Equinor ASA (EQNR) 2016 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Statoil first-quarter 2016 analyst call.

My name is Peter Hutton.

I'm Head of IR, and with me I have Hans Jakob Hegge, CFO, who will be leading the call, as well as Svein Skeie, Head of Performance Management and Risk, and Orjan Kvelvane, Head of Accounting.

Hans Jakob will run through a presentation for around 12 or 15 minutes on the results and the drivers and then, as normal, we will open up for questions and you'll -- it will be explained how you can poll for those questions.

We expect to end the call by around 1:30 UK time.

And with that, let me give the word to Hans Jakob.

Thank you, Peter, and welcome to everyone attending this conference call.

Despite the challenging surroundings and the uncertainties in our industry, I am happy to present a result with continued strong underlying performance and visible progress on our improvement agenda.

I'll give a brief introduction to our numbers and then open up for questions in a few minutes.

My main messages to you today are that we are on track on delivering on our CMU priorities.

Costs are continuing to come down and we are capturing sustainable efficiencies.

And production efficiency continued to improve for the third year in a row and is now at record-high levels.

This quarter is characterized by the low commodity prices that impact not only our results, but also affects our focus and actions.

And we continued to deliver strong operational performance with sustained high regularity, and this is reflected in an underlying organic production growth on the NCS of 2%.

We have converted to US-dollar reporting.

This is a natural development or reporting as Statoil is a US-dollar company.

It will also simplify our communication with investors.

And finally, the Board has approved a first-quarter dividend at $0.2201 per share and we intend to offer a scrip dividend with a 5% discount.

This is subject to approval of the scrip program by the AGM on May 11.

Looking at the financial results, we report a net income for the quarter of $611m, compared to a net loss of $4.6b in the first quarter of last year.

As always, we make adjustments to reflect the underlying business.

And this quarter we adjust the result downwards by $203m, mainly as a result of a reversal of impairments, compared to a positive adjustment of $6.2b in the first quarter of last year.

The reversals reflect lower operating costs and are not related to higher price assumptions.

The adjusted earnings after tax ended at $122m, compared to $902m in the first three months last year.

These results reflect the steep reduction in the price achieved in the first quarter.

Brent averaged at $34 in the first quarter, compared to $54 in the same period last year.

On the positive side, our results also reflect a sustained high production regularity and strong production.

We also see visible cost reductions and the efficiencies coming through.

Adjusted OpEx and SG&A was reduced by 20% year on year.

The adjusted tax rate in the quarter was 85.8%.

This is a result of three factors.

First, with lower prices the effect of the uplift tax credits takes down the effective tax rate on NCS.

Second, the MMP segment was a low tax rate -- had a low tax rate in the quarter due to a higher production of income in countries with low effective rates.

And finally, it is a result of the international tax rate caused by earnings composition, with losses in jurisdictions without a tax shift.

Moving to adjusted earnings by segment, so let me take you through our segments and let me start with development and production Norway.

We report an adjusted earnings of $1.3b, compared to $2.4b in the same period last year.

Although the result is affected by the oil price development, the quarter also shows good results from production efficiency well above 90%, as well as continued good progress on cost reduction.

We can report a 25% reduction in OpEx and SG&A per barrel in NOK.

Let me remind you that second and third quarters are typically busy maintenance periods and you should typically expect higher unit production costs as volumes are lower and costs are higher.

Depreciation was down by 7% in NOK in the quarter.

Reported in dollar, the DD&A was down by 17%, reflecting the high deduction from fields with relatively lower DD&A per barrel, as well as a reduction in asset retirement obligations.

Outside Norway, adjusted earnings was negative $800m, compared to a negative $282m in the same period last year.

The results were significantly affected by the low commodity environment.

Having said that, we are pleased to see that the positive cost trend continues in the part of our business, with a 14% reduction in adjusted OpEx and SG&A per barrel.

The main drivers for this reduction was lower operating and maintenance costs, in addition to positive contribution from lower dividend expenses and reduced royalties following the price reduction.

DD&A per barrel was reduced by 13%, mainly as a result of revised reserve bookings and impairments, partly offset by a ramp-up of new fields.

And finally, our results from our MMP segment, which continued to deliver good results in the demanding markets.

The adjusted result in the quarter was $431m, compared to $890m in the same quarter last year.

The reduction was driven by warmer weather and volatility in the gas price.

We saw strong contributions from the refineries and from our liquid trading business.

Looking at our production, the daily production in the first quarter was just over 2m barrels.

This reflects the high regularity and the seasonal gas offtake.

In Norway, we continue to produce with high regularity, and the production efficiency this quarter is the best we have seen since we started reporting.

New fields on stream and ramp-ups of fields contributed positively to maintaining production at the same level as last year.

And among these were the Heidelberg in Gulf of Mexico, Kizomba satellites in Angola, Corrib in Ireland, as well as Ballymun, and Edvard Grieg on the Norwegian Shelf.

In addition, our production increased as a result of our increased share in Eagle Ford.

This was offset by divestment of Shah Deniz and a stake in Gudrun, as well as a decision to produce less from Oseberg as a part of our flex gas value-over-volume strategy.

Then our cash flow.

The cash flow from operation is clearly affected by the low price environment that we're in.

And we paid one tax installment on the NCS in the quarter.

Remember that this payment is based on the oil price for 2015.

We continue to see a positive trend on reducing CapEx through efficiency and strict capital prioritization.

Note the CapEx figure include our financial investments in Lundin, representing 0.7 percentage points on our gearing.

Our net debt to capital employed was 28.1% at the end of the first quarter.

This is up from 26.8% at the end of last year.

If you look at our outlook, we continue to focus on our improvement program, as we discussed at the Capital Markets update in London in February.

Our outlook remains unchanged.

CapEx is expected to be around $13b.

And we anticipate an organic production growth of around 1% for the period 2014 to 2017.

Maintenance is expected to be around 60,000 barrel per day for 2016, with a quarterly impact of 55,000 expected in the second quarter.

And we do expect to spend around $2b on exploration this year.

Let me also give a comment to the scrip program.

The Board of Directors has approved a scrip program for the first quarter in line with the program for the fourth quarter.

Assuming approval of the program at the AGM, we will distribute formal information about the practicalities for the fourth-quarter scrip process around a month from now.

And subsequently, shareholders can elect whether to opt for shares in early June.

With that, I hand the word over to Peter to lead us through the Q&A.

Thank you, Hans Jakob.

So yes, we will now move to questions, so I'll ask the Operator to open up the lines and we'll take those through.

We'll go through -- try to keep this fairly short and swift, one or one question with a follow-up if we can, please.

Thank you very much.

Brendan Warn, BMO Capital Markets.

Yes.

Thanks, guys.

Thanks, Peter, Hans, for the opportunity to ask questions.

It's Brendan Warn from Bank of Montreal.

I guess just one question, and it relates to the -- your international business.

Hans, if you could just talk through, and if you break it down by the components that go into that division, if we're still in a $40-to-$50-oil-price environment this time next year, considering the new fields that have started up, a number of them are in that international segment, just where will we be, both on earnings in terms of if we're back into positive earnings, but then also in terms of cash flows.

And just if we can tie it back to the Capital Markets Day statement and if we can keep it related to this international business, just in terms of cash neutrality at $60 a barrel, please.

Okay.

Thank you, Brendan, for asking that question.

First, let me just say that it's obviously challenging at current prices and prices realized in the first quarter given that -- with Brent at $34.

And our realized price is just below $26.

As you're aware of, the adjusted earnings for the international was minus $800m.

And as you also know, we are structurally more exposed to the oil price than the EPN due to the historic cost and the lower margin, as well as differences in quality of the products.

So do we have a discount on some heavy oil fields?

Also, elements taking into account like a bit of an over-lift in the beginning of the quarter when prices were low.

So this explains the result that we are presenting.

Having said that, we also have a positive development on the control elements, like the adjusted OpEx and SG&A per barrel, which is down 14%.

So we see a positive trend on the earnings.

And we have presented a plan forward to 2018.

Remember Torgrim talked at CMU about the plan from $90 to $50.

And we're talking about cash neutrality.

And it will also depend on the CapEx level, which again will depend on factors such as activity level, not only the oil price, but also future exploration success.

So overall, to be very specific on [in] for next year is hard, but we are doing activity adjustments, like the onshore business in the US, where we only have on rig crew in each area and no fracking crews in the first quarter.

Can I just ask a follow-up question?

Just in terms of your growth then, certainly into 2017, what I assume are the price -- and certainly gas price because a lot of it's coming from US onshore, that would actually begin to decline rather than a 1% CAGR growth?

If I understand your question correctly, Brendan, you're talking about the production guiding forward.

And as I said, it's 1% overall for the period 2014 to 2017.

Depending on prioritization, we could adjust the activity level up and down on the onshore business, whereas -- so that's the main component in the flexibility short term.

Okay.

Thanks, Hans.

I'll leave it there.

Martijn Rats, Morgan Stanley.

Hello.

Good afternoon, gentlemen.

Thank you for the presentation.

Just a question from my side and perhaps a quick follow-up if that's okay.

The first thing is just on depreciation.

Hans Jakob, you talked about that's been obviously coming down and that it might start to go up again as fields ramp up and you get less gas contribution.

Can you perhaps just give us a sense of how to quantify that?

Just because we've seen such a big decline in DD&A per barrel, things like DPN DD&A per barrel now down to just over $10 a barrel from $12, $13.

Does that revert back to the $12, $13 level that we saw about a year ago or actually is it not going to be quite as severe as that?

The second question or follow-up perhaps is just on the gas business.

And you've highlighted the weak result that you had on the trading side in the quarter.

I just wondered if you could just talk a little bit more about this and just perhaps, more broadly, just your thoughts, latest thoughts on the European gas market.

We've obviously seen quite a big recent move in NBP.

I don't know well positioned you would be able to take advantage of that, but is that something that you can benefit from or is that volatility actually not very helpful in your trading business?

Thank you.

Okay.

Thank you, Martin, for asking that question.

First, the DD&A development, and it's three main components.

It's currency, around half.

It's the asset retirement obligations and it's the new fields.

So if you look at the depreciation in the first quarter, it was down by 13%, and a significant component is currency.

So in the international part, it's higher production from start-up and ramp-up of the various fields, plus the effect of previous year's impairments, whereas on the Norwegian Shelf it is also decreased production from fields with a high DD&A rate, like the Gudrun field.

And we also have increased production from fields with relatively low DD&A rate, like Snohvit and Ormen Lange, but also the effects of the ARO obligations.

To your second question about the gas business and the trading results and the gas market going forward, that's obviously a huge and important question.

And if we look at the MMP segment overall, we were good on the refineries, with high production efficiency, quite healthy margins and liquids trading okay, gas somewhat lower.

Why?

31% lower average sales price due to abundant gas supply and a relatively mild winter.

And we are also more exposed to shorter-term contracts in this quarter.

But overall, MMP, good, in the upper end or guiding of $250m to $500m.

Looking at the gas market moving forward, it is obviously a lot of elements into this, but the starting point is that the EU gas market is well supplied short term, both with gas from Russia and from Norway and potentially some new LNG volumes coming in.

So far this year we see limited US LNG volumes reaching the EU.

And we also see upside going forward linked to the switching of coal into -- from coal to gas in the UK.

Groningen is capped at 27b bcm for 2016.

And due to the shipping distance, it is expected that the Australian LNG will end up in Asia.

So the US LNG, even more flow, according to the price signals in the market.

So long term, we have a positive view on the European gas.

And Norwegian gas is competitive in this market with our training position.

Thanks, Hans Jakob.

John Olaisen, ABG.

Yes.

Good afternoon, gentlemen.

A question on exploration and CapEx spending.

If I take the numbers for Q1 and multiply them by 4 I get quite below your analyzed guidance.

So I just wonder, is this due to timing within the year or have you started off slowly to give (technical difficulty)?

Sorry, John, I can't hear you, but it was a question around the CapEx and the low burn rate.

First of all, as you've seen, we maintained a strong capital discipline and quite strict prioritization.

We maintain our guiding on CapEx.

And I think we should be cautious and not base the full year on a quarter.

We expect higher activity during the year.

Sverdrup execution is a key part.

Also starting execution on Peregrino phase two and the potential US onshore.

So the organic CapEx of $2.4b is in line with our guiding on the $13b.

Okay.

And for exploration?

Exploration, I give that to Svein Skeie.

Yes.

On exploration, as we guided at the Capital Markets Day, we expected to have a spending of around $2b for the year.

We have spent a little bit more than $300m this quarter.

So we are then -- but we are remaining or guiding of around $2b, so we also expect that this will come up somewhat later.

So we are remaining the guiding of around $2b for the year.

Yes, and --

Okay.

And I only have one -- sorry.

No.

It's just to add, John, that as Svein said, while maintaining the guiding, we're working hard on replenishing the portfolio.

And this guiding that we have given is down from the $2.9b that we had previous year, so we are taking it down while replenishing the portfolio.

And my follow-up will be on exploration, if you could comment on the Gavea A1 well in Brazil, which is said to be a big success, but I haven't seen any comments from you guys on that well.

If you could comment on the outcome of that well, please.

Yes.

The starting point is that the partner has just completed Gavea A1, which is the fourth operation well in the license.

And it was a positive well, encountering 175m hydrocarbon column, a good reservoir quality and a positive well test.

So then you might add, what's the next step?

Well, that's to evaluate the subsurface data from the appraisal program, as well as assessing the potential development solutions.

So we expect to complete the operatorship transfer in the third quarter, so quite positive news from Brazil on that one.

Okay.

Thanks a lot.

Jon Rigby, UBS.

Yes.

Thank you.

Can I just ask a question on tax, both Norway and international actually?

Could you just go back through the comments you made about the uplift and just contextualize that about how that will play out through, let's say, an oil price scenario where we are now, $40-ish up through $60-ish and how that will then translate into your headline tax rate on the NCS?

And then on the international side, for almost the entire period that you've been making losses in the international arena while oil prices have been low you've been actually taking a tax charge.

I guess that's on mixed effects.

And then this quarter, with the lowest oil prices, that you get some credit back.

So I just wanted to understand as we move forward what we should be expecting, all things equal, in terms of tax debit or tax credit in relation to the international business.

Thanks.

Okay.

Thank you, John, for asking that question.

Overall, as I said, the tax was 86%, which is relatively high.

And the tax rate was negatively impacted by the loss in int' and the limited tax protection we have there.

If you look at the DPN, the low tax rate on adjusted earnings is a result that we have a higher effect of the uplift deduction due to low adjusted earnings, with a 64% tax on the adjusted earnings for the NCS.

We also have a relatively low tax rate on the adjusted earnings from the MMP segment caused by earnings composition.

And lower prices increases the tax rate.

And we expect fluctuations in the tax rate in the current volatile environment.

Regarding the tax installment, it's quite limited effect on this quarter.

We're talking about $40m due to an overpayment on taxes in the three -- in the first three installments paid in 2015, so that actually led to a lower installment payable in 2016.

Going forward, around 70%, 72% in periods with high oil prices.

And we shouldn't expect material changes to short-term if you're assuming flat prices, but if the prices go up you should also expect a higher tax rate.

But within the int' segment, it will be very much driven by results.

Right.

Just on the international business, you've, as I understand it, been unable to shelter losses in certain countries with profits you've made in others.

But it would appear that in terms of either the composition of your production or potentially the cost reduction that you've been able to achieve in different countries, you're now into a situation where that's not the case and you're able to have a tax rate that is at least directionally consistent with the losses you're making, i.e.

credit.

Is that a reasonable assumption that -- or is it a reasonable assumption that that will be the case while you are loss making in the international business going forward?

Okay.

Orjan Kvelvane, Head of Accounting, would you like to answer that one?

Yes.

So as a starting point, it is more difficult to defend recognizing taxes when we're making losses because we need to defend the debt, we are having convincing evidence that will be utilized in the short term.

So as you see from the 20-F that we have published, we have unrecognized deferred tax assets in US, in part of Angola, so that's a split, and Canada and Ireland and also part of Brazil.

So that -- in a low-price environment, that is more challenging, but that is an assessment that we do period for period.

Right, okay.

So there's some recognition of a change of that view in the first quarter.

Is that fair to say?

So there is not much changes to the position by year end.

Okay.

All right, thank you.

Ilkin Karimli, Credit Suisse.

Good afternoon, gentlemen.

Thanks for taking my question.

I have one general one.

You've done an impressive job in terms of cost cutting and have significantly reduced breakevens for your projects.

So given your peers are not taking FIDs at the moment either, isn't now a good time to do that i.e.

to take FIDs given you would have better access to teams, infrastructure etc.

So I'm trying to understand what is the holding factor here?

Is it further cost efficiency that you are planning or is it more certainty on the oil price side that you're waiting for?

Thank you.

Okay, thank you, Ilkin, for asking that question.

Remember, first of all we invest a lot in Johan Sverdrup, which is a capital-intensive and world-class project.

We also sanctioned the Oseberg Vestflanken on the NCS in December and [Triestok] is expected later this year.

What determines the point of FID-ing a project?

If you think the project could be optimized further, I think we should carry on the improvement work and really work on it.

And we also make an assessment of the capacity in the supplier market and the timing of the sanctioning related to the market prices.

Understood, thank you.

Oswald Clint, Bernstein.

Yes, hi, good afternoon, thank you.

Maybe just some questions on information within the release today.

I'm curious again on the European gas business with your invoiced gas price.

It tended to come in much, much higher than hub prices in the quarter.

Was there anything specific in the quarter that made that invoice gas price be so high relative to hub?

Anything we have to consider?

And then secondly just on the impairments and specifically the reversal of impairments which I know is something you do every quarter but I think it's referring to some unconventional shale assets.

I'm curious which asset that is and what's really triggering that impairment reversal?

Thank you.

Okay, thank you, Oswald, for asking that question.

Let me start with the last question on impairment and reversals.

Overall in the quarter, we -- first of all, let me say that we are clearly exposed to the impairments and the reversals, given the volatility in the prices.

In note 6, you would see that the net impairment charges is $308m before tax.

We had a $600m overall reversal and $300m in impairments, which gives a net of around $300m.

We do the assessment of the impairment triggers and this has resulted in some impairments, as I said, but even more reversals.

And these are according to the IFRS standards.

But it's mainly onshore assets in North America and conventional outside US.

Looking at the EU gas market, and the invoiced gas price, we will give that question to Svein Skeie to start with.

Yes, as you referred to, it was probably the invoice price above, for example, the NBP price, where we have seen that we are selling the prices or on the invoices prices it's quite a bit higher than the NBP.

That comes from a situation where we are then selling gas at -- not everything at the spot or the day head prices, but we have a structured sale with partly coming from day head, partly coming from monthly head or season head.

And that has then given a higher price on the invoice price this quarter compared then to the NBP which is then more the spot prices.

Okay.

Okay good, thank you.

Teodor Sveen Nilsen, Swedbank First Securities.

Good afternoon and thanks for taking my question.

I have two questions on OpEx particularly in Norway.

I notice that the IFRS OpEx that you report on the past few quarters is substantially higher than the adjusted OpEx you have reported.

I think it's $1.3b on the past five quarters.

I just wonder what's this difference related to?

Is it only cost cutting initiatives which is these $1.3b?

Okay, thank you, Teodor.

First of all, cost savings is going according to the plan.

But as I said, we also see some currency effect and adjusted OpEx and SG&A decreased by $590m overall which is 20% as I said, and on the NCS, 25% per barrel.

But also impacted by some quarterly specifics.

We see mainly efficiency gains now and we also expect some market effects to come.

When it comes to more specific examples, we have lower O&M costs on the NCS.

We have lower well interventions on the NCS.

And we also see that we have some quarterly specific, like the pension costs.

And we will have more maintenance going forward, as I said in the second and third quarter.

So that's the main points on the NCS OpEx SG&A.

My question was more referring to the difference between the adjusted OpEx, which I think is the numbers you referred to, and the IFRS OpEx, which is $1.3b higher in sum from first quarter 2015 until first quarter 2016.

Is it possible to explain that difference?

Yes.

Orjan has that.

So I do not have the exact figure that you're referring to, Teodor.

But in general, so we have the over-under lift adjustment in the adjusted earnings.

That will impact that amount.

Then we have in some quarters some provisions that is clearly not part of the underlying in that quarter.

That also explains part of this.

But I do not have the exact five quarters in front of me.

But that is it in general.

Okay, thank you.

And then just one follow up when it comes to OpEx on next two years.

Assuming somewhat higher oil prices, do you think the current OpEx level should represent a proxy for what we should expect over the next few years?

Well, as we've said, this is mainly efficiency gains.

Some currency effect but mainly efficiency gains.

We do more work ourselves, we have become more efficient.

So that's what we are aiming for, to actually maintain the efficiency that we have and that's our main guiding that we are working structurally through the improvement program, we see a good progress and we are trying to stick to the new improved efforts.

Okay, thank you.

Biraj Borkhataria, RBC.

Hi guys, thanks for taking my question.

Just going back to potential project sanctions, you mentioned at your strategy day that you had a group of projects that the average breakeven was close to $40, and we're kind of around there now.

So in the scenario that you may want to sanction these projects and you feel like they're at the optimum position to sanction, what impact would that have on your CapEx guidance, i.e.

are you committed to spending $13b or could there be upside to that number as and when you sanction these projects?

Many thanks.

Thank you for asking that question.

That was one of the main key messages on the Capital Markets Update that we, as you said, have brought down the breakeven on our portfolio by $30.

And we are maturing these projects.

And we have $4b to $6b in flexibility in our CapEx in 2018 and 2019.

And we can choose to sanction some of these if we want to, if we think the timing is right and we have the right concept.

But we do not have to do it and it has little impact this year.

And any sanctions will impact -- will mainly impact CapEx in the next coming years.

Okay, thanks.

Michael Alsford, Citigroup.

Thanks for taking my questions.

I've just got a couple actually on some of the transactions that you've done through the quarter.

Just firstly on the wind deal, can you maybe just talk a bit about whether this is a sign that you're seeing an increasing capital allocation towards renewables or is this very much within your plan and guidance on spend?

And perhaps just could you contextualize the return that you're looking to target in these renewable projects relative to your typical oil and gas business?

And then just secondly, just following up on the potential sale or the planned sale of some non-core properties in the US and your unconventional business?

Could you perhaps just give us some indication on -- if there's a volume impact associated with that sale, please, in terms of production loss?

Thank you.

Okay, I think I'll take the second one first because as of April 20, we entered a confidential agreement to divest an unconventional, non-core property in the US and this is $400m in cash consideration.

But we do not expect to either gain or realize any gain or loss on the transaction.

But it's confidential and we will have more project -- more information later related to that as a part of the agreement.

Looking at the wind, if you take the last investment, it is a 50% of a wind park, Arkona Becken that we bought from E.ON as a part of the cooperation.

It is 2019 which is the start-up date supporting electricity households, 400,000 households in Germany.

Looking at the size of the investment, it's $100m this year.

Compared to an overall investment program of $13b, it's not a very big investment.

And looking at the attractiveness of this, we think it's a fair return for a different risk profile.

We do not have the subsurface risk in this project.

And we have a different risk profile.

And it's supplementing our core E&P business as a part overall strategy that we communicated at the CMU.

Okay, thank you.

Lydia Rainforth, Barclays.

Thanks, and good afternoon.

A couple of questions if I could.

The first one was just looking at the record quarter for efficiency.

Clearly there's been a lot of progress made there but it does make it very difficult to understand what's happening to the underlying decline rates.

I was just wondering if you could comment on that?

The second one -- sorry to come back to the cost data -- but on the per-barrel numbers on the international business, it did look like it flattened off quarter on quarter in terms of the per-barrel costs.

I'm just wondering whether that was just a seasonal factor or just whether or not you've actually got most of the cost savings in the international business you might expect at this point?

Thank you.

First, thank you, Lydia.

And there are no major changes on the decline rate.

It's around 5%.

And the second question, if I heard you right, is about the international business and any seasonal factors.

Yes, that's right.

Well, on the gas side, we had a relatively mild winter in the US.

But that's weather.

Svein, do you want to fill me in on this one?

If you look at the overall on the int' we have (inaudible) per barrel, measured in US dollar, approximately 14% this quarter when you compared it with the quarter last year.

That is more or less in line with what we have seen over earlier quarters as well, as we have reported, special seasonalities.

We have had some lower activities on the onshore in US.

But on the total portfolio, it's no major seasonality on the int' part of it.

That's all, thank you.

Anish Kapadia, Tudor, Pickering, Holt & co.

It seems they have stepped away.

Rob West, Redburn.

Hi there, thanks very much.

My question's really about Oseberg.

And just going through your field by field data, what really surprises me is the magnitude of how much that field decreased year over year on the gas production.

So it went from 67,000 barrels a day of gas in 1Q15 to 12,000 barrels a day of gas in 1Q16.

That decline, that's about 2.5% of all of your production.

So that's clearly a really big moving part.

Can you talk a bit about that decline?

I'm guessing it's intentional and part of your value over volume gas strategy.

But can you talk about how much time or cost would you need to bring back that 50,000 barrels a day?

And what would be the trigger for you to do that?

Thank you.

Okay, thank you, Rob, for asking that question.

These are fields that I know fairly well.

And Oseberg and Troll are the fields that provide the flexibility.

So this is part of our flex gas strategy.

And Oseberg can start up in relative short term.

Troll any minute, Oseberg a bit longer.

But this is something that we have done, as you correctly said.

It is value over volume.

So what would make you bring those volumes back?

As we all look to, can you maintain this production rate and can you keep growing, what do you need to see to produce those volumes?

An increase in the prices.

Can you say on what level?

Or prefer not to?

Well, we don't go into details on that one.

But if you look at the past performance of Oseberg, you have seen higher prices and higher production from Oseberg.

So increase in prices.

Okay, thank you.

Tom Robinson, Deutsche Bank.

Yes, afternoon, everybody.

Just one question on the domestic business and rig contracts, would you be able to provide an update on the Norwegian rig fleet in general and how active you've been in renegotiating terms?

And if so, is that something that is included in the current efficiency savings target?

Or would any progress here be incremental to that?

Thank you.

Well, the overall message on the rig is that we have the rig capacity we need for now.

And we have done cancellations to rigs within the existing frameworks in order to optimize this.

Where we come from a relatively high level of commitment, that we have taken down, and we are fairly balanced at the moment.

And just a follow up.

Are these predominantly dollar-denominated or NOK denominated?

Floaters are in dollar.

Thank you.

Kim Fustier, HSBC.

Hi, good afternoon.

My first question might be related to a previous one on tax.

But I noticed that you wrote off part of the DPI deferred tax assets because of uncertainty on future taxable income.

I wondered if you could elaborate on this and maybe tell us which assets specifically you've become less confident in, perhaps?

And secondly, I know it's early days but could you give any guidance at all on the level of scrip dividend take-up that you expect?

Thanks.

Thank you.

Orjan will take us to that question.

Okay.

So this is about an assessment, country by country, field by field.

So in some countries, we go down to field level.

We are not specific on which country we are talking about.

But this is an assessment that we do every quarter and it's about how we can defend keeping the taxed asset in the balance sheet.

And if the prices are going down in general, the uncertainty increases and we take a valuation allowance related to that.

Then to the scrip, overall feedback has been good but the take-up rates remain to be seen of course.

And we do not have any forecast to share with you on this one.

If it is approved by the AGM, there will be no issues that have been brought.

There will be no issues that have been brought to our attention.

It is in for one month from now, from the Company, and the election in June.

So we think we have an attractive offer with the 5% discount.

Okay, thanks.

Hamish Clegg, BofA Merrill Lynch.

Hi, thank you.

Just a question and follow up, please.

I wondered if you could talk us through a little bit about progress on Johan Sverdrup and the possibility of de-bottlenecking leading to a higher plateau rate.

I noted that some of your partners in the project suggested there could be some upside to this.

And relating to it, as part of a follow up, I wondered if you could walk us through your depreciation in Norway and how it could affect cash flows going forward with a view to the impact on tax?

Can we see depreciation which is running currently half of total CapEx for the Group catching up with CapEx?

Or was this a level we can -- you mentioned it would go up but what's a sensible percentage of CapEx appreciation we can expect?

Thanks.

Okay, thank you, Hamish, for asking those questions.

On the Johan Sverdrup, the de-bottlenecking is definitely a question that is being discussed in the license.

We recognize that some partners have been sharing their thoughts on this when it comes to the upside potential.

And we have a close dialogue in the license.

But we are working on it.

So we do not have any new information according to this issue today.

Yes.

On the DD&A in Norway, it's both CapEx and DD&A have flattened out in the recent years.

But DD&A in this quarter is close to the CapEx level.

And going forward, I think we -- as I said, we both have decreasing production from fields with a high DD&A rate, like the Gudrun field.

But we also have increases from more mature fields.

And we should expect some increase in the DD&A as new fields are ramping up both Edvard Grieg and Goliat and later in the period you would have fields like [Osterhunstern] and eventually also Johan Sverdrup.

Lovely, thank you so much.

Halvor Strand Nygard, SEB Enskilda.

Yes, hello.

Your Bakken production came down some 10% sequentially in Q1.

And you said that you're currently running one rig crew in each area and no frack crews.

Can you give us some color on what you expect from the onshore assets in terms of production going forward?

Okay, thank you, Halvor.

As you are right, absolutely right, there has been one rig crew in each of the three areas in the first quarter and no completions in 1Q in Bakken.

Having said that, we are bringing in a frack crew to the Bakken area.

so we expect the team to do some completions going forward.

And can you say something about the production levels in the next few quarters?

Yes.

The quarter-on-quarter decline consequently not representative for what we expect going forward.

But the beauty of the onshore business is the flexibility.

So I do not -- still I do not think it's representative what we have seen quarter on quarter, the decline that we actually have experienced.

So going forward, with increasing prices, you should expect a higher activity level, including in the Bakken area.

Thank you.

Anish Kapadia, Tudor, Pickering, Holt & Co.

Hi, yes.

A couple of questions please.

Just going back to the tax position, so your total unrecognized deferred tax assets in the US increased by around 150%.

So you're at about $5b in the US.

I'm just wondering, does this make you more inclined to look at acquisitions in the US rather than elsewhere around the world?

And especially given your existing position?

And then secondly, I was just wondering if you could give an update on your Canadian exploration and development plans?

I think you mentioned you were going to give an update in Q2.

So you've drilled five wells, exploration appraisal wells over the last couple of years.

Just wanted to get a sense of where you see yourselves with that Canadian offshore position?

Thank you.

Okay, thank you, Anish, for asking those questions.

First to the tax and the deferred tax assets.

In the US, it's definitely something that we can make a substantial amount of money on when we can account on it.

And does it make M&A more interesting in the US?

Well, unfortunately, I won't go into detail on this question as we have a policy of commenting on the M&A when we actually have a deal to announce.

So that's the boring answer to that.

But we follow the market closely.

To exploration, it's been quite a relatively quiet quarter.

We completed seven wells, we had two small discoveries on the NCS both the [Volomfel] and the [B Vest Onkoltrom].

Under evaluation is [Povonup] in the Gulf of Mexico.

We have appraisal programs for Wisting Central in Norway and [Goveas] I just talked about with positive results.

Four wells ongoing, you mentioned Canada, [Bay du Loope].

An interesting one is Raya in Uruguay.

[Viti] and Wisting Central on the Norwegian shelf.

And we're working on access.

On the Flemish Pass, it is anticipated that Statoil will complete its 18-month drilling program focused on appraising the Bay du Nord discovery and exploring in larger Flemish Pass Space in the summer this year where to date we have finalized drilling of seven wells, including side tracks.

So we intend to provide an update on the program and the date when they are fully evaluated.

And we have to come back on this issue.

Thank you.

As there are no further questions in the queue, I would like to pass the call back to our host for any additional or closing remarks.

Well, thank you, everybody, appreciate the questions.

As ever, if there are any follow-up questions, please don't hesitate to contact the IR team and we'll get back to you as we can.

And we'll let you get off to get ready for the next conference call that many of you will have in half an hour.

Thank you very much for your attention and your participation.

Thank you, bye bye.