Equinor ASA (EQNR) 2008 Q1 法說會逐字稿

Ladies and gentlemen it's now 1.30 Central European Time. Good afternoon and welcome to this first quarter earnings presentation of StatoilHydro. Welcome to the audience in Oslo. A very welcome to the audience following us from the Internet, on the webcast. If you please be aware that you can actually send questions to me and I will ask them on your behalf during the Q&A session after this presentation. You can actually already start sending in questions now if you use the submit question button on your screen.

The presentation we'll use today is the one that you have been able to download from the Internet since 8 o'clock Central European Time this morning. And it can be downloaded if you use the download button on your screen.

To take you through the financial highlights for the first quarter 2008, it's my pleasure to welcome StatoilHydro's Chief Financial Officer, Eldar Saetre.

Well thank you Lars. Ladies and gentlemen, mostly gentlemen I think here today. It's a real pleasure for me to present the first quarter results for StatoilHydro. The main message today is that both our operational and our financial performance has been good during the quarter. We have grown our oil and gas production as planned.

However, and not surprisingly, the single most important factor that explains the development in our results is obviously the development in the commodity environment. Our realized oil price in the quarter was close to $94 per barrel, and our realized gas prices was above NOK 2 per standard cubic meter. We have also seen that the US dollar has depreciated further towards the Norwegian krone during the quarter. And this development is obviously impacting our operating income negatively, but then again both our cost base and our financial items is impacted positively. I will come back to the financial and operational details later, but let me first take a brief look at the highlights of the quarter.

There are basically four main characteristics of the deliveries this quarter. First of all, and as already mentioned, we delivered strong financial performance. Secondly the oil and gas production is, overall, in line with our own expectations. The first quarter production is reflecting a typical high seasonal gas off-take combined with very limited turnaround activities, both on the Norwegian shelf and outside of the Norwegian Continental Shelf. I should also mention in this context that we have actually started production from six new fields combined on the Norwegian Continental Shelf and internationally during the quarter so far.

Thirdly our exploration efforts continues at a high level, and I will come back to this, but we definitely think it pays off. On the NCS we have made 12 new discoveries so far this year. Most of these are located close to the existing infrastructure, and this means that the development can be made quite efficient, and the time from discovery to production also is potentially short.

And finally, we have strengthened our international positions, both in terms of the continued high exploration activity, adding three new discoveries so far this year, the strengthening of our long-term acreage position, and adding a new operator ship and enhancing our position in Brazil.

I will again revert to all of these issues later in the presentation, but let me just start now with an overview of the financial data. The net operating income for the first quarter was NOK 51.4 billion. This is up 49% from the same quarter last year and 67% compared to the fourth quarter last year, which was influenced significantly and negatively by almost NOK 14 billion in merger-related and some other non-recurring items. If you exclude for these one-off costs, in the previous quarter, the first quarter net operating income was up 16%.

The oil price increased by 42% in Norwegian krone and 66% in US dollar from the same quarter last year. Lifting of oil and gas was at 1,836 million barrels per day, which is down 3% compared to last year. Entitlement production however was up 4% and equity production overall up 8% compared to last year. We had an aggregate underlift position of approximately 40,000 barrels per day this quarter, impacting our net income, while in the same quarter last year we had a positive overlift of approximately 80,000 barrels per day. So this difference in the lifting position of 120,000 barrels per day had a negative impact on the net operating income of approximately NOK 4 billion on a quarter-to-quarter basis.

And then, not surprisingly again, there are various non-recurring items also in this quarter; I will review this later on. But the overall net effect of these items is a negative NOK 0.4 billion on the quarterly net operating income.

Net income in the first quarter amounted to NOK 16 billion, and this is up 62%. And I will now illustrate how we arrive at this number from the operating income of NOK 51.4 billion. And as you know, this is a story about financial items and taxes. The net financial items were NOK 3.9 billion positive in the first quarter, and this is compared to NOK 1.2 billion in the same quarter last year. This net increase, of NOK 2.7 billion was mainly due to currency impacts caused by weakening of the US dollar versus Norwegian krone totaling NOK 3.7 billion in the quarter. The gains are related to the Norwegian krone hedging strategy on our long-term debt, as you are aware of, and also currency impact from our short-term liquidity management. The net financial income as such was NOK 1.6 billion in the quarter, of which NOK 500 million was a one-off interest income from a tax dispute with a Norwegian state, related to tax treatment of asset removal cost.

Then to the taxes, NOK 39 billion, and the income tax rate in the quarter was 71%, which is down from 72% in the same quarter last year, and close to 80% in the very special quarter we had in the previous quarter. The decrease in the tax rate was mainly due to this time, a more, I would say, typical relative distribution of the oil and gas revenues between Norwegian Continental Shelf, taxation and other tax regimes.

In addition the profit from the net financials was higher this quarter, as you have seen, and these incomes are typically subject to a lower than average tax rate as such. I should also mention that the one-off items also in this quarter have a slightly negative impact on the tax rate. These comments on the financials and taxes takes us to the net income, actually a record income in the short history of this new company, of NOK 16 billion.

So I will now move on to look at our most important value driver, the production. Our average daily equity production in the first quarter was 2,048,000 barrels per day, which is up 8% combined from last year. 40% of this equity production was gas and approximately 23% of the equity production was related to production outside of the Norwegian Continental Shelf. The average daily entitlement production, that is after volume impact from production sharing agreements, was 1,889,000 barrels per day, which is up 4%. So this implies actual production sharing effects of 159,000 barrels this quarter compared to 79,000 barrels in the same quarter last year.

As already mentioned, the NCS production in the first quarter of the year is typically quite high, related to the gas off-take in Europe is normally higher in the first and fourth quarters, compared to the second and third quarters. The oil production typically has the same seasonal variations, as the maintenance activities mainly are scheduled for the second and third quarter. We expect oil-related maintenance activities in the second quarter of approximately 55,000 barrels per day combined for the Norwegian shelf and outside of Norway. And close to 100,000 barrels per day of maintenance activity in the third quarter, again combined for the whole portfolio.

So overall I think we have delivered a solid production performance in this quarter. And the short version is that we are on track to deliver the equity production as we have guided of 1.9 million barrels for the year as a whole.

Then a few comments also to our unit production costs. Our overall entitlement based, production costs per barrel was NOK 45.1 which in krone per barrel for the last 12 months ending this quarter. Based on equity volumes, the unit production costs were NOK 41.9, compared to NOK 29.3 in the same quarter last year. This quite significant increase is mainly due to the restructuring costs that we talked about in the fourth quarter but also from startup new fields, increased maintenance costs and general cost inflation in the industry.

So if we adjust for the restructuring costs, and also costs related to purchase of gas for reinjection mainly at the Grane field, the production costs per barrel of equity production for the last 12 months was NOK 31.6, as you can see on this slide. And this number, this is comparable with the guidance that we have given you on NOK33 to NOK36 for the period 2008 to 2012.

Then I would like to summarize some of the main deliveries and business developments in this quarter. At the very beginning of our value chain we have added important new acreage position to our exploration portfolio. We have won 16 new licenses in the deepwater Gulf of Mexico, central area lease sale this quarter.

In addition we were the highest bidder for 16 leases in the Chukchi Sea in Alaska and we'll be the operator for all of these leases. I should reminder you that the final approval and award remains for both of these lease rounds and typically, that takes 90 days. I should also mention that the sale of our Gulf of Mexico shallow water or shelf portfolio has been completed in the first quarter this year.

In Brazil we agreed with Anadarko to take over the operatorship and the remaining 50% of the Peregrino field and again the deal is subject to approval by the authorities.

Moving to Angola, the Exxon operated Mondo field in Block 15 has started production. And also in Azerbaijan the operator BP announced that the third phase of the ACG development has started producing. The deepwater Gunashli is expected to produce approximately 320,000 barrels per day at plateau and the StatoilHydro share of this ACG development overall is 8.56%.

Then to Shtokman; the Shtokman Development Company was formally established in February, through an interim shareholder agreement and the first major task, as you know, of this company is to prepare the feed study for the Shtokman field.

Finally, in Norway, several new fields and important developments have started producing. And we also matured new resources by submitting plans for development and operation of two new developments, the Yttegryta and the Morvin fields.

Let me then take a look at the exploration achievements. A total of 32 exploration wells including appraisals and extensions have been completed so far this year. 13 of these wells are still being evaluated, as you can see on this slide. On the Norwegian Continental Shelf we have completed 16 wells altogether. 12 wells, the green ones here, have been discoveries so far including two discoveries on the Oseberg area which was announced actually this morning. As already mentioned, many of the NCS discoveries are located close to the existing infrastructure with the potential for quite fastrack developments.

I would like to remind you that we have made an interesting discovery in the Obesum well in the Barents Sea where StatoilHydro actually has the 100% ownership. It's far too early to conclude on the size and the reservoir characteristics of this discovery, but it definitely strengthens our view perspective on this area of the Barents Sea, and we actually plan to drill one more well in this license already this year.

Outside of the Norwegian Continental Shelf we have also completed 16 wells so far this year. Three wells have been concluded as discovery and 13 wells are still being evaluated. We have made another discovery in the Hassi Mouina in Algeria and oil discoveries in the Big Foot, the Sidetrack and in Block 1506 in Angola.

So all together we are quite pleased with the results from the ongoing exploration program and we maintain our guidance of 70 wells to be drilled for the year as a whole.

Then to the financial results, a few comments on each of the business areas starting with E&P Norway. And the net income for this business segment was NOK 42.2 billion compared to NOK 31 billion in the same quarter last year, and this is up 36%. The increase was mainly due to a 40% increase in the realized oil price for the segment in Norwegian krone which contributed NOK 10.5 billion to the increased income. An increase in the transfer price of natural gas by 12% to NOK 1.55 per cubic meter also contributed close to NOK 2 billion. In addition, an increase in the lifting of natural gas of 14% added NOK 2 billion to the operating income.

These increases were partly offset by lower lifted volumes as already mentioned. The total production was up 5% while total lifting was down 1% on the Norwegian shelf. This implies the negative change in the lifting position of more than 90,000 barrels on the Norwegian Continental Shelf. And this impacted the operating income negatively by NOK 3 billion alone. In addition we have small increases both in the operating expenses and the depreciations mainly due to new fields coming onstream.

Then a few comments also to our other E&P segment, addressing the upstream business outside of the Norwegian Continental Shelf. The net operating income for this part of the business was NOK 4.3 billion compared to NOK 3.1 last year. And again, the main explanation, main driver is the 51% increase in the oil price measured in Norwegian krone. And this added NOK 3.5 billion from the first quarter last year.

In addition we had gain from sale of assets which added up to approximately NOK 800 million. So these positive changes were partly offset by a decrease again, as we saw in the NCS, in lifted volumes, both the equity volumes and entitlement volumes had a positive development. So this means that we also, outside of the Norwegian Continental Shelf, had a negative change in our lifting positions. And this implied an additional NOK 1 billion negative development on a quarter-to-quarter basis.

Exploration expenses outside of the Norwegian Continental Shelf were NOK 3.6 billion in the first quarter compared to NOK 1.1 billion last year. And the increase is related to higher drilling activities in general and an impairment of a deepwater exploration asset in the Gulf of Mexico.

Our Natural gas business segment had a net operating income of NOK 1.9 billion in the quarter, compared to NOK 0.7 billion last year. This increase of NOK 1.2 billion was due to a 16% increase in the prices of natural gas adding NOK 3.7 billion to the operating income.

Higher sales volumes increased the income by approximately the same amount. And in addition NOK 1.5 billion came from positive changes in the fair valuation of derivatives. The main offsetting factor to these increases that were the higher cost of goods sold, which reduced income by NOK 7 billion, approximately NOK 7 billion. Natural gas, or entitlement volumes for the first quarter was 10.9 bcm compared to 9.2 last year, an increase of 18%.

Then I should also mention that we have revised the formula for our internal transfer price for gas between the E&P Norway business segment and the natural gas business segment. So from January 1, the new transfer price is reflected the weighted average of volumes sold into three different price regimes.

For the long-term contracts, where the gas price, as you know, is linked to a basket of products, there we have defined a back-to-back arrangements, and adding fixed margin on top of that. The transfer price for gas indexed contracts and sales activities are linked to NBP in the UK, and for LNG, the US the Henry hub quotation is used when this is relevant. This new transfer price formula and the actual transfer price for the quarter will be calculated at the end of every quarter, as soon as we can, and published on our website in due course before the quarterly result presentations.

Finally, a few comments also to our Manufacturing and Marketing segment where the net operating income this quarter was NOK 1 billion compared to NOK 1.4 billion in the first quarter of 2007. The result for the Manufacturing part of this business was down from NOK 1 billion last year to NOK 0.5 billion this quarter, and this decrease was mainly due to lower refinery margins driven by a strengthening of the Norwegian kroner versus the US dollar, combined with an increased spread for the light sweet crudes that typically fits into these refineries.

Net operating income for our oil sales, trading and supply, in the first quarter was NOK 200 million compared to zero in the same quarter last year. This difference was mainly due to the positive change in the value of inventories, then we had negative currency effects, and somewhat lower trading results this quarter compared to previous quarters.

Net operating income for Energy and retail was approximately NOK 300 million in the first quarter compared to NOK 400 million in the same quarter last year, and the main reason was that we had -- was related to - NOK 100 million related to the final settlement of the sale of our retail business in Ireland in the previous quarter.

So let me now summarize the results for the segments, and at the same time give an overview of the, what we call, the infrequent items impacting the income statement this quarter. As already mentioned, the aggregate of these items have a relatively small negative impact on the corporate results, although the impact is somewhat bigger on the individual business segments.

The results for E&P Norway was negatively impacted with NOK 0.2 billion from one-offs. This was due to the overlift situation that I just described influencing the results negatively by NOK 1.2 billion in the quarter, and a positive impact of NOK 1 billion related to the change in fair value of derivatives from so-called earn out agreements from previous years transactions.

In the International E&P segment, the non-recurring items added up to NOK 2 billion net in the quarter. The already mentioned impairment of an exploration asset in the Gulf of Mexico was NOK 2.1 billion. In addition, the change in lifting position, as I mentioned, had a negative effect of NOK 0.7 million, and sale of asset, a positive effect of approximately NOK 8 billion.

Natural Gas was impacted negatively with NOK 1 billion from infrequent items, coming mainly from valuation of various derivatives. Within Manufacturing & Marketing, there was a positive adjustment of derivatives of NOK 0.4 billion, and a positive inventory adjustment of NOK 0.3 billion. Then the so-called Other segment had positive contributions also from sale of assets mainly. And finally, the last one, the Eliminations had a positive impact of NOK 1.3 billion, which is related to realization of values from reduced oil stocks.

So then, adjusted for all of these non-recurring items, the net operating income would have been NOK 51.8 billion for the quarter against NOK 36. 4 billion last year, and this is an increase of 43% on a type of normalized basis.

So let me now switch to the outlook for the second quarter that we are in the middle of already. And, as already mentioned in the presentation, our oil and gas production in the first quarter has been solid and as expected. We actually had no maintenance activities on the Norwegian Continental Shelf in the quarter, and only minor maintenance scope outside of the NCS.

In the second quarter, however, we expect a corporate impact of approximately 55,000 barrels per day, and in the third quarter close to 100,000 barrels per day. These estimates, they exclude the impact from a scheduled maintenance stop at Snohvit, which was shut down as planned on May 8 this year for an approximately two months maintenance period. The gas off-take from the long- term take or pay contracts is expected to be reduced in the second and third quarter, as already mentioned. And finally, we will continue with high exploration activities and maintain our guidance on this activity.

So to conclude my presentation, I would just like to remind you on the guidance that we have given you, and that we are going to repeat now. Short version is that there is no changes. We maintain our guidance. Equity production of 1.9 million barrels for the year as a whole, increasing to 2.2 million per day in 2012.

Capex program, at NOK 75 billion this year, approximately NOK 80 billion in 2009, and to remind you this is at a currency exchange rate of NOK 6 per US dollar, and a big part of the spend here is actually related to US dollar. We plan to drill 70 exploration wells at a cost of around NOK 18 billion, again, with the same currency assumptions. And finally, the unit production costs based on equity volumes is in the range of 33 to 36 for the full year, as I've already mentioned.

So this concludes my presentation, and I leave the word to Lars to take us through the Q&A session.

Well, thank you very much, Eldar. We're now open for questions, and I'd like to remind the audience here in Oslo please to wait for the microphone so that the web audience can actually listen to your question at the same time. And also, remind the web audience that you can send in questions from your screen if you use the submit question button right in front of you.

Just to open questions, I'll take one first question from Aymeric de Villaret at Societe Generale. After very good production numbers in the first quarter, is it possible to have some guidance for the second quarter, including maintenance, if oil price will stay at $120, and also for all the year at the same oil price?

Well, I think that's pretty much covered the second quarter with the details that I can provide you on the specifics of the maintenance activity, 55,000 barrels per day, mainly on the Norwegian Continental Shelf but also some activities outside of Norway.

Seasonal gas off-take, typically, is down compared to the higher off-takes that we have seen in the first quarter. So, beyond that, I don't think I can provide any more specific guidance as such. Obviously, also there will be production sharing impact, and, as you know, those will depend on the actual oil prices, and the earnings that we have made accumulated on each oil individual production sharing contract. And we have previously given you some guidance as to how this could look for the year as a whole, depending on different type of oil prices.

Right, thank you very much and with us here at the podium, we also have the Head of Performance Management in StatoilHydro, Torgrim Reitan, to answer questions together with Eldar

Next question from the web. It's from Theepan at Morgan Stanley. What was the rational behind changing the method of internal gas transfer price calculation?

Well I think this was pretty much reflecting the development that we have seen in the gas markets where they're very strong and more or less linear link between oil and gas pricing not as strong as it used to be. In particular on the high oil price levels that we have seen lately. So for us the old or the previous mechanics here was directly linked to brent blend, it was not even linked to gas oil or fuel or any of other elements that typically move into this basket. So this -- we think this now is a better reflection of how the fundamentals of the gas markets out there is actually behaving and also reflecting the fact that we are increasingly also selling volumes outside of the long-term contracts and including L&G from the Snohvit field.

Any questions from Oslo. Arctic Securities, Trond Omdal. Just one quick question on international project. Agbami is one of your major projects, could you say anything, is that on schedule? Will it come in end of Q2 or Q3?

The short version, just referring to the operator, saying that the field will be in production during the third quarter. So that's also our -- the piece of information we can provide.

Take another question from the Internet. It's from Colin Smith at Dresdner. Can you provide us with an update on Snohvit, with a detailed assessment of the extent of the issues there?

When it comes to Snohvit I could say basically we have been operating the plant now, at 60% capacity. So that's the capacity we're able to operate at when we are operating. Now we have been planning a maintenance shutdown for quite some time, so the plant was shut down and that process went smoothly on May 8. It will take approximately two months to do that planned activity, it's a complex activity to basically open up the facility and moving in there.

So what we will do is to do a lot of planned activities to make the facility more robust as such for future production -- maintaining future production regulatory. We will also install a lot of equipment, measurement equipment to measure temperatures and a lot of other stuff, flows and so on, that can help us to find the best prescription for how to increase the permanent capacity up to full capacity from the 60%, that's our capacity at the moment.

So basically we believe that we will spend most of the year, so 2008 to actually conclude on that and it's very important for us to have this firm plan and a firm project that really can take the capacity from 60% to 100% on the plant. And I would say also that I do not exclude that there could be potentially some repair work and maintenance work being done later this year, but that has not been planned specifically so far. But I don't exclude that opportunity.

The activity that is tailored to increase the capacity, beyond the 60%, that's the main idea for us now is to do that during the second half of 2009. So hopefully that will have a significant impact on the capacity and take us up to 100% better. When I talk about Snohvit I think it's important to underline that it's -- there is still uncertainty. We haven't got the full prescriptions yet, we don't understand the problem fully. We understand quite a lot of it but we still need these maintenance activities and the rest of the year to really digest and come up with a firm plan. So this will lead into a project that will be set up separately to increase the capacity and, as I said, hopefully that will be done during next year.

And that was basically also an answer to Barry MacCarthy from ABN, who also wanted to know about Snohvit.

Next question is from Adam Porter at Argus Media Group. The Norwegian Government says it will increase its stake in StatoilHydro to over 66.7%. Do you have any update on where we are on that?

No I will not elaborate on this, I don't have any update. I know nothing basically and I don't want to know anything about it either. So I have no information about this, other than you have actually. We share the same information.

Then there's a question from Paul Spedding at HSBC. Could you update us on the progress of planning and timing for the next phase of Shah Deniz, especially where is the export line going, which destination are you going to take the gas to?

Well the short answer again is that we don't know where the gas is going. We are at the moment we are exploring alternatives and we appreciate alternatives and basically for us it's to take the gas where the value could be -- where the value chain could create most values for us. Basically this is a discussion that will have to be taken within the sellers Group of Shah Deniz, so all the partners joining us in this Group will have to join us in discussing the relevant options. So at the moment we are, as you know, we have taken a position in the TAP, potential pipeline going into Italy. So definitely we believe that could be an interesting option but we still consider that to be only one of the options for taking this gas into the market.

A question from Neil McMahon at Bernstein. Production guidance, production looked better than forecast even at high production -- high oil price PSA conditions. You have provided some guidance today but the reference conditions are not clear, are they $75? But if they continue at the $100 level for the year, what production do we estimate for 2008 and 2009?

Torgrim would you please address that?

At the capital markets, we show our guiding on equity terms and then we provided the guidance on PSA effects at various prices. We said that the $75 per barrel on average in 2008, the PSA effect will be 150,000 barrels per days, at $100 per barrel it would be approximately 180,000 barrels per day. So that is the current guiding related to that and if relevant to provide guiding on an even higher oil price as such. We will come back to that on later occasion.

Okay, we have a question from Alastair Syme at Merrill Lynch. There are a lot of different ways of looking at production unit costs, but could you tell us what we would adjust for in terms of merger related costs to make the first quarter '08 entitlement production most comparable to the 1Q '07 entitlement production? Cost -- production cost sorry.

I think this is actually all laid out in one of the tables in the MD&A where we reconciled from the reported unit production costs to both entitlement and equity terms, adjusting both for currency rate. And also for the one-off effects, merger related. So in the condensed version is that we want to be measured in equity terms related to this because the PSA effects are very uncertain. And we also think the most comparable number is adjusting for currency effects and the one-off numbers. So the number for the first quarter is NOK 31.6 per barrel and that is comparable with the guidance that we have provided and Eldar talked about a few minutes ago.

Thank you. There's a question from Thomas Williams at TH Williams Consulting. Can you provide us any more detail on StatoilHydro's involvement with Petrobras in developing the new offshore deep water fields off the coast of Brazil and Rio de Janeiro? Thank you.

Well to my knowledge there is no involvement in developing -- from our side, in developing any of the recent giant discoveries that have been made in Brazil. We are not involved in any of those discoveries. We have an extensive exploration program coming up in Brazil. We have a position of 11 licenses now and we will start on the first exploration effort this year. But that is not in any way related except for actually we have three licenses located in the same Santos basin, but they are not in any way connected to the discoveries that you are referring to I guess.

So what I could say generally is that we are working closely with Petrobras on many other aspects, including some of these exploration opportunities. And we also have an MOU with Petrobras addressing also some other issues. But in terms of the discoveries that I expect you are referring to, there is no -- we have no sort of cooperation with Petrobras on that.

Just another question from Theepan at Morgan Stanley. Can you talk about the outlook for summer gas prices? They're particularly strong, have you sold ahead into these strengths?

Generally, I don't think I would like to comment on any of the transactions that we might do in the market as such. So when it comes to the summer prices, again we are a significant player in the market and in the UK market. And for us to comment on specific beliefs as to how we look at the price outlooks, I think that wouldn't be proper for me to do, from a commercial perspective.

There's another question about gas from Colin Smith about Ormen Lange. Given the strong performance from Ormen Lange, can you provide more visibility on what production ramp-up might look like now that you have had some months of operating experience? How is the drilling program of Ormen Lange going?

Well there have been some issues on the drilling. We should be back on track and we have three wells producing from Ormen Lange and now we will expect to have two more wells in place during the second half of 2008. Then we expect the full capacity to be in place at the end of 2009, beginning of 2010. So basically, that is the profile and I guess also a more or less linear profile from the point where we are today.

Alright. There's another question from Neil McMahon at Bernstein. Exploration success looked to be strong in the quarter, but were any of the fields substantial in nature?

Also can you give us an update with regards to the Gulf of Mexico and the St Malo 3 appraisal well and the Julia 2 appraisal well?

Well when it comes to the exploration achievements, we are not disclosing drillout volumes for the aggregate nor for any of the discoveries as such. But I think the short version is that there are no elephants, no really big discoveries in this portfolio. In particular on the Norwegian continent, there's a lot of smaller discoveries, as I said, close to existing infrastructure. However there are a couple of other discoveries which are quite interesting and I mentioned one of them, the Obesum. So I think that's what I can say on the NCS. We have approximately five, six high impact wells on the Norwegian Continental Shelf that we planned for this year.

When it comes to the Gulf of Mexico and specifics, I'm not in a position to disclose any details, but when it comes to the Julia well, I think that is planned for, but the exact timing of that, I haven't got that available at the moment.

There's another question from Alastair Syme. Since you made your full year '08 production guidance at the capital markets day, did first quarter '08 gas sales positively or negatively surprise versus expectations?

Well I would say the gas sales might have been slightly above expectations, but I think what we're trying to say is that basically that is not going to have an impact on the overall guidance that we have given. We typically have this seasonal pattern that I talked about and typically the gas year ends in the third quarter and then the volumes will have to be adjusted by the end of the third quarter to the overall commitments that are included in the long-term gas contracts.

So the off-take on the long-term contracts has been good, but it doesn't tell us anything really about what you can expect for the year as a whole.

Then we have a question from Jason Kenney at ING. Have you any update on the likely capital outlay for your Canadian heavy oil sales position? The phasing of new capital spend there and the likely split upstream and downstream?

Well when it comes to the Canadian position, I would say there are basically two projects that we are working on. The first one is to develop the pilot plant, the demonstration plant on the Leismer, that's a small development adding a potential of 20,000 barrels per day by 2010, it's 10,000 -- it's what we have been allowed to produce from that capacity.

When it comes to how we are going to develop the overall reserve base -- resource base, it's something that we are working on and that's our second project. To really look into all the alternatives that we see all the way from taking on an integrated solution in Canada, an upgrader in Canada, and adding various types of refinery arrangements and also diluting the crude and taking it out into the market as diluted crude.

So all these are options that we have and we are looking into all of these options and it's very important for us to take the time, spend the time that we really need to make sure that we get the best solution out of this and make the right choices. And so I would say doing the right thing here is more important than doing the -- necessarily the fast track solution.

What we have seen in Canada is that there has been -- that it's a quite busy cost environment which is definitely influencing the capacity to build upgraders and the cost of building upgraders these days, that's the one I mentioned that I could add to it. But providing any specific numbers of the barrels or whatever on cost in this environment in Canada, that's a tough one, but the direction has been in terms of cost increases for the upgrader type of activities.

Another question from [Geoffrey] Stone at Cheuvreux. You had in the first quarter, 2008, on the NCS a discount of around $3 per barrel on price realization compared to Brent. In fourth quarter '07, it was around EUR 50 or $O.5 per barrel. How do you explain the increase?

Well this is related to NGL and condensate which was tied very closely to oil prices and that situation has now changed. So our oil price is not only crude, it's also including -- it's including all liquids in the portfolio, so it's liquids and gas.

So NGL has had a much lower oil price, so basically I think when it comes to oil price as such, we are pretty close to the Brent plant, but including the NGL and the condensate into this, that takes it down to this average for the liquids as a whole.

Basically one question from two, it's from Colin Smith and from Neil Molten at MF Global. What is giving rise to further write-downs of the Gulf of Mexico's assets and are you at the end now, or is there a little more to come?

Well what I can say is that the combined company has made some transactions in the Gulf of Mexico, also involving various type of assets, asset producing assets, development assets and exploration assets. And what you have to do when you do an acquisition is up front actually to do an allocation of the purchase price. So you make an assumption as to where you actually will find the values going forward and in particular, when it comes to exploration assets, that's a tough one.

It isn't necessarily so that the value turns up in the same assets that you allocated the purchase price. So this is really what happens here. You have to do an impairment every quarter on all of these assets and in this case this has led to an impairment on one of these assets. And what could happen in the next quarter is that if the value of this asset is increasing, then you could actually, according to IFRS, have an upward revision of the valuation as such. So I think what you typically will see in the -- with the current type of accounting practices is that we will see more volatility in the balance sheet related to fair valuations.

Then Neill Morton from MF Global wants to know which are the assets? Are they ex-Statoil or ex-Hydro assets or both?

I think you just made a consideration and there are -- what I can say is that there are clear commercial reasons actually in this case for not talking about that or disclosing that so I will not go into any details on that, for that reason that I mentioned.

There's another question from Theepan at Morgan Stanley. Plant maintenance impact of 55,000 barrels per day in the second quarter in the North Sea liquids, what are the main fields? And is there any -- is there not any associated gas impact? And what do you do with that?

Well the -- the 55,000 as I said, that includes both the Norwegian Continental Shelf maintenance activity and the outside of NCS, the international maintenance activities. So -- but the main bulk of this is through obviously related to the NCS maintenance work. There is a lot of maintenance programs going on. I think we have something like 18 different maintenance programs on different platforms going on in the second and the third quarter, so it's all over the place.

So picking out the impact on individual licenses I actually, I haven't got that information, I don't think, for what kind of values that would really add to it. So I think overall it's 18,000, sorry 55,000. When it comes to gas, that's an area where -- this is liquid, so when it comes to gas, which is also related to liquids, that is dealt with -- we have a more flexible situation on gas and we are able to compensate for lost gas. That's also from this type of activities on production on other fields, typically the Troll and Oseberg fields where we have the flexibility. So you will typically not see any impact out there in our overall volumes from the gas side as such. So our guidance is liquids only.

There's a last question from Neil McMahon at Bernstein. Given the strong cash balance, the underleveraged balance sheet, should we expect the restart of the buy-back program at the AGM?

Well, as you know buy-backs is an integrated part of our dividend policy and it's in our tool box. This time we have selected not to use it so there will be no -- there's no proposition to the AGM on giving us a mandate for share buy-backs this time.

Question from Paul Spedding at HSBC. What sort of rates of cost inflation are you seeing? And is there any sign of cost pressure easing? If possible could you talk about cost pressures from different segments of the oil services business?

Well obviously we have been through a period of quite a few years now of quite a significant cost inflation, in particular on, I would say, on drilling and well related type of activities including subsea equipment and installations. Less so, but still quite significant on more facilities and labor intensive type of activities. We do see that this pressure is leveling off. There is a better balance than there has been in general, but there is still a pressure, upward pressure, on costs and the cost inflation in the industry and I would particular relate that to subsea related activities.

Another question from Barry MacCarthy at ABN Amro. Recent press reports suggest your Iranian South Pars project is about to commence production. Is this correct? And, if so, what volumes could we expect by year end? Are other Iranian projects on hold due to the political climate?

Eventually we are getting to see the end of the South Pars project so it has been there for some time. So we expect this project to be in production I would say during the summer. That's the current estimate. When it comes to volumes I haven't got the exact number but it's definitely less than 10,000 barrels per day of volumes and then it's a buy-back arrangement, as you know.

We are also involved in other activities in Iran related to service agreements on two exploration licenses. At the moment there is no physical activities whatsoever going on, on these activities so we are evaluating the opportunities and there are no development activities as such going on. And I can assure you we are very well aware of all kind of regulations and restrictions on activities in Iran and take this very seriously and any decision on the future activities would be based on these kind of considerations.

Well I don't have any more questions from the Internet. Any more questions from Oslo? It doesn't look that way.

Well then I have to say thank you very much on behalf of StatoilHydro. Thank you very much for listening and goodbye.