TotalEnergies SE (TTE) 2023 Q2 法說會逐字稿

Ladies and gentlemen, welcome to TotalEnergies Second Quarter and First Half 2023 Results Conference Call. I now hand over to Patrick Pouyanné, Chairman and CEO; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.

So good morning, good afternoon, everybody, wherever you are, Patrick Pouyanné speaking. Before Jean-Pierre, we'll go through the details of what we could characterize as a solid set of numbers, I would like to come back in the solution among the major investments that we have announced in this last quarter, which are a good illustration of our oil and gas and electricity strategy which, in fact, are based on these 2 fundamental growth pillars on one side, growing our hydrocarbon base, mainly driven by LNG, but all, of course, is our cash engine of today; and secondly, developing a profitable and integrated power business, which is key for the future cash engine of the company.

Results, I should characterize them as good cash flows, good (inaudible) and good distribution, strong distribution through buybacks. So continuity and strong and solid set of numbers, but Jean-Pierre will come back on it.

So first, on the first pillar, I would like to highlight some few important projects. The first one, of course, is our projects in Iraq, we call GGIP. You know what the companies were doing in Iraq 100 years ago, but it's not a matter of emotion, it's a matter of creating value, let's be clear. And the GGIP, in fact, providing for us access to exactly the type of hydrocarbons we are looking for, low-cost, low-emission oil and gas because of both projects and targeting both. Whereas gas being, of course, a source of gas for (inaudible), but all as in Iraq we feel we will have to increasing production of (inaudible) our second objective, though, I would say, a breakthrough contractual, breakthrough innovative, contractual conditions compared to previous service contracts, which were signed by others in the past. This contract offers an attractive reward well balancing, of course, the Iraqi rates. We are fully aware of that.

Second, of course, example, a very major example of the strategy in motion is our new projects in LNG projects in the U.S., the Rio Grande LNG projects, which we have announced in June and which now is FID. You know that we are very committed to LNG. We think that is a growing demand, and that -- of course, the U.S. position is very important because you have lowest cost -- a very low cost source of gas there. And I would say this is a project on which -- is attractive because it's one of the most competitive LNG plant with $850 barrel per tonne. Rio Grande project benefits from a very good location outside, I would say, the Louisiana crowded area and more importantly, access to scale forces with no competition, limited site preparation. So again, it's a CapEx competitive project. I know it's a matter to deliver on it.

More importantly, of course, for us, we have decided to integrate that project by different angles. And why do we integrate it by different angles, becoming equity holder shareholder of Mexican, the company promoter of the project, but also direct investor in the projects with 16.15%, and also, of course, as a speaker.

We've done that because, in fact, we are leveraging with integration in order to have access to the most competitive pricing for U.S. LNG, and which will give us a clear competitive advantage on the market. So it's not only a matter of taking, but the integration gave us the capacity to negotiate better price than others. And that, of course, has -- it's a source of value. We might also enhance there's a value of the project by further integrating the upstream in order to protect our gas feedstock costs in the future. Another upside will come also for expanding the plant from 3 to 5 clients.

So that's why we consider that not only being in the stake, but more importantly, also to contribute directly to the investments is way to leverage and to create different sources of value from this project.

Last project, of course, (inaudible) from oil and gas is the final award of the contract for the Amiral project in Saudi Arabia in petrochemicals. In fact, it's really, I would say, leveraging the (inaudible) platform, an integrated platform, the world-class petrochemical facility, well supported by the Kingdom of Saudi Arabia in order to get advantaged feedstock and a very competitive project.

Then we have also, during the quarter, continued to deploy, I would say, the second growth pillar of the company, which is building the profitable integrated model in electricity, so integrated power. So it's oil and gas on one side, integrated power on the other side on which we focus, I would say, our transition strategy.

Two events, we had 2 deals or 2 projects happened during this past quarter, very recently. By the way, one is the full acquisition of Total Eren, which has been announced for quite a long time. You've seen through the figures that it's $400 million EBITDA. It's a company and cash flow for additional cash flow next year for TotalEnergies. The multiple is quite attractive. It was negotiated 5 years ago. It's 3.5 gigawatts. And mainly, by the way, 2/3 of them being in what I call the unregulated countries, so feeding our integrated power business model.

So it's also a lot of competencies since we joined the company in order to be efficient and more efficient with this integration and all the -- know the next step. And I think we'll come back to you on that in September is to we have all these assets around the world, it's a matter of industrializing the way we operate them in order to deliver more value for the integrated power business.

We also won some maritime leases in Germany to develop two offshore. Some people think it's too expensive. It's not because I think it's exactly, I think, what we are looking for in integrated power. It's fitting. It's a perfect illustration of our business model. Why? Because it's the first as our market, the German market, which will offer the best price for electricity in the future. Germany has decided not to go to new players. So you know, in the end, price of electricity in Germany will be supported.

Secondly, it's like an oil and gas concession. Now, we pay only with -- amounts are important, but in fact, it's an upfront payment, like we pay a bonus on an oil and gas concession. For the oil in fact, we expect exactly our fiscal quarters by what do we take upfront, 10%. So for all these 3 gigawatts, it's something around EUR 500 million. And then we will pay a royalty around 20 years. And the royalty by the way, avoid us to pay any connection fee to the gride. So when you look to the math, I can tell you, I'm very happy that we have managed to get access to the 3 gigawatts of offshore wind because it's exactly the model we want to put in place.

Price is not controlled, up to us to decide which part we will sell to PPAs, to general manufacturing industries and which part will keep merchants in order to trade around and to asset integration. So my answer to the ones who have criticized us is that, in fact, we are exactly in the model, not an infrastructure model, but an integrated power merchant model, exactly what we do in oil and gas.

So that -- and you will see us continuing to deploy this strategy. And by the way, it might be because Jean-Pierre -- it's easy for me to explain that because Jean-Pierre will explain you, but these results in integrated well are surprising you quarter after quarter as they will not -- they will continue to surprise you in a positive way. So that's what we want to build.

Back to my introduction, I would say my last comment, of course, is that the Board is very comfortable with the cash generation of the company. So yesterday, (inaudible) its trust in the future by increasing the interim dividend by 7.25% year-on-year and maintaining the $2 billion buyback for the third quarter is the fifth quarter in a row that we stay at $2 billion despite the softening environment.

The payout for the first half is more than 42%, in line with the commitment of the group to distribute more than 40% for 2023. And so I can only reiterate my commitment. And all the transactions and projects, of course, will be the highlights of our presentation to you on September 27 in New York. And then I will leave the floor to Jean-Pierre for getting into the results.

Thank you, Patrick. So let's move to the financials. The (inaudible) environment softened in the second quarter, but still at high levels. Quarter-over-quarter, our Brent was down 4% to $78 per barrel. And European gas dropped by around 35% to $10.5 barrel per million BTU.

In this context, TotalEnergies reported second quarter '23 adjusted net income of $5 billion, a decrease of only 24% quarter-over-quarter and was able to generate a strong $8.5 billion of cash flow. Over the first half '23, adjusted net income was $11.5 million, and cash flow was $18 billion. We continue to deliver excellent profitability, reporting the 22% ROACE for the 12 months ended June '23, and we continue to share our success with our shareholders, as explained by Patrick.

During the second quarter, we paid $1.8 billion in ordinary integrated dividends and executed $2 billion buybacks, which is consistent with this the first quarter distribution despite the softening commodity environment as described. As a result, payout to shareholders, as mentioned by Patrick, was more than 42% over the first quarter -- the first half, sorry, '23. Our balance sheet remained strong with gearing at 11.1% in the second quarter.

Moving now on to the segment results. Operationally, our oil and gas production was 2.47 million barrels of oil equivalent per day, up 2% year-on-year, thanks to new project assets, Johan Sverdrup Phase 2 in Norway, Ikike in Nigeria, Mero and Brazil and Block 10 in Oman The production also been benefited from the integration of SARB and Umm Lulu in the United Arab Emirates.

Note that our oil production was up 12% year-on-year, reaching almost 1.4 million barrels of oil per day. Production for the third quarter is expected at around 2.5 million barrels of oil equivalent per day, notably supported by the start-up of Absheron field in Azerbhijan. Exploration and production reported adjusted net operating income of $2.3 billion, down 11% quarter-over-quarter, primarily due to the lower oil and gas prices. Similarly, cash flow of $4.4 billion was also down 11% quarter-on-quarter.

These are quite resilient set of results compared to the lower environment. I already mentioned the minus 4% for Brent and around 35% drop for European gas prices. As previously announced, we are now reporting integrated energy and integrated power as in the balance segment. So let's move on integrated energy.

In the second quarter '23, LNG selling was stable at 11 million tonnes quarter-on-quarter, benefiting from the restart of Freeport LNG but decreased year-over-year due to lower demand in Europe because of mild weather and high inventories. Integrated LNG generated adjusted net operating income of $1.3 billion, down 36% quarter-on-quarter, reflecting lower LNG price, averaging $10 MMBtu in the second quarter and softer trading results compared to the exceptional rents we benefited in the first quarter in less volatile markets. However, operating cash flow was down only 13% quarter-on-quarter, also due to lower LNG prices, but partially offset by higher margin secured in '22 on LNG cargoes to be delivered in '23.

Given the reduction of oil and gas prices in recents and the lag effect on price formula, TotalEnergies anticipates that its average LNG selling price should be between $9 and $10 per million BTU in the third quarter '23.

For integrated power. In the second quarter, we met our target of double-digit returns, bidding a (inaudible) as an integrated fee and profitable player in the electricity business. So for the 12 months ended June '23, we achieved ROACE at 10.1%.

The truth is in the results. Our integrated approach to the business is working, which combines renewable projects, flexible power generation, energy storage, asset optimization, trading, and B2B, B2C supply. Integrated power second quarter adjusted net operating income is $450 million, and cash flow is $491 million, up 22% and 12%, respectively, quarter-on-quarter due to the good performance of our integrated electricity portfolio.

Integrated power generated [$930 million] of cash flow in the first half '23 versus only $340 million in the first half of '22. The different segments have performed well and contributed to distribute forecast '23 results. Gas-fired power plants will (inaudible) supply, demonstrating the strength of our integrated power strategy.

Net power generation was 8.2 terawatt hours in the second quarter of '23, up 8% year-on-year, as growing electricity generation from renewables was partly offset by lower generation from flexible capacity in the context of lower European demand. Gross installed renewable power generation capacity is now at 19 gigawatts at the end of the second quarter, up by more than 1 gigawatt quarter-on-quarter, including 0.5 gigawatts installed in the U.S. and the connection of 0.3 gigawatts from our Seagreen Offshore Wind Project in the U.K.

Let's move to downstream. So downstream contributed $1.5 billion of adjusted net operating income, down [23%] quarter-over-quarter, reflecting clearly, lower refining margins, particularly in Europe, partially compensated by higher marketing and services results quarter-over-quarter due to the seasonality of the business. The remaining margins were impacted at the start of the period by Chinese exports and the quicker-than-anticipated reorganization of Russian flows following the European embargo.

They were also supported at the end of the quarter by higher gasoline exports to the U.S. and lower diesel imports in Europe from China. Our refinery utilization rates on processed crudes improved to 82% in the second quarter, which is a good performance, compared to 78% in the first quarter. We expect same operational performance of over 80% in Q3. And since the beginning of July, the average refining margin is higher, above [$70] per tonne.

On company working capital requirements. Last quarter, we had an (inaudible) high build of $4.5 billion, mainly related to higher crude and petroleum product from countries and water and to the seasonality of our power and gas marketing business. I said last quarter that we are expecting $1.4 billion good reverse. As indeed, we have a $1.5 billion working capital release, mainly due to the effect of lower inventory, seasonality of payments of the gas and power marketing business.

Of course, we continue to monitor closely and take actions to minimize the working capital requirements. We're expecting in the next quarter some working cap release coming from Exploration & Production tax payment schedules.

Our net investment, second quarter amounted to $8.6 billion, and our guidance for '23 net investments in the range $16 billion to $18 billion. The Board of Directors, as mentioned by Patrick confirmed for '23 a shareholder distribution of more than 40% of cash flow, supported by our Canadian divestments as expressed (inaudible). The Board decided the distribution of the second interim dividend for the '23 financial year in the amount of EUR 0.74 per share, up 7.25% year-on-year, and authorized the company to buy back shares for an additional $2 billion in the third quarter of '23.

And with that, let's move to the Q&A.

(Operator Instructions) The first question is from Christyan Malek of JPMorgan.

I wanted to ask you about the 2 pillars, which you've simplified very well. I know you have framed a compelling case of wind and renewables through optimizing across the value chain. What I'm trying to rationalize is how you generate a return competitive with the oil and gas pillar when you're looking at overall terms for the portfolio. And if you're essentially trying to maximize every dollar you place into your jewels generation, if you will, it just doesn't make sense to me why you don't double down on the oil reserves, while oil is getting firmer over the next few years. So my question is basically, can we expect a higher growth oil target for you over the coming years? And if so, will that take CapEx higher?

Thank you, Christyan. We have -- and we will come back on this question. Of course, it's at the core of our presentation in September 22, all of you and to our investors. It's true that we have quite a large portfolio of oil and gas projects, oil and LNG projects, and we'll come back on it and already know we have Uganda, Angola. We have Iraq. We should have probably -- our Suriname project come in. We are just testing the last wells.

And so -- but to be clear, at the end, the guidance we gave you for $16 billion, $18 billion in an environment that we have like today, it will be maintained, to be clear. And if we have more oil, we'll have to arbitrate the project, we have room to maneuver in our portfolio, let's be clear. So don't expect the CapEx increase. But again, we will not arbitrate against oil and gas, the profitable projects. It's a question of finance.

We have 2 pillars in our strategy. One is our [free] pillar, the oil and if we've more oil I'm happy to deliver oil. We have gas. And we have a global hydrocarbons growth, like oil and gas growth. You can make the math. I mean some of you've knowledge, we'll find a 2% to 3%, I think, but that's good. (inaudible) but we are also a company in transition or integrated forward pillars.

As I said, we simplify and we are looking to the various energy, new energies that we are strong and we consider that of commitment to build this integrated product. And the business we are delivering is the core of our transition strategy. And we might, I would say, simplify the rest of the molecules, which, by the way, we see a demand later than 2030. So that might be -- will be -- we come back on this topic, of course, in the strategic presentation in September. You should describe TotalEnergies as oil and gas and electricity. That's the core of our strategy, more than the sort of the energy supermarket. So let's simplify and then we'll know the value.

The next question is from Oswald Clint of Bernstein.

Just on LNG and specifically United States, you -- TotalEnergies are -- I think, is the largest off-taker of U.S. LNG. It's just -- you've got bigger now with Rio Grande and -- but I wanted to ask about that exposure to U.S. gas feedstock. I think you touched on potentially integrating further upstream. Is there a number here, a percentage, something we should think about in terms of feedstock coverage for these terminals, for these offtakes that you would think about looking forward is the first question, please.

And then secondly, I noticed it looks like you may be planning to drill a well in the South African portion of the Orange Basin perhaps next year. So just curious if you've completed any further analysis over the last quarter around the venous discovery that gives you the confidence to really extend the exploration campaign further south?

The second one, I think we will focus on Namibia. My priority is Namibia. We have drilled an appraisal well of Venus, which is very positive. Of course, we still are expecting the dynamic data. The first test will start beginning of August, and I think when we'll make I'm sure in September, we'll have the results of the first test, which, of course, is important because positivity per well, of course, if it's 15,000 barrels per day, it's fine, if it's 5, it's not fine.

But as I can tell you the oil plant is very big. So my focus will be Namibia first. We have a lot of in place. Of course, we have some license in South Africa, and we will come (inaudible) working on it. But it's -- again, I feel comfortable by -- my priority will be to give value to Namibia if it's confirmed. And then we'll see what are the expansion in the Orange Basin on the other side.

Newest LNG exposure, and it's true. We have 10 million tonnes. We'll move to 15 million tonnes. It's quite a big exposure. And again, but -- and you have noticed that we -- each projects, we try -- since I am CEO, not only to offtake, but to integrate the project, government LNG, ECA in Mexico, Rio Grande. Why? Because when you contribute to investment, you have a leverage on the pricing.

And of course, yes, because there is a integration. It's not -- we have already produced a production -- a net production more or less of 500 million tonnes per day in the U.S. on the Barnett Shale agreement we've gained. And we can extend and double but at this quarter. No worries, no worries.

There is no specific -- just for me, takes time. So we'll have opportunities on that, but it's part, of course, because I think wondering the cost of the feedstock is a smart way in order to control the full integration value. So it's part of, I would say, our strategic agenda and integration in the U.S.

The next question is from Irene Himona of Societe Generale.

Congratulations on a very busy quarter in terms of the 4 new projects that you launched in different areas. You referred to the competitive advantage of low cost in all of those. Can you perhaps help us with how we should think about the return on capital in these very different projects, please?

And then secondly, you preannounced the third quarter buyback. Obviously, you are generating very strong cash flow. Why would you not preannounce the fourth quarter buyback at this point?

Okay. It was decided by the Board. The Board, we have to discuss in meeting in September. The Board is meeting in September, have decided to reduce the full distribution policy for the last -- the end of the year. But as I told you, we have the fifth quarter in a row $2 billion (inaudible) be very surprised. And then -- and to give perspective to you in New York compared to these elements.

So we decided that it was -- we maintained the $2 billion per quarter. And again, the environment is softening, so we want to keep that flexibility. But the main commitments have taken to our investment is more than 40% of distribution this year. We have 42% -- or it will not be 40.1%, it will be more at 42%. So we bet you can make the numbers.

But first, again, the Board is working. And remember that the commitment are also linked to the closing of the Canadian sales. And so we are moving forward on these elements positively. (inaudible) So we'll see the score by end of the third quarter and the decision we've said are also progressing -- also due to (inaudible) complete view in order to make the right decision for our investors instead of distribution.

All the projects themselves. I cannot give total figures. You know there are some tracks, in particular, I commented to explain you, but the active projects being -- yeah, that's true, we have created a new category of contracts, clearly, fitting with our standard way to work [in German]. And I commented that the reward was commensurate to the risk.

So also you can imagine that it's positively -- it's a good return. The growth costs (inaudible) the best way to maintain our report in terms of CapEx result like [$7] per barrel. So with a lot barrels there is CapEx, it gives you a good way to be competitive leader or rather than other areas of the world.

So at first, we commented which of the projects I commented Rio Grande. Rio Grande, again, we have good leverage. And again, for us, I'm looking to the way to integrate it with because not that we will invest in the project, but backs to the investments, we negotiated. Of course, I told you a very good offtake contracts. The price is very competitive, and we make money on the -- that we make more money than somebody who do not invest in the project, thanks to our vast stream exposure, the offtake contracts, and also because it's -- in fact, we want to capture the infrastructure margin somewhere, leveraging it through, of course, (inaudible)

Globally, we think the integrated IRR is more than 15% of these LNG projects. So 15% next to 20%, in fact, so just to give you an idea. So globally, it's a strong project for us, which other than [Ty's] comment, I think, sorry to -- I think -- and Germany, to be clear, the Germany projects, I'd say some periods, we are perfectly in line with our double-digit objective in Germany. And even more because I'm absolutely convinced that the German electricity project price will be meeting when we'll come and we'll have flexibility to deliver the double-digit projects better. Okay.

The next question is from Christopher Kuplent of Bank of America.

Just 2 quick ones, hopefully. Patrick, I wonder, as you are highlighting the more than 40% of CFFO payout ambition, whether you've learned anything from last year's special dividend. Is it a fair assumption to assume that the continuation of the $2 billion buyback run rate into Q3 is by now your preferred way of redistributing these, let's call them, extra proceeds from your expected oil sands closing? So just wanted to see whether you have a view on what the market prefers, buybacks over a special dividend.

And my second question is going back to the LNG portfolio, which is growing nicely. And I wonder whether if you consider all your options that are still pre-FID. And I would count Mozambique into that, too. Whether you think, by the end of this decade, all these options will actually be in development and will be operating? Or whether, to your point on CapEx, whether you're answering -- actually, it might be a good thing to have more portfolio options because then you can be tougher on the returns you can squeeze out of them from a project-on-project competition. Talking about P&G, Mozambique, of course, Arctic 2 is no longer in your consolidated numbers. And you're very busy in the U.S., too. And I'm not even mentioning some of the smaller assets. So sorry, it's a long-winded question, but hopefully, a relatively short answer.

Don't worry. It's always (inaudible) relevant question. I'm thinking exactly like you. I'm taking the second one first. And it's clear that today, the portfolio, we are in a position to arbitrate these costs [up to a settlement]. To be clear, I think we'll make an arbitration in the U.S. And because [a 57%] of the [Eren] is better than the cost we are seeing today from the additional train on Cameron. So I mean I have the option. And clearly, I'm very comfortable. And if the CapEx on Cameron will not decrease compared to the first feedback we get to contractors, it will be easy for us to postpone it, and then we'll come later. (inaudible) but not just one.

We [can't] keep it in the portfolio. We are delivering PCA Phase 1 shortly in Mexico. We have also the possibility to expand and then again, semester arbitration, [resigned] a specific position that we can arbitrate it. And so the key for me is really what is the position of the project in terms of quarter end CapEx per ton is very important to keep that discipline because at the end, long-term projects, that's the key.

On recent PNG, we'll see what we did across at Mozambique, we have a public debate with subcontractors. So we are keen to deliver them and that's part of the plan. But again, as I said, we have an anyway large portfolio, and we work on all of them. And at the end of the day, if the CapEx are not meeting our expectations because (inaudible) markets, we know we'll arbitrate.

But again, it probably -- I mentioned the North American project because it's where we see many projects coming together. And so I'm more -- I think on the international area, we'll find a way to make this project going through. And again, we are in a,I would say, comfortable position to be -- to select the ones on which we consider we have better returns.

On the cash flow, we are not exactly the same position last year. Last year, remember, the special dividend gain of super revenue we generated last year, $45 billion of cash flow. This year, we are more (inaudible) $18 billion for (inaudible) and $36 billion, $35 billion, $36 billion. Again, it's not $45 billion. So the post is making a difference between $45 billion and $36 billion. Even if we receive $4 billion from Canada, we make $40 billion and not $35 billion, $36 billion.

So we keep up the debate there. We also know that today's market is keen on buyback because we consider that the share of TotalEnergies is undervalued compare to some of our peers. So there is a certain logic I think of the Board, who shows the trust in the share. (inaudible). So that's my -- the argument. But with all these elements, I think you can make the conclusion yourself or we'll see. But let me be clear, we drive my math on 27th of September to refer those to the markets.

The next question is from Lydia Rainforth of Barclays.

Two questions, if I could. On the renewables business, clearly, the capacity and development has gone up again this quarter to the 50 gigawatts. Can you talk about what you're seeing in terms of the cost of this? And I think this was related a little bit to the German wind farm as well that actually people are worried about costs going up. And I think sometimes the idea of the grid connection costs and the integration with the rest of the business that's missed. But just are you worried about the cost base in renewables at this point on the CapEx side?

And then secondly, Patrick, probably, we've seen oil prices rally in recent weeks, and we've seen refining margins rally more. Can you just talk through what you're seeing in the markets in terms of demand at this point?

Okay. The first part, to be clear, it's like exactly at the end, it's likely (inaudible). We will invest in projects if we (inaudible) returns we get. And that's why, by the way, the German auctions were interesting because, in fact, we have committed the bonus to get the option in our portfolio, paying 10% of the (inaudible), I would say, a bid, which is for me, I'm putting my option. Like when I'm buying an exploration license in Brazil, I could pay you bonus of $300 million (inaudible) there, this one [I'm sure there is win]. But the cost has to be better. You have the cost.

So of course, we see that there is -- and again, it's a question of, honestly, (inaudible) told you, I'm not surprised at the end that all major companies are coming into that business because it's clearly exactly the type of projects that we are able to manage, project management. We can leverage the skills of the company in relation with its contractors. It's exactly what we do in any offshore oil and gas projects. So for me, that's the right way to look at it. So I'm not worried. I'm just -- I'm not worried. I don't like CapEx (inaudible) in LNG, in oil offshore nor in offshore wind. But to us, to leverage the processing power. And I think this is where we have an advantage.

I think TotalEnergies, in this business, I think in scale on the value and the purchasing power of TotalEnergies, CapEx has to come efficiently. We have approved a very large solar module contract to cover part of our future needs, leveraging or projecting product. So that's where we need to work in order to be more efficient. (inaudible) the stage of things expecting from us to be efficient.

And again, the other point for balance is that we consider by European electricity price because of all that happened in Europe, no Russian gas, more renewables, the nuclear actually comes more expensive, nuclear. So price will go in the right direction. So that's one we see fundamentally. And we believe there is volatility, of course, but the price is up. So we understand the concerns that we have, and it's up to us. Exactly same answer (inaudible). We have to manage this CapEx side.

Refining margin. So refining margin. Okay. Well, we see the refining margin. I would say today on the (inaudible) first margin today, as I said (inaudible) $70 per ton, which is more the average [inside 4 to 5 months]. They are supported as well on gasoline by the season, the average which is quite -- we have more consumption in Europe and in the U.S., on both sides.

So in the U.S., the inventories are quite low, which means that today we export gasoline from Europe to the U.S., which is good for my European refineries. And I just [would that] they have a good performance availability today, more than 80%. So that's what we think on the gasoline. So we are positive on the gasoline.

On the diesel, the demand draw is true because it's more into, I would say, the global macroeconomic environment. But we can benefit also an effect in Europe. When the running is low labor or low water, then you have some problem of supplying Germany, and then you create some upside in our downstream business. So it's another part of it.

So I would say each time I'm trying to get (inaudible), but we are more positive on the refining margin for the third quarter. But I would be surprised to go down to $40 per ton, which (inaudible) an average on the second quarter. I think the third quarter will be (inaudible). That's my view on these markets.

By the way, when we [spot], we finally do not like hot weather. So running a refinery is not so good in particular when the weather is too hot. So it's good for margins as well.

The next question is from Alastair Syme of Citi.

On Iraq, I understand it's confidential. But are you able to say maybe what your maximum capital employed exposure would be in the country? We all see the $27 billion headline, so I just want to get it some context.

And then I'm just interested and fascinated in your comments about Germany having the highest power prices in the future. And that's quite a statement about one of the industrial powerhouses in Europe. How do you think about the issue of industrial competitiveness and affordability for consumers?

Iraq, $3 billion maximum capital employed, $3 billion. Beyond 45% of CapEx, which are around $10 million -- $10 billion, but we are also of portfolio production coming onstream immediately. And the beauty of the contract is that (inaudible) producing will stabilize very quickly the production to 50,000, 60,000 -- 60,000 barrels per day very quickly. (inaudible) we work a bit on the year end.

Then we have a phase on the improvement of the oil production up to $90, $120 per barrel per day and then going to [12%]. So we have some cash coming in. So it's a way to generate -- to lower our exposure as part of the scheme we have in Iraq. So keep that in mind. And $3 billion, for me, is very acceptable with the terms we have. So that's the clear answer to you.

Germany industrial competitiveness, okay. I mean it's a more global question. The question will be more for the space, which is how do we -- what will be again. And we see that what will be the support of the states to energy-intensive industries is, in fact, the question mark. But I think in Europe, thinking that the price of electricity might be around EUR 70, EUR 70, EUR 80 per megawatt, it's not a bad bet, in fact. So that might work. But it's a matter of course, I will tell you, of we'll go to some industries.

It's a long-term commitment. The only thing (inaudible) answering to the government, to the -- my -- to the customers, if you are ready to take some long-term commitments, we have to lower the price. In fact, (inaudible) just a question of if you want to stay (inaudible). And I don't comment anybody to invest in Europe based on spot prices because then you could be in trouble.

So we see what we disclosed last year, I would say. So I think the question for me is, yes, there is room for industrial competitiveness in Europe and Germany if we are able to put together some long-term contracts. And I think this is part of our intent with these offshore wind development will be to commit some of the capacities to this type of long-term contracts and to keep part of it as merchant. So we have been famous at (inaudible). But we have -- we know that this is the type of price we can update today in Europe and Central Europe, and people are ready to commit on this level of pricing.

Patrick, can I ask, when you speak to politicians, are they surprised in that EUR 70 to EUR 80 megawatt hour sort of number? I mean that's twice what it used to be, right?

Yes, but the truth is the world has changed again. The world has changed. I mean we have to be clear for (inaudible) [the energy] transition has an impact on the energy prices. And there is no way to make a transition in Europe without even a higher price. And I think they understand. The new nuclear is not under the price that adjusts to get you (inaudible) and so we can have to the U.K. investors or to the French government, I will tell you. So I think it's part of the transition and we have to adapt towards this fact. Going at the end customer, we have to accept to pay somewhere the cost of energy, the cost of the transition. But you know, I observed as well in the U.S. that today, the contracts, given the solar contracts in Texas, began to increase a little and to recover. So it's part of the -- we have to keep that in mind.

The energy transition will happen if we have access to cost increase. And we have a super efficient system -- gas system. And we want to move to a system which is not inefficient in terms of energy efficiency. That has a cost, that has a price. And it's a real question for all of us is at which space we make that transition in all the customers to accept it. It's what we call the just transition.

We have to manage the transition. If it's just, it will be effective. So that's -- so I'm not sure they are so afraid. There's just a matter of accepting (inaudible) and we have to be consistent. That is a question for industrial competing for European manufacturers to be competitive and probably to have like the U.S. finally to take actions in -- as we are accessing this price of (inaudible) somewhere, we have to protect these companies' industries otherwise. Europe is integrating price of CO2 into products and not the other countries will have an issue (inaudible).

The next question is from Biraj Borkhataria of RBC.

First one is on your LNG business again. In the past, I think you used project financing that delivers some projects. But obviously, your balance sheet is extremely healthy at this point, and you probably have some capacity to take on some more CapEx. Could you just talk about your plans and whether it's Rio Grande, Mozambique or otherwise and your intentions on financing? And how you're thinking about that split between balance sheet and off balance sheet?

And then second question is just following up on Al's point on competitiveness. Obviously, you have a refinery in Germany and chemicals operations. With your view on higher power prices, obviously, that feed into gas prices, and then you've said you want to take (inaudible)

Of course, we will partake, but when the [Mozambique] will start, of course, (inaudible) the project management.

So the conditions are good. So as soon as conditions for post financing are okay and competitive to our equity, I would say, I think we'll maintain that stance. PNG, I don't know, we are not yet there, I think, today on these projects, but we are working with Japanese banks are very attendant to finance PNG, and you could have good conditions in Japanese banks in that part of the world.

So from us, it's -- I think we are fine with that, and it's part of the -- it's a way to globally have the returns I mentioned to you. On Rio Grande, for example, 15% to 20% are baked into account. And on the view on (inaudible), its strong, that's what you said, [the 52]. Yes, I can tell you when we look to our refining breakeven in Europe today, 26 compared to 21, no more Russian gas, no more plus CO2 pricing, last quarter, at the end, there is an impact. And we think the breakeven went probably up from $25 per ton to $30, $35 per ton.

So at the end, the question is we have to work in order to find the efficiency way to compensate it. And this is why, by the way, my position on refining in Europe, it's a good way to transform to biorefineries. And so it's a question of the pace of it.

So I mean -- so we are managing that already. We have transformed 2 refineries. The next one will come, as I told you before, because we understand that the question of competitiveness and we take it into account in our industrial decisions. That's obvious. So I cannot hide it.

And I think -- but again, the question will be there on this type of probably more complete for plans for refineries in Europe because they are (inaudible). we don't like that too much. But again, it's a question of security of supply for the government. And this is the best we have today.

If we are to maintain this activity in Europe, because you still need a gasoline and diesel and you don't give us conditions in order to have an attractive, I would say, returns, we might take decisions which might be detrimental. But again, there are also positive ways to look at it. We are working today to see how we can leverage all the hedge free directly in order to get the green hydrogen and could work additional revenues. In fact, when you look carefully to the new scheme which has been published by Europe, so you can see it's a cost -- CO2 as a cost, but CO2 might be a source of revenue as well when you combine green hydrogen with CO2 products. And we are working on 2 projects, one in France, one in Germany, which will bring additional revenues, which might compensate part of the company -- the lack of competitiveness.

I think it's 2 ways to look to the energy transition.

I can look at a cost or an opportunity. It's a price framework I put into -- in place. It seems to be the case for hydrogen. With adoption there is a strong push. Then that might become a new source of competitiveness for refineries in Europe. And we are working on it. And I think in September, we'll be able to come back to you and to give you 2 good examples where we created value from, I would say, these energy transition framework.

And so that's also, I would say, is a case of a negative and a positive way to think to that. By the way, I'm convinced that the transition will work only if we create opportunities and not just including cost and prices.

The next question is from Kim Fustier of HSBC.

Firstly, just on your existing targets on renewable capacity. I was just wondering what is the acquisition of the 71% stake in Total Eren and then other deals as well that you've announced. So what does this do to your targets, particularly the 2025 target of 35 gigawatts? If I recall, you'd already reached a pipeline of over 35 gigawatts more than a year ago. So I mean there's upside to that 35 gigawatt target? Or do you have the opportunity now to pick and choose the best projects as you talked about with respect to LNG and high-grade your project portfolio?

My second question is around reports a few months ago that Total was looking at a major gas development in Saudi Arabia together with Saudi Aramco. I just wondered what the angle is here. Is this about the domestic market or more about exports in the form of either LNG or blue hydrogen or ammonia?

We don't have a good information on the second one. I don't think you should believe (inaudible) agencies are pricing in the paper.

The second one, because as long as I know, Saudi Arabia has a lot of (inaudible). So the second one -- the first one, to be clear, it was very clearly in our mind that the acquisition of Total Eren will be part of our road map. So when we set the 35 gigawatts, the acquisition of Total Eren was already there. So be careful there, it's not as an additional element. We knew that Total Eren was working well. We knew where our conditions to leverage our auction. And we've -- the figure I gave you, EUR 400 million is included in the EBIT. You can understand that we can (inaudible) an attractive (inaudible) will use that.

So for me, there is nothing additional. By the way, we are also working more on value and volumes and (inaudible) for me. Of course, there are some simple -- the 35 gigawatts, and we are working. There are optionalities. And by the way, the offshore wind in Germany is not there. It will be 2030, not 2025. There's no way to build any offshore wind in 3 years.

So the more I'm thinking to that again is more if we have more opportunity, we can arbitrate advanced projects, right? Because we have, in my portfolio, more opportunities to reach a target, but we were moving the target up and devoting all the volumes, not volumes over value. We know that (inaudible) its value. So I'm happy that the teams are able to generate opportunity. And then we might recollect the ones which are the best for us.

And more importantly, the bigger one, by the way, at the end, for me, what is important is because it's clear we focus on it is how much (inaudible) for the cycle oil and gas. In oil and gas, [we load by] 2.5 million barrel oil per day. You will have to learn that we will speak more (inaudible) year rather than in (inaudible).

That's what creates the revenues, the reserves and the profit and the cash flow. So I think we should move in that field as well because for me, it's improving. We reached quickly 50 terawatt hours per year, 50 terawatt hours per year. We're looking at the 15 largest utilities. So it's not small. So next tick in terawatt hours per year just in capacity. At the end, what is important is delivering revenues, cash and reserves.

The next question is from Lucas Herrmann of Exane BNP Paribas.

Most have been answered. But a couple, if I might. First, Patrick, Arctic 2, do you have any interest remaining in that project? I'm just conscious of the Novatek comments around (inaudible) start-ups, so on and so forth, and the original position even though you obviously have not been funding anything.

And the second question was just around going back to balance sheet. And how do you think about gearing debt levels absolute at this time? Is the range still 10% to 20%, something you're comfortable with? Just a reiteration, really.

Just a reiteration, we told you before that it was less than 15% we are given, and I told you already, we declare we have a positive treasury. I think the best way to protect an oil and gas company is to have the strongest possible balance sheet.

There is a question of arbitration and the remainder of the scheme we gave you in this year, dividends, CapEx and then strong balance sheet and even targeting potentially at the very rating, we can. So I'm still -- then there's the question of when we are to do buybacks. So we are -- the Board is looking to all of that.

Recently, by the way, Jean-Pierre has bought back EUR 1 billion of (inaudible) debt. So we have decided to lower that debt that because before it was a good way to maneuver. So our balance sheet is improving. So (inaudible) [10 20] is less than 15 and lower (inaudible) as possible. That's my thinking on this (inaudible)

(inaudible) I agree. Yes, I am.

As we have said in March '22, we don't bring any capital from TotalEnergies into these projects. We know the project when we last was, in fact, the equity was already injected, and it was more project financing, in fact. So the project is moving on. We didn't put a single more (inaudible) from TotalEnergies AG from balance.

And then -- so today, yes, we still are around (inaudible) information because, as you know, our governance decided to leave all the Russian assets. So I cannot tell you what is really happening there. I will read the newspaper like you. As long as (inaudible).

Remind me, did you have any legal liability to offtake volume from when you were 2 million ton of offtake agreement?

If the mutual plan is produced, we have some of the (inaudible). I don't remember exactly a specific, but the contract is not (inaudible). We have a long-term contract, 25 years, it's a take-or-pay contract, and we have [one on the amount]. Today, the only offtake, the long-term contract on the (inaudible). Absolutely nothing else than the long-term contracts, no spots, no additional volume.

We have reduced our Russian activity to the only long-term contract. And that's the reality of what we do. And if our Arctic 2 came onstream without a commitment, so I don't remember exactly, I should read that. To be honest, I did not spend much time on Arctic 2 for the last year. And I say, I will -- I think we'll be able to tell you exactly what is the volume. We had a lower share on Arctic 2, by 10% and not 20% of the amount. So I think it's worth proportionate.

And by the way, so we see that we can come back to you. But again, the same policy (inaudible). We have a contract. We have a contract. We have to execute and to do the contract as loan consumptions do not prevent to do it, but we did the same policy. But we can come back to you on exactly where we see uptake (inaudible) 10%. So independently of our shareholding, what happens to our equity, the contract is -- still contract is there.

The next question is from Jason Gabelman of TD Cowen.

First, just on the Novatek dividend. I believe historically, you guys got it in 2Q and 4Q. So wondering if you received the Novatek dividend this quarter? And if not, what the certainty is you will see them moving forward?

And my second question is on goal with gas. There's a lot of concerns around European gas storage actually filling over the coming months ahead of winter draw season. And given your unique position in operating European gas assets, just wondering what your outlook is for the European gas market in the fall? And kind of an extension of that, how these tighter gas oil spreads have impacted your outlook for trading given last year integrated LNG trading was particularly strong in part because of the wide gas oil spreads?

No, we did not receive any dividend this quarter. So that's the first answer. Second one, in new gas storage bidding, it's clear that the storage could be full by October. So today, this is why you have a soft gas price, $10 per million BTU. We don't anticipate difficulties because we exited the window with our inventory, so it's easy to reinitiate and so it will be down.

So that's why today as well, as I have always explained, if the winter is cold, if the Ukranian pipeline, the gas in Russia going through Ukraine is stopped, the situation will be [quickly intentioned]. And also cold weather, if on the top of it, China is recovering the activity and is buying more LNGs, which seems to be the case today, we have another additional factor of (inaudible).

The situation in Europe will be (inaudible). We are relying on the metrological transitions plus external events, including the ones I mentioned about the transit through Ukraine. So that's the reality. So that's why, by the way, the full oil price of European gas is retreating now. So the price is fixed in dollar, the next week, next January, next first quarter, the first half '23, the higher the gross market, you see more H1, more situation bull factor than the H1, I think that's the reality.

So what happens? What will happen? And we'll see. We'll see what will happen, will pass from (inaudible) tension. And by the way, it's also why, today, you don't see manufacturing industry in Europe shifting from fuel to gas. Gas, we've seen because the prices are very high in '22, the manufacturing industries have shifted from gas to fuel. We could have expected about the $10 per million BTU. The price is lower than the fuel price today in Europe, but they stay -- they stick on fuel because they're afraid what could happen next winter. So it's an interesting thing.

That's why people say the demand in gas in Europe is lower and stay low because in fact, they should make that shift on the short-term front. It's only because they are truly frightened by that. There is no stability, I would say, in the gas price in Europe, the volatility. And that's why, by the way, over 3 years (inaudible) into 5 years (inaudible) you can make more money. This quarter was lower volatile, so lower results that we could expect winter (inaudible) So volatility is higher. That's what I can tell you.

Sorry, just to clarify on the first one, on the Novatek dividend. Should we assume that you stop receiving it moving forward?

I don't -- I don't know. That depends on the (inaudible). It depends on (inaudible). So I think I just answered you. (inaudible) decide the Board and the CEO of TotalEnergies, the Chairman and CEO (inaudible) by Russia is not -- no more in my account, not clear.

We do not plan any distribution or any shareholder returns linked to any cash flow coming from Russia, to be honest. So we are waiting, we think we will see because Russia's goal and the figures ensuing to the goal of regards Russia. That's all. Because anything could happen. So I prefer to show in case if something is coming from it, but we are not chasing it. It's more that the way we think in the (inaudible). The consolidation was a very clear decision by the Board in December '22, and this is the way the management (inaudible).

The next question is from Henry Tarr of Berenberg.

I had two. One, just coming back on the hybrid debt. Why did you choose to buy back some of the debt? And would you think about buying back more in the future? And then kind of what did you have to pay for it?

And then the second question is on the downstream. You're talking about changing refineries into biofuels and biofuels platforms. How do you see profitability for the biofuels platforms in Europe? And how are you getting on sort of securing feedstock for those platforms? And are you seeing increasing government support for sustainable aviation fuel and renewable diesel and other biofuels within Europe at the moment?

Yes. First question regarding high grade. So at any one time, our IP portfolio is at its very best, below 3%. It's 2.4%, if I remember well. So we have the flexibility offered by S&P to diminish the global level of hybrid, minus 10% on a yearly basis. In May, we have a tranche maturing, and so we decided to use the flexibility.

All the while, in the market, at present time, variability cost increased compared to the 2.4% I mentioned to you. It's around 5%. So given the cash we are able to generate at present time, so we pass it to the Board, we think -- we do not choose -- we do not need to renew this hybrid tranche, and that's the main driver behind the decision not to renew this tranche. And so we decided to get rid of this EUR 1 billion. Yes, yes. At present time, the cost of the hybrid in euro is more than 5%. So it makes no sense to...

So that means that the vision this year could be renewed for next year just because we don't want to incur [chase behind], so it's just the management of the of the cash and the balance sheet of the company. So I think it's an obvious decision, if it makes sense.

On the downstream, no, we have changed some refinery into biofuels. We changed La Mede which are changing (inaudible). I told you that with the others. In fact, there is a clear framework in Europe, which is why I'm confident in Europe because you have some mandates in Europe. In particular, the sustainable addition fuel in Europe is a mandate. It's not just a target, it's a mandate. They immediately, you create a market and a pricing which will integrate the CO2 cost. So I'm comfortable to invest because I think they really -- Europe is very serious about -- we have a 6% mandate by 2030, which is increasing to 15% mandate in 2045. So it creates a market, a positive market.

Then the big question is on how do you produce it. So you have -- so we like old refineries because we have a CapEx per ton which is lower, but we make (inaudible). So you will not see TotalEnergies investing in mid-shale refineries to make stuff, to be clear. I prefer to convert the old refinery, by the way, in part of the transition. We have realized the demand for gasoline and gas oil will diminish in Europe. We have more EVs in 2025. So you need to prepare the transition and transforming and we can reuse some unit to make a biorefinery.

So -- and the CapEx per ton is around $500, $600 per ton. The (inaudible) is around $1,000 per ton. So let's convert whatever I'm treating new (inaudible) refinery. That's fundamentally our view. But we need to find the feedstock, yes, you're right. And the feedstock in Europe is an issue because they want -- they don't want 1G. They do 1G vegetable oil feedstock. So we need to secure it.

We don't want to import [new scooper] from far away and being trapped into -- I don't know which story about waste imports. I think it's not good approach. But there are ways. We have secured feedstock on (inaudible) by a JV with a German company. We produce and it works fast. So we are looking to that segment. And we are also beginning to look to another technology, which is (inaudible), which might be the next one because when you look to, in fact, to the balance of the European market where in 2035 to reach a 15% mandate, it will be difficult to bid only with repeat foodstock. I mean we've used food color, animal fat. We could have to be organized.

So it opens the room to additional mix technology. So we try to select the ones which don't need the most expensive. We don't need issues, but we might have technology in between providing the fat, I would say, a little more expensive, but not the most expensive one. So this is the way we approach the project this issue.

But again, for me, it's -- for us, the focus will be in Europe again because we have the assets. We know we have to make the transition. It's an opportunity which is, in fact, given to us by this transition or this famous European [green E] framework. So let's seize the opportunity. It's like I said, green hydrogen is the other way to compensate services, the cost of CO2 and the cost of energy in a positive way to create new markets and to decarbonize the airlines. So that's the way we look at it. So we work, and we are doing 2 projects. We are working on the third one.

The next question is from Henri Patricot of UBS.

Yes. Two questions, please. First one, I wanted to come back to (inaudible) strong performance in the second quarter with the earnings (inaudible). As I think you can give us some new details on the driver of the sequential improvement because once you slash that net for production, it's down quarter-on-quarter. So I'm interested to hear what was driving the improvement here sequentially?

And then secondly, on Mozambique LNG, if you have an update to provide on the timeline, the next milestone to -- for the project before we can restart?

Mozambique LNG, we are working on both the parts. One is with the contractors, and I expect that to be done in the second half of this year. So we'll have the answer and I hope could be positive from them. And then we are working also like Jean-Pierre told you on the relaunching, decreasing the financing. So I think my objective -- objective for us is to come to you and to have before year-end, and we say we should have a clarity on the way forward.

But again, we need to notably cost reform and make debt to rate step by step properly, but plus, I would say, as the objective, we are, but if we need to wait (inaudible). I think Jean-Pierre gave you some indications. It's all you. It's coming from a (inaudible). I can't give you, but you know why.

In market for every supply business, the winter is always more tough in terms of business because we have an average cost of supply, more demand. So you have a sort of seasonal effect. I think when you look -- you are following some utilities, you can see the seasonal effect. So it's probably more positive in the second than first quarter.

The second and third quarter are more positive, but we have also good performance coming from our flexible generation capacities because of the, I would say, the gas to -- the spread between gas and electricity. We have some good reserves from trading as well, and we have positive results from (inaudible). So everybody is increasing, I would say.

So there is not one, it's everybody positioned. And by the way, it's why the more we look at it, the more we did our approach of integrated power, and this is why we report to you these results in this way and like we report the results of refining and chemicals in an [interjective] way. And so I think nothing special, everything was positive, which is a good source of, I would say, confidence for the future on this one.

The next question is from Paul Cheng of Scotiabank.

Two questions, please. Patrick, any update you can provide on Suriname? And (inaudible), I know that you guys may not be ready yet, but any kind of (inaudible) capacity (inaudible) for the first (inaudible), assume that that's going to go forward? And also the time line that you will expect for the first order?

Secondly, I just want to see if you can share over the past several months, what's your investors decide given the changing market conditions about your change of investment in the low carbon expectation from the wind and solar [price] (inaudible). I think that the pace is right or that do they think that the pace should be accelerated (inaudible)?

I captured the first question. The line is not very -- sorry, the line is not very good here in Paris on this one. I captured the first question. I think it's about Suriname, I'm sure. And the second is that investor feedback on more integrated on our renewable integrated business, if I understood carefully. Is it right? Did I catch the 2 questions?

Yes.

Okay, good. So Suriname, again, I told you that we are just finalizing the test of the last appraisal well. So I will give you a meeting point in September because my teams are working. I gave you a positive indication. It seems that we are moving forward with development, but I want to keep working in the -- to take all these reserves together, to put that together to have a case.

I think we'll have a case of development for sure. Exactly when will be designed the (inaudible) in terms of my (inaudible) takes you relate and then you come back to me end of August, September. So we'll answer to you with a clear -- I think we have a clear idea by September 27. So come to New York, and we'll have the answer to your question, if not before.

But obviously, we will work on it. I can tell you, we have an integrated group of development. So if it's positive, sanctions might be targeted by end of '24, I would say, and then submission of execution. But more what I have in mind, but again, I want to -- there are still some debate about what could be decided actually. The news that I read is that the benefits should be quite good. So on Suriname. So just a little patience, it will come.

On the -- I mean our investors, on our -- they are just investors. You know they want to have the cash, they also have dividends and cash flow. So if we demonstrate that this business is contributing. And so that's a question mark for us. And I think before I've been trying to publish these results to demonstrate that it's profitable, but we can generate cash flow. And the operation cost will be one that become net cash flow positive.

So -- and again, we are working hard on that because our objective that this should be a cash-positive generator. So we invest more or less in this (inaudible) 4 billion per year. So when do we have the pressure for 4 billion? And that, again, we'll come back to you in September on that because it's also part of the question.

So third question, probably from investors. We understand you are in transition. I think the main thing is, okay, if you focus on one thing, let's focus on it, so that (inaudible) simplify. And again, I think it's better for us to -- I guess in these are last, what we clarified in the last year, which is, in fact, we want (inaudible) apply to reiterate for our business the same way between in (inaudible), the volatility in capturing and integration. I think it's a right answer to [refer to]. And so that where we are to this. So we'll think on our strategy, to be clear. But we might simplify from some molecules part that we are here on this part.

The last question is from Giacomo Romeo of Jefferies.

Yes. I have one last. Just there is some cash flow this quarter and obviously showing the impact of your hedging position integrated LNG. Just wanted to check if you can remind us sort of -- what's sort of the hedging level for the remaining quarters of the year, and whether you're still continuing into your rolling hedging program and given where current gas prices are looking for next year?

It's a strong -- it's a clear policy. We are hedging more than 80% of the portfolio. So what has been done in '22 for '23 is done, and we do same for '23 for '24, and '24 for '25. And that's it. We have a merchant exposure on our balance sheet in LNG, and we assume it, but we try to, I would say, to cover a part of it and to keep some of it margin by the way.

You know that we have decided that all the Russian LNG should not be hedged because I'm not sure that, that will continue. So I mean -- so it's part of the answer. So it's continuing. And so that's why so you should expect the next quarter in terms of cash would be to remain more or less positive because if I remember well, the -- for Q3 and Q4 '23, we are higher than the one for Q2. The war began in March. And you remember, the peak of the prices were in Q3, Q4, not in Q2. So we should have good cash flows, although it might be something that you do not understand about our business, but I think we understand.

No, I'm clear. I'm very clear.

So, I'm joking, I'm joking.

No, no, it's clear.

So the core of the [AGs] will come on the second half of '23, more than the first half. Okay, Giacomo?

So thank you to all of you for your answers and all your participation. And I know that you have a busy day because we are 3 company -- companies are delivering results the same day. I will not be longer.

Just again, the key, I think, on the results of the first -- second quarter, we demonstrated that we are profitable, 22% ROCE. We have a strong cash flow, including from LNG, $8.5 billion, much stronger than, I would say, the decrease of the environment. And further, of course, we are committed to the distribution to shareholders by maintaining the buyback at $2 billion for fifth quarter in a row despite a softening development.

So with this message, have a good vacation, have a good summer. And I hope we meet all of you on September 27 in New York for our update on strategy.

And keep in -- and just to remind you, we took your lesson that you don't want to listen too much to us. So it will be only flexible morning, and then we'll have lunch with you and answering questions. Thank you for your attention and have, again, a good rest of your summertime. Liven it up.

Thank you.

Ladies and gentlemen, this concludes the conference call. Thank you all for your participation. You may now disconnect. Thank you.