Good morning, good afternoon, ladies and gentlemen. Thank you for standing by. Welcome, and thank you for joining the Equinor Analyst Q3 call. [Operator Instructions] It's my pleasure, and I would now like to turn the conference over to Mr. Mads Holm, Head of Investor Relations. Please go ahead, sir.

Thank you, operator. Ladies and gentlemen, I'm very pleased to welcome you to the presentation of Equinor's third quarter results call. I'm Mads Holm, Head of Investor Relations. It's my great pleasure to introduce Torgrim Reitan, who, as you know, started as CFO just a few weeks ago. For those of you unfamiliar with Torgrim, he has been with the company for 27 years and held several management position in Norway, the United States and the United Kingdom. His most recent position was Senior Vice President for Finance and Control in renewables. Torgrim was a member of the Corporate Executive Committee for 10 years, first as CFO, then as Executive Vice President for Development and Production USA and later the combined international business. With strong experience from upstream, trading and operations of natural gas and renewables, we are delighted to welcome Torgrim back as CFO to present Equinor's results and outlook, and to engage in the important dialogue with analysts and investor community. Torgrim will take us through the results, and then we will open up for questions as usual. We aim to complete the call within the hour. So with that, let me pass straight over to Torgrim for the presentation. Thank you very much.

Thank you, Mads, for that kind introduction, and good morning, everyone. And very good to be with you. And I do look forward to meet you face-to-face at a later point in time. So it's a privilege to step into this role in a company so financially solid with such a rich and attractive investment portfolio and with a clear plan for transition. Coming into this role, I have 2 main priorities. The first is to ensure that Equinor steered safely through these uncertain times. We see high geopolitical uncertainty, weaker prospects for global economic growth and high volatility in the markets we operate. And I want Equinor to come out of this as a stronger company. My second priority, but equally important, is to support the transition for Equinor to be a leading company as the energy transition develops. So my role will be to ensure that we continue to invest and optimize the portfolio in oil and gas as well as grow and develop within renewable and low carbon solutions, ensuring that we focus on quality and value creation. I see our strategy as even more relevant now than before, and you should not expect any changes to the strategy as I am coming into this role. We will continue to drive value creation, which is always more important than volume targets. The numbers this quarter and for the coming quarters will be impacted by all the changes so closely. One factor we will monitor closely is the inflation and cost increases. This is a growing concern. We see bottlenecks and delays, lower efficiency and risk of a drop in quality in the global supply chain. Our sanctioned project portfolio is mostly protected from this by contract already entered into. However, our unsanctioned portfolio is exposed to changes in the supplier market and in the frame conditions. For instance, the proposed change in the temporary tax regime on the Norwegian continental shelf will increase breakeven prices for the relevant project with $2 to $5 per barrel. Second, the outlook for commodity markets carries significant uncertainties, and we expect high volatility. Our balance sheet is robust with a net debt ratio of minus 19%. But I ask you to note and remember that -- this is impacted by delayed tax payments on the NCS, the Norwegian continental shelf. So as an example, if we paid all the taxes we owe as of today, net debt would move from minus 19% to within the guided range, which is plus 15% to 30%. The point here is if we see a drop in commodity prices, that can quickly increase the net debt ratio. So this is why capital discipline is so important. So we will prioritize in our investment portfolio, so we can execute projects with quality, on time, and on cost. Furthermore, maintaining a competitive capital distribution through the cycles will be very important to me. And looking at the capital distribution framework presented last year in 2021, we have used the flexibility with both significant step-ups in the share buybacks and an extraordinary dividend. And we will continue to use the framework and the flexibility within it. Okay. So let's turn to today's topic. So we present strong results, still against a dark backdrop. And Norway and Equinor's role as a supplier of energy to Europe is more important than ever. And I want to use the opportunity to thank all our employees and suppliers, for all the strong efforts this quarter. We expect continued tight and volatile markets through the fall and winter. But that's always for European gas, temperatures and weather will have an impact. As usual, for the third quarter, we updated our commodity price assumptions. This is a slight increase in our expectations for brent from $70 to $75 in 2025 due to limited expected supply. For European gas, we expect TTF at $20 per MBtu in the same year as we expect Russian volumes to be reduced for the foreseeable future. We assume these prices will spill over to the prices for CO2 quarters, and German electricity prices. We post adjusted earnings of more than $24 billion driven by high prices, particularly for gas, where European gas prices grew by 240% from last year, but also driven by continued high production. The production performance both at Hammerfest LNG and Peregrino, which came back on stream this summer has been good. All the 13 LNG cargoes from Hammerfest went to Europe. And by the way, so did 96% of crude from NCS in the quarter. Peregrino Phase 2 came on stream now in October, almost 2 years delayed by the Corona pandemic but it is still on budget. Gudrun Phase 2 also payment stream, and this will contribute with a higher recovery rate and extends the tail production of that field. And talking about renewables. The first solar plant in Poland is completed. Although energy security and production are on top of the agenda. We remain firm on our strategy and transition plans. In the quarter, we've seen Northern Lights signed its first commercial contract for CO2 transport from the Netherlands to Gudrun outside Bergen for storage under the seabed, an important step in the development of commercial and viable value chains for CO2. We have entered several partnerships to develop projects for large-scale commercial CO2 storage on the Norwegian continental shelf, and to develop low carbon opportunities in the United States and U.K. We delivered strong financial results and with updated earnings expectations for 2022, we took a commercial decision to make an additional tax payment of around $10 billion in September. The strong results allow for continuing a competitive capital distribution. The Board has decided on a cash dividend of $0.20 per share for the third quarter. On the back of the continued strong financial results, the extraordinary cash dividend is further increased from $0.50 to $0.70 per share for the third quarter. This is an increase in our cash payments to shareholders, of around 30% from second quarter. Furthermore, we continue our share buyback program now at $6 billion for 2022. The fourth and final tranche will be around $1.8 billion with a market share of around $600 million. In total, we increased the capital distribution from $13 billion to $13.7 billion for 2022. We view this as a balanced approach where we invest in our competitive portfolio and in the energy transition, while showing a clear commitment to offer an attractive shareholder return. Energy production from the Norwegian continental shelf is crucial to Europe's energy security. We have increased the state of alert based on our assessment to the threats to Equinor. And as a precautionary measure -- and we collaborate closely with the authorities on safety and security matters. Now to safety statistics. The 12-month average serious incident frequency is 0.4, a slight improvement from last quarter. The total recordable injury frequency for the past 12 months is 2.4 per million hours worked. We delivered a high production in a quarter where we also carry out a bigger scope of seasonal turnarounds. And even with a turnaround at Oseberg, we delivered 11% more gas from the Norwegian continental shelf than in the same quarter last year. Troll gas set a production record, delivering 38 BCM, or billion cubic meters, on a 100% basis in the gas year ending in September. Our total oil and gas production ended at 2 million and 21,000 barrels per day. Power production for the quarter ended at 491 gigawatt hours, 294 gigawatt hours of this production came from our renewable assets, slightly lower than last year due to maintenance activity and less wind. This summer, we acquired 50% of Triton Power in the U.K. with the key plant being the Saltend Power Station. Around 1 month of production is included in the third quarter numbers with nearly 200 gigawatt hours and $29 million in earnings, already paying down on the investment, which was $140 million for Equinor share. We continue to deliver very strong financial results. The adjusted earnings totaled $24.3 billion and $6.7 billion after tax. The reported net operating income was $26.1 billion, and net income was $9.4 billion. So we are not isolated from the cost increases impacting the rest of society. Higher energy costs and increased CO2 tax and price impacts our operating costs but you also see effects from longer lead times on equipment for maintenance. The cost increase is masked in our report due to substantial currency effect as we are reporting in dollars. We will continue our improvements as well as working strategically with long-term suppliers to mitigate rising cost pressure. Then we have net impairment reversals of $1.1 billion, mainly due to increased expectations for refinery margins and higher expected commodity prices. Also, we see value creation from portfolio optimization with a gain of $655 million from the divestment of our share in Ekofisk and a share in Martin Linge through Sval Energi. The tax rate in the quarter ended at 72.4%. Now let's move to the segments. Our Norwegian upstream business delivered its best results ever, with adjusted earnings of $21.1 billion, and $4.7 billion after tax. High production, particularly of gas, combined with high prices drives this result. Our international business, excluding the U.S., performed very well in the quarter with adjusted earnings of $942 million, and $641 million after tax. Our U.S. upstream business delivered strong adjusted earnings of $889 million before tax and $868 million after tax. The Midstream and Marketing segment contributes over $1.4 billion in adjusted earnings, and more than $500 million after tax. The gas pipeline network with access to many markets, combined with our marketing and trading capabilities has enabled us to create value from volatility and geographical spreads, delivering gas where it is needed the most. Excluding the positive impact of timing derivatives this quarter, the results from MMP is $1.2 billion, which is more than twice the high end of what we consider a normal result for MMP. This shows MMP's ability to deliver strong results in volatile markets. Our renewable business has negative adjusted earnings as expected, of $46 million, a negative $32 million after tax. However, our producing facilities contributed with a positive result of $28 million. In the quarter, we have a cash flow from operations of $24.5 billion. The cash flow so far this year is $62.6 billion. In August, we started tax payments based on the 2022 results. In addition to the ordinary payment of NOK 70 billion in August, we choose to make an additional payment based on commercial considerations of NOK 105 billion at the end of September. In total, we paid around $17 billion in tax in the quarter. In fourth quarter, we will pay an additional NOK 140 billion in tax. Capital distribution in the quarter is $3.3 billion. It consists of the dividend from the first quarter, extraordinary dividends, and the market share of the buybacks we made in the quarter. This also includes the state share of share buybacks done in 2021, totaling $1.4 billion. We are doing some adjustments to our guiding. We expect a year-on-year production increase of around 1%, down from the previous guiding of 2%. This is mainly explained by Johan Sverdrup. Phase 2, starting up later in fourth quarter than we expected. Due to its high production impact, it affects or estimates on a corporate level. We see very high volatility in the natural gas markets in Europe. For days with low prices, we will defer some production to periods where the gas is more needed and the prices are higher. As you know, we did some of this in the second quarter, and we will continue to use our flexibility in the fourth quarter when appropriate. In the third quarter, we have organic investments of $5.8 billion. This is somewhat lower than previously expected, and impacted by removal of investments to Russia. For the year as a whole, we expect to invest around $8.5 billion. We still expect an average of about $10 billion for 2022 and 2023, and then increased to around $12 billion on average for 2024 and 2025. So we will revert on this at our Capital Markets Update in February. So thank you very much. And with that, I leave the microphone back to you, Mads, and I do look forward to your questions.

Thank you very much, Torgrim. Let us pass back to the operator to open up for questions. [Operator Instructions]

[Operator Instructions] The first question is from Biraj Borkhataria from RBC.

Congratulations, Torgrim. I wanted to ask about the base dividend. Previously, your guidance -- or the way you've talked about it is -- how it grows its underlying earnings, and looking at your updated Gastech today, which is materially higher, I would have thought the underlying earnings power should also be much higher than what you would have expected previously. So could you talk about how you're thinking about the base dividend in that context? And the second question is on your gas business, on the NCS. So in early September, there was a lot of chatter around Norway potentially agreeing a long-term fixed gas deal with Europe. So I don't expect you to talk about negotiations ongoing. But can you talk about whether Equinor would be open to this type of agreement hypothetically? And what kind of things you would need to see? Because obviously, it would give you greater clarity on your investments on the NCS as well over the long term.

Okay. Yes. Thank you very much, Biraj. So on your first question on the dividend, I mean, I'm very glad to see that we have been able to use the flexibility that sits within sort of the dividend policy we have. And also, I'm happy to talk about the increased -- the extraordinary dividend for the coming quarter. So you point to that, the dividend policy says that the ordinary dividend should grow in line with long-term earnings. That policy remains firm. And this is not the time to sort of make big reviews in that, but this is something that we typically do in the fourth quarter to consider sort of the composition of the total capital distribution. So if there will be changes, that will point in time will be the Capital Markets Day in February. On sort of the question on natural gas to Europe. Clearly, we see that we have a very, very important role for the time being, and providing energy to Europe in the current situation, and also providing energy to where it is needed the most. So clearly, we have optimized our production on the Norwegian continental shelf. Production permits have been increased by the government. And we have actually decided to sell natural gas instead of injecting gas as a sort of pressure support in some of the field. So very, very high gas production. And of course, there are dialogues constantly with customers in many countries, and different types of contract structures. I mean we have recently signed a contract, long-term contract to Poland and other smaller contractors as well. And many of these bilateral agreements have different types of pricing structures. So when sort of -- we consider those will take up full commercial considerations related to that. And I'm not prepared to go into any specific discussions in any specific contracts. But there's a broad range of discussions around bilateral contracts. That's right.

The next question is from Oswald Clint from Bernstein.

Torgrim, very good to have you back. First question, just on the inflationary pressures that you're speaking about there. And I wonder if you could talk around how you're thinking about locking in rigs for perhaps the NCS, the North Sea. And I think Ulrica earlier this year was speaking about deeper supplier relationships in order to get through any inflationary pressures looking forward. So perhaps you could speak what exactly you're actually doing there to perhaps mitigate some of the concerns that you're raising in your prepared remarks. And then secondly, I just want to explore more. I mean fourth quarter, first quarter, normally, we got a big seasonal uptick in your gas volumes, but you have been producing a lot of gas this year, sustainably through the year. The guidance still seems to suggest a decent uptick here in the fourth quarter. So are we going to see that normal seasonal uplift with natural gas volumes through 4Q, 1Q? Is that still on the cards?

Yes. Thanks, Oswald. So on the inflationary pressure. I think there are several elements to it. I mean, we see it in sort of many parts of the value chain. I mean clearly within rigs, and I'll come back to that, but we also see it within engineering and construction, and particularly sort of in yards in Asia. We see subsea and marine activities where activity going forward will be impacted by sort of the tax -- NCS tax package. And of course, within offshore wind, we see a tightness across the board. On rigs, in particular, I would say that within harsh environment, and semisubmersibles is sort of where we see probably the tightest. We work, as Ulrica said, closely with those suppliers and have a long-term relationship with key players. So we will clearly be able to maneuver within, but maybe a little bit back to what I said in my speech. We will have to prioritize in our portfolio. So we see that we can execute our investment program with quality, on time and on cost, and sort of the overall capacity in the supply chain will be a key element in that discussion. On your second question, on the third quarter -- or fourth quarter and first quarter gas volumes. I think, first of all, the situation in Europe is very special. And how demand and supply develops month-by-month is actually quite uncertain. But clearly, we do see a tight market going forward in maybe some of the specifics. In the third quarter, we had a turnaround on Oseberg, which is a large gas producer. So that is -- has come out of turnaround. So that will produce, and have capacity available in the fourth quarter. And in general, we have received increased production permits for the big gas producers from the state, also giving us the ability to continue to produce gas at a very, very high level. Then I think there is something that I need to say, and that is that the gas prices fluctuate very much on a daily basis and weekly basis. And we will have days and we will have weeks with very low prices in some of the locations. And at those points in time, we will probably use the opportunity and the flexibility in our machine to defer gas to periods where sort of prices are higher, and the gas is needed more. So I just want to make it clear for you that we will prioritize the value over volume in sort of optimizing our gas productions, both related to price but also to where the gas is needed. Not sure if that gave a very, very clear answer to you, Oswald. But the key point it is uncertain. We have capacity available to produce very high, and we will optimize for value instead of volume.

The next question comes from Lydia Rainforth from Barclays.

Two questions, if I could. The first one, just coming back to the dividend and the extraordinary dividend. The falloff in gas prices that we've seen just sort of relatively short-term does create a potential for a formal free cash flow for [indiscernible] in the fourth quarter. How do you think about how you set that sort of extraordinary dividend? Is it done on a -- this is what the results were for the quarter. And so are we looking at being slightly more stable in that sense. And then the second one, if I could cut to move in the accounting assumptions around the long run and the European gas price, in particular, does that have any implications for how you think about the business and how you think about investments going forward?

Thank you very much, Lydia. You were clicking a little bit. So maybe you can repeat the first part on dividend for me. So I know I got the question right.

Sorry about that. Yes, I was just wondering in terms of the -- how you think about assessing the extraordinary dividend, given how volatile the natural gas prices actually are at the moment. So we obviously had it fall off from where we were in the third quarter, would that automatically translate through to a lower extraordinary dividend in the fourth quarter? Or do you think about it being a little bit more stable?

Okay. Perfect. Perfect. It's a very, very important question. So the way we think about this is that we have in the policy that clearly we will have an ordinary dividend, and then we will use share buybacks to -- in times with high prices, and when we are outside sort of the guided net debt. And then we have used extraordinary dividends because we are in a situation with a very, very strong balance sheet. So what you should expect is that sort of -- we will do a review of the totality in relation to the fourth quarter and Capital Markets update. And sort of, clearly, there will be a clear direction that over time, we will get back to the guided range on net debt. On sort of specifics on a quarter-by-quarter, we will take the approach that we will pay out dividend based on money already made, not based on expected cash flow for the future. So if that gives you a little bit more steer, Lydia, I hope so, yes. And the second one was related to accounting assumptions, and you were clicking a little bit there as well. So maybe you can just repeat that briefly for me.

Sure. Yes, it was more about does the change in the gas prices that you've made, has it start to change how you think about the investment program and sort of how you allocate capital, effectively.

Okay. Okay. Perfect. Yes. So I mean -- yes, so we have updated our assumptions related to prices, both for oil and gas. And those are assumptions that we clearly use in our processes when it comes to planning and prioritization going forward. And then as you see, it is particularly an increase in sort of the gas price for the more sort of closer years up to 2025. So if anything, it sort of points investments in direction to investments that can give gas production in the short-term.

The next question comes from Teodor Nilsen from SB1 Market.

Two questions. First on your updated CapEx guidance, the implied CapEx guidance for 2023 is up from $10 billion to $11.5 billion. I just wonder how is the split between Russia and not more in the portfolio and [indiscernible] and thirdly, inflation. Second question is on Sverdrup. When specifically in Q4, do you expect Sverdrup Phase 2 to commence production? And how should we think around the production ramp-up through 2023 from Sverdrup?

Okay. Thanks, Teodor. So first on CapEx guidance. So you're right. So we have reduced CapEx guiding for the year to be [$8.5 billion]. And to give maybe a little bit more granularity into the reduction. It is not driven by sort of changes in sort of inflation because we don't see it really in sort of the reported numbers, but it's driven by some delayed CapEx, and that Russia is not sort of part of the guiding anymore. So Russian is out. And sort of we see some slight changes to Vito in the group of Mexico operated by Shell, and a little bit in sort of the Brazilian assets. On top of that, we have sold a share in North Platte in Gulf Mexico to Shell. So I think those give us a more of a complete picture. So then some of this is moved on to next year. And we have said that the average for 2022 and 2023 will be $10 billion. And clearly, we will come back to maybe more details on that in the Capital Markets Day. On Johan Sverdrup Phase 2. Yes, thank you very much. And coming back as the CFO, I really appreciate you all said, I must -- a long awaited itself to say. So Johan Sverdrup Phase 2 will have a production capacity of more than 200,000 barrels per day. So it will start sort of towards the end of the quarter. I don't have a specific date for you. But we do believe that it will come at full capacity during 2023. And when you add together Johan Sverdrup Phase 1 and Phase 2, you get to around 750,000 barrels per day in production, which is, of course, a very big contribution to earnings in '23 and going forward.

The next question comes from Yoann Charenton from Society Generale.

I have 2 questions, if you don't mind. So first, one of your remarks suggested that one should account for tax payables when assessing whether the net debt ratio is actually within the targeted 15% to 30% gearing range. Just to avoid any misunderstanding, are you saying that the net debt ratio is already back within that tranche from your viewpoint? So does it mean that there is currently limited room for maintaining capital distribution above CapEx guidance next year based on the current energy price environment? And second question, if you don't mind, at the start of the year when your predecessor presented your multiyear organic CapEx guidance, the company's project portfolio contain a few Russian projects. You have now exited the country. And the CapEx guidance beyond this year is maintained based on an unchanged USD, NOK exchange rates. As such, does this maintain or unchanged guidance for CapEx from next year onwards, captures a range of factors you touched upon in your remarks, which are basically inflation -- supply chain bottlenecks and possible changes to Norwegian development plans in response to lower tax deductions.

Okay. Thank you very much, Yoann. On your first question, on tax payable. So let me be very clear. We currently have a net debt of minus 19%. So the point I would like to make is that when prices are very high and earnings are very high from Norway, we will build a tax credit position that we have to pay back over the years. And sort of as prices come down, the tax credit will be reduced. So clearly, we have -- I mean we will not pay all our outstanding taxes in one go, it's just to illustrate the point. So this will be a slow-moving thing, and we will always have tax credits, but it will be dependent on the price level. So when we see a drop in gas and oil prices, the tax credit will go down, and the net debt will be -- net debt ratio will be higher. Then on your question on Russia, and exiting of Russia. So clearly, that will have an impact on sort of future outlook for the company, both when it comes to CapEx but also production as such. So we are not ready to give an update on how this will look beyond this year. So all of this will come together in the Capital Markets Day that we will host in early February. So I'm looking forward to see you there, you all.

The next question comes from John Olaisen from ABG.

I got a question on the -- let me see what my question was actually. Related to the profitability in renewables versus oil and gas, the last couple of years, Torgrim, you have been -- you've been busy with the renewable business. So probably a few people in the world knows more about profitability for projects in the renewable industry than you right now. So I just wonder -- if you look at -- right now, of course, the profitability for oil and gas are very high and for renewables is very low. So I wonder if you could elaborate a little bit on where you see profitability in renewable projects right now and going forward. Because I think that's important to bear in mind, since you have -- Equinor has a strong strategy of expanding in renewables. So I think your view on the profitability for renewable projects will be extremely interesting to hear, please.

Thank you very much, John. So it's a very, very important question and something clearly we discussed extensively, internally as well. So maybe first, so far, up to now, the renewable business have delivered actually, must allow myself to say, significant value creation, clearly, driven by that we have excess opportunities earlier. We have derisked them, and then we have divested half of them. So actually, I think there's some 2 -- yes, more than $2 billion in gains within that business. So, so far, we have net invested $2.5 billion into that industry. So I mean, it's so far actually gained quite a bit of money. Ongoing forward, and the underlying profitability in the project, yes, it is clearly lower than within the oil and gas activities, but also with a very different risk associated to it. So what we see is actually that there is a lot of competition for new opportunities and seabed leases in particular. We continue to see that area, and it has been so competitive that we actually have not won leases over the year. I think we actually didn't win in 4 of the last leases. And to be frank, I'm actually happy or not happy. I'm okay with that. Because, I mean, the prices were too stiff as we saw it. But we'll continue to participate. We will continue to monitor it. And I do believe that with increasing interest rates and sort of tighter capital available that it will sort of drive more normal economic behavior in many of these lease rounds. So we take a long-term perspective on that. We have started to build more of an onshore portfolio, particularly in Europe, but also in Brazil, where we actually see that it's possible to capitalize on taking a market perspective, making money through Danske Commodities and seeing the whole power market altogether. So actually promising results for many of those investments. And those are sort of more short-cycle investments, and quicker to returns and lower capital intensity. This is a long reply, John, but I think it's a little bit color what I've been doing over the last few years. Maybe the -- what I would like to highlight as well. I mean, we see that for renewable to become a competitive business within an industry. We need to allow that business to be run differently than the oil and gas activities. So we're -- we'll be making changes to how we run our renewable business, still safeguarding all the big synergies that we have as being part of Equinor. So clearly, we aim to capitalize on the best of 2 worlds, giving sufficient freedom for that business to develop as needed, but really capitalizing on being part of a big and strong company like Equinor. So you'll probably hear more of that as sort of step that matures.

And maybe I have a follow-up on that. So 2 particular projects is solar in Poland, and your Brazilian projects with [indiscernible] Solar. Is it possible to give us some kind of indication if those projects -- the equity IRR on those projects are above the -- the cost of equity for those projects? And is it possible to give like kind of a factor? Is it 20% above required equity return on those projects? Or is it below cost of equity?

Okay. We just installed or started our first solar asset in Poland. So -- and also -- and that we are doing through sort of the Wento acquisition we did earlier on. The Brazilian assets we are developing together with Scatec. And I won't go into specific returns in those but they are within sort of the guided range that we have said related to the renewable business. On your point on equity return, you're right, these projects, particularly the one in Brazil are product financed and then sort of equity returns is driven by the leverage that we put in those projects. Yes.

All right. So that was 2 questions for me. The final question is regarding CapEx. You don't make any change in your CapEx guidance. But as you mentioned, you talked about -- or you talked about inflation and bottlenecks. I just wonder how should we interpret that? Should as interpreter we say that it could be upside in the CapEx guidance between now and '25 if inflation comes in? Or is that already taken account for in your CapEx guidance, which you launched, if I remember correctly, a year ago or in January.

Thanks, John. So I mean, what we have updated today is more on the short-term topics. And we will revert on an update both in the shorter term and longer term on the Capital Markets Day, but I just want to leave with you that what we see is an increased pressure in the supply value chain, both when it comes to costs and also when it comes to the ability to execute with a capacity constraint. So probably nothing new compared to what you have heard from other companies.

The next question comes from Martijn Rats from Morgan Stanley.

I've got 2 questions as well, if I may. On the issue of gas production, you're sort of basically telling us is that Equinor from now on will start to act more as a sort of a swing supplier in this market, cutting production when prices are low. But these days, it's very hard to know what low really actually is because we've seen such a wide range already. Could you speak a little bit about what you would consider to be a low price that might trigger you to actually do this. And at what price you would mostly then be looking at? Is it they had months ahead I think for sort of market liquidity, and those participating in gas markets, it would be useful to know what's sort of the framework around these decisions would be, also simply to help the sort of working off the market? And then secondly, also related to the gas market, I wanted to ask you what you would currently consider to be the main bottleneck in supplying more gas to Europe. Is that mostly the ability to produce natural gas from the fields that you have? Or is it mostly related to infrastructure bottlenecks? And also given the situation that we have, and consistent with the revisions that you made to long-term TTF price assumptions, how you would consider about the CapEx budget, specifically for gas production and infrastructure-related assets. Should we expect at the Capital Markets Day in February, an increase in gas-related CapEx. Would that make sense?

Okay. Very good, Martijn. So first of all, the flexibility that we have in sort of our gas machine, as we call it, or the gas production system is something that we have had for many, many years, and is sort of built up deliberately for us to be able to reach various markets and to optimize or provide gas where it's most needed and also to give us flexibility to time the deliveries, to when gas is needed and the prices are the highest. So the results in the third quarter that you have seen from MMP is very much driven by actually -- I think it's a proof point that sort of what we have built up over many, many years is really working. It's working for Europe and is working for the bottom line for Equinor. Then on your key question, being a swing supplier. Well, we will not be a swing supplier. I mean we will produce natural gas as a base provider of energy to Europe. But within that machine, we have flexibility, and I can give a couple of examples. We have Oseberg where you sort of have a production permit that we can produce during 80 days of a year. So we can pick the best days to produce Oseberg. So that's sort of the production permit. So that is in sort of a gas storage term. I would probably call it Europe's largest short-cycle gas storage. Then we have Troll, which is a very, very large producer. That is typically production profile from Troll. It's produced at full capacity during winter and lower during the summer, and it has flexibility to move gas between summer. So it's more of a seasonal storage if you want to compare it to sort of the storage methodology. And then there are a lot of other smaller flexibilities around and production permits that we can optimize, and all of that. So we will adjust -- on top of sort of the base production, we will adjust the gas production depending on when the gas is most needed in Europe, and to the market where it is most needed. And price signals is what actually dictates where the gas is needed at any point in time. So MBtu prices currently are significantly lower compared to what we have seen lately. So yesterday, it was at $6 per MBtu and then for the day before. So clearly, that gives opportunities to defer gas. And also, we are in a period where there's not a big need for additional gas to the U.K. Yes, you had a question about infrastructure bottlenecks. Clearly, there are bottlenecks. I mean, infrastructure, there's a maximum capacity in all infrastructure. But in total, there is flexibility to route and reroute and swap volumes compared to the various landing points at that point in time.

Next question is from Kim Fustier from HSBC.

Two questions from me, please. Firstly, just going back to gas pricing mechanisms. There has been a lot of talk for many weeks now about a potential EU gas price cap. I wondered if you could share any thoughts you may have on this, particularly on the feasibility of such a cap and potential wanted or unwanted consequences. And then my second question is on LNG. Some of your peers are making a lot of money these days off taking U.S. LNG and bringing it to Europe, and I appreciate that you're a huge seller of pipeline gas to Europe, but you've did your toes into U.S. LNG with that contract with Cheniere you signed over the summer. I was just wondering if you're considering further increasing your U.S. LNG offtake.

Okay. Thanks, Kim. So yes, I mean, there are a lot of discussions related to efforts from the EU and mechanisms to manage a very critical energy situation for Europe. And yes, we understand that, that is a pressing issue, and that is being discussed. So -- but I think it's fair to say that anything discussed so far has not been firmed up -- and there are sort of elements are moving quickly around when it comes to the various mechanisms. On a price cap in general, I would say that it is important that -- well, the problem is actually it's too little energy available to Europe. So I mean the best we can do is actually to produce more gas to Europe. So that's clearly what we want to do. And what we see is that sort of pricing, and market prices is the best way to manage demand and supply. So if we sort of make changes to well-functioning market mechanisms, we might end up in a situation where demand probably too high, and it won't be able to attract the sufficient volumes to supply Europe. So I think any adjustments to well-functioning market mechanisms needs to be sought very well, too. Then on LNG to Europe yes. As you know, we have a significant gas production in the U.S., in the North West coming off of the Marcellus area. So that is sort of serving the Northeast and U.S. markets. I mean we have access to some re-gas capacity. It's not a big element of our earnings, but we have some. And we will, of course, always consider opportunities, but we know that prices are volatile, both on the U.S. side and the Europe side, and the margin in between, very volatile. So clearly, we will take a very cautious approach in exposing us to a volatility that we can manage.

The next question is from Amy Wong from Credit Suisse.

I just want to hear -- and I hear from a practitioner in renewables. In the U.S., you've got the inflation Reduction Act. You lot of talk of more policy moving things forward. And also in Europe as well, a lot of the politicians are very vocal in terms of saying trying to remove lot of the obstacles and moving faster on sanctioning projects. So I'd love to just get your thoughts as a practitioner, whether you're seeing a lot of that rhetoric really turning into action. What are you seeing on the ground there?

Thank you very much, Amy. Yes. So first of all, I would clearly give credit to sort of the federal offices in the U.S. for putting forward the inflation Reduction Act. I think it's a very, very important one, and we already see that it is attracting capital to the U.S. So as I said, very supportive. I mean there are several elements to it. There is a minimum tax, was called a minimum tax of 15% put on sort of upstream production. So that is something clearly that when we understand the details well, we'll probably have an impact on -- going forward. It will be effective from first of January 2023. So we will come back on the Capital Markets Day on sort of what sort of impact that may have. On sort of the efforts pointing towards the renewable business, investment tax credit is sort of a key. And what we currently have is an opportunity with 30% investment tax credit, which is clearly very important for the profitability in both the Empire projects and the Beacon projects. And with the new IRA, there are opportunities to qualify for a higher ITC based on sort of local content or investments done in the U.S. So that will be very important, but it will take that many of the suppliers will have to establish themselves in the U.S. to facilitate operators like us to use them. So what we typically will see is sort of an inflow of investments from suppliers, and then probably also for investors that [indiscernible] into projects. So we welcome very much the IRA on the top level.

Just a quick follow-up on your comments on Empire and Beacon. Would those tax credits actually move the dial-in terms of your IRRs in the projects?

I mean the use of the investment tax credits are important for the returns in those projects. So the higher the ITC credits, the better returns.

Ladies and gentlemen, in the interest of time, we have to end the Q&A session now, and I hand back to Mr. Mads Holm for closing comments.

Thank you, operator. Thank you, Torgrim, and thank you all for your time this morning. As always, if there's any further questions that you have, please contact the Investor Relations team on the usual numbers, and we'll get back to you as soon as we can. Also, please note that we plan to host a virtual gas market update, November 14, 3 p.m. CET. So once again, thank you for your time, and have a great day. Thank you.

Ladies and gentlemen, the conference is now concluded, and you may disconnect your telephone. Thank you very much for joining, and have a pleasant day. Goodbye.