My name is Peter Hutton, Head of Investor Relations for Equinor, 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 Ørjan 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. 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 deliver positive net cash flow, reducing our net debt to capital employed. We continue to deliver cost improvements across all business areas. At the Norwegian Continental Shelf, our total costs are, despite extensive plant maintenance, lower than any quarter since 2007. We take down our guidance on CapEx and exploration spending for the year. To the numbers. These elements characterizes 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. Our fundamental view remains unchanged, and we do see signs for a rebalancing of the oil market. 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 U.S., we see improvement in the gas market, 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. Personally, I think it's easy to start taking these results for granted.
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 2013, measured in dollars. In addition, we continue to improve our projects. For Johan Sverdrup Phase 1, we have, compared to the PDO, reduced the CapEx by more than 20%, increased the production capacity, and taken down the break-even below $25 per barrel. Norway, Gullfaks and Rimfaksd alen is now on stream ahead of schedule and more than 20% below the cost estimate in the PDO. We have continued to replenish our portfolio. In Brazil, we acquired Petrobras' operator position in BM-S-8 license, which includes part of the Carcará 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. We had extensive maintenance plans 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 guidance and exploration spend for 2016. 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. To the financial results. The adjusted earnings before tax was $636 million compared to $2 billion in the third quarter 2015. The realized liquids price was 8% lower. Natural gas prices in Europe, 30% lower. 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 48% drop in the gas transfer price, an 8% reduction of realized liquids prices. In addition, production was impacted by extensive turnaround activities. While we in the third quarter last year produced high levels of flex gas, we did the opposite this year. 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 startup and ramp-up of new fields. Excluding maintenance, divestments, and the effect of flex gas, we deliver an underlying production growth of 5% in the quarter. We continue to deliver strong cost improvements despite the heavy maintenance program. The adjusted OpEx SG&A expenses year-on-year were reduced by 16% in underlying currency NOK. 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 account for more than half of the negative results.
Realized liquids prices were 7% lower than in 2015, and this was partly offset by 3% higher gas prices in North America. Equity liquids 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 costs 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 2015 of $736 million.
This was largely due to good results in the European gas sales and trading, partly offset by lower refinery margins as well as higher transportation costs. Our equity production was 1,805,000 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 startup 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 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 NOK 5 billion on the Norwegian Continental Shelf in the third quarter. In the fourth quarter, we will pay two tax installments, each at NOK 5 billion. Dividend paid reflects the cash dividend portion of the $0.50 paid in the second and third quarter. In the quarter, we were net cash flow positive 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 - 2017. We reduced 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 our capital markets update in London, the seventh of February next year. 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, can I ask people to keep it to a maximum of two questions each so that we can cover everybody effectively. If we'd like to open up for questions, please.
Thank you. If you would like to ask a question today, please press star followed by the digit one on your telephone keypad. Please ensure that your mute function is turned off to allow your signal to reach our equipment. We will now take our first question from Oswald Clint, Bernstein. Your line is open.
Thank you. Good afternoon. Thanks, Peter. Thanks, Hans Jacob. 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 kind of project work that you spoke about. Is it really, you know, 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? Generally, if you could talk around that CapEx just a little bit more, please. Also how we should think about that CapEx number rolling into 2017, please. Then the second question was more on the Gulf of Mexico.
It seems to be we're always getting these impairments or exploration write-offs with the Gulf of Mexico portfolio. Is this resource issues or is it the economics that are just kind of not looking attractive here? Maybe if you just talk about that part of the 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 gains, and some scheduling. We will continue to work on the improvement agenda, and we see the results of that. 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. 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 the CMU, the $1 billion-$2 billion in 2016 and 2017. Where we are at the moment, I mean, we have a fairly low activity level. We started the year with fairly low activity level in the U.S., have stepped up a bit, and we are also planning an FID in Norway on the Castberg next year. We'll have to come back on guiding on CapEx for the future at CMU. To your second question, the Gulf of Mexico. Is it a resource issue? You're talking about continued write-offs. First of all, I would say that, you know, the Gulf of Mexico operations is characterized in this quarter by a record high production.
We are ramping up production from Jack, St. Malo, Julia, Heidelberg up to a production level of 65,000 barrels today. In the future, we have Stampede coming in in 2018. My takeaway from the GoM operations is this is good margins, it's high quality oil, low OpEx, and no tax payments.
Okay. Understood. Thank you.
We will now take our next question from Thomas Adolff at Credit Suisse. Your line is open.
Good afternoon. Thanks for taking my question. I'm covering for my colleague, Ilkin. Just wanted to go back to CapEx. Now I just wondered if
If you can take CapEx down even further without actually potentially selling the business or cash? Or perhaps even can you comment on Schlumberger's recent statement on the call, where they said they started talking about pricing recovery. 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, to cut it even further. We have traded on the flexibility, you know, in 2018, 2019 or $46 billion and the $1 billion-$2 billion in 2016 and 2017. As I said, we have used some of that flexibility, but we also see that, you know, the improvement efforts are paying off. As I said, it's across the board. We also see that from the normal. We're not stopping there. The potential for further reductions is there, but we have to come back on the future outlook on CapEx.
As you're seeing today, we're taking down another $1 billion for the year. I think the direction is about prioritization and continued improvement. When it comes to CapEx affecting production, it's limited effect because most of the growth in the period is from the committed part of the CapEx.
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. 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.
Our next question is from Marc Sheridan, Société Générale. Your line is open.
Hi. Good afternoon, all, and thanks for taking my questions. Two questions, please. First one on the European natural gas price trend. Can we have your view, please? I mean, 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 OPEC pre-agreement, natural gas price went up substantially. Do you think that issue it is more linked, sorry, to the issue around the French nuclear plants, which you know increase the natural gas demand through more, let's say, through an increasing use of the gas power plants.
Just wanted to have your view on that, please. The second question is about the working capital variation. I asked you the last quarter about the working capital movement expected for the rest of the year. You told me that given you will build natural gas inventories, working capital should go up in the third quarter. This definitely hasn't been the case. Can you then tell us the main reason of such a working capital decrease in the third quarter? Should we also expect a working capital decrease in the fourth quarter as you will sell gas from storage? Thank you.
Well, thank you, Marc, for those questions. First, to the natural gas. It will vary quarter- on- quarter, and we should not extrapolate based on one quarter. The prices at the end of the quarter was coming up and the forward price is indicating upward prices. We have moved gas out of the quarter due to the 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. The net effect is 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 we see not many LNG cargos to Europe. There are many elements into this. Let me just round off the gas comment on that. The fact that the average NBP gas prices was down 30% year-on-year, but we realized higher prices than the NBP in the quarter. 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.
This will vary quarter-on-quarter, but the main changes is related to markets. In this quarter, it's close to NOK 900 million, and we are constantly working to improve working capital. In the second quarter, we had cargoes in transit that we realized in July. 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 winter season, and this is maybe pulling it in the other direction. These are the main elements I think related to working capital and movement.
Thank you very much.
Our next question is from Anne Gjoen from Handelsbanken.
Thank you. Adjusted operating costs in Norway is as low as $633 million, even when we have maintenance. Is it reasonable to assume that it will be even lower in coming quarters when maintenance activity is low? Could you also give a comment in relation to international OpEx in coming quarters? Thank you.
Thank you, Anne, for the question. First of all, I mean, 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. We are on a good trend. There are no obvious reason to expect much higher OpEx and directional set. I mean, the improvement work will not stop. And we expect higher production in the quarter that we're moving into. On the OpEx, it's also a very positive trend, 10-20% down in dollars and 24% per barrel. And we...
Directionally said, I mean, there is no reason why we should stop the positive cost trend. That's the main guiding we give today.
Thank you.
Our next question is from 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 U.S. onshore volumes growing. I'm just trying to get a sense of the contribution from your three shale plays into your 2014 - 2017 1% CAGR. 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- 2016, and I'm just wondering if that's a reasonable assumption in the right ballpark. Any comments on that would be helpful. Thanks.
Thank you, Biraj. First to the volume guidance. As you know, we do not guide on regional assets when it comes to our volume guidance. However, we have provided updates on the fact that activity has been picking up on our U.S. onshore assets. We have added some additional rig and fracker in Bakken in August, bringing it up to total of two operated drilling rigs and two frac crews. At Eagle Ford, we have one rig and one frac crew, as with 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 reduction coming from?
Well, our CapEx in 2015 was just below $15 billion, and we typically talk around 50% of CapEx from existing assets. If that's what you are using for base CapEx, the forecast is $11 billion, which is 25% below the 2015, and the proportion on the base is little change. There will be some currency effects. The underlying composition around 20% is reasonable.
Thanks. That's really helpful.
Our next question is from 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, you know, hitting the production line. Is it gonna 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, you know, just on Brazil, you know, I saw that you're looking to build out your Brazil sort of team, particularly to focus on gas commercialization opportunities. I assume that, you know, links to obviously your acquisition of Carcará recently from Petrobras.
I guess my question is really, you know, should we therefore think strategically that Statoil will be looking to invest in the midstream and possibly downstream, you know, investments in Brazil to therefore monetize that gas, that you have in those fields? Thank you.
Yeah. Thank you, Michael. To the first question about deferred gas volumes, it is value-driven. It depends on the market. Traders will use the opportunity they can take, basically. It's value-driven. To the second one on Brazil, we have signed an MOU with Petrobras, including areas beyond the field development. Svein, would you like to elaborate a bit on Brazil?
Yeah. I can take a little bit from what Hilde said because we have now signed the agreement on Carcará, as you know. Also remember that we took over the operatorship for Peregrino, which was then also approved in third quarter. Both those fields has gas as part of the development. More gas in the Peregrino and in the Carcará relatively speaking. That's what we will work on. Also utilizing our competence that we have done in Europe in building a gas value chain as well as in U.S. to also look into how to develop gas value chain in the best possible way also in Brazil.
Of course the teams from MMP come for before we take the final investment decision. These are the ways that we are thinking and working on.
Yeah. This is long-term production coming in the mid-2020s.
Okay. And sorry, if I don't mind, 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 decline rates for the base portfolio? I think it was 5% in Norway. If you could perhaps update us on that would be great. Thank you.
No. You shouldn't expect an effect of the decline rate.
Okay. Many thanks. Bye.
Our next question will be from Jon Rigby, UBS. Your line is open.
Yes. Thank you. Hi. Two questions. The first on just going back to the exploration write-off. 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? 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? 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 sort of exhausted the future earning stream that you think you can put taxes against.
I guess my question is what needs to change, price, activity rates, et cetera, maybe, to be able to bring some of those tax credits back? The second, which is a 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 early on Ørjan Kvelvane will fill me in. 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. Early on when it comes to inventory and then the further development.
Yeah. If you look into the plant and equipment footnote in the report, you find the tangible assets and that is just about $8 billion. Half of that is related to EPI. Those are sitting in the full portfolio. Kind of both in Africa, both in Norway and in Brazil. That is $4 billion that is kind of both. Then we of course use successful effort when we do not have any firm plan. The kind of activity is not sufficient enough to
On the benefit. That doesn't mean that we are not working on, kind of, maybe keeping some of those licenses. But for accounting purpose, we need to write it off when we do not have any near-term plans.
When it comes to tax then?
Yeah. There was also a question about deferred gas production, but maybe we should cover the tax part.
Yeah.
I think we can continue with the tax. We do not have any kind of reported tax benefit. One example is in the U.S. What we are waiting for is kind of convincing evidence, as it says in the standards, that we can utilize those tax positions. That will come when we see positive profits in those areas. When we kind of demonstrate positive profits, that is the timing when we are set to kind of book those tax credits.
The deferred gas production on MMP, well, first of all, it's an assessment to do every quarter. MMP will actually see lower earnings when we move gas out to the quarter as they get less volume to sell in that particular quarter. We do, of course, expect to see and to benefit over time, both MMP and DPN. I guess that's the short answer to it.
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 decisions.
Svein, to follow- up on this.
What we do is that we evaluate the asset concept every day and then to see how then to utilize our flexibility in the gas portfolio. We have now decided then to move, and there is a separate decision if we are hedging or not, but due to also commercial reasons and trading position that that is not something that's done and goes on a regular basis.
Right. Okay. Thank you. Thanks. Thanks, guys. Appreciate it.
If you find that your question has already been answered, you may remove yourself from the queue by pressing star two. We will now take our next question from Halvor Nygaard, SEB.
Thank you. We have maybe sensed a shift the last month with a slightly more forward-leaning attitude with asset acquisitions seen in Brazil, in Norway, a couple of FID active exploration program for 2017 announced. Have Statoil's view on the market or your mode shifted over the last month to maybe a more countercyclical thinking with respect to M&A and so on?
Well, thank Halvor for asking that question. It's a very interesting one. I mean, 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 I 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 billion in phased payments. We have the swap with Repsol that we did, got the operatorship of Eagle Ford and the BM-C-33 in Brazil, and also the listing. We have increased our share in the Barents Sea discovery of OMV.
We talk about M&A mainly when we have done the transactions. 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.
Our next question is from Nathan Reeves, Morgan Stanley. Your line is open.
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's been a few questions already. Maybe just to sort of follow on from Thomas's question earlier on in the call. I just wanted to understand, given as you said, the flexibility that you've 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 particularly the lower end of that flex, really sort of you know stress scenarios where you know the macro environment remains you know very weak or as weak as what we saw earlier on this year for an extended period of time. Given that we are now you know substantially above where we were at the start of the year, I mean, should we be thinking about you know $11 billion as really sort of the you know towards the lower end of what you'd be prepared to take CapEx down to? The second question I had is just again on onshore activity.
Thank you for the sort of update in terms of the rigs. I just wondered, what are you looking for to potentially add more rigs back? I mean, is it simply a case of looking for WTI to stabilize above $50, or are there other things that are sort of you're watching before you sort of 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, Nathan. The first one on CapEx and the flexibility that we have, first of all, the efficiency is taking it down, and we see that across the board. We have, and there should be more to go. One of them is, of course, the market effect that we talked about, $300 million-$400 million this year, increasing into next year. The second element is, the prioritization and the phasing of the project, which depend on project under development and the project that we may sanction going forward. It can if you choose to, but you don't have to. 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 have it optimized, the concept or could we improve even further. It's also linked to the assessment of the supplier market. To your second one on adding more rigs or are we comfortable? We are comfortable where we are. We are assessing various scenarios, and we have added activity since the first quarter when it comes to the U.S. Onshore part. There's of course competition in the supplier market. I could see Permian attracting more crews and equipment, and 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.
Our next question is from John Olaisen, ABG.
Yeah. Good afternoon, gentlemen. A question on the gas prices in North America. The realized gas prices in North America now in Q3 had the biggest discounts to Henry Hub in the three-year history that you have reported this number. Was there anything in particular that caused that discount? How about going forward in Q4 and near-term, where should we expect that discount to be, please?
Svein will answer that, starting with Marcellus, maybe.
Yeah. 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 off gas to up to Toronto and also into New York. Part of the gas is also sold in the local market. It is dependent on both the local market and the Toronto and the New York market. What we typically see is that fourth quarter and third quarter is these months that we are realizing highest prices on the differential from exporting it out of the market.
We should expect that normally at least that we have a higher premium there and towards Henry Hub on what we sell in those markets.
Okay. My second question is relating to the flexibility on free cash flow to cover dividend. You have previously said you expect to cover dividend in 2017 with oil price at 60. I wonder if you could elaborate what kind of CapEx would that require? What kind of CapEx would make you cover your dividend pre script 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 we said, and at 50 in 2018. We also said that we have the $1 billion-$2 billion in CapEx flexibility 2016, 2017, somewhat more into 2017. We said that we have the $4 billion-$6 billion in flexibility for 2018, 2019. There's no change to that guidance under prioritization, but we will update you on that at the capital markets update in February next year. That's the short answer to that one.
Maybe what kind of oil price would you have required in 2016 to cover dividend?
We haven't given any figure on that.
I know. You don't want to give any indication?
Well, I didn't plan to, so I don't think I will.
Okay.
You know, of course I have an idea. I think we've shown that we have managed 2016 quite well using this flexibility and that our main reason for taking down the CapEx is the efficiency gains.
Okay, thank you.
Our next question.
We've got several questions to go, and, I wanna keep this to time. If we can keep it fairly short moving, and the answers will have to be a little shorter, I'm afraid, in the remaining time. Carrie?
With that in mind, our next question is from Brendan Warn, BMO Capital Markets.
Yes, thank you. Look, I'll keep my questions just to one, just for you, Peter. I wanna just ask a question on Johan Castberg, and I guess going into next year, you mentioned it in terms of a candidate 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 touch base on obviously you'd last said the CapEx was looking around sort of NOK 50 billion-NOK 60 billion. Can you just remind us what exchange rate you used for that assumption and whether we've seen any further cost deflation in that project, if you've improved the break even below $45 a barrel?
Well, Castberg is one of my favorite themes, coming from the northern operations. Well, first of all, we have agreed with the partners to pursue the concept of the extended FPSO, including the shuttle tanker. This is something that could happen towards the 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 markets and that we cannot improve substantially. We have given them the challenge of answering the $40 challenge. You remember a year ago, I mean, we said to all projects, basically try to reach $50 breakeven, and now we pushed it to $40. At the CMU, we said $45.
Great.
I'm eager to give an update at the CMU on this one.
Okay, appreciate it.
Our next question is from Lydia Rainforth from Barclays. Your line is opened.
Thanks. I'll try to keep this short as well. Just in terms of the production numbers, I wanted to ask about unplanned downtime. I think sort of back in the CMU, you gave a number of about sort of 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 was just thinking about some of the incidents in the recent weeks, that's all. Thank you.
Yeah, I can answer this very shortly. We have moved up slightly in the quarter, you're right. We're working hard to maintain the unplanned losses to the minimum.
Okay, thank you.
Our next question is from Anders Holte, Danske Bank.
Hi, good afternoon, gentlemen. Just two quick questions from me. I just wonder if you can confirm, if I heard this right, you said you would have two tax installments payable in Q4 for the Norwegian taxes, each NOK 5 billion, is that correct? The second one is related to the gas market. Now, although we've seen a spike in the short months ahead contracts, there's been little movement in the year ahead contracts. I'd just like your view on the state of the gas market when you look a bit further into time, please. Thank you.
Okay. Thank you, Anders. Yes, you're right. Two tax installments, each NOK 5 billion in the fourth quarter.
Thanks.
To the second one on the gas market, this is a lot of moving parts. 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 some somewhat higher volumes. As I said, also, we have moved the flex gas into future periods. They are up for grabs for the traders if the market conditions are there. We are positively awaiting the market development on the gas.
The Russian component, we have seen the effects of the oil-indexed gas contract 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.
Okay. Your view on the uncertainty of the European gas market hasn't really changed?
No major changes to our view.
Okay. Thank you.
Our next question is from Rob West from Redburn.
Hey, thanks for the informative call today. I've got two quick ones. One, just earlier 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've seen there that's made you revise the productivity of that asset higher going forwards? And then secondly, just really quickly, you mentioned 8 turnarounds this year, 2 last year. What's the right number per 3Q going forward? I'm just trying to get a sense of, is that 8 turnarounds per quarter a little bit higher than usual or something that will repeat? Thanks.
Okay. To the last one on turnarounds, we had 8 on the Norwegian Shelf. They've been through the massive plant maintenance period. In the upcoming quarter, it's more EPI 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. I'm not going to go into that. Then to your reversals, overall impairments, a net effect of $53 million in the quarter. They have a gas field in Europe that has improved. Off to a good promising start. They have improved and upgraded 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 higher refinery margins that has tanked, has triggered the opposite. Net $53.
Okay. Got it. Thank you.
Our next question is from Teodor Nilsen from Swedbank. Your line is open.
Good afternoon, and thanks for taking my question. 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? Second question is on exploration. Your updated exploration guidance $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'll try to be brief, but, thank you, Teodor. On CapEx reduction, only a small amount due to pacing, 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. We also have matured targets in the U.K. There are more countries that could be mentioned, but, you know, this is due to the strict discipline of prioritization.
This will most likely also be a topic for the upcoming CMU.
Okay, thank you.
Our next question is from Hamish Clegg, BofA Merrill Lynch.
Hi, guys. Just one quick one for you, amazingly it hasn't been done yet. Just on volumes, you guide basically to material decline year-over-year in your exit volumes. It's a nice time of year to really mark-to-market. I just note that the marking to market your volumes, it doesn't imply you've got much of a material downside year-over-year. Is the guidance just a bit old or can we expect Q4 to see a bit of a turndown, which, you know, we don't really expect?
Okay. Thank you for the volume question, Hamish. Our guiding on production volumes is 1% from 2014 - 2017. Our guiding is not changed. This year it's somewhat lower than next year. Beyond that, it's the move of the flex cap that we have updated on today. Maybe that's an indication going forward. You know, the main guiding on production towards the end of 2017 - 2019 is 2%-4%, and that's 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 mark to market it looks, you know, in line at worst, despite all your step-change, cost-cutting efficiency programs, et cetera.
Well, it is a bit smaller. So the amount here is marginally smaller, I would say.
We can expect a similar run rate into the end of the year then?
I repeat, the guidance remains unchanged. It's 1% for 2014-2017 and 2%-4%.
Got you.
towards the end. Okay.
Fantastic.
Thanks.
Brilliant. Thanks a lot.
Our next question is from Anish Kapadia, TPH. Your line is open.
Hi. Just yeah, one question from me. Your CapEx to barrel of production, when I look at that for the international business, is pretty high at, well, I calculate about $25 per BOE. Pretty high versus peers and much higher than what you see in the NCS business at about $10 per BOE. I'm 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'm just kind of thinking of that in the context of the international business as being highly free cash flow negative over the last few years. Thank you.
With the GoM example in mind, I would say it's good margin, it's high quality oil, it's low OpEx, and they have no tax payments. This is good business.
Think I'm gonna move to the next one in the interest of time.
Our next question then is from Marc Kofler from Jefferies. Your line is open.
Oh, good afternoon, everyone. Just one question remaining, for me, please. I was wondering if you could give an update on the Carcará 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. Thanks.
Well, thank you, Marc, for the Carcará question. Just returned from Brazil, very exciting to see the sentiment in Brazil with the MOU that we just signed with Petrobras as well. I mean, the Carcará is long-term production. It's in the mid-20s. Svein also mentioned the BM-C-33. This is a world-class discovery. In terms of closing, there is no change in the announcements that we made. Things are progressing according to plan.
Great. Thanks.
As there are no further questions, I will turn the call back for any closing remarks.
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-ups, and we look forward to seeing you all on the seventh of February for our fourth quarter results and the CMU. Thanks very much. Bye-bye.
That will now conclude today's conference call. Ladies and gentlemen, you may now disconnect.