Good morning, ladies and gentlemen. Welcome to Statoil's second quarter earnings presentation. I am Hilde Nafstad, and I'm the head of investor relations with Statoil. This morning at 7:00 A.M., Statoil announced the results for the second quarter of 2013. We announced it through the wires and through Oslo Stock Exchange. The report and the presentations can, as usual, be downloaded from our website, statoil.com. I would ask you to kindly make special note of the information regarding forward-looking statements, which can be found at the last page. We will start today with our CEO, Helge Lund, who will go through the earnings and the outlook for the company. As usual, the presentation will be followed by a Q&A session, and we will aim to end the conference at 2:30 P.M. CET.
Please note that the questions can only be posed from the audience or through the telephone. You cannot pose questions directly from the web, and you will find the dial-in numbers for posing questions on our website. Now it's my privilege to introduce Statoil's Chief Financial Officer, Torgrim Reitan. Please, Torgrim.
Thank you, Hilde, and good afternoon, and good morning to all of you in the U.S. In the second quarter, Statoil delivered adjusted earnings of NOK 38 billion. Strong performance, particularly from our international portfolio. Our financial results were impacted by lower prices and weak results from our marketing business. Our operations in the quarter were solid. We produced as planned, ramping up new production on the NCS and producing record volumes outside Norway. At the same time, we maintained stable underlying. We have earlier said 2013 production will be lower than 2012. This is due to commercial decisions we have made to increase value creation, like divestments on the NCS, and using our gas flexibility. Our production was broadly in line with what is needed for the full year.
Please note that our divestment with Wintershall and the Ormen Lange redetermination will have full effect in the second half of the year. This summer, our activity level in terms of project execution is high. One example is the Gudrun project in the North Sea. This is a global project with components from Thailand, Poland, Norway, Singapore, and China. On Thursday, the topside was lifted into place on the steel jacket, successfully completing one of the most important project milestones. Now we prepare for production start early next year as planned, and we are on time and around NOK 2 billion below cost. We continue to deliver industrial progress in the quarter and in line with our strategy. We sanctioned three new projects in the quarter and received government approval for four major NCS developments.
We decided to invest in a joint oil export solution for Edvard Grieg and Ivar Aasen, enabling future growth in the Utsira High. The Shah Deniz consortium selected a Trans-Adriatic Pipeline to efficiently bring the gas from phase two of Shah Deniz to the European market. We took over operatorship in Eagle Ford, strengthening our position in the U.S. onshore now with operatorship in all our three premium plays. We continue to prioritize robustness and value creation in our portfolio. In the quarter, we announced a review of the Johan Castberg development in the Barents Sea due to updated project estimates and awaiting clarifications in the tax framework. We also took down our U.S. rig count further to optimize our CapEx. We are achieving better efficiency in our drilling operations. Finally, we continue to deliver on our exploration strategy.
In 2011 and 2012, Statoil was among the companies finding most and largest discoveries. The drill bit has delivered 550 MMbbl so far this year, and this compares well with the success the last two years, where more than 1 billion barrels were discovered. We made five discoveries in the quarter, and we secured attractive exploration acreage. In Norway, we were awarded seven licenses in the 22nd round. In Russia, we signed new agreements in a joint venture with Rosneft. We will explore offshore Azerbaijan in the Caspian with SOCAR. In Brazil, we were awarded six licenses in the 11th round. In Tanzania, we farmed into Block 6. In Australia, we farmed into four offshore licenses in the south. It's a long list. By this, we take important new steps to position Statoil for the future.
Our net income is down compared to second quarter last year. As you know, we booked significant gains in the second quarter last year after completing the divestment of our retail business and the NCS Assets package to Centrica. We had actually around NOK 16 billion in one-off effects in the same quarter last year. Due to currency changes and increasing interest rates, net financial items contributed to a lower result for the quarter this year. As always, we make adjustments to our results to reflect the underlying business. This quarter, our adjusted earnings decreased somewhat. This is mainly due to lower realized prices for liquids and gas and changes in the production mix. We had lower earnings from marketing and trading that impacted the results, and I will come back to that in more detail on that segment.
However, we produced at record levels from our portfolio outside Norway, and that contributes to strong international earnings. As you know, depreciation normally fluctuates with production, but we have ramped up production and started new fields in the quarter. This quarter, we increased production at Skarv with a depreciation cost of around NOK 300 per barrel. This will increase over time from that field and on average, the DD&A over the lifetime is typically half of the initial DD&A. We also have lower production from older fields like Troll and Kvitebjørn, which have much lower depreciation, around NOK 20-NOK 30 per barrel. As you can see, our DD&A is impacted by the production mix.
New projects have higher depreciation per barrel due to the booking profile that you saw of the FCP reserves, and because new projects are more expensive than the old ones. This is a trend across the industry. As we continue to put new production on stream, you should expect our depreciation per barrel to increase. In 2014, this effect is particularly clear as we start producing from large new fields such as Gudrun, Goliat, and Valemon on the NCS. We maintained a stable underlying operating cost through the period. This is as expected and something I watch very closely, and I will come back to this in further detail later. Adjusted after tax, we generated NOK 11.3 billion, and this is on par with the second quarter last year.
The lower tax rate is the result of relatively higher production from lower tax regimes outside Norway. In the second quarter, we produced as planned. We maintained a stable FCP production. As previously mentioned, we delivered record production from a project outside Norway. Overall, the production was in line with our expectations. This is not more than what we need for the year as a whole. As we have said, we expect to produce less this year compared to last year, mainly due to divestments, gas optimizations, the redetermination at Ormen Lange, reduced capacity at Troll and in In Amenas. We also expect to carry out most of our turnarounds in the second half. I will come back to this further, when we talk about the outlook. The segment.
From our Norwegian business, we delivered adjusted earnings of NOK 31.5 billion. Compared to the same quarter last year, earnings were mainly affected by deliberately lower gas production and farm-down at Kvitebjørn and operational disruptions at the Troll and Snorre. We largely offset the natural decline on mature fields by ramping up production, including four new fast-track projects. As mentioned, DD&A is increasing as expected in DPN. From our operations outside Norway, adjusted earnings were NOK 5.9 billion. Our earnings have almost doubled from the same period last year, and we produce more than one-third of our volumes outside Norway.
The cash flow per barrel from our international portfolio is at least as good as from our Norwegian production. Increased our entitlement production by 11% by successfully ramping up Marcellus, Bakken, and Eagle Ford in the U.S., Peregrino in Brazil, and PSVM in Angola. Production was also positively impacted by operational improvements, in particular in Azerbaijan. The increase was partly offset by natural decline at several fields and decreased production at In Amenas. The results from marketing, processing, and renewable was NOK 0.8 billion. I'm disappointed by that result. It is mainly due to losses on the natural gas trading, weak trading in crude oil and products, and lower refinery margins. In addition, the results were impacted by lower NCS volumes.
Please also recall that the second quarter last year was a very good quarter for MPR across the board. Our overall realized gas price is down, but that is due to the higher share of U.S. gas in the global mix. If you look at the European prices, the realized gas prices were on par with the prices realized through the winter season, and they are still strong. Lastly, it's important to note that the value creation that comes from the flexibility in the gas machine is mostly reflected in our upstream results. We have stated earlier that MPR results will be more volatile. Trading results are by definition volatile. We have ramped down our ownership share in Gassled, which affected our results by around $1 billion per quarter.
We have delivered a cash flow from underlying operations of NOK 107 billion year to date. The change from last year is mainly due to lower prices and a lower production. We made three tax payments in the first half of 2013, and these were based on last year's earnings. Our NCS tax payments will be somewhat lower in the second half of the year. We paid our dividends of NOK 22 billion in May, and NOK 6.75 per share gives a solid dividend yield to our shareholders. We have invested NOK 59 billion into our projects, and this is according to plan and in line with our estimate of organic gross CapEx of $19 billion for the year as a whole.
Adjusted net debt to capital employed increased from 12.5% to 20.8% at the end of the quarter. An increased debt rate is according to our expectations. However, we do expect a somewhat lower gearing at year-end. The Wintershall transaction is expected to close after July 31st, and that will bring in proceeds, and tax payments will be lower in the second half of the year. We continue to maintain a firm financial framework and a solid balance sheet. As we discussed in the previous quarter, we are working constantly to improve our cost position further. In DPN and DPM, we have maintained stable underlying total cost for six quarters now. This is despite having more fields in production and despite industry cost inflation.
In the second half, we will produce less due to turnaround, and I would like to remind you that in the short term, our operating costs are to a large extent fixed, so you should expect a higher cost per barrel in the next quarter. In MPR, the improvement program we have put in place is paying off. Quarterly variations will naturally occur due to seasonal changes in volume. In the international segment, we continue to deliver profitable growth. The growth in operating costs and DD&A is explained by higher royalties and transportation costs. Compared to last year, diluent cost in Canada is now included in operating costs. The change since the second quarter last year is related to A, activities, more fields in production, higher transportation costs, and royalties. B, external factors such as increased CO2 tax on NCS.
The underlying operating cost is stable. Let's move to depreciations. We see an increase in DPN this quarter. We are putting new fields on stream with higher depreciation at the start of the life cycle, as we discussed earlier. Internationally, however, you will notice that we have improved the unit DD&A from the same period last year. In general, DD&A will vary between quarters also in the future, but you should expect to see higher levels as new fields are put in. We will continue to improve our cost base and further strengthen our competitiveness. Statoil has an attractive portfolio with more than 100 competitive projects. Through the summer, huge operations are taking place.
Over the last 12 months, 32 million work hours have been invested in projects where we are the operator, and I'm very impressed by the work done in the various project teams. We use the summer season, you know, with calmer seas and less wind to carry out the big lifts, lay pipelines and cables, and install subsea templates and risers. You have seen the progress on Gudrun, which I mentioned earlier. We have also installed the first modules on Aasta Hansteen subsea compression and subsea templates for three fast-track projects. On Valemon, we are transporting new modules to South Korea, where the topside are under construction as we speak. We work restlessly with improvement agendas across the organization, and we are delivering strong results. Of course, we are delivering our projects at or below our estimates.
We also forecast to reach all the main milestones for 2013. These are strong results and evidence of our robust project execution capabilities. Now let's talk about our outlook. As we have discussed earlier, our growth will not be linear. 2013 production will be lower than 2012, and this is due to commercial decisions we have made. Divesting NCS assets, realizing significant gains, optimizing gas offtake for maximum value creation. As we have said previously, we now have more resources in our portfolio than we need to reach our 2020 production ambition. We are prioritizing strongly among competitive investment opportunities. We are on track for our ambition to produce more than 3.5 MMbbl of oil in 2020.
As we said, value creation is what we do, and we are of course not married to any production numbers. Turning more specifically to our outlook, the Ormen Lange redetermination will reduce production by 20,000 bpd on an annual basis this year. This means around 40,000 bbl in the second half of the year. The divestment to Wintershall will also impact our production. 40,000 bpd from the closing, which is in a few days, 31st of July . We have decided to move some of our maintenance work from the second quarter towards the second half. For the full year, we expect our maintenance to reduce equity production by around 45,000 bpd . Most of this is at our oil and liquid producing fields.
We expect the turnaround effect in the third quarter to be around 110,000 bpd . Currently, we have reduced capacity, limiting the flexibility. The situation at In Amenas will also affect output in 2013. We will invest around $19 billion in 2013, as expected. We are bringing new projects online with low break-even price across the portfolio, delivering industry-leading rates of return. We expect to receive the proceeds from Wintershall during the next quarter, leading to net cash flow to investments being less than the gross investments of $19 billion. We will explore for around $3.5 billion, drilling around 50 wells in this year, and we will drill around 20 high-impact wells from 2013 to 2015.
We have a high inventory of competitive projects, and we will continuously optimize the timing around this. I know you like to watch our wells, so let me give you some wells to watch. The Barents Sea campaign in the Johan Castberg area continues. We believe in further oil potential in this area. Iskrystall is next out, and operations have started on that well. In East Canada, Harpoon delivered an oil discovery. While it's too early to determine the resource potential at this time, it is encouraging for the area and for the Bay du Nord well that is currently being drilled. We are preparing to start drilling on the Buzio well in Mozambique anytime. These are exciting times for our exploration team.
To round up, Statoil delivered strong operations in the quarter. Our financial results are impacted by lower prices for liquids and gas and a weak result from MPR. We produced as planned, we delivered record international production contributing to strong international earnings, and we maintained stable underlying operations, operating costs. Our activity level on the new field development is high, and we execute our project according to plan. We continued our exploration progress by accessing attractive exploration acres, and we are on track and maintain our guidance for 2013. Looking ahead, Statoil is well-positioned to grow and create value. We continue to efficiently develop our project portfolio. We have a strong resource base, and we are prioritizing strongly. We will maintain a firm financial framework, and we will continue to pay a predictable and a growing dividend to our shareholders.
We will do all of this while we are keeping our balance sheet solid. Thank you very much for your attention. I'll leave the word to you, Hilde, to lead us through the Q&A session.
Thank you very much, Torgrim. For the Q&A session, Torgrim will be joined by Svein Skeie, who is Senior Vice President for Performance Management and Risk, and Ørjan Kvelvane, who is Senior Vice President for Accounting and Financial Compliance. We'll start out with questions from the audience here in Oslo and then turn to the telephone audience. First I will ask the operator to please repeat the procedure for posing questions over the telephone. Please go ahead, operator.
To ask a question on the telephone, please press star one on your telephone keypad.
Thank you. We'll start out with the questions from the audience in Oslo, and I'll ask you to introduce yourself. Please limit yourself to one question. Also, if you have forgotten how to use the microphone, there's a card in front of it.
You push the button, and when it's red, you can speak. Okay, Trond, you're first.
Trond Omdal, Arctic Securities. You say the Troll compressor is limiting. It's not limiting capacity, but it's limiting your flexibility short term. Can you, when will that be finished? Will it be by Q1 or Q2 next year or finally replaced with the new compressor?
Thank you, Trond. The Troll compressor, the new Troll compressor will be in place in the second half in 2014. When that is said, we have capacity to produce more or less the production permitted during the year, but there is limited flexibility to profile the gas.
Can I just follow up on that specific? For the trading, what the poor results in the trading division, that was also impacted by trading losses?
The trading, so since there has been less flexibility at Troll, there are less and less profit in the trading organization this quarter.
Teodor?
Okay, let me from Swedbank first. Regarding the weak trading results that you already touched upon, Torgrim, there's no doubt about that, both this quarter and last quarter, it was well below consensus estimates and also well below your historical margins in the MPR division. I'm fully aware that the results will be volatile, but the two last quarters, does it signal a step change in the profitability in this division? Should we expect lower earnings going forward?
Okay. Thank you, Teodor. First, a couple of points. Historically, the profit from Gassled has been part of that segment. That was NOK 1 billion on a quarterly basis. That, you know, provided both profitability and stability into that segment. That is divested now, less results and more volatility. We must be prepared for strong results and weak results from this segment. Last year was a record set of numbers. This year so far it has been disappointing numbers. On an overall level, you should expect solid results from a business like this, but they are typically more able to make profits in contango markets than in a backwardated market on the oil side.
On the gas side, you will typically, you know, also be subject to the structures in the market, as such. It is not a systematic change, as we see it. It is two quarters in a row with disappointing results. Then again, if you look in last year and so on, a solid contribution for this, from this area.
Okay, the main reason is then from all of them, just the shape of the forward curve.
On the trading side, it is partly market structures. It is partly operational issues we'd like to touch upon on Troll that limits the opportunities on the gas side to earn money. It is partly related to Snøhvit being out, so there have been few cargos to arbitrate around. The value generated from sending those cargos to high-priced markets typically is in the MPR segment. Then there has been generally disappointing results from trading on top of that.
Thank you.
Do we have any further questions from Oslo? Yes, please go ahead.
From Nordea.
Turn off, please.
Kelly from Nordea Markets. Regarding your record-breaking international production, I noticed that most of the gain was from onshore U.S. production, and within that from Marcellus Gas. Could you give us an indication of whether or not this growth is to be expected going forwards? Will the production remain at this level? Also perhaps a bit on the rig count in the region as well.
Okay. All right. Thank you, Kelly. Production from Marcellus is increasing. It is increasing less than it would have done if we had kept up the rig count. We have taken it down from around 30 rigs to 14 rigs currently. That's the state. Going forward, you should expect it to continue to grow, but at a lower pace than earlier.
Any further questions? Yes, please.
Dag Ring from Handelsbanken. Can I also comment on the Eagle Ford and Bakken because Bakken has a 30% growth year-over-year and the Eagle Ford a hundred and forty percent. It's quite impressive. What to expect forward?
The rig count currently at Bakken is 10 rigs we are running there. We have taken on the rig counts also there to run a number of rigs where we feel that we really can extract the learning across the rigs as we develop, you know, drilling more efficiently and technology and fracking and all of that. That's a typical rig count to plan for going forward there. I can't give specific growth profile out of Bakken and Eagle Ford, but you have to correct me, Svein, but sort of a lower growth rate than we have seen over the last year, I think is fair to assume.
Okay. Do we have any further questions from Oslo? If not, we'll turn to our telephone audience. The first question comes from Peter Hutton with RBC. Please go ahead, Peter.
Hi. Thanks for taking the question. It's a confirmation on the Bakken there. You said you're operating 10. What was that before? I think in the first quarter you said that in the first quarter you produced 47,000 bpd , and over the rest of the year it would be more like 40,000 bpd-45,000bpd. Is that still correct? And the second part of the first question is on the cash flow and CapEx. And I know that there were two payments out for tax, but even adjusting for that, the second quarter underlying cash flow generation was just about NOK 8 billion, which is compared to NOK 30 billion a year ago. Is there something in terms of cash absorption that we're not seeing coming through on that one?
I'm struggling to get those two to tie in particularly effectively. Then, also on cash, you were able to confirm the CapEx guidance of $19 billion for this year. Are you also able to confirm the $21 billion average $13 billion-$16 billion as well at this stage? Thank you.
Okay. Thank you, Peter. That was one long question. Let's see here. On Bakken, we have taken down the rig count from around 15 rigs last year to 10 currently. When it comes to, maybe you can address the cash flow question, the details there, Svein. On the investment, yes, $19 billion for this year. We are running our investment portfolio without delays and overruns, so it's very stable, the forecast that we currently run. The $21 billion in investments is also intact as we see it. The $21 billion is consistent with delivering 2.5 MMbpd in 2020. Of course, our portfolio has the potential to produce well beyond that.
To get to $21 billion, hard prioritization among good investment opportunities will happen. $21 billion is what we plan for.
Excellent. Thank you.
Regarding the cash flow for 2013, in the first half of the year, as you said, it has been lower. It is mainly then related to that we are paying the taxes based on the results from last year, from the Norwegian Continental Shelf, where we had higher production. In the second half of the year, we expect that taxes could be somewhat lower. In addition, on the cash flow side, in the results from MPR is affecting the cash flow in the first half.
On the CapEx side, as Torgrim also said in his presentations, is that we just do get the proceeds then from the Wintershall transaction, which is coming up by end of this month.
Generally phasing more cash second half.
Peter, could you repeat that? It was hard to hear you.
Generally phasing issues, more cash expected in the second half.
Yeah. We will get the effect of the tax in the Norwegian assets, affecting the production level for this year and not then the level from last year.
Okay. Thank you.
Thank you.
Continue the next question goes to Guy Baber from Simmons & Company. Please go ahead, Guy.
Hi. Thanks for taking my question. I had a question about the Eagle Ford. Production picked up nicely there for the quarter. Now that you've taken over operatorship in the eastern part of the play, I was just wondering if you could address how comfortable you are with the size of your position there. It's obviously smaller relative to some of your other plays. You know, when people hear there's an opportunity to increase your exposure there. More broadly, are you still looking to add to your NAM onshore portfolio acreage position?
Okay, thank you. We have taken on the operatorships. That is going very well. I mean, the efficiency in the drilling operations is improving and the cost of well is improving. That's good to see. This is a rather small asset in our portfolio. It is a good asset, and generally we are fine with it, across the unconventional sector. It is, you know, we positioned those early in both Eagle Ford, Bakken and Marcellus, and we are pretty comfortable with the positions that we have. When that is said, of course, if the right opportunity is there and the price is great, then of course we will take a look at things. Generally we are fine with it and happy with the portfolio that we have.
Thank you. The next question comes from Brandon Mei from Tudor, Pickering, Holt. Please go ahead, Brandon.
Hi. On the marketing and trading results you touched upon, you know, lower results due to operational issues on the upstream volumes. Can you give some color on dollar impact there due to the lower volumes?
Okay. It was the impact of lower volumes on the trading results. It is on the MPR side. I can't give specific numbers on the volumes. It is contributing to a lower result. Can you recall how much it was?
I think if you look at the entitlement volumes from NCS last year it was around 10-ish. This year it's approximately nine-ish. We have less there. Then of course the price will also affect it. It's around from 10-ish down to nine-ish in the volumes.
Yes. Our next question comes from Brendan Warn from Jefferies. Please go ahead, Brendan.
Yeah. Thanks, Hilde, and thanks, Torgrim, for taking our questions. Look, just one question. Just can you give us a bit of an update on your gas commercialization negotiations in Tanzania? Just perhaps a bit of an outline on steps forward in terms of appraisal board, when you believe you're at sort of threshold volumetrics. Just can you remind us of timeline to something like a financial investment decision, please?
Okay. Thank you, Brandon. Good progress in Tanzania. Great discoveries, significant volumes and sufficient volumes to move forward. That makes us, you know, more confident of a commercial decision. We noticed quite a bit of interest from buyers towards these assets, so that is solid. We work together with BG to establish location for the onshore site, and that is typically something that we will share. We have more work to be done in the license and more wells to be drilled. LNG is a scale game, so the more volumes, the better profitability. The first priority is of course to maximize the volumes in place and then move forward towards the decision point.
I'm not prepared to give a date for that, but the progress is good, and we are working and our partners.
Okay, thanks for that, Torgrim.
Thank you, Brandon. The next question comes from Jeremy Aston from Exane. Please go ahead, Jeremy.
Hi there. Thanks for taking my questions. A couple of exploration questions. Firstly, Cachalote was dry. Should Buzio also be dry, will you throw in the towel in Mozambique? Secondly, Det norske, your partners, have just announced that the primary target of Cliffhanger North is dry. Could you possibly describe what you found in the secondary target? Thank you.
Yes. Cachalote, the status is known, so we are moving Discoverer Americas. We have moved Discoverer Americas to the other well, and that is being worked. Beyond that, there are more opportunities, and they are sort of separate in you know, modeling and so on. We still you know, have interest in that area. When it comes to Cliffhanger North, we will you know, finalize the well. We will conclude with our partners, and then we will communicate around that, well-coordinated with the Norwegian Petroleum Directorate like we do on all the wells on the Norwegian Continental Shelf.
Okay, understood. Thank you.
Thank you. The next question comes from Michael Alsford with Citi. Please go ahead, Michael.
Thanks, Hilde. Good afternoon. I've got a question a bit on the gas market in Europe. I know we've talked a little bit about the trading result that was weak in the quarter, but can you perhaps talk a little bit more broadly about what you're seeing in terms of your key markets for demand for gas, and how sort of the supply outlook is looking, currently? Thank you.
Okay. Thank you, Michael. Gas markets in Europe is strong. We are seeing summer prices, you know, above 65 pence per therm. In a historic perspective, it's great prices. The market is characterized by LNG going other places, so that is firming up the market. We see a growing demand for gas in over the years. Not a big growth, but you know, a 1%-1.5% growth in that market. We see significant decline in indigenous production, and we see that more gas needs to come to the market. That is one part of the equation. The other one is politicians and their appetite for gas as the long-term fuel for Europe.
We see a you know positive development also in that respect. There is maybe one concern, and that is in Germany, where we miss clear statements from politicians that gas is better than coal. We all know the answer to that, but we just are waiting for clarifications. Then the things we have done on our long-term gas contracts that has proved very well, carving back the flexibility, enabling us to you know create additional value and expand our presence in the European gas market. So far so good, and interestingly strong prices in Europe.
Okay. Thank you. Maybe just one comment on inventories. Are you seeing, you know, increased demand because inventories are generally low, or is that simply just like real demand is, short-term demand is high currently?
Well, could you repeat it? I didn't get that fully.
Yeah, just a question on where you see sort of inventories in Europe. Is it sort of simply people refilling low inventories, or are you actually seeing underlying demand strong within Europe, strong?
I mean, there has been the underlying demand has come down since 2008, but we expect that to turn, you know, in a year or two to you know modest growth in this area.
Okay. Thank you very much.
Thank you. Next in line is John Olaisen with ABG Sundal Collier. Please go ahead, John.
Good afternoon. Couple of questions. First on the payable tax this quarter that's, as already discussed, was a lot higher than the P&L tax. Just wondering for the whole year, should we expect the payable tax to be pretty much the same as the P&L tax, or should it be higher or lower? Any arguments on that?
Okay, Jon. Thank you. Svein, please.
As you said, we paid the taxes on the Norwegian Continental Shelf now based on what we saw.
From 2012. We paid half of it in the second half of last year, and then we paid the other part of it in the first part of this year. For the second half, there will be some expectations to what kind of return we are seeing for the remaining part of the year and then calculating the net taxes payable as we see it. That will be based on the returns as well as the capital expenditure. Based on what we see now, we see that it will be lower. I cannot comment on it'll be on the exact same level as the profits from the
With large investments on the NCS and with the depreciations that we do there will be, too, typically, you know, defer taxes. I mean, that contributes to build deferred taxes in that equation.
In net for the year, I suppose, will it all be reverted in the second half? Or just for the magnitude, is it such a huge payable tax charge this quarter?
Yes, this quarter. I think we're not ready to give you the exact numbers on the for the fall, but it will be lower than the first half of the year.
Okay. To the realized oil price in Norway, it was a record high discount to Brent of almost $9. Any reason why it keeps increasing? Any particular fields? Can you hear me?
Yes.
Can you hear me now? Maybe that's better.
Yes.
On the discount to the Brent in Norway, it was a record high of almost $9. Are there any particular fields where the quality of oil is trading at a bigger discount to Brent than it has been in the past? Or any particular field contributing to a lower realized oil price?
The main explanation to that is NGL prices and the share of NGL into the liquid production.
All right. Finally from my side, the natural gas realized gas price. You mentioned that it was due to a higher portion of U.S. gas production. If I just look at the numbers that you provide, it seems like the U.S. gas production contributed with 5.0% of Q2 gas production, while it was 5.1% of Q1 production. Actually the U.S. production was, in percentage terms, slightly lower in Q2 than in Q1. That doesn't seem to explain the dip in your realized gas price. You mentioned that as the reason why the natural gas price was down.
When we compare second quarter with second quarter last year, we see that increased share of U.S. gas is what you know changes the overall.
Sure, year-on-year, but you mentioned Q1.
When you look at the European prices for this quarter, it is on par with what we saw across the fourth quarter and first quarter gas prices.
Sure. You mentioned that the prices in Q2 in Europe were flat compared with the prices in Q1 this year.
We'll have you move on to the next question now to allow time for everybody on. But please feel free to contact Investor Relations for further clarifications. Next question comes from Nitin Sharma with JP Morgan.
Afternoon. One short question. It's around the medium-term free cash flow profile. You're guiding to average organic CapEx 2013-2016 of $21 billion. Could you also please comment on the free cash flow profile of the company over the same period, say assuming a $100 oil price scenario or maybe under your own planning scenario, please?
Okay. Thank you, Nitin. The free cash flow development over the year, if you recall our presentation at the fourth quarter we did in February, we laid out numbers for investments, for operating cash flow, cash, and also an oil price reference price, a price used for calculation purposes, which is at that point $101 per barrel. It was $19 billion in investments, and then it was twenty. Was it $20 billion i n cash flow from operations. 20-
In 2013.
Yeah, in 2013. Yes. You have the dividend. That is, you know, more or less on the same level when it comes to cash flow from operations. The redetermination of Odfjell and NPD results is, you know, impacting the free cash flow for the year heavily. When it comes to oil price assumptions, the sensitivities that we show in the MD&A is valid. An oil price change of $10 per barrel will reduce after tax NOK 8 billion or so. That's metrics that can be used to calculate the various price effects.
Thank you.
Thank you.
Next in line is Jon Rigby with UBS. Please go ahead, Jon.
Yeah. Thanks, Hilde. Can I just ask a question on the back end and then just a quick follow-up on CapEx. On the back end, the profile, it looks impressive year-over-year, but I think it's been noted it's flatlined Q4, Q1, Q2, and you talk about the reduction in wells. But is there anything else coming to old rigs. Is there anything else impacting it, like weather through the winter period which we would expect to unwind in the second half of the year? Is the production rate that we're seeing now consistent with the well count that you talked about. Also on the back end, are there any implications following the crash, the rail crash, rail out crude, for your operations?
Can you remind me how much you do rail out? Then just to come back to you on CapEx, sorry, it's a bit extended, is you did talk about choice and efficiency around choice of projects because of the success you've had. Might we expect that you could look at that $21 billion and maybe the positive impact is that can come down as you divert CapEx into more efficient projects? Thank you.
Thank you. Okay. Let me take the CapEx first. The CapEx in Bakken is, you know, spending there is consistent with the number of rigs that we are running. We see more efficient operations, so we get more out, more worth out of the rigs that we run. That's good. Bakken is performing well, and production is ramping up, and all of that is good. When it comes to the rail crash, the tragic rail crash, we are unfamiliar with that, with the company. There might be some changes in regulations when it comes to railing in U.S. and Canada, so we will follow that very closely.
I'm sure there will be an investigation and learning to be shared with other companies as well. When that is said, the rail cars that we use, 1,040 rail cars, they are built on a different standard than the ones involved in the crash. It's a bit like double hull, like we have in ships that we also have in the rail cars. We follow the latest standards in this respect. You had one last question, John, and that was related to prioritization. Can you repeat that?
It's to do with investments. I mean, you talked about the $21 billion being consistent with your production aspirations, but you've also then name-checked the fact that you've clearly had success developing and identifying better and better projects through the last couple of years. I just wondered, you know, will that translate ultimately to a lower CapEx bill for the same production aspiration, or do you think $21 billion remains about right?
I think $21 billion is what we are prepared to guide for currently, $21 billion a year and 2.5 MMbpd in 2020. You know, all the prioritization being done, meaning that the quality of the growth will improve when you pick the best project.
All right. The quality of the growth doesn't improve through the CapEx intensity. It's on the production or value of the production.
We are not ready to make any adjustment on that basis, Jon. It's a very interesting question.
Okay, thanks. Thanks, Torgrim.
Thank you, Jon. Next question comes from Helge André Martinsen with DNB. Please go ahead, Helge.
Hi. Good afternoon. Two questions if I may. Your DD&A cost on a unit basis is up 28% year-over-year in Q2, and 22% in the first half of the year. You warn of a further increase in DD&A cost for 2014. Could you please indicate the growth rate for the DD&A unit cost for 2014? Are we talking about 20%-30%, on a year-on-year basis?
Okay. Thank you, Helge. The growth rate or a growth rate of 21% or 28% going forward is not what you should expect in, you know, in the longer term. If you take a few years ahead, that's of course too high. But you will see some not a linear development necessarily. You know, I was very explicit in 2014, where we have, you know, a few significant new projects coming on the NCS that will typically contribute the same type of issues, DD&A issues as the Skarv has this year. It's just to give some highlight on that.
The growth rate in that magnitude that you mentioned on an, you know, longer term perspective is not the right number.
But for two thousand and fourteen?
I know we are not prepared to give a specific number on the growth rate on DD&A for 2014. Yeah.
Okay, thanks. I have one more question, if I may, on the realized oil prices for the international business. It dropped relative to Brent compared to Q1, despite that we have seen a significant strengthening of the WTI and Bakken prices relative to Brent. We also have seen improving West African crude differentials. Could you please elaborate a bit on what is driving your international liquids products relative to Brent?
Okay, thank you. Two main drivers there. Peregrino is at a discount to Brent, so there is higher production from Peregrino this quarter. The second one is related to WTI. Our Bakken production, we are railing that out of the Williston area. It has not been priced at a WTI up to now, at least to a lesser extent. That doesn't really make a big difference. The main explanation is Peregrino production. Yeah.
You know, and onshore U.S.
Onshore U.S. production as well. We have liquids production out of Marcellus that has increased significantly, and that is, you know, at a significant discount to both Brent and WTI.
It will follow the WTI price up?
The liquids out of Marcellus is, you know, NGLs, and ethanes, so that will follow that market more than WTI.
Okay, thanks.
We have Rahim Karim with Barclays. Please go ahead, Rahim.
Hi, good afternoon. Just one clarification, please, and then a question on gas markets. The clarification with Torgrim Reitan, when he talks about gearing being lower at the end of the year than where we are today. Can you just reconfirm the guidance you gave at 4Q of around 15% for year-end? The question on the gas markets was, you talked about the success of your historic gas contract renegotiations. I was hoping you could just give us an update just on your current renegotiations. Thank you.
Okay. Thank you, Rahim. At the fourth quarter, we said around 15% net debt at year-end, and then we used the forward prices at that point in time for calculation purposes, and that was $110 per barrel. Prices so far this year is lower. That will have an impact on the gearing. Apart from that, MPR results will also impact the free cash flow from the year earlier. On lower prices and with those effects, you should expect it to be, you know, north of, a bit north of 15% at year-end. On gas markets, gas contracts. We have successfully concluded a significant part of the gas renegotiations.
There are a few outstanding, but those are progressing well. The discussions that we have with our counterparts, again, I think we can characterize them as colorful, but that's the way of negotiations, progressing well. We are offering more of spot indexation into the long-term contracts. In return, flexibility goes away from the contract portfolio, and that flexibility is a good platform to create uplift value creation.
Great. Thank you. Would you say you're on track to finish those negotiations by the end of 2013?
It is progressing well. I will not be surprised if there are a few outstanding by year-end either. That's the nature of renegotiation.
Okay. Thank you. Very helpful.
Thank you, Rahim. We'll take one last question from Jason Kenney with Santander. Please go ahead, Jason.
Hi there, and thanks for taking my question.
Hi.
I'm just curious about the Bloomberg line this morning stating that Statoil management is not focused on the company's share price currently. I can appreciate the focus on operational delivery and the also intense effort to deliver value. I was just wondering if there was something you could do to highlight the inherent deep value in your business, you know, possibly by relating the share price to the underlying NAV. I know you tried to do that with the divestment analogy that at the recent capital markets event. I mean, on the face of it, self-incrimination could be value adding in this respect.
I just wanted to know how management might begin to think about the share price in the future once you get through this kind of intense capital commitment and, you know, operational focus at this time?
Okay. Thank you. I'm a bit puzzled by that Bloomberg says that management is not occupied with the share price because we definitively are. I'm not sure where that comment come from. The way we think about the business is that we need to be very good at what we do. That's the best recipe, and we need to be, you know, good at exploration. We need to have the best projects. We need to be good at developing those and strong at operating those, and then selling oil and gas. If you're good at all of that's a recipe for a strong share price.
If you do that within a firm financial framework, which is, you know, a solid balance sheet, strong gearing, and strict prioritization, I think that's a good medicine for long-term valuation for our shareholders. To me, it's very important to balance all of this well. You know, to what speed we actually push the accelerator. As we have discussed, we have the potential to grow harder. We have the potential to realize even more of our projects, but it's very important for us to find the right pressure on the accelerator. Balancing, you know, picking the best projects, seeing to that we have the execution, control, and capability in place, and also the financial framework that we deliver that in a sound manner.
It was a big question, but I can assure you very much that, as management, we are very occupied by share price and what we are doing compared to our competitors.
Okay. That's what I wanted to hear. Thanks.
Thank you very much. That will conclude the Q&A session for today. Today's presentation and Q&A session can as usual be replayed from our website in a few days, and transcripts will also be available. If you have any further questions, please direct it to us in Investor Relations, and we'll be happy to help you. Thank you all very much for participating, and have a good afternoon.