Ladies and gentlemen, good morning, and apologies for the slight delay to the start of this call. I'm delighted to welcome you all to our second quarter 2020 analyst call. With me on the line in Oslo, we have Lars Christian Bacher, the CFO; and Svein Skeie, who's the Head of Performance Manager. Also joining the call is Ørjan Kvelvane, he's Head of Accounting. He's calling in from Stavanger, and I'm here in London. With that, I'm delighted to pass straight over to Lars Christian to start the call. And we will have, after this, questions for the rest of the hour that we have on this call. Thank you very much.

Thank you, Peter, and good morning, everybody. We really appreciate you joining us today. I hope that you, your families and your colleagues are all doing well. Let me start by saying that this has been a second quarter and a first half year like no other. Our most experienced traders call it the most dramatic quarter in oil market history. In April-dated Brent, the reference price for most of our liquid product sales, reached a low point of $13.20 per barrel. And at one point, the WTI plunged into negative territory for the first time in history. In addition, European gas prices were at the lowest in more than a decade. Prices have since partly recovered, especially for oil. But Equinor remains well prepared for continued volatility going forward. Many countries are now gradually opening up. But the path toward recovery from the global pandemic remains tentative and uncertain. At all our locations, offices, fields and facilities, the safety and well-being of our people are top priorities. This year, we have really seen the value of having solid contingency plans for low-price scenarios. We took rapid and forceful actions to protect our financial position in an extraordinary situation and we now see the effects. Costs and CapEx are down. And through the suspension of share buybacks, cutting dividend and bond issuance at attractive rates, we secured our liquidity and financial flexibility. And thanks to a quick and effective action, we have had less than 1,000 barrels per day in production loss due to COVID-19. Our results are, as expected, impacted by the prices in the quarter. However, Equinor was able to not only capture significant value but also provide the flow assurance needed for stable and reliable operations. We delivered record-high results from our MMP segment with very strong trading results within crude and liquids. As CFO, I'm happy to see the organization continue to deliver cost reductions and solid operations. We are also progressing our quality portfolio of projects under development within oil, gas and renewables despite delays on a small number of projects due to COVID-19. The very low prices increased our net debt ratio to 29.3% from 25.8% at the end of Q1. Going forward, we will work diligently and systematically to continue to strengthen our competitiveness. Let me spend a few minutes on the temporary tax changes in Norway. In June, the temporary changes in the petroleum taxes were decided by a broad coalition in the Norwegian Parliament with the purpose of maintaining investments, activity and value creation in oil and gas industry. To operators and suppliers in Norway, including Equinor, this secures frame conditions, which makes it possible to continue progressing with planned profitable development projects. For 2020 and 2021, we can now fully expense all NCS investments against the 56% special petroleum tax rate in the year they are incurred rather than over 6 years. For 2020 and 2021, the uplift have been increased from 24% to -- to 24% from 20.8%. And we are also allowed to expense the uplift towards the special tax the year we invest rather than previously over 4 years. These changes will also apply to new projects sanctioned by the end of 2022 with impact on tax and cash tax or cash flow in subsequent years. Over time, the temporary changes are close to neutral cash-wise and in nominal terms since the taxes saved due to direct expense will be paid back late in later years. So to the effect of the changes to Equinor as a company. These temporary tax changes provide liquidity and enhanced project economics. And under these terms, cash tax charges from second half will be materially lower. Indeed, we expect the next settlement due in August to be a cash receipt of around NOK 1.5 billion. The changes in fiscal terms increase the profitability of our project on the NCS sanctioned by 2022 and improve break-even prices by around $10. Such improvements will influence the ranking and phasing of projects. And now I move on from tax. As we have tackled the demanding market situation, our strategy remains firm. We are developing as a broad energy company and aim to create long-term value through the energy transition and in a low-carbon future. In the quarter, we have achieved milestones on the climate ambition we communicated earlier this year: approval of the PDO for our floating offshore wind project, Hywind Tampen; the investment decision on partial electrification of Sleipner; investment decision on Northern Lights project for transportation and storage of CO2. In line with our dividend policy, our Board of Directors have considered expected cash flow, capital expenditure plans, financing requirements and appropriate financial flexibility. And again, such a difficult quarter in terms of prices, the Board has decided on a dividend of $0.09 per share for the second quarter '20, at the same level as for first quarter 2020. Let me then turn to the quarterly results. And as usual, I start with our safety performance in the quarter. We have a systematic and proactive approach on safety and security. This quarter, the efforts have been particularly focused on preventing the spread and impact of COVID-19. We report a Serious Incident Frequency of 0.6 and an overall injury frequency rate of 2.3 million -- 2.3 per million working hours the last 12 months. Compared to 2019, this is an improvement in overall injury rate while the frequency of serious incidents is at the same level. Let me then go into more detail on the quarterly financial results. Our realized liquids price in the quarter was $22.9 per barrel, down 61% from the same quarter last year. This is below the average dated Brent for the quarter at $29.2, mainly explained by differentials for the light and the qualities. Our average European invoiced gas price in the quarter ended at $2.24 per million Btu, down 59% from the same quarter last year. In the U.S., our average realized gas price was down 37% to $1.47 per million Btu. The IFRS net operating income in the quarter was negative $472 million, down from $3.5 billion in second quarter last year. Adjusted earnings were $354 million positive, down from $3.2 billion. We are happy to report that we are on track to deliver the $700 million cost reductions announced in the first quarter. The temporary changes in the tax regime have some special effects on our after-tax results this quarter. As a consequence of increased uplift applicable from January, we also recognized a benefit for the first quarter in second quarter, which contributes to a negative tax rate of 82.3%. After tax, we delivered a negative IFRS result of $251 million, down from $1.5 billion last year, while adjusted earnings after tax were positive $646 million, down from $1.1 billion. Then to the segments. From this quarter, E&P U.S.A. is a separate reporting segment and we provide increased visibility of renewables within the Other segment. E&P Norway delivers negative adjusted earnings of $85 million caused by very low prices for both oil and gas. We have chosen to defer significant values -- sorry, significant gas volumes to periods with higher expected prices, and we have adhered to government-imposed oil production cuts in June. E&P Norway delivered strong operations in the quarter with underlying operations cost down 8% per barrel. E&P International delivers negative adjusted earnings of $379 million. This result is due to the low prices combined with lower production and higher depreciation per barrel. At the same time, we also see a clear cost reduction in this segment. E&P U.S.A. is also affected by the very low prices. The segment delivers negative adjusted earnings of $341 million. In the U.S., we see the biggest cost reductions with a 12% reduction in the underlying operating cost per barrel and a 22% reduction in adjusted operating and administration costs. We have substantially reduced drilling and completion activity onshore to adapt to the market situation compared to the same quarter last year. The Marketing, Midstream and Processing segment delivered record-high adjusted earnings of nearly $1.2 billion this quarter. The record result is mainly due to strong contributions from oil trading, capturing value in volatile markets, benefiting strongly from taking positions backed by solid assets. Renegotiations of gas sales contracts also contributed to the adjusted results with a one-off effect of around $150 million. In our Other segment, we get solid contributions from our renewable plants in operations of $38 million in net income. After adjusting for costs, such as progressing and maturing our next milestone projects, Dogger Bank and Empire Wind, the total reported result for NES was around 0. Equinor's equity production in the second quarter was 2,011,000 barrels per day, on par with the second quarter last year. In the quarter, we delivered a high production efficiency with increased capacity from new fields and wells and had no turnaround activity offshore. Against this background, a good operational efficiency, volumes on the NCS in June were affected by the curtailments announced by the Norwegian government. Also, our international business was impacted from OPEC Plus actions. Adjusted for divestments of assets and government-imposed production curtailments, we still delivered an underlying production growth of more than 4%. We put value over volume and moved significant gas volumes out in time to periods with higher expected prices, mainly on the NCS. On the NCS, it is notable positive that the liquid production growth is 33%. The start-up of Johan Sverdrup with very low operating cost is the main driver. Let me also mention that we made 3 commercial discoveries in the quarter while 2 wells are still under consideration. So far this year, we have made 6 commercial discoveries in Norway and internationally, which bodes well for future value. The production from our renewable business was 305 gigawatt hours after conducting maintenance at Dudgeon. Adjusted for the sale of half of our ownership interest in Arkona, production is at about the same level as last year. The cash flow slide represents first half of the year. Note that the cash flow from operations is affected by the prices in first half 2020 while the taxes and dividend paid are related to 2019. We paid taxes of $2.6 billion so far with $1.5 billion related to NCS in the second quarter. Dividend payments in the first half totaled $1.75 billion. Organic investments are at $4.1 billion while we sold our shares in Lundin Energy for $332 million at a good return. The net debt ratio at the end of the quarter increased to 29.3%. Before I move to outlook, I would like to mention that we maintained our strong credit ratings, and we have also received ratings for our affiliates Equinor New Energy and Danske Commodities. Both achieved BBB+ equivalent ratings and are strategically important to Equinor, creating value through the energy transition. So let me end with our guiding. We will continue to put value over volume and make active decisions to create value in demanding markets. This makes it difficult to commit to a guiding on production growth in 2020. But we still expect average annual production growth of about 3% from 2019 to 2026. Exploration activity is expected to come in at around $1.1 billion. This is slightly up from first quarter, partially due to the drilling of appraisal wells around new discoveries. Our guiding for organic investment remains unchanged in U.S. dollars at around $8.5 billion and around $10 billion in 2021. However, note that we have used an exchange rate of NOK 9.5 per U.S. dollar, down from NOK 11 per dollar last quarter in our guiding for exploration and organic investments. And with that, I'm pleased to open up for questions, and I hand it back to you, Peter.

Thank you, Lars Christian. And we do open up the questions, and I'll pass it back to the operator to remind you of the polling.

[Operator Instructions]. Our first question is from Oswald Clint from Sanford Bernstein.

Just on the -- some of the sanctions in the quarter, specifically Northern Lights, I mean, obviously, still questions around, I guess, economic viability of CCS projects. So I just wanted to see if you could shed any light on how profitable do you see this project or really how we should think about profitability of this project, especially if it does become a big $2.5 billion, $3 billion CapEx project. That's the first question. Then secondly, related to the report, it's a risk that I saw popped up last quarter and is still present this quarter, and you're calling out risk around force majeure clauses around both suppliers and customers. So I mean I know you can't quantify any impact yet. But can you say how those conversations are going through the last couple of months into July? Has this risk diminished? Or is it still unchanged today?

Thank you. It is the ambition of the Northern Lights partners to achieve by 2030 cost levels for transport and storage in the range described in the IOGP report that potential for CCS and CCU in Europe for this type of project of around €30 to €55 per tonne of CO2. So this is, how to put it, a supply chain in many ways that needs to be put in place. So for us, our part of this is more from transportation and storage. And then other companies need to sort of look at the possibility for them to capture it for the totality of this to be realized. And could you then please repeat the second part of your question?

Yes. It's just around, I mean, one of the risks that you put in your quarterly reports. It appeared last quarter, it's here again today. It's around some of your suppliers and customers seeking to potentially enact force majeure clauses within contracts. And it's -- as a consequence of what's happened. So I mean you say you can't quantify the impact. But I want to know which are those gas contracts we're speaking about and has the risk diminished or it's impossible to say here.

I can hand it also over to Ørjan to comment on this in more detail. But I think that it's still a huge sort of uncertainty as to sort of how the whole supplier market is going to develop and the relationship between buyers and sellers of product, too. But all in all, I think it is somewhat of a better position at the end of this quarter than the previous quarter, than everybody looked into a steep fall in activity and prices. And at least now, we have some more visibility, even still with a huge uncertainty, how this is going to be panned out. Ørjan, any comments? Ørjan Kvelvane: So just to support your comment, Lars Christian. So this is related to what we write in Note number eight and we point to the uncertainty out of what has happened in the recent period. We assess this every month and every quarter. And there is no significant kind of development in this segment. But we need to keep it in due to the situation.

And our next question is from Biraj Borkhataria from RBC.

I have two, please. The first one is on cash taxes. You mentioned the rebate in the third quarter. I was wondering if you could say anything about the rest of the year. And you have your accountant on the call, so I guess, just wanted to try and get a rough sense of the cash tax potentially based on the prevailing commodity prices for the rest of the year. And the second question, I appreciate you breaking out the renewables segment. I guess the $38 million in earnings is better than definitely I expected. I was wondering if you could just clarify whether that is purely the generation side or whether the Danske Commodities electricity trading goes into that number as well or whether that goes into MMP. And as you did break out the U.S. business today, could you just comment on what you need to see from the renewables segment to start breaking that out as a separate business as well?

On the last part of the two questions, Danske Commodities is reported as part of the MMP segment. So this is purely from the renewables assets in operations. The numbers that we refer to are under the Other segment. We have said that 1 day renewables will be reported as a separate segment. It has to do with sort of materiality. And it is then a question of time before we get it to it. If we look at production numbers or returns, earnings, it will take a very, very long time for renewables to be material if you compare it to the oil and gas segments. So this, for us, it has more to do with material on its own sort of merits. And with the portfolio that we are having, I would argue that, as that progresses 1 day, we will be having a material position to start reporting it as a separate segment. And until that day, we are going to gradually, as we stated out with at the Capital Markets Day in February, to give you more visibility and granularity. And we give you somewhat more this quarter in the notes. On the cash tax, there will be sort of a NOK 1.5 billion effect in August, a positive for us to put it within those wording. We are going to do the calculations, the tax calculations in September for this total second half of this year. And until we've done that, we are not in a position to guide you on the tax -- what are the cash tax for the second half.

And our next question is from Thomas Adolff from Crédit Suisse.

The first question is on the dividend. And obviously, you're right at the 2Q sum doing quite well and the second half, you see strong free cash generation. But obviously, gearing is at the upper end of where you want it to be. And there may be some impairments with the third quarter results. Maybe perhaps you can share some updated thoughts here, if any, if there's been some changes to the tax regime in the Norwegian continental shelf maybe that will mitigate some of the potential impairments. So if you kind of combine the free cash generation potential and where gearing may be at the end of the year, how should one think about the dividend at which point you're happy to again raise it? And then I guess, the second question is just on the conversation you're having with your relationship banks. Obviously, investors are looking more closely where the money is invested and banks are looking hard at where the money is lent to. Do you see any changes in the conversations you're having with your relationship banks being a fossil fuel company?

On the discussion with the banks, so let me then start by even more of a helicopter view. The discussions that we are having with banks, investors, analysts and the like, I think the ESG topic has risen on the agenda. It is, especially in Europe, in many places. But I will also argue strongly that it is on the table for the most executive committees and boards in most of the U.S. companies and Canadian companies, too. And a lot of the discussion is actually about maturing our understanding and own understanding of what this is and what it's not all about, and in many ways, who are the good companies in this on a current status basis but also on a forward-looking basis. So we get a lot of good comments from bankers when it comes to our strategy, but even more so, our position, the current portfolio that we have, not only an active strategy and active ambitions when it comes to climate but also that we can actually back it with the quality oil and gas portfolio but also a quality renewables portfolio. So no questions of sort of a negative nature when we have this year borrowed money both in the euro market and in the U.S. market. On the dividend side of it, for -- we have said that when we, 1 day, will start looking at increasing the dividend again, the $0.27 per share is a good sort of reference point. And for us to start increasing the dividend again, we need to see more visibility both when it comes to sort of our own position in this but also the market outlook going forward. And we both live and see a huge uncertainty or volatility. So that remains somewhat to be seen for us to make that -- or such a decision. On the gearing, it's just south of 30%. And we have said that we are fine by having above for periods of time. So we have a very strong balance sheet. We have a very strong project portfolio. And we have a growth story towards 2026, despite of, in many ways, all the measures that we have taken to secure liquidity. On the impairments and, if we get any when we revise prices, that remains to be seen. And you said third quarter. I can't sit here and comment that we're going to adjust the prices in third quarter and by that, having impairments. If that were the case, then I should have done it yesterday in many ways. So we believe in the prices that we are having. And then we are looking at the development of different factors. And when -- and we do so on an ongoing basis and we will do a revision of prices when we believe that there is a solid round for doing so. And there are good reasons for believing it should be taken down, but it's also good reasons for believing it should stay high or it could be taken up also. So perhaps a little long answer, but I guess I would get some questions about the prices, too. And a lot of people are focusing on the demand side and how COVID-19 affects the demand side, definitely been affected by it in the short term since February, March. And one could argue that perhaps the demand medium term has been softened based on this. But you shouldn't forget either the supply side, huge uncertainty on the supply side, too. That has to do with the capacity in the industry. With consolidation in the supplier industry, the capacity will be taken down. And that will be a limiting factor of the total capacity that the industry then can have to deliver new volumes. We see that the risk appetite have been taken down by many companies. Projects have been postponed and canceled. So the willingness to sanction project has also softened. So this is about balancing then those 2 to make a view. And what we did this quarter is that we stick to the $77 in '25 and the $80 in 2030.

And our next question is from Alastair Syme from Citi.

Just one question really just on CapEx and Norwegian tax. So the CapEx change is obviously 0 in dollar terms. But there is a double-digit move in krone terms. So can you just sort of explain the moving parts there? And I kind of thought the principle of the tax change was meant to preserve investment. And then as sort of a follow-up, I wonder if you could elaborate on the point that you made in your remarks about Norwegian tax changes will influence the phasing and ranking of projects. What are you specifically referring to there? Is there any difference between the way you think of greenfield and brownfield or oil or gas? What do you mean by the ranking?

Well, I'll leave the first question to Svein, the CapEx and tax side of it. But I can start by answering your second question. Our project portfolio, the unsanctioned project portfolio, is kind of a moving target from the point of view that there is a healthy internal competition among the projects has to be among the best ones so that they can make sure that their project is sanctioned. And of course, a big sort of improvement in the economics, a reduction of $10 per barrel breakeven-wise for many projects now over the next couple of years, 2020 to 2022. Of course, that reshuffled somewhat the ranking of the projects in that portfolio. And so this has more to do with higher activity than -- on the NCS compared to oil and gas activity internationally. So that is more what I alluded to. Svein?

Yes. On the CapEx and the Norwegian tax, as Lars Christian also explained in his speech, it's about the changes imply that we are now able to expense towards special petroleum tax the CapEx that happens in the year that it occurs for 2020 and 2021 but also then for projects that reach a final investment decision within 2022. So those will have the benefits in the full period. In the quarter, since this is given effect back to 1st of January this year, we will get the benefits for the new tax system, including the increased uplift in this quarter. And that is impacting the cash taxes which we will pay for the remaining part of the year. And as Lars Christian said, a negative NOK 1.5 billion then in August and then we do a recalculation when we are in September then for the -- to see what will be the remaining. And then the remaining part of it will come in the three installments in 2021. But also remember in 2021, we will have the direct expenses of all CapEx on the Norwegian continental shelf, which will impact the taxes both in '21 and in '22.

Sorry, I'm still slightly confused because you -- effectively, the -- there's been a big reduction in the krone CapEx that has converted the rates that you've given. And yet you're implying with the tax change, you're going to put more money into Norway versus international.

Yes. What we had as the guiding and outlook as we had in first quarter, we based it on krone towards dollar of NOK 11. Now we are basing it on NOK 9.5. So we keep it in the amount in dollars, but of course, affected by the higher Norwegian krone, of course, towards the dollars. So -- but we also are working on the Norwegian assets and maturing those. And of course also, the new tax system in Norway will come for new projects. And those are the things that they are going to sanction in the months to come up until 2022.

And our next question is from Michele Vigna from Goldman Sachs.

Lars Christian, congratulations on a very resilient quarter in an incredibly difficult environment. It's very exciting to see Equinor leading the first large-scale blue hydrogen project in the U.K. I was wondering if you could elaborate on the regulatory framework you would want to go ahead. And particularly, what kind of incentives you believe would be best placed for the project, whether it's something similar to what's your bet in the offshore wind contract with a contract for difference? And what cost of hydrogen you believe you will need to have a profitable blue hydrogen development there?

For the world to be decarbonized, I think we need to pull a lot of different strings for that to happen, and hydrogen being one of them. The terms and all that kind of stuff, I think the best actually would be if Peter can come back to you on this one and follow up because this is very much into the details. So -- and if others would like to have the insight and the same answer, please contact Peter. I think that would be the best of me to do actually. But we believe that pursuing different opportunities is a way to broaden our understanding and to have optionality to figure out where we really want to put our bets going forward. Blue hydrogen is cheaper than green hydrogen. And then for the -- also the green hydrogen to actually work, it is very dependent on our overcapacity in renewables. And so I think our current thinking as of today perhaps is blue hydrogen is somewhat more of an alley to pursue. So yes to that.

Our next question is from -- sorry?

And I'll be happy to take those with you separately, Michele, so we can get through more questions this morning in limited time.

So our next question is from Mehdi Ennebati from Bank of America.

One question, please, regarding your priorities. So if the oil price remains as it is and even if the natural gas price remains under pressure, it is likely that you will start benefiting from, let's say, positive organic free cash flow for the dividend payment and then a decrease in your net debt in the coming quarters until maybe end of 2021. So how would you rank your priorities? Would it be to reinstate the dividend around $0.20 -- $0.27 per share? Or would you rather, first, significantly try to increase the CapEx in Norway, given the return on the project is weighted by the temporary tax change? Or would you take this potential extra money to, let's say, accelerate your shift towards renewable energy? So just wanted to understand your priorities here. And second question on the CapEx of full year 2020. So your CapEx went down significantly in the second quarter versus the first quarter. That makes sense. However, to reach your $8.5 billion guidance, you need to increase your CapEx in the second half of this year versus the first half. So do you intend to increase your activity in the second half of this year? Or have you been able to lower your CapEx in the second quarter more than what you were initially expecting? Just for us to see if there is a will to return one region of your CapEx guidance for 2020.

I'll try to answer both of your questions. And I say try because you broke up quite frequently during your speech, but I think I got it. And if not, please correct me or ask me again. On the CapEx guiding, $8.5 billion for this year and $10 billion for 2021, your question was more, are we expecting to spend more CapEx second half compared to the first half, which is true. This is a phasing and a timing issue. And we have seen lower activity in some yards, given the COVID situation. And we are seeing those yards are picking up again. So it's just sort of straightforward. In many ways, good development in many of our projects and we have delays in a few projects. But on the totality of it, we have good control over the spending, which is still good to see. And there always will be something that we pursue. On the prioritization, we want to safeguard the balance sheet. This for us has more to do what kind of company we would like to be coming out of this downturn. This is not about Q1. This is not about Q2 or Q3. This is about when the world is a better place to be and there is a more balance between supply-demand and the prices coming up again, what kind of company do we want to be at that point of time. And we want to be among the strong companies so that we can take advantage of the opportunities that we see going along but also so that we can represent competitive capital distribution to shareholders. So we haven't taken down the dividend to fund other projects. We took the measures we did on postponing temporarily the share buyback and a cut in the dividend and taking on more debt, the $3 billion action plan and so on. We all did that to safeguard the balance sheet and to have flexibility so that we can maneuver in very challenging terrain. And I think the weather has been somewhat of a nice nature in the back end of this quarter compared to the back end of first quarter. But it is a difficult times still ahead. Svein?

Yes. Just a comment to the $8.5 billion guiding. As you pointed to, we have spent $4.1 billion so far. We are giving then the guiding on -- based on our own $8.5 billion. What we are now seeing is that we have got the clarity on the Norwegian tax system there. We are also then being able then to work on the projects here. We had -- that were more impacted in the beginning of the quarter [indiscernible] COVID, but now you are seeing that people are gradually coming back to yards and those things. So that means that our best estimates for this year is around $8.5 billion.

Then you also talked about the dividend. I think I heard that you said coming back to $0.20. We had $0.27 before at year-end dividend per share per quarter and we have taken it down to $0.09. And the reference point for us coming back up again 1 day will be the $0.27, just to be clear on that.

And our next question is from John Olaisen from ABG.

In your annual report, you wrote that you are considering entering the onshore wind market. Wondering if you have had any progress in this so far. And also, if you're entering the onshore wind market, where would it be? And would you be likely to do an acquisition or organic?

Anyway, it's a very easy question to answer and at the same time, very difficult question to answer. The easy answer is if we're entering into a business, onshore, offshore, oil, gas, deepwater, shallow water, renewables or not, it has to be among the good assets. People, too, in my mind, people too often are having a vertical line between assets, whether you should invest in one category or the other. For me, it's a horizontal line. Everything above a certain good return, I'm very eager to look at and see if we can get it if it's among the best ones. That goes also for onshore positions. Whether we will enter and when and where, that remains to be seen.

I have a follow-up on that. I just wonder where do you see as your rationale, what's your competitive advantage in onshore wind? And I could see that you have some obvious advantages offshore. But what would you say is your -- would be your competitive advantage, way to add value by going onshore wind, please?

We have had and we still are having a competitive advantage, we believe, in the offshore wind, to your point. But then we also find out that when we start to learn the offshore business, to know and master it and operate it, then it's not that difficult to operate onshore. So I think it's more difficult to go the other way around, actually. And the only purpose for us to enter into any onshore wind project would be if it makes good returns for us. If not, we will shy away from it.

If I can just intervene, for questions -- remaining questions, I get that we started 5 minutes late, but we do have a hard stop after the hour, so around 12:00 Norwegian Time. So we will just give it one question each and we need to move through quite quickly in the remaining 10 minutes or so.

And our next question is from Lydia Rainforth from Barclays.

And I will keep this quick. First question, just a view on long run pricing that you outlined earlier in terms of the impairment testing, does that impact how you allocate capital? So effectively, if you're looking at $80 oil price in 2030, does that mean that you would naturally allocate more capital to oil and gas versus something like renewables? Or does that not play a role at all? And I hope I know the answer to that one, but I just wanted to double check.

The oil price and gas price assumptions is key for us to have a firm view on and balanced view, and we use it for accounting purposes. When we make business decisions, those are the criteria that we factor into this. And that is, I think, what you see reflected in our prioritization on projects between oil, gas and renewables, so yes.

And our next question is from Jon Rigby from UBS.

Can I talk about the trading result? Can you -- I guess you won't talk about exactly how you make the money. But can you talk about something around the framework of it? Do you take greater risk in the quarter? Is there a way that we can see between quarters how you're positioning yourself? Because I look at volumes traded, I look at the working capital movements, et cetera, and it's not clear where this is coming from. And perhaps if you were to disclose, let's say, a VaR number or inventories held for trading, would we be able to see a change in the sort of operating dynamic in Q2 versus other quarters that you've been operating this model?

Yes. I mean we are very, very happy with the quarterly results from MMP, of course. And the results are from the crude trading business of it. So perhaps, Svein, you can give some meat to the bone.

Thank you. I can give some further details on it. It's what we have talked about, as you might have remembered over the last years, is about an asset-backed trading. It's about utilizing positions that we have in the -- that we're optimizing around. That means that, for example, having shipping capacity available, utilizing storages and those things. And what we did during the last quarter into this quarter was that we took positions for wholesaling in March for delivering into the physical market later on. And there was a strong contango in the market. So we were able then to utilize that one but actively taking positions around it. So contango contributed some. But also on top of that, then the active position taking, utilizing our positions and taking position were the key contributor then to deliver the results. We are following the VaR mandates very closely to make sure that those are in good control, not going out with what the VaR mandates and those things are, but we have a very strict control on the VaR mandates and then how we are running the business. So it's about optimizing our own assets and then also taking positions based on what we have available.

And our next question is from Christyan Malek from JPMorgan.

And again, congrats on a great quarter, given the circumstances. So the question I have is around the E&P U.S. position. I know that it's been sort of mixed through the last few years. But with the sale of the Eagle Ford, and you've obviously acquired Caesar back end of last year, the question I have for you is now that you've reported it separately, which is very useful, what are your thoughts of how U.S. sits within the portfolio, more broadly speaking, from a strategic standpoint? Should we expect you to allocate more CapEx towards the U.S. or continue to divest out and potentially wholesale? I would love hear your thoughts on that, please.

Well, what we're going to do on the M&A side, whether it is to add assets or sell out of assets, you will read about it when we've done it. So I can't give you any indication of that. The U.S. is important for us. It is a huge resource base with a lot of good opportunities. And for an oil and gas company like ours with a position and the strength, I think it will be strange if we are not continuing to look at opportunities in U.S. as we do elsewhere. We look at opportunities in Norway, in Brazil and many, many, many other places. But the good thing is that we have a CAGR of 3% from '19 to 2026. We are not distressed. We don't have to sell assets. We don't have to buy assets. So that means that we can work the market and look for the good opportunities, whether that is from an acquisition point of view or a divestment point of view.

And our next question is from Alwyn Thomas from Exane BNP Paribas.

I'll keep it quick. Just looking at production guidance, obviously you kept that flat to 2026. But you've seen a reasonable number of operational impacts during the last few months. We've seen Castberg delayed, the impact of Peregrino as well. I'm just wondering, to think about the production guidance now, is it more back-end loaded? And perhaps you can give a little bit of color on some of the issues you've experienced and the timings you now expect from some of those projects? And perhaps within that, whether you're able to just discuss what you expect for Norwegian gas volumes to be sold through, through the rest of the year?

On the last one, that is very, very difficult to answer because we are focusing on value over volume. And how much we're going to push out in time remains to be seen. And those decisions are made more or less on a daily running basis, dependent on the prices. If, for example, the gas prices 1 day would spike, of course, we would like to take advantage of that and then produce fully. So I mean this can go all ways. On the production guiding, I think I heard you said is flat. I interpret it as we are keeping the one that we had at the CMU that is around 3% CAGR from '19 to 2026. And that remains. At the CMU, we said that it would be somewhat front-end loaded, given the start of Johan Sverdrup and many other projects coming. And then with some of the small delays and the reprioritization that you have seen, that front-end loading will be somewhat softer but still a healthy good production growth in the short term.

And there are no further questions, so I will hand the word back to Peter for any finishing comments. Anything, finishing comments from the speakers?

No. Just to thank you for listening in and for being so engaged. And [indiscernible] continue this. And please remember to stay safe. This coronavirus is definitely challenging for each one of us, but it's also a very, very serious business. So take care of yourself and your dear ones. Bye-bye.

This now concludes the conference call. Thank you all for attending.