So welcome, everybody, to this presentation of the 2025 year results and the objectives for 2026. We are in London. It is sunny, like the recent performance of TotalEnergies shares until now; we’ll see after this call. I’m happy to be here today with the Executive Committee members. You know all of them, but you may not know Catherine. Catherine, if you could stand up — she is our new member in charge of people and social engagement and all global services. There is another person next to us you should know, Arnaud Le Foll. Arnaud is our Deputy CFO and you will hear from him today. We will make a presentation in two main parts with two focused segments in the middle. First, we will have a safety moment and the Safety and Sustainability segment presented by Nicolas Terraz, our President Upstream. Then Jean-Pierre will review the 2025 results. After that there will be two short focused presentations: one on Namibia by Arnaud, who before becoming Deputy CFO was in charge of negotiating Namibia, and one by Stephane on data centers and AI, both as a business opportunity for us and for our internal use. I will close with the objectives for 2026. If we respect the timing, the session should last about one hour to one hour and five minutes. Please be patient; you will have time to ask questions. Nicolas, the floor is yours.

Good afternoon, everyone. First, let me take a minute for a sustainability moment. For this sustainability moment, we'll share a concrete illustration of what we are doing to fight methane emissions. To fight methane emissions, the first step is to detect them. Last year we installed at all our sites a fixed continuous detection and monitoring system. The footage here is from Argentina in Neuquen where we were commissioning an infrared camera. This infrared camera detected not a fire but methane. In fact, it detected methane coming from underground from a pipeline that had a pinhole. It was a very small hole leaking methane in fairly modest quantities, but it was detected. The leak was immediately fixed: the pipeline was excavated and repaired. This illustrates the role and benefit of permanent methane detection to reach near-zero methane emissions, which is our objective by 2030. Now let me move to safety. As you can see on the slides, we are on a journey of continuous improvement in safety, both for occupational safety and for process safety. For occupational safety, on the left part of the slide you see our total recordable injury rate, which has been continuously decreasing. Last year we were below 0.5 events per million man-hours, and we are pleased to be ahead of our peer group. Where we are not happy is that we had one fatality last year. This happened in Angola during the offloading of drilling casings from a rig to a platform supply vessel, where one person working onboard the supply vessel was crushed by those drilling pipes. Manoj Kumar was 51 years old, married with one child. After the accident, we took the actions owed to him, reinforcing the safety of dock operations on our supply vessels by installing more physical barriers and steel frames for pipe offloading operations, and by strengthening supervision of dock operations on our supply vessels. For process safety and prevention of major risks, the right part of the slide shows a reduction in the number of primary losses of containment on our sites, which have decreased by 60% since 2020. We continue to work on that front. Today, more than ever, we want to ensure everyone working on our sites, whether staff or contractors, can return home safely and we aim to achieve zero fatalities in our operations. Now to emissions. We are pleased that in 2025 we reached and even exceeded all our emission reduction targets. As I mentioned, methane is down 65% compared to 2020, exceeding our target of 60%. We are monitoring this closely to reach near-zero emissions in three to four years. For greenhouse gases, looking at our Scope 1 and 2 emissions, last year for oil and gas operations we reduced emissions by 1 million tonnes compared to 2024, and we have a cumulative reduction of 38%. The gradual evolution of our sales mix is also driving down the life-cycle carbon intensity of the products we sell; that figure is down 19% in 2025 compared to 2015. Finally, we invested $1 billion in an energy efficiency improvement program over 2023 to 2025. This is paying off: the actions implemented through this program resulted in a reduction of 2 million tonnes of CO2-equivalent emissions and generated around $200 million annually of energy and CO2 savings from 100 initiatives across our sites. That was about emissions. Now I'm going to hand back the floor to Jean-Pierre.

Thank you very much. Good afternoon. I will present the 2025 results and the key achievements of the year. We have a well-balanced, integrated strategy anchored on two pillars: oil and gas, and integrated power including gas and LNG. I will go through the main achievements of 2025. Starting with oil and gas. We started up two major projects: Ballymore in the U.S. and the deep offshore Mero-4 development in Brazil. Entering the Namibia block previously operated by Galp and supporting the Mopane discovery is another clear achievement, confirming Namibia as a promising province for TotalEnergies. Arnaud will provide more details on that. To prepare the future, we refreshed our exploration portfolio across several geographies where we were active in 2025. On the gas and LNG side, we reached FID for Rio Grande Train 4, adding 1.5 million tonnes per year of LNG capacity. We acquired an additional interest in Malaysia, confirming TotalEnergies’ positioning to supply Asia’s gas market in the coming years. We continued upstream gas integration in the U.S. with additional dry gas acquisitions in the Anadarko Basin. At the end of 2025, we announced an agreement with NEO NEXT to merge our upstream assets with theirs, creating one of the largest oil and gas players in the U.K. and aiming to deliver synergies. To summarize, we are growing. In 2025 we delivered 4% upstream growth, well above our guidance of over 3%. We maintained discipline on costs: OpEx per barrel was $5, the best among our peers, which is important to withstand a low-price environment. We delivered 120% proved reserve replacement, meaning our proved reserves at the end of 2025 will cover 12 years of 2025 production. On integrated power, we delivered more than 20% net power production growth from renewables and flexible CCGT assets. Three notable achievements: the agreement with EPH to accelerate gas-to-power integration in Europe, expected to close mid-2026; signing 6 TWh per year of PPAs with data centers; and recycling capital through farm-downs in the U.K., Greece, Portugal, and France, recycling approximately $2 billion. Scorecard for 2025: we are a growing company delivering on objectives. Total energy production grew 5% combining oil and gas and electricity. Upstream grew close to 4%, and electricity net production increased by almost 20% year-on-year, reaching roughly 50 TWh in 2025. Refining utilization faced technical reliability issues in the first half but was fixed in the second half, and full-year utilization met our targets. LNG sales grew 10% year-on-year, in line with production growth. Renewables: gross installed capacity reached 24 GW at year end 2025, down from 26 GW at end-2024 because we put 8 GW into production during 2025; this pace of about 8 GW per year is the cadence needed to meet our 2030 target. More energy, less emissions: we lowered emissions and maintained Scope 1 and Scope 2 intensity while increasing production by 5% in 2025. Growing free cash flow to support shareholder returns relied on two main drivers: disciplined OpEx and controlled CapEx. OpEx per barrel remained $5. CapEx came in at $17.1 billion in line with guidance. Overall CFFO was around $28 billion, slightly below our initial objective but still delivering robust cash flow. On cash flow contributions, exploration and production drove growth and accretive cash flows. Integrated energy operated in a low-volatility market but offset lower prices with additional production; integrated LNG delivered roughly $4.7 billion of CFFO, only 4% below 2024. Integrated power generated $2.6 billion of cash flow, meeting our target to be above $2.5 billion. Downstream delivered $6.2 billion, reflecting resilience and the benefits of improved utilization in the second half. Uses of cash: roughly $17 billion was allocated to CapEx, acquisitions minus divestments, and shareholder returns. Dividend cash outflow was $8.1 billion, and we executed a $7.5 billion buyback program for the full year. Net adjusted income reached $15.6 billion, with return on equity at 13.6% and ROACE at 12.6%. IFRS net income after nonrecurring adjustments was $13.1 billion. We maintained a strong balance sheet, with gearing at 14.7% at year end. Total shareholder returns (dividends plus buybacks) amounted to $15.6 billion, representing a payout close to 55% of the cash flow generated in 2025. CapEx discipline was maintained, with the final figure of $17.1 billion. About one third of CapEx was devoted to new oil and gas projects and close to $3.5 billion to low-carbon energy, mainly integrated power. The $17.1 billion translates to $16.8 billion spent on organic CapEx plus $3.9 billion of acquisitions net of $3.6 billion of divestments, showing balanced M&A activity. Adding these figures indicates continued portfolio activity: divesting mature assets and replacing them with higher-performing assets, particularly in integrated power. Key acquisitions included VSB in Germany and assets in the U.S. and Malaysia; divestments included mature assets in Nigeria, Congo (N’Kossa), and Vaca Muerta in Argentina, as well as sales in the U.S. and Europe. Upstream details: production grew 4% supported by a low decline rate of about 4% per year for the base portfolio and by bringing 150,000 boe/d of new production onstream. Production growth was accretive: upstream cash flow rose by 10%. In a $70/bbl Brent and $12/MMBtu gas environment, our baseline portfolio generated about $19 per barrel of CFFO, while the new projects averaged more than $30 per barrel of CFFO, contributing an additional approximately $700 million of CFFO in 2025. Integrated LNG: spreads between Asian and European markets narrowed in 2025 and volatility remained low, with most of the GMI-TTF spread below $0.5/MMBtu. Freight optimization led U.S. LNG to go mainly to Europe and Middle East LNG to go largely to Asia, reducing arbitrage opportunities. Despite the low-price, low-volatility environment, 10% production and sales growth allowed integrated LNG to nearly offset headwinds and post CFFO of $4.7 billion in 2025. Integrated power: we continued executing the strategy and significantly scaled the business between 2021 and 2025, with CFFO and net operating income increasing multiple-fold. At the end of 2025 ROACE for integrated power was close to 10%. We continued to recycle capital, signed the EPH deal to accelerate European integration, and scaled our data center business through PPAs. Ordinary share: on December 8, 2025, we listed the same ordinary share on the NYSE as is listed in Paris, allowing investors to buy the same share either in Paris or in the U.S. This provides near-continuous access from Paris market open to New York close, eases access for investors, and may help attract new shareholders through wealth managers and financial advisors. It also gives us the option of using the U.S.-listed shares as currency for potential M&A in the U.S. Benchmarking versus peers: we remain best-in-class on ROACE for the fourth consecutive year, demonstrating leadership in the energy transition while delivering top profitability. Total shareholder return in 2025 was best in class at 28% for the year. Proved reserves life remains strong at 12 years, a differentiator versus peers like Chevron and BP, and upstream production cost stayed at an advantaged $5 per barrel. In closing, our share performance was strong in 2025, up 20% for the year, and we believe the market increasingly understands our strategy: accretive growth, cost discipline, controlled CapEx, low OpEx per barrel, and delivering growth across both pillars — oil and gas on one hand and integrated power on the other.

Thank you, Jean-Pierre. That's for 2025. That's the past. So let's speak about it as a bridge between 2025 and 2026. Namibia, which we did not hold a special session on because it came late in December, is our opportunity to revisit what we have built with the agreement with Galp in Namibia, which will be, for us, obviously a major step up for our future. Arnaud, it's yours.

Thank you, Patrick. Ladies and gentlemen, so let me start by setting the context for our progress in Namibia. Over the past few years, our exploration and business development efforts in the Orange Basin have led to significant discoveries that are now forming the foundation of a new deepwater Golden province for TotalEnergies. And so today, I'm really thrilled to walk you through the steps already taken and what lies ahead. So here, you have the core of our position. So across two licenses, PEL56 and PEL83. We have already confirmed substantial discovered resources, and we begin with two operative deepwater projects, Venus and Mopane. I'll come back to them in more detail. Together, what we have already enhanced is 1.5 billion barrels of discovered resources. And we see major additional prospects and potential currently being matured. These two projects, they form the basis of a new deepwater hub for TotalEnergies, enabling us to plan for future development, of course, but around shared infrastructure, optimize logistics and economies of scale. So this is really the beginning and materializing the beginning of our presence in this highly prospective basin. I'll come back to this important milestone, which was the transaction with Galp. So last December, we concluded this cashless transaction with Galp, which we expect to close by the summer, mid this year. First, for us, this deal crystallizes the value of our discoveries. It strengthens our operating position and of course, it opens new opportunities in the country. So on our side, with the transaction, we secured 40% operated interest in PEL83, which is the home to Mopane with already resources identified to end up in the development and more than 1.5 billion barrels of exploration potential opportunities on the same block. In return, what we give to Galp is a 10% interest in PEL56, which is the home to Venus and slightly less interest in the neighboring PEL91 exploration block plus we'll carry them for 50% of their expenditures for exploration appraisal and for the first development on the block. So as a result, TotalEnergies becomes the anchor player in one of the world's most dynamic basins with stronger alignment across the value chain which is illustrated here on the slide. It shows how Venus and Mopane make TotalEnergies the reference operator in Namibia definitely. As you know, with 10 FPSOs already operated across Africa with one new being in construction currently, we definitely benefit from a broad deepwater project experience in the region. This enables us to deliver fast and reliable execution, proven low-cost development, strong long-term relationship with contractors and efficient scaling of procurement, logistics, engineering. This experience was definitely an important factor in our selection as operator of PEL83 and for the authorities of Namibia to bring their full support to the transaction. They definitely see us as a credible partner in the basin. On the left-hand side, the production profile shows our Venus and then Mopane could sequentially ramp up from 2030 to reach about 350 kb/d of production with additional upside thereafter. So our objective is clear, and you got it. We want to establish a sustainable multi-FPSO hub in Namibia to maximize synergies for the benefits of all the stakeholders. Turning to Venus in more detail. So Venus is our first development. Venus is fully appraised with around 750 million barrels of resources. The engineering is well advanced. The FEED is complete. And today, with recent EPC bids, we have confidence in visibility on cost. Key parameter of the project. So it's a 150 kb/d plateau production with costs below $20 per barrel. In terms of course, Scope 1 plus 2 emission intensity, we are around 15 kg per barrel featuring the same low emission design as in our other FPSOs, so full electric architecture, centralized power generation, vapor recovery units, et cetera. We are now fully engaged with the Namibian authorities to progress towards an FID by mid-2026, allowing a first oil in 2030. So Venus is expected to become the first FPSO development in the country and is really the opener of the basin as a new producing region. The second project is Mopane, which is progressing in parallel. We have current estimates from 800 million to 1,100 million barrels of resources which will allow production above 200 kb/d. We plan in the short term an exploration and appraisal campaign, so in '26 and '27 to refine the development concept and confirm the size of the first phase including in 2026 the Mopane extension well and thereafter, two appraisal wells. Like Venus with Mopane, we target emissions intensity below 15 kg per barrel and cost below $20 a barrel, of course, taking full benefit from the synergies with Venus. So with potential FID in 2028, Mopane is the second pillar of our Namibia strategy which is contributing significantly in production beyond 2030 and with additional potential from prospects, such as, as you can see on the map, Quiver or Sobreiro in the same license. Finally, let me zoom out and have a look at our broader exploration portfolio in the Basin. So beyond Venus and Mopane, we see around 10 billion barrels of exploration potential across multiple prospects. So to the south with our licenses, DWOB and 3B/4B and material well-defined prospects in South Africa and to the north with the recent signature of our entry into PEL104, that expands our operated acreage in Namibia. So you can see with discovered resources, prospective upside and strong operational capabilities, we think we are well positioned to lead the next development cycle in the Orange Basin. So in summary, Venus and Mopane are large competitive low emissions deepwater projects. For Namibia, these projects are important. They are the projects that represent the first steps toward establishing domestic oil industry in the country. And with wider exploration portfolio, we have meaningful upside in the future. So this all together forms the foundation of a new golden province for TotalEnergies with a multi-FPSO hub with strong long-term potential, all operated by TotalEnergies.

Thank you, Arnaud. I think you will have some questions, but we'll give you more insights. I was myself in Namibia last week, and we discussed with the authorities and what Arnaud said is true. We are considered now as a major player there and it gave us a good momentum to move forward these projects. Now I leave the floor to Stephane, who will make a second focus on one of the other major activity, which is, of course, taking benefit from this AI and data center evolution. Stephane, the floor is yours.

Thank you, Patrick. Good afternoon, everyone. We'll cover two subjects: how we will power the AI revolution with our integrated power supply, and how we plan to boost our operations using AI. First, a simple message: we are creating additional value by providing data centers with fit-for-purpose solutions. There are three product types with increasing sophistication. The first is the standard corporate PPA: quick to build, fast to connect, not baseload, 100% green and quite competitive. The second is clean firm power: a baseload profile that matches exactly what the data center needs and will consume, supplied mostly by renewables so 100% of the consumed volume comes from green production while matching their consumption profile. The third, new and specific to data centers, is providing access to land to build a data center close to the grid where connection is available and construction can be fast, ensuring they get the power supply they need. Examples: the first product is what we sold to Microsoft and Amazon Web Services in 2025. The second type is what we are doing with Casa dos Ventos in Brazil. The third is what we just signed with Google in Texas and other prospects, notably in Spain. Why this matters: these offers let data centers achieve faster time to market and lower cost of supply. When you create that value, you can share part of it, which allows us to charge a premium on PPAs — roughly 10% above what we would get selling the same energy to other industries. There is a direct impact that helps us deliver double-digit returns on CapEx, and an indirect impact because bringing consumption locally helps develop our project pipeline and can raise local power prices, benefiting our other assets. This is not just on paper. Through our JV and partners we have signed 4 gigawatts of projects backed by data center demand for 2025 and 2026. The geographic spread is broad; about one third was done directly by us, and others through partners such as Clearway and Casa dos Ventos in Brazil, working with large tech companies and specialized data center developers. When all projects are materialized, they will generate about $250 million of EBITDA per year. Two specific projects illustrate this. The first is the deal with Google in Texas, which followed our work in Malaysia. We are building a 1 gigawatt solar farm that has already started, and we will sell Google the roughly 2 terawatt hours produced by that farm. In addition, Google has an option to install a data center on our land close to the solar production. We will provide them direct access to our solar output, direct access to the grid — we have applied to withdraw some power from the grid and expect approval soon — and the option to install batteries to smooth the profile. That package enables them to move quickly to market next year and lower their supply cost, notably by reducing grid fees, which allows us to sell a PPA at a slightly higher price than the market average. The second example is Brazil. There we blend solar and wind from our portfolio with hydro purchased on the market to deliver clean firm power: 24/7 baseload, 100% green. With Casa dos Ventos we also provide land with secured grid connections so data center customers can build quickly. In Brazil, customers also benefit from favorable tax treatment and, if they take equity in our projects, from additional subsidies. This creates a very competitive offer. For us, the advantages are improved returns, secured consumption to develop our multi-gigawatt pipeline, and accelerated development in regions where assets might otherwise be built years later. Now on to how we will use AI for our operations. First, there is no AI program without a strong data platform. In 2025, Namita and the team focused on building that foundation with two goals in mind: to multiply by ten the datapoints we collect on our assets, because AI requires large volumes of precise data, and to make those datapoints real time so we can act in real time in asset management. To achieve this, we signed a major contract with AspenTech to deploy across all 40 of our upstream sites and 16 of our Refining & Chemical sites; the integrated power part was already completed. That is the layer for data capture. We also signed with Cognite to transform, enrich, store and expose those data so we can add an AI layer to uplift production and availability. This program is ongoing and should be fully deployed by the end of next year. Second, once you have data you need to act on it. We have focused our efforts top-down on three programs. The first is using digital tools for HSE — for example, the safety moment where digital monitoring reduces emissions. The second is the digital plant program to improve how we run our plants. The third is integrated power modeling. There is a major modernization underway: for example, AI can halve the time required to produce a convincing weather forecast, which dramatically improves short-term power trading accuracy. This is just the beginning. To scale these efforts we have chosen to build capacity in India, creating a Global Competency Center staffed by our own team. The center will manage programs end-to-end, with full accountability, and we are targeting a critical mass of at least 500 engineers by 2027; this work has already started. This is how we plan to use AI to transform our operations. One final note: my presentation was not prepared by an agent — perhaps that will be next year. Thank you. With that, I leave the floor to Patrick.

Thank you, Stephane. Because next week, each executive of the company will be trained to have at least one agent with him. I don't know which one I will have. It will be difficult for him to follow me, but we'll see. So I will take the last part of the presentation now. Thank you, Stephane. And thank you, Namita, because the second part is largely led by Namita. She knows India very well. So let's move to the 2026 objective. We are not fully on time, but I will try to catch up. I know I like to speak, so I'm not sure we will catch up completely. 2026 is a clear continuation year for 2025. The program is the same. We will continue to deliver our growth: growth in oil and gas and growth in Integrated Power. This growth is accretive. New barrels continue and our cash flow from operations will grow faster than the production growth itself. At the same time, because we think the environment might be more challenging in 2026, we launched a cash saving program in September to strengthen resilience. You will also see in the presentation that the Integrated Power business is growing. We reached $3 billion of cash flow and, because it is independent of oil and gas cycles, it reinforces the resilience of the company’s overall model. A word on the market: I will not tell you what the price is, but we are planning everything at $60 per barrel. Today prices are around $71 or $72. The fundamentals we see are that demand continues. From 2023 to 2025 demand increased by a little less than 1 million barrels per day, a little under 1 percent, and we do not see peak demand ahead at this stage. In 2025 prices were quite stable around $70. People speak about volatility; in reality prices moved around $69 per barrel. We saw at the beginning of the year that fundamentals combined with events in Venezuela pushed prices down to $60, but reactions were twofold: OPEC decided not to add more oil to the market, and U.S. shale producers began to reduce drilling because $60 does not yet provide balance. Additionally, many countries are serious about putting more stringent sanctions on Russian oil. We have seen more Russian oil at sea that cannot find a buyer; the Indians are not buying Russian crude for March and April. Remember that Russian oil exports are 3 to 4 million barrels per day, so this has a real market impact. We still view fundamentals as balanced supply and demand, but we plan at $60 per barrel, and this explains certain decisions I will present. On the gas side, 2026 is more of a transition year. Global LNG capacity was 400 million tonnes per year in 2022 and 435 million tonnes in 2025, an increase of only 35 million tonnes in three to four years, which was not enough to absorb the increase in European demand. European demand rose from 65 million tonnes in 2022 to 115 million tonnes, an increase of 50 million tonnes. In 2026 some capacity will come online in the U.S. and Qatar, and we expect an additional 35 million tonnes. We translated this into moving TTF from $12 per MMBtu last year to $10, but not yet lower. Today, with winter, TTF is still around $12, but it could go down. Another factor is that the EU has decided to ban Russian gas from 2027, which will increase EU demand from 115 million to 150 million tonnes. We will have an additional 35 million tonnes per year of LNG coming in 2027, which is almost the increase of capacity in 2026. Global capacity will move from 400 million to 600 million tonnes by 2029–2030, but the impact on price will be gradual, and 2027 will not yet be the low point of the LNG price cycle. Having said that, we have taken actions to address this. 2026 objectives: overall energy growth +5 percent, oil and gas growth about +3 percent; I do not think we will reach 4 percent. For electricity net production we should grow by 25 percent to about 60 terawatt hours, which depends in part on when we close the EPH deal, but I am comfortable with this objective. The real objective for refining utilization from Vincent and his team is to stop having issues on big assets and improve availability by 2 percentage points. Refining utilization rate is not the best sole indicator of economics. LNG sales will continue to grow production by 6 percent, which will translate into sales; because there are spot volumes in Stephane’s team’s LNG sales, we aim to stay above 44 million tonnes. Renewable gross installed capacity target is 34 to 42 gigawatts—this is the roadmap of the Integrated Power teams. Emissions: on methane we think we will reach minus 80 percent sooner than expected; we had targeted minus 70 percent. Each year we do 5 percent more, so we will continue to deploy the program. We have deployed 11,000 devices for permanent monitoring, showing leadership and direct contribution to the climate. Methane’s heating power is much higher than CO2, so this is a strong focus for the company and our ability to demonstrate results. We will continue to lower Scope 1 and 2 emissions from operated facilities and to reduce the lifecycle carbon intensity of our sales by 19 to 20 percent, depending on production mix. We are on the way to the 25 percent reduction target by 2030, continuing to deploy strategy and grow Integrated Power. On growing free cash flow: I will come back to this because it is important. I read your comments this morning—some of you were surprised by the more than $26 billion figure. I will explain why we moved from $27.8 billion in 2025 at $69 per barrel and $12 per MMBtu down to $26 billion. If you take the environment at $60 and $10 you would find something like $25 billion. There are reasons why we think we will reach more than $26 billion. It is linked to the accretiveness of oil and gas production growth. In two years we will have, in fact, compensated $10 per barrel of oil price because of the growth and because this growth is accretive in terms of cash flow per barrel compared to two years ago. Last but not least, an important target discussed at the Board is to maintain 15 percent gearing, which will guide management of company cash flow. We said less than 20 percent before; we heard investor feedback in 2025. Our model is to maintain 15 percent, and we have ways to achieve it. We might see some volatility during the year because of working capital seasonality, but please do not panic—we will end at 15 percent. We deliver what we say; trust us. We have demonstrated that year after year. A word on our cash savings program: it contributes directly to free cash flow. We announced $7.5 billion in September and increased it to $12.5 billion because the guidance we gave in September around $16 billion of CapEx was reduced to $15 billion for 2026 as a result of the EPH deal being in shares. At the end of the day, issuing shares for EPH is an investment effort and we do not want to double count it. We are also working on OpEx savings. For 2026 we have a $500 million savings program. Part of it comes from Integrated Power because farm-downs allow us to rationalize assets and organization; we expect $200 million of fixed cost savings from that, and savings across upstream and downstream. Many initiatives are underway in marketing and services, reorganization of central services, and headquarters streamlining. We are reviewing organization as we did when prices were down in 2016–2017, and we will streamline again. We are launching new initiatives to continue feeding the cash savings program beyond 2026. One is supporting growth in Integrated Power and digital AI with a Global Competence Center in India, providing competitive cost and access to talent to accelerate growth; we plan to reach a critical mass of at least 500 engineers by 2027. Second, we are reviewing all non-proximity-dependent services and moving them to lower-cost countries. Some IT and engineering services currently delivered by high-cost contractors can be relocated; we believe there is more than $100 million of savings, probably more. We will apply this approach across segments. Third, we established procurement factories in Romania to handle framework contracts; we have negotiated with many suppliers. We will make this mandatory for the LBUs, pragmatically moving 20 of them by 2027 and more thereafter. There is good potential to centralize sourcing and benefit from company scale—probably at least 10 percent savings on a $2 billion footnote and more to come. The last initiative is mutualizing some support services across LBUs regionally, for example in Africa or even in France, where different refineries each have support services that could be consolidated for gains. Overall, we are taking the opportunity to review the way we work to become more efficient and resilient. CapEx for 2026 is $15 billion as announced. On Integrated Power low-carbon in cash it is $3 billion; if you add one year of EPH shares the equivalent is close to $4 billion. Elsewhere the figure is similar to 2025. Let me be clear: there is no reduction of the growth ambition. All projects launched will be delivered within budget. This is about working more efficiently. We revised CapEx from $17 billion to $16 billion in September, now from $16 billion to $15 billion because of EPH. In this figure we plan to divest $1 billion more than we will acquire. We have identified flexibility to go down to $14 billion, particularly on the acquisition side, if we face an environment below $50 per barrel. Growth: I mentioned 3 percent for oil and gas. Growth will come in part from start-ups from 2025 reaching plateau production, like Anchor and Mero 4 which are not yet plateaued. New start-ups identified for 2026 include Lapa Southwest in Brazil and Mabruk in Libya—these are not very large—Ratawi Phase 1 in Iraq which is more significant and will increase production to 120,000 barrels per day, Tin Fouye Tabankort in Algeria with around 55,000 barrels per day, North Field East in Qatar planned for Q3, and Uganda where we now plan to start the first train before year-end 2026, shifted from Q3 to Q4. This 3 percent production growth is likely the most important slide: it will translate into 7 percent cash flow growth. As Jean-Pierre told you, in 2025 a 4 percent production growth translated into 10 percent cash flow growth because of higher cash from new projects. In 2026, 3 percent production growth will be translated into 7 percent cash flow growth according to our plan, maybe a little more. When you do the math, upstream operating cash flow at $60 per barrel in 2026 will be equivalent to what we achieved in 2024 at $70 per barrel. We have offset $10 per barrel thanks to accretive growth. This is a strong message of the presentation. We continue exploration and spent on average $1 billion per year on exploration appraisal over the last 10 years. We had two major discoveries in that period, GranMorgu and Venus, which we plan to sanction in 2026. We have been active winning new licenses in 2025 in the U.S., Algeria, Liberia, Congo, Nigeria, Namibia, Malaysia and Indonesia. We have an interesting drilling program in 2026, particularly in Nigeria, Congo, Namibia, and Malaysia, with some frontier wells in Papua New Guinea and Indonesia. Efforts continue and Nicolas Mavilla has taken the lead of these teams to maintain our exploration success rate. On Integrated LNG, 2026 will have growth of LNG production of 6 percent with two projects starting up: North Field East in Qatar and Energia Costa Azul in Baja California, planned for Q3 with good offtake. These will contribute to sales. On the other hand, we lowered the gas price assumption, TTF from $12 to $10, which impacts LNG prices. If we are at $60 per barrel and TTF $10, the average energy price of our sales will be $8; we announced $8.5 for Q1. That math explains a decrease from $9 in 2025. With about a 10–12 percent decrease in sales prices and a 6 percent increase in volumes, we plan integrated cash flow from operations around $4.5 billion in 2026, roughly stable versus $4.6–$4.7 billion last year; growth is offset by a lower price environment. Integrated Power: the year will be dominated by closing the EPH deal, which brings 15 terawatt hours per year of net power production and $750 million per year of available cash flow on a yearly basis. This is a major step with potential to grow because there is a pipeline coming with 14 gigawatts of gas-fired power. For 2026 this will be translated into production of about 60 terawatt hours and expected cash flow above $3 billion. With planned net CapEx of $2.5 to $3 billion, 2026 should, for the first time, be a free cash positive activity contributing to the dividend, though there is uncertainty on the closing date. If not 2026, it will be 2027 for sure. This business will be free cash positive and is a turning point for how to value the business within the company; it will contribute to the dividend. Refining & Chemicals: in September I reported three weak sites—Port Arthur, Donges and Normandie. The good news is they are improving. Problems were identified in the reformer and steam systems; Port Arthur had a large turnaround delivered on time and is back on track. Donges suffered for several years; we will start the Horizon project to be able to produce gasoline to spec rather than for the export market in February–March, and Donges is returning to normal availability. The cracker problems in Normandie have been repaired and that platform is back to good availability. In the fourth quarter results Refining & Chemicals captured a good margin of $11 per barrel, which shows the plants are available. Vincent and his teams are implementing Boost27 to increase availability by 2 points and we will follow these KPIs closely throughout the year. Margins are currently lower overall because when oil is at $72 our integrated margin is around $4 to $5, but this is part of being integrated. Marketing & Services is growing steadily and generating about $100 million of cash flow per year. We had $2.3 billion in 2024, $2.4 billion in 2025, and we plan $2.5 billion in 2026 despite streamlining some networks in Europe and Africa. We have a special focus on lubricants and reorganized the lubricants business unit as an independent unit. There is no plan to divest it; lubricants are very cash generative, low capital employed, and a stable business. We will focus on auto and industrial markets and develop nonfuel revenue streams at our networks as a source of potential cash. The global picture for 2026: at $60 per barrel, $10 per MMBtu and a refining margin at $5, we will generate about $26 billion of operating cash flow, invest $15 billion, and have free cash of $11 billion. Dividend will be roughly EUR 0.80 to EUR 0.85 depending on exchange rates, and $3 billion of buyback is planned. Between 2025 and 2026, if you rebase 2025 to the same price environment, we have an additional $4 billion of free cash flow: $2 billion from lower CapEx and the other $2 billion from accretive upstream growth (about $1.1 billion), about $500 million from Integrated Power, $100 million from Marketing & Services, and $300–$400 million from Refining & Chemicals due to better availability. This is why the company is more resilient and able to distribute dividends. The Board decided yesterday to return to the traditional TotalEnergies dividend approach. Until 2022 we distributed quarterly intermediate dividends in the French system and a final one equal to the three previous ones. We departed from this tradition over the last two years because we had high price visibility. The Board prefers to be a little more cautious now; there is no signal against dividend growth. The new approach implies dividend growth of 5.6 percent per year in euros and 13 percent in dollars. Compared to peers we are well positioned. We will announce the quarterly dividend level by the end of April; the Board decided to see the market for one quarter to have better visibility. The idea is not to keep the dividend at the same level but to return to the traditional management of the dividend. A 5 percent guidance is probably reasonable. On buybacks, we had announced $3 to $6 billion between $60 and $70 per barrel in September. We have reset that guidance. During roadshows many asked whether there would be no buyback at $50 per barrel. The answer is there is no precise mathematical formula; the Board took a flexible approach and we want to be able to buy back $3 to $6 billion. We will start the first quarter at the bottom of the guidance and, if prices remain around $70, we will have the opportunity to increase that. I think it is better to increase than decrease. We chose the low range because we do not have full visibility. Priority remains maintaining gearing. We listened to investors loud and clear: 15 percent gearing is an anchor point. This matches roughly with $3 billion of buybacks at $60 per barrel. We do not want to increase net debt to finance buybacks; that will be part of cash allocation decisions in 2026. We have resilient operating cash flow, clear investments and will execute the $15 billion program. Dividend will continue, with some uncertainty from exchange rates. Keep in mind gearing sustainability: working capital can lead to a 2 to 3 percentage point swing in gearing; we anticipate $2 to $3 billion of working capital impact in Q1, which could represent 2.5 to 3 percent of gearing, so no panic. To finish, we updated the slide showing our consistent strategy which is differentiated from peers in two ways: in oil and gas we deliver growth and accretive growth and maintain a medium- and long-term view. We have renewed more than 100 percent of proven reserves over recent years, demonstrating capacity to identify new resources and sanction projects. I am confident in the pipeline of FIDs for 2026 and 2027 and that we will maintain our track record. The other differentiation is the integrated power pillar, which benefits from strong electricity demand in Western countries and will contribute to dividends if not in 2026, then in 2027 for sure. Thank you for your attention, and we are ready to take your questions. With our own staff, second, we want to manage all that to give them tasks end-to-end so they are fully accountable for these programs, and we should reach a critical mass of at least 500 engineers by 2027; that has already started. We plan to use AI to transform our operations and the way we act. One note though: my presentation was not yet done by an agent, so that's probably for next year. Thank you. And with that, I leave the floor to Patrick.

It's Biraj Borkhataria, RBC. First one, just on Namibia as you visited there. We know for Venus, you were looking for an extension to concession. Could you just talk about Mopane and whether the fiscal conditions today are sufficient for you to take FID and whether you're looking for any improvement there? Any comments that would be appreciated. And then the second question is just on your energy portfolio and specifically Yamal, you were quoted today around sanctions and the lack of ability to divert the cargoes. In the past, I think you said that you could divert some to Asia or keep some. So what's your latest understanding of how those sanctions will be enforced?

Okay. Namibia. First, again, the good news is that because we made this transaction with Galp, the authorities perceive us as a necessary partner. So we are there, and we will be the company which will help them to establish the oil and gas industry. So the dialogue even on Venus was much more, I would say, engaging — it's a new administration. It's a new country to oil and gas, so they had to learn. But they see us as the engine of capacity to deliver it. And I would say, we explained to them that we have an opportunity because now we have received the tenders. And honestly, we are within the ballpark for the CapEx we were anticipating, which is good news because there is also more appetite from contractors to transact with TotalEnergies again. So this deal has generated a lot of a good virtuous circle for us. So maybe I'm optimistic, but we have in front of us as well, the Namibian authorities organized themselves now in order to be able to engage with our teams. So we are working together. So the idea that we could sanction by middle of the year, we see if we can deliver. But clearly, it is on the program placed by the President, and we'll see if we can reach the point where we can sanction that. On Mopane, it's very different. Mopane has a permeability, which is much easier. Again, we are facing a development which is, I would say, more straightforward. So no — and again, it works with the CapEx we have in mind and the fiscal, it works without having to negotiate plenty of elements. The point on Mopane is more that we know it's big. We don't know if it's very big or bigger. So the idea of the appraisal program: Is it 800 million, 700 million, 800 million barrels? Or is it 1.1, 1.2? So we need to refine that — because in fact, the last wells drilled show an extension. So we need to see up to which point this extension goes because this could influence the way we develop the field. So we don't want to make a wrong call — that's the idea of the three wells, which will be drilled in 2026. So again, the idea is that we'll be able to define it and if we do that, we should be able to sanction that by '28 and then moving forward. So the idea is to have one project and the other one moving behind. And there are, obviously, synergies. And for TotalEnergies, by the way, it will also help to discuss all this business because we have the perspective to link Venus and Mopane, which was advantageous. So in terms of the way we'll approach this fiscal discussion: It helps everybody. And I think we have engaged in a smart and good way. So '26 for sure for us focus on Namibia will be important. And again, we have the opportunity to deploy our competence there in a very efficient way. Yamal, first, for '26 there are no new short-term sanctions that affect us. We do not have short-term deals with them; we make only the long-term contracts. For '27, there are rules that the EU has decided that will ban imports of Russian gas into the EU; this will be debated and clarified. Today, legally, there is a question mark because the way it's written leaves uncertainty: is it only import into the EU or does it prevent a European company like TotalEnergies from handling Russian LNG globally? The intent was not this initially from our reading, but the wording is unclear. We have engaged with the French Treasury and the European Commission for clarification. I cannot fully answer now. If required, we may have to stop marketing certain volumes, but at this stage we cannot say more. As a shareholder of Yamal, there is no immediate forced exit requirement. So that's where we stand for Yamal.

Matt Lofting at JPM. Two questions, please. First, you talked several times about the benefits of the higher-margin barrels and that's sort of bridging apart of the $10 per barrel '26 versus '24. No barrels are born equal. So I wondered if you could just expand on that a bit, geologically, fiscally size of assets, et cetera, when you think about the growth versus the base portfolio? And then second, I just wanted to ask you about M&A. I noticed during Jean-Pierre's comments, you did reference that the U.S. listed shares and that potentially being a sort of a source of supporting M&A in the U.S. in the future is obviously a province that historically, the company has often been pretty prudent on the view on valuations around. So any thoughts there would be appreciated.

You have no surprise. We have in the U.S. increased our gas upstream presence, and it's quite clear. We have done different deals. We still have, I would say, a gap of almost 1 Bcf/day. So we can do it by many small deals, so we can do it in other ways. So we are studying that. What I can tell you is that we have a currency we could use for some M&A in the U.S. And when you look to the U.S. market, it's better to make deals with shares. The upside is over 10%; you can do a deal in cash, it's much more expensive because of the fiscal regime. So that's one of the ideas. So we'll see if it works or not. But the idea to continue to find access to upstream gas in the U.S., that's a clear priority for us. And on the high margin barrels, you can see the mix on the slide. When you look at geography, the U.S. onshore and Brazil offshore are delivering quite high margin because fiscal terms are lower compared to others. And you have Brazil, which is also giving some good cash. So those are the main contributors. We are also replacing barrels from the North Sea or barrels from Nigeria, which honestly don't have a big margin. So we replace those by barrels which have a much better margin. So that's a mix story — geography, fiscal terms, and the nature of the fields.

If I go back to the cash accretive barrels — if we think about value as not cash flow, but cash flow, is there anything we can say about the CapEx of the new barrels and combined with legacy oil and gas, and therefore, the free cash flow generation of the new barrels? And then my second question on integrated power. Obviously, it would be a major milestone to turn a relatively young and very fast-growing business into free cash flow positive this year or next year. When I look at the renewable subsector of utilities, they're all cash negative, and they remain cash negative, perhaps with one exception. So I wanted to understand what it is that you have done so very differently to companies that have been in that business for far longer than you, some of which are much, much bigger than you are.

I can reverse the question: why don't others do like us? I don't know. But I know our figure, I don't have a huge experience and we are — our Board is asking us permanently to make some benchmarks on these big companies, but the size of the business makes it quite difficult for us to do it. Honestly, maybe Stephane has a recipe. It's a mix of — I mean, again, the integration delivers a global cash. In '26, the $3 billion we plan comes from a mix: roughly 60% from renewables and gas-fired power plants and 40% from downstream customer contracts and trading. On the renewable part, we continue to invest. In terms of free cash, the fact that we recycle the CapEx helps a lot: we recycled around $2 billion through farm-downs, which allow us to finance a large part of the organic CapEx. We more or less finance 70%–80% of renewable CapEx by recycling. That discipline helps a lot because that limits the cash burn. Also, we concentrate on fewer geographies and larger projects rather than many small projects across many countries — it is more efficient. We are industrializing the platform approach in the U.S. and other places with strong partners. So that's the approach — recycling, scale, platform partners, and focus.

I want to ask two questions. We've seen opportunities opening up in several countries or at least better fiscal terms where TotalEnergies has operated in the past, from Venezuela to Syria, Kuwait, et cetera. We've already seen the success you've had in Iraq and Libya leading to new projects. How do you think of these opportunities? And then I wanted to ask you on Tilenga. It starts up at the end of this year. It's a major part of the growth next year. When do you expect it to reach its own plateau?

The plateau should be reached by mid '27, to be clear. When being started this year, the second train in the first half, so plateau by mid '27. There was a delay, to be honest, it's not a strong performance instead of construction. The main difficulty we faced was to mobilize people on the ground. There were not so many people with the right competencies locally, and we were obliged — one of the main contractors had to find people and bring them in. So we lost some time in mobilization on the ground. Now progress is back on track. Nicolas is following that every week. So we are back, but there is a delay, it's a challenge. We have other sources of growth, so it will feed next year. On the first question: we like what we've done in Iraq. We can do more in Iraq. We have opened the door. The authorities remember that we have opened the door. We will work with them. New government will be put in place. I think we have a strong partnership also with Qatari partners. In Libya, we have improved fiscal terms and have an incentive to invest. The main challenge will be to mobilize contractors because Libya is not yet fully stable. But these assets can be very low-cost oil and they can renew reserves. So the interest is clear. On Kuwait and other Middle East opportunities, we look at them carefully. We don't have infinite resources so we prioritize. On Venezuela, it's not in our near-term priority because of the higher cost and upgrade requirements. So we are selective.

Yes.

Two questions. I noticed the CFFO payout link has disappeared. And I wonder with free cash flow inflection coming from integrated power, whether you're considering how that changes your linkage in terms of payout policies as we move into 2027? And finally, integrated power actually helps finance some of the buybacks and dividends. That's question number one. And number two is again on M&A. The EPH was a great example of a noncompetitive deal. But Namibia was very competitive, and it seems you should be in a good position to tell us what the M&A environment is like today for undeveloped resources. Where are you seeing the market there?

The mention of more than 40% payout was in the last slide, if I remember well. So it did not disappear. It's just 40%. Again, I think it will be clear that this year Jean-Pierre said 40%, 55% payout, it's too high. The Board felt 55% was high, and in fact, the buybacks in 2025 were financed by debt, which is possible. In 2022, we benefited from incredibly high cash which lowered net debt gearing to 7%–8%. Returning part of that cash was appropriate. The Board wants to anchor gearing at around 15%. Integrated power is good news because EPH will accelerate the path to being net cash positive, which changes the balance. But we will not change the payout policy now; we need delivery to be confident. On M&A, today's market is still quite high. Sellers expect $70 per barrel and valuations are elevated, so we remain disciplined. We prefer deals paid in shares where it makes sense, and we will use the NYSE listing as an additional currency for U.S. deals if needed. But we will be smart and refrain from overpaying.

Two questions on the AI-related topics. On the idea of selling to data centers, anything about the 60 terawatt hours going to 100 terawatt hours, how much of that uplift do you think you can sell to data centers? And that 10% premium, is it actually enough because ultimately, the value that data centers get from having power straight away, it should possibly be higher premiums? And then second, on TotalEnergies own AI. Patrick, you talked about getting agents next week. But that idea of what surprise here? Is it increased production, the 1%, 2% a year? Is it recovery rates? Just what — what is the ambition around it?

I learned that you have an agent, so you need to teach me. No, clearly, but I will let the floor to Namita and Stephane to answer the question. On the second one, more broadly, we are looking at improving availability of plants. We expect gains of 1%–2% in production from better maintenance and digitalization. Subsurface recovery gains are earlier stage; there may be some acceleration benefits but let's let Namita comment on the digital specifics and Stephane on the data center penetration.

Yes. I agree with what Patrick said. Our main goal is, of course, to increase production. I can give you some concrete examples. With digital in general, process control improvements can increase output by 1% to 2% on assets where we have applied them. Also, fewer breakdowns: we focus traditionally on very large pieces of equipment like turbines, but we realize many breakdowns occur on small components. The idea of getting connections to over 70% of our equipment is to have fewer breakdowns. That combination increases production. On the subsurface side, it's early stage for recovery improvements, but AI can accelerate FIDs — faster analysis, faster drilling — enabling quicker tiebacks, which matters for both large and smaller projects. So those are the main areas where we expect gains.

Okay.

Two questions. First, I'm interested about regulation in Europe. Now you're going to be one of the largest generators in Europe after the EPH acquisition. I understand your thoughts about the system and that it needs some changes. Second question: we are also seeing consolidation in services and drilling and it looks like there is a new wave of investments in the upstream business. What are your thoughts about potential cost inflation in upstream investments?

It depends on the market. If a market consolidates to just two or three players, that could be a problem for competition. We see stabilization of contractor markets and some appetite returning: in Namibia tenders we received more competitive bids. On integrated offers combining wells and subsea, some contractors promote integration but we haven't seen clear advantage to date in our tenders. We are experimenting with more integrated contracts where it makes sense, for example in Iraq, which can improve efficiency. Competition remains important and we prefer to preserve it when possible.

There are several regulatory questions. We are focused on ETS1 where CO2 prices can impact power economics. Higher CO2 price benefits renewables and CCGT and supports the transition, but policymakers must balance industry impacts. ETS2 questions have marginal consequences for us. Overall, integrated power benefits from a reasonable CO2 price which supports both renewables and gas-fired flexibility.

Fundamentally, we favor a CO2 price that drives the transition. If policymakers want to protect heavy industry, there are mechanisms other than lowering the CO2 price; they can design targeted support. The debate continues and it's important for policymakers to decide whether to use CO2 pricing or other tools to support industrial competitiveness.

Two questions. First, on FIDs for '26 and '27. You mentioned Venus for mid-2026. Which other projects do you see as perhaps more likely to go ahead over the next couple of years, which ones are more challenging across oil and LNG? And second, on LNG you mentioned risk of new project delays in '26. What do you see the risk for the projects in which you're involved in Qatar?

For NFE (North Field East) in Qatar, the industry expects completion toward Q3; it's progressing well. Energia Costa Azul (ECA) in Baja California we expect Q3 with monitoring of quality. On other FIDs in '26: Venus is targeted mid-2026; IMA in Nigeria is an easy gas project and we launched tenders and expect progress toward sanction in '26, but Nigeria has always some local hurdles. Papua LNG is a key decision in '26: we need the commercial and financing work streams to converge; we have reduced CapEx compared to earlier estimates to a more realistic range. If we manage the discussions with the government and partners, we should be able to sanction in '26; if not, we will take more time. So several projects are on track, but some are conditional on partner/government progress.

Two quick questions on upstream, please. First, on Mozambique LNG: you've now restarted construction. Could you talk about the revised timeline for the project in terms of remobilization and first LNG? And secondly, maybe just a word on the NEO NEXT transaction in the U.K. North Sea. What's the impact there on production, CapEx, maybe future growth? And do you see a similar structure elsewhere in the world potentially being applied?

We have restarted in Mozambique. I visited Afungi; we have almost 5,000 people on the ground already, 4,000 local and 1,000 expatriates. Full ramp-up to 15,000 will take time. Most engineering and long-lead procurement were already completed, so the project is focused on construction. We target first LNG by 2029, possibly 2028, but 2029 is the realistic date. On the NEO NEXT transaction in the U.K. North Sea, it increases our production by around 10,000 barrels per day on our share, delivers some CapEx synergies (we estimate some tens of millions to low hundreds of millions across the group through operational synergies and abandonment cost efficiencies), and creates an environment to optimize abandonment and operations. This deal is specific to the U.K. context where consolidation makes sense; we don't see an immediate replication everywhere, but we will consider similar options where scale and synergies justify it.

Two questions. First, when EPH volumes come into your portfolio, are they already presold? How are you looking to market them when they come through? Second, the net CapEx guidance of $15 billion for the year — is that an organic number? Are there acquisitions and divestments beyond what you've already mentioned in terms of farm downs that we should think about in that number?

EPH volumes are not presold. After closing, we will offtake 50% of the production and sell these volumes on the wholesale market; we will hedge normally like any other market participant. On CapEx, the $15 billion is net: we expect about $1 billion more of divestments than acquisitions, so the organic scheduled spend is somewhat higher (around $16 billion) with netting leading to the $15 billion figure. We have a pipeline of divestments to reach that net figure, particularly in upstream mature assets where disposals are planned.

To add: the organic figure is effectively higher but the net number includes our targeted divestments. We have at least $1 billion to $1.5 billion of divestments that are quite clear and in process. The net CapEx guidance is calibrated accordingly.

Two questions. First, chemicals: you are a big player, but I guess the scope for upside may be limited if the chemical cycle normalizes. Do you see signs that the chemical cycle may normalize and when? Second, on LNG: in terms of contracting and building the portfolio now, you've pretty much achieved the 8 million to 10 million tons of LNG sales that you wanted under Brent-linked terms. Are you broadly done contracting? Is there more to be done?

Chemicals: our exposure is mainly to polymers and ethylene/polyethylene. We are not a large diversified chemicals group. Today there is a global overcapacity, notably from China, which has built significant capacity and reduced its imports; that depresses margins globally and impacts European naphtha-based crackers. We are selective: we have exited or sold some assets (e.g., Lavera), we have shut down less competitive units and we are managing our crackers and polymers carefully. Ethane-based polymer value chains (U.S., Middle East) remain highly competitive. Overall, we are managing the portfolio — some parts are cash-generative, others under pressure. We are not in panic mode but will continue to rationalize. On LNG contracting: we sold more than 8 million tonnes on Brent link terms across '23–'25. The portfolio is well balanced through 2030 in our view. Contracting is an ongoing process — contracts expire and production increases, so we will continue to manage post-2030 exposures, but we are comfortable with the current portfolio.

As Lucas mentioned, we sold more than 8 million tonnes between '23 and '25 on Brent basis into Asia. We are happy with what we have done and consider the portfolio well balanced until 2030. After that, it's ongoing work as contracts mature and new production comes, so we'll continue to manage the portfolio post-2030 and expect additional Brent-linked sales where it makes sense.

Maybe we can take a question online.

I had a question on the new exploration acreage you just took in Namibia. It's a different basin, probably higher risk and less explored. How do you compare the potential of the basin with other basins such as the Orange Basin?

It's the Orange Basin. It's a basin that has shown very strong potential. The exploration success so far (Venus, Mopane) indicates a real basin play. We partnered where it made sense and competed where needed. The prospects are material — the license additions expand our footprint and offer a coherent basin development strategy. It's promising, and that's why we committed.

Congratulations on the good results. On the electricity business including renewables: you've grown it well and with better profitability than many traditional utilities. If you can continue to have good opportunities, good profitability, and good free cash flow, do you have a strategic cap for the expansion of your electricity business long term?

No, there's no fixed cap decided: this will be debated at the Board. We asked for a long-term time horizon to build the business. The turning point is when the business becomes free cash flow positive — that shifts the discussion. The Board is reflecting on how large to grow integrated power beyond 2030 and at what pace. We are comfortable with growth to a sizable position, but the strategy, pace, and geographic focus will be debated and clarified in the next strategic seminar. We also observe that different regulatory frameworks (e.g., Europe's CFD approach vs. US market approach) will affect how the business evolves. We are focused on profitable growth and integration with our gas and power assets.

Okay. So we have a technical problem, but I will take the question from Duke.

You asked whether you receive Galp's share of coastal benefits given you're carrying Galp. Also, what is the current dividend breakeven post the EPH deal and after the EPH deal is closed?

Yes, we take our share of coastal terms as part of the transaction arrangements. On dividend breakeven: roughly, using simple sensitivity, a $3 billion annual buyback equates to roughly a $10 per barrel swing. Dividend breakeven is in the order of $50 per barrel; post-EPH, the breakeven moves a bit lower given the cash flow contribution from integrated power — around $47–$48 per barrel depending on exact assumptions.

I had a question on the outlook for global gas. Clearly, some of the strategic moves you've made are on the back of your view that there's going to be somewhat of a narrowing of global gas prices relative to Henry Hub. If gas prices do fall further from here, below your TTF assumption of $10, what measures have you put in place? And how can the integrated power business, such as the acquisition you made in Europe help to mitigate some of that fall in TTF pricing?

We have tried to balance the portfolio so that a meaningful portion of our gas sales are indexed to Brent rather than purely to TTF, so we are not overly exposed to TTF declines. Second, integrated gas-to-power assets provide natural hedges: if gas prices fall, gas becomes more competitive for power generation in Europe and our CCGTs and integrated power assets can capture margin in power markets. So portfolio mix and integration mitigate downside on gas prices.

Yes, integrated power benefits from a lower gas price in Europe because CCGTs can run more and capture power margins; at the same time, renewables benefit from market dynamics linked to gas and CO2 prices. Integration across gas and power reduces exposure to wholesale gas-only moves.

Another question on Namibia acreage comparison: how do your geologists compare the potential here relative to other basins?

We have significant confidence given the discoveries and de-risking to date. The Orange Basin has clear play elements. The acreage we added complements our position and gives us scale. It is a high-potential basin and we are optimistic, but we will continue to appraise with rigorous work.

Follow-up on electricity business: do you have a strategic cap long term for expansion?

As I said, there is no fixed cap yet. The Board will debate the pace and scale beyond 2030. The key is profitability, cash generation and integration. We see strong opportunities, but we will choose the appropriate scale consistent with returns and balance sheet targets.

Okay. So we have a technical problem, but I will take the question from Duke. We lost Doug? He preferred to be with a competitor in New York. We will try to pick up online questions later.

So if you are satisfied, thank you. Thank you for your attendance. Thank you for your comments. And thank you to all the teams of TotalEnergies who have delivered these results, including, of course, the different executives present in the room. And so the next meeting with you potentially might be in Houston for the ones who want to participate to this field trip on Rio Grande. And again, with a focus on LNG and the portfolio, and how we manage all these times which are in front of us. Thank you for your attendance.