Quarter earnings presentation, both to the audience here in Oslo and our audio and webcast audience. My name is Morten Sven Johannessen, Vice President, 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 of 2013. The press release and presentations 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 the information regarding forward-looking statements, which can be found at the last page. Today's program will start with Statoil 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 P.M. Central European Time. It is now my privilege to introduce Statoil's Chief Financial Officer Torgrim Reitan.
Thank you very much, Morten. Good afternoon, everyone, and good morning to all of you in the US. After two years with record results, the earnings this quarter is lower than last year. In the first quarter, we delivered earnings of NOK 42 billion, and we produced 2 million bbl 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. We had disruptions at some of our largest fields, reducing production by some 50,000 bbl per day in the quarter. This led also to a change in the production mix, impacting the earnings further. First, realized prices are impacted by a higher share of U.S. high 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. Our results are also impacted by quarter-specific items, which I will revert to.
When it comes to cash flow from operation, that is down by NOK 13 billion. 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 on the Bressay offshore U.K. We have passed the final investment decision to further extend production at Åsgard in the Norwegian Sea and at Hibernia offshore Canada. We have further progressed Aasta Hansteen in Norway and Mariner in the U.K. I'm very glad to see that we delivered the first wave of our fast-track projects. As you know, we standardize the development solutions for smaller fields faster and cheaper. Last year, we put Visund Sør on stream as the first one.
This quarter, we started more, Hyme, Vigdis North-East, Skuld, and Stjerne. All of these were discovered between 2008 and 2010. They have an average break-even of around $40 per bbl, and there is more to come. 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. 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 a potential LNG project there. Then we secured 15 interesting leases in the central, in the Central Gulf of Mexico. 12 wells were completed in the quarter with a 58% success rate.
Last but not least, we made a significant discovery at Gullfaks in the North Sea. 40-150 million bbl, 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, a 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 2-3 percentage points average growth in the period from 2012 to 2016. We have divested assets on the NCS, and we have produced a lot from our value over volume strategy last year.
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, Snøhvit, Peregrino, and Troll. We have taken forceful actions to bring them quickly back up. Snøhvit started up at the 28th of April and is now at close to maximum capacity. Peregrino is ramping up, and yesterday it produced 75,000 bbl per day, and it continues to ramp up. We expect Troll to be back by end of the second quarter. At In Amenas, two out of three trains have started. Timing and startup of the third train is still uncertain. We also saw changes in the production mix leading to a lower realized prices.
We produced more U.S. 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 bbl discount to Brent. As every quarter, we make adjustments to results. On the NCS, we have adjusted for a warm-up effect related to gas lifting. We had lower fair values of derivatives impacted, impacting our net operating income. Finally, we have adjusted for about NOK 5 billion related to provisions on the Cove Point LNG regas terminal in the U.S. 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 ma king a provision for all of our remaining tariff payments.
Finally, the devaluation of the bolívar in Venezuela has impacted the results with NOK 600 million. 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. This is something I watch very closely, and I will come back to this in further details later. Adjusted earnings after tax was NOK 12 billion with an effective tax rate on adjusted earnings of 71.8%. Now over to the segments. Our Norwegian business delivered adjusted earnings of NOK 34 billion. Compared to the same quarter last year, earnings were mainly affected by the lower production and lower prices. I will revert to costs and DD&A specifically.
From our operations outside Norway, the adjusted earnings were NOK 5 billion. Our entitlement production grew by 16%, and we now produce around one-third of our volumes outside Norway. This generated an EBITDA of around NOK 12 billion. If you look at the cash flow per barrel from our international portfolio, it is on par with our Norwegian production. Marketing, processing, and renewables contributed by nearly NOK 3 billion . 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 Snøhvit and Troll. We have also increased our gas production in the U.S. as we are hooking up already 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 invoice gas price by 11%. In the first quarter, we produced 2 million bbl per day. This is down 9% from the same quarter last year. As we said, we expect lower production in 2013 than in 2012. However, production could have been higher without disruptions. 1.3 million bbl per day is produced from the NCS and 700,000 bbl 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 Kvitebjørn, the compressor issues at Troll and the prolonged shutdown at Snøhvit.
As you know, we have restarted Snøhvit 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 Skarv, 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 U.S. onshore. Following the terror attack on In Amenas, our production is significantly reduced there, impacting our overall liquids production. Cash flow. Our cash flow from underlying operations was NOK 58 billion in the quarter.
This is 19% lower than during the same period last year. Last year reduction is fully explained by reduced production and lower prices. We invested NOK 27 billion. This is in line with our estimate of $19 billion for the year as a whole. Adjusted net debt to capital employed increased from 12.4% in 2011 to 13.3% at the end of this quarter. We continue to maintain a firm financial framework and a solid balance sheet. Next quarter, we will pay two tax installments. Dividend will be paid late May, NOK 6.75 per share, and that is representing a direct yield of close to 5%. Now let us take a look at our costs, starting with the operating expenses.
A large part of the cost at our fields are fixed in the short term, and they will not vary directly in line with changes in quarterly production. 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 costs and SG&A is explained by higher royalties and higher transportation costs.
If we then move to depreciations, we see a stable development in DPN. 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 life cycle. This quarter, we have increased production at Skarv, which is contributing with high depreciation, close to NOK 300 per bbl in DD&A from that field. This will of course decrease over time on that field. We have also had lower production from, you know, older fields like Troll and Kvitebjørn, and they have a depreciation of NOK 20-NOK 30 per bbl. It's a very big difference. 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. 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 reduced staffing by 800 man-years. We also continue standardization and industrialization as demonstrated by the successful fast-track initiative. 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, our growth will not be linear. 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 bbl 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. This will impact the gas production this year by some 15,000 bbl per day. The situation at In Amenas in Algeria will also affect output in 2013. In 2012, In Amenas produced 23,000 bbl per day for us. Second, we expect a growth of approximately 2%-3% per year on average from 2012 to 2016.
Third, in the longer term, we see the growth accelerating from 2016, growing by some 3-4 percentage points on average per year as some of our big new developments start to come on stream. All in all, we are on track for our ambition producing more than 2.5 million bbl in 2020. Looking at 2013, Snøhvit, 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 U.S. 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 bbl 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 bbl 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 bbl per day, and most of this is at our liquid production fields. We will invest around $19 billion 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 $19 billion. $19 billion is a gross investment number.
We will explore for around $3.5 billion this year and plan to finish around 50 wells. 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 spudding in these days. Cachalote in Mozambique was spudded a week ago. Finally, in East Canada with Harpoon West also recently spudded. It is exciting times for our exploration team and for all of us. To round up, 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 deliver 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. As you know, the board has proposed to pay NOK 6.75, and we will do all of this while keeping a very solid balance sheet. Thank you very much for your attention. I'll leave the word to you, Morten, to lead us through the Q&A session. 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, Ørjan Kvelvane, 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. In order to ask a question, please press star one on your tele phone keypad. Please ensure that the mute function on your telephone is switched off to allow your signal to reach our equipment. If you find that your question has already been answered, you may remove yourself from the queue by pressing star two. Again, please press star one to ask a question.
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.
Anne Gjøen.
Hold on one second.
Anne Gjøen, Analyst, 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 is a margin now of NOK 0.10. I know that it's changed principles when it comes to this pricing, but is it possible to give some indication? Is this index low margin any indication of what we could expect going forward? Is this just kind of very weak in this single quarter? Thank you.
Okay, thank you, Anne. 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, you know, 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 prompt months. 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. I think that is the main explanation for the deviation this quarter, and then explains the rather small margin on the natural gas side. Svein, something to add?
I think you have covered it well. It's also about the cost element that goes into it and how that is being recovered. It's based on other prices in the long term, and then taking into account the LNG prices as well, and the spot prices, and then the cost element.
What you could expect is that when prices moves in the other direction, you will see the opposite effect. You know, the natural gas business is no matter what measured on how much value they can add on top of what they pay for the gas.
Next question. Will you turn off your microphone, Anne? Thank you. Next question, please, from Oslo.
André Benonisen, Danske Bank. What is a realistic EBIT level from marketing division going forward?
Okay. Thank you, André. I think it's fair to say that we should expect fluctuations from quarter to quarter. Last year was a very strong quarter, strong year, in most quarters from that business. If you divide it into the processing facilities, the refineries, I mean, they are, you know, very much a function of the refinery margins, which is healthy this quarter. Costs have been taken significantly down. On the trading side, you should also expect that it's for an oil company, it is easier to make money in market with contango than in backwardation due to that you are long oil and long gas. The structure of the market will typically impact the returns.
They are, you know, performing generally strong, very good contribution to the earnings, but it will fluctuate quarter by quarter. 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, also on Weizhou?
Okay. Starting with Peregrino. With Peregrino, you know, we have the well capacity for, you know, around 100,000 bbl per day in production. We have had a turnaround this quarter. Then we started up, and then we had some issues on the top side that is now solved, so it is ramping up. Yesterday it produced at around 75,000 bbl per day. On Leismer, production from Leismer is going very well. You know, the energy efficiency is improving, and the production contribution from Leismer in the quarter is around 80,000-90,000 bbl per day. You asked about Caesar Tonga.
After the startup has performed pretty well and is now producing around 9,000 bbl, just below 10,000 bbl in first quarter of 2013 in the Gulf of Mexico.
Next question from Oslo, please.
Securities. Can you say something about how you expect the ramp up from Skarv and the fast-track projects in Norway? Do you also have a backlog of drilled wells in the Marcellus that you are completing today?
Okay, thank you. On Skarv, BP is the operator there. They are best to answer on that specific. 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, you know, what has been started and what we are working on. In 2014, we expect that portfolio to produce around 100,000 bbl per day for us. It's actually more and quicker than we expected when we started with these projects. All of them have performed well and delivered, you know, generally earlier and at lower costs than we had expected.
I think this is a concept that we are very, you know, enthusiastic about, and we see the potential for this way of working. We are, you know, looking at standardization and simplification across other projects as well. When it comes to Marcellus, we have quite a lot of wells in the inventory that's waiting for infrastructure, you know, gathering systems to bring them to the high-pressure interstate. The inventory there is, you know, several hundred wells. The way we work there now is that we have reduced the rig count, and we drill one well pad that we can return to and drill five more, and that is to keep the acreage.
You know, we build a pad, and we drill one well, and then we go. There will be a lot of very attractive wells to drill later in this area. Also, you know, 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. You know, that uplift is very welcomed in the current price environment.
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. Now, 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. 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?
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. 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. Then there's a list of, you know, much longer list on everything that is done in that perspective. I'm very glad to see that is working. We have worked this, you know, pretty hard for a few years.
When it comes to the level of disruption, I will not read this quarter as a change in sort of how things work on the NCS. Generally, the technical conditions is very good. When it comes to maintenance, you know, we use a lot of efforts on preventive maintenance if power things happen, and that has worked very well. When that is said, I'm of course not satisfied with the disruptions we have seen. Snøhvit has had its challenges since the startup. Peregrino is a run-in issue more than anything else. Troll is an electric motor on one compressor isolated to that.
Perfect. Thank you.
Okay, 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. One clarification, if I may, and also one question. Just firstly on the production, I know you've sort of highlighted where we are on the various different fields that were affected in the quarter in In Amenas, Peregrino and Snøhvit. I just wondered if we could sort of give a bit of color on, in terms of how we should think of about the impact to the full year. I know, I presume you're not willing to provide sort of more specific guidance on the guidance you've already provided around production being lower year-on-year.
If we were to sort of take into account some of the impacts we've had in 1Q and the knock on impact to 2Q, do you feel comfortable to sort of offset that somewhat with some of the other sort of impacts that you have, such that your initial assessment of production lower year-over-year is effectively the same, or are you talking about incrementally lower within what you had talked about earlier on the year? The second sort of question I had is actually just about Tanzania. Just wanted to get an update there. We see good progress being made around building the resource up there with BG and Ophir 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 sort of any particular milestones that need to be achieved before we start to see a development to plans accelerate? Thank you.
Okay. Thank you very much, Haythem. On production and the impact for the full year. I mean, if you take, these are disruptions that we sort of haven't planned for and so on. Of course it's sort of impacting without us, you know, having taken that into the forecast. That said, there's a lot of moving parts in our portfolio as well. You know, we have the Gullfaks well, the new discovery on Gullfaks, that is put into production right away, and it's producing well. It is part of that and the totality, but I'm not ready to put forward, you know, any specific impact on an annual basis.
You know, our guiding remains firm and 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 operator in Block 1. Things are progressing well. We are currently discussing location for the onshore plant. Together we aim to make that decision together with the Tanzanian authorities by end of this year. Things are progressing well on all fronts in Tanzania.
Very good. Thank you very much.
Thank you very much.
Can I have another question from the telephone, please?
Yes. Our next question comes from Nitin Sharma from JP Morgan.
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. Cove Point is a regas terminal in the U.S., where we have capacity. We don't own it. We have never owned it. We have, you know, reserved capacity there. There is no book value within 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 the contract and taken down all future commitments to pay tariffs there. From a cash flow perspective, that means that there will be less tariff payments in the future on the Cove Point.
At the same time, we have made up our mind and said, you know, we don't think we will, you know, use the capacity that we have left, so we make provisions, an onerous contract. We look at this as an onerous contract and make provisions for some NOK 5 billion, and that is equal to all remaining tariff commitments in the future. 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? 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?
I'm not sure I truly 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.
Oh, hi. Hello. Hello, can you hear me?
Yes.
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? Could you give us some guidance on where you expect that production to run over the rest of the year? Thanks.
Okay, thank you. Bakken, we have approximately double 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. 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're testing on fracking, on well spacing, and all of that. We find sort of that the right speed moving forward. This is an asset that will continue to grow and, you know, flattish. Was that from fourth quarter to this quarter? I didn't get that. Yeah. Yeah. I think that is, it is still an asset that we will continue to grow.
We'll take another question from Oslo. No. We'll have another question on the telephone, please.
Thank you. Our next question comes from Brandon Mei from Tudor, Pickering, Holt & Co. Please go ahead.
Hi. I noticed on the international E&P tax rate it seems 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. Generally we say that the tax rate on the international business should be expected to be 50%-55%. On adjusted earnings, it is 66% this quarter. Key explanation to that is the devaluation of the bolívar in Venezuela. That is NOK 600 million reduction in earnings, both pre-tax and after-tax. That sort of takes up the tax rate when you measure the net earnings. That is the main explanation to that.
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, you know, 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 $24 billion of average annual operating cash between 2013 and 2016. 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. You know, as you know, with the 130% depreciation towards the high tax rate, you pay only 7% of the investment by six years. That is what you see in the difference between paid taxes and the taxes in the accounts. With a growing investment level, there will be growth in deferred taxes, and I think that was the question, Mark.
You know, to what extent this will impact, you know, towards 2016 is that, you know, as long as there is a growing investment level, growing in Norway, you will have generally a growth in deferred taxes and the paid taxes will be less than reported taxes.
Could I just come back on that, if okay? I mean, you've guided around cash flow growing or operating cash flow growing quite substantially between 2012 and 2016, and presumably part of that reflects the benefit of, you know, this differential between P&L and cash tax. Are you able, you know, I understand the reasons behind it, but are you able to quantify the delta?
Mark, I'm not able to quantify it on the. That's sort of not the level that I would like to guide on either. Generally, with a growing investment level in Norway, you will have such effects 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 .
Hey, 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 you consider any farm-downs there? When should we expect first gas from those discoveries?
Thank you, Teodor . On potential farm-out, on that 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. 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 you know concept. 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. It's too early to say when this gas will come to market.
Okay. It's 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're able to give us a number in terms of what you'd expect for new project startups to contribute to 2013 group production. Then secondly, just coming back to the NCS and the profitability. Are you able 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, you know, the number you've posted today? Thanks.
Yeah. Thank you. Svein, maybe you can take the question on the unit production cost. On the startups, going forward, you know, we have, you know, pretty large portfolio of assets that are in the sort of final part of the construction phase. You know, Goliat, Valemon, Gudrun, Svalin, Cove, In Salah, Big Foot, Jack, St. Malo, Hibernia, and so on. There's a lot of projects lined up. Those are for 2014 and typically towards the end of 2014. There are ramp-ups in Skarv. It is in PSVM. We're ramping up for a conventional part, and a few others as well. You know, 2013 will be lower than 2012.
Yeah, on the unit production cost, as Torgrim said it in his presentation, we see a stable underlying cost pressure on the Norwegian Continental Shelf, even though we are putting more fields into production. Now when we are getting them Troll and Snøhvit back into production, that will of course offset some of the production costs on that field. However, what we should also take into consideration for the full year is the turnaround effects that we typically have in most of it towards the third quarter on the Norwegian Continental Shelf. That will also affect the unit production cost.
Great. Thanks.
Next question on the cell phone, 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 $0.6 billion 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. What was the thinking as to, you know, should that be in or out?
The second is the you mentioned, and you gave us an update on the wells to watch and when these were spudding, but can you 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? The third was, you mentioned that, you know, obviously the gas trading business in MPR is fluctuations. Of course, we like fluctuations when they're positive, and we don't like them when they're negative.
Given that fluctuation, ha-ha, and last year being so strong, can we take it that, you know, last year was probably the sort of the kind of top of the range and this quarter starts to imply 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 too.
I did. It's my birthday, so I might, I get an extra one.
Okay. Ørjan, the Venezuela 0.6, that's related to the devaluation of the bolívar. If you can take that.
Yeah.
Svein, if you can address the wells to watch and drilling times, and then I can touch upon gas trade, gas trading afterwards.
Okay. On the Petrodelta, on the bolívar effect, the reason why we're taking that as part of the not adjusted for it's a currency effect, and that is kind of similar to other currency effect on other items that we do not adjust for. That is the reason.
Yeah. On the exact results from these front ends, that is, as you said, we have already started in Cachalote in Mozambique, so that is ongoing. These days, we are also then starting up in the Nunatak, where we should expect the results come summer, on that one. Those are the two particular that I would like to highlight.
How long are they expected to drill? When might we get results?
I'm not 100% sure of the exact number of dates 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. I mean, this quarter is not a good quarter, and it is, you know, partly driven by the structures in the markets and on the curve. It is also linked to that Snøhvit has been down in the quarter, so there has not been diversion opportunities on that LNG business that we run. You should expect the trading results to fluctuate. You know, I won't characterize one as a 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, circling back to a question from Lydia, and specifically on Snøhvit. I believe and I understand that it has 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? Just secondly, it's 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 risk respective resource is gonna be tested with that program, please?
Okay. Snøhvit first. Snøhvit, we took Snøhvit down for maintenance. When we, you know, ran it up, we experienced leakages in the cold box, cool box. That has been, you know, fixed and repaired, and it is now ramping at close to maximum capacity. You know, we are using quite a bit of efforts on that asset 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 startup. You know, going forward, I can't give any guarantees, but you know, most of the plant has been looked into.
When it comes to the Barents Sea program, that is starting now with Nunatak, and three more wells are on the Skrugard, Havis. Then we will test out a new play, the Hoop area, further north, before it comes back to the Hammerfest basin in the end. The, you know, 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, you know, higher risk and, you know, potentially, you know, that's a play opener. In the wells that are on the Skrugard area, the probability for discovery is, you know, is much higher. And we know, you know, we have much better view on how much is the potential there. 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 Topouzoglou from Exane BNP Paribas. Please go ahead.
Hi there. I note that opposition leaders are calling for Norway to potentially sell their holding in, well, 16% of their holding in Statoil, as it would give you better development prospects. 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, you know, since the IPO and before that as well, been a very, you know, 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. 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.
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'll find contact information on the web. Thank you all for participating, and have a good afternoon.