Carbon Capture: System Versus Material Innovation for Cost Reduction

Runeel Daliah: Hello, everyone, and welcome to the webinar, “Carbon Capture: System Versus Material Innovation for Cost Reduction.” My name is Runeel Daliah, principal analyst at Lux Research, and I will be moderating today’s session. Presenting today is my colleague Mukunda Kaushik, Associate Research Director here at Lux. Throughout the webinar, you can type any questions you have in the questions box on your screen, and we will answer as many as we can, time permitting. If your question does not get answered, please don’t hesitate to email it to [email protected], and we will respond. If at any point you experience technical difficulties, simply refresh your browser and check your internet connection. Without further ado, let’s jump into the presentation. Mukunda, over to you.

Mukunda Kaushik: Thanks, Runeel, and thank you, everyone, for joining today. We’re going to be talking specifically about carbon capture. Over the last year to year and a half, the conversation around CCS has really focused on sequestration and storage, which makes a lot of sense because that has been a major pain point for the industry. However, the progress we make in storage will highlight that we first need to capture the CO2, making innovation here important again. It’s a cycle, and one that will continue until this value chain is fully built out. Lux senses that companies will soon refocus on innovation within carbon capture. This time, however, their appetite for engaging with new technologies is decreasing unless there is a clear path to scalability. That is what we want to explore today. The fundamental question is: Where is innovation in carbon capture really necessary? Oil and gas companies, which have spearheaded CCS efforts globally, have adopted a wide range of strategies in 2026. ExxonMobil has been moving full steam ahead. The company said that three CCS projects would come online, along with a final investment decision on a low-carbon data center in 2026 that would also use carbon capture. Equinor has taken more of a wait-and-see approach: It will continue to develop existing projects such as Northern Lights, but pause new CCS investments until that initial capacity is fully booked. Meanwhile, companies such as BP are looking to sell stakes in two of their largest CCS projects in the U.K. At this point, we don’t want to say that one company is right and another is wrong, nor would that be the correct conclusion. Rather, let’s discuss the factors that likely influence these decisions. In other words, what would it take for Equinor to continue, or for BP or even Exxon to reconsider its stance on CCS? We’ll start by discussing the current drivers of carbon capture and the key contributing industries. Then we’ll examine the economics of carbon capture and specific routes for cost reduction. Today’s focus is cost reduction through system improvements versus material improvements. Some companies are working toward near-term projects, while areas such as material informatics have become major use cases for AI, contributing to sorbent development and dual-functioning materials. We’ll provide some context for those developments. Lastly, we’ll end with an outlook, action items, and key takeaways. Overall, four factors drive whether a company wants to deploy or engage with CCS right now. The first is policy. Carbon capture is highly policy-dependent, so companies benchmark CCS costs against regional carbon prices and examine specific regional incentives. The U.S. still has the largest pipeline of new projects under development today, probably because of the 45Q tax credit. It therefore comes as little surprise that, of the three oil and gas companies we looked at earlier, the U.S. major is moving full steam ahead. The second factor is competing options. Industries with multiple options are still weighing the pros and cons. Steel is the clearest example, with a choice between hydrogen-based DRI and carbon capture. More broadly, we are seeing a strong focus on electrification: Do I invest in decarbonizing my fossil-fuel molecules with carbon capture, or do I invest in renewable electricity? Third is infrastructure. This is not just about availability, but also accessibility. We see this in the EU, where southern countries such as Spain and Italy are trying to deploy carbon capture but do not have as much storage capacity as northern countries such as the Netherlands or Germany. Fourth, and most importantly, is the cost of carbon capture. Today, capture is still the most expensive part of the CCS value chain, and we need to bring that cost down. We’ll briefly examine each of these factors. When it comes to policy and active carbon prices, apart from a few countries, overall carbon prices are still far too low to significantly affect decision-making. With EU prices constantly moving between USD 70 and USD 100 per ton, they become more relevant at times, but otherwise not significantly so. The most important development here is that the EU and Japan are allowing international carbon credits as part of their ETS systems. That can influence which industries adopt carbon capture, as we’ll see shortly. Policy support for technologies other than CCS may also lead industries to prefer those options. For example, the EU offers a fixed semiannual payment to support electrification. At Lux, we analyzed the electrification potential of each country and compared the cost of electrification with a CCS cost of USD 150 per ton to determine where CCS could be competitive. The optimal conditions are low electricity prices and high natural gas prices. We found that electrification will be easier in countries such as Denmark, Poland, Sweden, and Turkey, whereas CCS may be more cost-competitive in Germany, the Netherlands, Croatia, and Hungary. There has also been substantial momentum in CCS infrastructure in 2026. Unlike capture, where deployment tends to be more distributed, storage is an area where governments and industry can work together—and have been doing so—to develop infrastructure. What you see here are examples of infrastructure progress in 2026. Northern Lights in Norway began injection earlier this year. Petronas is moving faster than initially planned on its CCS project in Malaysia and is also building relationships with Japan and South Korea for CO2 imports. California began injection at its first CCS site, with an initial capacity of about 1.5 megatons per year. With eight more permits still pending with the EPA, that capacity could increase. In the Netherlands, Porthos’s sister project, Aramis, is receiving its first permits ahead of a 2027 final investment decision. I began by saying that everything will come back to carbon capture. Why? Because final investment decisions for storage projects—or, more specifically, phases two and three of storage projects—will be linked to final investment decisions for carbon capture projects. Now that initial injection has started, if California is to go beyond 1.5 megatons, or if the Netherlands is to increase Porthos’s capacity tenfold, there must be enough CO2 to fill that capacity. Again, it is only a matter of time before the industry conversation returns to carbon capture. Essentially, all roads lead to the cost of point-source carbon capture, which requires technological innovation. We also need to understand which industries will adopt carbon capture over the next decade, because those are the industries for which we need to build solutions. So, who will adopt carbon capture? First, industries with an inherent process dependency. If CO2 is emitted only through fuel combustion, fuel switching can eliminate the need for carbon capture. But if other CO2 emissions come directly from the process, carbon capture becomes much more essential. Second are industries with unprecedented growth in demand for carbon capture. Third are industries with opportunities for revenue generation, whether through a byproduct or another intangible commodity that can be sold for monetary value, such as a carbon credit. The industries that fit these categories, respectively, are cement; power generation, specifically natural gas; and waste-to-energy and other biogenic sources. Demand for cement continues to grow in the built environment, and the process continually releases CO2, making carbon capture important. For data centers, a recent Bloom Energy survey showed that 31% of on-site power for data centers will include some level of CCS by the end of 2030, increasing to 41% over the following decade. Again, much of this activity is currently in the U.S. The last category is the generation and sale of carbon credits from more distributed biogenic CO2 sources, which regulations are beginning to accept. Because carbon-capture costs vary across industries, these are the three growth areas for the next 10 to 15 years. With about 200 megatons of announced capacity over the next decade, cement, power and heat, and biogenic CO2—including waste-to-energy, bioethanol, and biogas—will drive capacity. Growth is expected to begin this decade and accelerate after 2035. However, these three industries have very different flue-gas properties and do not operate at the same scale, so their costs differ. For the rest of the presentation, we’ll discuss costs in the context of these three industries and examine reductions that can be achieved through systems and materials innovation. We’ll begin with a baseline: carbon capture using monoethanolamine, or MEA, and benchmark cost reductions against it. For a one-megaton-per-year facility, costs range from about USD 90 per ton for natural gas to about USD 160 per ton for a large cement facility. This variability is determined by CO2 concentration—lower concentrations require more energy—as well as process-specific factors and ease of integration. For example, is usable heat available within the process? In cement, it may not be available at the required location or temperature, so steam costs are much higher. These figures are for a one-megaton-per-year facility, but costs can rise at lower capacities. You can see the cost of carbon capture as a function of capture capacity here. Although most projects will eventually want to operate at megaton scale, initial deployments will be smaller. In cases such as waste-to-energy, a facility may simply not emit that much CO2 and therefore operates at a smaller scale. At about 500 kilotons per year, the cost with MEA can range from USD 100 to USD 160 per ton. At 300 kilotons per year, it can rise to about USD 120 to USD 180 per ton. Improvements to MEA already exist. In this analysis, we used an energy consumption of 3.5 gigajoules per ton for MEA. A novel or advanced amine has energy consumption of about 2.7 gigajoules per ton. Solutions at approximately this level are already offered by major providers. Compared with MEA, they reduce carbon-capture costs by about 10% to 15%, purely through material improvements. As you can see, however, costs in this scenario remain above USD 100 per ton. To reduce them further, you can take either a systems approach or a materials approach. The question we are trying to answer is this: Do we need a better solvent that operates well below 2.7 gigajoules per ton, or can system-level benefits or modifications, paired with an existing commercial solvent, achieve a similar cost reduction? New carbon-capture technologies can intensify processes that use existing amine solvents, introduce other material innovations, or rely on fundamentally different operating principles. System innovation and system modification can include process intensification—that is, equipment innovations that drastically reduce equipment size relative to capacity. These innovations can reduce energy use and utility costs or improve heat utilization. In essence, they deliver physical shrinkage, reducing equipment dimensions; thermodynamic benefits, enabling more efficient heat transfer; or functional system modifications that combine multiple unit operations, such as reaction, separation, and heat exchange, in a multifunctional apparatus. Novel materials involve developing and commercializing capture materials with higher CO2 loading, lower energy use, lower degradation, and similar advantages. Starting with system innovations, we’ll examine two examples and their impact on the CAPEX and OPEX of carbon capture. The first uses rotating packed beds, which are alternatives to solvent columns. They typically use centrifugal force instead of gravity to significantly increase contact between flue gas or CO2 and the capture material or solvent. RPBs mainly target CAPEX. They are much smaller at the same carbon-capture capacity and have a much smaller land footprint. In fact, companies working with rotating packed beds target not only solvents but also sorbents. A good example is Svante, which uses circular filter beds placed in a continuously rotating machine. Again, the goal is to maximize contact between the flue gas and the capture material. Relative to conventional solvent systems, we estimate about a 50% reduction in the CAPEX of the CO2 capture unit itself because of the RPB, as well as better resource use. This translates into smaller reductions in land and utility costs. Because the system is also more efficient, we assume about a 20% decrease in OPEX associated with steam supply and factors such as solvent disposal. When we apply these modifications, the cost falls by about 25% relative to the benchmark, which is significant, especially for a project that needs to begin operations before 2030. At the same time, however, it is not an order-of-magnitude shift. You may notice that we do not show cement here. One limitation of rotating packed beds and process intensification is that they are better suited to smaller projects than to a single, large, megaton-scale project. For smaller-scale operations, combining amines with some level of system modification could be a viable way to achieve a cost reduction of about 25% to 30%. The second example is integrated heat recovery. In this case, exhaust heat is captured to reduce the external energy required by the carbon-capture solvent. This thermal energy can potentially be used to cool flue gases while extracting heat and to supply steam for regeneration. Overall, this improves system efficiency and lowers OPEX. Compared with an RPB, it places greater emphasis on reducing steam-supply costs and OPEX than on reducing CAPEX. However, heat recovery and access to excess steam are not as easy as they may appear on paper because heat is not a static commodity. It is not always available at the correct temperature or at the right point in the process. The main benefit, again, is reducing the cost of steam, one of the largest contributors to overall capture costs. In this case, we assume a 50% reduction in the cost of steam supply, although the actual range may be about 10% to 60%. Because heat exchangers or other thermal-management units are being added, we also assume a slight increase in utility and infrastructure costs, as well as additional conditioning costs. When we apply these changes, costs decline, with a larger impact in industries such as cement, where steam costs are inherently higher. If waste heat can be integrated from the process or low-cost external heat is accessible, costs can fall by about 29% to 30%. Today, companies such as GEA offer waste-heat-recovery systems specifically for industries such as cement. Overall, however, the cost reduction still tends to be about 20% to 30%. Another important consideration is that system modifications—whether rotating packed beds or modified heat exchangers retrofitted into conventional facilities—cannot be standalone offerings. They must be part of existing EPC or engineering offerings for carbon capture or be integrated with the material, because a project is unlikely to use separate EPC, material, and systems partners. Companies that develop these technologies can have the greatest impact when they provide a more integrated and comprehensive solution. Turning to materials and comparing them with system innovations, what you see here is the cost of carbon capture as a function of changing energy consumption. We selected energy consumption because most material developers, whether startups or corporations, base their value proposition on this key metric. For metrics such as carbon-capture efficiency, most developers can operate at least at 85% to 90%, with leading players operating well above 90%. The key metric that differentiates companies and creates distinct clusters is energy consumption. What you see here are the three industries we examined—cement, waste-to-energy, and natural gas—and the cost of carbon capture at about 2.7 gigajoules per ton of CO2, the figure used in the earlier scenarios for advanced amines. Based on the rotating-packed-bed and heat-recovery examples, system innovation can reduce costs, but typically by about 30%. In a best-case scenario, the actual levelized cost of capture is somewhere between USD 90 and USD 100 per ton. That is the red-line threshold shown here. Novel solvents aim to reduce energy consumption. If they remain above the red line—the threshold for systems—you are likely better off using an amine solvent and modifying the system. Several companies today, both startups and corporations, offer solvents with much lower energy consumption than 2.7 gigajoules per ton. BASF and ION Clean Energy claim about 2.5, while companies such as Honeywell and Carbon Clean claim to operate between 2.0 and 2.1 gigajoules per ton. These results show that, in some cases, those technologies can offer better economics than system innovation alone. Solutions in the BASF or ION range perform well for natural gas combined-cycle plants, but they do not offer significant benefits for waste-to-energy or cement. Technologies in the Carbon Clean range perform better for both waste-to-energy and natural-gas power generation, but again not for cement. Even then, the improvement is only marginal relative to what systems can deliver. If your partner is BASF or Honeywell, with substantial institutional knowledge and market credibility, that may not be a problem. For less-established startups operating between 2.0 and 2.7 gigajoules per ton, however, commercialization will be challenging. Industry would need to bet on either a novel formulation or a relatively unknown company for a cost reduction of only USD 5 to USD 10 per ton compared with established players. Today, many companies are developing solvents or sorbents that operate between 2.3 and 2.6 gigajoules per ton and are seeking commercial partners. This is where we can begin to distinguish disruptive innovation in carbon capture from innovation that is not necessarily commercially meaningful given the market’s likely direction over the next five to 10 years. What next-generation innovations can deliver meaningful cost reductions across these industries? These technologies can operate at lower energy inputs—below two gigajoules per ton—through a new material or a fundamentally different operating principle. Here, we highlight examples of companies that fit the bill. These startups claim to operate at or below 1.5 gigajoules, more than a 50% reduction from the MEA baseline. Examples include Captivate, with a cobalt-based metal-organic framework; Mitico, which uses solid carbonates paired with a fluidized bed to extract more value from the material; and Mantel, which has developed a specialized system using molten borates to recover both combustion heat and absorption heat, reducing net external energy consumption. Net external energy consumption is the key measure. For Mantel or any other carbon-capture technology operating well above 100 degrees Celsius—or, in Mantel’s case, above 800 degrees Celsius—such low energy use is impossible unless the energy comes from another source. If it comes inherently from the process or from a unique aspect of the technology, it remains relevant to this type of innovation. Although these are all very early-stage companies, they are more likely to have long-term commercial impact than companies developing solvents in the 2.1-to-2.7-gigajoule-per-ton range. Early results show two advantages. First, these technologies offer benefits across all industries rather than working for only one, making them more likely to secure partnerships. Second, their improvements are much greater than 20% to 30%. As the gradient of these lines shows, costs begin to decline much more steeply below two gigajoules per ton. These are the kinds of companies that can have a genuine materials impact, and the kinds of cases in which betting on a new material makes sense as the industry moves toward a climate in which commercialization is critical. Many major corporations are also building portfolio approaches. It is important to understand which companies and technologies should be part of those portfolios. Much of that begins with novel solvents and the extent to which solvent technologies can be improved. Mitsubishi Heavy Industries has been doing this over the past decade. Across three generations of its solvent, it has reduced energy consumption. This is a major blind spot for early-stage material companies: They often assume incumbents will not improve their own technologies. If you have a novel solvent in your portfolio with slightly lower energy consumption than current offerings and pair it with a system-level benefit, you can maximize carbon-capture cost reductions rather than relying solely on a new material. A portfolio starts with novel solvents. When expanding into earlier-stage technologies, exclude technologies that incumbents could readily cannibalize and look for those with stronger inherent differentiation or long-term potential. These more disruptive technologies are characterized by energy consumption typically below 1.3 or 1.4 gigajoules per ton, or by the production of a byproduct that also helps reduce the net cost of carbon capture. To summarize the comparison between process intensification or system-based solutions and novel materials, the main benefit of process intensification is its alignment with commercial projects that must begin operations before 2030. If a natural gas combined-cycle plant or cement facility needs to begin carbon capture before 2030, it realistically cannot engage with technologies below TRL 7. If a next-generation carbon-capture technology cannot meet the project timeline, system-based solutions offer a good way to achieve that 25% to 30% cost reduction. We expect them to be increasingly paired with amine solvents. Second, system innovations can coexist with material improvements, especially in amines. Over the last decade, amine-solvent energy consumption has fallen from about 3.5 to 2.7 gigajoules per ton. It is possible that it could fall from 2.7 to, say, 2.1 over the next decade. If system-level benefits are already installed, operators can continue to capitalize on material savings. In other words, a new material is not required to reduce carbon-capture costs. The challenge with process intensification is that it can be less impactful for larger-scale projects. At two or several megatons, returns may begin to diminish. It also will not deliver an order-of-magnitude cost reduction, such as the USD 40-to-USD 50-per-ton costs claimed by several disruptive companies. The advantage of materials is that they target the largest cost center within the CCS value chain. Excluding materials that perform similarly to system-based solutions, material innovations are the ones that can deliver order-of-magnitude cost reductions. Investments in this space do not always involve only the material; they may also support manufacturing and supply-chain development. If you introduce a new sorbent membrane with a sorbent embedded in its matrix, the required manufacturing capabilities and supply chains may not yet exist. Building them can therefore present important opportunities. Lastly, material developers offering solutions that are roughly similar to existing market offerings will face a difficult path to credibility, especially if the retrofit approach differs. Companies will need to account for that. When considering carbon-capture cost reduction, we discussed process dependency and growing demand as drivers. We also want to spend more time on what revenue generation can look like in this context. This does not mean revenue from carbon capture itself, but rather byproducts or externalities of a specific carbon-capture technology that can offset or negate some capital costs. There are two examples. The first is carbon-capture technology that generates steam as a byproduct. Consider Mantel, which uses molten borates to capture carbon from high-temperature assets. The company can recover combustion heat by retrofitting its absorber before that heat is removed. The absorption process is exothermic, so both the heat of combustion and the heat of absorption can be recovered to produce about 2.5 tons of steam per ton of CO2 captured. Integrating a technology like this into a boiler can increase that boiler’s output. The company claims that, for a natural gas combined-cycle plant, output increases by 20% to 40%. Another way to think about this is a facility operating three industrial boilers. If Mantel’s carbon-capture technology is installed on one boiler, the additional steam generated may allow the facility to shut down another boiler because the carbon-capture unit inherently produces steam. We calculated the value of that steam, which varies significantly by region. In the U.S., Mantel’s primary market, it translates to about USD 26 per ton of CO2 captured. If that value is combined with the 45Q tax credit, which remains in place in the U.S., the cost of carbon capture can fall to approximately negative USD 20 per ton. In Europe, where natural-gas prices are much higher than USD 4 per MMBtu, the value of the steam alone can reduce cost by about 80%. Facilities with on-site steam demand should therefore evaluate technologies such as Mantel because they can offset costs or generate additional revenue. The second example is the emerging business model for storing biogenic CO2. As long as regulations consider biomass carbon-neutral, any CCS applied to biogenic CO2 will qualify as a carbon-negative technology and can be sold into the voluntary carbon-credit market. Compliance markets such as those in the EU and Japan are also showing interest in this approach. Here, we are looking at a waste-to-energy facility and assuming feedstock with 40% to 60% bio-based content. Even for a one-megaton-per-year facility with carbon-capture costs of about USD 200 per ton, current carbon-credit prices can still generate substantial positive revenue. Over the last two years, credits from biogenic CO2 storage have sold for between USD 350 and USD 750 per ton. The average shown here is closer to USD 400, but the range illustrates what the market has been willing to pay. Credit prices are unlikely to remain at USD 700 per ton into the 2030s. However, a project developer generating these credits can adopt dynamic pricing based on actual carbon-capture costs and anticipated project margins. Ethanol, biogas, and waste-to-energy will be major growth markets for CCS, and carbon-capture technologies tailored to these markets will also see strong adoption. To conclude, within capture, transport, and storage, carbon capture is the main component from which cost reductions will come. Demand from data centers and new business models, such as the two examples we just discussed, is driving innovation and creating more application-specific solutions. For natural gas, if oxygen-based degradation is a problem, companies can develop material innovations to address it. For projects that must be operational before 2030 or in the early 2030s, we strongly recommend exploring process intensification and system-level benefits. Reductions in amine energy use, combined with system innovation, could eliminate the need for a significant share of the new material innovations currently in the market. Companies should capitalize on existing market credibility or established positions within the CCS value chain to maximize the potential of solvents. Finally, this is highly application- and industry-specific, so connect the dots among systems, materials, regulations such as 45Q, carbon contracts for difference in Europe, and any technology-specific byproducts. These are all levers that can be assessed to determine where the greatest cost reduction is possible. For example, if an amine technology can be combined with the sale of carbon credits at USD 700 per ton and there is a buyer for those credits, there may be no need to evaluate very early-stage technologies. As we saw, byproducts do not directly reduce the cost of carbon capture; they provide an additional revenue stream that lowers the overall levelized cost of capture. To the extent possible, connect the dots and evaluate these different levers. With that, thank you for your time. I see a few questions already, and I’m happy to take questions from the audience.

Runeel Daliah: Absolutely. Thank you very much, Mukunda. As Mukunda said, we will now take your questions, which you can type in the question box. Some of you have already found it, because several questions have come in. I’ll take a look through them. Mukunda, perhaps we can begin with the regional drivers. You showed the European map earlier and compared electrification with CCS. From a global perspective—North America, Europe, Asia, Australia, and so on—what would you say the drivers are? Are they the same in every region, or do they differ depending on where you are in the world?

Mukunda Kaushik: The biggest challenge for carbon capture will be moving from a heavily subsidized industry to one around which you can actually build a business. Even at scale, if profitability is inherently dependent on regulation, it is not a self-sustaining industry. The regulations we see as most impactful within specific regions are those that address bottlenecks in transport and storage. Of course, incentives such as 45Q drive project development in the U.S.; that is stating the obvious. In Europe, however, companies are asking whether it is cheaper to store CO2 on the EU side of the North Sea or in the U.K. Sometimes the U.K. is cheaper because it has carbon contracts for difference. These types of regulations drive project development. In Asia, we see much more focus on cross-border transport. About 50% of the projects under development involve collaboration between two countries. I have been emphasizing this point for almost two years. Europe is also considering cross-border transport, and projects such as Northern Lights will transport CO2 from different countries to Norway. In Asia, however, CO2 may be transported from Japan to Malaysia or from Japan to Australia. The scale is much larger, so the driver is different and has a greater impact on cost reduction.

Runeel Daliah: We received a question about a statement you made in your presentation. You discussed carbon credits and mentioned prices in the range of USD 300 to USD 700 per ton of CO2, which is very high. Is there demand or a market for these carbon credits? The cheaper they are, the larger the market, but that is quite a high price.

Mukunda Kaushik: The concept of credits from biogenic CO2 storage, or biomass-based storage, has existed for only the last 16 to 20 months. It is still a relatively new model, and companies are figuring out what works. Prices of USD 700 per ton will not last long because even offsetting technologies such as direct air capture average about USD 700 to USD 800 today. The higher prices are primarily intended to get projects started or to trial a different carbon-capture technology. Overall, however, the price of any credit sold from biogenic CO2 will be tied to the cost of carbon capture, not simply to what Microsoft is willing to pay for it.

Runeel Daliah: All right. We also have several technology questions, so I’ll combine them. You talked extensively about amine solvents, which are among the more commercial carbon-capture technologies. What about technologies such as cryogenic capture, oxy-fuel combustion, or PSA? What do you think about these newer forms of carbon capture?

Mukunda Kaushik: The reason we did not show them here is that each technology has a completely different CAPEX and cost structure, so each must be compared separately with amines. We see pressure-swing and vacuum-based desorption technologies as well. These approaches can help carbon-capture units operate at lower temperatures and consume much less energy. They are system innovations, but the key metric they target is still material performance. The relevant question is which materials are compatible, because that compatibility affects energy consumption. Some of these technologies have potential, but others will still not be competitive with amines. Lux is quite skeptical about oxy-fuel combustion. The only company that is very active and provides a strong benchmark is NET Power. Earlier this year, it announced a pause or delay in its project because of a significant cost overrun. We therefore do not expect oxy-fuel technology to be commercial in the near term or to play a major role in low-carbon power.

Runeel Daliah: Thank you. A few more questions have come in, but I’m also mindful of the time. I’ll ask one final question, Mukunda. Much of the innovation in this space is driven by startups. Do you have any comments on the venture-capital ecosystem for carbon capture? These startups are raising—or have already raised—substantial amounts of money, yet some have not shown much for it. Is the VC ecosystem as active as it was in the past, or how do you see it evolving?

Mukunda Kaushik: Across many technologies, it is no surprise that venture-capital activity has been sparse since the climate-tech bubble burst. Carbon capture is no exception. When we speak with startups at Lux, they say it is relatively easy to obtain seed funding from innovation funds and similar sources. However, funders have explicitly said that they do not want to be in a position where companies are raising Series A or Series B rounds in 2026, because funding is sparse and difficult to secure. That makes sense for all the reasons we discussed today: Companies do not want to bet on relatively unproven technology unless it offers a very significant cost benefit or a clear path to scalability. I do not expect to see many EUR 20 million to EUR 30 million funding rounds for point-source carbon capture in the near term. However, companies such as Mantel are among the few that have continued to attract oil and gas investors.

Runeel Daliah: All right. That concludes our webinar for today. For those of you in the audience, the slide presentation and recording will be emailed to you today. Afterward, you will be asked to complete a survey about this webinar. We would greatly appreciate your feedback, as it helps us improve future webinars. For now, thank you very much for joining us, and have a good rest of the day. Thank you.