Equinor ASA (EQNR) 2007 Q2 法說會逐字稿

Welcome to this Statoil second quarter 2007 earnings presentation. My name is Lars Sorensen and I'm the Head of Investor Relations. This morning at 08.00 Central European Time the accounts, the press release, the stock market announcement and presentation material were published through the Oslo stock exchange and on our website, statoil.com. All material can be downloaded from there.

Let me take just 30 seconds of your time to tell about safety. There are emergency exits there and at the back of the room. And if the alarm goes, it is real. There are no tests planned for today.

As usual, this presentation is webcasted and I would like to say welcome to all you listening in from the web. I would like also to draw your attention to the disclaimer on the second page of the presentation set that you can download, or have been handed in print the version, here in Oslo. And then I won't use much more of your time on introductions. I'll just introduce our Executive Vice President and Chief Financial Officer, Mr. Eldar Saetre, who will take us through the second quarter presentation. Please, Eldar.

Well, thank you, Lars. Ladies and gentlemen, it has been only two months since I presented the first quarter results. And I guess in the short time that we have had since the last update we have seen a continued demonstration of the dynamics and volatility of our industry and global economics. There is continued high growth in the world economy, indicating increasing demand for energy and oil also in the years to come. And oil prices above US$60 per barrel have so far not had any -- implied any material demand destruction.

The IEA forecast in its latest report that conventional oil production from non-OPEC countries would reach a plateau around 2011/2012. And accordingly, non-conventional oil production will increase, but in a moderate pace. The world will consequently to a much greater extent look to the OPEC countries and the national oil companies to meet the increasing demand and the resource owners are also increasingly aware of their position. Simultaneously, the U.S. National Petroleum Council have produced a comprehensive report to the Bush administration recommending tougher measures to increase energy efficiency and reduce energy consumption, including capture and storage of CO2.

We believe that the conclusions from both of these reports coincide with the assumptions forming the basis for our strategic moves over the last couple of years. The merger in itself proves our capacity and capability to meet the new industry challenges. We have strengthened our heavy oil position through the acquisition in Canada. We have created a solid and robust transition in Gulf of Mexico. Our cooperation with national oil companies will continue. And we are increasing our focus on technology for handling of CO2.

In this context, it is rewarding to see that Statoil is making steady progress every quarter, and that takes me to the first slide of this presentation. Overall, we are very satisfied with the results that we can present for the second quarter. The merger is on track to close on October 1. We are delivering production growth, both on oil and gas, compared to the same quarter last year.

We have high exploration activity and the exploration results are also good. 10 wells were completed in the second quarter and drilling was ongoing on nine additional wells at the end of the quarter. Year to date, we have completed 28 wells with 16 discoveries, only four dry wells and eight wells awaiting final completion. And we have delivered some solid financial results in the second quarter.

Statoil had a net operating income in the quarter of NOK26b against NOK30b in the same quarter last year. The 13% lower EBIT is mainly due to a 3% lower oil price in Norwegian kroner, 13% lower average gas price, and 2% reduced lifting.

In the second quarter we had a total underlift of 33,000 barrels of oil equivalents per day, split between 18,000 on the Norwegian Continental Shelf and 15,000 internationally. Last year we had an overlift of 26,000 barrels per day, adding up to a difference in the net lifting position of approximately 60,000 barrels per day.

The net income was 11% higher, primarily due to lower income taxes of 61.3% compared to 69.4% in the same quarter last year. The lower tax rate is mainly due to higher income contribution from activities outside of the Norwegian Continental Shelf, and an average tax rate on financial items which was lower than last year.

The EPS increased by 13% from the growth in net earnings and the reduced number of outstanding shares due to the share buyback program.

Total oil and gas production in the second quarter was 1,112,000 barrels of oil equivalents per day, which is up 3% from the same quarter last year. Oil production alone increased by 4%. Given the reservoir and production issues that we have had on Kristin and Kvitebjorn, the overall production performed satisfactorily. The ongoing efforts to complete the wells on Kristin and Kvitebjorn are following the new plans that we announced in May this year and we expect to get the full contribution from both of these well fields in 2008.

In the second quarter we also had a number of scheduled turnarounds. All of these activities have been performed according to plan and impacted production with around 16,000 barrels per day, which is in line with our guiding.

It is also worth noticing that our international production has an increasing importance for Statoil's overall oil and gas production. The international production this quarter increased by more than 10% to a total of 209,000 barrels per day, accounting for almost 20% of our corporate oil and gas production. The increase comes mainly from new fields in production and ramping up of production from Angola, Azerbaijan and Algeria.

The gas production from In Salah in Algeria fell significantly from the first quarter of this year, as a result of the PSA arrangements. Oil production increased by 23% to 181,000 barrels per day, which is the highest oil production outside of Norway in Statoil's history.

Return on average capital employed was 23.6% compared with a return on average capital employed of 26.4% in 2006. We maintain our position amongst the best performers on this indicator within our peer group and this ranking also supports our position as one of the companies with the best profitability and capital discipline in the sector.

Net interest-bearing debt was NOK43b at the end of the second quarter, compared to NOK13b at the end of the corresponding quarter last year. And that equals a net debt to capital employed of approximately 26%. The increase in net debt is mainly due to lower liquid assets combined with higher short-term funding.

And the three main factors for the use of cash in the second quarter, except obviously for the running costs, were a scheduled tax payment of almost NOK30b, payment of dividends of almost NOK20b, and the acquisition of North American Oil Sands Corporation of NOK12b.

Our estimate for net debt to capital employed by year-end is still in the range of 15% to 20%, excluding any effects of the merger.

Then I will say a few words about the overall exploration activity before we dive into each of the business segments.

As mentioned earlier, our exploration activity is still at a very high level and this chart illustrates the intensity and diversity of our overall exploration program. In the second quarter we have completed five wells, with four discoveries on the NCS. Since the end of the quarter we have completed additional three wells, which all were discoveries.

In Azerbaijan the long exploration well on Shah Deniz is under evaluation, while the sidetrack is still ongoing. And in Angola the Janus well is being evaluated and Portia 1 is ongoing. Both of these wells were in Block 31.

In Algeria both wells on Hassi Mouina are discoveries and we are now moving to complete the drilling program for the field and evaluate further possibilities.

In the northern part of the U.K. North Sea we are awaiting the two Rosebank -- evaluating the two Rosebank wells. Tests have been encouraging so far and the third well in this prospect was started actually last week.

At the Plataforma Deltana in Venezuela, Statoil has completed the drilling of the second well of the three-well program, the Ballena well. That is part of the ongoing exploration campaign in Block 4 on Plataforma Deltana.

And finally, in the Gulf of Mexico the two wells completed this quarter are still being evaluated. And we now have a total of 11 confirmed discoveries in our portfolio in Gulf of Mexico and four wells are being evaluated as we speak in relation to the 11.

Then to each of the business areas, and as usual I will start with E&P Norway.

The net operating income from E&P Norway this quarter fell by 14% compared with last year. This was mainly due to 11% lower oil lifting, partly offset by 7% higher gas lifting. We had a total overlift in the second quarter last year of 29,000 barrels per day of oil equivalents, compared with an underlift of 18,000 barrels per day this quarter. The oil price in U.S. dollars per barrel was marginally up last year but [the U.S. dollar] compared to last year. But the U.S. dollar fell more than 3% against Norwegian kroner, which resulted in a 3% lower oil price in Norwegian kroner.

Operational -- general and administrative expenses increased, mainly because of higher activity. In addition, there is also rising costs from general industry cost pressure. And DD&A was up - excuse me - 11%, mainly because of the upward revision of asset retirement costs from the fourth quarter last year.

These cost increases were more than offset by the lower exploration expenses of approximately NOK0.4b, mainly due to higher success rates and capitalizations.

Then, a few comments also to some other NCS activities. Within exploration we have had some very good exploration results lately. I mentioned the Ermintrude discovery in the Sleipner area in the first quarter presentation. Since then we have completed two sidetracks, confirming that this discovery is between 50m and 75m barrels. And with 100% ownership in this license, the volume is obviously of significance for Statoil.

We have also made a gas discovery in the so-called Yttergryta - strange name - prospect in the Asgard area and are now making preparations for this well to be transformed from an exploration well to a producing well at the end of 2008.

Furthermore, the Onyx southwest is finalized with a positive outcome this quarter. This gas discovery was originally estimated between 10b to 50b cubic meters, which is around 300m barrels, of oil equivalents. The appraisal well has confirmed the northern extension, making us look more at the upper part of the estimate of the estimated reserve range.

The appraisal well on the Snohvit oil zone was recently also completed. It is too early for any conclusions about the significance of this well.

In June the Norwegian Parliament approved the development of the Gjoa field, which is currently one of the largest developments on the NCS. Gjoa is planned to be in production in late 2010. Also in June the development plan for Skarv and Idun combined was submitted to the authorities. The BP-operated project in the Norwegian Sea is planned to be in production in 2011, and Statoil has an equity interest of 34%.

Two smaller projects have also started producing in this quarter, the Enoch and Huldra Compression. And let me just elaborate a little bit on the Huldra project. This project is not a very big project, but I think it illustrates well how Statoil constantly seeks to optimize value creation from all our fields.

Huldra came into production in 2001 and according to the original plans the field should have been shut down in 2006. In 2005 the owners decided to install a compressor [at the press pump] to increase recovery and recoverable reserves with approximately 28m barrels of oil equivalents, and increased the lifespan of the project by at least five years. So the Huldra Compression project is one type of IR project that we will see more of in the years to come and it's also very good value creation.

Now, to our international business segment. The net operating income within international E&P was down 7% compared to the second quarter last year. This was mainly due to increased exploration expenses of approximately NOK500m from the acquisition of seismic data, particularly in the Gulf of Mexico, in Brazil and also Northern Africa.

Oil prices in the second quarter fell by 3% in Norwegian kroner, while total lifting was up 3% compared to last year. The result this quarter was influenced by an underlift of 16,000 barrels per day compared to production growth of 10%, as I mentioned, corresponding to 20,000 barrels per day.

Oil production in international E&P is increasing, and has been a record high at 181,000 barrels per day. Gas production, mainly from the In Salah field in Algeria, was 27,000 barrels per day in the quarter, 30% -- 35% down compared to the same quarter last year, which is as expected and as we have previously guided you about. This was partly offset by more sales from the Shah Deniz field in Azerbaijan.

Our international E&P business is becoming gradually more important for Statoil and also in this quarter we have had some important achievements to support this development. As mentioned, we have closed and finalized the acquisition of North American Oil Sands Corporation. The new management team is in place and being integrated with the existing organization.

The Shah Deniz field started up production in late February this year and in early July the gas from the field also started flowing into the Turkish market.

We have signed an MoU with PDVSA and the authorities in Venezuela on how the transfer of ownership in the Sincor project is to be performed. This MoU clarifies Statoil's role in the new mixed company structure. The agreement is subject to approval by the National Assembly, which is expected to happen before the end of August.

A couple of weeks ago there was also renewed attention to the Shtokman field in the Russian part of the Barents Sea, as Total made an agreement with Gazprom, becoming a partner in this development. I cannot say anything specific about the process and the relationships that we have to Gazprom. However, we are in a continued dialog with Gazprom also on the Shtokman field, and our goal is still to reach a solution that is acceptable to Gazprom and Statoil. And it goes without saying that we will not participate or cannot participate in any project unless you are fully convinced that this will create long-term value for our shareholders.

Natural gas. Net operating income for this segment was NOK700m against NOK2.9b for the same quarter last year. This reduction was mainly due to a fall in the average external market price for gas of 13%, while the transfer price was approximately unchanged. Natural gas sales increased by 12%, while the equity volumes part increased by 7% from last year. Adjustments on derivatives affected the EBIT in natural gas negatively with approximately NOK700m compared to last year. The effect on the quarter in itself was insignificant.

At this point, I would also like to share some perspective on the European gas market going forward. Short term, the gas market no doubt is affected by new capacity and new fields coming into production. This is no surprise to us. Especially in the U.K. market the prices have been under some pressure, due to new import supply combined with a warm winter that has dampened demand. I would like to stress that, even after low prices that we have seen lately, Statoil creates considerable value from our exports due to the proximity to the market and the cost structure implied by this proximity.

In the longer term we maintain the positive view on gas as an increasingly important energy source to Europe. The indigenous production of gas in the E.U. declines rapidly, while demand for gas is expected to increase. This is not least due to the natural gas lower carbon footprint compared to oil, and especially coal.

Statoil's proximity to a gas-hungry European market and the efficient and flexible infrastructure that we have operated for many years encourages our optimism on gas in the longer term. The growing use of LNG will increasingly act as a link between markets and gas will therefore become a more global commodity with reduced regional pricing.

So, to conclude on gas, we expect a somewhat soft market in the short term, where demand as usual is also depending on temperatures. But medium term and longer term we see no reason to change our fundamental view on the demand for gas in the E.U. and due to the proximity, as I said, to the market we are in a position to be actually the most affected competitor both in the Continental European market and in the U.K.

And now to our last business segment, manufacturing and marketing. Net operating income for this segment was NOK2.6b against NOK2.5b in the same quarter last year. This 5% improvement is mainly due to realization of deferred gains on inventories and improved results on the energy and retail business. The increased earnings are partly offset by planned turnaround activities.

Oil, the trading and supply contributes NOK1.3b to the manufacturing and marketing EBIT, 0.5 or NOK500m of this is due to deferred gains on inventories according to IAS39. In addition, we have net positive effects from changes in inventory values.

Within manufacturing the FCC margin increased this quarter, but our refining result was also affected by expenses and planned turnaround at (inaudible), as I just mentioned.

The methanol price averaged EUR250 per tonne in the second quarter. That is 12% lower than last year. The methanol plant at Tjeldbergodden was also closed, due to the planned turnaround, for approximately seven weeks in the second quarter.

Within energy and retail margins have improved somewhat and the volumes have also increased slightly, contributing to a total of -- EBIT of NOK300m in the quarter, an increase of 45% compared to last year.

Then a few comments to the oncoming merger process. And the main message from this process, as I said in my introduction, is that it is on track to be closed on October 1. In the second quarter we got the shareholders' approval of the merger at EGMs in both Statoil and Hydro, with overwhelming majority in both companies.

We got in place management levels three and four, as we call it, and we have now started at May manning process, including almost 10,000 positions to be filled. All of these positions will be concluded and decided upon in late August/early September. So this means that when the merger is being closed on October 1 we will have the full organization in place and in operation from day one.

So the only remaining approval is from the creditors, and we do not expect any major issues to arise from this process.

So let's also have a look at some events that you should be aware of in the third quarter. The high exploration activity will continue also in this quarter and we still expect approximately 40 -- or at least 40 wells to be completed this year. We have a high level of planned turnaround activities in the third quarter, expected to influence production by approximately 45,000 barrels per day in the quarter.

The Shah Deniz field in Azerbaijan will ramp up production. And we also repeat our guidance on the production from the In Salah field in Algeria; the production from In Salah in 2007 is estimated to an average of 25,000 barrels per day for the full year. And I remind you that the entitlement production to Statoil in the first quarter of this year was 56,000 barrels on this field and that we -- and that there is a significant fall in the entitlement production from this field, due to the PSA terms, after the first quarter.

And of course the production of gas will depend on the customer offtake within the commitments of the gas year.

Finally, the agreement made in Venezuela is subject to approval in the National Assembly, as I said, and we expect this to happen before the end of August.

So let me now summarize the presentation. And, starting with the guiding for 2007, our production forecast for 2007 is unchanged and estimates to an average between 1.150m and 1.2m barrels per day of oil equivalents.

The production cost per barrel is estimated to exceed NOK30 per barrel for the full year. Exploration expenditure is expected to be approximately NOK9b, assuming the completion of 40 wells. And the organic CapEx is estimated to be around 45, bringing total CapEx for the period five to seven up to a level of NOK120b. And all of these forecasts are unchanged compared to what I said in the first quarter.

To summarize our key deliveries for the third quarter, the merger process is on track to close on October 1. We have grown our production year on year by 3%. The exploration results have been good, the activity is high and will continue at this high level. And we are delivering solid financial results with an earnings per share of NOK5 in the quarter.

So thank you very much for the attention and I guess I leave the word back to you, Lars.

Thank you very much, Eldar. I'll now invite the audience, both here in Oslo and on the Internet, to ask questions. On the Internet, if you want to ask a question you can use the submit questions function, which there's a button underneath your picture on the screen. And I'll take your question up here and I'll read them aloud to Eldar to answer.

With us here in Oslo we also have the Head of Corporate Planning, [Thorgren Reiten], and the Head of Corporate Accounting, (inaudible) [Thorson], who will assist on answering questions.

Are there any questions from Oslo? Bjorn Enarson has a question. While he's getting the microphone, I might just as well say that we also have a question from Jason Kenny on the Internet, or rather two questions, which both allude to things that happens after the merger. He wants a guiding on the ROACE after the merger and he wants a guiding on the CapEx after the merger. I might just as well say now that all such guiding is something that we can't give you now. We have to wait until we close the merger. And all such guiding will be given on our Capital Markets Day, which is now set for January 9, 2008.

So please, Bjorn, go ahead.

Yes, please. I wonder if you could elaborate a little bit on the realized gas price in Q2. It seems to be somewhat lower than what Norsk Hydro reported. So, for instance, could you tell us how much was spot exposure in the quarter versus long-term contracts?

And also, if you can give a little bit indication of the second half of the year, what kind of gas price would you expect for the second half of the year to realize? Thank you.

Okay. The gas price, as I said, was NOK1.63 for a standard cubic meter, which is down 13% compared to the same quarter last year and also down compared with the first quarter of this year. The average gas price is an average between our long-term contracts, which is a lot of contracts linked to different products, typically gas oil and fuel oil products and typically with a six months plus/minus delay, and also a combination of the volumes that we sell into the U.K. market at NBP pricing.

So this is a mathematical calculation based on these long-term contracts. And there is no special items, anything, except for the delays that we have in the link to gas oil fuel, typically, of approximately six months and the average quotation on the NBP. Compared to first quarter, for instance, we are down 12% and our long-term contracts were down 12%, NBP were down 12% on average. So we don't see any special item issues explaining our gas prices. It's an average compared to what has actually been achieved and what this logically can be calculated from, from the fundamentals.

(Inaudible question - microphone inaccessible).

Well, Statoil is quite a big player in the gas market and I don't think we'll give volumes on the overall mix. But it's pretty much in the same range as you saw in the first quarter, maybe slightly down compared to the first quarter, but not significantly down.

All right. I'll take a couple more questions from the Internet. There's a series of questions from Theepan Jothilingam from Morgan Stanley. I'll take the first one of these. Or rather, Snohvit, he's got two questions on Snohvit. Firstly, could you give us an update on the start-up and whether you have -- you're still on track? And what volumes do you expect this year?

Well, on the start-up, we are on track. There is no news. There has been good progress. We always say when we talk about Snohvit that it's a lot of challenges ahead of us still and in particular, as you move from a project phase into production testing and making sure that everything works, there could always turn up surprises and things that we have to make functioning.

But, overall, we are according to plan. We expect regular deliveries from December 1 this year and we expect that we can get gas to the tanks late August/early September, and then have our first export opportunities or shipments during September. That's the overall timescale due, but it's tight. And there is always a risk in this phase that things might happen that might interrupt our plans but so far, so good.

In terms of volumes, it's not significant volumes as we are talking about regular production only from the last month and maybe some volumes ahead of that. But it's not significant volumes in any case that we're talking about for this year.

Theepan has got a follow-up question. What about the oil zone? Can you give us an update on that?

Well, the oil zone, in any case, is a marginal project. And, as I just said in the presentation, we have completed the well and we will now have to go back and see what are the implications from that, whether that justifies the development. But at this time, it's far too important to give you an indication in direction.

Any questions in the audience? Yes, Anne Gjoen from the audience in Oslo.

I have a question in relation to the slide standing there, production estimate for this year. If the oil price should be $15 to $20 higher, how much should that impact on the production sharing agreements?

I have another question also, if I may. In relation to this Rosebank discovery, it's now been drilled to appraisal. When is it planning to start, or Chevron planning to start a third one? It's published the results from number two but not number one. Is it possible to give a comment on that?

I can do the Rosebank first. But both of the two wells is included in my statement that the result so far is positive. So, beyond that, it's a sidetrack and it confirms and is included in the positive statement. So now we are waiting (inaudible) has just started their third well in this three-well program, and then we will have to wait and see what kind of possible development solutions that Chevron might come up with.

So, on the PSA program?

Yes. On the PSA effects, for the last years we have enjoyed very high prices so we have actually moved into the new tranches in the PSA contracts. We are moving away from cost recovery to profit tranches.

So, currently, the production is less vulnerable to changing in -- changes or increases in oil prices. But that being said, we have some new fields which are still in profit, not on the cost recovery phase, Dalia, for instance, in Angola. I won't give any specific numbers but normally it takes a time until the end of the next tranches. So I would say that the number is fairly robust to changes in the oil price.

All right. We have two questions from Alastair Syme from Merrill Lynch. To confirm the -- let me just see. To confirm the approximate restart dates for Kristin and Kvitebjorn - can you do that?

And secondly, what level of Sincor entitlement production is factored into the 2007 production guidance?

Let's take the Kristin and Kvitebjorn start-up dates first.

Yes. Well, when it comes to -- there's no new significant news on any of these schemes, actually. As I said, it's following the plan, basically, that we established back in May. Kristin is -- we expect that to be -- there is one remaining well that needs to be drilled now before we can turn the production up to plateau level. And there is always risk but, assuming everything works fine, we expect production from Kristin to reach plateau, let's say, early in the fourth quarter.

When it comes to Kvitebjorn, I'd like to be a little bit more precise on that, so we still say during the fourth quarter. And also I'm pleased we only now have one remaining well. The first well is completed, so we are talking about one more well until we can go back into full production on Kvitebjorn.

On the Sincor, I haven't got the exact number but the basic assumption is they're transferring to the mixed company structure and taking that down to approximately 10%. The implications of that transfer is included, basically, in the production guidance that you can see on the screen now.

Okay. We had about the same question from Colin Smith about Sincor, so we won't repeat that. But Ian Reid from UBS has got a question here. Can you give a guidance for the full-year tax rate under your oil price assumption?

All right. I expected a question in that form. As you have probably noted, the tax rate for the quarter is fairly low on the corporate level. It's 61.3%. And Eldar went through the things that drives it, both the net financial results and then income outside the NCS.

On the level going forward, we normally don't give any guiding to it. Over time, we have said earlier that you should expect that the average tax rate for the quarter will be somewhat reduced, due to the higher share of international production and income. And you should also be aware of that this number will probably fluctuate quite much from quarter to quarter, as such, and I wouldn't say that the number we see from this quarter is representative for the full year.

The things that really affect this quarter is that we have a positive financial result in isolation and we also have the effect of the gas prices, which is lagging the oil prices. So in a stable world we would have anticipated somewhat higher gas prices, which would have increased the tax rate somewhat. So for the full year, personally, I would not be very surprised if it is somewhat above the 61%.

All right. We'll go back to Theepan from Morgan Stanley. He's got more questions here. (Inaudible) when there has been reports that you are in negotiations with Gazprom Neft to develop the Lopukhovsky block at Sakhalin Island. Do you expect a potential further deal in Russia?

You know we are in discussions with Gazprom based on the MoU that we have on a different set of various opportunities, so I will not elaborate on any of those specifically. But I cannot exclude that we will, at some point, reach conclusions and agreements with Gazprom on working together on other opportunities beyond the obvious one which we are discussing and, as I mentioned, also the Shtokman opportunity. But I will not comment, then, specifically on the prospect that was mentioned.

Okay. We have a question here from Dan Barcelo at Bank of America. The deepwater Gulf of Mexico, is the strategy acquisition there, or shifting towards drilling, such as the AMI with Exon? Any updates on exploration projects in the U.S.?

I just touched upon the exploration on the Gulf of Mexico in this -- in my presentation. We have drilled -- have completed four wells this year, which are all under evaluation. We are, as we speak, drilling four or five additional wells and we plan approximately four wells in addition to those. So, 12, 13 wells is the overall exploration program that we are looking at this year in the Gulf of Mexico. So at least that gives also an indication of that we are gradually getting more into the mode of exploration on the -- in Gulf of Mexico. Having said that, I will never rule out further acquisition also as an opportunity, but the main focus is to pursue and go further with our comprehensive exploration program.

Okay. There's a question from Mark Hume at Credit Suisse. You've recently sold your stake in Murchison and Trym. Are you expecting to become more aggressive in portfolio rationalization on the NCS?

I don't see any change in the strategy. We have always, from time to time, done that kind of sales from the NCS and this is reflecting a continuous portfolio optimization that we also do along the Norwegian Continental Shelf. So in this case we believe that other stakeholders could put more attention into these small developments and maybe create more value than we were able to do. So when it comes to the new -- the merger and the new companies, I think you will discuss that kind of issues in that context and I have nothing further to add at this point.

Okay. There's another question from Dan Barcelo, Bank of America. Do low U.S. natural gas prices alter your plans on the volumes? And what landed price is required to cover the cost of capital?

Now, if we were to go through that, Dan, I don't see really what we could do short term on that. But we don't have any fundamentally changed view on gas prices. I talked about the European gas market in my presentation. The same goes for the U.S. gas market. So we don't see it longer term. And when it comes to Snohvit, it's a longer-term perspective that we need to take. I don't think it's any change for us in the perspective on the U.S. gas market.

When it comes to the breakeven price on Snohvit, well, we have discussed a price in the range of US$4 per barrel to cover our discount rates. Cost of capital is lower than that, so you're talking about below US$4 per million bcu gas price at least as a breakeven against our cost of capital.

All right. We'll take another question from Mark Hume at Credit Suisse. Based on your $60 scenario for production guidance for this year, could you give us an idea of approximately your breakeven on oil price for 2007? Further, are you continuing with your shareholder return policy of about 50% payout going forward?

The shareholder distribution, what I can do on that is really just refer to our dividend policy and there is no other statements than what you can read out of our dividend policy.

So on the $60 and the breakeven, Thorgren, I don't know if you could comment on that.

Yes, the breakeven price for the portfolio. In general terms, we are investing for growth. And we are one of the few companies growing our production currently, with our intensive investment program, and that would, of course, be reflected in the breakeven price currently you see in the Company. And you know we match that with a generous distribution of funds to our shareholders. So, the breakeven price, we don't have an update on that compared to what we have said earlier but it is fairly the same as we have guided or not, or said in earlier respect to that.

Okay. There are two questions on tax rates on the Internet and then we'll take your questions from Oslo here afterwards. There's a question from Paul Spedding at HSBC and there's a question from Miss Michele Della Vigna from Goldman Sachs. And they're both alluding to, could you tell us what the tax rate was on FX gains and financials in the second quarter?

Yes, I think Thorgren will do that as well.

The tax on the net financials, in the second quarter the tax rate on the net financials was around 37%. And 37% is broadly in line with what we would expect when we have positive financial results, maybe a little bit on the low side. But that tends to vary quite a lot from quarter to quarter so seeing that as a stable number is probably something you should not anticipate.

If you look at, for instance, the second quarter last year, we had approximately the same net financial results but we had actually an implied tax rate with that result of 95%. And that was due to that we had the gain in the -- a gain in the mother company and we had a loss abroad related to that. And you know that will vary from quarter from quarter, depending on how the different currencies are fluctuating and how the funds are flowing. But, in general terms, I would say that the tax rate on net financials, 37%, is maybe a little bit on the low side to what you normally would anticipate.

We have a -- yes, we have a question from the audience here in Oslo.

Yes. There were a report about three weeks back from the National Energy Agency pointing to a much sharper fall in reaching production than you've been stating earlier. Is there -- should we be any alarm about this report or do you still see things as you have done?

I haven't got any details about that report fresh in my mind. But the direction I've noticed, basically I think what you should assume is that we have access to the same information as they have and they're basing their forecasts on production on information from the operators. And, obviously, from Statoil's [side], there's nothing in their statements which has any implications compared to the guidance that we have given you. So, that's the general statement here.

Another question from Christine Tiscareno, Standard and Poor's. Chevron has reported that Tahiti in the Gulf of Mexico has been suspended indefinitely. Do you have any idea what indefinitely means?

No, no. But I know a little bit about Tahiti. So Tahiti is delayed due to a material weakness in the so-called -- the shackle that connects the spar buoy to the subsurface and the pillars in the subsurface. And they need to be replaced before they can go on with the project. And the original plans, Tahiti was set to be in production in mid 2008. And I think the best guidance that Chevron has indicated now is that this will happen some time during 2009. And, hopefully, it will be at the early part of 2009 compared to the alternative. So that's the information we have and what we can give you at this time.

Okay. We have -- sorry, there's a question from the audience in Oslo.

Could you make a comment on the project in Nigeria which is expected to come onstream next year, if the unrest in Nigeria, whether or not it has any effect on the start-up there?

To my knowledge, there is no changes in the time schedule for the Agbami field, so that should be in production in 2008 as planned. It's a project where there is cost pressures, to put it that way. But, beyond that, there is no issues and the unrest that we have seen in Nigeria hasn't, at least, had any impact on this project as far as we know.

There is a question from Dan Barcelo at Bank of America again. Are you able to provide any update on the expected merger synergies from the Hydro deal?

I think I'll just answer that question actually, because I started, in my introduction, with saying that we can't give you any updates on what's happening with the merger. And that also goes for the synergy. We have to close the deal first and then we can update you on synergies as we go along.

But then there is a question from Peter Ramsay at Argus Media, which also goes on the merger. Do you have any figures on staff retention of Hydro and gas personnel, on positions currently allocated within Statoil Hydro?

I'm not quite sure that I understood the question but, obviously, there is -- most people that come from the Hydro oil and gas business is going to be continued and be part of the new company, and there has been very few people leaving in the situation that we have seen. And so we don't see this as an issue. But I don't know -- I'm not quite sure I understood the question clearly.

Okay. We are almost -- well, Peter Ramsay is here again. Can you give us an update on partner discussions on the Troll further development project? When might the PDO be submitted and is there any timescale for increased gas deliveries to Europe and when these might arrive?

There is basically no news. The license group is working on the plans for the further development and, at least, we are not looking at a deal this year, so we are into next year. But, beyond that, in terms of being more specific on time schedules, I have no new information.

Then a question from Ian Armstrong at Brewin Dolphin. What proportion of your capital employed is currently not earning an economic return?

To my knowledge, there is no assets that we are involved in that we are not making good results on at the moment, as we have no negative numbers actually walking through; all our numbers now in the second quarter. So, broadly speaking, I think we are happy with all parts of our business at the moment. I don't think you (inaudible).

I have a question here from Oslo.

What tax rate can we expect in the natural gas segment going forward?

And again to my expert here.

Okay. Well, what to expect. The last two quarters have been not typical when it comes to how much of the results is related to natural gas, since you know the internal price is making the margin into Norway. But in general terms, you should probably see a tax rate -- most of the business is in the NCS segment with 78% marginal tax rate. But then you have some results, especially at the [Korshta] plant, which is on the onshore tax part, so in the 60s is probably a good assumption.

All right. We'll take one from Theepan again from Morgan Stanley. Costs; most of your peers are seeing further cost inflation. Can you give us some color on what you see and how much you are able to mitigate for further years?

I think the whole industry is facing the same cost challenges and we have seen some -- on new developments we have seen some quite significant cost increases on development projects, obviously varying from project to project but quite significant. And we see that whether we are partnering projects or we are operating the projects ourselves.

Basically, I think we have been working on strategies, contract strategies and sourcing strategies, for some time now. And I think we have been able to really supervise all our activities in terms of sourcing across the Company and across operational and development projects and drilling and so on, and establishing a set of contracts and freight contracts and longer-term contracts. That is our response, in a way, to the increasing cost pressure.

That's the best we can do in the current environment to make sure that we have suppliers that we can rely on and have a long-term relationship with and that we have a contract structure which is the best possible that we can have. So I think that's really the general -- my general response to that question.

We have another question from Oslo.

In the natural gas division there's been -- for the second quarter in a row there's a fairly large loss for derivatives. Could you comment on whether this is going to be recurring or if this is just coincidence that it happened twice in a row, or in terms of a little bit more detail on it, perhaps?

On the second point, we didn't have much losses on derivatives. It was compared to the second quarter of last year, where there was a change. So the derivatives in the second quarter for the natural gas was minor. For the time to come, of course, it's just to predict the development of the commodities. So, I think with derivatives it will swing and there will be changes from quarter to quarter. But, to give any guidance on how it will develop, that we can't do.

Another question from the Internet here from Jeneiv Shah from JP Morgan. With regard to your North American Oil Sands acquisition, how close are you to deciding on whether to install an upgrader or not?

That's -- as we said when we did the acquisition, the base case is still for us to install an upgrader. But that's the flexibility that we have in this situation and we are just now focused on getting the organization in place, the management in place and also continuing to get the approval for the demonstration project. That will give us the first 10,000 barrels of production late 2009/early 2010. And then our studies to look into this is ongoing. But the base case definitely is an upgrader for the first -- at least for the first phase of this project.

There's a question from James Hubbard at Deutsche Bank. What volumes do you expect Shah Deniz to be at by year-end?

I haven't got the exact number. I think the overall second quarter production was at 10,900, 10,000 barrels per day for Shah Deniz, and half of that in the first quarter. As we said, gas is now flowing into Turkey from early July. (Inaudible) is starting to nominate gas. and so we will see a ramp-up.

All three wells are in production now, or one is injecting and supporting the production, so we're producing from two wells but three wells are in place. And the third well -- the fourth well is expected to be in production late this year. But overall, the plateau production on the Shah Deniz, we will not see full plateau production until two to three years ahead. So -- but an exact number guidance for the full year, I haven't got that number for you, actually.

Another question from Patrick Gillett of Merrill Lynch. Could you please give us an update on when you expect to receive gas from the Ormen Lange field, and whether you believe early flows will meet reported expected production levels of 20,000 to 30,000 cubic meters per day?

I cannot confirm the numbers to you but in our -- what we have referred to in this case is just the official plans for Ormen Lange, which is a production start-up on October 1. To the extent the operator will be able to deliver the gas before that, we would be very happy.

Okay. I think we are almost done. There are a couple of questions in the middle, one from Theepan. We've had some excellent exploration success. I know it's early days but can you give some indications of which were high impact or the ones you have been most encouraged about?

Well, as I said, on the Norwegian Continental Shelf I mentioned, in particular, the Onyx discovery and the Ermintrude discoveries on the NCS. Those have been very important for us this quarter. And on the international, Rosebank obviously, that we have discussed, has been also very important and maybe the most significant so far on the international side.

Are there any more questions from Oslo? There is a couple of questions left on the Internet but they are extremely detailed and I think we would actually answer them from Investor Relations directly to the ones with the questions, because I think it's going to be very complicated to do it here, actually.

So, with this, I thank you very much for listening in and goodbye.