Earnings Call Transcript - TTE Q3 2023

Operator, Operator

Ladies and gentlemen, welcome to the TotalEnergies Third Quarter 2023 Results Conference Call. I will now hand over to Patrick Pouyanne, Chief Executive Officer; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Please go ahead, gentlemen.

Patrick Pouyanne, CEO

Hello everyone, good afternoon. If you are in the U.S., good morning. Today, we will share our third quarter results, which once again showcase the effectiveness of our strategy. Our transition strategy focuses on two pillars: oil and gas, and integrated power. This approach enables us to capitalize on positive energy market conditions like those we are seeing today. As we outlined in our strategy and outlook presentation at the end of September, we have remained consistent, and this quarter reflects our strategies at work across all business segments. In oil and gas, we have built a strong portfolio of projects organically, and our focus on low cost and low emissions is projected to yield production growth of 2% to 3% annually over the next five years. Due to this strategy, we achieved a 5% increase in production this quarter compared to Q3 2022, with new projects like Mero 1 in Brazil, Absheron in Azerbaijan, Block 10 in Oman, and Ratawi in Iraq offsetting our natural decline of 3% per year. The downstream sector is also contributing positively to our oil and gas business, especially through our strong refinery utilization rates and robust refining margins. In the LNG sector, we witnessed considerable price fluctuations in European gas markets, with prices soaring as much as 28% in a single day this quarter. We capture value throughout the value chain and optimize margins in both our strong U.S. and European markets. We are the largest U.S. LNG provider and have enhanced this position by sanctioning the Rio Grande LNG project in Texas. We are also the largest holder of oil and gas capacity in Europe, bolstered by the commissioning of our second FSRU in France, following the commissioning in Germany earlier this year. Our integrated strategy is evident in our integrated power business, as the electricity market in Europe is closely tied to the gas market. This market is currently facing rising demand and limited supply, creating opportunities. As Jean-Pierre will detail, Integrated Power reached a significant milestone this quarter, with adjusted net income and cash flow surpassing $500 million. We are on track to achieve our $2 billion cash flow target for the year in this segment. This morning, we announced a noteworthy acquisition in the German market that aligns with our integrated power strategy. Quadra, the second largest aggregator of renewable energy in Germany, manages 9 gigawatts of virtual onshore wind farms and offers a valuable platform for maximizing opportunities in the renewable-dominated power market without substantial capital investment, contributing to our profitability in this sector. In conclusion, the importance of balancing our transition strategy between oil and gas and integrated power has never been clearer: more energy, lower emissions, and greater cash flows. This quarter demonstrated this balance with adjusted net income rising to $6.5 billion and cash flow from operations increasing to $9.3 billion. We generated $4.2 billion in free cash flow after net investments. Given these strong results and our confidence in the company’s future, our Board has approved a third interim dividend, which is a 7.25% increase year-on-year, set at EUR 0.74 per share. Now, I will turn it over to Jean-Pierre, who will provide further details on our solid third quarter financial results.

Jean-Pierre Sbraire, CFO

Thank you, Patrick. So now we're moving on to the detailed financial results, starting with our first pillar, Oil and Gas, which is the cash engine of today. Third quarter hydrocarbon production was nearly 2.5 million barrels of oil equivalent per day, which is notably up 5% year-on-year, as already mentioned by Patrick. Thanks to the startup of several oil and gas projects. On oil, production benefited from new production from the first FPSO on Mero in Brazil, EKK in Nigeria, and our entry in the Ratawi oil field in mid-August in Iraq. Speaking of projects, Mero 2 should be online by the end of the year. Production also benefitted from our entry in January into the project in Abu Dhabi. On the gas side, production benefited from the startup of Block 10 in Oman and the Absheron project in Azerbaijan. Although production was flat quarter-to-quarter, exploration and production posted strong quarterly results with adjusted net income of $3.1 million and CFFO of $5.2 billion. The 34% increase in adjusted net operating income quarter-to-quarter was primarily driven by higher oil prices and a lower effective tax rate, which is a result of two effects. First, the lower taxation rates on new barrels in Brazil, Azerbaijan, and Iraq compared to declining historic level barrels. Secondly, a lower weight of North Sea barrels in the segment results for this quarter. Operating costs decreased to $5.5 per barrel this quarter. For the integrated LNG segment, we continue to demonstrate our leadership as a top global LNG player. Integrated LNG production is up 18% year-on-year and stable quarter-to-quarter. LNG sales were down by 5% quarter-to-quarter due to a decrease in spot traded volumes in a less volatile environment, and LNG price sales were down 3% quarter-to-quarter linked to a certain environment. However, after our results have landed last quarter from the historic high exceptional results experienced in '22, integrated LNG maintained robust results this quarter with adjusted net operating income flat quarter-to-quarter at $1.3 billion and CFFO at $1.6 billion, down 8% compared to the previous quarter, in line with sales down by 5% and prices down by 3%. Despite entering the winter period with high natural gas inventories in Europe, in a tense market, gas prices remain at good levels and very reactive to production disruption as we have seen over the last several months. Given the evolution of oil and gas prices in recent months and the lag effect on price formulas, we anticipate that our average LNG selling price should be above $10 per million BTU in the fourth quarter of '23. For the combined Downstream, adjusted net operating income and CFFO increased sequentially to $1.8 billion and $2.2 billion, respectively. Despite lower petrochemical results due to the European environment, our results reflect higher refining margins in Europe and a higher utilization rate during the third quarter, which was supported by greater profitability of our French refineries. The utilization rate on processed crudes increased quarter-to-quarter to 84% despite an unplanned shutdown at the refinery in the U.S. For the fourth quarter, the acquisition rate should be above 80% and includes the restart of the refinery in mid-November. Moving now to the second pillar, we continue to develop a profitable and differentiated integrated power model, building a world-class, cost-competitive portfolio that combines renewable assets, solar, offshore wind, onshore wind, and flexible assets such as CCGTs and storage to deliver clean firm power. As mentioned by Patrick, this quarter, we achieved a milestone in the integrated power business segment with adjusted net income and cash flow, both exceeding $500 million, and we are well on our way to achieving our target of generating $2 billion cash flow in '23, having already generated close to $1.5 billion through the first three quarters. All the value chain contributed this quarter to these $500 million results; renewables, flexible assets, heavy supply to customers, as well. During the third quarter, we also acquired 100% of Total Eren, which contributed to the growth of our electricity production and results. Early October, we signed a corporate PPA with Saint-Gobain in the U.S. to supply clean power from our Danish solar farm in Texas. The agreement is a good illustration of our strategy in integrated power, including an upside-sharing mechanism under which both companies share potential upside arising from spot market prices over the contract's term. We recently achieved another milestone. Earlier this month, our Seagreen offshore wind farm in Scotland became fully operational and is running at the design capacity of more than 1 gigawatt. This project was delivered within budget, with only a 5% cost overrun, and is TotalEnergies' biggest offshore wind farm globally. I'll wrap up with CapEx and shareholder returns. Year-to-date net investments as of the end of the third quarter totaled $16.1 billion. As a reminder, we expect to receive cash proceeds from the sales of our Canadian assets and from the deal in the fourth quarter. Therefore, we reiterate our full-year guidance of $16 billion to $17 billion of CapEx this year. Our balance sheet is strong. Our gearing slightly increased from 11.1% at the end of the second quarter to 12.3% at the end of the third quarter, primarily due to the consolidation in our accounts of Total Eren's debt. Proceeds from disposals should bring gearing back below 8% by the end of the year. Over the last 12 months, our ROACE was 20.1%, and return on equity was more than 22%. In September, we raised our annual payout guidance from 35% to 40% of cash flow to more than 40%. We're on track for '23, having paid out a cumulative 43% for the third quarter. Our payout is a combination of ordinary dividends and buybacks, as we believe our stock, despite having reached historical highs this quarter, is still undervalued by the market. We bought back $6.1 billion of stock through the third quarter. We are well underway in executing our $9 billion buyback program for the full year '23 as the Board decided to allocate $1.5 billion of Canadian sale proceeds to this buyback program in '23. This concludes my comments, and now we can move to the Q&A.

Operator, Operator

The first question comes from Oswald Clint of Bernstein.

Oswald Clint, Analyst

Two questions. The first one on the U.S. offshore wind, please, attentive energy. It was a good press release this week, with lots of information that's not normally presented for these types of deals, and it helps us kind of get to the returns, I think. With the 40% tax credit, we were getting to something like 13.5% on an equity basis. And I just wondered if that was anywhere close to your own expectation for a project like that. And perhaps at this point, you could say how much of your $20 billion of capital employed in Integrated Power is currently in production? That's the first one. And secondly, I wanted to ask about geopolitical risk. You always have your finger on the pulse, and obviously, I wanted to get a sense of how you're thinking about the portfolio risk at the moment, especially Middle Eastern exposure. And were there any strategic changes or, indeed, merger and acquisition moves that may be needed or may be considered if things were to worsen?

Jean-Pierre Sbraire, CFO

Thank you, Oswald, for your comments. As you know, industry flow sometimes raises questions. Recently, we had two pieces of good news in our portfolio that I wanted to share. First, Seagreen in Scotland has come in with only a 5% cost overrun, totaling EUR 4 billion. This demonstrates that with a good team and a solid project, you can execute a project on budget with minimal delays. Regarding New York, while I can't disclose the exact price level, they mentioned an average price of around $145 per megawatt hour nominal, which is an adjustment from previous ranges. This shows you need to be pragmatic about costs in offshore wind, especially in discussions in the U.S. The pricing combined with the 40% IRA provides us with solid support. I would estimate the returns to be between 12 to 15 percent, so you're quite accurate in your calculations. We can develop profitable projects based on equity. One key to the higher price announced by the State of New York has been having a local partner. We introduced a well-established U.S. company into the partnership, which has credibility in New York and has significantly aided our negotiations with local authorities. Without TotalEnergies, I'm uncertain we would have achieved the same outcomes. This reinforces my belief that identifying local partners is crucial for renewable projects, and our U.S. partner also offers interesting opportunities for future business development. Regarding geopolitical risk, our portfolio spans many countries, but cash flow significantly comes from two: Abu Dhabi and Qatar. In Abu Dhabi, geopolitical risk is limited and well managed. I'm not overly concerned about dramatic issues there. While we need to remain vigilant about the situations in Iraq and Lebanon, our exposure in Egypt remains limited, which I don't view as a significant issue for TotalEnergies. Mergers and acquisitions may be considered if conditions worsen, but if that happens, I expect oil prices to rise, and we’ll reevaluate our strategy at that point. However, I don't currently foresee any mergers or acquisitions in the immediate future.

Operator, Operator

The next question is from Malek Christyan of JPMorgan.

Malek Christyan, Analyst

The only question I would like to ask is just around your views regarding consolidation, Jean-Pierre, in terms of what we're seeing in the U.S. How would you read two parts? One, there is a sort of opportunistic chasing of growth in terms of volumes through balance sheets as opposed to building organically. And then two, where does that position TotalEnergies in the upstream medium term, particularly if based on what they're doing, it suggests that they are looking for as well as backing the back end of the curve, so to speak. So do you feel like you have a little bit of FOMO, or are you very comfortable with your upstream growth? And I guess the question I'm asking is, why don't you feel the need to pursue consolidation, particularly given you are building these two pillars and building it through scale?

Patrick Pouyanne, CEO

To be honest, as you know, we are not in a position in the U.S. But I understand there might be consolidation in the U.S. It is quite a fragmented industry in the shale industry. So I have no comment, but it's not our case. Historically, companies tend to consolidate when you have low barrel prices to gain synergies. That has historically been the case in our industry. You are driven by low barrel prices, so you try to maximize synergies and scale. But that’s not our situation today. Prices are strong. For most of us, we are at the top of our historical values, and that’s not what I would look for. Honestly, I don’t believe TotalEnergies would find diverse synergies in terms of operations or costs. So we are not pursuing that. By the way, we have a strong and deep portfolio of projects in oil and gas. As I presented at the end of September, so I don’t feel a necessity to add more on this one. Again, we mentioned that we might look into more shale gas in the U.S. for feeding integration to LNG, which we mentioned in September. That’s all I can comment. But I observe this move, and it suggests that my colleagues believe the price of oil will remain high for some time, which makes me happy.

Operator, Operator

The next question is from Lydia Rainforth of Barclays.

Lydia Rainforth, Analyst

Two questions, if I could. One, just building upon the virtual power plant acquisition from this morning. Can you walk us through why that idea works in terms of special power plants, and just any indication on pricing? And then secondly, it seems we're clearly seeing a lot of volatility in the gas market. Could you just walk through what you think might happen over the winter period for us?

Patrick Pouyanne, CEO

A virtual power plant is integrated; while you can't build assets, you can aggregate some. The concept established by Quadra is quite robust. We are the second largest player in the German market, having connected with 4,000 renewable developers, aggregating 9 gigawatts, which is significant. This setup allows for trading, and pricing could yield EUR 2 per megawatt hour in margin. It allows access to resources with minimal capital investment needed. Essentially, it's an acquisition of expertise without owning physical assets. The acquisition cost was between EUR 200 million and EUR 250 million, which is relatively low given the skills gained. It complements our strategy by supporting our existing assets with a low capital employed model to further develop the business. This integration is crucial for securing supply sources and having customers, which may enhance flexibility for our trading platform in Germany, an important market for us. We are targeting Germany because it offers a blend of renewable and gas with ETS, promising a good price and considerable potential. We are progressively establishing our position in the country. Regarding the volatility in the gas market this winter, the weather conditions remain uncertain. Currently, it's a bit cold in Paris, but more importantly, the market is very volatile. There's little margin, meaning any disruption can significantly impact prices. Events like strikes in Australia or supply disruptions from Israel affect the market immediately. We've indicated that prices might hover around $16 per million BTU, suggesting they will remain elevated. Even though natural gas inventories in Europe are full, there may not be enough storage to handle a cold winter, as noted by the IEF. This situation could drive prices higher. Additionally, Asian buyers have returned to the LNG market, bidding at TTF plus $2 to $3, indicating strong demand that favors Asia, leading to more cargoes being directed there. This dynamic could add pressure to the LNG market, and we need to pay attention to the weather. Unexpected outages, similar to Freeport's situation last year, would also have an immediate impact on the gas market.

Operator, Operator

Next question is from Michele Vigna of Goldman Sachs.

Michele Vigna, Analyst

I wanted to ask two questions, if possible. The first one is back to M&A, considering a countercyclical approach. Energy prices are quite high, and a lot of companies are consolidating. Is this a suitable time to divest some marginal E&P assets from your portfolio? What about making countercyclical investments in energy transition assets that have substantially deteriorated over the past year? And then remaining on the theme of clean tech and renewables, congratulations on the consistent delivery of earnings and cash flow. I was wondering if you could unpick the $0.5 billion you make in integrated power per quarter between renewable CCGTs and trading, definitely highlighting the integrated nature of that business, but also helping us understand the scale of those different moving parts?

Patrick Pouyanne, CEO

Yes. On the second question, I think Jean-Pierre mentioned it was coming from three segments: renewables, flexible asset CCGTs, and trading, and also the marketing business, by the way. So consider that it’s coming from all of them. So everything is contributing positively to the integrated power. On the first question, it's clear that I'm a strong believer that in M&A, it’s better to become too cyclical than to be procyclical. That’s very clear. But in this business, in the commodity business, where you have cycles, I mean you take a risk when you make acquisitions out of the top of the market. Yes, you are right on E&P. But we’ve just done it. I remind you, Michele, that we just divested our Canadian oilsands assets at the top of the market, and we will receive $4.4 billion plus an extra earnout next year of $400 million. So I’m happy; it’s good value for these assets. So we’ve done it. We’ve just done it. We have cleaned a lot of our portfolio in the last several years. Since 2015, we have rotated a lot. We have cleaned a lot, but it does not mean that. I don’t think we have a lot remaining. We might have, as I said, some quite high exposure, which is challenging in some countries, like Nigeria, where we want to continue to invest. We might be willing to use this environment to reshape the Nigerian portfolio. I’m not very enthusiastic about all onshore in Nigeria for me because many issues persist about those assets, and it’s healthy to monetize them if we find buyers for them. Part of it we could do. However, we have cleaned, I would say, the portfolio to ensure that most of the portfolio today is defined by low costs and low emissions. As I previously explained, our priority lies in complementing key markets through targeted acquisitions. I mentioned lastly that we are still looking at flexible assets in Texas and gas-fired power plants that could come renewably. I believe in building our own portfolio, such as the project in New York, where we control our operations.

Operator, Operator

The next question is from Irene Himona of Societe Generale.

Irene Himona, Analyst

Two questions, please. You formed a new joint venture with Adani Green in India during the quarter. Earlier this year, when there was a financial crisis with the Adani Group, I think you had said that you would likely slow down that Indian expansion and wait for the outcome. Can we presume that you are satisfied with that group's financial situation and therefore, back to normal in terms of Total continuing to invest in Indian renewables? And then the second question on Chemicals, where we are clearly seeing a weak industry. Your nine-month volumes are down. When you look at the balance of new capacity versus this weak demand picture, what is your expectation for that business over the next year?

Patrick Pouyanne, CEO

On India, I think, again, what we said at the beginning of the year is that we wanted to have clarity on the situation. We have engaged with the Adani Group. You have noticed that we’ve done in fact, we want to make a difference between we are shareholders of Adani Green, not of Adani Group. Adani Green is a strong company with a large base of assets. The question for us is how do we continue to contribute to the development of Adani Green. What we have elected is to do it through a joint venture between Adani Green and ourselves. So let's be clear; this is a venture where we have direct access to the assets, which is fundamental. We didn’t put more money into Adani Green as a shareholder, but we help and contribute to the development of Adani Green by making access direct to the asset. For me, that means we protect TotalEnergies, and I think we can continue with growth, which is beneficial both as shareholders of Adani Green and our interests. That’s the first point. And we are, I would say, in the conditions in which we have discussed that deal are attractive in terms of metrics for TotalEnergies. On the chemicals in Europe, we know that chemicals in Europe are clearly quite linked to GDP. The GDP in Europe is softening more than that. So you have less demand in Europe. Two years ago, it was very good, but now it’s a reverse. Our exposure to the European chemicals market is not so strong. To be clear for us, the polymers part is more profitable compared to the other part because we make more money on refining and naphtha than on petrochemicals in Europe. Therefore, our strategy is not to develop any new capacity in Europe, just to be clear. I don’t think we’ve announced, since I have been in charge of Refining & Chemicals, 12 years ago, any single capacity addition in chemicals in Europe. I don’t think we’ve either announced any closures or sales in some of them. So I don’t think it’s the best place to invest, to be clear. Overall, the strategy in chemicals at TotalEnergies has been based more on cheap feedstock, either in the U.S. or in Saudi Arabia with various operations. While targeting markets in China and India, that's where the demand is. For next year, I don’t expect much better conditions.

Operator, Operator

The next question comes from Biraj Borkhataria of RBC.

Biraj Borkhataria, Analyst

Two quick ones, please. The first one is on your debt profile. Could you just confirm what proportion of your gross debt is on sort of long-term fixed interest rates? And then the second question is on the recent U.S. wind bid. There's a provision in the PPA that suggests it goes up with industry-specific inflation. I was wondering what you assume inflation-wise for that kind of project from here to FID?

Jean-Pierre Sbraire, CFO

Yes, perhaps I will take the first question. More than 80% of our debt have been fixed a couple of years ago. So that means that we benefited on that portion from very low coupons, around 3%. The remaining is flexible.

Patrick Pouyanne, CEO

The second answer is quite clear. Within today and FID, we probably have around three years to work. So you will have inflation over the next three years. I think it will probably be in the range of 5% to 10% over the three years, but again, there is a provision that protects us until the FID. After that, of course, we will take the risk of execution, but I think it’s a fair protection, which is offered by New York State to the investors. So this is the element of the bid and the negotiation we successfully managed to obtain. So we are satisfied. We will see if it’s higher than that, but we don’t expect much more than that.

Operator, Operator

Next question comes from Martijn Rats of Morgan Stanley.

Martijn Rats, Analyst

I just want to follow up on the question that Biraj actually just asked about the debt. Because interest rates continue to rise and rise, and Total bonds are not escaping that. Some of the longer-term debt that you hold is now sort of yielding 6%. I was wondering, in addition to the mechanical impact that this may have on the interest expense every quarter, how this affects possibly any investment decision making, particularly in the new energy areas? The question has been posed to me: can we have an energy transition when U.S. treasury yields, particularly the 10-year, are around 5%, and it’s an intriguing one. Therefore, can I ask you how are these rising interest rates impacting your investment decision making? And also, what are you seeing in others, particularly in CapEx intensive areas like renewables? What is the impact that you are seeing?

Patrick Pouyanne, CEO

The answer is quite clear: you transfer the interest rate to the customer, I will tell you. The question is, does it affect the pace of the transition? It might, but it’s clear that it’s against the idea that may contribute to a segment, which will stop growing, and prices will go down. It has already had an impact. In fact, I can tell you that we are discussing in the U.S., where the IRA has become a factor, along with the requirement to ensure that projects incorporate solar modules manufactured in the U.S. This has had an impact on project costs. So today, when we negotiate PPAs with our customers, it has an impact on the high side. The last PPA we signed recently with Saint-Gobain in the U.S. reflects higher costs of manufacturing in the U.S. and higher interest rates. When we bid, we do not use the 3% of TotalEnergies; we are pricing a higher one, which makes us more profitable. We are competing with companies that have higher costs of debt. So we use their cost of debt, and we may benefit from that to win these deals but keep the difference for us. I would say yes; you’re right, it may affect the pace. But I think we are back in a normal world. It’s much better for the world economy to have a 5% interest rate world rather than a 0%. In particular, for our companies, oil and gas companies with strong balance sheets and cash delivery. I believe it’s the anomaly—this 0% world after the 2008 crisis—was aimed to recover and absorb shocks, but it’s more damaging than beneficial.

Operator, Operator

The next question is from Lucas Herrmann of BNP Paribas.

Lucas Herrmann, Analyst

A couple of straightforward ones, I think. Firstly, just on your reporting, for as far as I can remember, actually, Patrick, 20-odd years, divisions may have changed, but your reporting method has always been consistent on a quarterly basis. And yet today, you’ve elected to alter it. I wondered whether there was any particular reason for disclosing more around cash or other items with the other things that you’re trying to emphasize? And the second question, just staying with that, some of the adjustment items in Integrated Power. I noticed that there’s a EUR 400 million, EUR 420-odd million asset impairment provision charge taken this quarter. If you could provide further detail on what that impairment concerns?

Patrick Pouyanne, CEO

On the second one, it’s written. I believe this business has impaired some of the goodwill that was allocated to the customer portfolio because, in fact, when we acquired these smaller companies, their value was based on the customer portfolio, which has high turnover. So at this point, we regularly review the situation with our auditors. We decided that this goodwill might need to be reconsidered. On the first question, it was a structural review asking for transparency on our measures. We had some exchanges, like other companies, with regulatory bodies. We use non-GAAP KPI indicators, and we have to reconcile the GAAP to non-GAAP. It was more of a formal exchange with the SEC, but at the end of the day, we concluded with them, but they wanted clarity on the reconciliation between IFRS and the terms we use during reporting. So that’s the reason you’ve seen some of the changes.

Operator, Operator

The next question is from Kim Fustier of HSBC.

Kim Fustier, Analyst

Firstly, I wondered if you could talk about the 3.5 million tonne SPA with Qatar Energy on LNG volumes? Some people have noticed the 27-year duration; it seems like other offtakers have signed shorter-term contracts. And it also extends well beyond 2050. So I wondered whether this was a requirement from Qatar Energy? And also, the LNG will be delivered in France, I believe. Can you say whether there was a destination clause or whether you can redirect the volumes? Secondly, I wanted to ask a broader question on climate. What could Total and the broader oil industry potentially announce at COP 28 next month? You already have a target of reducing leasing emissions by 80% by the end of this decade, keeping Paris in mind. Could the ambition be to share your best practices on leasing monitoring and emission reductions and encourage other oil companies to do the same?

Patrick Pouyanne, CEO

Good question. Thank you, Kim. The first one: No, we are not alone. The 27-year duration, in fact, is for all the LNG offtake for all the partners of Northern East and Northeast South, which were the last new ventures, where they were asked to take their share of offtake on the 27 years. We are not alone; all my colleagues have been asked to do this. You will see, by the way, they have released statements to other European companies. It’s only the German companies that are not part of the ventures or the developments that have decided on 15-20 years. It’s only for us that it makes sense. By the way, with the way our portfolio is set, in the net-zero company that we described in our last sustainable and climate report, TotalEnergies will still have a significant share of gas even by 2050. So we have no problem with that. Will it end up in France or Europe? Yes, we certainly could manage the complex electricity markets in Europe, filled with renewables without having flexible assets. So it makes me clear: total energies have a long-term gas vision and hedging for these. So on that, I’m quite clear. So it’s not just for France. It’s for TotalEnergies. Furthermore, if we need to redirect part of this LNG to another country, both Qatar and ourselves will discuss it amicably if it serves both interests. In fact, the 27 years are aligned with the concession delicately. It’s just an alignment between our investments and longer terms, which work on a 30-year concession. I can tell you, we are quite satisfied with the conditions in which we have joined this NFS venture in Qatar. Regarding climate; I can confirm we are leading the pack. What we would like to do at COP28 is to encourage collaboration between small and national companies. TotalEnergies and these other IOCs have been at the forefront of this fight. We already set the target ourselves. On methane, we aim for near-zero emissions by 2030. It’s about stopping flaring, stopping venting, particularly by using technologies to detect fugitive emissions, which we are doing in all our assets. We are also sharing these technologies with national companies, and we have been signing agreements which will be disclosed before COP. We signed 1 or 2 already, but we must respect the countries’ wishes to announce them together. We are doing our job, and we can announce some of these before COP at the right time.

Operator, Operator

The next question comes from Alastair Syme of Citi.

Alastair Syme, Analyst

Any updates on Namibia you want to share? I know you updated at the recent Capital Markets Day, but you're right in the middle of your assessment. How is the production test being received? Can you also talk about the hybrids? I mean they are perpetual. But I think as they start to be callable, the coupons change. Can you talk a little bit about that mechanic, please?

Patrick Pouyanne, CEO

Jean-Pierre will provide the specifics on the hybrids. For Namibia, we’ve started drilling the discovery, which is still in the process. Well drilling began on October 7, I recall, at the beginning of the month, and it’s on its way. Sorry, but our drilling operations do not follow our quarterly calls, so you will have to wait for more updates. As mentioned, we will develop the Vinis discovery; that will be our progression. So it’s a matter of assessing its full size and finding the suitable development scheme since quite a good ICGL is possible. We will return in February when we disclose our annual results to give you clearer details.

Jean-Pierre Sbraire, CFO

The hybrid bonds are an aspect we are very proud of. We benefit from a very competitive hybrid bond portfolio because the average coupon is 2.3%, which we consider quite low, or, I would say, cheap equity. The problem now, however, is that as mentioned by Patrick, the refinancing has become more expensive, around 6% for a maturity of 7 years. We use the flexibility offered by S&P to be able to reduce by 10% the global portfolio without losing the equity treatment. We use this flexibility because, in the second quarter, we had 1 tranche maturing. We decided not to refinance that one. So now we have to see in the future how we can lower the hybrid portfolio without losing equity treatment going forward.

Patrick Pouyanne, CEO

We will use the 10% flexibility over each quarter or year in order to eliminate while respecting the rules and maintaining our equity treatment in the plan.

Operator, Operator

The next question comes from Henri Patricot of UBS.

Henri Patricot, Analyst

Two questions from my side. The first one, on the outlook for oil demand and refining margins because we've seen quite a sharp drop in refining margins over the past month, obviously, from a very high level. Just wondering if you're getting a bit more concerned about the outlook for oil demand and refining margins at the moment? Secondly, I wanted to ask you about wind and the European wind industry. This week, we saw the Commission setting up more actions to support the European industry. I wonder if you have your initial assessments of these actions and whether you see potentially better dynamics for European wind acceleration?

Patrick Pouyanne, CEO

Oil demand in '23 is strong, with an increase of almost 2 million barrels per day, mainly coming from China. Moreover, it’s driven mostly by two main aspects: petrochemicals on one side and kerosene, i.e. jet fuel on the other. However, we are not fully back to speed on jet fuel demand. I don’t see how it would stop, to be honest since there’s demand. The IEA recently announced an additional increase in oil demand due to jet fuel. Our traders thoroughly agree with this interpretation. Often, despite concerns about the Chinese economy, we still have over 70% from China and a call for movement on this planet. So overall, I do not expect refining margins to quit dropping. There is an ever-elastic gasoline demand in Europe now impacted by price elasticity. When prices went high, consumption decreased. The gasoline crack softened. However, diesel crack is still very high at $30. During summer time, everything was under constraint due to the rising prices. So today, our operations are flexible. We can adapt to make more diesel if we must. Margin should still stay very solid over the next months, around the $70-80 per tonne. On the wind front, the European Commission is addressing manufacturing complaints from developers to support local manufacturers. Until now, the EU has prioritized consumer interests. And solar developers are now seeking the lowest renewable prices instead of protection. Ultimately, we are still negotiating with our partners like GE for our New York offshore wind project as they plan investment in New York, creating local jobs.

Operator, Operator

The next question is from Bertrand Hodee of Kepler Chevreux.

Bertrand Hodee, Analyst

Yes. Two very quick ones, if I may. The first one on Namibia; you disclosed that the first DST test was in line with expectations. But can you share a bit more color on that? You hinted that if it was 5,000 barrels of oil equivalent a day, it was not a good result; 15, it would be okay. Could you give us an indication of whether it was above 15 or below 15? That is essentially my question. Then on U.S. offshore wind in New York, can you disclose in dollars per megawatt your current CapEx estimate before any inflation provision?

Patrick Pouyanne, CEO

No, I cannot disclose your full details. I didn’t know that 15 was a threshold for you. Honestly, I think we mentioned that it’s in line with our expectations. Our assumptions taken during the planning process were met, confirming the productivity and expected production per well, so we are satisfied. Therefore, I don’t want to comment further on one test. We have plenty more tests coming, so let us continue the job, and you will need to rely on what we say. But as a listed company, we will always tell the truth. In terms of CapEx, we do not release specific information as we include contingency in our numbers. We execute projects with caution, using the experience from our projects to form long-term expectations.

Operator, Operator

The next question is from Paul Cheng of Scotiabank.

Paul Cheng, Analyst

Two questions. One is really short; maybe it's for Jean-Pierre. For the third quarter E&P, the effective tax rate – I called it wrong number, 45% – seems a bit low, even considering the lower contributions from North Sea. Is there any one-off benefit in tax for the quarter? And also, based on the current market conditions, what is your expectation for the division's effective tax rate in Q4? Second question: we have seen a substantial reduction in the renewable diesel margin over the past several weeks. The wind price in the U.S. has been dropping, and we have also seen supply in LCFS remain relatively low. Will any of these market conditions impact your investment thinking in alternative fuels by renewable diesel and SAF?

Jean-Pierre Sbraire, CFO

In regard to the tax rate for Q3, the 45% number seems slightly off, even considering North Sea's weight. The effective tax rate reflects our mix of barrels produced contributing at a high level, together with our exploitation of low-cost barrels across our portfolio.

Patrick Pouyanne, CEO

On the second question regarding the U.S. renewable market: yes, we noticed the conditions recently, especially concerning our efforts. However, we are committed to our investments, even with current conditions. These businesses today are regulated so that stock prices and upwards pressure very much rely on penalties for not meeting mandates. As the prices are high now, it does not directly affect our business models.

Operator, Operator

The next question is from Jean-Luc Romain of CIC Market Solutions.

Jean-Luc Romain, Analyst

It relates to your acquisition in Germany. I was wondering if the electricity you will purchase on medium-term contracts will be accounted for in your kind of power capacity or in your power sales. Will that work? Or will it be only an intermediary margin?

Patrick Pouyanne, CEO

It will be considered a sale, but not a capacity. We don’t own the capacity. We manage the capacity. As you know, we are honest people. So we do not invest in capacity, but we have access to some capacities, which is a good thing. We will be selling it to customers, for sure; we may have, I think, in the portfolio, we have 2 gigawatts out of the 9 gigawatts, which are secured under medium- to long-term PPAs. This sale will be reported as sales but not as capacity, as we’re not producing it.

Operator, Operator

The next question is from Jason Gabelman of TD Cohen.

Jason Gabelman, Analyst

I have a follow-up regarding CapEx. You mentioned that both the oil sands divestment and the sale would close in the fourth quarter, which suggests about $6 billion in divestment proceeds. Given that, it seems reiterating the $16 billion to $17 billion CapEx range for 2023 might be too high. Could you clarify that?

Patrick Pouyanne, CEO

No, it’s not high because we spend organically $5 billion to $6 billion per quarter. At the end of the quarter, we spent $5 billion to $6 billion per quarter, as earlier stated. We will divest, but we also have 1 or 2 acquisitions coming in the quarter too. So $16 billion to $17 billion seems to be right for us, and we will clarify that in our annual disclosures, while tracking our expected expenditures.

Operator, Operator

The next question comes from Alessandro Pozzi of Mediobanca.

Alessandro Pozzi, Analyst

Just one question on the macro side, and I guess, in a way, it's linked to the recent offtake agreement in Qatar. This week, the IEA has published the world energy outlook and downgraded again the gas demand for 2050. I think if you look at the EPS, it's down 40% gas demand. I was wondering if this is a concern for you when blocking such long-term contracts, or do you think the IEA remains too bearish on gas demand?

Patrick Pouyanne, CEO

No, I think it is a matter of positioning our projects correctly. In fact, for me, all that is driven by our investment costs in Qatar. In Qatar, you are in the first quartile for all costs. So I can tell you, producing LNG in Qatar, even by 2050, will still be more efficient than many places on the planet. So even if there is a demand reduction of 40%, there will still be 60%. In the 60%, Qatar will be perfectly positioned. The key driver of our strategy is driven by the remaining quartile projects—which are cost-effective, as they remain protected because investors are tested. There is no stranded assets in TotalEnergies' portfolio, and we are happy with our progress. Therefore, we are comfortable making long-term agreements with Qatar and investing in other projects, while some may prefer shorter durations due to various risks. We systematically assess our investments in viable oil assets or LNG projects to ensure they are low-cost, with OpEx below $20 per barrel and costs placed in higher quartiles, ensuring that we remain competitive within a shaky landscape.

Operator, Operator

There are no further questions registered. Back to you, gentlemen, for conclusion.

Patrick Pouyanne, CEO

Thank you very much for your attendance. We will provide details about our next meeting shortly, which will likely take place on February 7. The date will be confirmed for our annual presentation, where we look forward to meeting you once more in London. COVID is behind us. So I expect this to be held on February 7 in the morning. Renaud will provide all the details. Thank you for your attendance. As always, you are likely not surprised by TotalEnergies, even though we always expect surprises positively. We will continue. Thank you.

Operator, Operator

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