Equinor ASA (EQNR) 2019 Q1 法說會逐字稿

I know it's been a busy week for reporting, so we'll get straight to business.

On the call today, we've got Lars Christian Bacher, CFO, who will run through the quarter's results and then we'll open up for Q&A.

Also, with us are Svein Skeie, Head of Performance Management; and Ørjan Kvelvane, Head of Accounting.

With that, I'll pass straight away to Lars Christian.

Thank you.

Thank you, Peter and good morning, everybody, and thank you for joining us on this first quarter earnings call.

Today, Equinor presents solid results across all segments.

Adjusted earnings after tax were up year-on-year despite lower commodity prices in the quarter.

Oil price increased gradually through the quarter from below $55 per barrel at the end of 2018 to around $70 at the end of first quarter, resulting in an average Brent oil price of $63.

For the first 3 months of 2019, we report a strong cash flow from operating activities before tax of $6.5 billion and we reduced the net debt ratio to 19.4%.

We continue to deliver strong results because we are realizing on the improvements we have made.

Volatility and commodity prices is a clear confirmation of the need for continued cost and capital discipline for operators as well as suppliers.

In Equinor, we continue to strive for efficiency in everything we do and use lean principles as our way of working.

This is what we mean by an improvement culture.

Given our improvements and solid results, the Equinor Board has decided a first quarter dividend of $0.26 per share, an increase of 13% from the same quarter of last year.

If I move onto the quarterly results in more detail, allow me to point out some of the good industrial progress we have achieved in the first quarter.

One, we closed the transaction for Rosebank, Danske commodities, and the new wind licence offshore East Coast U.S. Two, we secured new prospective exploration acreage in Norway, Gulf of Mexico and Argentina.

Three, we formally opened Arkona, the German offshore wind park.

And four, we are steadily progressing the development on new projects on the NCS and internationally, which we expect to deliver around 3% average annual production growth from 2019 to 2025.

Johan Sverdrup Phase 1 is well on track to start up in November this year and expecting to reach a plateau of around 440,000 barrels a day within 12 months from starting up.

The full field Johan Sverdrup can produce 660,000 barrels per day at plateau with a very low unit production cost of around $2, carbon emissions below 1 kilogram per barrel and a breakeven oil price below $20 per barrel.

Equinor currently has 24 projects in execution, and we are pleased with our overall progress.

The safety of our people and the integrity of operations are, and will always be, of a top priority.

The group maintained its serious incident frequency level over the last 12 months at 0.5 per million hours worked.

Our strong safety focus continues with undiminished strength to further improve our safety performance.

Management visibility and setting clear expectations are key success factors.

Now to the financial results.

And as a reminder, this is the first quarter reporting on IFRS 16 leases and we have chosen to include these changes in the segment Other to provide clarity.

That means that reporting of operating segments is not impacted and therefore, fully comparable to previous quarters.

Now let me walk you through the main effects of this change.

A reported lease liability of $4.2 billion is now reflected in the balance sheet with increased net debt.

In addition, we continue to report on adjusted net debt ratio comparable to previous reporting.

The impact on equity and net income is insignificant.

Operating costs has decreased by $100 million, depreciation increased by $150 million and free cash flow improved by $250 million.

Moving on.

We delivered adjusted earnings before tax of $4.2 billion this quarter, down from $4.4 billion in the same period last year.

The IFRS net operating income in the first quarter was $4.7 billion.

Our financial results were impacted by the low average prices.

At the same time, we delivered solid operational performance across all segments and maintained high production.

Realized liquid price in the first quarter was $55.8 per barrel, a reduction of 7% from the first quarter of last year.

Realized European gas prices were at the same level as in the first quarter last year, while U.S. gas prices were down around 10%.

In addition, refinery margins were down more than 28%.

After tax adjusted earnings were $1.54 billion in the quarter, slightly up from $1.47 billion in the same quarter last year.

For the group, tax on adjusted earnings in the quarter was 63%, and this is due to strong earnings in regimes with low taxes.

Our international segment had a 25% tax rate, including solid results from our U.S. activities.

As expected, new fields brought onstream increased operating costs in the quarter, while increased reserves on several fields led to reduced depreciation rates.

And now, a short review of each reporting segments.

E&P Norway delivered adjusted earnings before tax of $3.2 billion, down from $3.4 billion in the same period last year.

The small reduction is mainly due to lower realized liquid prices and lower production.

Production in the quarter was 3% lower than in the same period last year, largely due to expected natural decline and operational challenges on Aasta Hansteen, Snorre and some partner operated fields, partly offset by new production from new wells and new fields.

Underlying OpEx and SG&A costs increased somewhat in the quarter mainly due to start-up costs for new fields.

Depreciation per barrel was down 11% in underlying currency due to increases in reserves and production with no depreciation effect.

E&P International delivered strong adjusted earnings before tax of $0.7 billion, an increase of 4% from $0.6 billion in the same period last year.

International equity production came in at 841,000 barrels per day, near a record-high.

This corresponds to 5% growth and compared to the same quarter of last year.

OpEx and SG&A were somewhat up mainly due to new fields and increased cost related to preparation for operation.

The achieved cash flow per barrel after tax was around $25, which is higher than on the NCS.

In the quarter, E&P International delivered $0.5 billion in adjusted earnings after tax, which is up 17%.

Our MMP segment delivered adjusted earnings of $359 million compared to $454 million in the same period last year.

In the quarter, MMP took a one-off provision linked to historical pricing for third party volumes.

Strong liquids trading and European gas sales contribute to an MMP result well within our guiding of $250 million to $500 million per quarter.

Equinor's production in the first quarter was 2,178,000 barrels per day, on par with the same period last year.

Expected natural decline of 5% was offset by new fields; among them, Roncador in Brazil and fields offshore in North America and new wells brought onstream on the NCS and in U.S. onshore.

For the first 3 months of 2019, we report a strong cash flow from operating activities before tax of $6.5 billion, and a net free cash flow of $1.8 billion without any proceeds from divestments.

The net debt ratio was reduced by 2.8 percentage points in the quarter to 19.4%.

The results and the cash flow was the main driver for the reduced net debt ratio.

Organic CapEx in the quarter was $2.2 billion, and we expect higher activity level and spending for the next quarters.

The net debt ratio was also positively impacted by not declaring dividend and thereby reducing equity as we do in the fourth quarter.

Including these liabilities, the net debt ratio was 25.8%.

In addition, we closed value-generating transactions such as the Rosebank acquisition in the U.K., Danske Commodities and the new offshore wind license in the U.S.

During the first quarter, we paid around $0.8 billion in dividends and around $1.4 billion in tax, including the first of 6 NCS tax payments.

To conclude, we are on track and we have no changes to our guiding for 2019.

We maintain our organic CapEx around $11 billion and our exploration activity of around $1.7 billion.

We expect 2019 production around the same level as in 2018 and an annual average production growth of around 3% from 2019 to 2025.

And with that, I'm pleased to open up for questions and hand over back to you, Peter.

Thank you, Lars Christian.

With that, I'll ask the operator to remind people of the procedure for calling in and then we'll go ahead.

We have around 45 minutes for questions.

Thank you.

(Operator Instructions) We'll take our first question from the line of Oswald Clint from Bernstein.

Lars Christian.

2 questions, please.

The first one just on international volumes, up strongly.

Obviously, Roncador is quite a bit of that, but I'm zooming in on your unconventional business, which I think has just hit a kind of volume peak, whether I look at gas or liquids.

So I guess with price realizations and pipeline capacity issues and some of the parent-child issues you've said you've had yourself within the Eagle Ford, what's happening to really drive that part of the volume pie up to these record highs?

And is that tracking your plan or is it coming a bit better than your production plan?

That's the first question, please.

And then secondly, I was curious looking at Orsted's numbers in Q1, seeing around $400 million of EBIT for offshore wind.

I mean, I know they're 4 or 5x bigger than wind but I was wondering, is there any positive contribution yet from your wind portfolio coming up in the corporate segment yet?

Well, thank you for your questions.

First on the volumes and international volumes.

You are right, Roncador, that contributes this quarter.

That was closed midway last year.

And when it comes to onshore activities and production in U.S. it is mainly related to gas.

And what we see is, in all these cases, it's more or less according to plan.

On the renewable side, there are contributions, positive for the quarter, but not big numbers given the size of our business.

We'll take our next question from the line of Jason Gammel from Jefferies.

Appreciate the commentary around Johan Sverdrup but I was hoping you could maybe just address what are the critical path items in front of you to be able to meet that November 1 production start?

And then maybe also just a second one.

Are we seeing any changes to the budget yet?

Is everything going according to schedule?

Or have you even possibly achieved any further cost savings?

Well, on Johan Sverdrup, I think perhaps the best way of answering your question is to rewind -- go back in time a couple of months and say what is on critical line as a sort of what we need definitely to be able to achieve, to create real comfort around that startup date, beginning of November.

And those activities were some of the heavy lift operations that we have finalized.

So that was on a critical part.

What is remaining then of work related to Johan Sverdrup is a lot of work still to be done but not sort of really big activities that if not being sort of delivered according to schedule, that could threaten that startup date.

But still, beginning in November is our best estimates.

On the budget for Johan Sverdrup and the other projects, 24 projects in our project portfolio in execution, and we are happy with how that portfolio is progressing.

As we said at the Capital Markets Day, we have placed contracts of $100 billion that we are securing more or less, a lot of what we need to do both on the projects side and maintenance side over the next 3 years.

So we are guiding of $11 billion for this full year.

That is because despite some $2.2 billion in CapEx, first quarter, we see and expect higher activity levels over the next couple of quarters, including some onshore wells in the U.S. that will come in.

So this is the best sort of bottom-up estimate that we are having.

And then just also to remind you that when we're saying around $11 billion, it is around $11 billion.

It has always been around $11 billion.

We'll take our next question from the line of Thomas Adolff, Crédit Suisse.

Two questions from me, please.

I think you mentioned Tanzania LNG earlier today, and I was just wondering whether -- what is going on there and whether this project has become a live project?

And then you also secondly mentioned that you are also looking at other LNG opportunities aside from Tanzania LNG.

So would you say LNG is a gap in your portfolio that you want to fill?

And if so, aside from Qatar, anything else you're looking for?

On Tanzania LNG, a very low burn rate related to that project.

We matured it sufficiently, so that we have a good understanding and overview of what that project will look like and some early cost estimates, even though that there is sort of a high case and a low case since this is very early in the project design phase.

And the reason for that is that we needed that to have a solid basis for engaging and having the discussion around establishing the host government agreement.

What we are seeing now is that there is progress, they are ready, our counterpart in the Tanzania government, to engage and start the negotiations.

And we expect those to take time, and what I mean by time is I don't have any better estimates and that is partly based on the learning and so far, operating in that country.

On other LNG opportunities.

First, we have a stellar quality project portfolio and execution and we have a very, very, very good non-sanctioned project portfolio with very good economics whether you look at it from a breakeven point of view or a returns point of view.

So we have a resource base of 20 billion barrels and are not distressed.

We don't have to buy stuff.

Of course, as a company operating in oil and gas, you need to discover or add volumes to sustain that production and production growth, but we have time to be selective and work with different alternatives.

LNG is one sort of alley that we are pursuing and looking at, that we can get more LNG-operated volumes into our portfolio, whether that is operated by us or non-operator.

But it has to make sense from an economic returns point of view.

And yes, we have different alternatives and screened several projects.

But so far, have not been able to make it work from a returns point of view.

And, thereby we are picky and saying that we wait and look for more alternatives.

And whether that is in LNG or other projects, that remains to be seen.

But I think the key takeaway is that whatever we do on acquisitions, it has to make sense.

And by that, I mean it has to fit nicely into our projects from a returns point of view, create value for the shareholders.

We'll take our next question from the line of Lydia Rainforth from Barclays.

Two questions from me as well.

The first one on the gas market and the Equinor approach contracting.

At the gas seminar in February, we talked about the idea that over time Equinor would want to transition to shorter term contracts rather than the mix of long-term and short-term contracts that you currently have.

Can you talk us through whether that is still the case given where the gas pricing is at the moment?

And just any reflections on the gas pricing as a whole would be helpful.

And then the second question was just to come back to Oswald's point on the renewables side, that you are investing in renewables, Scatec Solar and organic offshore wind there is a value to those, but it's actually very difficult for us to assess externally.

So at what point do you think it becomes scalable enough to give us more disclosure on that?

Well, on the gas market, as you correctly point to, we have announced that the day ahead, month ahead, the season ahead and year ahead, we are moving away from, and it will take time to get more into sort of more of the volumes being short-term pricing.

And currently, we see this quarter than that the volumes that we saw last year on season ahead, the year ahead prices and these prices had been higher than present.

So they're in the money and that contributes nicely.

And that's why we are saying that realized gas prices at this quarter for European gas is at par with what we saw last year but we are still transitioning into the new principle as we announced earlier this year.

On the renewable side, in many ways it's the same for oil and gas.

I mean it has to bring value.

Some of our project that are in operations, we have internal rate of return, 9% to 10% on an asset basis, that is not on a leverage based, but on an asset based return.

And we have also said that we expect the CapEx spending to increase going forward, but as it looks, it's going to be heavily back-end loaded given that the limited opportunities of good enough projects from a return basis.

So whether this -- when this will be scalable is highly dependent on us succeeding in finding projects that makes sense from a returns point of view.

We'll take our next question from the line of Teodor Nilsen from SB1 Market.

First, a question on net debt and capital employed ratio, which now has come significantly down on the past few quarters.

I guess, your guidance from previous, still valid that you're looking for keeping net debt to capital employed ratio about 15%.

So my question is, what is the exact order or what would be the pecking order of use of cash flow (inaudible) or increased investments?

And my second question is actually related to another question that's been today on Sverdrup and the ramp-up profile.

How should we expect ramp-up of 440,000 bbls in production to happen?

Would that be the first month of production or do you expect it to take a year or so?

Well, the ramp-up for Phase I, Johan Sverdrup, we are saying it will take within 12 months from production start-up to reach plateau.

Then, on net debt ratio, we are very happy to see this has been reduced from 22.2% to 19.4% during the quarter.

We have guided on we want the net debt ratio to be between 15% and 30%.

We can live with a net debt ratio about 30% for a period of time as well as below 15% for a period of time.

Having that said, we are also very mindful of a very low net debt ratio.

That is a question of how efficient your balance sheet is.

So looking at the numbers, before I go into how to prioritize free cash flow or the cash flow.

Yes, we have seen a 2.8% reduction in the net debt ratio during the quarter.

But then, be mindful that we did not declare dividend this quarter as well as we had $2.2 billion in CapEx -- organic CapEx booked for the quarter and expect in both cases those will kick in with a higher spending over the next couple of quarters.

So by that, I'm trying to say it's not automatic that you can take another 2.8% out of the 19.4% and so on going forward.

So we are trying to say that we are a little bit cautious when it comes to how you look at the development on net debt ratio going forward.

Can it go down?

Yes, with good pricing -- commodity pricing, definitely.

But there are elements that will mean that it's going to be around this level going forward.

Then, on how to prioritize your capital distribution.

One, we still want to strengthen our balance sheet, and we also are saying that we have a very healthy, profitable, strong project portfolio that we would like to invest in and with an internal rate of return of more than 25%, which is very, very good.

And then, cash dividend is our preferred means of distributing cash to our shareholders, and be mindful of the 13% increase in dividend that has now been decided by the Board yesterday for first quarter this year compared to first quarter last year.

And then going forward, we have options like share buyback that is in the toolbox, and we have options like we're doing M&A deals but be mindful, as I said, that it has to make sense from a returns point of view.

And then thirdly, it is very dependent on the commodity prices at this point of time going forward.

You have seen and we have seen and everybody have seen that there are still very volatile commodity prices and that is important to factor in when it comes to how you maneuver to ensure flexibility and robustness.

So that, I think, is the way I would like to put it.

On net debt ratio, anything else to add, Ørjan or Svein?

I would just add that we are also exposed to currency movements, that can hit kind of equity, so that can also impact either positive or negative on the quarter.

We'll take our next question from the line of Biraj Borkhataria from RBC.

Just one follow-up on European gas.

With prices being pretty weak recently, I was a bit surprised the see Troll running at full capacity.

I was wondering if you can talk about whether you are considering lowering your productional gas -- your flex gas down a bit, especially in the summer months?

And then second question is on Danske Commodities, which you consolidated in Q1 into the midstream LNG division.

I'm assuming that has a positive EBIT contribution, but you didn't move your range and guidance.

Can you just talk a bit about how you see that contribution going forward?

Yes.

On European gas prices, it's been weak compared to strong prices for a period of time.

And I think in a historical perspective, what MMP is telling me is that the current price level is in historical perspective perhaps a normal price level.

So I think that is just important to bear in mind.

But what we have seen is very -- some odd trends in many ways that has been a strong demand for gas and driving up LNG prices during the summer time from China when they wanted to fill their storage to avoid ending up in a situation related to the previous winter where they were kind of short.

And then we have seen that during this time, it's been both a mild winter but also a lower demand, meaning that more of the LNG is targeting Europe and then putting some downward pressure on gas prices in Europe.

And to counter this, you could say that there's been also quite steep decline in indigenous production in Europe.

Troll will be down in 3Q due to plant maintenance and I think, yes, Svein, you have anything to add on this?

Yes.

On Troll, as you alluded to, we have the production permit of 36 giga, which has decreased significantly over the years.

So that means that we are then also optimizing within the production permit.

And then, we have the flex on Oseberg as well and at all times we are evaluating and how long to run it most sufficiently based on what we see in the market.

Then, normally when we go into the summer months in May and onwards, we often take down production somewhat.

And then we have some turnaround as I said in the third quarter, a bit this year.

So then it's about then optimizing within the production permit of 36 giga for the year.

And then we had a question on Danske Commodities, which came in under very completed.

So we have 2 months in the quarter in our numbers.

First in January was, Danske Commodities, still not part of the company in many way, so -- but we see a positive contribution from Danske Commodities.

And very hopeful that by this company coming in, that we can strengthen their results for MMP.

But it's too early to say anything about the guiding range that should influence or impact the guidance range.

Svein?

Maybe you could also remind of what we said at the CMU, $80 million for the full year of 2018 was what the contribution announced spread over the 4 quarters.

We'll take our next question from the line of Jon Rigby from UBS.

I don't want to belabor the point, but first question is just on gas, again.

Is that, in the quarter, it looks to me that you probably traded a record level of volume.

It looks also to me that -- I mean, it goes up and down a bit, but the gas results, the gas trading result contributions for MMP was towards the lower end of the range you would expect for first quarter, which is generally a good quarter.

So I just wanted to ask whether, and this is for Europe -- so I just wanted to ask whether given -- if we assume TTF and NBP are lower or continue at these kind of levels, up and down for the next 18 months, 24 months, does that influence the profitability of MMP?

Or is the flat price the absolute price largely relevant to what you can make in trading and margin around gas optimization?

And then, the second question or request is can you just do a quick review of highlights, et cetera, on your exploration activities in the first quarter?

Yes.

On exploration activity, we completed 11 wells, 8 on the NCS and 3 internationally.

We had, in total, 4 discoveries, Carcara Northwest in Brazil and then Telesto, Ragnfrid North and Jasper South.

And then, after closing all the quarter, we also, as a partner, have a discovery in the Blacktip discovery in the Gulf of Mexico.

So spending, 1.7, still our best estimate for the full year.

We are still hopeful for our exploration campaign that we have planned for the Bering Sea and some other exploration activities or wells around.

On the gas volume and trading side, it was 16.4, Svein?

Yes.

Normally it's high volumes in the gas sense from NCS, then including the LNG at Snøhvit, just about 11 Bcm that has been traded.

But we also would like to remind you is that normally, what you see in the prices that we achieved is that the main results of that go into the DPN segment.

And, of course, we also take positions in the MMP, which impact MMP results.

But the gas prices and then invoiced gas prices is then mainly impacting the DPN segment, and so you see the impact there and to a lesser extent, on an absolute level in MMP but trading into the MMP segment.

Right.

And just if MMP is a standalone, can it make -- is where it sits in your guided range of results somewhat independent of what the external absolute flat gas price is?

Or is the level of gas price going to be somewhat -- is that going to somewhat determine where results are going to sit while global gas price -- global gas market remain well supplied?

I think it's fair to say that, of course, we normally take advantage of fluctuations in the gas trading, and so -- and then realizing prices, there in to the MMP segment.

But in a flat price environment, then most of that will be going to the DPN segment.

(Operator Instructions) We'll take our next question from the line of John Olaisen from ABG.

First I have to say, Lars, of all the 72 quarters that I have followed Statoil and Equinor, this is the shortest and most precise, so thanks for that.

And I'll hopefully try to do the same in my question.

One question only.

You recently participated in an exploration success in the Gulf of Mexico.

Can you tell us about the upcoming wells in the Gulf of Mexico, just update us on the Gulf of Mexico exploration please; what's next?

Well, thank you for the compliment.

And then, I will be very, very precise.

On Blacktip, it's a palogeen well in the western Gulf of Mexico and we are working closely with the operator on this and the assessment of what this might end up being when it comes to sort of the volumes.

The drilling is still ongoing.

It was still ongoing late April.

Yes.

But will you have more wells?

Another one coming up with the Monument well, that will come up expected them to be spudded d towards the year-end this year, second half.

And then we also have one well in Canada, the Harpe well in Canada that is a well to watch in the North America segment.

We'll take our next question from the line of Rob Pulleyn from Morgan Stanley.

Two quick follow ups on cash, since it's in vogue.

Firstly, to what extent will the week gas prices year-to-date impact 2Q results given the lag?

Or is there still enough of these longer-term contracts from last year since smoothing the way?

And the second question is staying with gas prices given the recent volatility.

What does Equinor consider the medium- to long-term marginal gas price in Europe to be given the increasing globalized nature of gas markets and, of course, volumes of LNG exports in the U.S?

On the first one, we expect a smoothing, as you say, when it comes to the effect of the contracts but there's still in the money there.

The one is out on long-term last year.

On the marginal cost of gas for Europe, Svein?

Yes.

What we believe is that we saw some other volumes now coming into the short term, but then see that in the longer term that more demand for gas is then coming.

So what we have said and in our economic planning assumption is that when we get into the 20s and 24, around $80-ish on the NBP prices is what we disclosed around the CMU.

Okay.

And obviously, that hasn't -- that thinking hasn't changed given the trends so far?

No.

Our next question comes from the line of Alwyn Thomas of Exane BNP.

May I ask on production plans for this year.

I know there's a lot of moving parts.

But maybe you could tell us what you assume for net volumes for Sverdrup in your 2019 production guidance of flat year-on-year?

And sort of in that context as well, maybe can you give a little bit more detail on current operations as Aasta Hansteen, Mariner and Martin Linge into next year would be helpful.

And then just on DPI, it's a pretty solid performance this quarter.

Can you maybe just give you a little bit more color on moving parts regarding the influence of Brazil and Roncador volumes in terms of cash margin and the U.S. onshore as well for the quarter, maybe help us try and explain the numbers.

Well, first of all, I mean, we delivered 2,111,000 barrels a day production last year.

And the decline on existing portfolio is still around 5%.

So that is equal to just north of 100,000 barrels that you have to replace for 2019 to stay flattish.

The startup for this quarter was as planned, and Aasta Hansteen started up just before the year end has been ramping up and reaches production plateau in February and are currently producing at plateau and nicely with a good regularity.

Mariner, we are guiding then that it will startup second half and hopefully, in the beginning of second half.

And Martin Linge, we see a lot of comments in -- from time to time, at least that there is a delay in Martin Linge.

When we looked at Martin Linge to take over the operatorship and increase our equity, it was assessed thoroughly, and we expected that the production startup for Martin Linge should be Q1 2020 and for us, that remains the same, and there is no cost changes either to that project.

So production guidance on Johan Sverdrup coming onstream, and it will ramp up to full plateau within 12 months time from starting up.

Yes, it's a good asset and contribute towards the end of the year.

But based on all these moving parts as you allude to yourself, we expect that the production for this year will be flattish compared to production last year.

And the 2.1 million barrels per day last year was record high and production for us.

So flattish is still on a record high level.

We'll take our next question from the line of Peter Low from Redburn.

Just one on your non-sanctioned project portfolio.

Would you consider that, that is currently adequate to organically deliver the 2025 production guidance you laid out?

And then, as a follow-up, can you provide any update on the progress towards FID of some of the larger projects in there, as I'm thinking of things such as Bay du Nord, Carcara and North Platte?

When it comes to the production guiding towards 2025, the sanctioned portfolio will come onstream by 2022 and then we have some other projects on sanction, as you say, that are progressing according to plan.

So we are confident that the guiding of 3% compound annual growth rate from '19 to 2025 will still hold.

And we have sufficient projects in the pipeline to deliver on that production growth, and then also production beyond 2025.

On Carcara, the final concept select, we expect sort of a -- for that to happen for the first FPSO during this quarter with a decision gate in third quarter for this year.

Bay du Nord, we reached an agreement with the provincial government when it comes to the framework for the fiscal terms for that development, we reached that in July last year.

And work is ongoing, the development application and benefit plan that we need to provide as part of that application.

The benefit plan is -- there are some requirements in the agreement with the provincial government when it comes to local contents.

Concept studies are being conducted for the floating production stores and offloading units as well as the subseatemplates, risers and umbilicals, and flow lines.

So those projects are progressing nicely.

But also bear in mind that one of our key learnings from the drop in oil price was that don't rush these projects.

Take the time you need to deliver good projects because if you're rush, you might start up a couple of months earlier, but it will come at a very, very high cost.

So take time to do it right and then plan, plan and stick to the plan.

I think that is why you see that we are able to sustain a guiding when it comes to capital spending at around $11 billion for the total portfolio.

We'll take our next question from the line of Christopher Kuplent from Bank of America.

And I hope I'm going to be quick too.

Can you let us know whether you're actually downgrading your full year CapEx guidance or is the IFRS 16 impact so small on that $11 billion?

Quickly, wanted to also ask whether the recent May activity pick up we've seen in the U.S. you think is making it easier or more difficult to potentially sell assets out of your portfolio?

And lastly, sorry, again, on European gas.

If I'm assuming that spot prices in the second quarter stay at current levels of around $4.50, are you saying that your pricing means you could actually see a premium in the second quarter?

Anymore more color for an idiot like myself would be welcome.

On the IFRS 16 and the effect on the CapEx, Ørjan.

On organic CapEx is not impacted by IFRS 16, so no impact on that.

Yes, short answer.

And then on the question of buying or selling assets in U.S. In many ways, you could say that the current commodity prices is among the worst we can have from the point of view that it's high enough for everybody to model through, and it is not high enough for the M&A market to really kick off big time like it was before the drop in oil price back in time.

Having that said, we see that there are pockets around the globe that the market is hot from a point of view that it is pricey and part of the U.S. onshore, Permian, to be more specific, is such a one.

We have looked at stuff in the Permian.

So surface-wise, it looks nice and it looks to work but they still need to make sense from a returns point of view, so it's too pricey.

And then you have a question on the $4.5 for European for second quarter, whether there's an opportunity to -- for us given our -- where we sit when it comes to the contracts we entered into last year, whether that can sort of represent a premium like we saw in the first quarter and that is what we expect, if the price is around what we have seen.

But bear in mind that we are smoothing out this change in how we are going to trade volumes going forward to more short-term prices.

We'll take our next question from the line of Anders Holte from Kepler Cheuvreux.

Congratulations on a strong quarter.

Just 2 questions, if I may.

One is on CapEx.

Now due to strong cash flow in Q1, you covered 47% of your CapEx is covered for 2019 from your operations.

So my question on the CapEx front is, how much of the remaining CapEx is contingencies of Johan Sverdrup?

And the second question, you talked about returns in the renewables segment as one of the key hurdles for you guys to launch your investment into the sector.

What I'd like to know is what exactly do you mean has to change in the renewable side for you to see more upside on the returns?

So if you could just allow us a bit more on the details on your reasoning for holding back on the renewables investments when we see companies like Enel they just take what they can simply not sanction enough and returns are fantastic.

This is what producers have been waiting for, for a generation and this kind of, it completes a bigger picture you're painting with the low returns and pullback on investment.

So what has to change in that sector for you guys pick up the pace?

That will be great.

First, on Johan Sverdrup.

I mean, now Phase I and Phase II being sanctioned at a total cost below what Johan Sverdrup Phase I alone were supposed to cost.

A stellar project development, execution and good collaboration and work by the supplier industry is helping out in making that happen.

On the contingency, the remaining contingency on the Johan Sverdrup Phase I, it's not much left.

I mean, we have more in the beginning and as the time go by, and you get more and more clarity and that contingency level has been taken down and that is also partly why you have seen a reduction investments, historically.

So there's not much left.

In the renewables space, we have seen a lot of cheap capital seeking infrastructure like returns with -- and accepting then low returns, so that has been -- the way we look at it, pushing down the returns in this segment.

Now that we see that the subsidies, more or less, is paving the way and we are being some industry being met with more merging risk, we expect the returns to come somewhat up and also people think that low risk is low return, high risk then should be also wanting high returns.

So this -- for this to be sustainable, the renewable space, when it comes to offshore wind and -- has to improve.

Okay.

When you say it has to improve, what does that actually mean?

It just means that either you are in -- you go into this and a very, very low returns or no returns at all and whether that is sustainable, it's up to you.

And in our case, we need to see better returns and worthy projects that create better returns for us to be going to invest.

We'll take our last questions from the line of Stephane Foucaud from GMP.

So Equinor's CapEx program for exploration in '19 and a specific question on what Equinor is doing in Turkey in the Thrace basin.

Looking at the [Junop] website, they talk about massive amount of gas, something like 20 tcf of resources without going drilling and testing.

So I was wondering you see that as being as mature as that because that could move the needle even for Equinor.

How -- when you think you would know whether the volumes are there or not, whether it works or not?

And how that would fit with the overall European gas strategy?

Well, the work program for the Banarli and West Thrace license in Turkey consist of several phases.

Phase I is the drilling and testing of the Malik 1 exploration well in the Banarli license.

The drilling has been completed and testing is ongoing, and it is way too early to conclude on the production potential of this license.

We have also completed some 3D seismic for other areas.

So drilling and testing one more exploration well will be on -- well, that was spudded in fourth quarter actually, 2018.

But all in all, it's way too early to conclude on the production potential.

The volume in this structure and both have to be in place for this to be of value.

For us, it is still value over volume but we still know that without volume, there will be no value.

But for this to fly, it has to make sense from a returns point of view, as for everything else, and it will compete with whatever we have obviously, in the portfolio.

Thank you, Lars Christian for the last question.

Thank you very much for everybody for participating.

We would like to deliver our projects on time and indeed, it is exactly 12:30, Norwegian time, so that keeps our tradition.

Thank you everybody for your interest.

Of course, any further questions that you have during the call today will be on, please feel free to contact Investor Relations and we will follow up immediately.

Thank you very much, indeed.

Thank you.

Bye-bye.

Thank you.

That concludes today's conference call.

Thank you, everyone for your participation.

You may now disconnect.