Equinor ASA (EQNR) 2018 Q3 法說會逐字稿

Ladies and gentlemen, and welcome to Equinor's 3Q '18 analyst call.

I'm Peter Hutton, Head of Investor Relations at Equinor.

And I'm delighted to welcome Lars Christian Bacher, our CFO.

He's also joined by Svein Skeie, Head of Performance Management; and Morten Haukaas, Chief Accountant.

Lars Christian will run through the presentation for around 12 to 15 minutes, and then we will open up for questions.

And we'd expect the call to finish within the hour.

So with that, let me pass the word over to Lars Christian.

Thank you.

Thank you, Peter, and good morning, everybody.

I've been looking forward to talking to you in my new capacity as CFO.

It's good to start by presenting Equinor's strong third quarter result.

Three things to highlights.

One, our adjusted earnings before tax this quarter more than doubled compared to the same period last year to $4.8 billion.

The after-tax adjusted earnings were strong, $2 billion, which is up more than 140%.

You have to go all the way back to first quarter 2014 to find strong results, and then remember the oil price level above $100.

Our third quarter IFRS net operating income was $4.6 billion.

Two.

We had the best ever after-tax adjusted earnings for our international segment of $774 million.

And three, we are lowering our CapEx guidance from around $11 billion to around $10 billion.

This is strong deliveries.

Higher oil and gas prices have, of course, contributed to the good result, but it is not the only explanation.

We create material value because we used the downturn to reduce costs and to transform Equinor into a more competitive company, being more agile and resilient.

With the E&P industry seeing higher oil and gas prices, now is the time we must show discipline and protect the structural improvements we have achieved over the last 4 years.

Together with our suppliers and partners, we have a joint responsibility to continue to improve and further strengthen our competitive position.

This is how we can create the basis for a stable activity level, new projects and value creation for all.

We are continuing to progress our next-generation portfolio.

In third quarter, we delivered field development plans for Johan Sverdrup Phase 2 and Troll Phase 3. These 2 projects, both with very low breakevens, are excellent examples of our ability to deliver on our always safe, high-value and low-carbon strategy.

Phase 1 of Johan Sverdrup is more than 80% complete and expected to start producing in November next year.

But it's not only the largest project that generate value.

On October 14, we started producing oil from Oseberg Vestflanken 2, the first unmanned wellhead platform on the Norwegian continental shelf.

We delivered this field with a CapEx of NOK 6.5 billion, around 20% below forecast at the investment decision.

The breakeven for the field has been reduced from $34 at FID to less than $20 per barrel now, further improving an already robust field development.

The Mariner field in the U.K. is progressing with hookup and commissioning ongoing offshore.

Due to challenging weather conditions, very challenging weather conditions and other factors, the estimated first oil date is delayed to first half 2019, with CapEx unchanged.

I repeat, CapEx unchanged.

Meanwhile, the Mariner reserves have increased by around 50 million barrels, a 20% increase.

This comes as a result of improved reservoir understanding and a more optimized drainage strategy.

We also continue to strengthen and sharpen our asset portfolio to create value.

The acquisition of Rosebank operatorship in the U.K. gives us the opportunity to leverage our experience gained from Johan Castberg to realize a new exciting deepwater project with a considerable value creation potential.

At the same time, we have reasonably divested the undeveloped and, for us, low-priority discoveries, King Lear and Tommeliten Alpha on Norwegian continental shelf.

With these transactions, we deliver on our strategy to create value through the cycle.

In the quarter, we also continued to strengthen our industrial position in renewables.

We are on track with the Apodi solar project in Brazil, and we have started the delivery of power from Arkona offshore wind project in Germany.

Equinor is now in projects with the capacity to supply around 1 million European households with power from offshore wind.

The third quarter is characterized by strong cash flow generation, strong earnings across all business segments and high production capturing higher realized prices.

We reduced our net debt ratio from 27.2% in the second quarter to 25.7%.

Combined with strict capital discipline and continued strong project execution, we are able to reduce our CapEx guiding for 2018 from around $11 billion to around $10 billion.

We maintain our commitment to capital distribution, and the Board of Directors has decided to maintain the dividend for third quarter at $0.23 per share.

The safety of our employees and the integrity of our facilities and installations is, and will always be, our top priority.

Our Serious Incident Frequency in the last 12 months was 0.5 per million hours worked.

This is the same level we achieved in the 2 previous quarters and it is the lowest level ever achieved by Equinor.

In the same quarter last year, our score was 0.7.

Now let's have a look at the key financial takeaways for this quarter.

Adjusted earnings before tax were strong at $4.8 billion, an increase of $2.5 billion.

This is more than a doubling when compared to the same period last year.

The IFRS net operating income was $4.6 billion.

There are 3 key drivers behind the strong quarterly results: higher realized oil and gas prices; high production due to new fields and new wells; and continued strong cost focus.

I'm very pleased to see that all segments delivered strong results this quarter.

We realized an average liquid price of $67.6 per barrel, an increase of 44% compared to the third quarter last year.

Realized European gas prices were up 33%, while North American gas prices were up 15% year-on-year.

Adjusted earnings after tax came in at $2 billion, up from $0.8 billion in the same period last year, an increase of 143%.

The tax rate in the quarter was a low 59%.

At higher oil prices, we are seeing sustained profits being generated internationally in the areas with low effective tax rate.

Let's now have a look at each of the segments.

E&P Norway.

E&P Norway delivered adjusted earnings before tax of $3.4 billion.

This is an increase of 68% year-on-year.

The main adjusted earnings driver were higher realized prices, combined with lower DD&A.

Production was down 6% due to an increased number of turnarounds and expected field declines, partially offset by contributions from new wells and ramp-up on new fields.

Underlying OpEx and SG&A costs per barrel increased somewhat, mainly due to plant turnarounds, new fields and preparation for operations.

E&P International.

E&P International delivered strong adjusted earnings of $1 billion before tax, up from negative $27 million in the same quarter last year.

After-tax adjusted earnings in the quarter from E&P International is the strongest ever.

We recorded the highest quarterly production of 831,000 barrels per day, a 14% growth year-on-year.

And I must say, it's kind of a bit annoying that the record was achieved just after I left EPI.

But Torgrim and Anders and the organization have done a great job.

And as CFO, of course, I'm obviously very pleased with these results.

The underlying OpEx and SG&A cost per barrel was stable in International, adjusted for royalty and asset retirement obligations.

The net cash margin -- sorry, the net -- the cash margin per barrel after tax in E&P International is a strong $30 per barrel, which is higher than the contribution per barrel from the NCS.

Our MMP segments delivered strong pretax adjusted earnings of $481 million compared to $423 million in the same period last year.

The good delivery is mainly due to strong products trading and strong results from European gas.

During the quarter, Equinor's total average equity liquids and gas production was 2,066,000 barrels of oil equivalents per day.

This is an increase of 21,000 barrels per day, corresponding to a 1% increase compared to the same period last year.

The production growth is due to start-up and ramp-up on new fields; portfolio changes, among them, the acquisition of the Roncador field in Brazil; and new wells put on production, especially onshore U.S. This is partly offset by high plant turnaround activity on the Norwegian continental shelf.

Year-to-date, we report strong cash flow from operations of more than $20 billion before tax.

After investments, dividends, proceeds and transactions, the net free cash flow year-to-date is $2.5 billion.

Without the value-enhancing transactions on Roncador and new prospective acreage in Brazil, North Platte in U.S. Gulf of Mexico and Martin Linge on the NCS, we would have more than doubled the year-to-date free cash flow.

Our net debt ratio was further reduced by 1.5 percentage points during the quarter to 25.7%.

In the first 9 months of the year, our organic CapEx is $7.2 billion, and proceeds from portfolio transactions add up to $1.2 billion year-to-date.

Let me close with a few comments about our guiding.

We have been able to lower our 2018 CapEx guiding from around $11 billion to around $10 billion, and we maintain our 2018 exploration spend at $1.5 billion.

This is due to good project execution, efficiency improvements and cost reductions on several projects, like Johan Sverdrup, and strict capital discipline.

Expected 2017 to '18 production growth is unchanged at 1% to 2% and 3% to 4% per year for the period 2017 to 2020.

We are on track to deliver on our ambitions communicated at the Capital Markets Day last February.

As Peter said, I am here with Morten and Svein, and we are looking forward to your questions.

And Peter will guide us through the Q&A session.

So thank you for your attention.

Thank you, Lars Christian.

And in fact, what I'll do is I'll pass the word right over through to the operator, so that she can remind you of the process to poll for questions.

Thank you.

(Operator Instructions) We will take our first question from Oswald Clint from Bernstein.

Yes, I'd like to ask just on the CapEx reduction that you've released this morning.

The $1 billion, maybe could you just break it down a little bit more in terms of is this pricing reductions?

Is this kind of redesigns and cost savings?

Or is it some rephasing of spend into 2019, please?

That will be my first question.

And then secondly, obviously, some very strong cash flow, some decent improvement in the balance sheet position here again.

We didn't really hear any language around the increased shareholder returns.

I think you spoke about earlier in the year that the scope for buyback's emerging back in February.

I just wonder if you could update us on that comment that you made at the beginning of the year given how good the cash flow has been through 2018, please.

Well, thank you, and let me start with the first question on the CapEx guiding for this year.

So we have taken the guiding down from around $1 billion -- sorry, from around $11 billion to around $10 billion for the full year.

And I must say that I'm impressed.

Perhaps I should stop being impressed, but -- because they deliver year-on-year.

But I'm still impressed by the quality of execution of our project portfolio that the projects deliver.

So the ability for us to take down the guiding is based on twofold.

One is capital discipline because we have a lot of sort of small capital projects, too, so this is about capital discipline and making the right priorities.

And then, combined with all the field developments and the projects, this is -- the majority of the contribution is related to project execution.

So this is not sort of a redesign at this stage, so it's more about project execution, so that's why we take down the guiding.

On the element of share buybacks.

So let me then -- and you referred to the beginning of the year, and let me then remind you of what we said at our Capital Markets Day.

We concluded the scrip program as planned.

And we increased the dividend, and said an emerging scope for share buybacks dependent on macro outlook and portfolio developments.

We also said that short-term priority was to strengthen our balance sheet, meaning reducing the net debt ratio.

So since then, in my view, we have delivered on this guiding, and we have reduced our net debt ratio from 27.2 to 25.7 percentage points.

We have delivered strong cash flow as you say after tax at $2.5 billion, which would have been more than double if we hadn't done any inorganic investments during the year so far.

And we have taken positions like North Platte in Gulf of Mexico, Martin Linge on the Norwegian continental shelf and the Roncador in Brazil, to mention a few.

All these, good value propositions for the company and, thereby, also the shareholders.

So you will see us going forward reducing our net debt ratio is a priority, and catering for a flexibility and strong balance sheet, given the different market outlooks going forward and the opportunity space we see for making any good deals.

We will now move to Thomas Adolff from Crédit Suisse.

My first question is also on CapEx and capital efficiency.

I wonder if -- you've done an amazing job over the past 4 years, whether there's actually more you can do from here on or whether it's kind of getting pretty difficult.

And given the update on capital efficiency with these results, I also wondered what it meant for CapEx for the period beyond 2018.

And secondly, on kind of capital allocation, I'm just wondering if you are more actively engaged in buying more assets or companies than selling assets at this stage.

On -- I'm just writing down the questions so I'd remember it correctly.

On CapEx, if there are more to do from now on going forward on projects deliveries.

I mean the better you get, it's kind of harder to improve even further.

So that's obvious.

But what we look at currently within the area of digitalization, we believe that there might be opportunities to improve even further.

But that is something that we are working on.

Too early to conclude and assess how that will influence our different projects going forward.

On the CapEx guiding for the period towards 2020, there is no change in the guidance.

We said around $11 billion in CapEx for 2018, and on average, $11 billion for the period '18 to 2020.

And that guiding remains.

On capital allocation, whether we buy more than we divest currently.

The proceeds from sales at $1.2 billion and $2.5 billion after tax in free cash flow.

And as I said, that number would have been more than double if it hadn't been for our acquisitions.

So yes, we have over the last 9 months bought for more dollars than we have sold.

And we will always look for business opportunities.

We see some areas around the world perhaps more of hotspots, and it's more difficult to make really good business deals, whereas other places, we still believe that there might be room for doing good business deals, and that is what we will seek for.

We will take our next question from Lydia Rainforth from Barclays.

Two questions, if I could.

One was just on the cost side.

You did see a slight uptick in terms of the OpEx numbers.

Is that something you're disappointed by or is that just as you would have expected at this -- sort of just given where the macro side is?

And then the second one, just to come back to the cash flow allocation side.

In terms of the -- you talked a little bit about the buyback, but can you just talk about how you see the dividends policy evolving as we go through the next 2, 3 years?

Thank you for your questions.

The OpEx and SG&A is up 10% year-on-year.

And then I think it's important to be aware of some of the underlying effects behind this.

If we take International first, the increase International is primarily due to new fields like Roncador, but also the fact that last year, we had a reversal related to a positive asset removal obligation.

Then we have higher royalty driven by higher prices.

And if you adjust for these items, then the underlying cost per barrel basis is flattish or even sort of slightly down actually.

On the Norwegian continental shelf, we see also some -- there is one technicality, perhaps I should call it, that you should be aware of.

Internally at the company, we have said that Nyhamna, the ownership of that asset is to belong to MMP and not DPN.

So that means that the DPN kind of have to pay for that service internally in the company, but the net effect for the totality of the company is 0. So that explains some of the cost increase in DPN.

Then we have new fields in preparation for operations.

Then, in addition adjust for the differences in turnaround effects on this, then the production in sort of the OpEx and SG&A per barrel basis for Norwegian continental shelf is up slightly below 3 percentage.

And then the cost per barrel this quarter is then down compared to cost per barrel per second quarter.

Then on dividend policy going forward, we have said that the dividend will increase in accordance with the underlying earnings, and that is still our guiding.

We will now move to Mehdi Ennebati from Société Générale.

I will ask 2 questions, please.

The first one, regarding the flexibility of your natural gas production.

So you've highlighted in the past that thanks to your compressor on some key gas fields, like Troll, for example, or Åsgard, you might be able to boost the natural gas production to create value.

So I wanted to know if you currently consider that the European gas price and European gas demand is allowing you to boost your gas production in the short term, meaning during the fourth quarter and maybe during the first quarter.

So that's the first question.

Second question, regarding your production trend in Angola.

So I have noticed it has been down 12% year-on-year during the first 9 months of this year.

And I wanted to know the reasons of such a decline.

And what will be the production trend in the following year for that country, particularly, as it look like -- as it looks like, sorry, it is a highly profitable production for you?

Let me start with your second question on production trend, Angola.

We see obviously the same numbers as you do, looking at the country and the different assets.

But we also believe that there might be room for actually fighting this decline, but that is highly dependent on achieving PSA extensions.

And then on to your first question, I felt it was kind of twofold.

One on gas prices and demand in Europe and then on our flexibility on the Norwegian continental shelf.

We have seen strong demand in Europe and, thereby, higher prices over the last months and quarters.

We expect that to continue in the short term.

Why?

Well, one, the indigenous production in Europe is declining and declining more sharply than historically, mainly related to the Netherlands.

Second, we see on storage capacity in Europe, there is good storage capacity.

But the storage levels are quite low, so we would expect that approaching winter, that there should be sort of a buildup of storage volumes.

And then thirdly, Europe is -- and gas prices in Europe is exposed to the LNG -- global LNG market.

We see more or less all LNG sort of bypassing Europe and heading for Asia, but that also means that there is kind of a surge then for gas prices to rise in Europe.

On our gas machine in Norway and the flexibility, we have a couple of assets that represent such flexibility.

Troll is one and Oseberg is one.

In the case of Oseberg, currently producing at minimum due to the lower prices now compared to what we'll expect getting closer to year-end and winter period.

So this is well within what we're allowed to produce per year.

So we'll try to use that flexibility to maximize our revenue.

We will now take our next question from Jason Gammel from Jefferies.

Two questions for me as well.

First, on -- just sort of one on capital allocation.

Is there any particular trigger that you would need to see on some of the leverage ratios on the balance sheet before you would move forward with share repurchases?

Or do you see those as linked but independent decisions?

And then my second question involves Rosebank, an asset that you had decided to exit previously.

What drove your decision to come back into the project?

And what's the path forward from here?

I know that the previous operator had put quite a bit of effort into pulling down the costs, but you also referenced your experience at Castberg.

So will there be another iteration of project redesign?

Well, on Rosebank, as you correctly pointed, we exited Rosebank back in time.

That was a non-operated position, 30%.

We sold it in 2013.

The oil prices back then were higher than today.

And also, the CapEx estimates back then was also higher than what we currently see.

And then this opportunity arose then for us to take 40% and the operatorship.

And then we looked at that opportunity and given our experience and given what we believe that we can create value with this, we saw this as an attractive opportunity.

Going forward, we have to wait for government approval and partner approval for this deal to go through.

And then, of course, the development of this will be an FPSO with subsea tiebacks.

And as you correctly point to, we have, among others, Johan Castberg to draw upon when it comes to learnings.

On capital allocation and trigger points, and this is also a question I get quite frequently even out on the road, whether we have trigger points or not.

And we do not have any trigger points.

Why?

Because we feel that, that would not be sort of prudent sort of management given the leverages or the elements that I pointed to.

This is a combination of trying to strengthen our balance sheet, reducing the net debt ratio.

We would like to maintain capital discipline and flexibility and to weather off whatever macro developments we will be facing.

And then it is the opportunity space to build a stronger portfolio.

As an oil and gas company, we need to replenish, which we have been good at, both during sort of the downturn as well as when we have seen an uptick in oil price.

And we will do continue to look for good value opportunities.

But then, remember, a couple of points.

One, it has to be good value opportunities because that's the best way to create value for our shareholders.

And two, no projects will be sanctioned until it is good enough.

We will take our next question from Alastair Syme from Citi.

A couple of questions.

Turnarounds are normally pretty high in the summer months.

So can you just explain what was special about this year that caused Norwegian production to be down 6%?

And I guess put it another way, if you remove the effect of the turnarounds, what would the underlying production trend have been?

And then secondly, can I just come back to the Capital Markets Day?

You presented that chart at the sort of the cash flow from operations guidance, 2018, '19 average.

Obviously, 2018 has seen the benefit from significant tax tailwinds.

Can you just sort of come back to that chart and remind us, is that how you see the average play out in '18 and '19?

Or how should we think about adjusting the tax in that chart versus what you've seen year-to-date?

Yes, lets start with the turnaround.

I mean we guided for the third quarter a turnaround, an expected turnaround effect of 80,000 barrels a day.

And I don't know, Svein, if you want to add some granularity to this one?

No, I think as you said Lars Christian, we guided this quarter's turnaround at 80,000.

Most of that came from Norwegian continental shelf.

If you also compare it with third quarter last year, we also saw that the turnaround was approximately, yes, 30,000 more this quarter compared to last quarter.

So if you adjust for that one, then you see the production on the Norwegian continental shelf.

And then on the cash flow and the guidance, we indicated that we would deliver a free cash flow of USD 12 billion in the period 2018 to 2020; accumulated, $12 billion and at an oil price of $70 a barrel.

If you look at the first 9 months of this year, we feel comfortable that we will be able to deliver on that guiding.

I was actually also referring to -- there was a specific chart that sort of showed the cash flow from operations '18 and '19.

It was a bit of a fuzzy bar chart, but sort of indicated numbers in the high teens for cash flow.

And clearly, you're going to hit that this year in a $70 oil world.

But you've had significant tailwind from tax, so how do we think about '19 in that context?

Svein?

Okay.

I'll just take that one.

As we said, we gave the scenarios for different prices of oil, $50, $70, [$90] (corrected by company after the call) for -- on average for '18 and '19.

What we indicated and took into account the tax effects that we had coming in from 2017.

So -- but what could also then be looked at is when we look at the tax rate and the taxes payable, as we have then taken out and showed in the accounts note for 2018, that could also then kind of -- be kind of indications for also then what to expect going forward.

But definitely taking into account the taxes from '17 for the first half of the year.

Now we are -- entered a situation where we pay taxes on the results from 2018, and we had one tax payment in this quarter.

And sorry, just -- and your expectations for the fourth quarter on tax?

We will have 2 tax payments on the Norwegian continental shelf in the cash flow.

One was paid on 1st of October, which half of it was then adjusted for in the net debt ratio; and the second one will come 1st of December, both of them are NOK 14 billion.

We will take our next question from Anders Holte from Kepler Cheuvreaux.

I just have 2 quite short ones.

First of all, it's related to your just list of priorities for next year.

As your cash flow improves and as your position improves, it seems that the balance sheet is probably at the top of your list of priorities.

Just if you could take us through what then follow in terms of your priorities?

Would you prioritize buybacks or would you continue to look for more value-adding opportunities through M&A?

And also, while we're on to the M&A, what does the opportunity set look like from where you're sitting at the moment?

I mean, previously, you have said that the opportunity set in the industry is as good as you have ever seen it.

I just wonder if that's still the case right now.

On the opportunity set, it is still very good but -- on the aggregated level.

But there are some hotspots around the world where the competition is higher, you could say, and the possibility to really make good value propositions based on a deal is somewhat tougher or more limited.

But there are still plenty opportunities, and we will continue search for them and hunt for them and see if we can strengthening and high grade our portfolio as part of this.

And the M&A is both an accommodation of acquiring assets, but also high grading by farming down or divesting assets.

And we have a tradition for not announcing neither sort of amounts of dollars part of our program or any sort of possible deal prior to you read about them in the news.

On the priorities, on -- in capital distribution, there is no change in our guiding on this topic.

Scrip has ended, dividend has increased.

And going forward, we have said emerging share buybacks, dependent on market outlook and portfolio opportunities, in combination with strengthening our balance sheet, meaning reducing the net debt ratio.

And that is the guidance I can provide you.

We will take our next question from Jon Rigby from UBS.

A couple of questions.

First is on the tax.

You made some comments around the international tax rate looking lower at these oil prices.

I just wonder whether you could give me some sort of further color around how long you would see that and to what sort of sensitivity there is to oil price assumptions.

And sort of as an aside, is that effect carried forward into the cash flow?

Or is this effectively an accounting effect in the P&L?

But the second question is about your U.S. onshore.

I mean, the key advantage of U.S. onshore seems to me, or one of the key advantages, is flexibility.

I know that you're cutting CapEx this year.

But isn't there a case to say that, voluntarily, you start to raise CapEx particularly in the U.S. onshore where you can take advantage of the short cycle aspects of that element of your upstream portfolio?

Very good.

On tax first and tax international.

We elaborated around this during the second quarter where we had internationally a tax rate of 27%.

This quarter, it's lower.

But we said then, at 27%, that, that could be seen as a representative level at these commodity price levels that we currently are seeing.

That means at this low tax rate, that we are earning good money in countries with low tax rate or no tax rate.

And this is why we can report highest earnings after tax ever internationally.

But I also think that the 27% compared to an even lower tax rate this quarter -- I think you should remember that this quarter, there are no exploration activities in the countries with the low or no tax rate.

And you can't sort of -- as you take that for granted going forward, so still, our very best guidance given the current commodity prices is around what you saw with international tax rate for the second quarter.

And yes, you'll see this carried through into the cash flow numbers.

On U.S. onshore and the flexibility and activity level, I think I'll leave that to Morten or Svein to comment on.

But before I do that, to your comment on cutting CapEx this year, that is a way of -- one way of looking at it, but it is not cutting from the point of view that you may just slash the budget because you want to take down the activity level.

The result of around $11 billion, this sort of going down from around $11 billion to around $10 billion in guidance is as a result of being more efficient in the execution of project deliveries and strong capital discipline, but mainly, mainly the first one.

So yes.

So on the onshore activity in U.S. that we're also then following closely what's going on, and as we have said, that we have flexibility here in the operations.

When you compare it to the production one year ago, it has then increased.

We are now producing around 275 while a year ago, we had approximately 225.

So then increasing it in line with prices.

We are -- in the operations, as we end the quarter, we have 3 rigs in place there.

And also, on the non-ops, there are more rigs now than earlier.

So it's about then utilizing the flexibility.

But what is also important is then the completion of the wells that we -- and as Lars Christian said also in his presentation, that production is going up, also due to the fact that we have completed more wells.

So a combination of both drilling as well as doing completion on the wells already drilled.

Can I just follow up?

Do you have the capacity or capability or the acreage to lift activity rates should you choose to from here?

That is on -- there is flexibility in the onshore then to adjust the activity.

We will now take our next question from Christyan Malek from JPMorgan.

Two, please.

First, I mean, sorry to come back on this tax.

So just can you give us visibility in terms of how long this is going to last in terms of these sort of effective subsidies through the unrecognized or deferred tax assets that you have in the U.S.?

I mean, is this sort of an opportunity over the next few years or do we draw it to a close at this year?

I understand the relationship with the oil price and the fact that it's then generated through U.S. But just to what context can you provide a quantum and the sort of an expiry in terms of when it sort of rolls over to help us model sort of the numbers better through the U.S. In terms of tax rate.

The second question regarding -- understand the capital allocation philosophy that you have, and there are no triggers.

But just to flip it around perhaps, what is the incentive to take -- to advance with more opportunities when you have fantastic assets as it stands?

Or put another way, do you have to keep delivering production growth through the medium term as opposed to just consolidating your assets and giving -- sort of giving the market the cash back through whatever means that you have?

I just want to understand the debate that you're having at the board.

What does it leans you -- seems to lean you more into M&A and taking advantage through a lower balance sheet gearing over and above cash, cash allocation, cash, cash returns.

I just want to understand the debates you're having.

And then if I can ask sort of sub part to that question.

In energy transition, you talked about the CapEx potential to rise to sort of $500 million to $750 million per year, just 15% to 20% of group spend by 2030.

So quite a big uplift.

Would it be perhaps that this is where you're looking to save your dollars and keep your powder dry in terms of putting it into energy transition again over and above returning it back to shareholders?

Let me start with your second question.

And then this question of tax rate and deferral, perhaps Morten can give you some more granularity.

On -- as an oil and gas company, we need to replenish our volumes unless we will decline.

And We have a very strong, healthy next-generation portfolio to come onstream by 2022, bringing 3.2 billion barrels of equity to the company and shareholders.

The 3.2 billion barrels is over the lifetime of those assets that will start up by 2022.

Average breakeven, 21, I mean, with an internal rate of return of more than 30%.

I think that is a very, very attractive value proposition also for shareholders.

And then when we look at the unsanctioned portfolio and the opportunity space we see to take on more, we would like to take on more good projects so that we can keep gearing a healthy return to the shareholders through those value propositions and those activities.

And Morten, on the tax rate and deferred taxes especially in U.S.?

Yes.

Thank you, Lars Christian.

I would also like to then refer back to the 2017 annual accounts note 9 regards to the unrecognized deferred tax assets.

And then with quite some thresholds that we need to pass before we can start recognizing deferred tax assets.

So before -- and we should be really confident before doing that.

We will not go out with estimates, but we can say that so far, we have not recognized significant parts relating to our U.S. operations, but that will come in when we pass these high thresholds given by the accounting standards.

So this is also driven by the technical requirements set from the accounting standards.

Before we go to the next question, can I just ask that we keep the questions tight?

In fact, we are taking the questions in the order in which they are polled.

We want to try and to keep this call within the hour or only shortly past after that.

We still have around half a dozen to go.

So can I ask, can you keep it to one, maximum 2, definitely not 3, and we'll try and get through this to the benefit of everybody.

Thank you.

We will now move to our next question from Rob West from Redburn.

One, just with Oseberg Vestflanken online, could you update us on your reflections from doing that project?

Then any future unmanned wellhead platforms that you feel are now more likely to go ahead now that you've learned the lessons from that one?

And second question is back on shale.

Just the Marcellus and the ramp-up that you've had there.

Is that growth rate going in line with what you would have expected around the start of the year?

Or has something changed to unlock some extra growth, particularly from the Marcellus part of that shale portfolio?

Well, on Oseberg Vestflanken, a very profitable project, well executed, delivered at a cost more than 20% below the FID or the plan for development and operation estimate.

And then we'd love to look for sort of a copy-paste opportunity for that kind of thinking and development.

On Marcellus and the Appalachian, Svein?

Well, at the CMU, we indicated the total production then for U.S. here, including the Appalachian, which is both non-op and the operated part that we're having.

And we are in line with what we said at the CMU, so things are going then according to plans.

We will take our next question from Alwyn Thomas from Exane.

Just a couple of quick questions for me.

Firstly, can I refer back to the Norwegian production question?

We have seen some issues this year, some reported issues in May and also September by the NPD.

Could you comment on the sort of reservoir across your portfolio and whether you're seeing decline rates higher than expected?

And perhaps whether this should lead to higher drilling or maintenance CapEx into next year?

And if I may just ask the CapEx question in a slightly different way.

If you say $10 billion is your base from this year, what makes it more expensive into next year and future years, and bridging the gap?

Well, on Norwegian production and the decline rate, it's as expected; meaning, in accordance with the guidance of a 5% decline.

The quality of assets on the Norwegian continental shelf is still very good and still some tieback opportunities that we are looking at and infill wells and drilling.

We do not see any sort of relationship between sort of this decline rate and the need to do sort of much more maintenance to sort of maintain the production level.

This is more about infill drilling and tiebacks to fight this decline rate than anything else.

The regularity of the assets in third quarter were up compared to second quarter, and very, very good, good results.

On the CapEx and the $10 billion or around $10 billion in guidance for this year compared to then around $11 billion going forward.

So on the $11 billion, and this is, currently, a very healthy, steady -- represents a healthy, steady activity level, given the size and the capacity of our organization, I think that is key to take in.

One of our key learnings -- through the downturn was that you never sanction a project before it is as good as it can get.

So then it's very important now that the prices comes up, but we are not tempted to sanction projects because they're almost as good as they get.

I mean, if you feel that it's the right thing to do, just send it back and have them to go through it one more time.

We will continue doing so because, ultimately, that is what really brings cash to the company and value creation.

The second learning is you don't overstretch your organization, because if you do, then that will influence the whole sort of quality and execution machine as such as an organization.

So if you want to sort of increase your activity level substantially, then you have to do something about the manning side, so that you maintain sort of a good enough sort of capacity.

I'm not saying that we will have slack in that organization because that's far from the case, but overstretching is not good either, and that is also part of the learning from downturn.

So then bridging it from the currently guidance of a $10 billion, around $10 billion for this year and back to an average of $11 billion over the next couple of years, and that is just to say that, that is the healthy, steady activity level.

And we need to replicate overachievements in many ways on the execution level, like we have done this year.

And fingers crossed, I hope for that to happen, but we need to be prudent in our guiding externally as well as our planning internally.

And this is sort of a P50 estimate of what we believe then the ultimate spending will be given what we have our project portfolio for 2019 and '20.

We will take our next question from John Olaisen from ABG.

First, a question on the CapEx.

Is the lower CapEx guidance for 2018 owing to the guidance that you provided earlier this year of an average CapEx of $11 billion for the period '18, '19, '20?

That's my first question.

And the second question, Lars Christian, you have experience now from both Norway, offshore North America and also offshore internationally.

Where do you think Equinor has the best competitive advantage of these 3 areas?

Well, on CapEx guiding, we have said $11 billion for the period average then, '18 to '20, and that remains our guiding, independent on us guiding around $10 billion for this year.

And if I look at -- to your second question, onshore, offshore, whether it's international or in Norway, this is -- in many ways, you can slice this, I think, an answer to this.

But if I look at the oil and gas development, it is about 4 levers that you have to pull to make it work.

One, it is about reservoir understanding, and we are among the best when it comes to that.

Two, it is about drilling wells and being good at it.

And if you look at the external benchmark for the time being over the last couple of years, well, we've been ahead of the pack.

Three, it is about building good, strong organizations.

And I think both the Canadian development and in Brazil and whatever we have in Norway, to mention a few, are good at attracting talent, local talent, and combine that with the experience of the mother ship.

And then, fourthly, it is about deploying technology, technology development.

And technology is in our DNA, and this is about deploying it.

So then, for me, it's -- not whether it's offshore or onshore or one basin over the other, what we really need to continue looking for is the best assets, regardless of whether it's onshore or offshore or wherever.

The only thing that we need to comply to, of course, is sanctions and the no-go zones that are put in place around the world, and we adhere to that, definitely.

No difference whether it's onshore in Argentina or offshore in the Barents Sea in Norway?

You are just as successful -- you'll be just as successful?

If it's a good asset in Barents Sea, I'm game.

If it's a good asset in Argentina onshore, I'm game.

We will now move to our next question from Rafal Gutaj from Bank of America Merrill Lynch.

Just drilling down back onto the CapEx guidance, and apologies for this.

So in the last 3 months, what has specifically led to $1 billion saving in your CapEx budget?

Is it actually just release of contingency and things like Johan Sverdrup Phase 1, which you updated in August?

Or is it actually deferring sanction decisions, for example, perhaps Melaka this year?

Or is it indeed a bit of rounding in there because it looks like it's to the nearest billion?

Correct me if I'm wrong.

And then, secondly, just on exploration, given that you've done all these acquisitions this year, spending $1.5 billion on exploration this year, should we expect intensity on exploration to be consistent over the coming years, or should we be perhaps expect a pullback as you digest your acquisitions?

Well, first of all, going from around $11 billion to around $10 billion is not necessarily equal to us reducing it by exactly $1.0 billion.

On -- there was a part 2 to that question, wasn't it?

CapEx side of it?

But more on the CapEx side, or this is just...

Contingency release or deferring project sanctions.

But I just wanted to know what the split was on that, please, driving to $1 billion saving.

Yes.

As I said, it's not exactly $1 billion in reductions, since it's around $11 billion to around $10 billion.

On those improvements, we do internally, twice a year, go with a run-through of all our projects, and that was done recently.

And then when we look at it, we see that across-the-board, regardless of whether it's a large project, big project or a small one, we see contributions, positive contributions in bringing down the overall CapEx spending for this year.

And it's impossible to pinpoint one explanation, but the big bucket that contributes the most is a stellar execution, project execution.

So that's a part of it.

On exploration, we have taken exploration acreage over the last couple of years and tried to high-grade drilling targets to feed the exploration machine, to put it like that.

And we maintain the guidance for this year at $1.5 billion, and we haven't given any indication of what to expect over the next couple of years, except that we have said on a drilling -- number of drilling of wells, that we should expect a level between 30 to 40 new wells year-on-year.

We will now take our next question from Rob Pulleyn from Morgan Stanley.

I have one question.

So following on from your explanation of your disciplined approach and your operational success, may I ask a little bit around the opportunity set of future projects beyond greater Carcará?

Because at some point, obviously, the geology matches in terms of your opportunity set as to what IRRs and breakevens can be achieved.

So does the opportunity set of what you have in the next 5 to 10 years help support this view that you can maintain this capital discipline and deliver similar breakevens and IRRs?

This is a very key question, a very good one, too.

I think the industry, for many years, have said that the easy barrels are gone.

And from that aspect of it, it's more and more demanding to produce, and usually, that means that they will also be somewhat more expensive compared to the easy barrels.

Then of course, there is another factor that counters this, and that is technology development.

And we have seen huge contributions in the area of technology development and have brought down then the costs per barrel, both when it comes to exploring, developing and producing, and we expect that to continue.

And digitalization is one area that is contributing all these elements or a part of the value chain for oil and gas development.

The opportunity sets around the world, yes, there is fierce competition for good assets.

But I think that we have been able to demonstrate over the last couple of years an ability to be quite successful in taking on good assets.

And going forward, that is our ambition.

And we will only take on projects that we are sure that can represent good value propositions and not erode value.

And taking us back to the Capital Markets Day, we also said then when we look out to the unsanctioned portfolio that our average breakeven were brought down 30% over the last 12 months leading up to February and giving us comfort that as we work then going forward, that we can still improve that portfolio somewhat more.

I'm sure this topic will be revisited.

We will now take our next question from Thomas Klein from RBC.

We've been hearing about capital allocation this morning.

I just wanted to ask one question on another potential aspect of this on offshore wind and how you're seeing opportunities there.

I know you recently signed an MOU with Petrobras and a deal on Holland before that.

So any more color kind of on this side would be helpful.

Okay.

Thank you.

On the offshore wind, as you said, we signed an agreement earlier in Poland this year, so we're looking into that one and working on that one.

We also then secure positions then in U.S. that we also are working on maturing outside New York.

And then in U.K., we have the Dogger bank area that is also what we are looking at.

And then we are then looking into if there are other opportunities that could fit us well.

But currently, those are the areas that we currently have in our portfolio.

We will take our next question from Giacomo Romeo from Macquarie.

A very one -- only one very quick question for me.

Just looking at the Roncador field, this is one of the fastest-declining assets in the Campos Basin in Brazil in general.

Just wondering if you can provide a bit more details on the opportunity set there for you.

You discussed the improved recovery rates in the past.

But when do you think we could start seeing improvements in decline rates?

And then attached to that, whether you see a greater opportunity from doing more work on mature assets in Brazil alongside Petrobras.

We have a very strong and good relationship with Petrobras.

In the current environment in Brazil, we are able to progress our business and get then the approvals, so we have also a very good relationship with the authorities.

In the case of Roncador, it's not that many months since we finalized that deal and started the bookings.

But that also means that, that was the opportunity for us to really be able to look into the books.

And from the point you -- to start looking at IRR opportunities, and we are in a very early phase of looking at those.

But we still believe that there is an opportunity and should be an opportunity to improve the recovery factor for that asset.

We will take our next question from Jason Kenney from Santander.

So I'm going to hop back over decades to when your company, indeed, many oil companies were happy to talk about return on capital employed.

And I'm just thinking if you would be feeling more confident about setting return on capital employed targets in your Capital Markets Day in February.

Obviously, you're enjoying the oil price rate at the moment, but your underlying capital discipline, obviously and we've heard about capital allocation just through this call and through this year.

What do you think is an acceptable through-the-cycle return on capital for a company of your size today?

Well, if I take you back to the CMU, we had a ROCE of 8% in 2017.

And we guided up to 12% in 2020 based on an oil price of $70 a barrel.

And on path to deliver 12% in 2020.

We sort of guided at 10% in 2018.

And we are on good path and comfortable as our ability to deliver on the 12% in 2020.

With that one, that's the final question that we're able to take today, the last one that we've had.

Thank you to everybody.

Always appreciate the calls and questions.

And as ever, please contact IR if there's any further questions or follow-ups.

I'd like to thank all the -- all my colleagues for joining us today.

And I remind you that the fourth quarter is on the 6th of February, and will be accompanied by our Capital Markets day in London, and we look forward to seeing you then.

Thanks, everybody.

Goodbye.

This concludes today's call.

Thank you for your participation.

You may now disconnect.