Carbon capture, utilization & storage (CCUS): the 20 most-asked questions, answered

Carbon capture, utilization, and storage (CCUS) has moved from a niche research topic to a central pillar of global decarbonization strategy. The International Energy Agency projects that CCUS must capture approximately 6 gigatonnes of CO2 annually by 2050 to align with net-zero pathways, yet operational capacity at the end of 2025 stood at roughly 50 million tonnes per year. This gap between ambition and deployment generates persistent confusion about costs, technology readiness, regulatory frameworks, and practical implementation. The following 20 questions reflect the issues most frequently raised by sustainability leads, investors, policymakers, and engineers navigating CCUS decisions in 2026.

Why It Matters

The EU's Industrial Carbon Management Strategy, published in February 2024, established a target of 50 million tonnes of annual CO2 storage capacity by 2030 and 280 million tonnes by 2040. These targets sit alongside the revised EU Emissions Trading System, which now includes an explicit role for CCUS in industrial decarbonization. In the United States, the Inflation Reduction Act's enhanced 45Q tax credit provides $85 per tonne for geological storage and $60 per tonne for utilization, creating the strongest financial incentive for CCUS in any major economy. Understanding the practical realities behind these policy frameworks is essential for organizations evaluating CCUS investments, partnerships, or compliance strategies.

The 20 Most-Asked Questions

1. What exactly is CCUS, and how does it differ from CCS?

CCUS encompasses three distinct processes: capturing CO2 from industrial sources or the atmosphere, transporting it to a destination, and either storing it permanently underground or utilizing it in products or processes. CCS (carbon capture and storage) refers specifically to permanent geological storage without a utilization pathway. The distinction matters because storage and utilization have fundamentally different economics, regulatory requirements, and climate outcomes. Permanent geological storage delivers verifiable, long-duration carbon removal. Utilization pathways vary enormously in their climate benefit depending on whether the CO2 is permanently sequestered in the end product (as in concrete mineralization) or re-released (as in synthetic fuels that are subsequently combusted).

2. What are the main capture technologies?

Three primary approaches dominate commercial deployment. Post-combustion capture uses chemical solvents (typically amine-based) to absorb CO2 from flue gases after fuel combustion, applicable to existing power plants and industrial facilities. Pre-combustion capture converts fuel to hydrogen and CO2 before combustion, separating the CO2 at higher concentrations and pressures. Oxy-fuel combustion burns fuel in pure oxygen rather than air, producing a flue gas with high CO2 concentration that simplifies separation. Emerging technologies include membrane separation, calcium looping, and electrochemical methods. Post-combustion capture accounts for roughly 75% of installed capacity globally because it can be retrofitted to existing infrastructure.

3. How much does carbon capture cost per tonne?

Costs vary dramatically by application. Capture from high-purity industrial sources (natural gas processing, ethanol production, ammonia manufacturing) ranges from EUR 15 to 30 per tonne because the CO2 stream is already concentrated. Capture from cement and steel plants costs EUR 50 to 100 per tonne due to lower CO2 concentrations and complex flue gas compositions. Power plant capture ranges from EUR 50 to 120 per tonne depending on plant type and capture rate. Direct air capture (DAC), which removes CO2 from ambient air at approximately 420 parts per million concentration, currently costs EUR 400 to 1,000 per tonne, though leading developers project costs below EUR 200 per tonne by 2035 at scale.

4. What is the energy penalty of carbon capture?

Carbon capture is energy-intensive. Post-combustion amine scrubbing typically consumes 15 to 30% of a power plant's energy output, reducing net electricity generation proportionally. This energy penalty translates directly to higher operating costs and, if the energy source is fossil fuel, additional upstream emissions. Next-generation solvents, solid sorbents, and membrane technologies aim to reduce the energy penalty to 10 to 15%. For industrial applications, waste heat integration can offset a substantial portion of the energy requirement. Climeworks' DAC facility in Iceland uses geothermal energy, avoiding fossil fuel energy penalties entirely.

5. Where can captured CO2 be stored?

Geological storage options include deep saline aquifers (the largest capacity globally, estimated at 1,000 to 10,000 gigatonnes), depleted oil and gas reservoirs (well-characterized geology with existing infrastructure), and unmineable coal seams. The North Sea basin alone offers an estimated 150 to 300 gigatonnes of storage capacity, making it a strategic asset for European CCUS deployment. Storage sites require detailed geological characterization, injection testing, and regulatory permitting. The EU CCS Directive (2009/31/EC) establishes the legal framework for CO2 storage permitting and long-term liability across EU member states. Norway's Northern Lights project, operational since 2024, provides the first cross-border CO2 transport and storage service in Europe.

6. Is geological CO2 storage safe and permanent?

Decades of geological research and operational experience indicate that properly selected and managed storage sites retain CO2 with extremely high confidence. The Sleipner project in Norway has stored over 20 million tonnes of CO2 since 1996 with no detected leakage. The IPCC estimates that well-selected sites will retain more than 99% of injected CO2 over 1,000 years. Monitoring technologies including seismic surveys, wellbore integrity testing, groundwater sampling, and surface monitoring provide continuous verification. The primary risks involve well integrity (particularly legacy wellbores from previous oil and gas operations), induced seismicity, and caprock integrity, all of which can be managed through proper site selection and monitoring protocols.

7. What is enhanced oil recovery (EOR), and should it count as carbon storage?

EOR injects CO2 into depleted oil reservoirs to increase oil production, with some CO2 remaining permanently trapped underground. Approximately 70% of current global CCUS capacity is associated with EOR. The climate accounting is contested: while each tonne of CO2 stored through EOR permanently removes CO2 from the atmosphere, the additional oil produced generates emissions when combusted. Life-cycle analyses show that CO2-EOR projects typically produce oil with a 30 to 60% lower carbon intensity than conventional extraction, but the net climate benefit depends entirely on whether the alternative is reduced oil consumption or continued conventional production. Under the EU Taxonomy, EOR-linked CCUS does not qualify as a sustainable activity.

8. What are the main utilization pathways for captured CO2?

CO2 utilization broadly divides into permanent and non-permanent pathways. Permanent utilization includes concrete and aggregate mineralization (CarbonCure, Solidia), where CO2 chemically bonds with calcium or magnesium minerals and remains stored for centuries. Non-permanent utilization includes synthetic fuels (e-fuels), chemicals (methanol, urea), carbonated beverages, and greenhouse agriculture. From a climate perspective, only permanent utilization delivers genuine carbon removal. Synthetic fuels release stored CO2 when burned, making their climate benefit dependent on displacing fossil fuels rather than achieving net removal. The EU Innovation Fund has allocated over EUR 3 billion to CCUS projects, with increasing emphasis on distinguishing permanent from temporary utilization.

9. How does CCUS fit into the EU regulatory landscape?

Several EU frameworks shape CCUS deployment. The EU ETS creates a carbon price signal (fluctuating between EUR 50 and 100 per tonne in 2024-2025) that improves CCUS economics for industrial emitters. The Carbon Border Adjustment Mechanism (CBAM) extends this price signal to imports, reducing competitive disadvantage for EU producers investing in capture technology. The Net-Zero Industry Act identifies CCUS as a strategic technology with streamlined permitting provisions. Member states must identify potential CO2 storage sites, and several (notably the Netherlands, Denmark, and Norway) have developed national CCUS strategies with financial support mechanisms.

10. What role does the US 45Q tax credit play?

The enhanced 45Q credit under the Inflation Reduction Act provides $85 per tonne for CO2 permanently stored geologically and $60 per tonne for CO2 used in enhanced oil recovery or utilization. For direct air capture, credits reach $180 per tonne for storage and $130 per tonne for utilization. These credits are available for 12 years from the project start date and, critically, are now transferable and available as direct pay for the first five years. This structure has catalyzed a pipeline of over 150 CCUS projects in the US as of early 2026, though permitting bottlenecks at the Environmental Protection Agency for Class VI injection wells remain a significant constraint.

11. What is the current global CCUS project pipeline?

As of early 2026, approximately 45 commercial-scale CCUS facilities operate worldwide, capturing roughly 50 million tonnes of CO2 annually. The project pipeline includes over 500 additional facilities in various stages of development, with a combined planned capture capacity exceeding 300 million tonnes per year. The United States leads in project count, followed by the United Kingdom, the Netherlands, Australia, and Canada. However, project attrition remains high: historically, fewer than 30% of announced CCUS projects have reached final investment decision, with cost overruns, permitting delays, and shifting policy landscapes as primary causes.

12. Which industries are the best candidates for CCUS?

Industries with high CO2 concentrations in their waste streams and limited alternative decarbonization pathways represent the strongest candidates. Natural gas processing and ethanol production offer the lowest capture costs because their waste streams contain 90%+ CO2 concentration. Cement manufacturing generates process emissions from limestone calcination that cannot be eliminated through fuel switching alone, making CCUS one of the only viable deep decarbonization pathways. Steel production (particularly blast furnace operations), refining, and petrochemicals similarly produce emissions that are difficult to abate through electrification or renewable energy alone. Collectively, these "hard-to-abate" sectors account for approximately 20% of global emissions.

13. How does direct air capture (DAC) differ from point-source capture?

DAC removes CO2 from ambient air at approximately 420 parts per million, while point-source capture targets flue gases with CO2 concentrations ranging from 4% (natural gas power plants) to 95%+ (ethanol fermentation). This concentration difference means DAC requires 100 to 300 times more air processing per tonne of CO2, driving substantially higher costs and energy requirements. DAC's advantage is location flexibility: facilities can be built near optimal storage sites or clean energy sources rather than being tied to industrial emitters. Climeworks (solid sorbent technology) and Carbon Engineering, now owned by Occidental Petroleum (liquid solvent technology), represent the two leading approaches. The US Department of Energy's four Regional DAC Hubs, funded at $3.5 billion, aim to accelerate commercialization.

14. What are the main transport options for captured CO2?

Pipelines represent the most cost-effective transport method for large volumes over distances up to 1,500 kilometers, costing approximately EUR 1 to 5 per tonne per 100 kilometers. Ships offer flexibility for cross-border transport, particularly in Europe where the Northern Lights project receives CO2 by ship from industrial emitters across multiple countries. Road and rail transport is viable for small volumes during early project phases. The EU is developing a cross-border CO2 transport infrastructure through the TEN-E regulation, designating CO2 network corridors as Projects of Common Interest eligible for streamlined permitting and financial support.

15. What are the financing models for CCUS projects?

CCUS projects typically require capital expenditures of EUR 500 million to 2 billion, demanding complex financing structures. Common models include: project finance with long-term CO2 offtake agreements, government grants and concessional loans (EU Innovation Fund, UK CCUS Cluster Sequencing), tax equity structures (US 45Q), carbon contracts for difference (Netherlands SDE++, UK Dispatchable Power Agreements), and corporate balance sheet financing by major emitters. The emerging trend is "CCUS-as-a-service" where specialized operators (Northern Lights, Santos CCS) offer transport and storage services to multiple industrial customers, reducing risk for individual emitters.

16. What monitoring and verification requirements apply to stored CO2?

EU regulations require comprehensive monitoring plans covering injection operations, storage complex integrity, and potential leakage pathways. Monitoring technologies include 4D seismic surveys (repeated over time to track the CO2 plume), downhole pressure and temperature monitoring, groundwater sampling, soil gas monitoring, and atmospheric monitoring. Operators must submit annual reports to competent authorities and maintain a corrective measures plan. After site closure, monitoring must continue for a minimum of 20 years before liability transfers to the member state. The Global CCS Institute's CO2RE database tracks monitoring results across operational projects, providing transparency on storage performance.

17. What are the biggest risks for CCUS project developers?

Policy risk ranks highest: CCUS projects with 20 to 30-year lifetimes require stable carbon pricing or equivalent support mechanisms, and political cycles introduce uncertainty. Geological risk includes unexpected storage behavior, induced seismicity, or containment issues, though this risk is manageable with proper characterization. Technology risk has decreased as capture technologies mature, but novel approaches (solid sorbents, membranes, electrochemical methods) retain scale-up uncertainty. Market risk affects utilization projects dependent on commodity prices for products like synthetic fuels or chemicals. Public acceptance risk, particularly for onshore storage and pipeline infrastructure, has derailed several European projects including the Barendrecht project in the Netherlands.

18. How does CCUS interact with hydrogen production?

"Blue hydrogen" couples steam methane reforming or autothermal reforming with carbon capture to produce low-carbon hydrogen from natural gas. Capture rates of 90 to 95% are now technically achievable, though many early projects operated at 50 to 60% capture efficiency. The EU Delegated Act on renewable hydrogen does not classify blue hydrogen as renewable, but several member states include it in national hydrogen strategies as a transitional technology. The economic competitiveness of blue versus green hydrogen depends on natural gas prices, carbon prices, and electrolyzer costs. At current EU gas prices and carbon prices, blue hydrogen production costs EUR 2 to 3 per kilogram, compared to EUR 4 to 7 per kilogram for green hydrogen, though the gap is narrowing.

19. Can CCUS deliver negative emissions?

CCUS achieves negative emissions in two configurations: bioenergy with carbon capture and storage (BECCS) and direct air capture with storage (DACS). BECCS captures CO2 released from burning or processing biomass that absorbed atmospheric CO2 during growth. The Drax power station in the United Kingdom is piloting BECCS at one of its biomass units. DACS directly removes atmospheric CO2 for permanent storage. Both pathways are included in IPCC scenarios limiting warming to 1.5 degrees Celsius, with modeled deployment ranging from 2 to 10 gigatonnes annually by 2050. Scaling to these levels requires addressing land-use constraints (for BECCS biomass supply), energy requirements, and costs that remain substantially higher than point-source capture.

20. What should sustainability leads prioritize regarding CCUS in 2026?

Immediate priorities include: mapping organizational emissions to identify streams amenable to capture (high-concentration, hard-to-abate sources first); monitoring CCUS policy developments in operating jurisdictions (particularly the EU ETS Innovation Fund and member state CCS strategies); evaluating emerging CCUS-as-a-service offerings that reduce capital requirements; incorporating CCUS into corporate transition plans where alternative decarbonization pathways are insufficient or prohibitively expensive; and engaging with sector-specific initiatives such as the Cement Sustainability Initiative or the Steel Climate Standard. Sustainability leads should treat CCUS as a complement to, not a substitute for, energy efficiency and renewable energy deployment.

Key Takeaways

CCUS technology is technically proven but commercially immature at the scale required for climate targets. Costs are falling but remain dependent on policy support mechanisms. The EU and US offer the strongest regulatory and financial frameworks for deployment. Hard-to-abate industrial sectors represent the highest-value applications in the near term. Organizations evaluating CCUS investments should focus on policy durability, realistic cost projections, and integration with broader decarbonization strategies rather than treating capture technology as a standalone solution.

Action Checklist

• Map all organizational CO2 emission sources by concentration level and volume to identify highest-value capture opportunities
• Assess proximity to geological storage sites or emerging CO2 transport infrastructure (North Sea corridors, US pipeline networks)
• Evaluate eligibility for CCUS financial support mechanisms including EU Innovation Fund, 45Q tax credits, and member state programs
• Engage with CCUS-as-a-service providers (Northern Lights, Storegga) to understand commercial terms and timelines
• Incorporate CCUS scenarios into corporate transition plans with realistic cost and timeline assumptions
• Monitor regulatory developments including EU CCS Directive revisions, CBAM implementation, and national storage permitting processes
• Conduct internal stakeholder education on CCUS technology readiness, costs, and role within portfolio decarbonization strategies
• Establish measurement, reporting, and verification frameworks aligned with ISO 27914 for CO2 storage and emerging regulatory requirements

Sources

• International Energy Agency. (2025). CCUS in Clean Energy Transitions: Global Status Report 2025. Paris: IEA Publications.
• European Commission. (2024). Industrial Carbon Management Strategy. Brussels: European Commission.
• Global CCS Institute. (2025). Global Status of CCS Report 2025. Melbourne: Global CCS Institute.
• Intergovernmental Panel on Climate Change. (2023). AR6 Synthesis Report: Climate Change 2023. Geneva: IPCC.
• Northern Lights JV. (2025). Annual Report 2024: Europe's First Cross-Border CO2 Transport and Storage Service. Stavanger: Northern Lights.
• US Department of Energy. (2025). Carbon Capture, Utilization, and Storage: Program Status and Outlook. Washington, DC: DOE Office of Fossil Energy and Carbon Management.
• BloombergNEF. (2025). Carbon Capture Market Outlook: Costs, Policy, and Project Pipeline Analysis. New York: Bloomberg LP.