 2007. 37 of these wells have been completed, providing 19 discoveries so far. We have seen only 5 dry wells concluded, and 13 wells are awaiting final evaluation, 10 wells were ongoing at the end of the quarter.

And we are quite confident that we will reach our Statoil only, to put it that way, activity ambition for 2007 of completing at least 40 wells in total. We are also very pleased with this achievement -- achievement, both in terms of the ability to actually execute this comprehensive drilling program and in terms of the high discovery rate. 18 of the completed wells on the Norwegian -- are on the Norwegian Shelf, and out of the 19 wells we have completed internationally, 6 are located in the deepwater Gulf of Mexico and all of these are still under evaluation.

So let's now took a -- take a closer look at the Gulf of Mexico position for the new company. I think the deepwater US Gulf of Mexico is a very good example of how the merger has created an even stronger company on the basis of existing positions from each company before the merger. This map shows an overview of StatoilHydro's total lease portfolio in the Gulf of Mexico as a merged company. In the western lease sale in August and in the central lease sale in early October, we were awarded a total of 78 leases, mainly in the deepwater areas of the Gulf of Mexico. So that means that StatoilHydro is now one of the largest players in the deepwater regions of the Gulf.

Exploration for new deepwater resources and the potential later development of these resources will require both organizational capacity and relevant technology and experience from the operators of these fields. And I think that is exactly what's StatoilHydro can bring into this game from its strong competence base on the Norwegian Continental Shelf.

And then a few comments to Shtokman. Last Thursday, the CEOs of Gazprom and StatoilHydro signed a frame agreement relating to the development of phase one of the giant Shtokman gas and Condensate field in the Barents Sea.

StatoilHydro will participate, we will partner up with Gazprom and Total through an equity share of 24% in the Shtokman Development Company. The first objective would be to establish an acceptable, technical and commercial basis for the final investment decision expected to be made in the second half of 2009.

Phase one will consist of an LNG facility and pipe gas production of almost 24 bcm per year for a period of 25 years. The total field is estimated to contain some 3,700 bcm or 3.7 trillion, I think it is, of natural gas. Both Statoil and Hydro have been working on realizing this project for years and the entering of this agreement is a strong demonstration of the capabilities of the merged company.

We are very pleased we being selected as a partner in this giant and Arctic project development and also to be able to further develop a long-lasting relationship with both Gazprom and Total. We expect to be able to utilize our experience, both from Arctic LNG, gas transportation and general offshore experience in general to design a value-creating project for our shareholders at the time of the final investment decision in 2009.

Let us now, towards the end, take a look at some of the important events to be aware of in the fourth quarter. We are planning to start any day now, the production from the Tordis IOR project, which is an important step in our subsea technology development. Njord and Volve will also startup in the fourth quarter together with Marimba North in Angola, which is already producing.

Both Snohvit and Ormen Lange will continue their ramp up of their production and we also plan to complete as already mentioned the last well at the Kvitebjorn field and start production before year end.

The merger was effective on the 1st of October that also means that we will accrue for committed restructuring cost in the fourth quarter accounts. The main part of this cost provision would be related to early -- the earlier retirement scheme as a consequence of the merger. We will revert with guiding on the size of these cost accruals before the fourth quarter presentation, where necessary and reliable estimates have been established for this cost provision.

On the 12th of November this year, this month, we will issue a pro forma set of consolidated accounts for StatoilHydro that is for the third quarter and for the first three quarters of this year, including Hydro oil and gas activity. And we will also include a full year guidance on CapEx and production for the combined company in that announcement.

On the 9th of January, we will arrange our first Capital Markets Day for the new company, discussing both relevant strategies going forward and also more specific targets for the new company.

Then to summarize this third quarter, we have successfully completed the merger between Statoil and Hydro oil and gas according to plans and at the same time, we have been running our operations in a both safe and efficient mannerism.

Solid financial results with an earning per share increased by 29% from last year. We have delivered three giant gas projects in the third quarter and each of these are frontier projects in their own ways, highlighting our strong capabilities.

The Kristin field now produces at full capacity from nine completed wells and we have kept on securing growth options in the future for the future growth both related to the Shtokman opportunity and also through the new acreage added in the Gulf of Mexico.

And before I end my presentation, just -- I would just like to repeat three important dates. The first one is tomorrow, on the 30th, you can listen into Hydro's -- Norsk Hydro presenting the Hydro part of the oil and gas business which is now merged. On the 12th of November, as already mentioned, we will issue pro forma accounts and on the 9th of January next year, we will have our first Capital Markets Day.

So, that concludes my presentation. Thank you very much for the attention so far.

All right. Ladies and gentlemen, then we'll open for questions and just to inform you listening in from the internet, there is a submit question button on your screen as you want to ask questions to us here in Oslo, please write your questions in and send it to me here on my PC and I'll read them aloud and we will answer the question from here. With me here in Oslo now, if you can get room on the table here, in addition to Eldar Saetre, our CFO; we have the Head of Performance, Management and Control [Jorgen Reissem] to answer questions.

So while we see -- I will just take a question from the internet and then leave the other questions to you here in Oslo afterwards. So there is a question from Neil McMahon from Sanford Bernstein. And he asks, can you give us any guidance on the dividend and buyback policy through the rest of the year? Or will we find that out on the 12th of November?

Well I don't think we will communicate any further information on the dividend and buyback policies to put it that way on the 12th of November, so I think that's something we will have to revert to and get to our Capital Markets Day. Basically there is no change to our dividend policy and we have also the mandate from the General Assembly to buy back shares at the same level as we did last year. So the mandate is exactly the same as we had last year. So, beyond that there would be no additional information on the 12th of November.

All right we will take another question from the internet then, it's from Iain Reid at UBS.

Can you explain why international E&P gas prices fell so far in third quarter?

Actually not, I am not in a position, there are two fields that -- basically two and also a small field in the UK, but it's about Shah Deniz and the In Salah and I am not in a position to disclose any specific information on neither contractual arrangements nor the gas prices realized under any of these contracts. So all I can do is, simply to state the fact that the average gas price has been reduced by 44% and it has an impact of NOK1.2 billion on the accounts on a quarter-to-quarter basis.

There is a question there from [Gudmund Isfeldt from DnB].

DnB NOR Markets. I have a question regarding the eight, possible on, stuck on the possible $800 million that you are going to pay, if you are going to pay that, will that imply that you could [book] some reserves on Shtokman for instance, the second half of 2009?

Well, when it comes to a potential bonus payment related to the Shtokman, all I can say is that we haven't paid any bonus, however if there is a positive investment decision made, and we are part of that investment decision in 2009, there would be a bonus, cash bonus payment to be paid, but I cannot confirm any specific amounts or could comment on any specific amounts related to that. When it comes to booking of reserves, that is a complicated issue, I can tell you, and all I can say is that there is, as it is complicated, there is a loss of -- lot of elements that goes into that consideration and some of these takes us in a positive contribution, some in the opposite, and it is simply too early for us to conclude on that issue. So what I would like to add though is that, booking in itself doesn't create any value, that's just a number on a piece of paper. So its really there, the setup the commercial terms and the value creation that we see in this, which is important for us and which should be important for the shareholder although we recognize that, it is, it has some value in itself, to put it that way. To be able to book this, but basically we are looking at the fundamental value creation potential.

And just as a follow question from [Stan Habish] at Hudson River Global Energy. Can you tell us, how you can support the possibility of a possible return on investment in Shtokman? Do you have any estimates of cost timing margins?

Well, obviously, we have some estimate, but I am not ready to disclose. Obviously, when you enter into an -- a frame agreement like this we -- you do a lot of calculations and assumptions. But, at this point it's too -- it's far too early to be specific on the cost estimates, for instance, that's something which is really going to be worked out over the next couple of years. So, basically, I am not in a position to disclose any specific information. What I could refer to is on the start-up dates, is that Gazprom has indicated 2013 for the pipe gas as a start-up and 2014 for the LNG.

There is number of Shtokman questions here. I will take a couple of them from James Hubbard at Deutsche Bank.

To be involved in such a world-scale project such as Shtokman, would you accept lower returns say 10% IRR?

All I can say is that we will accept the returns that we find reasonable for a project of this nature, and to be specific on any specific criterias on specific projects, that's something I wouldn't sort of discuss at all.

There is a question from Jason Kenney from ING.

Can you give us any further information on the earn-out agreements that impacted the E&P Norway business by positive NOK1.5 billion in the third quarter?

Well, these are related to asset sales that was made in the 90s actually and it's not only one agreement, it's a couple of asset transactions that were made at that time and those that made those transactions they were probably able to look in to the future. So, clauses that were included in those contracts was related to actually higher levels of future oil prices, which I don't think anybody expected at that time. But, now they are coming into money in a way and that sort of simply adds to the revenues from the asset sales of that time. So, it's not only one contract. There are couples of contracts and it goes back to the 90s, actually. And this is the sort of the future value as we'll look into the forward prices or the assumed prices into the future and changes in those assumptions on the total of these contracts. So, I think accumulated they have a positive value of approximately NOK7 billion for the time being.

I think we actually left the Shtokman question, but there is one I think we need to take, because there probably are some misunderstandings out here. One question is from Neil McMahon of Sanford Bernstein.

He says, you've mentioned how entry into Shtokman could be a catalyst for additional joint activity with Gazprom offshore, Russia. Are there any discoveries which interest you in the region, i.e. are the two discoveries shown on slide 13, discoveries you would like to be involved in. And, there is nothing -- I mean, Shtokman has not -- our participation in Shtokman has nothing to do with the discoveries shown on that slide. It's just to show where Shtokman is positioned. So, I mean, people shouldn't misunderstand that that's not connected with those two discoveries at all. So, just let it say, it's a matter of indication where Shtokman is placed. There is nothing else indicated in those two fields.

Then, we'll follow-up with a question from Iain Reid at UBS. International E&P, OpEx, and general and admin costs rose by 15% year-on-year in dollar terms in Q3, is this likely to be the ongoing run rate?

Well, on the international side, I think what is the main driver, there are two -- basically two drivers. One is what you see all over the place in the whole industry, there is a cost pressure and the cost inflation going on, which obviously also hits the US dollar as such and we see that also on our international projects. The second one is, simply that we have more fields coming into production. So, the portfolio of fields like the Shah Deniz, ACG is growing, In Amenas is coming to production since last year and so on, and it's simply a bigger portfolio of fields adding to the production cost. And that is going to continuing going forward as we will continue to see a growing production from the international portfolio. But, being specific on 15% or other numbers that I am not ready to do that at the moment.

There is a question from Colin Smith at Dresdner.

Please provide guidance on Kvitebjorn status. Please confirm Kristin production level now is at plateau? And when in the quarter the plateau was reached?

well -- yes.

There is a similar question from Michele Della Vigna at Goldman Sachs, by the way.

Yes. It's -- as I said we have 9 wells and none of them are held back in anyway because of pressure issues in the reservoir. So, all of these wells are producing at full capacity. There are still some additional capacity on the platform, not very much though, so we are very close to the full capacity now. There are still three more wells to be completed. The total number of our wells is -- that is planned on the Kristin is 12 wells. We will not see the last well until going into 2008, being completed that's [the 12th well]. But, we are very close to the full capacity of the platform and all wells are now producing at full capacity.

Then there's a question from James Hubbard -- sorry, there's a question from Huw Williams at Bear Stearns.

Could you comment on the potential impact on economics for the proposed North American Oil Sands Corporation project of the proposed revisions to Alberta royalties?

Well, we have observed that there have been -- this proposal has been made and that there has been made some political decision also in terms of going forward with this proposal, which is basically an increased royalty and also corporate tax based on a sliding scale starting from $55 and increasing as the oil price is increasing.

We also recognized that there are some specifics that needs to be outlined and further elaborated on -- in these proposals before its effective. What I can say is that when we did the acquisition, we obviously realized that there was some uncertainty and risk related to tax system and -- as such. And that's something that we have taken into account. And all I can say now is that we will have to simply take these adjustments also into account when we make our future decisions on further developing this. So, that's what I can say. But obviously, any tax increase has a negative impact. But I cannot be specific on more quantitative terms.

[Martin Molsaeter, First Securities]. When you emphasized, it might be discussed, cash bonus in 2009. Can you exclude that you will be willing to discuss ownership in Snohvit or Ormen Lange or is that not something you would like to comment on that might be the part of the negotiations?

This is a cash bonus and that's it.

Okay. We will take another question from the internet, James Hubbard again from Deutsche. Why do you think the Norwegian Government didn't want to give you the go ahead for the further development of the Troll field?

Basically, I am tempted to say, you should ask them. And that's probably the right way of approaching it. But what they have stated is -- basically is that these are related to concerns on risk reserve or resource management as such and that the development of the -- further development of the oil -- of the gas, excuse me, would lead to lower potential on the oil side. And so, that's what they have stated. That's the reasons and I have no reason to believe that there are any other elements included in their conclusion.

What I can say is that we have obviously made these kind of evaluations ourselves, and we believe that the proposition that we have been working on the expansion, took reasonably care of resource evaluations and considerations as well. So -- and that's then we came up with a different conclusion. But all I can say, we have to respect the conclusion made by the government.

Anne Gjoen.

Anne Gjoen, Kaupthing. I have a follow up of question on that is the government decision related to new pressure tests that they have done of the area?

Again, I have no reason to believe, that's what we are basing our information on different studies. I think we have access to the same piece of information. So, I believe this simply has to do with a different base of looking at it.

There's a question from the internet. Let's just take that before [Goodwin] is coming on. From -- one from Jason Kenney and from Theepan at Morgan Stanley. Basically, could you give us any further information on the loss in the trading and supply part of the M&M division?

Well, as I said, this is -- there's a lot of elements going into this and some of them are related to the actual underlying performance on a quarter-to-quarter basis and some are more accounting effects from FIFO principles, from hedging activities that we do on some oil inventories and then there are currency effects. And what happened in this quarter specifically was that due to the strengthening of the Norwegian Kroner, we saw a NOK700 million negative development in the value of the inventories and that immediately has to be taken into the accounts through the profit and loss statement.

Last quarter -- same quarter last year, we actually had an opposite development of something like NOK150 million. So, between NOK800 million to NOK900 million is the change between the two quarters in terms of a currency effect on inventories.

In addition to that, we had -- we [all] receive variances on our actually underlying performance on our trading activities and this quarter, it was slightly lower compared to what we saw in the same quarter last year. So, it's the currency effect and also slightly lower performance on the underlying trading activities.

Then, -- sorry.

First Securities, Martin Molsaeter. You got a positive tax impact from financial items. In which range do you expect the tax to be in the fourth quarter and in 2008?

Well, I think to guide on tax effect on financial items, that's a science I wouldn't dare to go into really. But maybe you, [Torgen] would comment on this issue. I am sorry again --.

Sure, I can. I think the tax rate on the financials is --.

On the overall.

On the overall, yes, okay. I think in general terms, I mean, what we have said is that in our international business we'll increase in share overtime. And as you will expect somewhat decline in the corporate tax rates well, that is, that is going to take a long time. And the number that we see currently for this quarter is on the low side on what is the, normal tax rate as such. And then, you know, there will be distortions, quarter-to-quarter and you will see quite large preparations in the corporate taxes due to currency effects and due to financials as such.

Okay. There is another question from (inaudible).

You previously stated that your strategy is to keep the Norwegian production flat and your growth will come from international activities. Given that the Gas Network Expansion project did not come -- get through, do you still believe that's possible to keep the Norwegian production flat through 2015? And what about your plans in the Norwegian Sea, how will they be affected by this?

[Well], I think, when it comes to any new statements now on the potential for the Norwegian Continental Shelf, I think, that's something we will have to come back to because now we are really, we have to be allowed to spend some time to put together our portfolio to see that's -- how that's going to look. And also view the potential that you are asking for on the Norwegian Continental Shelf. But obviously, I mean, there what happen on the Troll and the expansion of the gas network that has pointed not in a positive direction. On the other hand, we are not sort of digging ourselves into a hole. So, what we have to do now, given that assumption is really to look at sort of the alternatives and other ways of sort of getting gas out of -- from the Norwegian Continental Shelf wherever it might be located.

What kind of ownership stake were you prepared to take in that pipeline? I understand that they are referring of course to pipeline running from the Norwegian Sea to Troll?

If I had that percentage I am not sure I would disclose it but I actually don't have it so and I am not quite sure actually that this discussion will come to that on a conclusion on that at all. At this stage we decided to terminate the -- the plans.

Okay. There is a follow-up question then just go ahead.

Yes actually just another question that is I mean you are guiding here that you'll meet the lower end of your production forecast of 11.50. Just how confident are you about that given the high number of start-up fields that we see here at Volve. You have an increased oil recovery project and so on?

Okay. That is a good question. I can assure you we are thinking about it almost everyday, how certain are you about the production forecast. There's obviously uncertainties in the numbers still although its only two months left, but because of the reason that you mentioned we have the ramp up on the Ormen Lange, we have the ramp up of Snohvit and that means that there is still a lot of risk involved in the numbers. We haven't been come back in production on the Kvitebjorn that is we have -- the first well has been turned out positive, the second one we are getting close to (inaudible) that could be -- surprises. So, there is always that kind of issues and in addition I would like to highlight the gas side. And as usual we would have to expect sort of normal behavior in the market on the gas side.

There is a question from Martin Molsaeter.

First General Market Securities. Question on EBIT -- on the international part of the gas production. We saw a very low gas prices Iain Reid mentioned, should we expect that going forward? Is the reason for this Shah Deniz that the prices are very much lower than other gas prices in other regions.

I think I answered that more or less that question that I am not in a position to go in to specifics because I mean there are two contracts and I cannot -- if I start to talk about average you are very close to addressing each of these individual contracts. I am not in position to talk about the commercial arrangements on these contracts. So I think I have to give you the same -- the same answer, really.

There are couple of questions from the internet on Ormen Lange and Snohvit, and the ramp up there I mean both Iain Reid, Theepan from Morgan Stanley, Jason Kenney, Colin Smith and so on asked about when did they start up production and when will plateau be reached on both fields and how much do they should produce in third quarter and how much will they produce in fourth quarter? Do you have any guidance on that?

It's very difficult to give an exact number and that's what we have said on the Snohvit that we are now gradually stabilizing and increasing the production and you know -- normally we will see irregularities in the production going forward into next year, at least into the first quarter of next year. But we have defined what we call commercial deliveries and we expect to have commercial deliveries, that is, reasonably stable. Full capacity deliveries on the Snohvit from 1st of December, but we also expect you know irregularities and issues that could arise since we are still in very early days in running period of such a big complicated facility.

On the Ormen Lange, I haven't got any -- I mean we are gradually building up the capacity and that's going to go on beyond this year as well. So, but specific dates for sort of the well program and a profile on the build up I haven't got that, specific information for you today.

Our other question is from (inaudible).

(inaudible). Regarding the production cost per barrel, that's up from NOK26.6 per barrel to 31.5. Can you go into how much of that is cost inflation and how much is the fact that you are facing in new fields?

Let's say 10% to 20% of that is cost inflation. The rest of that -- and some is related to actually that we are -- we have operational cost on Kvitebjorn, but there are no barrels. So, that is accounting for 10%, 20% -- that kind of events. And then the rest is simply in the activity levels. We have seen -- we have to address maintenance activities at a higher level and also some well activities to fight the decline that we see. So, that's part of the explanation. And then also we are -- on some of the fields that we are ramping up production on like -- Ormen Lange, Snohvit and so on. We have a full cost of running these fields. But we haven't got the full barrels yet. So, it's simply preparations for production and early production phases that is also impacting this. So, it's -- there's various reasons going into it. But, specifically on the cost inflation as such, I would estimate that to be between 10% and 20%.

Based on this -- what you are saying I would gather that is it likely that the production cost per barrel will be sort of coming somewhat again, or is this a level we could anticipate going forward?

I -- so, I think what I can refer to now is simply what we said and that's rather vague, but it's -- we expect definitely to see a cost level of above NOK30 per barrel for the full year, and -- but there are sort of certainly forces which is sort of putting pressure on the cost developments. As I mentioned about sort of maturing and older fields that we need to take care of. To fight the decline we need to sort of be willing to spend sort of necessary money to create value on our fields and so on, and there is the cost inflation and the industry, and there is also increasingly fields with producing more and more water and lot of liquids, but it's not that much oil that it used to be. So -- but, operating these fields has the same cost as -- irrespective of what is being produced. So, there are forces which are sort of pushing the cost, but then on the other hand we have to continuously fight this and work on cost improvements and so on, and the merger in itself would be one of that tools that we will use to fight the cost development. So, where this balance is taking us? I don't know, but there is definitely a cost pressure also on the operating cost.

And I wonder on the Alberta oil sands, the oil question before, but to what extents did you foresee that the tax rate were going to increase as much as it did, and now its also gone about half a year since you entered into the agreement. Have you sort of come any further of what sort of progress and when we can sort of get some more signals from you to sort of what extent you are going to invest and explore and develop that license?

Well, on the -- as I touched on the -- little bit on the tax changes, tax risk is something that we account for and we are able to look a little bit into the future -- to put it that way -- and to some extent address that risk. In this case, it's not affecting sort of the breakeven levels of these developments, because, sort of, they don't hit us until we have reached the 45 -- excuse me, $55 per barrel of WTI. So -- but, it is something as, again, as I said that has a negative impact on the higher level of earnings here. When it comes to the news here, the Leismer -- the demonstration plant that has been approved by the authorities, we still have to go through our internal a process of deciding on that. That's going to happen quite soon. And, then, we simply -- and it's still early days, and we are still looking -- really looking into how to develop this and its far too early actually to be specific on, sort of, the major developments of this opportunity at this time. Beyond what we had said previously that, sort of, the first step is likely to come something in the mid of this -- of the next century and towards the end of the century the full capacity, that's the best guidance I can give you right now. Excuse me, decade. It's a little bit heavy.

There is question from Paul Spedding.

Could you talk about how talks are going for the marketing of the second phase of the Shah Deniz and which export route do you think will be used?

No. It's -- I don't think I am prepared to, sort of, talk specifically about the progress. I think there has been progress, to put it that way, if that's of some help. And when it comes to export routes, we are still in the situation where we are looking at several opportunities on that. But, one of them is obviously to look through Turkey and into the European market.

There are a couple of questions from -- both from Neil Morton and Dan Barcelo at Banc of America and Neil Morton is with MF Global.

This quarter you had considerable success in the US, Gulf of Mexico lease sale are you able to provide more detail around the strategy?

This strategy -- strategy, what we did was I think like all others to really look deep into and we've been working on this for a long time. Where do we see the best opportunities for us and we have placed our bids and based on the valuation and also some obviously consideration of how the competitive situation would look on each of the specific opportunities. So a quite thorough job. So there isn't a general statement on the strategy other than that we have we have been doing a thorough job and being evaluating each of the opportunities based on the economics and on the competitive situation and we are very happy with the conclusions.

I'll just remind you that there is still some time before sort of we have all the formalities in place on these leases.

There is a follow-up question on that from Neil Morton at MF Global.

You got some 100% leases that you intend to proceed on a 100% basis or is it your intention to firm down your interests in due course?

Again I cannot give a specific answer and that's something obviously we will be willing to firm down and work on some of these opportunities together with partners. That's the part of the strategy which is quite typical in that part of the region I guess that there is a lot of sort of transactions and [farmings] being done following lease rounds like this and that's policy that we also would like to pursue.

Okay. There is a question from Kjetil Bakken at Fondsfinans. Are you looking at some -- any opportunities in Iraq? How do you view the current situation with regards to legal framework and security situation?

Well it goes without saying that it's a challenging situation in Iraq and as we have said for a long time I think Iraq is -- you know its -- there is a lot of interesting prospectivity in Iraq and if you look and I think sort of what we do like most other companies here is to look at these opportunities and put that together with how you look at the political situation and security issues and so on. So, yes Iraq is something that we are screening you know, quite actively, but still there hasn't been made any specific moves in that respect.

Okay. There is a question on rigs and rig rates that's from James Hubbard at Deutsche Bank.

Based on your heavy involvement in the drilling market this year, are you seeing any sign of rig rate declines starting in any rig segments?

I wouldn't say declines, but we have seen sort of -- that's you know parts of this have sort of flattened in a way. Then I am talking about sort of more of the conventional -- the conventional rigs, so we haven't seen sort of the increases that we have seen for the last few years, that has continued. But no decline so far, more stabilization on the situation. That also goes for the more sort of ultra deep water harsh environment type of rigs, going forward I think we see a more tight situation on that type of rigs in general than we do for the more conventional rigs.

There is a question from Mark Bloomfield at Citigroup.

Can you offer any guidance on expected maintenance in fourth quarter and can you offer any guidance on the split between maintenance on the Norwegian Continental Shelf and international in the next quarter going forward?

In general terms will be very limited maintenance in the fourth quarter, and so I would say approximately 5,000 barrels a day, as maintenance and 75% of that's within the international E&P business.

All right we have a general question from [Nick Pope]. What is your decline rate for oil and gas on the NCS?

Well, on the gas side, we still haven't seen lot of decline and this field tends to be more stable over time and so when you talk about decline rates, you are more talking about the oil -- oil fields. And then I would say there are two types of decline rates. One is sort of the natural decline in a way that comes from the reservoirs and then, as you know, we have also due to struggling, and we are not the only one to be struggling, we are simply having enough capacity to drill sufficient volume of production wells. So that has added to the decline that we have seen over the last couple of years. So, I would say, if sort of were able to sort of really drill the plant number and the plant, the number of [production wells] that we would like to see, I would still say that we typically would see a decline rates in the ratio of 4% to 6% on the average on the oil side on the Norwegian Continental Shelf. That's on the mature part of the Norwegian Continental Shelf. But we have seen slightly higher rates, because of the issues that we have had in terms of not succeeding with the drilling programs on the production wells.

Okay. There is a further question...

I might add a little bit on that, that is not sort of -- that doesn't have an impact on the reservoirs and reserves as such. That's volume that is still there. But it will take simply more time to recover those volumes.

There's question from Mark Bloomfield from Citigroup again on the OpEx and the DD&A. We are up and I think we have already answered that, but going further, can you offer a broader comment on the level of industry cost inflation, which you were seeing to the extent -- to which you are able to offset this? And there is a similar question from Mark Hume at Credit Suisse. What measures are you taking to mitigate cost inflation and where do you see the pressure point of this cost inflation? What are the [results] of increases and so on?

Well, there is a general pressure on cost. I think what is really important here is also to be willing to spend money or spend activities on really relevant activities that sort of can add values through increased production, IOR and so, and I think that is these days as, also very important. So to hit the right activities in terms of whatever we actually doing and whatever we are not doing. Then obviously what is important for us is to take up the full effect of the merger and that's something we will come back to when we get to the 9th of January. There is a lot of value capital to made from the merger and synergies and also on the operational side and that's something that we will go after with full force and that is maybe for the time being the most important effort that we can put in place in order to fight the increasing cost.

Then we have a couple of questions left on the internet here. We have a question from Dan Barcelo at Bank of America. International production was up strongly year-on-year, but you noted that PSA effects in Angola and UK declines partly offset the growth. Are you able to quantify this impact either year-on-year or quarter-to-quarter?

The PSA effects are quite stable for the time being. We've said that we may have based our guiding on a $60 per barrel development in oil price and then what we see currently so far year-to-date is a PSA effect of around 3,000 to 5,000 barrels per day so far this year as such. So that should be added, substituted to the reported production to get the $60 barrel equivalence. Furthermore, the rest of the year in PSA effects, we don't expect any new fields to hit any new tranches in the short-term its of course very dependent on the oil price and if you see extremely high oil prices things move faster into the next tranches. So, but there will be a few fields that enters into new tranches next quarter or the first quarter of 2008.

Next question from (inaudible) in Oslo.

(inaudible). Is it possible to say anything about sort of the timing of events regarding Shtokman and what do you sort of anticipate regarding when first gas can be reached?

I think what I can do here is, as simply refer to Gazprom, and they have indicated first piped gas from 2013 and LNG from 2014. I cannot add any or subtract any to that information, which has been provided by that's their estimate for the time being.

I suppose to get some information of the total costs? Total investment costs?

No. So that's something we would have to comeback to when we get to of course the final investment decision.

Okay. We have a couple of detail questions that we will come back to basically face-to-face we will call the single process and inform them of that. That's probably intimation there is nothing new that you won't have but it's a very detail things to go into, so we'll just leave it at that. And with these words we just say thank you very much and good bye.