Welcome to the Equinor company update conference call. [Operator Instructions] Today I am pleased to present Mr. Peter Hutton. Please begin.

Thank you very much. Ladies and gentlemen, welcome to the Equinor Results call for the First quarter of 2020. This morning, we’re running the call from Oslo, Stavanger and the UK. So reflecting, to some extent, they’re more remote working under present conditions. With me on the line, we have Lars Christian Bacher, CFO; [indiscernible], the Head of Performance Management; and Orjan Kvelvane, Head of Accounting. As normal, Lars Christian will introduce the results and presentation for 10 to 15 minutes, and then we will run a Q&A session, which instructions you have had in order to call for around 45 minutes. Thank you very much. And with that, I’m pleased to pass the line to Lars Christian.

Thank you, Peter, and good morning, everyone, and welcome. I truly hope all is well with you and your families during these difficult times. Before I go into our quarterly reporting, I’d like to reflect shortly on the truly extraordinary times and how we are – as a company are responding. We are being hit by two storms at the same time, coronavirus pandemic and a sharp fall in energy markets due to demand destruction, leading to an unprecedented oversupply. The corona pandemic and the forceful mitigating actions from governments impact societies and economies. As a global company, Equinor and our people are affected, albeit in different ways. Those who can work from home, and travel is reduced to a trickle. On all our installations and facilities, we have introduced strong measures to reduce the risk of infection. In the last two months, Equinor has taken forceful actions to further strengthen our financial position. First, we suspended the buyback under the share buyback program until further notice. Second, we introduced an action plan to reduce spending by $3 billion before tax in 2020. Third, we issued bonds for $5 billion at attractive terms to be proactive given the uncertainty of financial markets. And finally, we reduced the first quarter dividend by 67% compared to the one proposed for the fourth quarter last year. This reduction reflects the current unprecedented market conditions and uncertainties. These measures strengthen Equinor’s liquidity and resilience and increases the flexibility and support of investing in a high-quality portfolio including renewables. Throughout this crisis, we will be guided by our values and stay committed to our strategy towards a low-carbon future. We all have seen the world responding in various ways to the pandemic. OPEC Plus has decided on significant cuts. And last week, the Norwegian government announced production cuts at the Norwegian Continental Shelf of 250,000 barrels per day in June, and 134,000 barrels per day for the second half of this year. The implementation of this on a field-by-field basis remains to be detailed out by the government. The Norwegian government has also announced that they will put forward to the parliament a proposal on temporary changes in the tax regime for our industry. The purpose of these measures is to maintain activity through a short-term release or increase in liquidity and improved profitability. We agree on these goals, but we do not see the current proposal achieving the intended results. We hope that the dialogue between the industry and the government will lead to a good solution. Then I move on to the first quarter. As expected, our financial results have been negatively impacted by the lower prices. Our average realized liquid price was $44.2 per barrel, down 21% since the first quarter last year. Similarly, our average invoice gas prices, both in Europe and the U.S., were down 41% in the quarter. Despite this, Equinor delivers a solid net free cash flow of $362 million after capital distribution. We closed the quarter with a solid balance sheet, a net debt ratio of 25.8%, and we keep our credit ratings in the AA category. We had safe and stable production, and our improvement and cost focus continues even more than before. In the quarter, our unit production cost was down by 6% compared to last year. Johan Sverdrup continues to impress by achieving 470,000 barrels per day by end of April. This is 30,000 barrels higher than designed capacity. And remember, with a unit production cost below $2 per barrel, Johan Sverdrup contributes with a very strong cash flow. As you all know, last summer, we increased our equity in Johan Sverdrup by 2.6% through a transaction with Lundin. We invested in Lundin back in 2016, and two days ago, we divested all our remaining shares in the company. Over several transactions, we have had all our invested money back and 2% equity in Johan Sverdrup effectively for free. Let’s take a quick look at our safety performance. This quarter, we report a serious incident frequency of 0.60 per million working hours in the last 12 months and a strong improvement in the total recordable injury frequency of 2.3 versus 2.9 in the first quarter last year. We have had no – no reported cases of COVID-19 impacting production in the first quarter, but it has led to reduced manning, impacting the development schedule of certain projects. Now to the financial results. IFRS net operating income this quarter came in at $58 million, and we delivered adjusted earnings before tax of $2 billion, down 51% from the same period last year. We report net impairments of $2.45 billion this quarter. Of this, around $900 million are related to E&P Norway and $1.4 billion to assets E&P International, of which $1.1 billion is related to our assets in North America. The impairments are mainly due to lower short-term price expectations. The price drop at the end of the quarter and uncertainties ahead makes cost discipline and continuous improvements even more important. It is therefore good to see the strong capital discipline in the organization and that costs are trending down. We are on track to deliver on the $700 million cost improvement for 2020. The tax rate on adjusted earnings was 73% due to the earnings composition. IFRS results after tax was negative $0.7 billion. Adjusted earnings after tax was $0.6 billion, down from $1.5 billion in the same period last year. Now a few comments to each of the reporting segments. The unprecedented market situation has negatively influenced earnings in all segments. Increased product differentials and a lower dated Brent price, which is the basis of much of our realized prices, has further reduced our results. Exploration & Production Norway delivered adjusted earnings before tax of $1.9 billion, down from $3.2 billion for the same period last year. The continued cost and efficiency focus within E&P Norway resulted in a 12% reduction in unit production costs impacted positively by currency effects. Exploration & Production International delivered high production, adjusted earnings of $15 million before tax and around $100 million after-tax as a result of a tax settlement in Canada. Absolute and per barrel adjusted OpEx and SG&A costs are stable in the quarter. Then to the MMP segment. MMP delivered adjusted earnings of $229 million before tax compared to $359 million in the same period last year. We saw strong results from sale and trading of gas to Europe, again, beating the spot price. This was partly offset by weaker products trading and refinery margins. The after-tax result was negative $40 million. Due to high contributions from NCS gas trading with a high tax rate and losses in product trading with a low tax rate, MMP ended up with a high tax rate in the quarter. Our renewable business delivered positive earnings in the quarter reported as part of the Other segment. Equinor delivered record-high equity production in the quarter, 2,233,000 barrels per day. New fields on stream, in addition to new well capacity, more than mitigated the natural decline in existing fields and divestments. As previously announced, we expect an average annual production growth of 3% from 2019 to 2026. However, the short-term outlook remains unclear with the market uncertainties and government-imposed production curtailments. Since the last quarter, we have reported new discoveries in Brazil, The Gulf of Mexico, Azerbaijan, and Norway, which will add to our strong non-sanctioned project pipeline. Our renewable segment produced 559 gigawatt hours this quarter, which is a new record and is enough to supply 0.5 million homes in UK. Despite a difficult market situation, we delivered a solid net free cash flow of $362 million. And remember, this is after capital distribution. The net debt ratio increased by 2 percentage points from last quarter to 25.8%, which is in line with the currency effect on reported equity. We paid around $900 million in taxes this quarter. And the capital distribution in the quarter was around $900 million, including the end of the first tranche in the market of our share buyback program at $58 million. Year-to-date organic investments are $2.3 billion. Let me end with our guiding. There is unprecedented uncertainty regarding the global economic outlook. Based on this, it is difficult to guide on expected 2020 production. Nonetheless, we have very strong project pipeline and maintain our guiding of an average 3% annual production growth rate between 2019 and 2026. As part of our $3 billion action plan, the 2020 organic CapEx guiding have been reduced from $10 billion to $11 billion to around $8.5 billion. And the 2020 exploration guiding is reduced from around $1.4 billion to around $1 billion. For 2021, we now guide on an organic CapEx level of around $10 billion. And the average CapEx for the years 2022 and 2023 is around $12 billion. Thank you very much for your attention, and I look forward to your questions, and I’ll pass it back to you, Peter. Thank you.

Thank you, Lars Christian. And with that, I pass that through to the operator to call out the questions. Thank you.

[Operator Instructions] First question is from the line of Oswald Clint of Bernstein.

First question, just around you talked about maintaining the credit rating, which I think, as you said, AA or, I think, stand-alone at least on S&P is probably AAA+. But obviously, this – and the gearing below 30%, I guess, is obviously part of your long-term compensation, and I guess it is featured heavily in the dividend discussion that you had a couple of weeks ago. So my question is that 25.8% today, what do you think is most likely path for that number from here and certainly given the action steps you’ve taken? And how low does it need to fall to again before we can talk about dividend growth again, please? And then secondly, just on this concept of you may reduce activity further if needed, and obviously, the dividend decision implies things were getting pretty tight. So I was curious why you’re still producing nearly 70,000 barrels a day of oil in terms of the Bakken shale, and surely, something like that basin should be dialing back closer to 0, that’s my second question.

Thank you. On production in U.S. onshore and Bakken, we have shut in 15, 1-5, percent of the wells in Bakken, and we have a list of another 10% of number of wells that we will just run to failure, which means that when they need maintenance to be able to continue to produce, and we will not continue that maintenance under current price environment. And we have also stopped all drilling onshore as part of focusing on the value side of it and also helping us to reach the $3 billion action plan in capital sort of improvements. Another asset that we have postponed in that regard is the Bay du Nord offshore in Canada from a CapEx point of view. On the credit ratings, it is stable, but the whole industry is put on the watch list by both credit agencies, and they will pay sort of close attention to how the market develops, I guess, and what the different companies are doing to safeguard predominantly a strong balance sheet. And part of that is to secure a healthy cash flow. As we said when we launched it, we said that we will be cash flow neutral at $25 before capital distribution for the period sort of March and for the rest of the year. And it’s a juggling act in the current environment to deliver capital distribution to shareholders, to continue to invest in a very strong project portfolio and, at the same time, secure the balance sheet so that we have optionality and flexibility. So it’s very difficult to guide on kind of the net debt ratio and how that is going to develop going forward because it’s also highly dependent on the further measures that we might be taking. On the dividend coming back, I felt it almost was like three questions that you put into this. And I guess dividend might be a question that many others are wanting to address too, so perhaps I should just get heads onto this. We have always said that we want to grow the dividend in line with earnings growth, and that is part of our dividend policy. But if you look at our dividend policy, it says more. It says that the Board of Directors, when they’re assessing and deciding on the dividend, they need to look at the market conditions, the commodity prices, and also the financial strength of the company. So this is an extraordinary cut in – under extraordinary conditions and times we are living. And of course, the Board will quarter-by-quarter assess this. So this is more about near-term circumstances than long-term earnings. And when we get out of this, we want the dividend to grow again. And we also want to have competitive capital distributions to our shareholders.

Our next question comes from the line of Thomas Adolff of Crédit Suisse.

Two questions from me as well, please. Just firstly, on CapEx for 2021, your guidance, it might be preliminary, is to go to $10 billion from $8.5 billion in 2020. Can you please comment where the increase comes from? And whether that is contingent on the oil price recovery and the tax release for Norway coming through. And secondly, on gas production near term in Norway, we now have spot and one month forward gas prices below $2 per MBTU. And I suspect most of your sales are now done on day ahead and month ahead. And I remember, you mentioned that your cash costs are somewhere in the range of $1.50 to $2. So is the current spot and month ahead price now forcing you to cut back on gas production? And if so, whether you can quantify that, that would be great.

Thank you. If you go back to the Capital Markets Day, we said that what we need to spend our CapEx to have a flat production going forward amounts to $6 billion so that was kind of an illustration of what we put on top of that is in relationship to growth, both in oil and gas and our renewables business. So now we have taken the CapEx down both for this year and what you see for next year. And I think it’s a couple of reasons why we wanted to see the 2021 numbers, actually. And one was that this is – the reduction in the 2020 spending is not to push into 2021. And so that’s one. But it’s also a confirmation of the flexibility we’re having in our portfolio, but also the growth and to your way of putting it, from $8.5 billion this year to 10-ish billion dollar next year, it is to do with our very strong quality portfolio that we would like to continue to invest in. And this plan has sort of been put in place before the discussions from the industry association with the Norwegian government on tax changes temporarily on nature, though. On gas production near term, to your point, we have well below $2 delivered in Europe for our gas produced out of Norway. And of course, in the current environment, we are perhaps even more than ever focusing on value over volume. So yes, we are pushing some gas from 2020 to 2021 and, in some cases, beyond to – because that has to do with the market conditions and the prices we see further out in time. So we are trying to maximize the results, short, medium and long term. And in many ways, you could also argue that in the current situation, it’s even more important to make the right long-term decisions. The value proposition that we put forward to you is a strong company, very strong operational deliveries also this quarter, very competitive, profitable portfolio to be invested in. And for me, this is more about what this company should look like, and we got positioned at coming out of this downturn that we do not know the longevity of. And we want this company to be in a very strong position coming out of this downturn so that we can have an even better competitive advantage and represent a good capital distribution to shareholders. So this is not about the prices of today or the dividend of tomorrow. This is actually about the longevity of this downturn and to make sure that we are strong coming out of this.

Just quickly ask – go back to question one. How much of the $10 billion for next year is committed? And do you prioritize CapEx spending over dividend growth into 2021?

On how much of the CapEx is committed, I don’t have that numbers straight in front of me. But we still have some flexibility on top of what we have guided, if you want to. Why aren’t we sort of cutting further down from around $8.5 billion to $6 billion, well, that has to do with when we are going to stop project on execution, and that is very, very costly and erodes value. So there is more flexibility in that 2021 number. And we are not prioritizing CapEx spending before sort of dividend. What we want to safeguard number, the top two in the current environment is a strong balance sheet and a healthy cash flow as possible.

Our next question comes from the line of Biraj Borkhataria of RBC.

I have a couple on the balance sheet. You’ve taken some large impairments today driven by 1 year of low prices. But long-term testing is still at $80. So as you have the chief accountant on the line, I was wondering if you could give us a sense of what the impact on equity would be like if you run $50 or $60 long term. And also when you think about the balance sheet, gearing is obviously heavily influenced by equity. When you look at it internally, is that the most relevant measure? Or should we be thinking about net debt to cash flow? And is there a limit you’re trying to keep within on that basis?

We see very, very low prices currently. And to me, whether the prices are at $30 or $27 or $22 or next day, month to $34, in many ways, it’s interesting, but what I think is really, really important in the current environment, is whether you believe this is going to last for a period of time or not. And that is going to be kind of the wear and tear on different companies and the balance sheet. So you need to be in a position to weather off that longevity. And when we do impairment testing, it is the forward prices that we see in next three years, and then it is our assumptions from then on onwards. People are asking the $80 that we have out in 2030 is too high and we should reduce it. And if you do, then you have more impairments. I think it’s very, very difficult to have a very firm view on the oil price, commodity prices in 2030. When I studied finance, they said that the best estimate for tomorrow’s price is yesterday’s price or today’s price. I don’t think that the best estimate for 2030 is today’s price. Low prices is actually a good driver for increased demand in oil and gas. What you see now of companies shutting in production, and some companies even filing for Chapter 11 and going down that path, there will be underinvestment’s in new production capacity if you factor in the decline that all assets are being faced with after they reach plateau production. So yes, the jury is still out there what the prices will look like in 2030 and onwards. We have a yearly process, a very thorough process that we have started, and we update our economic planning assumptions third quarter. And I think this year it’s going to be even more difficult than ever to have a firm view on that. We will have a firm review on that and make up our mind and that’s why we have started somewhat earlier this year because it is difficult to assess given all the variables and moving parts. Orjan, do you want to follow up on the impairment side of it?

Yes, I can give a short comment. Of course, other price assumptions would kind of – could lead to a bigger impairment. And I just want to refer to the footnote in the annual report that we published on the 20th of March on Note number 10. We give a sensitivity of reducing kind of the fuel price curve. And then we give kind of reducing the price curve by 30%, just to give an illustration. And that gives a US$15 billion pretax impairment effect. This is – it needs to be kind of handled with caution because this is price-only effect. And of course, if we kind of believe in a 30% reduction, we would also have done other measures that would then lead to the number would not be US$15 billion. But on a pure price only, we indicate in the footnote number 10.

Our next question comes from the line of Jon Rigby of UBS.

I just wanted to ask a question about the production portfolio at the moment. I take the point that you’ve withdrawn guidance for this year. But can you just take a tour of your portfolio and just sort of indicate where you think there is risk to production? So I’m thinking – you talked about the Bakken, OPEC Plus, other economic issues, gas, Norway curtailments, et cetera. And then just rather technically, are you able to give any insight into where there’s sort of physical risk or an absence of physical risk, of shutting in production within the portfolio?

Thank you. On production for this quarter compared to last quarter, we are up 3%. If you compare this quarter’s production to a rebased first quarter last year production, meaning that you adjust for divestments, and that is predominantly Eagle Ford and Lundin, then we are up 6%, and so a strong sort of production and growth. Then on a forward-looking basis, a risk to production. In the petroleum law in Norway, and you accept that when you take on equity in a license, the government of Norway have secured their right to impose production curtailment when and if seen – deemed necessary. And I think the last time they did so was in 2002, if I remember correctly. So all partners in the licenses have received a letter from the ministry and where it states that they will utilize that right. And we have all seen the production cut. But they are also saying that if licenses in very tail end kind of a marginal, then they might say that you do not need to cut your production because then they will just make it even worse, and perhaps that asset needs to shut in. So it is that juggling between the different assets I think that the ministry is now working out the details. We have no insight into that, and there is no dialogue between us or other companies with the government in that regard. They have full insight to everything through the monthly reporting and also the production plans that all companies or operators are putting forward. So then you could say that there might be a risk on the face value for some of these really tail end assets but – from a curtailment point of view. But that measure might end up that not being the case, and then many more assets are perhaps safer from that aspect of it. I think also that many oil producers, us included, is kind of faced with a little bit of the same situation than onshore pure gas producers have been for a long, long time, and that is if you have an asset start having red numbers or negative numbers, you still have high fixed cost. And you continue to produce as long as you are able to cover at least some of those fixed costs. And in many ways, that will just prolong, you could argue, the gap between supply and demand. So then it’s more about whether you have a balance sheet to better off in that situation. And we do have such a strong balance sheet. As I said, we are going to do more adjustments in the number of wells and shut in more wells as they run to failure, onshore U.S. And other than that, we have had some delays in a few projects. Martin Linge will start up a little bit later. For example, Bergen Phase II might start up a little bit later than end of this year. Beginning, of next year instead. So – but that’s more from a project execution point of view given the coronavirus and the manning situation on different installations or different sites, meaning yards around the world.

And just on the – I’m not the geologist. So are you able to sort of give any feedback on where there’s risk of tamping down production, reducing production, shutting in production for future production either because of the implications for the reservoir or indeed for above-ground facilities in doing that? Or are you able to manage through that?

I mean shutting in separate wells is or kind of choke it in to reduce the flow is quite easy to do without any sort of major impact. Shutting in whole – the whole installation is also something that we do from time to tome and we have turnarounds, major maintenance overhauls. So both stopping and then preparing the plant to be shut in for a period of time safely, to ensure a safe working environment, if that is the case, from a maintenance point of view, or being able to start up the production again, all the installations have plans like that so – already and utilized several times and improved over time. So that side of it, it’s easy. Then you might have a few cases where the subsurface is of such a nature that it is harder to start up again. We are not in the oil sands, anymore. The SAGD, for example, steam-assisted gravity drainage, that if you shut in wells and that steam is then condensed into water, it’s almost impossible to get that well up and producing again. So I think it is more to the nature of the different assets, and we have very, very few assets of that nature if any, actually, if I think about it, and in those cases it’s hard to start up again. We usually have submersible electric pumps that helps us to produce even today and that will help us to kick start when we start-up again. So it might be a few, Jon, but not many and not of a material impact at all, not – you won’t see the dent in the production numbers even, I believe.

Our next question comes from the line of Teodor Nilsen of SB1 Markets.

I have two questions. One is a follow-up on production. I definitely acknowledge the fact that it’s hard to guide on production going forward. But just looking at Norwegian Continental Shelf and announced production cut, it looks like Norway’s production will come down approximately 4% compared to NPD’s annual production forecast. So how should we think about our changes to your NCS portfolio? Is like 4% a fair share number on annual basis? Or is that a way too low reduction? Second question is if you could comment briefly on price differentials achieved this far for second quarter.

That’s production cut, the 4% you’re referring to, I guess it’s based on the 250,000 barrels a day number, or is it a combination of the 250,000 and the 134,000?

Yes. It’s based on 250,000 in June and 134,000 for the remainder of the year.

Yes. No, I mean, if you’re looking at it from the outside, I guess that’s a good starting point. But be mindful then that this is liquids production and not gas and also not related to gas with associated liquids if those gas assets are to deliver on our sort of commitments to the European market. So be mindful of that difference. And then on top of it, for us to be able to guide for this year, it is also to do with how much volumes you are moving from one year to another from value optimization point of view. So that’s why we are saying what we are saying, that it is very, very difficult. Before we know more details around the production curtailment asset-by-asset basis, and so we will see second quarter if we are in a better position to guide you on what the production for this year will look like. Price differentials, very important factor to watch. One thing is Brent or ICE Brent that you read about in the papers on a daily basis. Another one is dated Brent, which is the one that we use to get our realized prices. Usually, those two have followed each other very closely. One, it is very seldom, perhaps $2 differential between the two, up or down actually a little bit on both sides, but the differentials have usually been around $1. And this has nothing to do with the quality differentials on the oils, the different oil qualities. This is between the two price stacks in many ways. And now we see a totally different widening of this. $6, $7, $8 is not unusual if you look at the history over the last couple of weeks and months. So I guess that’s a factor of – an illustration of how companies are able to evacuate their volumes in many ways or sell their products. We have seen a drop in demand from many refineries given the demand weakening. And then we have the oversupply and also our overhang, a huge sort of storage buildup. So yes, we will see how that develops going forward. Anything to add to this, Svein, from your point?

No. I think you have covered it well. It’s both and, as you said, the dated versus Brent and then the great differential, and you see difference within the different grades and some other light ones, which goes then towards most of the jet fuel, so which has gone a bit out compared to earlier.

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

A couple of questions from me. Firstly, I just wanted to touch on CapEx. Could you just remind us how much within the current 2020, 2021 guidance now is related to renewables and how much of that renewable spend step up in 2022, 2023 and whether there’s any particular impact of that investment plan from the recent things? Also, should we – should it be fair to assume that if tax proposals coming as expected, or as the industry hopes, I should say, would you increase CapEx in the shorter term with free cash flow still being neutral? And then my second question, just a follow-up on what you said regarding realization and price realizations. Can you just tell us where you’ve been able to sell your cargoes through May and June for all your production or whether we should actually start to see some fields close back as a result of lack of refining, demand?

So on CapEx spending, if the tax proposal comes through as before from the industry association, this proposition then will give more visibility over a certain period of time and make it – create liquidity, increased liquidity for the companies, too, so that they have more certainty and thereby invest and sanction new activity. And this proposition too improves the breakeven and profitability, a healthy sort of dent in the right direction. And then it’s more kind of on the engineering side of it, I think, on new activity more than sort of construction because those assets are already – have been sanctioned. So this is going to then be prioritized within the current frame. And if these assets improve materially their profitability, then we need to reshuffle the project portfolio of unsanctioned projects and prioritize within the frame that we had set. On the CapEx spending within the renewable space, $0.5 billion to $1 billion for this year and next year and $2 billion to $3 billion annually, 2022, 2023 was the numbers we gave you at the Capital Markets Day. We have – are not in a position to give you any updated numbers in that regard. Those projects that are in the pipeline within the renewable space like Dogger and Empire Wind are progressing. But those projects alongside all the oil and gas projects need to be prioritized but also really work and perhaps rework even one more time to see if they can improve their profitability somewhat more. And then it was a third question related to – the sale – the volumes. And we are able to sell volumes. We are working in the normal channels that we are having and also working on some new channels. And in some cases, we are taking the volumes further away. So that’s partly why you see some of the changes in inventory. More volumes on keel – on ship in transit, but no problems so far on that regard.

Yes, just to add to the last question to what you said on the CapEx and just reminding that, that it is gross CapEx for the renewables. And as we said, that we also do project financing of it. So our net CapEx into our organic CapEx will be lower.

[Operator Instructions]

Our next question comes from the line of Lydia Rainforth of Barclays.

And I’ll just keep it to one. You talked earlier about how you see the company being positioned coming out of the crisis. Within that context, can you talk about how – whether you think the risk/reward profile has changed between also still projects and some of the institutional spending on the renewable side of the investment.

Lydia, you were breaking. Could you please repeat that question?

Yes. So it was effectively thinking about – do you think the risk/reward profile has changed between the traditional fossil fuel projects and the renewables and new energy investments given what we’re seeing and just in the context you talked about how you want the company to be positioned coming out of the crisis?

I think coming out of this, I mean, we have a very strong pipeline of projects, whether that is in the oil and gas space or the renewable space, to bring us to 2026 and to a certain degree beyond. So coming out of this, it is more about being in a position to give competitive capital distribution to shareholders and growth in that regard but also to be able to take advantage of some more opportunities that we assume are coming as this moves forward in this current price, sort of commodity price environment. Having that said, you must not understand me that we are going to buy and buy stuff aggressively on the contrary. But of course, as a prudent company, we need to look at opportunities from an M&A point of view, but we will be very, very picky as to what we take on. It better be very, very good, and it better be possible for you guys to do a back on the envelope calculation and say thumbs up, this made sense. So yes, the bar has been risen. And we have tightened internal requirements when it comes to economical parameters for sanctioning projects to drive and spur sort of even more improvements.

Our next question comes from the line of Martijn Rats of Morgan Stanley.

I only have one. I wanted to ask you about CapEx and the dividend in the sense that it seems to me there are somewhat conflicting sort of signals there. The dividend has come down very significantly, of course. And what is embedded in that is a signal that the management does not see this as just another downturn that is cyclical in nature and that will ultimately come and go. But in that dividend is embedded the signal that the management sees the future weaker than the past and this is more than a cyclical downturn. But then the CapEx guidance goes right back to the levels that you guided previously earlier in the year and 10, 11 for next year and then, ultimately, that $12 billion figure for 2022 and 2023, particularly that $12 billion figure is unchanged. And what is – what you’re sort of signaling in that is that this is a cyclical downturn and that the future is unchanged, that there is no structural change. So I find there’s somewhat of a conflicting message in that. And I was wondering how you expect us and others to interpret what you’re really saying there.

On the – first, on the CapEx side of it, we guide more than one year on our Capital Markets Day. That’s when we give you an outlook for more than one year. And then the quarters in between, we will give you an updated guiding on this specific year, meaning 2020. That’s why we haven’t given you any change in the CapEx number of the $12 billion that you referred to. But we thought that it will be good for you to see that what we’re not – what we’re doing now on the CapEx side for 2020 is not going to pile up and increase the CapEx spending for 2021 because we believe that this situation might easily last into 2021. On the 10 to 11, we have taken it down to around 8.5 for this year, so I think that is a signal in line with that we are also taking down the dividend in that regard.

Our next question comes from the line of Christyan Malek of JPMorgan.

We’re getting a lot of investor questions and just around the framework on your dividend policy. And I mean specifically for the remainder of 2020, the key triggers for further dividend revisions either up or down. So would you care just to – I know you’ve gone through this, but why is it you didn’t go up for the whole year? Why is it that you’re – it sort of seems a little bit opaque in terms of just the part of that dividend particularly from sort of direction of travel for the balance of this year? Just want to understand the dynamics behind it. And can you be a little bit firmer in terms of what you plan to do with the 2020 dividend, if that’s possible? The second question is in terms of CapEx allocation for next year. I know there hasn’t been divisional guides regarding new energies, but I would be interested to understand how this may trend, particularly with your greater focus on transition ambitions to scale up renewable and non-oil sales. And so just coming – so following on from Martijn’s question. To what extent does this crisis make you reevaluate the sort of the marginal dollars into oil versus energy transition?

Now on dividend, I mean, this is for the Board of Directors to decide on a quarter-by-quarter basis. Now we have decided for first quarter this year, and then we announced the second quarter financial statement in July, we will give you the dividend proposal or the decision for that quarter. This is an unprecedented cut or extraordinary cut in – under extraordinary conditions, and cutting again perhaps is a trend because then you do it twice. We have taken a cut – extraordinary cut, in which we believe that in the current environment that we will be able to start building from in due time. But then there is no guarantee for any sort of changes in either direction on a forward going basis because the dividend policy stays firm, and we need to look at the financial strength of the company and also the commodity prices at each point of time and the outlook going forward. So that’s what I can do to help you on that side of it. And on the CapEx side, I get that question many times, whether I should prioritize oil and gas or renewables, which is kind of a vertical cut to me, it’s more a horizontal cut. I see really good renewables projects and really good oil and gas projects. And then I see it not so good in both categories. And for us, it is more about making sure that we sanction projects that are above that horizontal line and necessarily prioritizing between the two. But our strategy remains firm to a point, but we want to move and broaden into sort of an energy company with a good position in both oil and gas for decades to come as well as growth in renewables. And we have the portfolio in-house in many ways to do so over the short term.

Can I just intervene and say we’re getting close to the hour, we are able to overrun and extend a little bit. [Operator Instructions] And if there’s any other, obviously we can follow-up with Investor Relations.

Our next question comes from the line of Yoann Charenton of Societe Generale.

So maybe to avoid again asking on dividend, I would like to focus on U.S. tax losses pool, if you don’t mind. Will you be able to provide some color on the amount of tax loss carryforwards available to you in the U.S.? And if not, can you please provide some indication on the outlook for depleting such tax loss pool?

The unrecognized deferred tax asset in U.S. is around US$4 billion. We expect to utilize this over the next 10 years or so. But to recognize this, there are very strict rules. And that is kind of the determined factor as sort of the timing for when we can start utilizing that tax asset. Any comments to this Orjan?

No, just to confirm that what you say is correct. And this follows from the accounting standard that you need, so-called convincing evidence, if you have had some years with kind of more challenging results, you need convincing evidence when you can recognize. So – but we have been close to starting to recognize, but we haven’t done it yet.

Our next question comes from the line of Anders Holte of Kepler Cheuvreux.

One question. I guess it’s going to have to be on the proposed tax change by the Norwegian government. Your CEO was already at the press quoting and saying that the tax changes, they improved breakeven levels by about $1 per barrel on a mobile oil field that you have pulled these tax changes through. Looking at those changes, they will notably impact your IRR, and also impacts your NPV, the cash flow timing effect. So what valuation metric he is referring to when he sees that breakeven is not improved by more than $1 per barrel?

It was kind of a poor line, but I’ll try to do my best and then please follow up if there is anything that I missed out or misunderstood on this. The proposal that is on the table is sort of marginally improving the breakeven for projects. And the way we look at it, will not lead to more activity than what is already kind of in the making. And if the government wants to stimulate to more activity, we need sort of improvement in profitability and also improvement through liquidity improvements. And that, I believe, is what the industry association is discussing with the government before they put a proposal forward to the Parliament to be debated before there is a decision to be made. Anything to add Svein?

I think you covered it well. There’s a huge difference between the industry proposal and proposal from the government as we see it. And as was also said here earlier, that as we see the government proposal, it will improve by less than $1 due to reduced uplift.

Our next question comes from the line of Alastair Syme of Citigroup.

Can you talk around how long you can run production at the current reduced manning levels? You’ve clearly got severe restrictions on movement in social distancing. I’ve been through Bergen airport, and I see all the flights to the south of Spain. So I suspect a lot of your workers don’t even live in Norway. So can you please talk a little bit about that?

We have a few offshore workers living in Spain, and do surf and kite and whatever, I don’t know, but not that many, actually. But we haven’t had any corona cases, as I said, that have impacted the production. We have taken down the manning offshore and maintenance and projects and that to reduce the likelihood of some spreading of the coronavirus, resulting COVID-19 disease. And we are sufficiently manned to do safety critical maintenance, and the regularity is very, very good. This quarter is a quarter with very good operational performance in general across the whole board. Record high production both in oil and gas, as I said, and renewables. The cost is coming down, Opex, SG&A, 13% year-on-year, and unit production cost 6%. So yes, I’m very impressed and happy with the efforts that I see that my colleagues are putting in to make the wheels keep on churning and production – keeping the production up.

So it is the only thing that’s really happening then, we’re sort of impacting on future growth? Is that really the issue?

I think there is something about future growth on top of what we already are investing in. That is the big question. So – but we are still able to deliver on the cumulative annual growth rate of 3% from 2019 to 2026 with the existing plans. So in that regard, you’re talking about production beyond.

Our next question comes from the line of Michele Della Vigna of Goldman Sachs.

One quick question. I wanted to ask you about the Baccalieu field and the investment decision there. Clearly, it’s a very large, very important investment decisions, sits low on the cost curve. Is this something that you would be happy to go ahead with given its attractive returns? Or you think you would be more prudent to delay in order not to take on more commitment for CapEx given the uncertain macro environment?

Well, the Baccalieu is part of our non-sanctioned project together with several other projects. We need to sort of come back to the timing and the phasing on different projects at a later stage because, currently, we are working through the portfolio and reshuffling some of it. So far, we have announced the two-year delay on Bay du Nord and also stopped the drilling onshore in U.S. So this is highly dependent on the outlook as we see it, more or less, almost from month-to-month. But I also think that in the current environment, it is good to draw experience from the last downturn where we learned very good that there is value also in turning back the project and ask them to go over it one more time to improve the breakeven in economics. I’m not saying that we have done so in the case of Baccalieu or are going to do so in the case of Baccalieu. I’m just saying that with the tighter investment criteria, the tightening of the investment criteria, people need to really look at their projects and see if they can make it through that sort of door, which is now – I’m not saying it’s closed, but it is not that wide of a door as it used to be when it comes to sanctioning project from an economical point of view. But it is one of our best assets in our portfolio, to your point, but no update in that regard on timing.

Thank you. And that was our last question, so I’ll hand back to our speakers for closing comments.

And just can I just take this opportunity to thank Lars Christian for the presentation. I know that there were a couple of questions that we weren’t able to get round to at this time. We will follow up directly with those. And with that, I’d like to thank everybody. Everybody stay safe, and we will be in touch. Thanks a lot. Goodbye.

This now concludes our call. Thank you for attending. Participants, you may disconnect your lines.