Equinor ASA (EQNR) 2007 Q1 法說會逐字稿

Ladies and gentlemen, it is now past 1.30 Norwegian time so we start the webcast on Statoil's first quarter 2007 earnings presentation. My name is Lars Sorensen and I am the Head of Investor Relations. This morning at 8 o'clock, Central European time, the accounts, the press release, stock market announcement and presentation material were published both through the Oslo stock exchange and on our website, statoil.com. All material can be downloaded from the website. As usual, this presentation is webcasted and can be followed via our website, statoil.com.

Let met just take 30 seconds of your time on safety in Oslo. If an emergency should occur you'll hear the alarm bells and the emergency exits are there. there are no fire drills planned for today, so if the alarm bell goes please leave the room calmly and go to the assembly point across the street where you came in.

I would like to direct your attention to the disclaimer of the presentation. It is explaining about the non-GAAP measures that we use and also the forward-looking statements that we use in the presentation.

And I would like to make you remember that Statoil, since the announcement of the merger with Hydro on December 18 last year, been subject to the US Securities and Exchange Commission's rule 425 which sets our rules and guidelines for communications from Statoil in the merger period. We are still subject to those rules.

And with these words I would leave the presentation to Eldar Saetre, Statoil's CFO who is going to take us through the numbers for the first quarter. Please Eldar.

Thank you, Lars and good afternoon to everybody. Now, as you all know, the oil and gas industry is facing increasing challenges with accessing new oil and gas resources. The grow in demand for energy and hydrocarbons force the industry to make use of new [frontier] technologies in order to find and develop new resources. From this perspective I believe Statoil has a very good position, helped by a strong operating experience and technological competence. Sometimes, however, we have to accept that developing new technologies may take a little bit longer time than we had planned for.

The first quarter of this year has been influenced by the temporary production, or reduced production on the Kvitebjørn field. High temperature and high pressure fields like Kvitebjørn and Kristin are definitely technologically demanding and have to be developed with special care. By doing this and continuously adapting to the rest of our behaviors we are protecting our resources and values. And this is also why we have chose to delay the ramp-up of production from these two fields while completing the wells in a safe manner.

The first quarter of 2007 is the first time Statoil's reports according to IFRS. And as you are probably aware of, we have sent out a transition document reconciling the 2006 figures according to US GAAP with the corresponding IFRS numbers. This document should help you to understand the main changes in accounting principles and also the impact moving from US GAAP to IFRS. The transition document can be downloaded from our website. So from now on Statoil will, on a quarterly basis, report according to IFRS, but in our annual 20-F filing you can find a full reconciliation to the US GAAP.

So let's now have a look at the highlights from the first quarter. The first quarter of 2007 has been influenced mainly by the merger with Norsk Hydro where the transaction process and the integration planning process are on track. Secondly, we have made an offer to acquire North American Oil Sands Corporation in Canada representing significant new opportunities and growth opportunities for the company. And finally, we have also in this quarter, seen a very high level of project development and exploration activity. So I will revert to all of these issues in the presentation, and let me now start with some comments to the financial results.

Net operating income fell by 28% from the first quarter last year to NOK23.8 billion this quarter. The net result was NOK7.8 billion compared to NOK10.8 billion in the first quarter last year. This decrease was mainly due to a drop of 11% in the oil prices, and that should be in Norwegian krone, a 14% reduction in gas prices, a negative impact from derivatives of NOK2.7 billion and NOK0.8 billion due to deferred gains on inventories related to our oil trading activities. An increase in operating costs was, to some extent, balanced by a reduction in SG&A expenses.

The negative effect on derivatives comes mainly from the same financial derivatives that we have been used to under US GAAP. However under IFRS some additional commercial contracts have to be posted as derivatives and mark to market on a quarterly basis. The result is that volatility will be somewhat higher than we have been used to under US GAAP.

Finally Manufacturing & Marketing had solid results from operation with a higher regularity combined with both refining margins and methanol prices at a very high level.

The actual underlying production this quarter was [1,214,000] barrels of oil equivalents per day. However due to an adjustment of volume allocation between Statoil and STFI from previous years related to Kvitebjørn and [Troll] the reported production in this quarter was reduced by approximately 15,000 barrels a day to 1,199,000 as you can see.

Average daily oil production from the NCS was at 510,000 barrels per day, which is 52,000 barrels a day lower than the same quarter last year. In addition to a decline in mature field this rate of reduction was due to lower production on the Kvitebjørn field. As you are aware we had to decrease production on the Kvitebjørn high temperature, high pressure field, while completing the remaining production wells and we have also slowed down the ramp-up of production on the Kristin field. Both measures are taken as a result of careful [risk/reward] management to secure maximum recoverable resources from these two fields.

Gas productions from the Norwegian continental shelf was down 19,000 barrels per day to 456,000 this quarter. In addition to the adjustment between Statoil and STFI as I just have mentioned there is in general and has been a lower customer gas offtake to the European gas market in this quarter.

Internally oil production increased by 20,000 barrels per day to 172,000 barrels per day. This increase was mainly related to ramp-up of production from new fields such as the ACG in Azerbaijan, the Dalia in Angola, Block 17, and in Amenas in Algeria. This increase were partly offset by reduced entitlement production from the Kizomba A and the Kizomba B in Angola due to PSA effects.

International gas production was up 61,000 barrels per day compared to 39,000 in the same quarter last year. This increase was due to increased gas entitlement from the In Salah field in Algeria and start-up of Shah Deniz in Azerbaijan in February.

The return on average capital employed over the last 12 months was 24.3% compared to 26.4% for the whole of 2006 which still places Statoil in the top three amongst our peers.

So let's now take a more detailed look at each of the business areas starting with the NCS site. Net operating results from E&P Norway in the first quarter was NOK20.8 billion compared to NOK24.9 billion last year in the same quarter. The reduction was primarily due to decreases in oil price, in income from derivatives and in lifted volumes of natural gas. The operating, general and administrative expenses increased by approximately NOK600 million, mainly due to higher operational costs and also increased cost provisions due to an over-lift situation. This was partly offset by a 9% increase in the internal transfer price of natural gas to our natural gas segment. Exploration expenditure was at approximately NOK800 million in the first quarter which is largely unchanged from the same quarter last year.

So then to the International business, net operating income from the International E&P was NOK3.5 billion which is slightly down compared to the NOK3.7 billion in the same quarter last year. The changes were mainly due to a negative effect of NOK900 million due to lower realized oil and gas prices, and an increase in operating general and administrative expenses mainly due to higher activities and volumes produced. In addition exploration expenses increased by approximately NOK200 million. All of these items were almost offset by a 32% increase in lifted volumes of oil and gas combined.

Then to the Natural Gas part of the business. The results from Natural Gas segment in the quarter was approximately zero compared to NOK3.8 billion in the same quarter last year. Now the decreases from last year was mainly due to three factors. First of all, lower sales prices in the market in combination with higher internal transfer prices from E&P Norway. Secondly, lower sales volumes, and finally a negative change in fair value of derivatives.

The average gas price in the quarter was NOK1.74 per standard cubic meter compared to NOK2.02 in the first quarter last year. The transfer price from E&P Norway International Gas was NOK1.38 per standard cubic meter, which is an increase of 9% compared to the first quarter. So altogether this takes the Natural Gas margin down from 76 to 36 per standard cubic meter, that is more than a 50% reduction.

The Natural Gas sales this quarter was 7.1 bcm including sales of L&G and this compares to 7.9 in the first quarter last year. The reduction was mainly due to lower customer offtake in the European market and of the total gas sales in the first quarter, NCS Equity Gas was 6.6 bcm compared to 6.9 last year which is down 6%.

The negative change of NOK1.7 billion on derivatives is explained by approximately NOK900 million from a long term gas sale contract measured at fair value and approximately NOK800 million related to gas trading and optimization activities.

So Manufacturing & Marketing this quarter provided a net result of NOK1.1 billion compared to NOK1.6 billion last year. The decrease was mainly due to unrealized losses on hedging contracts which are not qualifying for so called hedge accounting. The results from oil trading in the first quarter was approximately zero compared to NOK0.7 billion in the first quarter last year. As I just mentioned the reduction was mainly due to unrealized losses on hedging contracts or rephrased, deferred gains on inventories of approximately NOK800 million.

Net operating income for the Manufacturing part of the business was NOK900 million compared to NOK700 million last year. The improvement is due to higher refinery margins in general, a continued high regularity and also strong methanol prices. The average FCC margin in the quarter was $6.8 per barrel which is $1 up compared to the same quarter last year. Average contract price for methanol was a record high; EUR420 per ton. The net operating income from energy and retail was at approximately NOK0.3 billion compared to NOK200 million in the same quarter last year mainly due to better fuel margins in Sweden and in Norway.

Then a few comments to our financial situation; this illustration shows the development of our net debt position. Actual net debt was NOK4 billion at the end of the first quarter however, on April 1 we paid almost NOK30 billion in taxes and, as usual, we have normalized for 50% of this tax payment taking the normalized net debt to capital -- net debt to NOK18.9 billion at the end of the quarter. Actual net debt to capital employed was 3% and again normalizing for the tax payment, as I just mentioned, the net debt to capital employed was 13%.

Taking into consideration that Statoil will pay dividend to shareholders of almost NOK20 billion and the acquisition of North American Oil Sands Corporation of approximately NOK10 billion we estimate the net debt to capital employed to be in the range of 15% to 20% at the year end.

Then I would like to expand a little bit on some of our efforts to build future business opportunities starting with an overview of our exploration activities. A total of 13 wells were completed in the first quarter and we have had activities on 24 wells in total, ten on the Norwegian continental shelf and 14 wells internationally. Internationally seven exploration and appraisal wells were completed in the first quarter; Miranda and Cordelia in the deep water Block 31 of Angola are both oil discoveries taking the total number of discoveries up to 14 in this block. The first well on Hassi Mouina on land in Algeria has also resulted in a gas discovery, while four wells are still awaiting final evaluation.

On the Norwegian continental shelf Statoil participated in the drilling and completion of six exploration and appraisal wells, three of which resulted in discoveries. In addition, one of the ongoing wells at the end of the quarter, the Ermintrude was announced, a discovery yesterday. Ermintrude is a high quality oil discovery situated north east of Sleipner and Statoil has 100% equity interest in this discovery in this field and this license was awarded back in 2003 as a part of the government's permission to increase exploration activities in the North Sea. Based on the preliminary estimates of recoverable resources the field contains approximately 50 million barrels of oil. We have now just started on the process of evaluating potential development solutions with possible cost effective tiebacks to existing facilities or other discoveries in the area. Currently we are drilling a sidetrack to confirm volumes and liquid potential.

Then a few comments also to our recent extra heavy oil step up. As you know on April 27 Statoil launched a bid to acquire all shares of North American Oil Sands Corporation in Canada. The acquisition will definitely strengthen our North American position significantly with both operator ship and a significant resource base. The acquisition will allow us to access more than 2 billion barrels of resources at less than $1 per barrel.

Heavy oil in situ production is still in its early days and Statoil wanted to be a part of this development, and the development of these opportunities, and technologies needed both in terms of production and drilling technologies and environmental solutions. Through this acquisition we will secure Statoil a significant operatorship also located in a stable region of the world. It will strengthen our heavy oil portfolio significantly and improve our overall marketing position in North America. As an operator we will also be able to ensure sustainable development of the resources. We are confident that we can use Statoil's core competences both from the Norwegian continental shelf and from Venezuela to create significant values from this portfolio. The structure and contents of the portfolio allows us to move forward with the existing plans, but also gives us optionality to adjust the development strategies if that is considered appropriate.

And then finally a few comments to the ongoing merger process. The short version of this story is that the merger process is progressing according to plan; the EU's competition authorities announced on May 3 that they had no objections to the merger between Statoil and Hydro. The FCC had no more comment to the draft F4 submission and the prospectus is now effective. So printed documentation [including call] for an AGM is now on the way to all shareholders. The AGM will be held on July 5 in Stavanger. The management on levels 2 and 3, as we call it in the organization, have now been appointed and we are presently in the process of selecting personnel for management at level 4 positions and the overall starting process of the new organization will be concluded by mid September. Following the AGM we need to creditors a 60 day warning implying that the deal most likely will be effective from October 1.

So let me now look at some of the main events to focus on in the second quarter. As you know, and as I mentioned, we have submitted a bid to the shareholders of North American Oil Sands Corporation and we expect to be able to close this deal at the end of the second quarter. We will definitely maintain a high level of exploration activities through the whole of 2007 adding up to approximately 40 wells expected to be completed this year.

Regarding the second quarter production there are a couple of things you should take into consideration. Our turnaround program will have an effect of 15,000 to 20,000 barrels a day in the second quarter and you can find the specification of the planned turnaround activities per field in the supplementary information to this presentation.

Enoch in the UK sector and Huldra Tail End on the (inaudible) will start production in the quarter. On the International side be aware of expected lower gas entitlement volumes due to the specific contractual of mechanisms on the In Salah field in Algeria. We expect average volumes on In Salah for 2007 to be at approximately the same level as for last year. We also remind you of the typical seasonal variations and gas off take from the Norwegian continental shelf. And finally there are continued negotiations on terms and conditions regarding Sincor in Venezuela as set out in the MOU signed on April 25 this year.

Then some concluding remarks on the 2007 forecast. The average production of oil and gas for the year is estimated between 1.15 million and 1.20 million barrels per day as communicated earlier and there are no change to that. Consequently, the production cost per barrel is expected to climb above NOK30 per barrel.

Due to increased exploration activity we expect to drill at the high end of the previous guidance of 35 to 40 wells hence expected exploration spending will increase from NOK8 billion to approximately NOK9 billion this year. The estimated CapEx for the period 2005 to 2007 is maintained at NOK120 billion.

So this concludes my presentation and I give the word back to Lars.

Thank you very much, Eldar. Now it's time for questions and with Eldar here in Oslo is also our corporate -- Head of Corporate Accounting, (inaudible) and Head of Corporate Planning and Control, (inaudible) to answer questions. The ones of you who listen in via the Internet, you can submit questions to me on my PC here, via the submit questions button on your screen and I will read them aloud here or ask the questions on your behalf.

So let's take a question from the audience, anybody? While you think about that, I'll take one from the Internet, then. That's a question from Ian Armstrong from Brewin Dolphin. He asks, do you have any updates or progress on the Jack field in the Gulf of Mexico?

Not really. There's no news. (inaudible - microphone inaccessible) simple answer to that question.

(inaudible)?

Is it possible to comment on the share of gas, oil in [stock market] during the third quarter [out of] Norway?

And secondly, is it also possible to comment to what extent you've taken into your production guidance the impact from Venezuela?

I think it's a fact that this quarter we have had a slightly higher share of gas sold into the UK market than we usually have seen previously. And that is mainly due to the low offtake that we have seen from some of our European customers. But to give you a specific share, I'm not prepared to do that today, but there has been more gas into the UK market.

When it comes to the situation in Venezuela, I would say that the potential outcomes of that is included in our production [guidance].

Okay, I'll just take a question from the Internet from Theepan from Morgan Stanley. Could you please give us an update on guidance for the tax rate for the Group in 2007, in particular again the tax rate in International E&P appears a bit higher than the 40%? Do you have any guidance on where this may be for the full year based on your $60 per barrel assumption?

Well, I don't think we will give a specific guidance, but we can give some -- provide some discussions on this issue (inaudible - microphone inaccessible).

Yes. I mean, first of all it's important to remember that the tax rate on the segments, they are calculated tax and they are not 100% aligned to the tax paid as such, so it's a calculated tax. So the segment tax, that will vary somewhat from quarter to quarter. Currently in the first quarter 2007 it's 46.5% which is the tax rate on [Int]. That is colored by a couple of items. One is on the West African assets on the Angola side where the effect of the uplift is lower when we have higher oil prices, and is also related to our business in the US where we are not in a tax position and the result hits the bottom line directly. So 46.5% does not fully reflect the underlying tax rate. For the full year, as I said, we will not give a guidance, but in the range we are talking about here it's not unrealistic to assume, I would say, between 40 and 50s is the normal rate. It will be -- could be quite significant changes from quarter to quarter and the full year is very hard to predict as such, but it's in that range.

John Olaisen.

John Olaisen from Carnegie. Also a question regarding to your gas sales. More than 10% of the gas volume is now being produced outside of Norway. Could you just confirm that it's still being organized under International E&P?

And secondly, what kind of price do you get on the International gas, could you give us some indication on that as well, please?

[Right], the international gas -- it's included in the International E&P segment; it is not introduced into the Natural Gas segment as such. So, there are no plans to change that. When it comes to the International gas price, there is one -- a couple of contracts there which have terms and conditions which doesn't allow us to be this specific on the gas prices that is achieved through these contracts. So I'm not in a position actually to discuss that in more detail.

There's a question from the Internet, here from Colin Smith at Dresdner. Can you comment on likely per barrel margin structure for 2007 for a) Ormen Lange and b) Snøhvit relative to current Norwegian per barrel margins in E&P?

To be honest, I didn't bring with me the specific numbers on this, but basically the development solutions that we see on both the Ormen Lange and on Snøhvit are quite cost efficient development solutions. Obviously there is a CapEx to be spent into this, but in terms of operational costs they are very cost efficient and I think in general these -- neither of these two assets would add to the average of our operating costs as such, but the specific development costs per barrel as such, I haven't brought with me a number on those. But in general terms I think they are on the higher end compared to the average that we have (inaudible).

You want another question?

Yes, please. Could you comment on when you expect the drilling results in Algeria to be finalized?

Was that Algeria? Okay. Well, as I just mentioned in the presentation, we have made a gas discovery on Hassi Mouina and we are now in the process of drilling the second well on Hassi Mouina. And so far there are no results from the second well and we haven't disclosed any details on the first well either. But there are definitely gas discovery related to the first one, and there will be a drilling program of [ten years] beyond this.

And when will the second one be finalized? When will you (inaudible)?

It's not very far ahead, so I think we are quite deep into the well. Put it that way.

There's a question from Alastair Syme at Merrill Lynch. What lessons have you learnt from the problems at Kristin and Kvitebjørn that can be transferred to the way you approach future developments? How confident are you that you now fully understand the reservoirs on both fields?

Well, I think first of all I would just remind you that both for Kristin and the Kvitebjørn fields the developments that we have seen, they are actually not a surprise to us. If you go back to the plans for developing these two fields you will find this discussed and the challenges related to this really discussed in both of these development plans.

So the ambition has been to -- what you typically do on a high temperature, high pressure field is to drill all the wells before you start producing. So we have had a slightly higher ambition on these two fields and have developed technology, actually specific technologies to deal with it, which made it possible for us to start producing while we also were completing some of the wells.

This has turned out to be as challenging as we feared and we have to, really as I said, listen very carefully to the reservoirs. We are developing technologies and accumulating experience which I am sure will be very valuable to future high temperature, high pressure fields, and we are also exchanging significant experience between these two fields, from -- specifically from the Kvitebjørn experience into what we are doing at the Kristin field.

So I'm not saying that the strategy that we chose was wrong, it was an ambitious strategy and we are learning every day and we will be able to transfer that experience further and we also very much appreciate the support that we have been given from our partners and (inaudible) especially, some of the partners who have some experience on these kind of reservoirs.

Any questions from the audience?

You mentioned that exploration expenditure was increased by NOK1 billion to NOK9 billion. Can you explain more in detail what this is due to, whether this is an effect of cost inflation or are you doing more wells etc?

Well, this specific increase, you know when we estimated the NOK8 billion, we had a quite transparency into the cost basis and the specific rig situation and the rig rates that would be relevant for the 2007 drilling program. So what you we are talking about here is basically an increased activity level on the exploration program. So we are stepping up the exploration program; there was some adjustment within the exploration program that also tends to take the cost up a little bit, but it's mainly activity related and not related to the rates of the sources that did really well.

We have a question from Michael Murphy at Pioneer. Can you comment on progress of (inaudible)? What's the expected startup date? What's the likely production offtake? Is this secured on the gas sales agreement?

Well the (inaudible) has been progressing quite well lately; Shell has been doing a good job and there are good progress. I think the production startup estimated is still late 2009, but there are uncertainties on the specific dates that it is arranged obviously in that kind of project, but we are still talking about late 2009 as the base case for this being -- for first production.

That's a question from Michele Della Vigna at Goldman Sachs: Are you looking for a refining partner, pardon me, for the Canadian heavy oil operations?

I think now we have to get the acquisition in our firm. That's the first priority, get all the formalities and approvals in order and access the necessary market share. Then we will integrate into the existing organization and look further into the development plan. The base case, as we have said, at the time of the acquisition is an upgrader solution. So that is the base case for the development; that doesn't exclude that we might consider other alternatives, but at this stage there's nothing else on the base case which is sort of what we (inaudible).

Any questions from the audience?

Hi, it's Peter Ramsay from Argus. Going back to your Gas sales business. Given that you've made a slight loss there and you've said that you've sold more gas in the UK due to reduced long term continental offtake, is it fair to say that a decision has been made there to maximize production and sales rather than look to protect the revenue? And if so, will that continue through the rest of the year?

I can assure you that everything we are doing on the gas side is to maximize value. So we haven't been -- this is -- depending on way you look at the market and the way you look at the alternative and the forward way for looking at the market as well and we don't -- there is nothing in our ways of looking at this which takes into value destruction. So for us this is value creation, the way we look at the market and also the future of the market. And if we come to a situation where we felt that now we were destroying values then we would not go for production volumes, but to give the highest priority to creating values for shareholders.

There's another question from Theepan at Morgan Stanley. Could you comment on the underlying cost inflation you're experience on the NCS?

Well, I think NCS is not very different from what you see in any other part of E&P business; it's a global supplier market out there. So there are no different (inaudible) significant cost increases on most kind of supplies starting with accessing rig and new rig commitments into engineering services and fabrication and marine operations and subsidy equipment typically. We have seen some quite significant cost increase. So for that, the picture that you see basically the same picture on the Norwegian continental shelf as you have seen internationally. And it's quite substantial, put it that way.

When it comes to the operating costs, it takes more time. We have a base load of operating contracts and supplies into operations and it takes more time to see the significant impact coming into our cost base. But also on the operating costs some of the increases that you have seen prevail is coming from the increased cost of supplies, but some is also coming from the lower volumes that we have talked about and some also related to actually higher activities and some also related to high volumes of new fields that is getting into production or ramping up. Well the cost is there, but all the volumes are not there yet. That's also impacting our operating costs (inaudible).

So the question on accounting from Christine Tiscareno at Standard and Poor's. What are your deferred taxes for 2007 or do they disappear under IFRS?

Well, they don't disappear. I think (inaudible) could you try to comment on that?

Yes, for 2007 that would be an estimate implying many things, among others to give an estimate of the profit for the year. But the deferred taxes, they don't -- they are not removed under IFRS. What we get is deferred taxes on the differences between US GAAP and IFRS. So the deferred tax situation is just an implication of the differences between IFRS and US GAAP and all other is mainly remaining the same.

Alright. There is another question from the Internet, Barry MacCarthy at ABN Amro. Do you see a high -- do you see a risk that UK gas prices next winter could again be significantly lower than comparables prices in continental Europe? Are you assuming prices in the UK will be equivalent to European prices next winter? Are you confident new -- sorry, let's just take that first. So we see a risk that UK gas prices next winter could again be significantly lower than comparable prices in continental Europe and whether we assume that prices in the UK will be equivalent to the European prices next winter?

Well, that's a lot of factors determining the gas prices in the next winter. Obviously, this winter we saw significantly lower gas prices compared to last winter which was quite extreme. More volumes and more gas from the new pipeline from the Norwegian continental shelf and also that pretty mild winter was the important factors in that respect.

When it comes to next year we will have more gas coming in and the Ormen Lange field obviously, is going to be an important contributor to supplies into the UK. And there are also additional L&G -- a couple of L&G facilities that have been planned for and will come into place next year. On the other hand also, there is still a decline in the indigenous gas production in the UK. So where the balance of this, and combined with weather conditions and the [interconnector from] hazards from the work is very hard to see. I don't exclude anything actually, next winter, due to the factors that I just mentioned. But as I said, there is an interconnector that could -- and there is also L&G in this which could add to the flexibility and give the correct balance between the continent and the UK.

There's a question from Neil Morton at Man Securities. In natural gas, can you explain your thinking behind your decision to lock margins to 2009?

I think it's -- what we're talking about is more portion of our volumes distributed, some in 2008 and 7, 8 and 9. So this is the pure -- have a look at the market view, and I will look at it. It's not a strategic change in the way we do this business. But the reasoning behind it is quite obvious, but I'm not standing here and explaining that because that's not commercial considerations and I wouldn't disclose the way we're thinking behind this [fixed] positions.

But there's a follow-up question from Neil saying, does this imply that you are worried about margins going forward?

So that's the kind of answer that I wouldn't like to provide because this is a pure and integrated part of the way we are doing trading and optimization in our Gas business. And specific reasons for this, I'm not prepared to discuss.

There's a question from Theepan at Morgan Stanley. Can you point out some of the more important or high impact prospects within the 2007 exploration program?

Well, as I said, there is a quite substantial drilling program ongoing. On the Norwegian continental shelf I would say the most significant wells with the highest potential is probably the Midnattssol drilling that we will do towards the end of the year. And we also acquired 20% from Shell, so we'll now have a 50% interest in the Midnattssol with quite a substantial potential and it's in the same license as we made the [Aleda] well was drilled. And that provided us with a combination which we think is making this quite attractive.

The other one I would mention is something which is called [Luksan] in the south -- in the [Vøring] basin which we also consider is a new area for us and we consider that also to be quite interesting from an exploration perspective on the Norwegian continental shelf. Obviously we'll also do further exploration in the north (inaudible) to support the way we look at the further development of the Snøhvit gas development. And there are a lot of other wells, also further wells in the Sleipner area where we did the Ermintrude discoveries, so these is quite interesting for us.

On the International side I would just highlight the ongoing well obviously on the Shah Deniz in Azerbaijan; that's an expensive well. That's been going on for a long time, but obviously there is potential -- the potential is there. And in Plataforma Deltana Venzuela we're drilling the second well, We have the (inaudible) opportunities obviously due to the size of that opportunity. And we also do -- are also doing drilling in the Gulf of Mexico on the Julia and we're doing north (inaudible) and also have this year. So all of that is quite exciting work.

There's a question from the audience here.

Eric Nasby from Handelsbanken, a quick question on Snøhvit and the potential for the oil zone there. Can you talk a little bit about developments there going forward, what's expected, what's the plan?

Well, as you know, there has been a discussion in the license group which finally concluded to drill an additional well. So we will start drilling a well to further define the potential within the oil (inaudible) and I think the well will be [spurted] in June or July of this year. And I think the important -- the potential from that well is quite important as to the side of potential development.

We're also looking into potential ways of looking at this combined with Goliat on the [oil site] area. And there is -- if everything succeeds and we're determined to go on with this you could see potential production from this by, let's say 2011 something like that.

There's a question from Michele Della Vigna at Goldman Sachs. How's your thinking about the new phase of gas development, the Troll proceeding, what's the likely timeline?

Well I think there is enough, it's -- there's a lot of work ongoing on that and it's too early to conclude on the specific timeline for the gas -- potential gas development of the Troll (inaudible) development. But no, no specific timeline actually at this point.

Any more questions from the audience? It doesn't look that way. We've got a number of very detailed questions I would say that we will make sure that -- from the Internet, that we will make sure that you get answers to. But apart from that I'll just say thank you very much for coming and goodbye.