CCUS: What will it take to scale up?

CCUS (Carbon Capture, Utilisation and Storage) technologies have long been a subject of controversy. Yet the ground is shifting. In 2025, the world crossed a significant threshold: commercial-scale carbon capture began operating in hard-to-abate industrial sectors for the first time, with the commissioning of Heidelberg Materials' Brevik cement plant in Norway. Investment in CCUS has grown more than fifteenfold since 2020, exceeding USD 5 billion in 2025, and over 30 projects reached final investment decision in the past two years alone. Europe, in particular, is emerging as the global engine of deployment.

In this article, we examine the most promising technologies across the CCUS value chain, from point-source capture and carbon removal to CO₂ transport and geological storage, and assess their realistic role in climate change mitigation. We also explore how certain processes may find applications beyond mitigation alone, generating economic value through CO₂ utilisation pathways such as synthetic fuels, construction materials and low-carbon chemicals, a dimension that could prove decisive in establishing the long-term commercial viability of the sector.

Carbon capture processes involve separating and removing CO₂ from a mixed gas stream. The source of that stream defines two broad categories: point-source capture, which targets flue gases emitted by industrial facilities such as power plants or cement kilns, and direct air capture (DAC), which extracts CO₂ directly from the atmosphere. This distinction has major implications for cost and energy intensity: CO₂ concentrations in industrial flue gases typically range from 5% to 15% by volume, compared to just 0.042% in ambient air, making point-source capture significantly cheaper and less energy-demanding than DAC. Long regarded as an immature and peripheral technology, carbon capture is now experiencing rapid development. As global greenhouse gas emissions are still increasing, a growing consensus holds that carbon dioxide removal (CDR) technologies are becoming a necessary complement to emissions reduction efforts, both to achieve climate neutrality by 2050 and, ultimately, to draw down accumulated atmospheric CO₂. The IPCC’s Sixth Assessment Report identifies CCS as one of several key mitigation levers and puts its 2030 potential at about 0.5 Gt CO₂eq per year in the energy sector, 0.3 Gt for BECCS and 0.15 Gt for industrial CCUS, at costs of USD 50–200 per tonne, among the highest of the options assessed. These estimates rest on few sources for the energy sector (±50%), are not necessarily additive, and reflect what could be achieved at that cost rather than a deployment forecast 0.5 Gt¹. Enerdata’s own estimates for total CO₂ capture globally by 2050 vary according to the scenarios (1 Mt for EnerBase, 1,366 Mt with EnerBlue and 2,500 Mt with EnerGreen). While those levels represent only a few percents of current global emissions (~38.4 Gt CO₂ per year), CCS is considered essential for decarbonising hard-to-abate sectors such as cement, steel and chemicals where process emissions cannot be eliminated through electrification alone. Capture is cheapest for high-purity streams (around USD 15–25/tCO₂ for processes such as natural gas processing or bioethanol production) and rises to roughly USD 40–120/tCO₂ for dilute flue gases from cement plants and power generation². Direct air capture remains substantially more expensive, with recent cost estimates of up to USD 340/tCO₂ for liquid-solvent DAC and up to USD 540/tCO₂ for solid-sorbent DAC, although these costs are expected to fall significantly as the sector scales up³.

Regarding carbon capture at point source emissions, four main strategies can be adopted (Fig. 1):

• Post-combustion capture is the most widely deployed approach: CO₂ is separated from the flue gases produced after the combustion of a carbon-containing fuel, whether fossil or biomass-based, the latter giving rise to the BECCS (Bioenergy with Carbon Capture and Storage) concept. Because it operates downstream of the combustion process, post-combustion capture can be retrofitted onto existing installations, making it particularly attractive for near-term industrial deployment.
• Pre-combustion capture takes the opposite approach, removing carbon from the fuel before it is burned: the fuel is first processed through a gasifier to produce a syngas rich in H₂ and CO_2, the CO₂ is then separated and stored, and the remaining hydrogen is combusted as a clean fuel. 
• Oxy-combustion eliminates the dilution problem altogether by burning the fuel in pure oxygen rather than atmospheric air, thereby avoiding the ~78% nitrogen content of air in the flue gas stream; the resulting exhaust consists almost entirely of CO₂ and water vapour, from which CO₂ can be separated at relatively low cost and energy penalty.
• Inherent capture is a category that encompasses industrial processes which, by their very nature, produce a concentrated or near-pure CO₂ stream as part of their process chemistry, such as ammonia synthesis, natural gas processing, or bioethanol fermentation, and therefore require little more than compression and drying rather than full chemical separation, resulting in the lowest capture costs across the value chain.

Figure 1: Main carbon capture strategies for point source emissions

Chemical absorption (Fig. 2) captures CO₂ by reacting to flue gas with an amine-based solvent that is then heated in a separate unit to release a concentrated CO₂ stream and regenerate the solvent in a continuous loop. This is a mature technology whose main drawback is the high thermal energy cost of regeneration.

Once captured and compressed, CO₂ must be transported from the capture site to a utilisation facility or a geological storage site. This step involves several technical considerations relating to the physical state of CO₂, the transport mode, and the quality specifications of the CO₂ stream.

CO₂ can be transported in four physical states: gaseous, liquid, dense/supercritical, and solid, though the latter is not relevant for large-scale transport. For pipeline transport, CO₂ is preferably maintained in dense phase (above its critical pressure of 73.8 bar and critical temperature of 31.1°C), which combines the high density of a liquid with the low viscosity of a gas, maximising throughput efficiency and avoiding two-phase flow issues that could damage pipeline infrastructure. For shipping, CO₂ is transported in liquid form at medium pressure (around 15 bar) and low temperature (around -30°C), similar to the conditions used in the established food-grade CO₂ shipping industry⁴. Compression and conditioning typically add USD 11–28/tCO₂ to the overall chain cost and must be carefully managed to meet pipeline and storage site specifications⁵.

A critical and often underestimated technical challenge is the purity of the CO₂ stream entering the transport system. Captured CO₂ inevitably contains impurities (mainly water, nitrogen, oxygen, hydrogen sulphide, SOx and NOx) whose presence affects pipeline integrity, compression requirements, storage reservoir behaviour and long-term monitoring. The acceptable levels of these impurities vary depending on the capture technology used, the transport mode and the storage formation, and no universally agreed international standard currently exists⁵. This lack of harmonised CO₂ quality specifications is considered one of the key technical barriers to the development of open-access, multi-user CO₂ transport networks in Europe, where streams from different industrial sources with varying compositions may need to be commingled.

Pipelines are the most mature CO₂ transport technology (TRL 10), with over 9,500 km of CO₂ pipelines currently in operation globally (primarily in the United States, where they have been used since the 1970s to transport CO₂ for enhanced oil recovery⁴). CO₂ pipelines share many design features with natural gas pipelines but require specific materials and coatings to withstand the corrosive effects of CO₂ in the presence of water, as well as careful management of pressure and temperature to maintain dense-phase conditions throughout the line⁶. 

In Europe, dedicated CO₂ pipeline networks are still at an early stage: the Fluxys C-grid in the Port of Antwerp area, which began construction in May 2025, is one of the first open-access CO₂ pipeline systems on the continent⁷. Several large cross-border pipeline projects are in planning, including a proposed 1,000 km CO₂ Highway Europe connecting industrial clusters in Germany, Belgium and the Netherlands to Norwegian North Sea storage sites⁸.

CO₂ shipping is emerging as a particularly relevant transport solution for Europe, given the geographical distance between many industrial emitters (notably in Southern and Eastern Europe) and the main offshore storage sites in the North Sea. The Northern Lights project in Norway is the world's first commercial-scale CO₂ shipping operation, using three dedicated vessels of 7,500 m³ capacity each to transport liquefied CO₂ from capture sites to an onshore receiving terminal before injection offshore. However, the current fleet of CO₂ vessels is small and largely derived from the food industry, operating at medium pressure (15 bar). The next generation of purpose-built large-scale CO₂ carriers, with capacities of 40,000 to 70,000 m³ operating at lower pressure (around 7 bar), is currently at prototype stage (TRL 6–7) and will be essential to achieving the economies of scale required for intercontinental or long-distance European transport⁴. A dedicated report on CO₂ shipping concluded that CO₂ shipping is poised for rapid growth as more projects opt for maritime transport over pipelines⁹.

While CO₂ utilisation pathways are gaining interest, geological storage is expected to dominate at scale in the future. It is worth noting that today's reality differs sharply from the long-term target: roughly 73% of currently operating capture capacity is still linked to enhanced oil recovery (EOR) or industrial uses rather than dedicated permanent storage⁴. This structural shift from utilisation and EOR towards dedicated permanent storage is one of the defining transitions underway in the sector.

Several significant challenges remain on the storage front. Long lead times for site assessment (typically 3 to 10 years, involving subsurface modelling, seismic surveys, test drilling and regulatory approvals) mean that storage development must begin well ahead of capture project planning. The long-term liability for stored CO₂, covering potential leakage, induced seismicity and post-closure monitoring obligations that can extend over decades, raises complex questions about risk allocation between operators, governments and society that remain largely unresolved in most jurisdictions. Under the EU's CCS Directive, operators must demonstrate that stored CO₂ is fully contained before liability transfers to national authorities after a minimum 20-year post-closure period, a requirement that introduces significant uncertainty for project developers. Finally, public acceptance of storage infrastructure has proven to be a tangible obstacle in several European countries, most notably in the Netherlands where Shell's Barendrecht project was cancelled in 2010 following sustained local opposition, underlining the importance of early and transparent community engagement in any storage development process.

The economics of CCS vary considerably across each step of the value chain, from capture through transport to geological storage¹⁰. 

Capture consistently represents the largest share of total CCS chain costs and is primarily driven by the concentration of CO₂ in the gas stream being treated. For industrial processes generating high-purity CO₂ streams (such as ammonia production, natural gas processing or bioethanol fermentation), capture typically costs USD 11–34/t CO₂, requiring only compression and drying rather than full separation⁵. For medium-concentration streams (cement kilns, steel blast furnaces, refineries and waste-to-energy plants), where CO₂ typically represents 5–15% of flue gas, costs rise to USD 28–140/t CO₂. Cement is at the upper end of this range⁴, with CCS increasing levelised production costs by 60–130%, while steel plants see cost increases of around 10–20%.

The choice of capture technology also influences costs. Chemical absorption with amine solvents, the most mature approach, remains cost-competitive but carries a significant energy penalty for solvent regeneration. Solid sorbent adsorption is emerging as a cheaper and less energy-intensive alternative for modular applications, while membrane separation promises lower energy use but currently faces higher capital costs at industrial scale⁶.

For carbon dioxide removal technologies, costs are significantly higher. BECCS ranges from USD 45–85/t CO₂ depending on the sector of application. Direct Air Capture (DAC) is currently priced at USD 110–900/t CO₂ and is considered unlikely to fall below USD 340/t CO₂ even at gigaton scale⁵, although it is a very debated point and some believe that costs can go below USD 150/t CO₂¹¹. Looking ahead, cost reductions of 20–40% are anticipated across most industrial capture applications by 2035 as technology matures and supply chains develop.

CO₂ transport costs depend heavily on distance, volume, transport mode and degree of infrastructure sharing. Compression and conditioning prior to transport add a further USD 11–28/t CO₂ regardless of mode⁵.

For pipeline transport, economies of scale are dramatic⁴: costs range from USD 9–11/t CO₂ for a small 3 Mt/year line down to USD 2–3/t CO₂ for a large 30 Mt/year network over 250 km. In Europe, CATF's geospatial cost modelling shows that, with only the announced (mostly offshore) storage sites and without pipeline access, transport and storage costs for cement and lime plants range from USD 38 to 240/t CO₂ (median USD 120/t CO₂). When pipeline access is enabled, 79% of plants achieve combined transport and storage costs below about USD 110/t CO₂; if storage is also developed more widely, including onshore, 90% of plants fall below about USD 70/t CO₂ (median USD 43/t CO₂)¹².

For CO₂ shipping, current cost estimates range from USD 17–45/t CO₂ for dedicated vessel connections, with significant reduction potential as fleet sizes grow¹³.

Overall, European transport costs are projected to fall by around 18% by 2030 and 37% by 2050 as infrastructure expands³. Transport thus weighs much less than capture for most emitters, but can rival it for sites located far from storage, and it is a more readily actionable lever: shared pipelines and more geographically distributed storage sites would reduce transport distances and open CCS to a broader range of industrial emitters.

Storage costs are the most variable component of the CCS chain, driven primarily by geological conditions. A recent modelling study by the Global CCS Institute identifies boundary conditions as the single most decisive cost driver: closed-boundary systems (where pressure cannot dissipate into surrounding formations) can cost up to four times more than open-boundary equivalents¹⁴.

For onshore saline aquifer storage, costs range from USD 2–15/t CO₂ under favourable conditions to USD 10–58/t CO₂ under the most challenging geological settings but rarely exceed USD 60/t CO₂ even in worst-case onshore scenarios. Offshore storage carries a higher base cost due to additional infrastructure complexity, ranging from USD 5–31/t CO₂ with open boundary conditions, but up to USD 147/t CO₂ in constrained settings (closed boundaries, poor-quality reservoirs). Notably, offshore projects with open boundary conditions can achieve costs comparable to onshore sites and remain the preferred option across much of Europe given geological availability and social acceptance⁵.

When capture, conditioning, transport and storage costs are aggregated, end-to-end CCS costs currently range from around USD 25–60/t CO₂ for the lowest-cost applications (high-purity streams with onshore storage) to USD 120–200/t CO₂ or more for harder industrial sources with offshore transport and storage^4,9. A presentation to the European Parliament estimated the average end-to-end cost for EU industrial CCS at between USD 170–340/t CO₂.

These figures are telling when set against the current EU ETS carbon price, which averaged around USD 90–96/t CO₂ (EUR 80–85/t) during the first semester of 2026, well below the full cost of CCS for most industrial applications. This gap explains why most operational CCS projects today still rely on blended public funding, Carbon Contracts for Difference (CCfD) or long-term offtake agreements to bridge the commercial viability gap, and why policy support remains indispensable to scaling the sector in the near term.

Beyond storage, the long-term value of carbon capture may also lie in treating CO₂ as a feedstock rather than a waste stream. The most mature route is synthetic chemistry: combined with low-carbon hydrogen, captured CO₂ can be converted into platform molecules such as methanol (whose downstream derivatives include formaldehyde, olefins, and synthetic fuels) as well as ethylene, formic acid, and polycarbonates, through thermocatalytic or, increasingly, electrochemical pathways¹⁶. Altogether, e-fuels and chemicals are expected to represent the vast majority of CO₂ use, although other applications, such as building materials or precision fermentation represent further opportunities. LanzaTech, for instance, already sells protein derived from industrial gases and has set a roadmap toward commercial-scale CO₂-to-protein production by 2028. Crucially, the economics of these applications improve markedly when CO₂ is valorised in short loops close to the point of capture: co-locating conversion units with high-purity emitters such as ammonia or ethanol plants cuts transport, compression, and purification costs, and integrated coproduction systems have been shown to lower both emissions and the effective cost of the captured¹⁸.

The European Union has moved decisively from voluntary ambition to binding legislative targets for CCS, marking a significant shift in the policy landscape. The Net-Zero Industry Act (NZIA), adopted in May 2024, is the cornerstone of this new framework. It sets a binding EU-wide target of 50 MtCO₂/year of injection capacity by 2030, to be developed within storage sites located in the EU⁵. Crucially, the NZIA also places a mandatory obligation on 44 European oil and gas producers to collectively contribute to this target, calculated pro-rata based on each company's share of EU crude oil and natural gas production between 2020 and 2023 ⁷.

Looking beyond 2030, the EU's Industrial Carbon Management Strategy (February 2024) sets more ambitious long-term targets: approximately 280 MtCO₂/year by 2040 and 450 MtCO₂/year by 2050 across the European Economic Area (the latter representing around 13% of the EU's 2022 total emissions). These figures are consistent with the JRC's POTEnCIA model projections of approximately 400 MtCO₂/year of annual capture within the EU alone by 2050.

The Clean Industrial Deal (February 2025) further reinforced this direction by positioning industrial decarbonisation, as a central pillar of European industrial competitiveness and announced the creation of an Industrial Decarbonisation Bank planned for 2026 to help finance the transition⁷. The legal basis for CO₂ storage remains the 2009 CCS Directive (2009/31/EC), complemented in May 2025 by a Delegated Regulation and a Decision under the NZIA setting out each oil and gas producer's contribution to the 2030 injection target¹⁹. In October 2025, the European Commission also launched a public consultation on new legislation for CO₂ markets and infrastructure, signalling further regulatory developments to come.

Over the long-term, when the European economy reaches net zero, the total CO₂ capture requirement is broadly estimated at 300–500 Mt/year, with the European Commission's own modelling pointing to approximately 450 Mt/year²⁰. This breaks down across three main source categories: biogenic sources (BECCS) could realistically contribute 80–105 Mt/year, by equipping 38–50% of biomass CHP, power and heat plants, pulp & paper mills and waste-to-energy facilities (technical potential of about 220 Mt/year²¹), though sustainable biomass constraints cap the realistic ceiling well below the theoretical ~480 Mt/year potential. Hard-to-abate industrial sectors would represent the core of CCS activity, with cement alone averaging ~65 Mt/year (where CCS is essentially the only viable solution for process emissions), iron & steel ~50 Mt/year, and chemicals ~32 Mt/year (totalling roughly 143–280 Mt/year depending on the degree of competing decarbonisation pathways such as hydrogen-based steelmaking and electrification)²².

The remainder, needed to bridge the gap to the 450 Mt/year target, would come from other point sources and carbon dioxide removal (CDR) technologies, including waste-to-energy plants (up to 75 Mt/year), fossil-fuelled power with CCS (~30–55 Mt/year during the transition)²³, and Direct Air Carbon Capture & Storage (DACCS), which could contribute up to 150–200 Mt/year in high-ambition scenarios²⁴, albeit at significantly higher cost.  Taken together, the assessment suggests that meeting net-zero targets in Europe would be difficult without significant CCS deployment. In this view, hard-to-abate industries would account for much of the capture activity, biogenic sources could contribute negative emissions, and DACCS might help address residual emissions where other options are limited or unavailable.

Beyond the EU-level framework, several Member States and associated countries have set their own national CCS targets and strategies:

• Norway anchors European storage rather than capture. The state covered roughly two thirds of the Longship/Northern Lights cost (about USD 2 billion), and Northern Lights began injecting in August 2025, the world's first open-access cross-border CO₂ store. Phase 2, sanctioned in March 2025, lifts capacity to at least 5 MtCO₂/year from 2028. Norway has set no national capture target.
• The United Kingdom runs Europe's most complete national programme: 20–30 MtCO₂/year of capture by 2030 and over 50 Mt/year by 2035, backed by GBP 21.7 billion (about USD 29 billion) over 25 years for its two Track-1 clusters. Both reached financial close (East Coast Cluster in December 2024, HyNet's Liverpool Bay in April 2025). Its Carbon Contracts for Difference and its Regulated Asset Base model for transport and storage are now the reference templates in Europe.
• The Netherlands was the earliest EU mover, funding CCS through the SDE++ scheme (over USD 10 billion committed, USD 2.4 billion of it to Porthos) rather than through a headline target, with supported volumes initially capped at 7.2 MtCO₂/year to 2030 under its Climate Agreement. Porthos is under construction and Aramis in advanced development, together up to 24.5 MtCO₂/year.
• Denmark has committed DKK 28.7 billion (about USD 4.3 billion) in a single CCS tender requiring capture plants to be commissioned by end-2029 and 2.3 MtCO₂/year captured and stored from 2030, on top of an earlier contract with Ørsted for 0.43 Mt/year. Greensand, in the Danish North Sea, is due to become the first operational CO₂ store in the EU. Denmark has also signed cross-border CO₂ transport agreements with Norway, Sweden, France and Belgium.
• Germany, Europe's largest industrial emitter, lifted its de facto ban only in November 2025, when the Carbon Dioxide Storage and Transport Act (KSpTG) replaced the 2012 statute that had confined CCS to demonstration projects. It permits commercial offshore storage, creates a first unified permitting regime for CO₂ pipelines, and, with the London Protocol amendment ratified in January 2026, opens the way to CO₂ export. Given a congested exclusive economic zone, export to Norway and Denmark is the near-term route. No capture target has been set.
• France published a national CCUS strategy in 2023 targeting 4–8 MtCO₂/year captured by 2030 and 15–20 Mt/year by 2050, concentrated on two to four industrial-port hubs (Dunkirk, Le Havre, Fos-sur-Mer, Saint-Nazaire, the Rhône corridor). Support runs through tendered Carbon Contracts for Difference and the France 2030 low-carbon industrial zones programme. With no domestic storage expected before the 2030s, French emitters depend on North Sea capacity, which makes cross-border access the binding constraint.

Europe's CCUS industry has crossed a decisive threshold in 2025, moving from pilot-scale demonstration to commercial-scale deployment for the first time. In its 2026 Global Status report, the Global CCS Institute counts 15 operational CCS facilities in Europe and 21 under construction, with a development pipeline of 141 MtCO₂/year²⁵; operating capture capacity, still below 3 Mt/year in mid-2025, is expected to exceed 90 Mt/year by 2030 if the current project pipeline materialises²⁶. 

The most significant milestone of 2025 was the commissioning of Heidelberg Materials' Brevik CCS plant in Norway, the world's first commercial-scale carbon capture facility at a cement plant, capturing 0.4 Mt CO₂/year and permanently storing it via the Northern Lights infrastructure in the Aurora saline aquifer beneath the Norwegian North Sea⁵.

Other major projects now operational or in advanced construction in Europe include:

• Northern Lights Phase 1 (Norway), the world's first open-access, cross-border CO₂ transport and storage facility, operational since 2025 with 1.5 MtCO₂/year of storage capacity, developed by Equinor, Shell and TotalEnergies with strong Norwegian government backing.
• Ravenna CCS Phase 1 (Italy), Eni's natural gas treatment plant capturing 25,000 tCO₂/year in its initial phase, with expansion to 4 MtCO₂/year by 2027 planned via the Ravenna hub in the Adriatic Sea. 
• Porthos (Netherlands), the Port of Rotterdam CO₂ Transport Hub and Offshore Storage project, currently under construction and targeting 2.5 MtCO₂/year stored in depleted North Sea gas fields.
• Twence CCU (Netherlands): a capture plant at a waste-to-energy facility where captured CO₂ is supplied directly to the neighbouring greenhouse industry, representing one of Europe's first operational carbon utilisation projects at industrial scale.

Beyond these operational projects, ten projects reached Final Investment Decision in Europe between December 2024 and October 2025 alone, representing approximately 4 MtCO₂/year of new capture capacity and 14 Mt CO₂/year of new storage capacity⁷. 

Despite the EU's ambitious framework, progress against the 2030 target remains significantly behind schedule. An analysis of 33 planned CO₂ storage sites across the European Economic Area and the UK estimates mid-range injection capacity of only around 60 MtCO₂/year by 2030, technically above the 50 Mt target, but highly dependent on projects currently in early development stages actually reaching FID and commissioning on time⁷. A study has estimated that existing and planned CCS projects in the EU and Norway are on track to deliver only around 10 MtCO₂/year of storage capacity by the early 2030s, far below the NZIA target. Enerdata’s own estimates are that the EU will fall short of its 2030 targets, with no material volumes of CO₂ captured by 2030 in all scenarios, although volumes grow from 2031 to 2050. In detail, the EnerBase scenario (conservative) sees total CO₂ captured remain insignificant (below 1 Mt/year) up to 2050, while EnerBlue (implementation of current policies) sees volumes reach 35 Mt by 2040 and 139 Mt by mid-century. In EnerGreen, the most ambitious scenario, capture rates reach 46 MtCO₂ by 2040 and even 254 Mt by 2050. 

No longer a long-term aspiration, CCUS has become a reality that materializes into tens of projects across Europe, covering all steps of the value chain, from capture to storage. If it remains true that electrification of various sectors (land transport, buildings heating and cooling, low-temperature industrial heat) using renewable electricity is by far the most cost-effective way to lower emissions, carbon capture could be interesting as a complement, mostly to decarbonise hard-to-abate industries (such as cement and steel) and to generate negative emissions (through BECCS). These hard-to-abate industries (steel, cement and chemicals) account for around 18% of energy-system CO₂ emissions²⁸, but CCUS is no silver bullet: in the IEA’s Net Zero Emissions scenario, it delivers only about 8% of cumulative emission reductions to 2050, far behind renewables, energy efficiency and electrification²⁹. Decarbonisation will primarily come from reducing fossil fuel consumption, including through changes in consumption patterns, rather than from keeping fossil-fuelled plants running, or building new ones, on the promise that an emerging technology will curb their emissions. Beyond the mitigation of carbon dioxide emissions, the CCUS value chain may also grow in importance to the wider economy, as it could replace fossil fuels as a source of carbon for industries such as chemistry and liquid fuels (notably e-fuels), for which carbon is non-substitutable.

These prospects, however, should not obscure a critical condition: the technology still has to prove its economic competitiveness if CCUS is to become a durable pillar of decarbonisation rather than a passing trend. Several challenges remain before deployment ceases to be a financial burden. The capture technologies themselves need to become less energy-intensive. Robust value chains, including short loops between capture and use, have to be built to limit transport and conditioning costs. The regulatory framework requires further development to provide investors with clear and stable conditions. And substantial investment, public funding in particular, will be needed to bridge the gap until the technology reaches maturity. How these conditions are met will largely determine whether CCUS fulfills the role that current scenarios assign to it.

Notes: 

1. IPCC, Climate Change 2022: Mitigation of Climate Change, Working Group III, Chapter 12 (Table 12.3) and Supplementary Material 12.SM.1.2, 2022
2. IEA, Is carbon capture too expensive?, 2021
3. IEA, Direct Air Capture, 2024
4. IEA, CCUS Policies and Business Models, 2023
5. JRC, Clean Energy Technology Observatory: Carbon Capture, Utilisation and Storage in the European Union - 2025 Status Report on Technology Development, Trends, Value Chains and Markets, 2025
6. Global CCS Institute, ADVANCEMENTS IN CCS TECHNOLOGIES AND COSTS, 2025
7. CATF, Carbon capture and storage in Europe: Slow but significant progress in 2025, 2025
8. IOGP, CO₂ storage projects in Europe, 2025
9. GCCSI, Needs, Opportunities and Prospects For CO₂ Shipping in CCS Projects, 2025 
10. Amounts originally expressed in euros are converted into US dollars at the 2025 average ECB euro reference rate (EUR 1 = USD 1.13; GBP and DKK amounts at the corresponding 2025 average cross rates) and rounded to two significant figures, without adjustment for the price year of the original sources.
11. World Economic Forum, Achieving net zero: Why costs of direct air capture need to drop for large-scale adoption, 2023
12. CATF, Key insights on EU CO₂ transport and storage costs from CATF's new interactive tool, November 2025
13. Global CCS Institute, NEEDS, OPPORTUNITIES AND PROSPECTS FOR CO₂ SHIPPING IN CCS PROJECTS, 2025
14. Global CCS Institute, Cost of CO₂ Storage, December 2025
15. Agora Industrie & Öko-Institut Consult GmbH, Carbon Capture and Storage (CCS) in der Energiewende zur Klimaneutralität — Der infrastrukturelle und regulatorische Rahmen für CO₂-Transport und -Speicherung, 2026
16. Chem & Bio Engineering, Green Methanol from CO₂ Hydrogenation at Industrial Scale: Progress, Challenges, and Perspectives, 2025
17. Trends in Biotechnology, Food production from air: gas precision fermentation with hydrogen-oxidising bacteria, 2026
18. Environmental Science & Technology, Technoeconomic and Life Cycle Analysis of Synthetic Methanol Production from Hydrogen and Industrial Byproduct CO₂, 2021
19. European Commission, Commission identifies the EU oil and gas producers to provide new CO₂ storage solutions for hard-to-abate emissions in Europe, 22 May 2025
20. EC, Industrial carbon management, 2025
21. BEST & Bioenergy Europe, BECCS: Bioenergy with carbon capture and storage, basics and opportunities, April 2025
22. JRC, The Role of Carbon Capture Across Hard-to-Abate Industries in the EU: A Review of Projections for 2030 and 2050, 2024
23. European Commission, 2040 climate target, 2026
24. CATF, Vision for CCUS in the EU, 2023
25. Global CCS Institute, Global Status of CCS 2026, October 2026
26. Global CCS Institute, Global Status of CCS 2025: Staying the Course (Executive Summary), October 2025
27. Enerdata, Global CCS Companies Database, January 2026 update
28. IEA, The challenge of reaching zero emissions in heavy industry, 2020
29. IEA, CCUS, Net Zero Roadmap: A Global Pathway to Keep the 1.5 °C Goal in Reach, 2023

Cyril Aselmeyer joined Enerdata in 2023 as a consultant in the Cleantech team. His work focuses on developing expertise in technologies including solar PV, wind power, hydrogen and its derivatives, ammonia, e-fuels, biofuels, batteries, electric mobility, carbon capture and storage, and electricity grids. He applies this expertise to client assignments and the development of commercial products, reports and training programmes.

During his first two years at Enerdata, Cyril worked on clean ammonia, solar PV, wind power, CCUS and hydropower.

Before joining Enerdata, Cyril began his career in academic research and completed a PhD on third-generation biofuels. He subsequently studied energy economics to broaden his expertise.

Cyril holds a PhD in biochemistry from Aix-Marseille University and an MSc in Energy Economics from Université Grenoble Alpes.