Equinor ASA (EQNR) 2013 Q1 法說會逐字稿

Ladies and gentlemen, welcome to Statoil's first quarter earnings presentation, both to the audience here in Oslo and our audio and webcast audience. My name is Morten Sven Johannessen, Vice President of Investor Relations at Statoil, standing in for Hilde Nafstad today.

Before we start, let me say there are no fire drills planned for today. However, should the evacuation alarm go off, you will need to exit through the four doors to the left of the building or this whole room. The security guards will escort you out of the building.

This morning at 7.30 Central European Time, Statoil announced its first quarter results for 2013. The press release and presentation for today's event were distributed through the wires and through Oslo Stock Exchange. The quarterly report and the presentation can, as usual, be downloaded from our website statoil.com.

I would ask you kindly make special note of information regarding forward-looking statements, which can be found at the last page.

Today's program will start with Statoil's CFO, Torgrim Reitan, going through the earnings and the outlook for the Company. As usual, the presentation will be followed by a Q&A session. Please note that questions can be posted by means of telephone but not directly from the web. The dial-in numbers for posting questions can be found on the website. The Q&A session will end at 2.30 Central European Time.

It is now my privilege to introduce Statoil's Chief Financial Officer, Torgrim Reitan.

Thank you very much, Morten, and good afternoon, everyone, and good morning to all of you in the US.

After two years, with yes, we had the record results, the earnings this quarter is lower than last year. In the first quarter we delivered earnings of NOK42b, and we produced 2m barrels per day. Our industrial progress is strong. Our guiding remains firm. And we are on track for our long-term ambitions.

Our financial results were impacted by reduced prices and lower production. We have earlier said that 2013 production will be lower than 2012 and this is due to commercial decisions we have made to increase value, like NCS divestments.

We produced broadly in line with what we needed for the full year. We produced record volumes from our international portfolio, and I'm pleased that we continue our profitable growth outside Norway.

But, we had disruptions at some of our largest fields, reducing production by some 50,000 barrels per day in the quarter. And this led also to a change in the production mix impacting the earnings further.

First, realized prices are impacted by a higher share of US gas and more NGL.

Secondly, the fields with disruptions have a very low DD&A per barrel, while the recently started ones naturally have a very high DD&A per barrel leading to a higher than usual DD&A.

Third, operating costs are not variable in the short-term and are not reduced when we have production disruptions. Oil sales are also impacted by quarter-specific items which I will refer to.

When it comes to cash flow from operation, that is down by NOK13b. That is 19%, and this is the result of reduced production and lower prices.

Our projects are progressing well. We have selected the concept for Johan Castberg in the Barents Sea formerly known as Skrugard and also for Bressay, offshore UK.

We have paused the final investment decision to further extend production at [SOCAR] in the Norwegian Sea and at Hibernia offshore Canada, and we have further progressed Aasta Hansteen in Norway and Mariner in the UK.

I'm very glad to see that we delivered the first wave of our fast-track projects. As you know, we standardized the development solutions for smaller fields, faster and cheaper.

Last year, we put Visund Sor on-stream as the first one. And this quarter, we started four more, Hyme, Vigdis North East, Skuld and Stjerne. All of these were discovered between 2008 and 2010. They have an average breakeven of around $40 per barrel, and there is more to come, so we are on track with fast-track.

We will make the concept selection for the giant Johan Sverdrup in the fourth quarter, and we will then return with more details together with an updated resource estimate.

And finally, our exploration team had another great quarter. We made the fourth high-impact discovery in Tanzania in just one year, bringing further robustness to our potential LNG project there. And then, we secured 15 interesting leases in the Central Gulf of Mexico, 12 wells were completed in the quarter with a 58% success rate.

And last but not least, we made a significant discovery at Gullfaks in the North Sea, [40 to 150m] barrels high-value barrels and there's a further upside potential.

In 2011, we announced our strategy for growth up to 2020. We have delivered the first wave of projects at 3% average growth from 2010 to 2012, and an 8% production growth last year. The first wave of projects are delivered without cost overruns or delays.

As you know, we expect a 2 to 3 percentage points average growth in the period from 2012 to 2016 but we have divested assets on the NCS and we have produced a lot for more value over volume strategy last year. So, we have said that 2013 production will be lower than 2012 and this will, of course, also impact earnings.

This quarter, as such, results are down. In addition to reduced production and lower prices, we had production disruptions at In Amenas, Snohvit, Peregrino and Troll. We have taken forceful actions to bring them quickly back up.

Snohvit started up after April 28, and is now at close to maximum capacity.

Peregrino is ramping up and yesterday it produced 75,000 barrels per day and it continues to ramp-up.

And we expect Troll to be back by end of the second quarter.

At In Amenas, two out of three trains have started. Timing and start-up of the third train is still uncertain.

We also saw changes in the production mix leading to a lower realized prices. We produced more US gas this quarter. However, realized prices in Europe are on par with last quarter.

The share of NGL increased to around 21% on NCS. And as you know, NGL trades currently at a $40 per barrel discount to Brent.

As every quarter, we make adjustments to results. On the NCS, we have adjusted for a one-off effect related to gas lifting. We had lower fair values of derivatives impacted -- impacting our net operating income.

And finally, we have adjusted for about NOK5b related to provisions on the Cove Point LNG re-gas terminal in the US.

In the current market, we expect not to use our capacity at that terminal. We have renegotiated and reduced our obligations and we are now making a provision for all of our remaining tariff payments.

Finally, the devaluation of the bolivar in Venezuela has impacted the results with some NOK600m. This is an after tax effect with no cash impact for Statoil. This effect is not adjusted for, but is part of the adjusted earnings.

Importantly, we maintain a firm underlying cost control throughout the period. We are keeping operating expenses at the fields stable and this is something I watch very closely. And I will come back to this in further details later.

Adjusted earnings after tax was NOK12b with an effective tax rate on adjusted earnings of 71.8%.

Now, over to the segments. Our Norwegian business delivered adjusted earnings of NOK34b. Compared to the same quarter last year earnings were mainly affected by the lower production and lower prices. And I will revert to costs and DD&A specifically.

From our operations outside Norway, the adjusted earnings were NOK5b. Our entitlement production grew by 16% and we now produce around one-third of our volumes outside Norway and this generated an EBITDA of around NOK12b. And if you look at the cash flow per barrel from our international portfolio, it is on par with our Norwegian production.

Marketing, processing and the new builds contributed by nearly NOK3b.

In total, we sold a similar amount of gas as the first quarter last year. However, gas production on the NCS was reduced, mainly due to repairs at Snohvit and Troll.

We have also increased our gas production in the US, as we are hooking up all ready drilled wells in Marcellus through the gathering systems and infrastructure.

The North American gas market is strengthening as demand has exceeded supply and gas storages -- gas storage levels are now below the five year average. We have also sold more third-party volumes in the quarter.

Overall, these effects decreased our average in (inaudible) gas price by 11%.

In the first quarter, we produced 2m barrels per day. This is own 9% from the same quarter last year. And as we said, we expect lower production in 2013 than in 2012. However, production could have been higher without disruptions. 1.3m barrels per day is produced from the NCS and 700,000 barrels per day from outside Norway; record international production and this is profitable growth.

On the NCS, the decrease is mainly due to the reduced share at (inaudible), the compressor issues at Troll, and the prolonged shutdown at Snohvit. And as you know, we have re-started Snohvit production this week.

We are also progressing well in replacing the compressor on Troll, and we expect to have most of the capacity back by end of the second quarter. Current reduced capacity at Troll, of course, reduces our flexibility somewhat.

Production was positively impacted by our fast-track projects, the ramp-up on SOCAR and we have also started production from the newly discovered volumes on Gullfaks.

In the international portfolio, we increased equity production by 6%. That is primarily gas. We are ramping up PSVM in Angola and we are continuing to ramp-up in the US onshore.

Following the terror attack on In Amenas, our production is significantly reduced there, impacting our overall liquid's production.

Then cash flow. Our cash flow from underlying operations was NOK58b in the quarter. This is 19% lower than during the same period last year. The reduction is fully explained by reduced production and lower prices.

We invested for NOK27b. This is in line with our estimate of $19b for the year as a whole.

Adjusted net debt to capital employed increased from 12.4% from year end to 13.3% at the end of this quarter. So, we continue to maintain a firm financial framework and a solid balance sheet.

Next quarter we will pay two tax installments.

A dividend will be paid late May NOK6.75 per share and that is representing a direct yield of close to 5%.

Now, let us take a look at our costs, starting with our operating expenses.

A large part of the costs at our fields are fixed in the short-term, and they will not vary directly with -- directly in line with changes in quarterly production. And this means that production disruptions will not lead to reduced OpEx.

We are working constantly to improve our cost position further. In Norway, we have kept the underlying total cost stable for five quarters now. And that is despite having more fields into production and despite industry cost inflation.

Within marketing, processing and renewables, the improvement program we have put in place is paying off. Quarterly variations will naturally occur due to seasonal changes in volumes.

In the international segment, we are growing and the growth in operational cost and SG&A is explained by higher royalties and higher transportation costs.

If you then move to depreciations. We see a stable development in DPN. And as you know lower production usually means lower depreciation. However, this is offset in the quarter by new fields coming on stream.

Fields typically have a higher depreciation at the start of their lifecycle.

This quarter, we have increased production at Skrugard, which is contributing with high depreciation close to NOK300 per barrel in DD&A from that field. This will, of course, decrease over time on that field.

We have also had lower production from older fields like Troll and Kvitebjorn and they have a depreciation of NOK20 to NOK30 per barrel, so it's a very, very big difference. So, as you can see, the DD&A in the quarter is impacted by the production mix.

Internationally, you will notice that we have improved the unit DD&A from the same period last year.

So, we will continue to improve the cost base. We are simplifying our processes and we are increasing efficiencies across the Company.

In April, we implemented the new staff organization across Statoil, and we reduce staffing by 800 [members]. We also continue standardization and industrialization as demonstrated by the successful fast-track initiative, and we continue to expand our portfolio of suppliers using the global market, further strengthening the competitiveness of our projects.

Now, let's take a look at the growth outlook.

As we have discussed earlier, all growth will not be linear. The production -- the lower production in 2013 is due to commercial decisions we have made; divesting NCS assets and realizing significant gains.

The Wintershall deal will impact production by some 40,000 barrels per day from closing.

We have reduced the rigs on Marcellus reacting to the price environment, and we have produced NCS gas at a high level in 2012 due to a strong market. And this leaves less capacity for 2013. So, this will impact the gas production this year by some 15,000 barrels per day.

The situation at In Amenas in Algeria will also affect output in 2013. In 2012, In Amenas produced 23,000 barrels per day for us.

Second, we expect a growth of approximately 2% to 3% per year on average from 2012 to 2016.

And third, in the more long-term, we see the growth accelerating from 2016 growing by some 3 to 4 percentage point on average a year as some of our big, new developments start to come on stream.

So, all in all, we are on track for ambition producing more than 2.5m barrels in 2020.

Looking at 2013, Snohvit, Peregrino and Troll will also affect our production in the second quarter. They are now back up while Troll will be back towards the end of second quarter.

For the next quarters, please also take into account the higher share of US gas and the current NGL share in our liquid production.

Finally, planned maintenance is expected to have a negative impact on the quarterly production, around 40,000 barrels per day in the second quarter. Most of this is planned outside the NCS. In the third quarter, maintenance is expected to reduce production by around 100,000 barrels per day, the majority on the NCS and more than half is gas.

For the full year of 2013, our maintenance program is estimated to reduce equity production by around 45,000 barrels per day and most of this is at our liquid production fields.

We will invest around $19b this year, bringing new projects on with a low break-even price across the portfolio and with industry-leading rates of return.

We expect to receive the proceeds from the Wintershall deal during the year, leading to that net investment will be less than $19b. $19b is a gross investment number.

We will explore for around $3.5b this year and plan to finish around 50 wells. And we will drill approximately 20 high-impact wells from 2013 to 2015.

I know you like to watch our wells, so let me give you some wells to watch in the shorter term.

We now kick-off three exciting drilling campaigns; the Barents Sea with Nunatak in the Johan Castberg area. And that is building in these days.

[Caixa Lofter] in Mozambique was spudded a week ago, and finally in East Canada with Harpoon West also recently spudded. So, it is exciting times for our exploration team and for all of us.

So, to round off, our financial results are impacted by disruptions and quarter-specific items but we are progressing according to plan. We set a new record for international production. We continue our robust project execution and we delivered good on exploration.

Looking ahead, we are well positioned to grow and create value. We continue to efficiently execute our projects. We maintain a firm financial framework. We continue to pay a predictable and growing dividend. And as you know, the Board has proposed to pay NOK6.75, and we will do all of this by keeping a very solid balance sheet.

So, thank you very much for your attention. And then I will leave the word to you, Morten, to lead us through the Q&A session. So, thank you.

Thank you very much, Torgrim. We will now turn to the Q&A session. Torgrim will be joined by Senior Vice President for Accounting and Financial Compliance, (inaudible); and Senior Vice President for Performance Management and Risk, Svein Skeie.

We will take questions from the audience and over the telephone. I will first ask the operator to explain the procedure for asking questions over the telephone. Please, Operator.

Thank you. (Operator Instructions).

Thank you. I would ask you to limit yourself to one question to allow for questions from as many of you as possible. We will start with questions from the audience here in Oslo using the microphone in front of you. Please state your name and the name of your company.

I would also like to remind you to remember to turn off the microphone after you have finished asking your question to allow the next question. First question from Oslo. Anne.

(inaudible -- microphone inaccessible).

Hold on. One second.

Anne Gjoen, Handelsbanken Capital Markets.

I have a question in relation to natural gas and natural gas prices. Because you've given before this result release, the internal gas price, it's a margin now of NOK0.10. I know that it's changed principles when it comes to this pricing. But is it possible to give some indication is this low margin and an indication of what we could expect going forward, or is this just kind of very weak in this single quarter? Thank you

Okay. Thank you, Anne. So, let me start and, Svein, you can add on if you like. The way that the internal price is working between natural gas and the Norwegian area is on a day ahead basis. I mean the average of day ahead prices for what is gas indexed. While natural gas, they have a lot of volume to deal within the market, so they typically sell quite a bit in the front months.

So, in a quarter where you have had rising prices on a day ahead basis, the internal price becomes higher than actually what natural gas has realized in the way they have sold the gas. So, I think that is the main explanation for the deviation this quarter and that explains the rather small margin on the natural gas side. Svein, something to add?

I think you have covered it well. It is also about the cost element that goes into it and how that is being recovered. So -- but it's based then on the prices on the long-term and then taking into account LNG prices as well and the spot prices and then a cost element.

So, what you could expect is that when prices moves in other direction you will see the opposite effect. And then, the natural gas business is no matter what measured on how much value they can add on top of what they pay for gas.

Next question. Could you turn off your microphone, Anne. Thank you. Next question please from Oslo.

Andre Benonisen, Danske Bank. What is realistic EBIT level from marketing division going forward?

Okay. Thank you, Andre. I think it is fair to say that we should expect fluctuations from quarter to quarter. Last year was a very strong quarter, a strong year in most quarter from that business.

If you divide it into the sub-elements, the processing facilities, the refineries, I mean they are very much a function of the refining margins, which is healthy this quarter. Costs have been taken significantly down.

On the trading side, you should also expect that it's from oil company, it is easier to make money in market with Contango than in backwardation due to that your long oil and long gas. So, the structure of the market would typical impact the returns.

So, they are performing generally strong -- generally very good contribution to the earnings but it will fluctuate quarter by quarter. So, this is a disappointing quarter on the trading side.

Another question. Could you give some more flavor on some of the important international fields like Peregrino and Caesar Tonga and also may Leismer?

Okay. Starting with Peregrino, Peregrino have the well capacity for around 100,000 barrels per day in production. We have had a turnaround this quarter that -- and then, we started up and then we had some issues on the top side. That is now solved, so it is ramping up. So, yesterday it produced at around 75,000 barrels per day.

On Leismer, production from Leismer is going very well. The energy efficiency is improving and the production contribution from Leismer in the quarter is around 18,000, 19,000 barrels per day.

And then you asked about --?

Caesar Tonga.

Caesar Tonga.

Caesar Tonga, after the start-up has performed pretty well and is now producing around 9,000 barrels, just below 10,000 barrels in first quarter of 2013 in the Gulf of Mexico.

Next question from Oslo please.

Ole Jacob Storvik, Fearnley Securities.

Can you say something about how we expect a ramp-up from Skarv and the fast-track projects in Norway. And do you also have a back-log of drilled wells in the Marcellus that you are completing today?

Okay. Thank you Ole Jacob. On Skarv BP is the operator there. So they are best to answer on that specifics. But you know it is producing well currently and it is continuing to ramp-up.

When it comes to the fast-track, we have now 12 fast-track projects in the portfolio on what has been started and what we're working on. In 2014 we expect that portfolio to produce around 100,000 barrels per day for us. So it's actually more and quicker than we expected when we started with these projects. So all of them have performed well and delivered, generally, earlier and at lower costs than we have expected.

So I think this is a concept that we are very enthusiastic about and we see the potential for this way of working. And we are looking at standardization and simplification across other projects as well.

When it comes to Marcellus, we have quite a lot of well in the inventory that waits for infrastructure, gathering systems to bring them to the high-pressured interstates. So the inventory there is several hundred wells.

And the way we work there now is that we have reduced the rig count and we drill one well pads that we can return to and drill five more and that is to keep the acreage. So we take -- we build up a pad and we drill one well and hook-up. So there will be a lot of very attractive wells to drill later in this area.

And, also, the Marcellus gas that is now being sold in Toronto. Statoil's Marcellus gas is sold in Toronto, generally around $1 higher than -- $1 or $1.50 higher than in the Marcellus area. And that uplift is very welcomed in the current price environment.

And now we'll take a question over the telephone. Please operator.

Thank you. We will take our first question from Lydia Rainforth from Barclays. Please go ahead.

Thank you. If I could ask two questions please. The first one on the cost base in the Norway side. You did say that underlying costs were flat against industry cost inflation. I'm just wondering where specifically Statoil is able to make savings within the cost structure.

And then the second one, if I could just have that one in, is on the level of disruptions that you saw in the quarter in Norway. Is there anything that you can do to actually improve the reliability or is this just something that we should factor in for some ongoing contingencies going forward?

Okay, thank you. First on costs, I'm very glad to see that all the efforts put in place is working. There's a lot of sources of that. One is the ability to take out synergies across assets and fields. One is related to logistics and optimizing that and then it's about procurement.

We don't have to procure on an asset-by-asset basis, but we procure on a portfolio level. That makes us able to have much more flexibility and also to capture opportunities in the market. So -- and then there's a list of -- much longer list on everything that is done in that perspective.

So I'm very glad to see that that is working and we have worked this pretty hard for a few years.

When it comes to the level of disruption, I will not read this quarter as change in how things work on the NCS. Generally, the technical conditions is very good. The -- when it comes to maintenance we use a lot of efforts to preventive -- on preventive maintenance before things happen and that has worked very well.

When that is said, I'm, of course, not satisfied with the disruptions we have said -- seen. Snohvit has had its challenges since the start-up. Peregrino is a run-in issue more than anything else. And Troll is an electric motor on one compressor, is related to that.

Perfect. Thank you.

Next question from the telephone please.

Thank you. We'll now take our next question from Haythem Rashed from Morgan Stanley.

Thank you. Good afternoon gentlemen. Thank you for the presentation. I have one clarification, if I may, and also one question.

Just firstly on the production, I know you highlighted where we are on the various different fields that were affected in the quarter, In Amenas, Peregrino and Snohvit.

I just wondered if we could give a bit of color in terms of how we should think about the impact to the full year. I know -- presume you're not willing to provide more specific guidance on the guidance you've already provided around production being lower year on year. But if we were to take into account some of the impacts we've had in 1Q and the knock-on impacts to 2Q, do you feel comfortable to offset that somewhat with some of the other impacts that you have, such that your initial assessment of production, you'd lowered year on year, is effectively the same? Or are you talking about incrementally lower within what you had talked about earlier on in the year.

The second question I had was actually just about Tanzania. I just wanted to get an update there. We see good progress being made around building the resource up there. [BG are] obviously providing updates recently.

Could you just provide us with an update on how discussions are going amongst yourselves as the partners in the blocks and whether there are any particular milestones that need to be achieved before we start to see development plans accelerate? Thank you.

Okay. Thank you very much, Haythem.

On production and the impact for the full year, if you take -- these are disruptions that we haven't planned for and so on. So, of course, it's sort of impacting without us having taken that into the forecast. When that is said, there's a lot of moving parts in our portfolio as well. We have the Gullfaks wells, the new discovery on Gullfaks. That is put into production right away and is producing well. So it is part of that and the totality, but I'm not ready to put forward any specific impact on an annual basis. But our guiding remains firm and the things are up and running, more or less as we speak.

When it comes to Tanzania, the resources there is growing. I'm very glad to see that. We are discussing with the partners, and BG especially as the operator in Block 1. Things are progressing well. We are currently discussing location for the onshore plans. So together we aim to make that decision, together with the Tanzanian authorities, by end of this year. So things are progressing well on all fronts in Tanzania.

Can we have another question?

Very good. Thank you very much.

Can we have another question from the telephone please?

Yes. Our next question comes from Nitin Sharma from JPMorgan.

Hi. Afternoon, gentlemen. My question is on the provision relating to Cove Point. Could you please clarify how much, if any, book value of Cove Point you're carrying today? And also maybe some details on the underlying assumptions behind the current provision? Thanks.

Okay. Thank you. So Cove Point was -- is a re-gas terminal in the US where we have capacity. We don't own it. We have never owned it. We have reserved capacity there. So there is no book value in the books related to Cove Point.

In the current market environment we don't see that we will use that terminal for the foreseeable future. We have therefore reduced or renegotiated a contract and taken down our future commitments to pay tariffs there. So, from a cash flow perspective, that means that there will be less tariff payments in the future on the Cove Point.

But at the same time, we have made up our mind and said we don't think we will use the capacity that we have left so we make provisions on onerous contract. We look at this as an onerous contract and make provisions for some NOK5b and that is equal to all remaining tariff commitments in the future. So it's sort of the provision covers for all future commitments.

Just to clarify that point. Was this contract of the nature where even though you may not be using the capacity, you'll still be obliged to make a certain payment over a certain period of time? And what you're saying today is we'll continue to make that payment, all we do is write it off today. Would that be the right way of putting it?

Not sure I fully understood it, but yes there are still tariff payments to be made. It is take-or-pay obligations. But they are less than it was before the renegotiations and then we have made provisions for all remaining payments to Cove Point.

Thank you.

We have another question from the telephone please?

Yes. Our next question comes from Rob West from Sanford Bernstein.

Hi, hello. My question is on the -- hello, can you hear me?

Yes, we can hear you.

Great. My question is on the Bakken. Just looking at the production back to the middle of 2011, you've ramped up that consistently but this is the first quarter where we've seen kind of flat to down volumes.

My question is what's behind that decrease? Is it where you're drilling, or is it the amount of drilling you're doing, is it more of a seasonal factor? And could you give us some guidance on where you expect that production to run over the rest of the year. Thanks.

Okay, thank you. No, so Bakken we have approximately doubled the production since we acquired it a bit more than a year ago. So it is progressing well. We are earning good money from that asset currently.

We have taken down the rig count a bit so we are now at around 10 rigs -- 11 rigs and we will go to 10 rigs, which we find the appropriate level and speed to run that asset on because the key at Bakken is to see to that. You learn across all your drilling teams with everything that you are testing on fracking, on well spacing and all of that. So we find that sort of that the right speed moving forward.

So this is an asset that will continue to grow. And flattish, was that from fourth quarter to this quarter? I didn't get that.

Yes.

So I think that is -- it is still an asset that we will continue to grow.

We'll take another question from Oslo. Any? No. Then we'll have another question on the telephone please.

Thank you. Our next question comes from Brandon Mei from Tudor, Pickering, Holt. Please go ahead.

Hi. I noticed on the international E&P tax rate it seemed like a little bump sequentially. I'm just wondering if you could explain some of the reasons why it's a little higher this quarter.

Okay, thank you. So generally, we say that tax rate on the international business should be expected to be 50% to 55% on adjusted earnings. It is 66% this quarter.

Key explanation to that is the devaluation of the bolivar in Venezuela. That is NOK600m reduction in earnings, both pre-tax and after tax. There are no -- so that takes up the tax rate when you measure the net earnings. So that is the main explanation to that.

Okay. Next question on the telephone please.

Our next question comes from Mark Bloomfield from Deutsche Bank.

Good afternoon. Yes another question on tax please. If I look through the uneven quarterly payment schedule for your tax, for the last three years you've consistently reported cash tax below P&L tax, which I presume reflects your investment levels. I was wondering if you could perhaps quantify what P&L versus cash tax delta you're assuming in your guidance of $24b of average annual operating cash between 2013 and '16? Thanks.

Okay, Mark, thank you. First of all, this is very much related to the Norwegian tax system where you have very good, very high tax depreciation from day one leading to low payable taxes when you invest. So you -- as you know with 130% depreciation towards the high tax rate, you pay only 7% of the investments within -- by six years.

So that is what you see in the difference between paid taxes and taxes in the accounts. So with a growing investment level, there will be growth in deferred taxes and I think that was the question mark.

And to what extent this will impact towards 2016 is that as long as there is a growing investment level in Norway you will have, generally, a growth in deferred taxes. And paid taxes will be less than reported taxes.

But could I just come back on that, if it's okay. You guided around cash flow growing, or operating cash flow growing quite substantially between 2012 and '16. And presumably part of that reflects the benefit of this differential between P&L and cash tax. So are you able -- I understand the reasons behind it, but are you able to quantify the delta?

No, Mark, I'm not able to quantify it. That's not the level that I would like to guide on either. But generally, with a growing investment level in Norway, you will have such a tax in the cash flow.

Okay, thanks.

Next question on the telephone please.

Thank you. Our next question comes from Teodor Nilsen from Swedbank First Securities.

Good afternoon. I just want to follow-up on the Tanzania questions. You currently have a pretty high owner share in the licenses down there. [Will we going to see] any farm-downs there and also when should we expect first gas from those discoveries?

Okay. Thank you, Teodor. On potential farm-down, that's of course nothing I could comment on. We have a significant share and we are an operator in our block, which is important to us.

So when it comes to the first gas, that's too early to say. Things are progressing well. We are going to select a site for the onshore development. And then things are progressing on the regulatory side and also on concepts.

But it's fair to say that we really would like to do even more appraisal and even more drilling in this license because there are a lot of prospects that we want to look into before we make a decision here. So it's too early to say when this gas will come to market.

Next --.

Okay. But it's now clear that you do not need any production from Tanzania to reach your 2020 guidance.

You are absolutely right. We have not taken into account any production from Tanzania in that guiding.

Okay, thank you.

Next question on the telephone please.

thank you. Our next question comes from Marc Kofler from Macquarie. Please go ahead.

Hi there. Thanks for taking my questions. Just two things, please. Firstly in terms of contributions from new projects, I was wondering if you are able to give us a number in terms of what you'd expect for new project start-ups to contribute to 2013 Group production.

And then, secondly, just going back to the NCS and the profitability, are you able just to give us some sort of indication in terms of how you'd expect unit profitability to be moving on a quarterly basis? I'm particularly thinking second quarter versus the number you've posted today. Thanks.

Okay. Thank you. Sven, maybe you can take the question on unit operation cost.

On startups going forward, we have a pretty large portfolio of assets that are in the final part of the construction phase; [Gulyad], Valemon, Gudrun, Svalin, [Klort, Vinsalla], Bigfoot, Jack, St. Malo, Hibernia and so on. So there's a lot of project lined up. So those are for 2014 and typically towards the end of 2014. And then there are ramp-ups in [Skuld]. It is in PSVM we're ramping up for unconventional part and a few others as well. So, but 2013 will be lower than 2012.

Yes, on the unit production cost, as Torgrim said in his presentation, we see a stable underlying cost structure on the Norwegian continental shelf, even though we are putting more fields into production. Now when we're getting then Troll and Snohvit back into production, that will of course offset some other production costs on [that field].

However what we should also take into consideration for the full year is the turnaround it takes, that we typically have been -- most of it towards the third quarter, on the Norwegian continental shelf. So that will also affect the unit operation cost.

Great. Thanks.

Next question on the telephone please.

Thank you. Our next question comes from Peter Hutton from RBC. Please go ahead.

Good afternoon, gentlemen. Two questions, but that's because I can't count. It's three really. First of all can you just give us some of the insights why you decided to include the NOK0.6b write-off on the Venezuela asset within the underlying results?

I guess it's commendable but a lot of people -- a lot of your peers may not have done that and it does make quite a difference to the overall. So what was the thinking as to should that be in or out?

The second is, you've mentioned and you gave us an update on the wells to watch and when these were spudding, but can give us an indication as to what kind of drill times are expected and when we might start to expect to see some results coming from those three.

And the third was, you mentioned that obviously the gas trading business in MPR is fluctuations. And of course we like fluctuations when they're positive and we don't like them when they're negative.

Given that fluctuation and last year being so strong, can we take it that last year was probably more -- sort of the kind of the top of the range and this quarter starts to inflow, where we are would be at the bottom of the range, or are fluctuations actually over a wider variance than that? Thanks very much.

Thank you, Peter. I think you ended up with three questions, to be honest.

I did. It's my birthday so I get an extra one.

Okay. So (inaudible), on the Venezuela, NOK0.6b, that's related to devaluation of the bolivar, so if you can take that.

And, Svein, if you can address the wells to watch and drilling times and then I can touch upon gas trading afterwards.

Okay on the Petrocedeno, on the bolivar effect, the reason why we're taking that as part of the not adjusted worth, is that it's a currency effect and that is kind of similar to other currency effects on other items that we do not adjust for. So that is the reason.

On the exact results from different wells, that is -- as we said, we've already spudded quite a lot in Mozambique. So that is ongoing. Then in these days we're also then spudding off [Penaluna Nunatak] where we should expect the results during summer on that [one]. Those are the two particular that I would like to highlight.

Okay --.

How long are they expected to drill and when might we get results?

I am not 100% sure of the exact number of days on the two different wells.

Okay.

Okay. On the gas trading side, I think it's fair to say that 2012 was a strong year. This quarter is not a good quarter and it is partly driven by the structures in the markets and on the curves. And it is also linked to that Snohvit has been down in the quarter so there has not been diversion opportunities on that LNG business that we run.

So you should expect trading results to fluctuate. And I won't characterize one as the maximum and the other as a minimum, but generally there will be fluctuations.

Next question on the telephone please.

Thank you. Our next question comes from Brendan Warn from Jefferies.

Yes. Thanks, gentlemen. It's Brendan Warn from Jefferies. Just two questions if I may. The first one is circling back to a question from Lydia and specifically on Snohvit. And I believe -- I understand it's had a number of challenges, but what sort of program is in place to resolve these challenges going forward and what sort of program and who's accountable for that.

And then just secondly and it is tying into Peter Hutton who should be allowed to ask 50 questions today. Just in terms of the Barents Sea program that's now kicked off that we've been waiting for, just what sort of net prospective resource is going to be tested with that program please.

Okay. Snohvit first. So Snohvit, we took Snohvit down for maintenance. And when we ran it up we experienced leakages in the cool box. So that has been fixed and repaired and it is now ramping up close to maximum capacity.

So we are using quite a bit of efforts on that assets to make it work like a Swiss clock. I think it's fair to say that we have been through all parts of that asset. When that is said, it has had its issues since the start-up. But -- and then going forward I can't give any guarantees, but most of the plant has been looked into.

When it comes to the Barents Sea program, so that is starting now with Nunatak and three more wells around the Skrugard Havis. And then we will test out a new play, the Hoop area further north before it comes back to the Hammerfest Basin in the end.

So the risk resources here is, I can't comment on that. I think it's fair to say that the Hoop area, which is opening a new play, that is higher risk, potentially that's a play opener. In the wells that are on the Skrugard area then the probability for discoveries is much higher. And we know -- we have a much better view on how much is the potential there. So it's a different risk profile across that program currently.

We have time for one more question. Please, operator?

Thank you. Our next question comes from Alex (inaudible) from Exane BNP Paribas. Please go ahead.

Hi, there. Last -- I note that opposition leaders are calling for Norway to potentially sell their holding -- well 16% of their holding in Statoil as it would give you better development prospects.

So do you actually feel in any way constrained by the strategic shareholder or pressured into developing projects in a more expensive way than you otherwise would have done as an independent? Thanks.

Thank you, Alex. First of all I think it's fair to say that the Norwegian state has, since the IPO and before that as well, been a very good and long term owner. That has sort of given Statoil the necessary freedom and opportunity to grow and make strategic decisions.

When it comes to what politicians will or will not do, that's for them to answer on. Generally all shareholders can make up their mind on what to do with their shareholdings.

Okay. So there hasn't been a dialogue with you over this process or anything like that?

It's not natural for to have such discussion.

Okay. Great thanks.

Thank you. That will have to conclude our Q&A session for today.

Today's presentation and Q&A session can be replayed from our website in a few days and transcripts will also be made available. Any further questions can be directed to the Investor Relations team. You will find contact information on the web.

Thank you all for participating and have a good afternoon.