Equinor ASA (EQNR) 2016 Q3 法說會逐字稿

My name is Peter Hutton, Head of Investor Relations for Statoil. And I'm joined by Hans Jakob Hegge, CFO who will run through the results and key drivers, and we will then open for questions and answers. Also participating on the call today are Svein Skeie, Head of Performance Management and Orjan Kvelvane, Head of Accounting.

We aim for the call to run for a maximum of an hour, and we expect to cover all your questions in that time. The operator will explain the procedure again after the presentation. And with this, I turn the floor over to Hans Jakob to run through the results.

Thank you, Peter. And welcome to all to this third quarter conference call. As you have seen we report an IFRS net operating income in the quarter of $737 million, and an adjusted result of $636 million.

Before I go through the numbers in more detail, I would like to draw your attention to some key points. In the quarter, we delivered positive net cash flow, reducing our net debt to capital employed. We continue to deliver cost improvements across all business areas. And at the Norwegian Continental Shelf our total costs are, despite extensive planned maintenance, lower than any quarter since 2007. And we take down our guiding on CapEx and exploration spending for the year.

Then to the numbers, these elements characterize the quarter. First, results continue to be impacted by the low oil and gas prices. Oil prices were lower than the same quarter last year but improved towards the end of the quarter. So, our fundamental view remains unchanged, and we do see signs of a rebalancing of the oil markets. As expected, the gas prices in Europe continued to be weak and we have utilized our flexibility to move gas out of the quarter to future periods, where we see higher prices in the forward curve. In the US, we see improvements in the gas markets and our realized gas prices are up approximately 20% compared to the second quarter in 2016.

Secondly, we continue to deliver strong operational performance. We have consistently shown good results from our improvement program. And personally, I think it's easy to start taking these results for granted, but remember this is hard work from all our teams.

Operating costs are down by 10% compared to the same quarter last year and 34% compared to 2015, measured in dollars. In addition, we continued to improve our projects. For Johan Sverdrup phase one, we have, compared to the PDO, reduced the CapEx by more than 20%, increased the production capacity and taken down the breakeven below $25 per barrel.

In Norway, Gullfaks Rimfaksdalen is now on stream, ahead of schedule and more than 20% below the cost estimate in the PDO. And we have continued to replenish our portfolio. In Brazil, we acquired Petrobras's operater position in BM-S-8 license, which includes part of the Carcara discovery, one of the largest oil discoveries in recent years. We have taken over the operatorship of BM-C-33 and signed an MOU with Petrobras.

Thirdly, the results are impacted by some quarterly specific elements. We have expensed two previously capitalized exploration wells in the Gulf of Mexico, negatively impacting results from our international operations. And we had extensive maintenance planned on the Norwegian Shelf with eight turnarounds compared to two in the same period last year. These turnarounds have been completed effectively according to plan.

Finally, in the quarter, we delivered net positive cash flow and reduced our net debt ratio to 30.3%. With strict prioritization and strong results from our improvement program, we lower our CapEx guiding and exploration spend for 2016.

And our Board of Directors has approved a third-quarter dividend of $0.2201 per share and there will be a scrip option with a 5% discount also for the third quarter. The second scrip offering yielded a take-up of 45% by shareholders. This improved the cash flow in the quarter by more than $300 million.

Then to the financial results, the adjusted earnings before tax was $636 million compared to $2 billion in the third quarter 2015. The realized liquid price was 8% lower, natural gas prices in Europe 30% lower, and refinery margins almost 60% lower compared to the same period last year.

The adjusted result after tax was a loss of $261 million. This includes expensing more than $300 million related to the previously drilled exploration wells in the Gulf of Mexico where we have no tax protection. On average the tax rate was 141% due to earnings composition with losses in countries with no or low tax protection.

I will now move from Group results to comment on the results in the various segments. Development and production Norway had a second quarter pre-tax result of $1 billion compared to $1.9 billion in the same quarter last year. The result was impacted by a 48% drop in the gas transfer price, and an 8% reduction of realized liquid prices. In addition, production was impacted by extensive turnaround activity.

While we in the third quarter produced high levels of flex gas, we did the opposite this year. We have added -- we have decided to move gas out of the quarter to later periods where we see higher prices. This was partly offset by underlying good production, the end of Ormen Lange redetermination make-up period and the start-up and ramp-ups of new fields.

Excluding maintenance, divestments and the effect of flex gas we delivered an underlying production growth of 5% in the quarter. We continue to deliver strong cost improvements despite the heavy maintenance program. And the adjusted OpEx SG&A expenses year on year were reduced by 16% in the underlying currency, NOK, and down 5% per barrel despite the lower volumes in the quarter.

Development and production international had an adjusted pre-tax loss of $596 million compared to a loss of $508 million in the same quarter last year. The two expensed exploration wells counts for more than half of the negative result. Realized liquid prices were 7% lower than in 2015 and this was partly offset by 3% higher gas prices in North America.

Equity liquid production was 2% higher and natural gas production 16% higher. Also, here we continue to see significant improvements in our cost base. OpEx, SG&A was down by 20%. This was mainly a result of efficiency measures, partly offset by cost associated with new fields on stream and higher transportation costs. DD&A increased by 9% due to new fields on stream and ramp-ups. However, DD&A per barrel was stable.

The MMP adjusted result was $301 million compared with a record result in the quarter, in the third quarter of 2015 of $736 million. This was largely due to a good result in the European gas sales and trading, partly offset by lower refinery margins as well as higher transportation costs.

Our equity production was 1.805 million barrels in the quarter, a reduction of 5% compared to the same period last year. The reduction was largely a result of extensive maintenance, less flex gas in the production mix and our decision to move gas volumes to future periods, as well as the decline, as expected, in the mature fields. This was partly offset by start-ups and ramp-ups of new fields, a record high production from Gulf of Mexico and resumption of equity volumes on Ormen Lange after the redetermination period.

Cash flow from operations pre-tax was $9.9 billion year to date. Year to date Statoil has paid $3 billion in tax and with $1.5 billion in dividend payments, cash investments of $8.9 billion and proceeds from sale of assets of $0.5 billion, we have a net negative cash flow of $3 billion.

Organic investments are $7.8 billion; difference from cash investments is largely caused by the investment in Lundin. We have paid one tax installment of $5 billion on the Norwegian Continental Shelf in the third quarter. In the fourth quarter, we will pay two tax installments each at NOK5 billion.

Dividend paid reflects the cash dividend portion after the scrip is paid in the second and third quarter. In the quarter, we were net cash flow position and net debt to capital employed is reduced to 30.3% at the end of the third quarter.

Let me conclude with a few comments on our guiding. We maintain the production guiding and expect an organic production growth of 1% from 2014 to 2017. We reduce the organic CapEx guiding for 2016 from $12 billion to around $11 billion, mainly due to continued strict prioritization and the impact of the efficiency efforts.

We estimate the exploration spend to be around $1.5 billion, down from $1.8 billion as previously guided. The reduction is mainly a result of continued improvements in drilling efficiency, not changes in our drilling plans for the year.

Before I leave the word to Peter I would just like to remind you of our Capital Markets update in London, the February 7 next year. Then, Peter I leave it to you to take us through the Q&A.

Thanks Hans Jakob. Now in a second I'll ask the operator to open for questions. As is normal please can I ask people to keep it to a maximum of two questions each, so that we can cover everybody effectively? So if we'd like to open up for questions please.

(Operator Instructions). Oswald Clint, Bernstein.

Thank you. Good afternoon. Thanks, Peter, thanks, Hans Jakob. First question please, I just wanted to ask about the CapEx reduction. Maybe if you could talk -- maybe flesh it out a little bit more in terms of the efficiency and the strict project work that you just talked about. Is it really releasing some of the rigs that we've seen recently is that what's doing this? And should we expect some charges against those contracts in the fourth quarter? But generally, if you could talk around that CapEx just a little bit more please. And also how we should think about that CapEx number rolling into 2017 please.

And then the second question was more on the Gulf of Mexico. It seems to be we are always getting these impairments or exploration write-offs with the Gulf of Mexico portfolio. Is this resource issues or is it the economics that they're just not looking attractive here? Maybe if you could just talk about that portfolio please. Thank you.

Well, thank you, Oswald, for those questions. To the first one the CapEx is mainly about three elements: first, efficiency; second, market gain; and some scheduling. We will continue to work on the improvement agenda and we see the results of that. And we see it both in the Norwegian Shelf and in international operations, it's both operated assets and non-operated assets, it's across the board and we are not going to stop there.

The main contribution is efficiency, which is very encouraging to see. And I think that, as you said, we have also optimized schedule on our projects. Going forward, we expect to see more market gains. We have used some of the flexibility that we guided on, on the CMU the $1 billion to $2 billion in 2016 and 2017.

And where we are at the moment, we have a fairly -- we started the year with a fairly low activity level in the US, have stepped up a bit and we are also planning an FID in Norway on the costs for next year. But we'll have to come back on guiding on the CapEx for the future at CMU.

To your second question the Gulf of Mexico, it is a resource issue; you talk about some continued write-offs. First of all, I would say that the Gulf of Mexico operations is characterized in this quarter of a record-high production. We are ramping up production from Jack/St. Malo, Julia, Heidelberg up to a production level of 65,000 barrels per day. In the future, we have Stampede coming in, in 2018. And my take away from the GOM operations is this is good margin, it's high-quality oil, it's low OpEx and no tax payments.

Okay, understood, thank you.

Thomas Adolff, Credit Suisse.

Good afternoon, and thanks for taking my question. I'm covering for my colleague Illkin. Just wanted to go back to CapEx, now I just wondered if you can take CapEx down even further without actually potentially starving the business of cash.

And perhaps even can you comment on Schlumberger's recent statement on the call where they said they started talking about pricing recovery. And linked to the CapEx question I also wondered if there is an annual budget for bolt-ons to ensure resource replenishment that comes on top of the guided CapEx. Thank you.

Thank you, Thomas, for the questions. When it comes to the statement from Schlumberger I think I'll withhold from commenting on that. Back to the CapEx one, can we cut it even further? Well, we have guided on the flexibility in 2018, 2019 of $4 billion to $6 billion and the $1 billion to $2 billion in 2016 and 2017. As I said we have used some of that flexibility. But we also see that the improvement efforts are paying off. And as I said it's across the board. We also see that from the normal. And we are not stopping there. So the potential for further reductions is there.

But we have to come back on future also on CapEx. And as you have seen today we are talking it down another $1 billion for the year. So I think the direction is about prioritization and continued improvements. When it comes to CapEx affecting production its limited affect because most of the growth in the period is from the committed part of the CapEx.

And my second question was on bolt-ons if you have an annual budget for bolt-ons that actually comes on top of your guided CapEx.

No, we don't.

Okay. And you think with the CapEx you guide to you can replenish your resource base fully?

Yes. As I said, most of the growth in our production going forward is from the committed part of the CapEx.

Okay, thank you.

Mehdi Ennebati, Societe Generale.

Hi, good afternoon, all ,and thanks for taking my questions. So two questions please. First one on the European natural gas price trend. Can we have your view please? Natural gas price for winter contract increased in a material way since mid-September. In your view, what is the main reason behind this? Is it more related to the oil price increase? We can see that on the day of the OpEx pre-agreement natural gas price went up substantially. Or do you think that issue it is more linked, sorry, to the issue around the French nuclear plants, which increased the natural gas demand through more -- through an increasing use of the gas power plants. Just wanted to have your view on that please.

And the second question is about the working capital variation. I asked you last quarter about the working capital movement expected for the rest of the year. You told me that given you would build natural gas inventories, working capital should go up in the third quarter. This definitely hasn't been the case. So can you then tell us the main reason of such a working capital decrease in the third quarter? And should we also expect a working capital decrease in the fourth quarter as you will sell gas from storage? Thank you.

Well, thank you, Mehdi, for those questions. First the natural gas, it will vary quarter on quarter and you should not extrapolate based on one quarter. But the prices at the end of the quarter were coming up and the forward price is going to -- is indicating upward prices.

We have moved gas out of the quarter due to this fact that we expect higher prices. It is, as I said last quarter, last year in the third quarter we moved 45,000 barrels into the quarter. In this quarter, we have moved 45,000 out of the quarter so then that's affected 90,000 barrels due to this value over volume strategy.

We have the effect of the rough storage and the capping of the Groningen field. We also have the fact that we have higher coal prices impacting electricity prices. Also the fact that it we see not many LNG]cargoes to Europe. So, there are many elements into this. So, let me just round up the gas comment on that the fact that the average in for gas prices was down 30% year on year, but we realized higher prices than the [NVP] in the quarter.

Then to your comment or question about working capital and the movement, and that's mainly about inventories and the reporting of working capital in the JVs that we think should be sustainable. Also, this will vary quarter on quarter, but the main changes is related to markets.

So, in this quarter it's close to $900 million. And we are constantly working to improve working capital. In the second quarter, we had cargos in transit that we realized in July. And if we see a contango market going forward, our trading organization will utilize this and this might bring it up again.

In the fourth quarter, we have gas in storage at the start of this quarter that we will draw on in the weak winter season. And this is maybe pulling it in the other direction. So, these are the main elements I think related to working capital, our movements.

Thank you very much.

Anne Gjoen, Handelsbanken.

Thank you. Adjusted operating cost in Norway is as low as $633 million, even when having maintenance. Is it reasonable to assume that it will be even lower in coming quarters when maintenance activity is low? And could you also give a comment in relation to international OpEx in coming quarters? Thank you.

Thank you, Anne, for the questions. First of all, it's very encouraging to see the continued improvement efforts that we see. We are 10% down on the Group. And in DPN it's 16% down and adjusted per barrel 5% and despite the fact of the high maintenance activity. So, we are on a good trend. There are no obvious reasons to expect much higher OpEx and directional said. The improvement work will not stop. And we expect higher production in the quarter that we are moving into.

On the international OpEx it's also a very positive trend, 20% down in dollars and 24% per barrel. We directionally said there is no reason why we should stop the positive cost trend. That's the main guiding we give today.

Thank you.

Biraj Borkhataria, RBC.

Hi, thanks for taking my questions. First question was on your volume guidance. I was wondering if you could talk about how dependent that is on your US onshore volumes growing. I'm just trying to get a sense of the contribution from your three shale plays into your 2014 to 2017 1% CAGR.

And then the second question just going back again to the CapEx reduction, can you talk specifically about base spending? On my numbers the implied reduction on your base is about 20% from 2015 to 2016. And I'm just wondering if that's a reasonable assumption in the right ballpark. So, any comments around that would be helpful. Thanks.

Thank you, Biraj. First to the volume guidance, as you know we do not guide on region or asset when it comes to our volume guidance. However, we have provided updates on the fact that activity has been picking up on our US onshore assets.

[And you add] that it's on additional rig and frack crew in Bakken in August bringing it up to total of two operated drilling rigs and two frack crews. At Eagle Ford, we have one rig and one frack crew as with the Marcellus operated. On the southwestern we have added -- they actually have added two rigs in Marcellus South, up from zero.

To your second question where is the 2016 CapEx production coming from, well, our CapEx in 2015 was just below $15 billion and we typically talk around 50% of CapEx from existing assets. So, if that's what you are using for base CapEx, the forecast is $11 billion, which is 25% below the 2015, and their proportion on the base is little changed. So, there will be some currency effects so the underlying composition around 20% is reasonable.

Thanks, that's really helpful.

Michael Alsford, Citigroup.

Hi there, thanks for taking my questions. So, I've got a couple please. Just firstly on the deferral of gas volumes in the quarter, I don't know if you can give us some help as to when you expect to see those volumes hitting the production line. Is it going to be over the next couple of quarters through the winter months, or should we think about it as more progressive across a 12-month view?

And then secondly just on Brazil, I saw that you're looking to build out your Brazil team particularly to focus on gas commercialization opportunities. I assume that links to obviously your acquisition of Carcara recently from Petrobras. And so my question is really should we therefore think strategically that Statoil will be looking to invest in the mid-stream and possibly downstream investments in Brazil to therefore monetize that gas that you have in those fields? Thank you.

Yes, thank you, Michael. To the first question about deferred gas volumes, this is value-driven, it depends on the market, so traders will use the opportunity they can take basically so it's value-driven.

To the second one on Brazil, we have signed an MOU with Petrobras including areas beyond the field development. But Svein, would you like to elaborate a bit on Brazil?

I can take a little bit on Brazil there because we have now then signed the agreement on Carcara, as you know. But also remember that we took over the operatorship for the Pao, which was then also approved in third quarter. And both those fields have gas as part of the development, more gas in the Pao than in the Carcara relatively speaking.

But what we will work on then and then also utilizing our competence that we have done in Europe in building gas value chain as well in US to also look into how to develop gas value chain in the best possible way also in Brazil. But, of course, there's still some years then to come before we take the final investment decision but these are the way that we are thinking and working on it.

Yes, so this is long-term production coming in the mid-2020s.

Okay. And sorry but a quick follow up on the CapEx point as well, just wanted to ask you obviously mentioned that you're obviously cutting down on the base spend on CapEx. Should we think there's an impact therefore to your guidance on the decline rates for the base portfolio? I think it was 5% in Norway, so if you could perhaps update us on that that would be great. Thank you.

No, you shouldn't expect an effect of the decline rate.

Okay, many thanks. Bye.

Jon Rigby, UBS.

Yes, thank you, hi. Two questions, the first on just going back to the exploration write-offs. Can I ask whether you're able to characterize where you are on working your way through the inventory of exploration wells that sit on the balance sheet and are still yet to be assessed? So, get some kind of idea about whether over the course of the next few quarters we'll continue to see these kind of non-cash write-offs or are we starting to get to the end of that program?

And related to that is you obviously didn't take a tax credit for the write-off. I guess that means that as you look forward you've exhausted the future earnings stream that you think you can put taxes against. So I guess my question is is what needs to change, price, activity rate, etc. maybe to be able to bring some of those tax credits back.

The second, which is the shorter question, just on your comments around deferral of gas production. Is there any relationship between the deferral of gas production in the upstream and what looks like a relatively robust performance in the MMP business on European gas trading? Do you take any credit for able to move that gas on paper into future quarters where hub prices are higher? Thank you.

Thank you for asking those questions. Jon. First to the exploration, I will start and then Orjan Kvelvane will fill me in. But first to the GoM exploration expenses, I mean we have evaluated the volumes, these are discoveries with limited opportunities to develop and then we have to expense it. So, Orjan, when it comes to inventory and the further development.

So if you look into the property, plant, and equipment footnote in the report you find the intangible assets and that is just about $8 billion and half of that is related to wealth. Those are sitting in the full portfolio so kind of important in Africa, of course in Norway and in Brazil.

So that is $4 billion that is kind of exposed and then we of course use successful effort, it's when we do not have any firm plan. So, if the activity is not sufficient enough to keep it on the balance sheet that doesn't mean that we are not working on keeping some of those licenses. But for accounting purposes\ we need to write it off when we do not have any firm plan.

When it comes to tax should I --

Yes, there was also a question about deferred gas production but maybe we should cover the tax part.

Yes, I can continue with the tax. So, we do not have any reported tax shield and one example is in the US. What we are waiting for is convincing evidence as it says in the standard, that we can utilize those tax positions. So, that will come when we see positive profits in those areas and when we demonstrate positive profits that's the timing when we assess use -- booking those tax credits.

Then the deferred gas production and MMP, well, first of all, it's an assessment to do every quarter. MMP will actually see lower earnings when we move gas out of the quarter as they get less volume to sell in that particular quarter. But we do of course expect to see and to benefit over time, both MMP and BPN. I guess that is the short answer to it.

Okay, so there's no sort of locking in of prices, it's just a view of where prices are going to go that drives the actual production decision.

Svein has a follow-up on this.

What we do is that we evaluate, as Hans Jakob said, every day and then to see how we are going to utilize our flexibility in the gas portfolio. We have now decided then to move and then there is a separate decision if we are hedging or not but due to also commercial reason and trading positions, that is not something that we can disclose on a regular basis.

All right, okay, thanks guys, appreciate it.

(Operator instructions) Halvor Nygard, SEB.

Thank you. We have maybe sensed a shift last month with a slightly forward-leaning attitude with acquisitions seen in Brazil, in Norway, a couple of FIDs, active exploration program for 2017 announced. Has Statoil's view on the market or your mood shifted over the last month to maybe a more countercyclical thinking with respect to M&A and so on?

Well, thank you, Halvor, for asking that question, it's a very interesting one. Recognizing that this industry is cyclical and the fact that we have the flexibility to do M&A is a starting point. We have a strong financial position and as you said, we have done several transactions. Also in this quarter, you see the effect from divestments in Marcellus of around $500 million.

You have seen the Brazil transaction of $2.5 million in phased payments. We have the swap with Repsol that we did, got the operatorship for Eagle Ford and the BMC-33 in Brazil and also the Wisting where we increased our share in the Barents Sea discovery of OMV.

So we talk about M&A mainly when we have done the transactions, so reference to these transactions is of course something I gladly share. We assess this continuously and we have the strength to do more.

All right, thank you.

Haythem Rashed, Morgan Stanley.

Hi, good afternoon, thanks for taking my questions. Two quick questions please. I wanted to -- I'm afraid to follow up again on CapEx, I know there has been a few questions already and maybe just to follow on from Thomas's question earlier on in the call. I just wanted to understand given, as you said, the flexibility that you have already outlined in your previous CMU that you have around CapEx. But also the fact that you talked earlier on the call reasonably positively about the oil market, the fact that rebalancing is underway and the outlook that you see there.

I just wondered, should we be thinking about you now reaching sort of the lower limits of what you would be prepared to take CapEx down to. Because if I recall correctly, the flexibility that you were demonstrating or showing us earlier in the year, I had the impression that was really relating to -- and particularly the lower end of that flex -- really stress scenarios where the macro environment remains very weak or as weak as what we saw earlier on this year for an extended period of time.

Given that we are now substantially above where we were at the start of the year should we be thinking about $11 billion is really towards the lower end of what you would be prepared to take CapEx down to.

The second question I had is just again on onshore activity, thank you for the update in terms of the rigs. I just wondered what are you looking for to potentially add more rigs back. Is it simply a case of looking for WTI to stabilize above $50 or are there other things that you are watching before you potentially add more rigs? Should we be expecting those rig numbers to be going up from here or actually are you quite comfortable with staying at these levels now for a period of time? Thank you.

Thank you, Haythem. The first one on CapEx and the flexibility that we have, first of all, efficiency is taking it down and we see that across the board. So, we have -- and there should be more to go. One of them is of course the market effect that we talked about, $300 million to $400 million this year, increasing into next year.

The second element is the prioritization and the phasing of the project which depend on project and the development and the project that we may sanction going forward. We can if we choose to but we don't have to, so that's part of the flexibility that we have. We have a strong project portfolio but the decision to sanction a project is linked to how we optimize the concept or could we improve even further. It's also linked to the assessment or the supplier market.

To your second one on adding more rigs or are we comfortable. We are comfortable where we are but we are assessing various scenarios and we have added activities since the first quarter when it comes to the US onshore park. There is of course competition in the supplier market as we see Permian attracting more crews and equipment. Basically, we are looking at various scenarios for increasing the activity but no change to the guiding on this particular topic today.

Okay, thank you very much.

John Olaisen, ABG.

Yes, good afternoon gentlemen. First on the gas prices in North America, the realized gas price in North America now in Q3 had the biggest discounts through Henry Hub in the three-year history that you have reported this number. Was there anything in particular that caused that discount and how about going forward in Q4 and near term, what should we expect the discount to be please?

Svein will answer that starting with Marcellus maybe.

Yes, if we start with the Marcellus, that's where we have the main gas exposure is that there we are taking capacity then to take out gas up to Toronto and also into New York. Part of the gas is also sold in the local market so it is dependent on both the local market and the Toronto and New York market.

What we typically see is that fourth quarter and first quarter is the months that we are realizing highest prices on the differential from exporting it out of the market. So then we should expect that normally at least that we have a higher premium there towards Henry Hub on what we sell in those two markets.

Okay, and my second question is relating to the flexibility on free cash flow to cover dividend. You had previously you expect to cover dividend in 2017 with oil priced at $60. I wonder if you could elaborate what kind of CapEx would that require. So what kind of CapEx would make you cover your dividend pre-scrip in 2017 with oil price at $60?

Thank you for that question. At the CMU we said we could be cash flow neutral at $60 in 2017 as you said and at $50 in 2018. We also said that we have the $1 billion to $2 billion in CapEx flexibility 2016, 2017, somewhat more into 2017. We said that we have the $4 billion to $6 billion in flexibility for 2018, 2019. There is no change to that guiding and the prioritization but we will update you on that at the capital markets update in February next year. So that's the short answer to that one.

What kind of oil price would you need -- would you have required in 2016 to cover dividend?

We haven't given a figure on that.

You don't want to give any indication.

Well, I didn't plan too so I don't think I will but of course I have an idea. I think we have shown that we have managed 2016 quite well using this flexibility and that our main reason for taking down the CapEx is efficiency gains.

Thank you.

I'm going to have to intervene as an umpire here because we've got several questions to go and I want to keep this to time. So if we can keep it fairly sharp moving and the answers will have to be a little shorter I'm afraid in the remaining time. Can we carry on?

Brendan Warn, BMO Capital Markets.

Yes, thank you and I'll keep my question just the one, just for you Peter. I want to just ask a question on Johan Castberg and I guess going into next year you mentioned it in terms of Canada for FID, can you just highlight what the timeline is for submission of the PDO, what you believe you need to see before you took an FID decision?

Can you just base on -- obviously you last said the CapEx was looking around to $50 billion to NOK60 billion. Can you just remind us what exchange you used for that assumption and whether we have seen any further cost deflation in that project if you then prove to the breakeven below $45 a barrel?

Well, Castberg is one of my favorite themes coming from the northern operations but first of all we have agreed with the partners to pursue the concept of the extended FPSO including the shuttle tankers. This is something that could happen towards end of 2017. What do we need to see in order to move forward? First of all, I think an optimized concept, a clear view on the timing in the supplier market and that we cannot improve substantially.

We have given them the challenge of answering the $40 challenge. You remember a year ago we said to all projects basically try to reach $50 breakeven and now we've pushed it to $40 and at the CMU we said $45 and I am eager to give an update at the CMU on this one.

Okay, I appreciate it.

Lydia Rainforth, Barclays.

Thanks and I'll try and keep it short as well. Just in terms of the projection numbers and I wanted to ask about unplanned downtime. I think you said back in the CMU you gave a number of about 5% of unplanned downtime number. Are you still at the range for 2016 as to what you would expect to be within that or has it moved up slightly? I am just thinking about some of the incidents in the recent weeks that's all. Thank you.

Okay, I can answer this very shortly. We have moved up slightly in the quarter, you are right. But we are working hard to maintain the unplanned losses to the minimum.

Okay, thank you.

Anders Holte, Danske Bank.

Good afternoon gentlemen, just two quick questions from me. I just wondered if you can confirm if I heard this right. You said you would have two extra installments able in Q4 for the Norwegian taxes, each NOK5 billion, is that correct?

Then the second one is related to the gas market. Now although we have seen a spike in the short month ahead contracts there's been little movement in the year-end contracts so I'd just like your view on the status of the gas market if we look a bit further into time, please.

Thank you, Anders. Yes, you are right, two tax instalments each NOK5 billion in the fourth quarter. To the second one on the gas market, this is a lot of moving parts and yet we haven't seen a lot of LNG coming to Europe. We have the issue as I said on the rough storage and the capping of the Groningen. There are many elements into this equation, of course seasonality, weather. We are moving into the winter season where we expect somewhat higher volumes and as I said also, we have moved the flex gas into future periods. They are up for grab for the traders if their market conditions are there. So we are positively awaiting the market development on the gas.

So the Russian component, we have seen the effect of the oil-index gas contracts and the delay to that but how that is going to develop going forward is also part of the uncertainty that we see short-term.

So your view on that uncertainty as to the European gas market hasn't really changed.

No major changes to our view.

Thank you.

Rob West, Redburn.

Thanks for the informative call today. I have got a few quick ones. One is just you mentioned some impairment reversals in the release and you alluded to better performance coming from a specific asset. I was wondering could you say what that is and what you see in there that's made you revise the productivity of that asset higher going forwards?

Then secondly, just really quickly, that you mentioned eight turnarounds this year, two last year. What's the right number per Q3 going forward? I'm just trying to get a sense of is that eight turnarounds per quarter a little bit higher than usual or something that will repeat? Thanks.

To the last one on turnarounds, we had eight on the Norwegian Shelf, so they have been through the massive planned maintenance periods. In the upcoming quarter, it is more DPI and less Norway. We also had the Mongstad turnaround in this quarter.

To the better performance, it's a very pleasant topic to talk about but as you know on asset level we do not comment specifically on assets. So I'm not going to go into that. Then to your reversals, we -- are all impairments a net effect of $53 million in the quarter. We have a gas field in Europe that has improved, after a good promising start they have improved and updated their production profile. On the other hand, we have a refinery in the northern part of Europe as well which has due to a change in the high refinery margins that is taken down has triggered the opposite, so net $53 million.

Okay, got it, thank you.

Teodor Nilson, Swedbank.

Good afternoon and thanks for taking my questions. Two quick questions for me. First on the CapEx reduction, you mentioned several reasons for the reduction. How much of the reduction is explained by phasing i.e. that you move CapEx from 2015 to 2017?

The second question is on exploration. Your (inaudible) exploration guiding $1.5 billion per year and should that represent a proxy for what we should expect for 2017 and how many wells will that be in 2017? Thank you.

Okay, I will try to be brief but thank you, Teodor. On CapEx reduction, only a small amount due to phasing, mainly efficiency gains. To the second one on exploration, the $1.5 billion is for 2016, on 2017 we have spent the time on replenishing our portfolio. I think it's fair to say that we have more exciting options for 2016 coming up that is giving tougher prioritizations for us.

We have for instance a Barents campaign of five to seven wells coming up as a result of the 23rd round and we also have matured targets in the UK, so there are more countries that could be mentioned. But this is due to the strict discipline of prioritization and will most likely also be a topic for the upcoming CMU.

Thank you.

Hamish Clegg, BoA ML.

Hi, guys, and just one quick one for you, amazing it hasn't been done yet. Just on volumes, you guide basically to material decline year on year in your equity volumes. It's a nice time of year to really mark to market and I just note that the marking to market your volumes, it doesn't imply you've got much of a material downside year on year. So is the guidance just a bit old or can we expect Q4 to see a bit of a turndown which we don't really expect?

Thank you for the volume question, Hamish. Our guiding on production volumes is 1% from 2014 to 2017 so our guiding is not changed. This year it's somewhat lower than next year and beyond that it's the movement of the flex gas that we have updated on today. Maybe that is an indication going forward but you know the main guiding on production towards the end, the 2017 to 2019 is 2% to 4% and that is still valid.

It was really referring to the line in your outlook statement that says your equity production for 2016 is estimated to be somewhat lower than the 2015 level but marking to market it looks in line worst despite all your step challenge, cost cutting efficiency programs, etc.

Well, this is a bit smaller so the amount here is marginally smaller I would say. So guiding is --

So we can expect a similar run rate into the end of the (technical difficulty).

I repeat, the guiding remains unchanged, it's 1% for 2014 to 2017 and 2% to 4% towards the end.

Okay, fantastic, brilliant, thanks a lot.

Anish Kapadia, TPH.

Just one question from me. Your CapEx to barrel of production when I look at that for the international business is pretty high, I calculate about $25 for BOE, so pretty high versus peers and much higher than what you see in the NCS business at about $10 for BOE. I am just wondering if you could discuss why you see the capital intensity of that business so much higher and the potential to get that down. I am just thinking about -- in the context of the international business being highly free cash flow negative over the last few years. Thank you.

With the GoM example in my end I would say it's a good margin, it's high quality oil, it's low OpEx, and we have no tax payments so this is good business.

I think we have to move to the next one in the interest of time.

Marc Kofler, Jefferies.

Good afternoon, everyone, just one question remaining for me please. I was wondering if you could give an update on the Carcara transaction particularly around any sort of sense of timing until closing and if that transaction was still progressing as you initially expected when you first announced the acquisition.

Well, thank you, Mark, for the Carcara question. Just returned from Brazil, very exciting to see the sentiment in Brazil and with the MOU that we just signed with Petrobras as well. I mean the Carcara is long-term production, it's in the mid-2020s. Svein also mentioned the BMC-33. This is a world-class discovery. In terms of closing there is no change in the announcement that we made so things are progressing according to plan.

Thanks.

(Operator instructions)

Well, thank you very much. Thanks, Hans Jakob. Thanks for all your questions. Sorry we had to be shorter at the end than we were at the start but as ever please feel free to contact Investor Relations for any follow up. We look forward to seeing you all on February 07 for our fourth quarter results and the CMU. Thanks very much, bye bye.