Equinor ASA (EQNR) 2018 Q2 法說會逐字稿

Ladies and gentlemen, good morning, and welcome to the Equinor Second Quarter 2018 Conference Call.

I -- well I know it's been an especially busy day for you all so we aim to be very efficient.

Our CFO, Hans Jakob Hegge will run through the -- our the results in just under 15 minutes, and we will open up for questions from the phones and we expect to complete the call within the hour.

I'm also joined on the call by Svein Skeie, Head of Performance Management; and Ørjan Kvelvane, Head of Accounting.

And with that, brief intro, let me pass straightaway to Hans Jakob.

Thank you, Peter, and good morning, everyone.

Today, I'm presenting Equinor's first quarterly results after our name change in May.

It's a solid set of numbers, and I am particularly pleased with good results and cash flow from operations, strong adjusted earnings after tax, record international production, and the value-enhancing transactions.

We presented at our Capital Markets Update as Statoil.

These results confirm the delivery as Equinor and there are no changes to our strategy and guidance.

Our IFRS net operating income is $3.8 billion before tax, this quarter, and adjusted earnings before tax was $4.3 billion.

Adjusted earnings after tax was a strong $1.7 billion, and this is after 165% year-on-year adjusting for Angolan profit oil benefit taken last year.

I will revert to these results again in a moment.

Equinor's activity level in the second quarter was high.

We are progressing a large portfolio development project, and I am pleased to confirm that we are delivering according to plans.

Aasta Hansteen, Oseberg Vestflanken, Peregrino Phase II and Mariner are examples of strong project execution.

And the biggest of them all, Johan Sverdrup is the one you can see on this picture, with the lifting in place of the bridge between the drilling platform and the riser platform.

Many of you visited the living quarters at the construction site last year, and now, more than 800 people are currently working offshore, getting the field ready for startup in 2019, at substantially lower cost than anyone thought was possible at PDO.

In our project pipeline, we already have Bay du Nord in Canada, Carcara and BMC-33 in Brazil, and Johan Castberg, Snorre Expansion and Troll Phase III on the NCS on the move.

In early July, we presented the Phase III development plan of the Troll field.

With more than $2 billion recoverable barrels, this project is among the most profitable and robust ever in the history of the company.

The Troll field has already generated a massive NOK 1400 billion in revenues, and we are now extending the field's lifetime beyond 2050 and expect to create even greater value going forward.

In addition to this on-schedule and on-cost project deliveries, we continued to build our project portfolio for the future during this quarter.

We closed the Roncador and Carcará transactions in Brazil and the North Platte acquisition in the Gulf of Mexico.

And we secured attractive new exploration acreage in Brazil, the U.K. and Norway.

The second quarter is characterized by solid results, solid cash flow from operations, high production at higher realized prices.

Our after-tax result is especially strong this quarter with major contributions from E&P International.

And for the second quarter, the board has decided to maintain the quarterly dividend at $0.23 per share.

The safety of our people and the integrity of our operations is and will always be our top priority.

The group's 12-month period incident frequency was 0.5 per million hours worked.

This is at the same level as in the first quarter 2018, it was our strongest SIF to date.

The SIF for the same quarter last year was 0.7.

Now onto the financial results in more detail.

We delivered adjusted earnings before tax of $4.3 billion in the quarter, up $1.3 billion or 43% compared to the same period last year.

High production from ramp-up of new fields and new wells, and higher realized oil and gas prices contributed to the strong results.

Exploration & production International's contribution is especially strong this quarter.

Our after-tax result is very close to the record from the first quarter 2012, and the oil price was above $110 per barrel.

Realized liquids price for the group in the second quarter was $65.08 per barrel, an increase of 48% compared to this same period last year.

Realized European gas prices were up 28%, while U.S. gas prices were down 12%.

The IFRS result was $3.8 billion in the quarter influenced by net impairment reversals and derivatives.

Net reversals were $0.3 billion.

In the quarter, we report impairments of around of $760 million for U.S. onshore, largely caused by a change in our long-term oil price assumption and a change in valuation methodology for Eagle Ford.

Let me remind you that we, in the fourth quarter last year, had reversals of $1.3 billion, for our U.S. onshore activity.

The low tax rate in the quarter of 60.7%, resulted from strong earnings in areas with low or no tax.

The low effective tax rate in the International segment reflects structural composition of the earnings in the quarter, from areas with low on no tax.

There were no one-offs.

Let's now move on to look at the segments.

Exploration & Production Norway delivered adjusted earnings before tax of $3.1 billion, an increase of 58% from the same period last year.

High production, higher realized prices resulting in higher margins were the key drivers.

In the quarter, 10 turnarounds were completed.

We experienced some increase in reported costs, due to new fields coming on stream in line with what we communicated at our CMU.

In addition, we had some quarter-specific costs related to higher seasonal maintenance, pensions and some unplanned losses at a couple of our fields.

We continue our improvement work and maintain a strong cost focus across the organization.

Achieved liquids price for 50% higher and in this same period last year.

Exploration and production international delivered very strong adjusted earnings for more than $1 billion before tax, up 18% compared to this same period last year.

And let me remind you that we had last year impacted in our results for the second quarter an improved effect of $750 million due to a one-off effect related to Angola.

Adjusted for this effect resulted 8 times higher in the same quarter last year.

The production in the quarter was record high, with an underlying growth of 11% year-on-year.

And at the same time, the underlying OpEx SG&A cost per barrel was stable.

The cash flow after tax from our International business was very strong this quarter, at $30 per barrel, which is higher than what we saw from the NCS.

Then to our MMP segment, which delivered a pretax result of $302 million compared to $280 million, sorry, $292 million in the same period last year.

We achieved solid results from LNG and products trading, while the natural gas trading delivered somewhat weaker contribution.

Then to the production.

Equinor's production during the quarter was 2,028,000 barrels per day.

This is an increase of 32,000 barrels per day corresponding to an underlying increase of around 2% year-on-year.

Our international production was the highest ever, driven by strong production growth, mainly onshore but also offshore U.S. In addition, the Roncador field in Brazil, started contributing from June 15th.

Production ramp-up of new NCS fields like Gina Krog and Byrding, new wells and higher flex gas production volumes also contributed positively.

In the next quarter, we expect higher impact of maintenance on group level, with higher turnaround activity in our international operations.

The planned impact is estimated to be around 80,000 barrels per day.

Year-to-date, we deliver a strong cash flow from operations of more than $13 billion, and our net free cash flow of $0.9 billion, after the acquisitions of Martin Linge and Roncador and the Carcara farm down.

In the quarter, our net debt ratio grew by 2.1 percentage points to 27.2%.

Without the above-mentioned transactions and the change in our working capital this quarter caused by liquid inventory growth, the net debt ratio would have been 3 percentage points lower.

Year-to-date organic CapEx is $4.6 billion.

To sum up, we are on track to deliver on the targets we presented at our Capital Markets Update in February.

We maintain our CapEx guiding for the full year at around $11 billion, and our expected exploration spend this year is maintained at around $1.5 billion.

Expected production growth is still 1% to 2%, and the expected annual production growth during 2017 through 2020 is unchanged at 3% to 4%.

Before I ask Peter to start the Q&A, as you may know, I am moving to the U.S. to take all the responsibility of our global onshore assets.

Let me use the opportunity to thank everyone with whom I've met and spoken to during this busy, interesting and I believe quite successful period.

I want to wish my colleague, Lars Christian Bacher, every success as CFO starting next month.

It's been a great pleasure.

Hans Jakob was spot on in delivering again 15 minutes to the dot.

Now let's move to the Q&A, and I pass over to the operator, who will run the polling.

Thank you very much.

(Operator Instructions) Our first question is from Oswald Clint of Bernstein.

Peter and Hans Jakob.

Maybe -- I just wanted to clarify your question -- your comments there.

You spoke about a little bit of higher unit OpEx in the NCS versus the CMD, kind of ambitions, but alluding to the fact that it is pretty much quarter and field-specific in the second quarter.

Could you just kind of reiterate that point and why, whereas the second half of the year we should expect costs to come back in line with your 2018 forecast, please?

And then secondly, maybe going over to the U.S. onshore, the business you're going to start running.

I'm just looking international gas, and it looks like Marcellus gas is up strongly -- really strongly, 36% 37% despite gas prices actually falling year-over-year and -- through 2018, just wondering is that still because the Marcellus is so low cost and so profitable, you can still drive up volumes there and still deliver underlying profitability there?

That's the second question.

Thank you, Oswald, for those questions.

So first on the NCS cost.

As we said, we will see some higher costs when new fields are brought on stream like Gina Korg and Byrding, remember costs are still very close to a 10 year low after several measures taken over the years.

As you mentioned, there are some quarterly specifics related to maintenance, pension is a one-off, and also some additional costs on unplanned losses on some fields.

But we continue with our continuous improvement and strong efforts on cost and capital discipline.

On the U.S. onshore, you're absolutely right, it's a strong production growth of 34% overall from the U.S. The onshore is accordingly growing in the gas between Utica and Marcellus, new wells on stream and a record high 370,000 barrels overall U.S. production.

So this is in line with what we said at the CMU and it's a strong contribution from this, and it contributes to the strong close to record high international results.

(Operator Instructions) Our next question comes from Thomas Adolff of Credit Suisse.

I've got two fairly straightforward questions, please.

Firstly, just to clarify on -- your comment on the underlying decline rate.

If I'm not mistaken you said it was 2% or thereabouts, presumably that's kind of better than your base case.

Your base case, I think, is around 4%, 5% per annum.

So I was wondering what's driving that since production efficiency is quite high already on the NCS.

Second question just specifically to Europe gas demand, can you say something on gas demand including reloads during the second quarter and perhaps linked to that why European trading was a bit softer this time around?

So thank you, Thomas, for those questions.

On the decline rate, it's 5%, it's unchanged.

I said the production growth for this year is 1% to 2% and maintained so that's hopefully, clarifying that one.

On the European gas, you have seen hot weather increasing cooling demand reducing availability of hydro as an effect of the weather.

Going forward, we could see some pressure since the European gas prices gained through the second quarter, and the pressure from high crude prices, relatively low LNG volumes and some curtailments both from the U.K. and the NCS.

So storage inductions have been relatively strong, significantly reducing Europe's deficit to the 2017 levels.

So going forward, some pressure on European gas we expect.

Our next question comes from Biraj Borkhataria of Royal Bank of Canada.

I have two, please.

The first one is just following up on comments on the Eagle Ford.

You mentioned the impairment was driven by a lower long-term oil price assumption, but also change in valuation methodology for the Eagle Ford.

Could you just provide some more color on what exactly has changed there?

And also as a follow-up to that, could you give us an update if there is any on the well spacing issue?

So that would be the first one.

Second question is very simply for you is looking to the second half of the year, could you just remind us what your expectations were for the Norwegian cash tax installments?

Thank you Biraj.

On Eagle Ford, in the second quarter, first overall, in the U.S. we both have impairments and reversals overall for the U.S. it's $300 million net, $760 million impairments of which $240 million of them is exploration expenses.

On the Eagle Ford, there is a small change in the long-term price but also our business plan updated some deferred production from Eagle Ford due to the change of the well spacing.

We have, in the past, explained that we did 500 feet well spacing along with other players in the industry and narrowed it down to the 200.

We did campaign on 80 wells at 200, and that didn't turn out to be successful so we are assessing it.

And while the recent drilled wells show improved production performance, the results are not mature enough to be taken into consideration for the impairment evaluation.

And more time is needed realizing the production performance over a longer period of time, with more wells.

And this is impacting the production of -- the long-term production with some deferred barrels.

The second element of changing the evaluation methodology, Ørjan, you want to comment on that?

I can do that.

So in third quarter we used the fair value so that means that we got input from external market, and we are required to use the higher of the external market and our own assumptions.

What we see from the market is an indication of that not being present any longer and then we went back to our own assumptions now in second quarter.

So your second question was related to NCS tax installments and Svein, do you want to cover that one?

Yes, I can cover that one.

As you know, the Norwegian taxes are paid half the year and they occur, and half the year after.

So in the first half, we have paid taxes then from last year.

First for August, we will have the first installment on the 2018 taxes, that is estimated to be around NOK 14 billion.

We will do an assessment for the 2 remaining part of it, but the first one is NOK 14 billion, around NOK 14 billion.

There will be a recalculation also in September/October, related to the 2 remaining NCS installments.

Our next question comes from Alastair Syme of Citi.

I also had a question on the impairments.

You mentioned change in the long-term oil price view.

I just wanted to clarify if that's a corporate change or is that just applying to the U.S. business?

And secondly, I just wanted to ask about Roncador, you mentioned completed on first week of June, but I believe the deal was backdated to the 1st of January so I just wanted to confirm that that backdating is flowing through the working capital and the cash flow?

So on the impairments, it's a corporate change.

Roncador.

Svein, do you want to cover the question related to January?

On Roncador the effective date was done 1st of January in the settlement, but we then did the final payments on it and then we took into account the value of the production from 1st of January up until the closing date.

So that has then been taken into account, reducing the payment somewhat.

Okay.

So it's a reduction in payment rather than a -- within the working capital items.

Is that right?

Is that what appears in the cash flow?

Yes, the (inaudible) that you paid a little bit less on the CapEx.

So just back to the oil price.

Are you able to say what have you long-term oil price view is?

On the oil price, it is disclosed in Note 6 in the MD&A.

It is mainly then up a little bit on the short term, and then 2022 it's $75, in 2018 dollars and $80 in 2030 in 2018 dollars, which earlier was measured as a basis year 2016, that's the main change.

Our next question comes from Mehdi Ennebati of Societe Generale.

First question regarding the U.S. production, we can see that onshore our liquids production started going up with increasing number of rigs currently in use.

Can you tell us if you intend to keep increasing the number of rigs if the WTI price remained around the $70 in H2, and also for 2019?

And second question, regarding your production efficiency in Norway.

You highlighted the last quarter that you were reaching record high levels, above 90%, and you intended to stay around those levels.

But can you please tell us what was the production efficiency level in 2Q, given it went slightly down?

And do you think that you will be able to reverse the situation in second half 2018, despite you are increasing the impact from turnaround.

Thank you Mehdi, let me start off with the last one - on production efficiency.

We have had an impressive performance on many NCS installations.

Also this year, in the first half we have more than a dozen installations with regularity well above 90%.

In this quarter, we have somewhat higher unplanned losses due to events on a couple of our installations in April/May.

Those issues have been solved.

It's our deferred volumes, and we think we can achieve also high regularity going forward.

To your first question on the U.S. onshore production and activity level, we have high activity level in the U.S., continue to look closely at economics before we raise the activity.

We have 4 operated rigs and 1 completion crew in each basin, and in this quarter, the production increased by 34%, and overall, it's expected to increase slightly in 2018 versus '17 with more completions.

Our next question comes from Anne Gjøen of Handelsbanken.

I have a question related to maintenance activity.

You're guiding somewhat higher maintenance activity third quarter, in particular.

Will this have kind of an impact when it comes to cost level due to a different product mix?

Or will it impact tax to some extent if it's kind of different product country mix?

Our where is the maintenance activity mainly taking place in third quarter?

The maintenance impact was clearly visible as guided on the NCS this quarter.

The coming quarter there will be more so in the international portfolio.

We are expecting 80,000 barrels impact on the production and we do not have any guidance on the change in the product mix as such.

Our next question comes from Rob Pulleyn of Morgan Stanley.

Just shifting gears slightly.

Can I ask about some of your maybe further out projects, including in Brazil where, I believe, there are drilling plans on greater Carcará, and when we should expect an update in terms of newsflow around that development?

And secondly, if I can just clarify on the maintenance from the Norwegian side that those higher maintenance costs or maintenance-related costs in 2Q will not be spilling over into 3Q, as you mentioned there will be international maintenance but that's a different issue.

Yes.

Well the short answer to the second question is that yes, the seasonal one-offs and related to the maintenance, you should not expect to see it in the coming quarter.

On the first one, we have an exciting well in Brazil called Guanxuma, it is in the BMS-8 license with the Carcará discovery.

It's an ongoing operation, we had a discovery but we have not clarified yet the size of the discovery or the commerciality so this is something we will have to revert to.

But the initial results are promising.

Our next question comes from Christyan Malek of JPMorgan.

Just one question on this underlying cash flow.

Just so year-on-year looking at your CFO from Ops, I mean, I understand the delta on taxes paid, but with the improvement in the oil price, can you just help me understand to the extent of which, basically your cash flow from ops will come down, which links into the underlying cash flow for the quarter.

Why is it that you're not getting as much capture on the cash flow from ops relative to where the oil price is year-on-year and then also sequentially?

Just help me understand where is the cash flow leakage here?

And if you just walk me through the moving parts, please.

So on the cash flow from operating activities year-to-date is very strong, about $13 billion, $10 billion after tax.

This quarter from operations, it's $1 million lower than the first quarter so we ended up $6.1 billion.

This is mainly due to the reduced volumes sold in the second quarter compared to the first quarter.

It's partly offset by increased prices.

We also have the derivative effects related to commodity derivatives, a loss of $455 million in this quarter compared to a loss of $163 million in the first quarter.

So then we have the taxes paid, they increased by $1.2 million -- $1.2 billion and from the $1.1 billion that we had, so we are up to $2.3 billion on taxes due to the 2 tax payments in the second quarter, compared to only one in the first quarter.

Yes, I understand that but on a year-over-year basis, I mean, your cash flow from ops have gone from $4 billion to $3 billion.

And so I'm just trying to understand on the context of -- an oil price is up significantly.

I mean, put another way, is it basically your high oil prices are coming with more cash taxes, more working instruments, essentially, the capture on the oil price is not as good as you thought it would be?

I was just trying to understand on a year-over-year improvement rather than sequentially what the underlying cash flow efficacy is doing?

And just with the high oil price, trying to square why it's not better.

No.

There is no change in any guidance.

We are on track with the breakeven of $50 billion and the $12 billion free cash flow as we guided on, so no change to that.

Our next question comes from Rafal Gutaj of Bank of America, Merrill Lynch.

Just coming back to the maintenance in Norway that you highlighted, I just -- the fields that -- or specifically the drivers behind the I guess disappointing performance in 2Q.

And I wanted know if it was more logistics related or operational issues that led to the slower than expected ramp-up back to full pelt over there.

And then secondly, you mentioned your associated income that weakness was partly driven by, I guess, Lundin Petroleum, I just wanted to understand whether that was owing to operational or fiscal issues?

On maintenance in Norway, we had seasonally high maintenance activity, some additional costs related to that.

The turnarounds impacted the overall production and this is normal for the second quarter, but the impact was larger than in 2017, and on the regularity the production efficiency, it was not on par with the very high results obtained in the previous quarters.

As I explained, we had more unplanned losses, this added to some of the costs, but also the lower production.

So costs per barrel went up relative to the high performance we have had, but it's 2 fields.

It's -- back in time; the issues have been solved so the decline is expected, and we had the contribution from the new fields coming onstream.

So overall, we should be fine I think, going forward on the maintenance part.

The associated income of Lundin is FX impact and I would just refer to the Lundin results.

Our next question comes from Theepan Jothilingam of Exane BNP.

It's Theepan.

I had two questions actually.

Just one follow-up on -- could you just talk about these oil prices or macro assumptions you made for the guidance on the NOK 14 billion for the first tax installment.

And then secondly on CapEx, I know typically you are, sort of, second half loaded in terms of annual CapEx.

But I was wondering how much contingency is there in the $11 billion for 2018?

Okay.

Theepan, I'll do the CapEx and I'll ask Svein to cover the first installment.

On the CapEx, $4.6 billion year-to-date high activity level, higher in the second quarter than in the first.

Going forward, we have very good progress on our projects.

And the activity related to the startup of Aasta Hansteen, the completion of Martin Linge, Johan Sverdrup Phase II to -- will be sanctioned later this year, we have delivered the PDO for Johan Castberg, Snorre Expansion, so we expect higher activity.

We also have Peregrino Phase II in Brazil, so there will be higher activity in the second half.

Then to you Svein?

Regarding the basis for the calculation of the taxes, which then resulted in the NOK 14 billion and the first installment.

What we do then is that -- yes, in the beginning of June, we take the realized prices that we have done so far until May into context.

Then we look at the outlook for the remaining of year, and looking at the forward at that point in time and then taking into account the production and the investment levels.

So that's what we have used so we are into the 70s.

Our next question comes from Lydia Rainforth of Barclays.

Just a big picture question for me, I guess.

Just in terms of when you reflect on your time as CFO, what are the things that you are most proud of achieving?

And then what do you think is the biggest challenge for your successor coming into that role?

Thank you Lydia.

So it's been great to be a part of a team that has contributed to a significantly stronger portfolio through the value-enhancing transactions.

The countercyclical moves are selling at higher prices in Norway, buying at lower prices both in Norway and international, and the breakeven of our next-generation portfolio of USD 21 per barrel and $4.5 billion lower costs per year.

And also, I think, the share price development over the last years has been okay.

And I think looking at the biggest challenge for Lars Christian -- it's more related to what to do with all the strong cash flow going forward.

Our next question comes from Rob West of Redburn.

I'd like to go to 2 areas.

The first one is on the tax losses that you're getting into in your International business.

And I'm guessing that's mostly the U.S. where you have unrecognized losses and you're realizing those are boosting your cash flow per barrel.

Is there anywhere else in the international business where you have unrecognized tax losses that we should be -- be flowing through?

And then what would make you shift those unrecognized losses to actual tax assets?

So that's the first question.

And the second one is on Oseberg, which I asked about last quarter, but I'd like to go back there.

Is performance in the first half of the year of Oseberg where you wanted it to be?

And can you comment on some of the issues on fields flowing into the Sture terminal?

Thank you Rob.

Oseberg is a fantastic installation in the organization and has performed very well for a long period of time.

This quarter it's slightly lower on the regularity, but they will be back.

On the tax losses, there are more than the U.S., Ireland, it's -- an example, there are also some deferred tax losses in Brazil, and we have Canada on the list.

(Operator Instructions) Our next question comes from John Olaisen of ABG.

When I look back to the Capital Markets Update a bit earlier this year, you guided on average CapEx of USD 11 billion in '18, '19 and '20.

Since then you've done a number of rather big transactions both in Brazil, the U.S., Gulf of Mexico, Martin Linge, et cetera, et cetera.

I was just wondering over those next 3 years, does -- that CapEx, will that be influenced by these acquisitions, i.e.

will it be higher due to these acquisitions over the medium-term in the next 2 to 3 years CapEx?

Thank you John.

No, there is no change in the guidance on CapEx.

You're absolutely right.

You mentioned several, what we call, value-enhancing transactions.

These are opportunity driven.

We think they make good sense in a long-term perspective, and we will continue to grasp these opportunities as they appear, but there is no change in the CapEx side.

So the CapEx related to the acquisitions is included in the USD 11 billion guidance?

Yes.

And then may I ask how many more acquisitions can you do before the CapEx -- yes, before the CapEx is influenced for the next couple of years?

Well, organic CapEx sums are $11 billion, it's including those transactions.

So organic includes acquisitions nonorganic?

It's confusing.

No.

Our guidance on the nonorganic is slightly higher.

Okay.

So total CapEx will be higher than $11 billion.

Do I understand that?

Let's be clear.

We get -- we provided guidance on organic CapEx, we said it would be around $11 billion in 2018.

And on average, $11 billion a year, '18 to '20.

Okay.

We also said that we would be opportunistic in terms of anything that came up as we have been in the inorganic and that will be one of the ways that we might use the additional cash flow.

So that's not included in the $11 billion, it will be on top and opportunistic.

But the CapEx that we have on some of those acquisitions, for example, Martin Linge, is included in the $11 billion guidance.

Our next question comes from Kim Fustier of HSBC.

I just had one question.

I wondered if oil prices above $70 are starting to unlock incremental investment at the margin, for example, things like infill drilling on the NCS.

So do you find that, for example, within your $11 billion organic CapEx budget you've got good execution on the big projects so you're sort of running a little bit below that in terms of run rate.

But do you think you'll be able to do more than you expected initially on things like infill drilling?

Any color you are able to draw will be helpful?

Thank you for the question.

It has been very rewarding to see the drilling and well performance over the last year.

More efficient drilling, 70% more meters per today, 40% less time and 35% less cost per well, so that's been an impressive performance.

And that qualifies for -- we get more for less and we have done more wells for these benefits and including infill drilling.

So ambition level on IRR is very high.

We are already at a world record on some of our fields, and more than 3,000 engineers work on moving resource classes getting ready for this additional drilling.

So this is part of the ambition level or EOR, and part of the efficiency program that we are going through.

It appears that there are no further questions at this time.

I'd like to turn the conference back to your host for any additional or closing remarks.

Thank you.

Yes.

No more questions.

I'd just like to thank everybody for participating.

I know, it's a busy day.

As always, if there are any follow-up questions, don't hesitate to contact us in Investor Relations.

I'd also like to thank Hans Jakob for his time as CFO and wish him the very best of luck as he moves over to the states to welcome Lars Christian.

And with that, I'll bring the call to a close.

Thank you very much indeed.