Ladies and gentlemen, welcome to Statoil's Q3 earnings presentation, both to the audience here in Oslo and to our audience and webcast audiences. My name is Hilde Nafstad, and I'm the head of Statoil's Investor Relations group. This morning at 7:30 A.M., Central European Time, Statoil announced the results for the Q3 of 2012. The press release and presentations for today's event were distributed through the wires and through Oslo's stock exchange. The quarterly report and the presentations can, as usual, be downloaded from our website, statoil.com. I would kindly ask you to make special note of the information regarding forward-looking statements, which can be found on the last page. Today's program will start with Statoil's CEO, Torgrim Reitan, going through the earnings and the outlook for the company. As usual, the presentations 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 dialing numbers for posing questions can be found on our website. It is now our privilege to introduce Statoil's Chief Financial Officer, Torgrim Reitan.
Thank you, Hilde, and good afternoon to all of you here in our new offices at Fornebu. Good morning and good afternoon to those of you following us on the webcast. It is a pleasure to present our results for the Q3 this year. Once again, we present solid financial results and operational performance. We are delivering a 10% higher year-on-year production on the same period that last year, and an 8% production growth if you compare it to the full 2011. We continue to add barrels from discoveries and increase recovery, and we sharpen our portfolio through value-creating transactions. On Monday, we signed an asset deal with Wintershall, exiting our operated Brage field and farming down in Gjøa and Vega.
We realized $1.45 billion in cash from non-core assets. We added 15% in Edvard Grieg. That was previously known as Luno, and that is adding growth assets close to Johan Sverdrup, which is a key asset. The transaction demonstrates the underlying value of our NCS portfolio. Johan Sverdrup is one of the largest undeveloped oil fields in the world, and it is one of our key assets for the future. We now have secured working interests in all discoveries on the Utsira High, Johan Sverdrup, Ivar Aasen, Dagny, and Edvard Grieg. As the largest player in that area, we take these positions to drive the development and capture additional potential in that area.
We do this to revitalize the Norwegian Continental Shelf, and we continue to create value through the management of our portfolio and to sharpen our portfolio further. We have added substantial new volumes from the Ytre Hud prospect, which is part of the ongoing appraisal program, and development activity on the giant Johan Sverdrup. We will come back with a total resource estimate for that field early next year. We have also proved oil in the basement rock, and that's a possible upside. In the quarter, we have stepped up our activities in the Arctic. We signed agreements with Rosneft to establish joint ventures for four offshore licenses in Russia. We will drill nine wells in the Norwegian Barents Sea next year. I'm eager to see what Tim and his team can deliver on that one.
We have added new barrels through increased oil recovery. In the Q3 , we increased the average recovery rate from our fields on the NCS from around 49%- 50%. That is setting a new world record within increased oil recovery. You know, one percentage point, that equals 327 million barrels. If you use the oil price of today, that is actually some NOK 200 billion in revenues. This creates significant value to Statoil and to our shareholders. If you look back at the point of sanction, you know, the average recovery rate was around 30% on these fields, and we have actually added some 7.5 billion barrels from increased oil recovery. To put that in perspective, that is similar to two Statoil fields.
Based on this success, we have launched a new ambition early this quarter of getting to 60% recovery rate on our operated fields on the shelf. We continue to mature our project portfolio. We have been sanctioning 4 new IOR projects in the quarter, and we continue to ramp up productions from our new fields. In the Q3 , we delivered solid operational performance. I have said before that I have been looking forward to 2012, and this year we see significant growth, and we deliver as planned. So far this year, we have increased production by 8% compared to last year's average. I will come back to our production outlook in a few minutes.
We have increased our gas production by 18% in the quarter, and this is due to strong gas markets in Europe with good prices. At high value, we increase our volumes, and that is in line with our flexibility strategy. At the same time, our liquid production is slightly down in the quarter, and that is, as I told you last quarter, and we are very pleased with execution of the large turnaround program. That has been a great job done by our teams and our suppliers. The decline rate on our mature field is also stable, and that's in line with what we have discussed earlier. It's around 5%.
As you know, we are adjusting the production related to the Heidrun redetermination, which means that we will not book any production volumes from this field in the second half of 2012. Additionally, we see the effect of the divestment of the Centrica last year, so that is impacting the production in the second half. Even with a significant higher turnaround in the Q3 and the point mentioned, we deliver production growth in Norway. We are also progressing well on Gullfaks, now at more than 100,000 barrels per day. Internationally, we increase our production by 24% quarter-on-quarter. Year-to-date, we stand at an even stronger 27%. We continue to build up our production outside Norway.
Pazflor in Angola, that is operated by Total, continues to deliver. That field contributed with 47,000 barrels per day for us in the quarter. We produced 38,000 barrels per day from Bakken, the asset that we acquired a year ago, and we have added rail capacity to that asset, bypassing the pipeline bottlenecks that we are currently experiencing in that area. That is to ensure that we get our oil to the market at the highest price possible and reducing the differentials, and we see that it works. Our trading organization in Stamford create a lot of value from these barrels. Marcellus also delivers strong production at over 63,000 barrels per day in the quarter.
On Eagle Ford, we will take up operatorship of the acreage in the eastern part next year, stepping up for our second operatorship in U.S. onshore. We produce as planned. In the Q3 , our net operating income was NOK 40.9 billion, and that is up NOK 1.6 billion from last year or 4%. Our net income is NOK 14.5 billion, which is up 47% from last year. We see a lower effective tax rate this quarter, and I will come back to the tax a little bit later. The adjusted earnings before tax were NOK 40 billion. That's a slight decrease over the last year, and that is due to higher exploration expenses, partly offset by higher gas production and prices.
We continue with a high exploration activity, with drilling ongoing in several exciting prospects. Operational costs and SG&A are at the same level as last year, at NOK 19 billion. If we adjust for the SFR divestment, we see a flat cost development over the last quarters, despite the higher activity levels and the production growth. We will continue to attack our cost and our cost base. After tax, we made NOK 11.9 billion quarter on an adjusted basis. That's an increase of 4% from the same period last year. We deliver NOK 31.1 billion in adjusted earnings from development and production in Norway. That's a decrease of 13%. As discussed, our liquid production is down, and that is impacting earnings by some NOK 7.7 billion.
This is from the planned turnaround activity, the Heidrun redetermination, and our divestment of producing assets to Centrica. We saw lower depreciation in this segment, and that is due to higher reserves and lower production this quarter. We produce a lot of gas, and that is increasing by 11%. We realized a 14% higher gas price this quarter than the same period last year. In international development and production, the adjusted earnings was NOK 4.4 billion. That is up 7% from NOK 4.1 billion in the Q3 last year. We are growing our international production significantly. This increase was partly offset by increased exploration and depreciation expenses from lower prices and increased royalties.
The higher exploration charges are partly due to a significantly increased seismic activity, including the activity in the Kwanza Basin in Angola, where we are preparing for exciting, I must say, pre-salt wells to be drilled in 2014. We see a very strong quarter in marketing, processing and renewables. Deliver earnings of NOK 4.1 billion, which is a 67% increase over the same period last year. For natural gas, earnings were at NOK 2.7 billion compared to NOK 2.8 billion one year ago, and that is despite the lower Gassled stake this year, and normally that contributed with NOK 1 billion per quarter. The strong result was due to higher margins from our gas sales and higher volumes and higher prices, and good trading and end user sales.
For the crude part, and marketing, and trading, earnings were NOK 1.5 billion in the quarter compared to a loss last year of NOK 0.2 billion. Increase came from strong refinery margins and continued strong results from the trading activities, and another good quarter from our trading floors. There is still a demanding outlook for the refinery business, and we must be prepared for lower margins than we have seen in the quarter, and we will continue our improvement program with full force. We actually see the impact and effect of the improvement program in our earnings. Just a reminder that the results from MPR will fluctuate from quarter to quarter. The reported tax rate was 66.9% in the quarter, and based on adjusted earnings, it was 70.4%.
This is in the lower part of our guided range of 70%-72%. I said earlier that you should expect our tax rate for the full year to be in the upper part of that range or slightly above, and this is unchanged. The decrease in the tax rate is mainly related to a relatively higher adjusted earnings outside the Norwegian continental shelf. Over to the cash flows. The cash flow from our underlying operations year-to-date is NOK 188 billion. We have invested for NOK 84 billion. We have freed up NOK 29 billion from value-creating portfolio management, and NOK 29 billion amounts to the market cap of a top ten company on the Oslo Børs. Such transactions are and will continue to be an important and integrated part of our strategy going forward.
I will come back to that shortly. We paid NOK 77 billion in tax and NOK 21 billion in dividends. Please note that the paid taxes of NOK 77 billion is significantly lower than the reported income tax in the accounts of NOK 104 billion, so far this year. As you know, we pay tax in Norway six times per year. We have already paid one installment in the Q4 , and we will pay another one on first of December, of around NOK 20 billion. We are increasing our cash flow. Operating cash flow has grown by 10% the first 9 months based on safer prices, and this is in line with our production growth. This contributes to our strong balance sheet.
We have now close to NOK 85 billion or $15 billion in cash and current papers, and we have taken down our adjusted net debts to 12.6% this quarter. Financial robustness is still very important to us and a very important strategic issue. Our project portfolio is capable of producing more than 2.5 million barrels per day in 2020, and it is an attractive portfolio, as you know. However, we will continue to optimize the portfolio to sharpen the growth further and putting our money where our strategy is. I think, you know, the recent transactions illustrate this in a pretty good way. We realize value from non-core assets like Gassled and Statoil Fuel & Retail. We balance our risk by taking in new partners in Peregrino and the KKB.
We focus our portfolio by deploying resources into core areas and divesting non-core assets like we did with Centrica and Wintershall. You know, these transactions brings more than $15 billion in proceeds to the company in addition to our new stake in Edvard Grieg. We have realized accounting gains of more than $6 billion based on these transactions. We will continue our strategy of targeted investments in addition, like our Bakken acquisition last year. We will add, and we will subtract, and thereby creating significant value for our shareholders. Our growth towards 2020 will be of even higher quality. We will balance our investment program going forward with an active portfolio management. We maintain a policy of a predictable and growing dividend, and we will continue to maintain a strong and solid balance sheet.
We are progressing as planned. Excuse me. We are delivering a 10% growth in production year to date compared to the same period last year, and an 8% growth if you compare it to the average of the full year last year. This is an industry-leading performance, and it is in line with our guidance. Looking ahead, we will have organic investments of around $18 billion in 2012. Given the solid production growth we see for the next year, it is likely that we will see some growth in the gross CapEx next year. I will revert more closely to this in February. However, we are investing for growth with a low break-even price across the portfolio and industry-leading rates of returns on the projects. We are spending money to make even more money.
We will explore for around $3.5 billion. We will drill 45 wells in total this year, and we have already added more resources this year than the full 2011, which was a record year for us since the IPO. We will drill some 20-25 high-impact wells from 2012 to 2014. We will run, I must say, a very interesting drilling campaign in Barents starting next year or starting in this winter of 9 wells. We'll start with spudding the Nunatak prospect next month, and this is close to the Skrugard and Havis discoveries. We are on track for our 2012 production outlook.
We are delivering growth as planned, and then we expect our Q4 production to be around the level of Q4 last year. Let me give some color to this. We are currently ramping up production from Peregrino, Pazflor, Marcellus, Bakken, Eagle Ford, and then we plan to bring three fast-track projects on stream during the Q4 . You should remember that you have to adjust for the Heidrun redetermination and our reduced ownership share on Kristin, as well as the delayed Skarv startup, and that will counter the new production expected in the quarter. In the longer term, we are steadily heading towards 2020, and our ambition to produce more than 2.5 million barrels per day.
We are on track for an average growth of 2%-3% from 2012 to 2016. Production will fluctuate from year to year, and we see 2013 production lower than 2012 production. I would like to give some color on the reasoning for that. First, the Wintershall transaction will reduce production in 2013. The divested fields produce around 40,000 barrels per day in 2012, and a similar level is expected in 2013. Furthermore, we will reduce the rig counts in the U.S. responding to the low U.S. Gas prices. You know, the beauty of that asset is the ability to react to prices to create more value.
Growth in the U.S. will be slower next year, and the impact may be in the order of 25,000 barrels per day compared to plan. The reduced production from our U.S. Gas position will, however, have limited impact on earnings, which is the whole point. Both of these things are deliberate actions by ourselves to create value through divestment and through value over volume strategy in the U.S. In summary, we are significantly growing both our production and our earnings. 8% production growth compared to the full 2011. Adjusted earnings year to date grows also with 8%, and our operating cash flow is growing with 10% so far this year.
We are continuing to invest into a very profitable project portfolio. Thank you very much for your attention, and then I'll leave the word to you, Hilde, to lead us through the Q&A session. Thank you.
Thank you very much, Torgrim. We'll turn to the Q&A session, and for this session, Torgrim will be joined by Senior Vice President for Accounting and Financial Compliance, Kåre Thomsen, and Senior Vice President for Performance Management, 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. Operator, please.
If you would like to ask a question over the audio, please press star one on your telephone keypad at this time.
Thank you. We'll start with the questions from the audience here and also first. Please push the button on your microphone if you would like to pose a question. Yes, Anne.
Thank you. I hope you could give some comments about the renegotiation of gas contracts, because I think it was last year or the beginning of this year, it was the comment that 50%, I assume, of volumes is up for renegotiation. I assume you can't tell much, but how much is remaining when it comes to renegotiation now?
Thank you, Anne. Let me start with what's going on. You're right, we are renegotiating our contracts and modernizing our gas contract portfolio, which is about taking back flexibility and changing, you know, the structure of some of those contracts. That work is actually going well. We have concluded about half, 50%, of the contracts. They have been renegotiated, and I think I dare to say that we are well satisfied with the results. Quite a bit of, you know, the new contract mechanism is reflected in our gas price that we report today. As you see, it's a healthy gas price.
It also enables us to use the flexibility in the portfolio that we have. You know, Troll, Oseberg, the transportation facilities and all the landing points and so on. We are able to create value on that flexibility.
Next question, please.
It's me?
Oh, it's you. Yeah.
Push the button?
No, you can just talk.
Okay. Thank you. Lars from SEB Enskilda. In relation to your 2013 guidance, or at least what you say that the production will be lower than 2012. Can you explain or can you tell, have you excluded the Wintershall-related volumes from first of January or actually from the second half of 2013? Because you have said that the transaction will take place due to regulatory work from second half. From when have you excluded 35 thousand-40 thousand barrels per day? I mean, when that transaction. That transaction will have an effective date of first of January.
There will be earnings impact, you know, from first of January in a way or it will have an economic impact from the effective date. The way this works is that when everything is closed, you have a settlement in cash for that period and so on, and then you count barrels until you have closed everything.
Exactly. You are.
When the point of closure is of course uncertain because there needs to be approvals from the authorities on transactions like this. That is uncertain. But you know what? The data points that I give you is that that portfolio produced 40,000 barrels per day in 2012, and they will produce approximately on similar level in 2013. Of course, when you count barrels, you need to make an assumption on when this is closed.
Of course.
Yeah.
Okay, just to clarify, then, which means if this transaction takes place in the beginning of Q4 next year, you have produced 39,000 barrels for the first three quarters. The full year effect is only 10,000 barrels for you next year. Is that right?
If that's.
Yeah.
when it's closed. We do expect it to close earlier.
Even with that effect you have, you will say that you are below in 2013 compared to 2012. Or have you excluded 40,000 barrels?
Well, you know, we don't go into those details in the guidance. You know, based on that transaction and also what we're doing in U.S. Gas, we now see that it will be lower than 2012. Those are two data points that I'm giving to you today.
Okay. One more question related to your CapEx for next year. Kind of a soft guidance, a little bit higher next year or something higher. Can you tell a little bit more about the split in your CapEx growth between offshore, onshore and conventional, what will grow, what will not grow?
Yes.
In your budget.
Mm-hmm.
Thank you.
Typically 45% of our investments will be related to Norwegian continental shelf. Some 50% will be within the international segment. The remainder will be related to, you know, midstream investments that is there to support the upstream business. In general, 70% of our investments goes into greenfield developments, 30% into brownfield. That brownfield is split between, you know, IOR projects and drilling of wells, and then finally maintenance and modifications on the platforms. This is mainly going into new developments. When it comes to the split within the international segment, we don't give that specific guidance.
Due to the lower rig count, you know, we do in Marcellus. It is sort of slightly lower than we anticipated a year ago.
Okay. The next question, and can you please state the name of your own name and the name of your company? I think that's you, Trond.
Trond Omdal, Arctic Securities. On your Q4 guidance of the same level as last year, is there some upside on gas, or does that assume a robust offtake? Because, as you said, gas prices in U.K. are very high for the season, GBP 0.65 per therm. So is that even assuming quite robust? And/or is there still some upside, if you can give some color on that. The second question, I assume almost all of the lower drilling activity is on Marcellus, or will some of it be on the gas part of Eagle Ford? And I think you've indicated you're drilling some more of the liquids-rich component of Marcellus. Will that have any effect on liquid from Marcellus next year, or will that mean next year?
The third on ACG, of course, you're not operator, but is there anything you can say about the ongoing discussion between the government and BP on trying to maintain that production long term?
Okay. Thank you, Trond. When it comes to production in the Q4 and gas assumptions, it is a healthy gas market on the continent and in the U.K. currently. We see going forward, somewhat more tightening on the LNG side, more to Asia. We do expect a healthy market for the Q4 . The way that we run our you know, the gas machine is that typically in the Q4 and Q1 , it runs you know, on full speed. Then there are some assets that have flexibility. For instance, the Oseberg Field. The Oseberg Field, we can produce the production permit in 80 days and pick the very best days, and so on.
That, of course, there is also always an uncertainty when you want to produce that field, in a way. It is less uncertainty related to the gas production and gas off-take in the Q1 and the Q4 than during the summer months. When it comes to Marcellus or the U.S. gas, this will typically be in the northern part, in the dry gas area. The liquid area in the south is less affected on what we are doing. Couple of reflections on, you know, the gas market in the U.S.
Currently $3.3 per MBtu Henry Hub, which is, you know, an increase since the summer, so it is better. You know, in dealing with the gas in the U.S., it is extremely important to take care of your gas and add additional value through how you deal with your gas. From first of November, we will start to sell, transport and sell our gas in Toronto. You know, increasing, you know, putting in place quite generous uplift on our gas. Then we are working on a pipeline together with Spectra and Con Edison, Chesapeake to cross the Hudson River to the U.S. This will actually come up at Penn Station and connect to the grid there.
You know, the gas prices on Manhattan is totally different than on the Jersey side of the river. Taking care of the gas is extremely important, and we do that, and we create quite a bit of additional value on top of that. When it comes to ACG, I cannot go into, you know, discussions, you know, that BP has with the government there. I think, you are better asking them about that. I think on a general comment, we have BP as operator, you know, several places in the portfolio. Skarv has been mentioned earlier in Azerbaijan, ACG and Shah Deniz. PSVM in Angola and Schiehallion in the U.K. Those are sort of the, I guess, the most notable assets where BP is an operator.
We have BP as an operator several places in the portfolio. You know, when it comes to ACG, I think you are better placed to ask a question to BP on how they look at that.
Next question, please.
Ole Jakob Skarebekk from First Securities. You were mentioning you're reducing the activity in Marcellus. Do you have any plans on increasing activity in Bakken and Eagle Ford? How many rigs are you planning to run in these different basins next year?
Yeah, okay. Ole Jakob, thank you. Yes, we have plans to increase the production in Bakken and Eagle Ford. For instance, Bakken is producing some 38,000 barrels per day in this quarter. When we acquired it, a year ago, it produced 21,000, so it's almost doubled. We are continuing with is it 15, Svein, 15 rigs now?
Yeah, 14-15.
14-15 rigs in Bakken. Operations actually runs very smoothly. In Eagle Ford, that's, you know, gas and liquids and so on. The number of rigs that we are running there, I can't recall the specific number. It's, I think we're running 9 rigs there in Eagle Ford currently, which is, you know, approximately on the level we have been.
Yeah, in Marcellus, how many rigs are you planning running there next year?
I mean, it has not been concluded, you know, the specific number, but it is on its way down in the northern part of Marcellus.
One question related to East Africa. You have made very good discoveries there. When can we expect to see any production from that region?
From Tanzania, it is too early to say. We are, you know, very encouraged by both the Zafarani and Lavani discoveries, two large discoveries. All in all, some nine TCF in discovered resources, which is significant. You know, that block is a very large one. There are, you know, several others, very interesting prospects. First priority is to, you know, find out how much is actually available there, and so on. Then we are thinking carefully about, you know, the progress and how to deal with this. You know, it is promising, and we are looking forward to continue to work with that asset.
I can't see any further questions in Oslo, so we turn to the audience. Our first person to pose a question today is Haitham Rashid from Morgan Stanley. Please go ahead, Haitham.
Thank you, Hilde. Good morning, all, or good afternoon. I just wanted to ask three quick questions if I could. Well, firstly, just a point of clarification about the gas contracts renegotiations, just the question you answered earlier on to Anne Gjøen. I just wanted to understand, did you specifically say half of all the gas contracts that you have outstanding or half of the amount that you originally said was up for renegotiation? Just to clarify that would be great. Thanks. Secondly, just on CapEx, and I know you may wish to reserve the right to answer this question with the strategy update early next year.
Given your comments around some growth in gross CapEx and, given the sort of, you know, the recent acquisition of the stake in Edvard Grieg and some of the projects you have coming, I just wondered if we should be thinking about a sort of step change in CapEx over the coming one to two years or is it sort of something, you know, more benign than that? Just would be great to get your thoughts on that. Then finally, just an update, if possible, on some of the key wells that are being drilled at the moment. Specifically, I'm thinking of Kilchern, but also the Lavani and Zafarani appraisals, where we are on those three. That'd be great. Thanks.
Okay. Haythem, thank you. On the gas contracts, this is 50% on the totality-
Okay
of the scope, so it is progressing well. When it comes to CapEx 2013 and whether you should expect, you know, significant step up on it, I use the word some increase in CapEx, which is certainly not a significant step up as you say, but it is a direction on the number. Svein, can you give an update on the drilling program?
Yes. On the Zafarani and Lavani, we are in the progress of then evaluating them and looking at more appraisal wells in the block for Lavani and Zafarani. In addition to that, we are also then evaluating if further prospects and then come up with a drilling campaign for that a little bit later. First now we will then do the appraisal drilling for Lavani and Zafarani.
Great. Thanks. Corrib, did you have any sort of update there?
Corrib is in an evaluation phase, looking at that one. So that we need to come back to that a little bit later when we are done with our evaluation on it. Also maybe then on others, on the breakdown, which is then ongoing, where we expect results in a couple of months' time.
Great. Thanks.
Our next question comes from Nitin Sharma from JPMorgan. Please go ahead, Nitin.
Hi. Afternoon. Three questions from me as well. First one, coming back to those gas contracts. Average invoice gas price increase of 10% Q3 on Q3. I'm conscious of the commercial sensitivities, but could you tell us very broadly following the recent round of contract renegotiation, so what percentage of your total portfolio gas sale price is tied to oil products versus spot indexation? Two, on Bakken, you mentioned higher realization because of gas capacity. What kind of realization price related to the benchmark should we factor in? And finally, in an interview yesterday, President of Statoil Canada Operations expressed interest in LNG assets in the country. Is this something on near-term agenda of the company? Thank you.
Okay. Thank you. 216 øre per standard cubic meter in indexed gas prices. You know, a significant increase in that. Your question is about, you know, the exposure to oil products in there. Typically, 70% of our gas sales is related to long-term contracts. The rest is typically spot indexed. And, you know, of those 70%, half of the contracts have been renegotiated. That should give you a flavor of the impact. You know, we are. You know, when I talk about the renegotiations, it's much. You know, it's of course comes down to price.
You know, the long-term contracts, we are not selling, you know, all long-term contracts, that is not a spot product. You know, you sell flexibility and you sell energy security in those contracts in addition to gas. The long-term contracts should have a different price than a spot product. When we are allowing more gas indexations into the contract, I mean, the flexibility is taken back to the producers. Access to the traded hubs and so on. That flexibility is actually very valuable to us.
I'll give you one example, and that was in 2009 when the gas markets in the U.K. more or less collapsed from GBP 0.70 per therm to GBP 0.20 per therm in 2 or 3 months. We decided at that point in time that this was not a market that we would like to produce into, so we pulled back production and produced it the next year at twice the price, 100% return on that flexibility. Just an example of how much flexibility can be worth. Then on Bakken and realized prices, quite healthy on average, in the mid-$70s is what we realized for products there. That is good. Then, more strategic questions on LNG assets.
There is, you know, one project, Sabine Pass, is firm and coming on stream on LNG export, and there are several other projects that are evaluating what to do currently. I think when going forward, I mean, it's hard to see any greenfield developments of LNG export facilities, especially in the U.S. So if there comes some, it's typically on regasification plants and so on. This is a big discussion over there. To do such an investment, you actually have to be a strong believer as well. You need to believe in some $4 spreads between the U.S. market and other markets, and you need to believe in that for some 20 or 30 years to justify that investment.
Those evaluations are done, and if you know, we think about a lot of things in our company, and then sort of that is also part of what we think about from time to time. No firm plans in any direction, as such.
Thanks.
Next question comes from Theepan Jothilingam from Nomura International. Please go ahead, Kepan.
Yeah. Thank you, Hilde. Good afternoon. Another three questions, actually. Just very quickly, coming back to 2013 production, can you just talk about perhaps, just your assumptions on maintenance, for next year relative to this year? Secondly, just, exploration expense, clearly very, very volatile. But again, I was just sort of wondering what sort of assumptions we should make going forward, in terms of the percentage that you sort of think is appropriate to expense as a forecast. And then thirdly. In terms of Tanzania, there had been some, thoughts of a, you know, discussions, consolidations with other players in Tanzania for a development. I was just, hoping for an update there in terms of what you thought may be a solution for early development of gas in Tanzania.
Thank you.
Okay. Thank you. When it comes to maintenance, I mean, we have to revert to that in February. You know, in you know, the statements are made today, you know, we're taking into account so the expected maintenance. On exploration expense, we have earlier said that you should expect capitalization of 33% or one-third of our expenditure. My best advice is to do that going forward as well. It will fluctuate from quarter to quarter. It is sort of the nature of exploration. So far this year, it is actually 33%. So, I think that's an assumption that is fair to use going forward.
When it comes to Tanzania and East Africa, I mean, there's a lot of things going on there, and it's quite a dynamic picture and a lot of activities. There's a lot of players as well. It is, you know, no firm plans yet, and so on, but it is natural that sort of companies that operate in the same areas, you know, have discussions on, you know, how to deal with issues. There are no firm things in any direction feedback.
Okay. Thank you. Sorry, just to be a pain, but coming back, are you saying that maintenance in 2013 will be of a similar level to 2012? Is that the message?
No. The message is that, you know, we are not going to be specific on that today. I think in February is more prudent for us to lay that out in more detail. You know, it is sort of taken into account in the things that we have said today.
Okay, fantastic. Thank you.
We'll take the next question from Peter Hutton of RBC. Please go ahead, Peter.
Good morning, everybody. Good news is just two questions. Bad news is they're each in two parts. First one is in the international business and the cost. There was sort of higher than expected or higher than I expected costs in DD&A and, to some extent in, exploration. You also mentioned increased royalties. Can you just sort of say where the sort of increase in DD&A versus last year is coming from? Is it fairly geographically spread, or is it related to the Bakken or Pazflor or, you know, any particular areas driving that? On the exploration, is that nearly all the increase, because it was 1.3 this quarter compared to 1 for the first half. Is that all on the seismic and the royalties, again, geographical split?
The second question is simpler on exploration. You mentioned the seismic on blocks 38 and 39 in Angola. It's just an update on sort of the quality of that seismic and the status and how you're working with that. Also, you're a partner on block 22, which is directly between the two discoveries made so far with Repsol, the operator. Can you give a feel as to what the progress is on that block as well?
Okay, Peter. Thank you. Good and detailed questions. Svein, can you address, you know, the exploration, seismic, and seismic questions? When it comes to the DD&A, and when you compare it, you know, together with the Q3 last year, this is related to the Bakken acquisition we made last year. That was not part of the numbers last year. It is currently.
Mm-hmm
that is, you know, quite a chunk of it. Then we have higher production, it means higher DD&A because it's a unit of production depreciation.
Yeah
Then we have ramp-up of new fields, and those newer fields typically have much higher depreciation than older fields. That is back to that, it is depreciated based on booked reserves. When you start a field, you typically book some 40% of the reserves, and then you keep booking as you produce. In the early phase of a field, the depreciation is typically much higher. We see that particularly on the Peregrino and the Pazflor. When you have those elements, I think you have it all in the explanation of the increased DD&A on that one.
Yeah
Svein on seismic.
Yeah, on the seismic activity, as Torgrim said, we are stepping up our seismic activity in the Kwanza Basin quite significant. Which is an important explanation of the increased exploration cost this quarter. What we are doing now is that we are collecting the seismic, and we are now going over them to process it. What we will do with the seismic, we will do internal processing of the seismic.
We have developed tools for that internally, which we will then process in the seismic activity. That will make us ready then for drilling wells in 2014. Specific issues related then to the block around 22. I think that is too early to comment on. As for general lot, we are exciting about the concept basic, and we will come back to more details on that later.
Okay, great. Thanks so much.
Next question will come from Oswald Clint of Sanford C. Bernstein. Please go ahead, Oswald.
Yes, thank you very much, Hilde. Yeah, a couple of questions, please. The first one just on that value to volume strategy for the Marcellus. On the flip side of that, what gas price or what Henry Hub gas price do you need to see to bring back the sort of 25,000 barrels oil equivalent next year that you tend to switch off next year? Secondly, just also on the Bakken kind of sequential growth there on the oil slowed to kind of sub double-digit levels in 3Q versus 2Q. Is there anything going on there? Is that just rigs, or you need to increase the rigs to keep that part of the production growing, or I'm just curious about that growth level.
Actually, I was more curious on the European gas side, in terms of the sort of big increase in coal coming in to kinda U.K. parts of Europe and displacing natural gas. Are you seeing any of that start to impact your European gas business? Thank you.
All right. Thank you. In Marcellus, I mean, we are earning money in the current price environment, but we would like to earn more. This is based on our, you know, the way we look at the price outlook and so on. We think these volumes are better produced later and so on. We will sort of course, monitor the situation in the markets closely, and also the way we look at it and so on. You should expect us to apply that strategy, you know, in the current price environment. When it comes to Bakken and the growth, I mean, it is growing well.
The risks we are running are, you know, really efficient. The question is how fast. You know, there is a full value chain that needs to come into place here, you know, taking care of the volumes, and also that, you know, that you have the right rig crew, and all of that. I think we are comfortable with the rig count that we currently are running. I'm sure we could have stepped it up further, but I think it's a balancing act, and I think we are fine with the levels that we have currently.
When it comes to European gas and coal, sort of one of my favorite themes, and I think I can talk for a couple of hours on this one, but, you know, Europe actually need gas. I mean, that is especially Germany, I would say, and also U.K. I mean, it is quite a lot of it, and Europe is in middle of it, you know, when between Norway, LNG, North Africa, Azerbaijan, and so on. It is here to stay. It's rather affordable. It doesn't need subsidies. The third and very important point it is that it is very clean. It is the cleanest fuel, and so on. This is not a political speech, but it is to give you some background on the discussions.
In Germany, they have not been able to distinguish between various fossil fuels. They have clear views on the nuclear and clear views on the renewables. We think that German politicians need to put a clear stance on gas versus coal and so on. They could really, you know, solve, you know, CO2 emission issues, and it will actually make Germany even more competitive going forward. Both in the U.K. and Germany, we, you know, we sense, you know, more positive signals to gas, and, you know, we very much appreciate that. We do see that there is more realism coming into all the discussions, and it all points towards the direction of natural gas. We are welcoming that discussion. Okay. Thank you, Oswald Clint.
That's good. Thank you.
We'll take the next question from Guy Baber of Simmons. Please go ahead, Guy.
Yeah. Thank you, guys. I had a big picture strategic question here, but we've recently seen comments from the press noting that Statoil needs to become more global, which is obviously consistent with the strategy you guys are undertaking, but that there's also an increased willingness on your part to forge large strategic alliances. Just hoping you could elaborate on this comment. Are you referring to additional agreements similar to what you've done with Rosneft or potentially something more significant? How do we think about that? Can you just reiterate what the primary objective there may or may not be? Thanks.
Okay. Thank you. You know, our international production currently is becoming quite significant, and it is growing. I think I dare to say that we have positioned us well in, you know, key basins in the world, and then we are working actively on, you know, accessing the basins for the future, what really can be the next big things. You know, Arctic is very important to us. Both East Africa and West Africa, as we have discussed today. Brazil, key elements. We have had some really nice discoveries there. The Gulf of Mexico as well, you know, large acreage holder, and so on. You know, working together with other companies internationally is a natural thing in this industry.
I think the Rosneft deal is a good example of that. We actually see quite a bit of increased interest in you know, working together with us going forward as well, and we take that as a compliment. It's sort of a natural part of this business, and so on. On you know, any bigger things, of course, I can never you know, give any directions as such. I think it's fair to say that you know, if you look at our project portfolio, I mean, it is there, it's high quality, it can deliver in 2020 above what we have guided at. We know what to do. We know what to do all the way towards 2020.
This is about execution. Then we will add and subtract from portfolio management, but it actually allows us time to explore. We are not in a situation where we feel that we have to do something to fix anything. I mean, things, it works well. We feel that the strategy is working, and we can do what we are best at. That's sort of the thinking and so on. I think that is a good starting point for any strategic discussion.
Okay, great. Very helpful. Thank you.
We'll take our next question today from Michael Alsford from Citi. Please go ahead, Michael.
Hi, good afternoon. If I can, please. Firstly, just on the sort of financial framework, you've obviously, you're seeing an increasing cash flow progression as you mentioned in your presentation, but you're also seeing obviously an increasing CapEx burden to the group. I just wanted to know, as you think about it into 2013 and beyond, you know, it seems like, you know, break even is, you know, north of $100 per barrel. I was just wondering whether you have a view on or whether there's an absolute level of sort of disposals that you plan to do. The more obvious divestments like Gassled, Statoil Fuel & Retail, et cetera, have been done.
Could you maybe talk about your sort of disposal strategy in more depth? Or is it simply that you're gonna be, you know, increasing gearing levels over the next years? Secondly, just on sort of cost in particular on the NCS, could you maybe talk a little bit about how you're managing what is, I guess, a tight services market, maybe what the cost inflation is there and, I guess, how you're dealing with any bottlenecks that you're seeing in the services market on the NCS? Thanks.
Okay, good. Michael, thank you. On the financial framework, you know, it is we have not said anything upfront on how much we want to divest and sort of acquire. I think that is a deliberate choice and so on. I think we need to look into history to see what has happened. I dare to say that we have been pretty active over the last decade, actually, to sharpen our portfolio, to divest assets, and then reinvest it into things that are much more strategic. You should expect that to go forward. It is sort of one of the six elements in you know the honeycomb that we use when we communicate our strategy.
It is close to our heart to use that actively and so on. You shouldn't be surprised going forward if there are subtractions or additions to the portfolio. That's there. When it comes to you touch upon CapEx going forward and what sort of dollar oil price we need to balance the portfolio. You know, this is a black and white discussion, I notice. To me, it's important to put some context around that. I mean, we are running with a balance sheet, a solid balance sheet, double A minus rating, 13% net debt, $15 billion in cash and cash equivalents.
That is for us to be able to follow through our activity in a cyclical business. Then we are growing the cash flow, and so on. We have a, I must say, a great project portfolio that we would like to realize. Then we have a firm dividend policy, and the dividend policy is very important for me that is both predictable and trustworthy, and that you believe that this will come, and that we are able to handle this in, you know, an uncertain world and so on. You know, we have the liquidity, we have the balance sheet, we have flexibility into the investment program, and we have also flexibility in other parts of the company. This is a lot of things goes into this.
Of all the things in the world to worry about, this is not one of them you should be worried about, to be honest.
Great. Thank you. Specifically on the sort of cost inflation in on the NCS, is there sort of anything you can talk about sort of bottlenecks you're seeing in the services market there?
Well, there are certain, you know, elements in the market where there are scarcity. We all know that. There are other areas that have capacity. The way we. I mean, there will be some cost inflation typically. It's all about how to position yourself and handle it. I think the size of Statoil has actually enabled us to deal with that quite well. Taking longer-term positions within rig capacity, frame agreements, on, you know, the steps that we procure. Working closely with the suppliers, knowing that we have capacity with them. Also, you know, working with standardizing the project portfolio and working more effectively with them.
I think the fast-track portfolio is a great example of that. Where we have said that, you know, these fields should be developed in a quite similar way using, you know, this type of subsea templates, this type of risers, this type of valves, and so on. You know, we have reduced the cost by some 30% on those fields and the time from discovery to production by 50%. You know, that's the way we think about dealing with that. It is a tight market in certain areas, and yes, we will be somewhat impacted on it over time. It's really important to take some longer-term perspective and longer-term positions to handle that.
I do think we are dealing with that in a good manner.
Okay. Thank you, Torgrim. That's great.
We'll take our next question from Michele Della Vigna from Goldman Sachs. Please go ahead, Michele.
Hi. Thank you for the presentation. I had two quick questions. The first one is whether you could give us a guidance on the tax rate for next year. Are we still likely to be at the top of the 70%-72% range or in a different place? And secondly, just going back for one moment to the question about cost inflation in the NCS. Your position clearly allows you to get some good frame agreements and some discounts. Overall, what is the level of percentage cost inflation that you're seeing in the market?
Okay, thank you. Kåre, if you can take the tax question. When it comes to the specific rate, I'm not ready to give that. There is, you know, a global market within certain elements, so we are to a larger extent capitalizing on that and using that also to deal with that. Kåre?
Yeah. The adjusted tax rate year to date, we are at 72.3%, in line with our guidance of 70%-72%, maybe a little bit above. We will revert to if there are any changes to it when we address it in February, but we don't see any signs of any major changes. Of course, we will reassess it when the year has passed and come back to that.
Thank you.
We'll take our next question from Robert Kessler from Tudor, Pickering, Holt & Co. Please go ahead, Robert.
Hi. Thanks. Good afternoon. I know you've gotten a lot of questions on Marcellus already, but a couple more from me if you don't mind. One is, you've quantified the rate of change in the plan, but I haven't heard, I don't think, the new plan as far as how much growth you expect from U.S. Gas next year versus this year. Related to that, how much of a contribution might you receive from the liquidation of drilled but uncompleted wells or wells that have been completed that are still stuck behind pipe?
Okay. Thank you, Robert. I mean, what we have said that it will impact our outlook with some 25,000 barrels per day. You know, that was on a you know, quite a good growth trajectories. There will be some growth in Marcellus next year, but it is you know, I would say limited. That is as far as I can go on that one. When it comes to Marcellus and you know, well, that is ready. I mean, there are some 230 wells that we have drilled that you know is waiting for gathering systems and needs to be completed and so on.
It's a quite an okay environment or inventory of wells.
Yeah. Okay, thanks for that. An unrelated one, if you don't mind. Your Barents Sea exploration program for next year, do you have an aggregate unrisked resource size estimate you might be willing to share on that program?
Okay. Thank you. No, I'm not. I can say that, you know, we find, you know, the Barents very interesting. It is a huge area, so there are lots of different places. You know, when we Skugard and Havis discoveries you know opened up a totally new play in that area, and that is what we are pursuing now with quite a few of the nine-well program. We are going to test out something that is called the Hoop area, that is further north, and that is the northernmost wells that have been drilled, you know, in Norwegian waters. That is sort of a very virgin area. It has, of course, a lower probability for discoveries, but again, potential is absolutely there.
Now, I would have liked to give you all the details that I have, but I don't think it is prudent, Robert. You know, we are very encouraged by the development in the Barents area.
Well, well, thanks for the color, and goodbye.
I'll take the next question from John Olaisen from ABG. Please, John.
Yeah, hi there. A question on the oil price break-even level. It's possible to give some kind of indication of where your oil price break-even level is for 2012 after dividends. Maybe also for 2013 with lower production and higher CapEx, how much will that cash break-even level increase in 2013?
Okay, John, thank you. Svein, do you mind? Yes.
If you look at the cash flow from the three Q1 s of 2012, what Torgrim showed today, he showed a graph then. With the cash flow from operations, deducting CapEx, adding on what we have received in divestments and dividend, and then showing a surplus of NOK 35 billion based on what we see there. We have paid one more installment of tax, as we said in first of October, and we will pay one more. So far in 2012, we are on a big cash surplus of NOK 35 billion. And then with the prices that we have realized now.
Going into 2013, I think that is too early to say. We will come back to that with an updated forecast for the CapEx and those things in February.
Okay. My second question goes to the sales of some U.S. assets that's required with the Brigham acquisition. Can you tell us how that is moving forward and maybe how big will those sales be, like in proportion of the Brigham acquisition, please?
Do you have the details on that, Svein?
I do not have the details that we are in a position to disclose, no. It's optimizing the portfolio. It's not a big one.
No, it's. Yeah. In general, John, it's a natural part of what we do within conventionals all the time. There are some acreage that we divest and there are other acreage that is, you know, acquired. It's sort of natural part of optimizing the portfolio as such.
If I read you correctly, it will be a small proportion of the Brigham acquisition that will actually be sold.
Well, yeah. I think sort of, I mean, it's a natural part of, you know, optimizing around the portfolio that is, you know, ongoing around all assets.
Okay. Okay, thank you.
We'll take the next question from Matthew Yates of Bank of America. Please go ahead, Matthew.
Hi, good afternoon. We've heard you adjust your guidance on the gas production in light of market conditions. Could you elaborate a little bit more on the Canadian side with the oil sands, whether you've seen any change in environment there to affect some of your thinking? Thanks a lot.
Okay, Matthew. Thank you. On the Canadian side, we are exporting gas from ourselves into the Toronto area. In the Toronto area, it is healthy demand. Historically, that area has been sourced by gas from the west that now is used within the oil sands business, opening up a new market from the south. We will actually export gas out of the U.S., which is an interesting concept, but it's actually working very well and we are earning money in that respect. Was that answering your question, Matthew?
I'm sorry. I was referring more to the planned investments towards the back end of the decade in the oil sands, given that the realizations for the Canadian oil sands are pretty weak at the moment. Whether you view that as just a temporary bottleneck issue or whether it's more structural and you may rethink your commitment there?
I think, I mean, you're touching upon a very important general theme in the U.S., and that is actually bottleneck issues, which is seen, you know, on many of the unconventional plays due to that structural step in production. You know, there is something about market forces that works, and they actually works pretty well in that part of the world. Over time, I do see that, you know, bottleneck issues will be, you know, gradually be less and less as, you know, infrastructure is built and industry develops. Yes, you're right, there are bottleneck issues currently that is we are actually handling well.
All right, thanks very much.
We'll take our next question from Irene Himona from Société Générale. Please go ahead, Irene.
Thank you. Good afternoon. I had three short questions. First of all, you're guiding for a lower 2013 production. Should we expect depreciation charges to also be lower due to that? Second, enhanced oil recovery and the 60% target, can you talk a little bit about the economics of these projects? Obviously they work in a world of $110 oil. To what extent is the expected higher CapEx next year linked to that? Then finally, your Q3 exploration expense included $1.6 billion from previous periods. I'm told that relates to the Peon gas discovery. Can you talk a little bit about what that tells you concerning commercialization of discovery such as Peon shallow reservoirs, in other words? Thank you.
Okay, thank you. Thank you, Irene. When it comes to DD&A in 2013, when it comes to the assets that we have divested, Yoa and Vega and Brage, I mean, that will lead to reduced DD&A related to those fields. Yes, it will have an impact in that respect. On the gas side, it will also have some effect on the DD&A. When it comes to IOR, 60% and, you know, economics, you know, IOR projects are normally very profitable. I think the average internal rate of return we have seen across that portfolio lately is a 45% internal rate of return. These projects compete very well.
Now we have crossed, you know, the 50% limit, and you know, working hard going forward. This is very much about, you know, technology development, you know, within reservoir diagnostics, about drilling technologies, and so on, and how we can actually get the reservoirs to flow even better. We have recently opened a new IOR center in Trondheim, where we are going to use quite a bit of efforts to address, you know, all of these opportunities and so on. You know, I visited that a few weeks back, and I'm, you know, really fascinated on what you actually can do currently, both on, you know, reservoir characterization and also on the drilling technologies.
I'm really looking forward to that, and I'm sure this is going to be highly valuable going forward, as well. When it comes to whether this impacts CapEx, I mean, next year we will spend some NOK 2.8 billion on R&D, which is quite a significant step-up, and is much linked to IOR efforts and so on. Over time, it will, you know, feed into investment, into profitable projects and so on. You know, this quarter we have sanctions on four IOR projects. I mean, we are moving ahead on this one, and I'm really looking forward to that development. Irene, you had a question on expense of exploration from previous period and Peon. Kåre?
Yes.
Yeah. I want to answer more in general terms, and that is for accounting purposes, there is also a time horizon you have to evaluate when you are looking at your capital expenditure. You need to have a firm plan in the near future to have it on your books. Of course, as you work with your portfolio, that could change. The underlying business case doesn't change due to the timing of it. You can say this is also a result of some prioritization in what you take into account, when you make plans, and then we have to convert that into the accounting language, so to say, and sometimes we get that result. Basically no changes in the commerciality of those variations.
Yes, thank you very much.
We'll take our next question from Teodor Sveen-Nilsen from Swedbank First Securities. Please go ahead, Teodor.
Good afternoon. Just a question on the 2013 production guidance. You already highlighted a couple of items that will lead to lower production in 2013. Have you seen an underlying decline on your current portfolio?
Also secondly, when it comes to Sverdrup, are you planning to come with a new resource estimate before year-end 2012? Or will it wait until Lundin has built the two appraisal wells as well on 501, before you disclose a new resource estimate? Thank you.
Okay, Teodor Sveen-Nilsen. Thank you. When it comes to the underlying decline, I mean, this is developing, you know, healthy and as we have expected. There are no indication that the decline rate is increasing. It is still 5% as it has been over the last years. That is developing just as it should. When it comes to Johan Sverdrup and the new resource estimate, we have said next year. Yeah.
Next year.
Next year, we have said. It will not come in 2012, Teodor. It's of course there are two licenses that needs to put their heads together and sort of agreeing around this. It is next year, Teodor.
Okay. Just to clarify, you will not say anything for PL 265 this year?
No, we don't intend to.
Okay, thank you.
We'll take our next question from Jon Rigby with UBS. Please go ahead, Jon.
Oh, hi. Thanks for the questions. I admire your stamina. Just three quick ones, actually. The first is on the balance sheet. Now, I recognize that since Macondo, you've been generating lots of free cash flow, both because of the oil price and the disposals. Is the shape of the balance sheet with such a large amount of cash sat on it something that you see as being appropriate going forward? Or are you just waiting for the right time to start paying down some of your debt facilities? The first question. The second, just on Bakken, can I confirm where you are in terms of realizing the better oil price realizations? Is the rail car work that you've been doing now in place?
Is it sort of in the Q3 numbers, or do you have more upside, potentially both volume and price? Lastly, just on the last note you have in the release, can you just confirm that the deferred tax changes that you referenced, that's purely non-cash. There won't be any go forward effects in terms of actual taxes and cash taxes. Thanks.
Okay, thank you. On the deferred taxes, quarter, and I can take other ones first. I mean, yes, it's absolutely right observation that, you know, the balance sheet is quite cash-rich, and that is by purpose. You know, having liquidity at hand is something that is important to us, and so on. I think the way you should read that is related to the uncertainty in the macro environment and so on. To me, it's, and for us as a company, it is extremely important to be prepared for, you know, almost any outcome, and any development in the macro environment. What, you know, this industry and all the industry learned after 2008 was the importance of cash.
You know that is managed diligently and actively, but quite conservatively. We will continue to run with both a solid balance sheet and a significant liquidity. When it comes to the liquidity, you know, it is fluctuating, and the day after, you know, this quarter, we paid NOK 20 billion in taxes. It goes up and down, as you understand. When it comes to rail in Bakken, we have a rail in place. It will grow over the next year. We have, you know, when it comes to the summer, I think it is then we will have some 1,040 rail cars available, and that is sufficient to cover our needs.
You know, you should look at, you know, these rail cars as an onshore LNG ship. You can actually get your oils to exactly where you get the best price of it. This can go north and south and east and west. Part of that is below the line. A limited part is part of the Q3 results. A very limited part. Kåre, deferred taxes?
Yeah, deferred taxes. You refer to a subsequent event where in the national budget there was a white paper suggesting to accept all income and costs related to foreign petroleum activity. We have a deferred tax there, and that's a non-cash effect. We have assumed to get that reduced from our future cash payments. That's why it's deferred. It has no immediate cash effect, but we have assumed to get the deducted from the tax return in the years to come. When it comes to future effects with the present setup
For our activity, then it will have an influence on the international tax rate.
Right. Good. Thank you.
Our next question comes from Kim Fustier with Credit Suisse. Please go ahead, Kim.
Hi, Torgrim. Just two quick questions, if I may. Firstly, just on Snøhvit and Barents Sea gas. You've recently stopped work on a possible second train at Snøhvit, or alternatively, pipeline. My question is, when do you think you'll have firmed up enough gas resources in the broader area to be able to get back to the drawing table and look at options again? My second question is on the rig contracting strategy. Just going back to earlier questions on cost inflation. Statoil's been very active in the rig market lately. I think you've recently contracted three new semisubs at quite high rates.
Just wondering if you could give us an update on sort of how many more rigs you need to contract in the next, sort of 6-12 months to be able to execute your drilling plan in the medium term? Thank you.
Okay, thank you, Kim. Thank you. Yes, second train at Snøhvit. Together with our partners there, we decided to not take a decision on the second train on Snøhvit. Just to await the situation. It is, you know, partly linked to that there are more optionalities in the area and also related to, you know, a strong competition for investment funds within Statoil currently, and there are other projects that compete better than this project. But it sits there, and there's an opportunity, and going one time in the future, it will be revisited. I'm sure about that. I can't give you more specific guidance on that.
When it comes to the rig market, I mean, we are active, and it is by purpose. You know, we take a long-term view on our needs, and we know that our portfolio will need rig capacity for long time going forward. I cannot, however, go into you know, some specific comments on you know, contracting strategy going forward. That is something that we would like to keep for ourselves. Thank you, Kim.
Thank you.
Our last question today comes from Brendan Warn with Jefferies. Please go ahead, Brendan.
Yeah, thanks for that, Hilde. I agree with the comments. Just, I'll limit myself to one question. I'll cut the questions off. Just, can you remind us in terms of East Africa, just your current rig capacity? I guess the question more specifically, just timing around the drilling commencements in Mozambique and just whether this Total/Petronas well is going to influence the positioning of the first well that you'll drill.
I mean, when it comes to, you know, we have a global rig fleet, Brendan, and sort of we tend to move rigs around where they actually can, you know, be to the best use for us. We have the capacity available for the appraisal programs that we want to put in place. That's sort of fine going forward. You asked about Mozambique. I mean, do you have that thing on rigs?
Yes. The plans for Mozambique is that we will land probably the first well in the license, and it's scheduled for Q2 in 2013.
Okay. Thank you.
Okay. Thanks, Torgrim.
Thank you. That's where we'll have to conclude our Q&A session for today. As usual, you can download the presentation and this Q&A session from our website in a few days, and there will also be transcripts available. If you have any further questions, please don't hesitate to contact us in the IR department. Thank you all.