Equinor ASA (EQNR) Q2 2023 Earnings Report, Transcript and Summary

Thank you for standing by. My name is Ellie, and I'll be your conference operator for today. At this time, I would like to welcome everyone to the Equinor Analyst Conference Call. At this time, all lines have been placed on mute to prevent any background noise. [Operator Instructions] Thank you. Bård, you may now begin the conference. Bård Glad Pedersen: Thank you, operator, and good morning, everybody. It's a pleasure to welcome you to the analyst call for Equinor's second quarter result. My name is Bård Glad Pedersen. I'm heading up Investor Relations. I'm here together with Torgrim Reitan, our CFO, and he will present the results before we open for questions as usual. So with that, I hand it over to you, Torgrim.

Thank you Bård, and good morning, everyone. We appreciate you joining us, and I hope you all are enjoying your summer and that you also get some time for vacation. So let's go straight to the results. We are delivering solid earnings this quarter with adjusted earnings totaling $7.5 billion and $2.2 billion after tax. The main explanation for the drop in the results is of course, the energy prices are significantly down from the extraordinary levels we saw last year. But compared to prior years, these are still solid results. Particularly, European gas prices are lower. And after a record warm winter, current storage levels in Europe are more than 80% full. Still we see that the market is very sensitive to minor events and only small supply disruptions. And going into autumn, we expect more volatility. Prices will depend on weather impacting both heating demand and renewable energy production, and also Chinese and Asian demand competing for LNG will impact prices. We believe this vulnerability will continue into this winter and for the coming years. Longer term, we expect to get more LNG into the market and that LNG will be the price setter, providing fundamental support for higher gas prices. We take a role as perhaps the most important energy provided to Europe very seriously. And towards the end of this decade and beyond, we can deliver 40 bcm annually. We have a very competitive cost for piped gas from the Norwegian continental shelf below $2 per MBtu, and that puts us in a strong position. This quarter cash flow from operations continues to be solid. But as expected and as we discussed in connection with the first quarter results, our net cash flow is negative due to your high tax and capital distribution payments, reflecting the extraordinary strong results last year. Cash flow from operations after tax year-to-date is $9.4 billion, positioning us well to deliver on average $20 billion per year as we said at our Capital Markets Update in February. We see strong liquids production in the quarter, both from the Norwegian continental shelf and internationally, it is actually up 12% in total. But our NCS gas production is lower than last year. It is down 14%, that is due to planned turnarounds, but also due to unplanned shutdowns at Hammerfest LNG and Nyhamna impacting Snøhvit, Aasta Hansteen and Ormen Lange production in the quarter. We also continue to deliver on our strategy across the business. In the quarter, we reached yet another milestone at Johan Sverdrup, increasing capacity to 755,000 barrels of oil per day. And this resulted in record high production from this field, and it will contribute with strong value creation for years to come. In Brazil, we took the final investment decision for the BM-C-33 gas fields. And we also continue to invest in a portfolio on the Norwegian continental shelf. This quarter, the development plans for Irpa and Verdande were approved. Both are subsea tie-backs in the Norwegian Sea and can be developed over the next few years, adding new high value, low carbon barrels. Last week, we announced the acquisition of the Brazilian Renewable Energy Company, Rio Energy, with a proven organization, a producing asset delivering close to 1 terawatt hour per year, and a solid pipeline of onshore wind and solar projects. And I look much forward to welcome our new colleagues. The acquired project portfolio is anticipated to deliver at the high end of the range for our expected renewables return of real 4% to 8%, and that includes the acquisition price. We are developing our portfolio in a country we know well, taking part in the largest power market in South America. This is similar to what we have done in other selected markets such as with Wento in Poland and BeGreen in Northern Europe. In the U.S., the lease for floating offshore wind in California has been approved. And here in Norway, Hywind Tampen is in production. We continue to deliver capital distribution in line with what we communicated at our Capital Markets Update. For the quarter, the Board has decided an ordinary cash dividend of $0.30 per share. In addition, the extraordinary dividend of $0.60 per share totaling $0.90 in cash dividend. We continue our share buyback program. The third tranche will be $1.67 billion in line with a program for 2023 of $6 billion. In total, we expect a capital distribution of around $17 billion for 2023, as we have discussed at our Capital Markets Update in February. Okay, turning to safety. We see that the serious incident frequency is 0.3. This is our best result so far, and also the total recordable injury frequency is down from 2.7 to 2.5. Safety remains our top priority. We produced 1,994,000 barrels of oil and gas per day in the quarter, slightly higher than second quarter last year. In addition to record production at Johan Sverdrup, we also had strong liquids production from our international operations, particularly due to high production from Peregrino in Brazil and the partner operated Vito and Cesar Tonga fields in the Gulf of Mexico. We have lower gas production this quarter, partly because we had more planned turnarounds, but also due to the unplanned shutdown at Hammerfest LNG and Nyhamna impacting Aasta Hansteen and Ormen Lange. They are all back in normal production now, but the impact for the quarter was around 70,000 barrels per day. On power production, 345 gigawatt hours from our renewable assets is slightly higher than last year due to two new solar power plants in Poland and Hywind Tampen being fully operational. We are now waiting for the startup of Dogger Bank A, a milestone for the world's largest offshore wind farm. We are assembling the first turbines as we speak and we expect first power later this summer. Let me turn to our segment results. Adjusted earnings on the NCS totaled $6 billion, driven primarily by strong liquid production. It is a reminder that even if we are the largest gas supplier to Europe, we are also a large oil producer and we create significant value from that. Internationally, good production growth drove solid results. Our U.S. business posted adjusted earnings of $226 million, while E&P International delivered $751 million. This includes the reversal of previously expensed exploration of $227 million. Our marketing and midstream segment delivered solid adjusted earnings of $665 million. This is within our increased guided range achieved in a quarter with lower volatility and with lower prices. Our acquisition of Danske Commodities pays off and we had received our first dividend of €1.5 billion. In our Renewables business, our assets in operation contribute with $33 million, but with high activity, both within projects and business development, adjusted earnings are negative $84 million. We expect a further lowering of adjusted earnings in the coming quarters related to this segment as activity continues to increase. Inflation and global supply chain pressure continues to affect the industry. Transportation costs, high maintenance and activity levels and increase in CO2 prices contribute to increased costs compared to the same quarter last year. From first quarter, we see a fairly flat cost development, but we are prepared for continued cost pressure and strong cost management remains important. The reported costs for our operation in Norway are impacted by the strength of Norwegian kroner. Over the last year, Norwegian kroner has weakened impacting the results. Now we see that the Norwegian kroner is strengthening somewhat and that will also impact our operational costs going forward. In the quarter, we reported cash flow from operations of $10.5 billion and negative $356 million after tax, following two tax installments in Norway of $10 billion in total. In the third quarter, we will pay one tax installment of around $3.75 billion. In the second quarter, we also paid significant capital distribution of $6.8 billion in cash dividends and share buybacks, including $3.6 billion to the state, for their share of previous tranches. Working capital decreased by $2.2 billion, primarily due to lower gas prices and lower gas volumes sold. After tax, capital distribution and capital expenditures, our net cash flow was, as expected, negative $10.8 billion. When that is said, our financial position remains robust with a strong balance sheet and cash and cash equivalents and financial investments of $42.6 billion and a net debt to capital employed ratio of negative 35%. So let me then conclude by taking you through our guiding. We had unplanned production losses with an impact of around 70,000 barrels per day in the quarter. Despite this, we maintain our guiding of around 3% production growth this year. However, the risk is now more on the down side of this guiding. Organic CapEx so far this year is $4.6 billion, and we maintained the CapEx guiding we gave in February. With that, I hand it back to you, Bård, and I look forward to your questions. A - Bård Glad Pedersen: Thank you, Torgrim. We are then ready to open for questions, and I ask that you limit yourself to one or maximum two questions, so that we are able to cover as many as possible. You are of course free to sign up for a second round if we have time for that. The first question will come from Teodor Sveen-Nilsen from Sparebank Markets. So please, Teodor, the line is open.

Good morning, and thanks for taking my questions. I have two questions. The first is on balance sheet and dividends. Torgrim as you alluded to, yes, you have very strong balance sheet and one could argue that the balance sheet is a little bit out of stream compared to your long-term capital structure guidance. So I just wonder – and also given the fact that the current oil prices and gas prices, that situation will most likely not change. So then my question is, would you prefer to accelerate your dividend, i.e., increase extraordinary dividends or increase buybacks going forward to get the capital structure in sync compared to guidance? Second question, that is on gas strategy, gas sale strategy. I assume that we will see that the European gas storage now will reach 90% much earlier than previous years. So I just wonder how does that impact your gas sales strategy. Thanks.

Okay. Thank you, Teodor for two very important questions. So first on balance sheet. And as we have discussed earlier is that we have a very special situation after last year with extraordinary revenues. So that is the background for the $17 billion capital distribution this year. And I just want to repeat, we are very committed to deliver on that. And it's a composition between share buyback and cash dividend. So I'll give a little bit flavor on sort of our capacity to do share buyback because there are limitations to it. One limitation is that we can just only buy back 10% of free float, and that is the mandate that we have from the Annual General Meeting, of 94 million shares. And that is the background for the $6 billion share buyback program that we had this year. And that level of share buyback, we are comfortable operating with. So as you understand, there is a limit to how much share buyback we are able to do on an annual basis due to regulatory limitations as such. We want to use a combination of share buybacks and cash dividends as we go forward as well, yes. And yes, so that's the first one. The second one, the gas sale strategy. Yes, the situation this year is, of course, very much colored by a record warm winter last year. That has softened prices quite significantly. But the situation is still very sensitive and volatile. But of course, coming into the autumn with high storages and all of that will make sort of the situation easier for Europe as we start autumn and all of that. But very small changes can have the significant impact on prices. And I think we see on a daily basis 8% to 10% changes in prices just demonstrating the volatility. So what we need to clearly follow closely is weather as that develops. If we see a normal winter this time around, things will look very differently. If there are supply disruptions that will typically have a significant impact in that be LNG or other value chains and of course, as Europe will have to compete with typically China and Asia for LNG, growth and demand in Asia will have a very important implication for the European gas market. In summary, it is a very, very volatile situation. When that is said, we do know and we are probably the most important energy company in Europe. So we will help support Europe with energy through all of this. But if the price tells us that the gas is more needed a different period than we currently have, we will move gas in time and using price signals to do that, as we have done in the past as well. So the gas strategy is the same. We will optimize for value and price signals is what actually defines where gas is needed the most at any point in time. Bård Glad Pedersen: Okay. The next question will be from Biraj Borkhataria from RBC. Please go ahead, Biraj.

Caught my attention. Considering you bought this business for $400 million. Bård Glad Pedersen: Biraj, sorry to interrupt you, but we lost the start of it. If you can start over again.

Sorry about that. Hopefully you can hear me. So the Danske Commodities dividend, the €1.5 billion, which is a significant number. I assume this is based on 2022 earnings. Looking forward, what would be a more normal level of dividends to Equinor for this business? And then the second question is on the reliability of gas production. Obviously, 2022 was exceptional. You've had a number of issues in Q2. Do you think these issues are largely behind you? And is there any theme there? And what contingency have you put in your production guidance for the year? Thank you.

Okay. Thank you very much, Biraj. So yes, as you remember, we acquired Danske Commodities a few years back, and clearly, it has paid back multiple of times since then. And last year was a very extraordinary year also for Danske Commodities, where we let them use our balance sheet to actually take positions and make things – enable trading. So the dividend paid from Danske Commodities now is a result of extraordinary earnings last year. On a normal level, I mean, of earnings is clearly lower than 2022, but we are using our balance sheet and giving them the opportunity to take a broader perspective on the business than traditionally. So a much lower level is normal than what we saw last year. But as volatility will continue, I mean, we do believe Danske will continue to deliver strong results. Second question, reliability of gas production. So I just want to say a few things on this. First of all, the issues we had in second quarter are solved on Nyhamna, which is operated by Gassco, and then Shell is the technical service provider. That is back in production, but it clearly had an impact on Aasta Hansteen and Ormen Lange production. Hammerfest LNG or Snøhvit, we had a gas leak related to a maintenance stop or testing. That is now all fixed, and it is back in production. Apart from that, maintenance programs have gone well. We have had more maintenance in the first half of the year than we will have in the second half of the year. So I feel very confident that we are well set up to deliver on what we shall deliver from the assets. On your last question of what sort of contingency do we have, I think it's fair to say that is lower than it was at the Capital Markets Day due to that we have 70,000 barrels per day in the second quarter lost to unplanned stops, as such. So the contingency is clearly less. And that sort of leads us to say that we maintain production guiding, but the risk to the downside is larger than it was on the Capital Markets Day in January.

Okay. Thank you. Bård Glad Pedersen: Thank you. The next question will be from Oswald Clint from Bernstein. So please open the line for Oswald and Oswald go ahead.

Thank you, Bård and Torgrim. Torgrim, you made this new renewable corporate deal, Rio Energy in Brazil. I just wanted to see if you could just talk about the decision to deepen here in Brazil and also the rationale for not deepening in somewhere like Germany, where they had a recent round. You obviously know that country well. You linked up with EnBW to grow that position. So any comparison or contrast you could do between those two regions for wind or renewables would be interesting, please. And then secondly, on MMP earnings, impressive numbers as you said. Lower gas, lower volatility but still good numbers. Should we be thinking this is an outsized contribution from Triton, the power to gas piece? Or is there still a strong kind of geographical optimization piece that's coming through those numbers? And maybe in that, could you say why were your U.S. gas pipeline realizations just so low in the second quarter? Thank you.

Yes. Okay. Thanks, Oswald. Important questions. So first, on renewables, yes, there are some mixed signals in the market for the time being. On the one hand, in Germany you see a very, very competitive situation where sort of big dollars is put on the table for seabed leases. While at the same time, you see other companies handing back leases and handing back contracts on already leases acquired, reflecting sort of the reality in this industry, which is clearly higher inflation, limited capacity and increased interest rates. So there are some mixed signals out there. When it comes to offshore wind, we clearly believe that this is going to be large, and we are going to be a significant part of that. We have entered early, as you know. We do know the pipeline. So we are good with the current activity level, and we are in a position where we are not willing to accept levels as we have seen in the recent lease rounds. So we participated, as you would understand, but we could not justify to go to those levels. So we'll rather wait and see if there are other ways of getting access to offshore wind. When that is said, I mean, also a part of our strategy is to grow based on sort of markets and onshore activities. But I think it's fair to say that, that has actually proven to create value in times like this. We did the Wento deal in Poland. We have done the BeGreen in Denmark, addressing Northern Europe, and now it's Rio Energy in Brazil. So that part of the strategy is sort of accelerating more while we're sort of probably moving a little bit slower on offshore wind due to the pure competitiveness in that market currently. So I'm very enthusiastic about Brazil and Rio Energy. This is a country where the power market is growing rapidly and it is also being deregulated. And combining Rio Energy with Danske Commodities that is on the ground, we do see a very interesting investment proposition there. So I'm eager to travel to Brazil and meet our new colleagues and get to know them better. Bård Glad Pedersen: The MMP?

Yes, sorry. And then the second part, MMP. Yes, so another strong quarter for MMP. So what was actually the main contributor this time was actually liquids trading and operations and also results from the natural gas. Less contribution from geographical arbitrage on the gas side, but an underlying good delivery also on the gas. You've probably seen increasing costs in our accounts, and that is particularly related to shipping costs because we have taken on more capacity, and that has enabled us to make more money on the liquid side. So it's good to see that there are various parts of the MMP machine that delivers in different environments.

Thanks, Torgrim. Sorry, just anything on the U.S. gas realizations, pipeline gas realizations this quarter?

Yes. So I mean, it was very low prices in the quarter in the Northeast. The realized price was $1.46 as far as I remember. And while Henry Hub is higher than that. And it is a pure reflection on the different pricing in the different markets. So the Northeast is lower than Henry Hub, and it has always been, but significantly changes quarter-from-quarter here. I think it's fair to say that our U.S. gas production out of Appalachian is some of the lowest marginal cost barrels of gas to be produced in the U.S. So it's a robust business.

Very good. Thank you. Bård Glad Pedersen: Thank you. The next question will be from Alastair Syme from Citi. So please, Alastair, go ahead.

Yes. Thanks, Board. Torgrim, a couple also on the renewables business. I think you said in your opening statement that – on the forward guidance that the losses will deepen over the next few quarters. So I just wanted to understand that. I mean, you referenced inflation, but I would presume most of the development costs have been capitalized. So I'm not sure I sort of sure what's hitting the cost line. So maybe you can explain that. And then just a follow-up to the question on the German auction. Can you give us some sense of how much you're being outbid by? I'm not sure if I understand it, it's 5% or 25% or 50%. I don't need you to be specific, but some sense would be useful. Thank you.

Thanks, Alastair. On your first one, I mean, we have fairly limited production from our renewables business. So that – but it is contributing with $33 million for the quarter. And then the adjusted earnings is minus $84 million. It is driven by higher activity, early phase development costs and business development activities as such. So you should expect going forward that we will probably deliver negative results a little bit higher than this over the next few quarters. But gradually, more and more production will come into the renewable business, Rio Energy. One terawatt hour per year in electricity production from now on and then Dogger Bank gradually coming. And as you know, we are about to start production from Dogger Bank A from the first turbines, and that will gradually increase over the year and next year. And then this will look typically very different when that happens. Then on your second question on sort of the German auction. No, I'm afraid I'm not in a position to say by how much we lost. But I can say it was – it was not with a small number.

Can you just say on the first question on the renewables earnings, do you think you'll be in positive territory at any point in, say, 2024? Do you think that's going to kind of inflect?

When it comes to positive earnings, I mean, it is – the positive earnings will happen over the next few years. But I think we will give a proper update on this on the Capital Markets Update in February. But it is – as sort of the various phases of Dogger Bank is coming into production, that will generate quite an interesting earnings and a positive contribution.

Great. Thanks, Torgrim. Much appreciated. Bård Glad Pedersen: Thank you, Alastair. The next question is Kim Fustier from HSBC. So please, Kim, go ahead.

Hi. Good morning, all. Thanks for taking my questions. Just again, going back to offshore wind. I wondered if you could talk about the cost challenges you're encountering at your U.S. offshore wind projects, particularly those you have in a JV with BP. I read somewhere that you've gone back to the state to try and get better terms. I mean, how likely is it that will happen? And then what happens if you don't get better terms, I mean, do you just pause the projects and then revisit them two years later? My second question, if I could, is just on Northern Lights. What are the next steps before taking FID on the second phase of that project? And how much of the project capital cost do you expect to be financed by subsidies? Thank you.

Okay. Thanks, Kim. So offshore wind and the U.S., you are right. The U.S. offshore wind projects, I would say, is probably the weaker part in our portfolio. We have signed on two contracts with the New York State on revenues. That is not adjusted for inflation, while at the same time, we have seen significant inflationary pressure in sort of the investments and all of that, coming to a point where sort of the returns are challenging for those projects. When that is said, we entered early into these projects. We have limited acquisition costs and others have spent more money acquiring assets. So in June, we filed a request with [indiscernible] the regulator, for a renegotiation of the contract. We are definitively not alone. This is – most companies, if not all, are doing the same. So this is an industry-wide issue. I do expect it to be a positive outcome of that. But clearly, it remains to see the results, and the discussion is ongoing. But I think it's quite interesting to see the differences between the various regions because in the U.K., we have contracts that are linked to CPI and where we had already agreed on investments and financing. So you see the opposite effect there. So the Dogger Bank projects, they benefit quite a bit from the inflation we have seen over the last few years, where revenues have increased nicely while sort of costs have been relatively flat. And also in our Polish projects, we have inflation index contracts, making those projects look quite robust. So I would say it is particularly U.S. projects that are sort of vulnerable in this situation. But we are taking actions and working closely with the regulator to make these ultimately happen. On Northern Lights Phase 2, so we are working towards final investment decisions for Northern Lights. It is a very important project for maturing the whole CCS industry in Northern Europe, and there is a lot of support for it. So we are working towards an FID, but I can't share more at this stage on sort of when that exactly will happen. Bård Glad Pedersen: Thank you. The next question will be from Martijn Rats from Morgan Stanley. Please, Martjin, go ahead.

Hi. Hello. I had two questions, if I may. First of all, I noticed the deal with Cheniere to buy more LNG from 2027 onwards. And as a company who is already the largest natural gas supplier to Europe, I thought that was quite an interesting transaction. I was wondering if you could say a few words about sort of why you signed this deal, what the attraction could be, and broadly where you are planning to sell this gas, in Europe or elsewhere. And secondly, I also noticed that some projects for FID like BM-C-33, but also there were some sort of delays, particularly Bay du Nord, which you announced a couple of weeks ago. I was wondering if you could elaborate a little bit on why one project went ahead, but Bay du Nord did not and what the headwinds are there. Thank you.

Thanks, Martjin. So first, on the Cheniere contract, I mean, we do believe that LNG is an attractive place to be. And we have a rather limited exposure as it is today and we would like to have a bit more exposure. So that's sort of background for this deal with Cheniere. We see LNG to be the price setter for Europe, and we also see that LNG is – that Europe needs to compete with Asia for LNG. So this will help us take a more holistic perspective on the global gas markets going forward and around trading and optimization of it. So this LNG might land in Asia, might land in Europe, depending on what prices tells us to do. Then on sanctioning, yes, so BM-C-33 final investment decision, a large Brazilian gas developments and it can contribute with some 15% of the gas demand in Brazil. I think this will, of course, will take some years, but we also see that there are some cross-commodity perspectives across natural gas and power in Brazil that we want to investigate as well. And BM-C adds nicely to the large portfolio we have in Brazil and the competent organization we have down there. Bay du Nord, yes, actually another very nice and good project, greenfield outside Newfoundland, where sort of we have decided that we won't do that now. We'll give it three more years to develop. And this comes from the way of thinking that we say we'll rather postpone investments to make them better than pushing them forward as soon as we can. So this is value over volume. So this is the similar way of thinking as we have done with Wisting last year on the Barents Sea and what we did with Johan Castberg and other fields four, five years ago. So there's no mystery to it other than we do think we can make it better by redesigning it and taking it out of a very heated market now and place it in a time where it will work better. I do believe it will happen. It is important for Newfoundland. It is important for Equinor.

Thank you. Very clear. Bård Glad Pedersen: Thank you. The next question is Peter Low from Redburn. So Peter, please go ahead.

Can you talk a little bit more about some of the cost pressures that you alluded to in your opening remarks, where that's coming through and what you're doing to manage it? And then just a very quick one on CapEx phasing. I think in the first half, your organic CapEx is tracking at about $4.6 billion. Should we assume that run rate increases in the second half given your $10 billion to $11 billion guidance? Thanks.

Yes. Thanks, Peter. So clearly, we see cost pressures and we see it in sort of various places. When it comes to the operational costs, you saw a 15% increase in SG&A. So that is driven by, first of all, increased transportation costs related to more volumes being sold and particularly relating to shipping costs. We see increased costs related to CO2 and environmental costs, and we also see increased royalty costs. So all of these are sort of cost elements that are sort of, in a way, what should I call it, good cost in a way, meaningful cost. And then we see quite a bit of growth in field costs, which is also understandable because there are more fields in production in this quarter. You have Peregrino, you have Vito, you have Johan Sverdrup Phase 2, but also there is an underlying growth in inflation in some of the supplier costs. So it's important to follow. So compared to last year, plus 15%. If you measure it compared to first quarter, it's only 1%. So we see that as sort of easening off a bit, but clearly an area that we will have a lot of attention to. And we have, but this is not over yet. Then when it comes to project portfolio, still the average breakeven is $35 per barrel. We see that in the sanction portfolio. It is rather robust compared to the cost increases we have seen. But it is in the unsanctioned portfolio where we have the most exposure. We are, during the autumn, going to do a full update on the whole portfolio, and we will revert on sort of how this look at the Capital Markets Day. We don't see – clearly, we are in a position to manage this, but we are not immune to cost increases. Of course, we're not. So this will have to be managed in the right way. And what you saw on Bay du Nord, which we just talked about, if it's not good enough, project is are not good enough, they'll have to wait for later. Then the second part of your question was the phasing of CapEx, $4.6 billion versus $10 billion to $11 billion, I think we are on track to deliver. I mean, we have quite a few developments ongoing. We sanctioned a lot of projects before New Year last year due to the tax incentive package in Norway, and those projects are now gaining speed and gaining traction. So there is sort of an increasing CapEx during the year related to that. So on track. Bård Glad Pedersen: Thank you, Torgrim.

Thank you. Bård Glad Pedersen: Okay. Thank you, Peter. The next question is Paul Redman, BNP Paribas. Paul?

Hi, Torgrim. And thank you very much for your time. Just two from me. I'm just thinking about if gas prices do go lower in Q4 when Europe potentially reaches tank tops, kind of when you think about potentially lowering production or cost of supply, kind of where does Norway/Equinor sit on that kind of basis, what sort of price do you think about where you can use your flex? And what fields and volume of production to actually have flex on? And then secondly, just about projects. Any update on Rosebank? There's been a lot of communication in the U.K. press around labor talking about securing the contracts that were agreed prior to elections. Any comments on kind of where you are on Rosebank? Thank you.

Okay. Thanks, Paul. So we are clearly following the European gas markets very, very closely. We are the largest supplier naturally. So I think, as I discussed earlier, I mean, the situation is both very volatile, and very small changes can make a big difference on the prices. So even if it's sort of feeling somewhat comfortable with the current storage levels, I think we need to be prepared for quite a bit of volatility. What we will do – I mean, clearly, we are strongly committed to help Europe to whatever happens on the gas side. And if there are market situations where we see that this gas is better produced later on in a different time period where it's priced better, meaning that it is needed more later than it is currently, we will do that. It will be good for Europe and it will be good for value creation. So we, again, value over volume. Whether we will be in a situation in the fourth quarter where that is an opportunity or something that is needed to do will remains to be seen. But we have flexibility to do that, and we will use that tool if it sort of make sense. And this is much aligned across Norway as well. On Rosebank, yes, Rosebank is very important and a good project, an important project for the U.K. It is important for energy security in times like this. This will be low-carbon footprint development compared to the average on the U.K. and it will contribute quite massively to U.K. with some £30 billion in taxes and investments over the life of the field and 1,600 jobs at peak. So it is important. So the project is mature, it's being mature according to plan. We are awaiting some final conclusion on a couple of topics and final approval from the regulators. But we are of a clear expectation that this will move forward and there will be some clarifications not too far into the future related to this. Interestingly, the development is an FPSO development, where we actually use an existing FPSO rebuilding that. So it's sort of more limited exposed to cost increases than sort of a greenfield development of an FPSO asset. So this is sort of a well risk-managed projects, and there's a lot of things that we are – yes, so this is going ahead, but there are some final clarification needed. Bård Glad Pedersen: Thank you. The next question is Chris Kuplent from Bank of America. So please go ahead, Chris.

Thank you very much. I think I've only got two questions left. Firstly, Torgrim, I know this is quite a boring question, but considering we've got the CFO on the line, I might as well try. Can you explain to me how the dividend you referred to from Danske is reflected in your accounts as a 100% subsidiary? I'm not quite following and I'm struggling to find it. So any insights would be welcome. And secondly, I just wanted to go back a few months and remember that beautiful sunny day in Stavanger when we were listening to one of your gas and power experts, and I think TTF prices were around €30 at the time, suggesting that we'd be close to the bottom. And in a way, that's true because we're still around 30%. What do your comments mean? Or would you be prepared to add euros in terms of your volatility comment from earlier, Torgrim, when you said the outlook for Q3 is very tough to frame. How bad or how volatile could it be? Thank you.

Okay. Thanks. The first question on Danske Commodities, and you can't find it in the account. I'm really glad that you have looked and you haven't found it because you won't find it because it is sort of an intracompany deal. So this is sort of moving from one pocket to another pocket inside the company. So you won't sort of detect it in the accounts. It was – just say it more from – for the points you demonstrated that this has actually created quite significant value for us as such. But you're right, you won't find it specifically in the accounts. Unless you go down on sort of subsidiary levels and see reports later on, but anyway. The second one, on the gas market and gas prices in Europe. So yes, market is currently around €30, but we see quite a bit of movements on a daily basis. And I think it will be wrong of me to give a strong view on where the market goes from here, but more comment on sort of the volatility and the fragility of the market. So I mean, it can go lower naturally but there's a limit to how low it can go. On the volatility, on the upside, it's harder to see a limit. I mean, we have all 2022 with us into this. And I know that rather small changes can give significant impact on prices. So I don't dare to quantify volatility, as you suggest, but – other than saying that it might turn out to be significant just based on smaller events.

Fair enough. Okay. Thank you very much, Torgrim. Bård Glad Pedersen: Thank you. The next question is Henri Patricot from UBS Group. So please, Henri, go ahead.

Yes. Thank you, Bard and Torgrim. Just one left for me, which is on the working capital movements. Quite a positive movement in the first half. I was wondering if you could give us a sense of potentially how much of that could reverse in the second half of the year? Of course, it's very dependent on where prices go, but maybe looking at where the forward curve is at the moment, what should we expect? Thank you.

Okay. Thank you very much, Henri. So working capital was reduced by $2.2 billion in the quarter. So the total working capital balance now is around 6, 6.5 or in between there in total working capital. I would say that, that represents sort of a more normal level of working capital given the current prices that we have in the market and volatility. So – but I think it's sort of – when you do the math, I think it's something I would like to add here. If you look at sort of our cash flow statements, that is actually without working capital movements. So when we talk about sort of the negative cash flow, net cash flow for the quarter of minus $10.8 billion, that is without working capital movements. So if you adjust for that, you can – it will be minus, let's say, minus $8.6 billion or something like that in totality. So yes, but I would say we are not currently pretty normal levels. Any changes from here is typically driven by price levels and volumes and volatility. Bård Glad Pedersen: Thank you. And the working capital balance at the end of the quarter was $6.2 billion, So...

$6.2 billion, right. There you go. Bård Glad Pedersen: The next question is James Hosie from Barclays. Please, James.

You might be looking for opportunities to acquire additional LNG projects for our international business... Bård Glad Pedersen: James, sorry, there was something on the line so we lost the start, if you can start over.

Yes. Sorry. I was just following up with the comment about LNG being an attractive place to be. Could we take from that comment that you might be looking for opportunities to acquire more LNG projects for your international E&P business?

Thanks, James. Well, I mean, what we have currently, we have Snøhvit in the Barents as an LNG plant. We have contracts, and then we have for the really long-term opportunities in Tanzania as an LNG development. Beyond that, I mean, we will not be actively looking for – to acquire LNG projects. But exposure to LNG is something that we can get without being – having ownership to LNG facilities.

Okay. Thanks for that clarity. If I could just ask one more question, just Johan Sverdrup. And I mean, could you give any idea of long you think the field can sustain its new plateau rate?

Okay. Thanks. Yes, important question. Well, I'm not ready to give you an exact date on that. But of course, the recent update in capacity increase is very important, and we will be looking for how to maintain production on that level for longer. And we are already thinking about Johan Sverdrup Phase 3. It is not sanctioned, of course. But the whole purpose of that is to capitalize on the existing infrastructure and to prolong this plateau of 755,000 barrels per day. So yes, clearly, a priority with us to prolong that as long as we can.

Okay. Thank you very much. Bård Glad Pedersen: Thank you. The next question will be from Giacomo Romeo from Jefferies. Please, go ahead.

Yes. Good morning, and thank you. A couple of clarification. And one, you were talking about Northern Lights FID. I'm just wondering whether there will be a percentage of volumes that you'll be looking to be sort of contracted some sort of contractual cover before taking FID there. And the second is it's related to the comments you made about the lack of CPI indexation on U.S. contracts. It's – just wondering how that relates to the California contracts you won, an auction that you won in the end of last year. And whether there is effectively a lesson that you're taking going forward that you'll be looking at some sort of CPI indexation in future projects?

Okay. Perfect. No, thank you. So first on Northern Lights, we are not looking for a particular percentage of volume contracted. There is generally quite a big demand for CO2 services and storage capacities. So this is progressing, and we are maturing towards a final investment decision on that project. On California, so the – we haven't signed any contracts with the state of California on the revenue. What we have won is sort of the seabed lease, the right to develop floating offshore wind in California. And then over the next few years, there will be rounds for PSA or sales contracts for power in California. And with this project, we are well positioned to take part in an early phase of that. So that will come in a couple of years. Bård Glad Pedersen: Thank you. We are fast approaching the full hour, so we'll take one final question. That's from Yoann Charenton from Societe Generale. So Yoann, please go ahead.

Good afternoon, both. Thank you for taking the question. A quick one. Given moves in both oil and gas prices in the past months, would it be possible to confirm what are the full-year 2023 oil and gas price assumptions that are used to derive the NCS tax instalment that are falling due in the second half of the year, are we looking at about $15 per million BTU for gas? And low $80s per barrel for Brent?

Thanks, Yoann. So first, taxes that we have paid in the first half of the year of Norwegian tax is related to earnings from last year. Of course, very high tax payments. In the second half, we have – we are going to pay $3.75 billion each of the instalments, 3x that instalments over the next six months, one in the third quarter and two in the fourth quarter. So these are based on our best estimates for taxable income for the year and we use the forward curve, just as simple as that, to establish these levels. So that's all of the forward curve. Maybe that was present in the market for a couple of weeks ago, so yes.

Okay. Thank you. Bård Glad Pedersen: Thank you. And thank you, Torgrim. Unfortunately, that's what we had time for. I would like to thank you all for calling in and for asking your questions. As usual, the investor relations team remain available if there are any follow-ups that you would like to ask. So with that, we conclude the call and say goodbye for now to everybody.