Equinor ASA (EQNR) 2017 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Statoil analyst conference call for the third quarter 2017.

With me this morning, I'm pleased to welcome Hans Jakob Hegge, Chief Financial Officer; Svein Skeie, Head of Performance; and Orjan Kvelvane, Head of Accounting.

Hans Jakob will present the results for around 15 to 20 minutes and we re-invite polling for questions and take Q&A for around 45 minutes, expecting to close the call around 12:30 CET.

With that I hand over to Hans Jakob to start the call.

Thank you, Peter, and good morning, everybody.

Thank you for calling in.

This morning we presented Statoil's third quarter results, and let me share some of the highlights from another strong quarter.

Adjusted earnings before tax was $2.3 billion.

The quarter is characterized by solid earnings and underlying cash flow, good operating performance and high production sold at higher prices, continued progress on our cost reduction and efficiency improvements.

The IFRS result before tax was $1.1 billion, impacted by $0.8 billion in net impairments.

Reported net income was negative $0.5 billion.

We're cash flow neutral at $50 including the scrip.

Note that reported cash flow from operations in the third quarter was impacted by $0.5 billion of cash outflow related to FX movements on derivatives, which is mainly offset at group level and there is no impact to gearing.

We will cover this in more detail on a later slide.

Before we go into the results in detail, have a look at this picture.

It shows the Aasta Hansteen topside, the world's largest spar platform on its way to Norway from South Korea.

The field will start producing in 2018.

We have increased the reserves and when Snefrid Nord is tied to Aasta as a satellite in 2019, this result in further value creation.

We had a good progress on Johan Sverdrup and this quarter, we reduced the CapEx by another NOK 5 billion to NOK 92 billion for Phase 1.

We have also started electricity production from the Dudgeon, Hywind project offshore U.K. And we took a first step into solar energy in Brazil.

Then to the macro.

There has been a strengthening oil and gas markets and we are heading towards rebalancing in the oil markets and this affirm gas prices compared to last year.

However, Oil and gas prices continue to be volatile with uncertainty linked to the prolonging of production curtailments among the OPEC members, the production level realized from unconventional U.S. and geopolitical uncertainties.

We adjust just our medium-term price expectations somewhat this quarter.

We previously assumed an oil price of $75 per barrel in 2020.

We now assume $75 in 2022.

Our fundamental oil price will remains the same.

We see increasing demand taking inventories closer to balance, we're seeing under-investments in new oil supply for 3 years and we believe in an uptick in the prices going forward.

Statoil has been an active explorer in 2017.

During the first 3 quarters, we completed 22 exploration wells and made 11 discoveries.

Some of these discoveries can be tied into producing fields rather quickly.

In the Barents Sea, we completed a very efficient high well campaign and made the Kayak discovery, adding volumes to Johan Castberg.

The value of the Kayak discovery alone pays for the entire campaign in the Barents Sea.

We also collected valuable information for next year's campaign and we continue to replenish our exploration prospect inventory.

The 3 main takeaways this quarter are solid earnings and underlying cash flow, good operational performance and high production sold at higher prices.

Expected production growth in 2017 is increased from 5% to around 6%.

And due to good progress in the field development project portfolio, continued capital discipline as well as the further improved efficiencies, we are reducing our CapEx guidance for this year from $11 billion to around $10 billion.

In sum, Statoil is doing a lot more for less.

We cover our investments and dividend at $50 as communicated at the Capital Markets update.

We have made the company more resilient and better positioned for further recovery in the oil price.

As noted earlier, our IFRS result before tax is reduced by net impairment.

We have made impairments and reversals.

Based on asset market reviews, operational asset reviews and the effect of price changes, the net sum of impairments and reversals is $0.8 billion negative.

The largest impairment $0.85 billion is that specifically on Eagle Ford.

This was triggered by lower-than-expected production volumes, but the impairment in itself is calculated based on a market valuation.

As you would know, there is volatility and uncertainty in evaluation and we have therefore used an independent third-party in this case.

Remember, we have made impairments and reversals.

In fact, since fourth quarter 2015 on Eagle Ford, we have made reversals of $0.6 billion.

We are working hard on an improvement plan for the asset.

Our other U.S. onshore assets are not affected.

Then to the dividend.

The Statoil Board of Directors has decided to maintain the dividend also for this quarter at $0.2201 per share with a 5% discount in scrip dividend option.

We have run the scrip program in a predictable way.

Third quarter 2017 is the last quarter of the program and we have no plans for an extension on new program.

From fourth quarter 2017 onwards, you should have the expectations that we will return to full cash dividend with no scrip option.

Then to safety.

Statoil's serious incident frequency the last 12 months was 0.7 per million hours worked.

This is down from 0.8 in the last quarter.

Safety is and will always be Statoil's top priority.

We continue executing our safety improvement agenda to further improve Statoil's safety record.

Let's now have a look at the third quarter and year-to-date financial results.

We delivered a solid $2.3 billion in adjusted earnings before tax this quarter.

This is up from $0.6 billion for the same period last year.

The key levers behind our third quarter earnings are good operations with high production and regularity, capturing higher realized prices.

Adjusted earnings after tax was $0.8 billion compared to a loss of $0.3 billion in the third quarter last year.

The tax rate in the quarter was 65%.

We realized an average liquid price of $47 per barrel, an increase of 18% compared to third quarter last year.

Realized European and North American natural gas prices were also high in the third quarter by 8% and 11% respectively.

Statoil's OpEx/SG&A costs, measured in underlying currency, have been further reduced by 11% per barrel, compared to the same period last year.

Now, let's have a look at the segments.

E&P Norway delivered on adjusted earnings before tax of $2 billion.

This is a doubling of the result delivered in the same period last year.

Our improvement agenda continues to yield good results.

This quarter, we delivered the highest third quarter production since 2009.

In addition, we utilized our flexibility to produce more gas at higher realized prices.

Also in the quarter, we had fewer planned turnaround compared to last year.

This resulted in an underlying production growth of 27% compared to third quarter 2016.

The underlying OpEx/SG&A costs are at the same level as in the same quarter last year, even if you added new producing fields.

On a per barrel basis, we see a reduction of 18% measured in NOK.

Liquids prices 16% higher and then internal gas transfer price 59% higher.

Our liquids production increased by 8% and the natural gas production by 48%.

E&P International delivered adjusted earnings before tax close to 0 compared to adjusted earnings of minus $0.6 billion in the same period last year.

E&P International delivered an underlying flat production year-on-year adjusted for changes in the portfolio.

Higher prices and lower exploration cost contributed to the improvement.

The cash flow per barrel after tax from E&P International is strong at around $18 per barrel on par with NCS, and year to date, E&P International has delivered positive adjusted earnings of $1.1 billion.

Our MMP segment delivered strong pretax adjusted earnings or more than $0.4 billion compared to $0.3 billion in the third quarter last year.

The increase in earnings is due to strong liquid trading result, higher margins and strong regularity at our refinery.

The increase was partly offset by a price review arbitration award.

Then to the production.

During the quarter, Statoil's total average liquids and gas production was 2,045,000 barrels of oil equivalents per day.

This is up 240,000 barrels per day, year-on-year.

On the NCS, up time was high.

This combined with [IR and ULs] largely affect the natural decline.

Important incremental production volumes were added by increased production of flexible gas volumes at higher prices, mainly from Troll.

Compared to last year, our turnaround activities this quarter resulted in lower production losses.

Finally ramp-up of production from new fields like Gina Korg, Ivar Aasen and (inaudible) on the NCS, an increased production in the Gulf of Mexico contribute significantly.

Early in 2017, we guided that Statoil would be cash flow neutral as an oil price of $50 per barrel including our dividend program based on organic investment.

With an oil price just below $52 per barrel during the first 9 months, we can report solid year-to-date progress with free cash flow of $3.6 billion.

The organic free cash flow in the third quarter was around 0. Our net debt ratio is 27.8%, on par with last quarter.

The figure reported for cash flow from operations in the quarter was impacted by $545 million related to FX movements on financial derivatives.

We optimize interest charges through derivative instruments and these may not be in USD, so we hedge these so there is no FX risk.

Any movement in USD/EU shows on operating cash but equal opposite effect in cash is shown elsewhere on the cash flow statement, mainly in cash flow from investments.

This is difficult to see directly that explains why operating cash flow may seen below some expectation.

Net at group level, no impact on overall cash flow on the gearing.

So let me close with a few comments about our guiding.

As I mentioned in my introduction, we are adjusting our 2017 CapEx guiding downwards from $11 billion to around $10 billion.

This is due to excellent project execution, efficiency improvements, cost reductions and strict capital discipline.

We increased our production growth from 5% to around 6% in our guidance.

The average annual production growth rate during 2016 to 2020 is unchanged at around 3% per year.

Our 2017 exploration expenditure is unchanged at $1.3 billion.

In closing, please make a note that Statoil's Capital Markets update will take place in London, February 7, 2018.

Thank you for attention . I look forward to your questions, and Peter will guide this us through it.

Thank you, Hans Jakob.

With that, I'll pass the phones back to the operator who can explain the process for polling for questions.

Thank you.

(Operator Instructions) We will now take our first question from Theepan Jothilingam from Exane BNP Paribas.

I just wanted to come back to the cash flow if that possible, please.

And thank you for the clarification on the FX impact from derivatives.

I wanted to perhaps just come back to cash tax in previous guidance.

Could you just update on where you see cash tax guidance [trend towards] perhaps both between the Norwegian piece and also international E&P, and then just bridge the gap therefore to Q4 cash flows.

Thank you.

So let me just take one step back on the cash flow.

As I said, they are neutral at $50, so this is in line with guiding [$3.6 billion] positive year-to-date . In the third quarter, the organic cash flow to investments and derivatives is an important explanation.

In the first half of this year, we had [2 billion] in the deferred taxes and [1 billion] on CapEx.

If you look at the third quarter versus the second quarter on the operating activities, minus [400], the derivative is [0.5] and taxes is [0.4 or 0.5].

So on this P&L tax versus cash taxes, the P&L tax was [1.4 billion], the taxes payable [1.5 billion], so there is a negative deferred tax of around [100], we paid [1.6 billion] in taxes in the third quarter, of those [1.2 billion] were in Norway.

If you look at the fourth quarter, we will have to 2 tax payments, each are 1.2 billion , only one we have in this quarter.

So we still have free cash flow for the year and we continue our efforts.

And is there any -- was there any particular higher cash tax in international or?

Svein, you can go into the international segment.

As Hans Jakob said, we paid [1.2 billion] in Norway and you see the total around [1.6 billion].

On the international segment, it's been very high between the quarters.

It's been also then related to several of the countries that we are in where we are then paying taxes or it varies between the quarters.

So no major changes.

Yes, I mean, if you look at what we are actually paying on the international, the tax on the adjusted earnings were [51 million] versus compared to the third quarter last year it was [121], so it was lower this quarter.

Next question comes from Biraj Borkhataria from RBC.

It was on the Eagle Ford, could you just give some more details on that impairment and some more color around that asset.

Is this a localized issue and certain acreage that you have or is this an asset level issue?

And could you talk a little about recovery rates and how things have changed versus your expectations, because it does look like quite a significant shift.

So the [history] coming from -- both in this quarter and in previous quarters, we had impairments and reversals and the largest one in this quarter is Eagle Ford.

So this is due to the trigger of reduced production rate.

We -- as part of the industry, we started a year ago to do tight well spacing 200 feet to 250 feet.

We had the great faith in this measure of course.

So we actually reversed based on the plans and indicative results.

That didn't turn out to be as favorable as we hoped for.

So we have of course stopped that practice and are changing it.

This is an the Eagle Ford issue as it has been for the industry with tight well spacing.

So based on that we did evaluation, third-party market assessment and they have started working out on improvement plan.

So we have moved from 200 to 250 feet well spacing to 500 feet.

Very early days, too early to conclude but the indicative result so far is in the positive direction.

So this is something we will come back to.

As I said, there is uncertainty in evaluation and reserves and so that's why we have these changes.

Our next question comes from Oswald Clint from Bernstein.

Maybe just on the CapEx reduction, perhaps you could go into some examples of where you are actually getting more for less [it sounds] possible certainly over last 9 months which has actually caused that reduction.

And maybe also can we expect that similar saving to flow into 2018?

And then a second question, just quickly, I was curious if you could give us some numbers on the up-time or the regularity that you're speaking about maybe so far in 2017 versus the same time period last year if possible, please?

So on the CapEx.

This is very encouraging to see, because we have more than 30 development projects and we see small focus and improvements across the board.

This is what we call the [capital] component.

The obvious example of course from this quarter is the continuation of the improved world-class performance of Johan Sverdrup.

Taking it another [NOK 5 billion] this quarter to [NOK 92 billion].

This is, as you know, a very big project, many elements, many moving parts, 60% completion on the project and they just continue.

So this is very encouraging.

The other clear examples over time have been the drilling on the well area where we are drilling faster, more cost efficient, less time, fewer mistakes.

So these these are very strong contribution.

In terms of '18 in CapEx that's a natural theme for the Capital Markets update, we will revert to that.

On the production efficiency and the up-time, we see very high regularity on the NCS.

Also on Peregrino for the quarter, we typically talk about up-time caused by not only very sound operational judgment by our people offshore, but also very good execution of the turnarounds, fewer unplanned losses.

So this is really, really strong performance adding to the strong production in the quarter.

Our next question comes from Lydia Rainforth from Barclays.

Two questions if I could, hopefully, both are very simple.

Just go back to the cash flow from out from the 500 million that you are talking about (inaudible) is that something that was just one-off related to the FX rate or is there something else that means the cash flow will constantly be switched between the [CFFO] and the [CFF] and the investment lines within that.

I just want to make sure it's just one-off for this quarter.

And then second one, it was (inaudible) in terms of what was a good production in the 3Q, are you utilizing that safe gas capacity in fourth quarter as well?

So to the last one, Lydia, probably for the fourth quarter the flex gas -- you know, this is winter season, normally high demand, we have the power, we also have the increased permit on Troll with 36 giga.

So this is likely to be used and taken into into account also and we say around 6% production.

On the first one, they will vary quarter-on-quarter.

This quarter it is FX, so it depends on your view on FX fluctuations in that.

Our next question comes from Teodor Nilsen.

First I'm clinging on another question on CapEx . Is like the updated CapEx value of $10 billion, is that sufficient to support the 3% growth up to 2020 excluding any potential cost inflation effects.

And then my second question is on another one on Eagle Ford, that definitely makes sense that the changes you have made there (inaudible).

But how much have changed the assumed production level going forward?

So on the CapEx, $10 billion sufficient to support 3% growth, yes.

And no changes to the growth rate and we think this is sustainable.

On the Eagle Ford, our production guidance for this year takes into account all the changes in the portfolio.

It doesn't give a level of detail specifically on the Eagle Ford or the U.S., but it was a high production in the quarter in the U.S., a combination of ramp up in the Gulf of Mexico, but also significant contributions from the onshore, particularly Bakken and Marcellus produced very well.

And since we are into a phase now, with improvement work on the Eagle Ford, I think is a topic that we will revert to the implications for onshore.

But to let there be no doubt that our production guidance from around 6% is as an increase and we have changes because we think we are likely to reach it.

Only one on the Eagle For.

Could you -- is it possible to indicate somewhat like the range of reduction for your estimated production, is it down 5% or down [50%] compared to your previous plans?

No range today.

Our next question comes from Alastair Syme from Citi.

Can I ask about the revision to the medium-term oil price that you have made.

OPEC has acted to (inaudible) the oil market this year.

So I wonder what has made you change or delay your $75 view by 2 years, and can I also ask what was $75 view is based, why is not $60 or $90?

Very simple answer to that.

This is complex, but simple answer, more cautious view.

The $75 is unchanged and it's a 2-year deferral due to some of the resilience that could potentially come from the onshore part.

It has not been all is strong in the production from the onshore, but this still has the capacity we think, the development in the storage levels, yes, they're coming down, there coming into a re-balancing of the market, but just a more cautious view on it might take some time to reach the $75.

So the sort of view essentially the U.S. shale comes back into the market little bit more aggressively, is that what I take to read?

So to reach the $75 also need a conventional production kicking in and we had 3 years with under-investment.

So we still have a firm view on the oil price going to go up over time.

Our next question comes from Rob West from Redburn.

I'd like to ask 2, please.

One is on the different shale basins in the U.S. Could you give us a sense of how you are in terms of free cash flow within those basins?

So are they absorbing cash or something like Bakken is getting towards more cash generating tradition.

And really the reason I was wondering is, in the Eagle Ford, you talked about the impairments that are typically noncash, but I was wondering are there any one-off extra cash flow hits from what's on your competitors [call things] like train wreck wells that [tight] down-spacing in the Eagle Ford and whether there is some extra CapEx that will drop out and not be spend going forward?

Second one was just really quick.

It was something elevating your depreciation rate in Norway in the quarter.

Normally when troll ramps up depreciation goes down, but it stayed pretty high and so I was wondering if you could comment on that.

So on the shale in the U.S. and the cash flow, what we say is, on the international, it's on par with NCS overall.

Remember, we have given figures on wells with a competitive breakeven and we've also given ambitions for cash generation of $12.5 and they have good progress on this program, which we call 90 to 50.

So on the wells spacing, and the change of CapEx, it's too early to conclude.

We have changed the wells spacing to avoid the space of 500 feet.

But we haven't grown to say any change in the CapEx related to the changes, it's too early.

On the DD&A, this was Norway, right.

So in Norway, it's minus 5.5% per barrel year-on-year in NOK.

Remember, we have new barrels like Gina, (inaudible) Ivar Aasen, they are [140 million] if you look at the contributions and the FX is around [60] so there is [200] related to that.

Okay.

I guess that's clear, it's maybe also the FX is contributing there as well.

It's around [60].

Our next question comes from Jon Rigby from UBS.

So take a point about the increasing guidance for production for 2017, but also note that you've not changed your medium-term guidance, so I just wanted to look little closer at this increased gas production in the third quarter.

You're able to characterize the quarter in terms of what was just you taking opportunity, what you think was unusual demand characteristics in the quarter and what you think maybe somewhat more structural.

And if there is some kind of uptick in structural demand in continental Europe and U.K., is or does your portfolio technically and from a license perspective allow you to run at higher rates over the next 2 to3 years and is currently envisaged in your production guidance, which will be more consistent with your 2017 performance.

So for last part quarter, yes, portfolio allows us.

We have -- remember, we have the increased permit on Troll 36 giga from fourth quarter and they're ready to use it.

So the first part on unusual demand versus structural demand U.K. is of course is an example.

You gave it yourself replacing coal with gas.

We also saw quite high demand in Europe, warm weather, boosted gas to power.

We saw fairly low storage levels into a strong gas production in the quarter.

We also saw some deferred volumes from 2016.

The EU gas prices were up 8%, and in addition with increased production permit for fourth quarter, we actually see some bullish pricing for the EU gas for the rest of the '17.

I didn't mention the storage rough and capping of Groningen.

So this taken into account we have a quite optimistic view going forward, and yes, we have the capacity.

So just to confirm, when you set out your medium-term view last year, it was a mix of what you could technically produce from what you thought the market would technically would want and you sort of [plotted a cross] between those 2 numbers, is that a way thinking about it?

Yes, you are right.

Our next question comes from Brendan Warn from BMO Capital Markets.

I just -- most of being answered but I just want to kind of look at 2018, Hans Jakob, just you've still got a quite a stubbornly high gearing.

You might note in that you've got allowance to produce more from troll, but I just remember seeing something in 2018, we're expecting higher annual sort of turnarounds.

Can you sort of talk through -- obviously, we're going to have higher cash taxes in 2018, through the oil price this year in moving to full cash dividend in 2018.

Just the expected impact to your gearing level, if you're expecting that to actually pickup in 2019 sort of current oil price levels or what you're looking to do arrest some of that debt issue?

So on the gearing, we maintained it flat in the quarter, still below 28%.

Turnaround activity next year, yes, it is higher than this year, but we will come back to the specifics on that one.

Increased prices and [small] taxes, you're right.

Cash dividends, you are right.

Remember, we have reduced the annual expenditure on improvement of [$3.2 billion], adding [$1 billion] this year.

We are fostering our culture of continuous improvement.

We expect to see across the board further improvements.

We are not stopping by any means.

We have digital, more than digital [30 digital pilots]; we haven't talked a lot about those.

So many things to look forward to, I think.

The next question?

Our next question comes from Christyan Malek from JP Morgan.

Three questions.

First is , I know you talked about $10 billion being sort of the updated guidance, can you just confirm that's going to be your medium-term outlook on CapEx and there's no upside risk to that, particularly with a slightly more bullish view on oil prices urged by the forward curve, isn't stays at $10 billion?

The second question is regarding sort of the approach of drifted instruments in your cash flow.

Clearly given the negative reverse into Q3, I just want to understand how we think about that in the context of your cash flow going into Q4, particularly as taxes don't go up.

It was strong in the first half yet didn't seem to be netted out of cash flow and now it is being netted out.

The third question is regarding the switch of the script.

Is it too early to just ask you whether there is a view or discussion around the board on what do you look to sort of neutralize of buyback in 2018.

So on the last one, this is the part of our CMU communication in February.

On the derivatives this is a one-off and on the $10 billion CapEx, medium-term outlook, unchanged.

Our next question comes from Hamish Clegg from Bank of America.

Couple of quick ones.

Just, first of all, could you give us a kind of that color on what we can expect in international exploration in the fourth quarter.

We saw a bit of tick up this quarter and to hit your guidance and I see that higher than the first half of the year.

Also, this is a long shot, if you pull your guidance down to $10 billion for this year, you're guiding $11 billion for the 2-year period, should we be forecasting a higher number next year to count for all those projects, like Johan Castberg that you are intending on FID.

Can we see a slightly busier FID pipeline (inaudible) ?

So on the last one, no -- not higher CapEx for '18, but we revert to the CapEx for '18, so you cannot interpret it as a significant change from this year.

It's something we will revert to.

So on the international exploration guidance, keep at unchanged activity level of [$1.3 billion] for the year and we have said that we would do around 30 wells.

We haven't given any changes to that.

And we had several discoveries that could be tied in.

There will be wells around year-end which has not been completed.

So there is no change of thoughts on the guidance, and most of the wells would have been drilled and we don't expect any major changes, that's why we keep the guiding unchanged.

And a tiny follow up.

When we hear about the Brazilian licensing rounds, can we expect that to be fed into CMU or you might give us a little bit of color kind of post-announcement, I'm guessing, it will be at some point on Friday?

That would be a part of CMU.

Our next question comes from Anne Gjoen from Handelsbanken.

Two questions, if I may.

First, on Page #5, E&P Norway, 18% cost reduction per barrel.

Could you comment something on the cost level next quarter and into 2018 as well?

On the same slide, MMP, natural gas impacted by price review.

Could you comment -- give bit more flavor on how much the impact is of that review?

So on the first one, on the E&P Norway, absolutely right.

We have -- we're still getting cost improvements on group level.

The OpEx/SG&A is down 11% in the third quarter.

And in E&P Norway, it's 18% as you said year-on-year per barrel.

We see (inaudible) costs down year-on-year and we also know that the cost per barrel will vary with the production mix.

Typically towards the end of the year, you would see higher levels of gas produced with an increased permit and that gives an indication of the development.

But in this quarter, we added significant volume from Gina, [Bergen], Ivar Aasen.

So the production mix is also part of this.

But remember, NCS is now at a 10-year low on costs.

Our next question comes from Anish Kapadia from TPH.

First question was on your -- the balance in your portfolio of short-cycle U.S. onshore versus longer cycle following this the downgrade in Eagle Ford.

Just wondering how do you see that balance at present and would you be more inclined to make acquisitions U.S. onshore or outside of that space.

And just kind of related to the Eagle Ford downgrade, I think there is some concern in the market over you're relatively low reserve life.

And I'm guessing that's going to fall further on the back of the Eagle Ford downgrade to reserves.

So just how you kind of thinking about that reserve life within that context as well.

And then just 1 quick clarification, based on kind of current oil prices, is it fair to assume that your cash tax payable in 2018 will be about $2 billion to $3 billion higher than in 2017?

Thank you.

So I'll start with, on the second question before over to you, so excuse me for that, but on the price review then, it is significant but it's less than a [$100 million] in the quarter.

So then to your 3 questions.

The onshore M&A, well, unfortunately, I have no announcements on the M&A either onshore or offshore today.

We have an opportunistic view on M&A as we have had in the past.

So we'll talk about it if and when something happens.

In terms of a reserve life, on the portfolio level, we like to talk about the next generation portfolio with an excellent breakeven at [27] on average short payback time [2023, IIR] 20%, you've heard me say this before, so we are not worried about that.

On the Eagle Ford, this is part of what we are assessing based on the change and the improvements work we are doing.

On the cash tax, going forward, I leave up to Svein Skeie.

On cash taxes, remember what we said before for the first half of this year that we had the benefits come from oil price level and gas price levels from 2016 and we said that for the first half that it has an impact of approximately [2].

So oil price will be depend on the (inaudible).

We are paying the cash taxes on NCS and based on the prices that we currently see.

I said that we've paid [1.6 billion] in taxes in this quarter and it was [1.2 billion] related to the first tax installment 2017 Norway, so that's -- I also said, I think, that we will have 2 tax installments, 1.2 billion each in the fourth quarter, so...

We will now take our next question from Marc Kofler from Jefferies.

Just 2 left please.

Hans Jakob, a few weeks ago, you talked about CapEx rising slightly to 2020 from $11 billion in 2017.

So I just still not 100% clear in my mind, if that's now rising slightly from $10 billion in 2017 or if 2018 number is still premised of that rising slightly off $11 billion for this year.

And then could you also just give a bit more color around the trajectory on volume growth out of the U.S. at the year-end?

On the volume growth, U.S. towards the year-end, we have -- if you look we are restoring.

We continue to look closely at the economics before we raise activity.

At the moment on the onshore, we have the 5 operated rigs and 4 completion crews due in Bakken.

Onshore has increased year-on-year with new wells in Bakken and Marcellus is nonoperated due to improved basin prices.

And in the Gulf of Mexico, we are up year-on-year Heidelberg, Tahiti, Julia and 7 new wells.

So that's [restoring] point.

So, offshore, we have increased production; onshore, we will assess it based on cautious economic considerations.

But bear in mind that our guiding on production for the group has been raised to around 6%.

On CapEx going forward, I think this is a natural theme for the Capital Markets update in February.

Our next question comes from John Olaisen from ABG.

All my questions have been taken.

We will now take our next question from Iain Reid from Macquarie.

Just another question on CapEx, maybe you can answer this one.

The Brazil pre-salt license rounds, as was previously mentioned, that's closing tomorrow.

You are going to be awarded the (inaudible) Carcara, which is got essential bonus of BRL 3 billion.

So are you going to take your share of that in the fourth quarter or is that going to be a 2018 item?

The day before the bid closes, I won't make any comments on the sales.

I will have to avert that.

Can I ask just another quick one then.

When you gave that answer about cash taxes in 2018, I couldn't hear the answer because of there was a lot of interference on the line, do you think, you just repeat the answer to that pretty much again?

I didn't comment on it.

Sorry for that, not commenting to that, Reid.

I just commented on the taxes that we had in first half of this this year.

And what we said that those have a benefit from the price level in 2016 and then estimated that to be around [2 billion] in the first half in lower taxes compared to if you have paid the taxes based on (inaudible) production.

So...

Thank you, everybody.

I think that's the end of the questions.

I just like to thank all the participants both on the call and here in the room in Oslo.

Also just as a reminder, we have our fourth quarter earnings and Capital Markets Day, as Hans Jakob said, on 7th of February and look forward to meeting you then, and of course, engaging with you before then.

Any other questions, as always, please direct them through to Investor Relations.

Thanks very much.