Head-to-head: Carbon capture, utilization & storage (CCUS) — comparing leading approaches on cost, performance, and deployment

Carbon capture, utilization and storage encompasses at least five fundamentally different technological pathways, each with distinct cost profiles, maturity levels, and deployment constraints. Choosing the wrong approach for a given application can mean the difference between a project that reaches final investment decision and one that stalls indefinitely. This comparison examines the leading CCUS approaches side by side, grounding the analysis in verified project data rather than vendor projections.

Why It Matters

Global CCUS capacity must scale from approximately 50 million tonnes of CO2 captured annually in 2025 to over 1 billion tonnes by 2035 to remain consistent with net-zero pathways, according to the International Energy Agency's Net Zero Roadmap. The US Inflation Reduction Act's enhanced 45Q tax credit now provides $85 per tonne for geological storage and $60 per tonne for utilization, creating the strongest economic incentive for CCUS deployment in any jurisdiction globally. Canada's Investment Tax Credit for Carbon Capture, Utilization, and Storage offers refundable credits of up to 60% of eligible capital costs for direct air capture projects and 50% for other capture projects. The EU Innovation Fund has allocated over EUR 3 billion to large-scale CCUS demonstrations through 2030.

These policy tailwinds have produced a pipeline of over 300 announced CCUS projects in North America alone, yet fewer than 40 have reached final investment decision as of early 2026. The bottleneck is not capital availability but rather the complexity of matching capture technology to emission sources, securing transport and storage infrastructure, and structuring projects that can deliver returns within acceptable risk parameters. For founders and investors evaluating this space, understanding the comparative advantages and limitations of each approach is essential for identifying commercially viable opportunities.

The Five Leading Approaches

Post-Combustion Chemical Absorption

Post-combustion capture using amine-based solvents remains the most commercially mature approach, with over 30 years of operational history in the oil and gas sector. The technology works by passing flue gas through a liquid solvent (typically monoethanolamine or proprietary advanced amines) that selectively binds CO2. The CO2-rich solvent is then heated to release concentrated CO2 for compression and transport.

Cost structure: Capital expenditure ranges from $600 to $1,200 per tonne of annual capture capacity, depending on scale and flue gas CO2 concentration. Operating costs are dominated by the thermal energy required for solvent regeneration, typically consuming 2.5 to 4.0 GJ per tonne of CO2 captured. All-in costs for large-scale coal or gas power applications fall between $50 and $100 per tonne of CO2.

Performance benchmarks: Capture rates of 90% are standard, with next-generation solvents targeting 95% or higher. The Boundary Dam project in Saskatchewan, operated by SaskPower, demonstrated sustained 90% capture on a 115 MW coal unit, capturing approximately 1 million tonnes of CO2 annually since 2014. However, the project experienced significant operational challenges in its early years, including solvent degradation and equipment corrosion that reduced actual capture rates to 60 to 70% during extended periods.

Best suited for: Large point sources with moderate to high CO2 concentrations (8 to 25%), including coal and gas power plants, cement kilns, and steel blast furnaces.

Pre-Combustion Capture (Integrated Gasification)

Pre-combustion capture converts fossil fuels into a synthesis gas (hydrogen and CO2) before combustion, then separates CO2 from the hydrogen-rich stream using physical solvents or pressure swing adsorption. The remaining hydrogen is combusted for power generation or used as industrial feedstock.

Cost structure: Capital costs are substantially higher than post-combustion systems, ranging from $1,200 to $2,500 per tonne of annual capacity, primarily because the approach requires an entirely new gasification front end rather than retrofitting existing infrastructure. Operating costs are lower per tonne captured because the CO2 stream is at higher pressure and concentration, reducing separation energy to 1.5 to 2.5 GJ per tonne. All-in costs for integrated gasification combined cycle (IGCC) plants with capture range from $70 to $120 per tonne.

Performance benchmarks: The Kemper County IGCC project in Mississippi, originally designed to capture 3 million tonnes of CO2 annually from lignite coal gasification, was abandoned in 2017 after costs escalated from $2.4 billion to $7.5 billion. The project's failure highlighted the integration risks of coupling novel gasification with carbon capture at scale. In contrast, the Quest project in Alberta, operated by Shell, successfully captures approximately 1.2 million tonnes of CO2 annually from hydrogen production at the Scotford Upgrader, demonstrating that pre-combustion capture works well when applied to established industrial hydrogen processes rather than novel power generation configurations.

Best suited for: New-build facilities where hydrogen production is the primary objective, including refineries, ammonia plants, and blue hydrogen production.

Oxy-Combustion

Oxy-combustion burns fuel in a mixture of pure oxygen and recirculated flue gas rather than air, producing a flue gas that is predominantly CO2 and water vapor. This eliminates the need for chemical separation, as water can be condensed to yield a nearly pure CO2 stream.

Cost structure: The major cost driver is the air separation unit (ASU) required to produce high-purity oxygen, which consumes 200 to 250 kWh per tonne of oxygen produced. Capital costs range from $800 to $1,500 per tonne of annual capture capacity. Operating costs are dominated by ASU electricity consumption, adding $25 to $40 per tonne of CO2 to operating expenses. All-in costs range from $60 to $110 per tonne.

Performance benchmarks: NET Power's Allam-Fetvedt cycle demonstration plant in La Porte, Texas, represents the most advanced oxy-combustion implementation, integrating supercritical CO2 as both the working fluid and capture medium. The 50 MW demonstration achieved first fire in 2018, and a commercial-scale 300 MW plant is under development with an estimated completion by 2027. The technology promises near-zero emissions at costs competitive with conventional combined cycle plants, though commercial-scale verification remains pending.

Best suited for: New-build power generation and industrial heat applications where the cost of an air separation unit can be amortized across large volumes.

Direct Air Capture (DAC)

Direct air capture extracts CO2 directly from ambient air (at roughly 420 ppm concentration) rather than from concentrated industrial sources. Two primary approaches exist: liquid solvent systems using aqueous potassium hydroxide solutions and solid sorbent systems using amine-functionalized materials.

Cost structure: DAC remains the most expensive capture pathway due to the thermodynamic penalty of capturing CO2 at atmospheric concentrations. Current costs range from $400 to $1,000 per tonne, with credible projections suggesting $200 to $300 per tonne is achievable by 2035 at scale. Climeworks' Mammoth plant in Iceland, which began operations in 2024 with 36,000 tonnes per year capacity, represents the largest solid sorbent DAC facility. Occidental Petroleum's STRATOS plant in West Texas, using Carbon Engineering's liquid solvent technology, targets 500,000 tonnes per year capacity when fully operational.

Performance benchmarks: Climeworks' Orca plant (4,000 tonnes per year) demonstrated sustained operation but at costs estimated between $800 and $1,200 per tonne. The company reports that Mammoth will achieve costs below $500 per tonne through engineering optimization and economies of scale. 1PointFive (Occidental's DAC subsidiary) projects costs of $400 to $500 per tonne for STRATOS, declining to below $200 per tonne for subsequent facilities incorporating learning-rate improvements.

Best suited for: Carbon removal for hard-to-abate emissions, compliance with net-zero commitments, and locations without access to concentrated emission sources. DAC's location flexibility allows co-location with optimal geological storage sites, eliminating CO2 transport costs.

Membrane Separation

Membrane-based capture uses selective polymer or mixed-matrix membranes to separate CO2 from gas streams. Compared to solvent-based approaches, membranes offer modular scalability, lower water consumption, and reduced thermal energy requirements.

Cost structure: Capital costs range from $400 to $900 per tonne of annual capacity, reflecting the simpler equipment requirements. Operating costs are primarily electrical (for compression), ranging from $20 to $35 per tonne. All-in costs for high-concentration streams (above 15% CO2) range from $30 to $60 per tonne, though performance degrades significantly at lower concentrations.

Performance benchmarks: MTR (Membrane Technology and Research) has demonstrated pilot-scale capture from natural gas combined cycle flue gas (4% CO2) achieving 90% capture rates, though at costs exceeding $80 per tonne. Air Liquide's membrane systems for biogas upgrading and natural gas sweetening represent the most commercially mature applications. The US Department of Energy's Carbon Capture Program has funded multiple membrane development efforts, with several reaching Technology Readiness Level 6 to 7.

Best suited for: Modular applications, biogas upgrading, natural gas processing, and as a first-stage concentrator paired with downstream polishing technologies.

Comparison Matrix

Parameter	Post-Combustion	Pre-Combustion	Oxy-Combustion	Direct Air Capture	Membrane
All-in Cost ($/tonne)	$50-100	$70-120	$60-110	$400-1,000	$30-80
Capture Rate	90-95%	90-99%	95-99%	75-90%	80-95%
Technology Readiness	TRL 9	TRL 7-9	TRL 6-8	TRL 6-7	TRL 5-7
Energy Penalty	25-35%	15-25%	20-30%	High (variable)	10-20%
Retrofit Capability	High	Low	Low	N/A	Moderate
Water Consumption	High	Moderate	Low	Variable	Low
Scalability	Proven	Proven	Emerging	Emerging	Modular

Deployment Trade-offs for Founders

The selection framework depends on three primary variables: the CO2 concentration of the target stream, whether the application is retrofit or new-build, and the availability of transport and storage infrastructure.

For retrofit applications at existing industrial facilities, post-combustion chemical absorption remains the default choice, with the most extensive reference plant database and the broadest vendor ecosystem. The 45Q credit at $85 per tonne makes large-scale post-combustion capture economically viable for cement plants (CO2 concentrations of 15 to 30%) and steel mills (20 to 27%), where all-in costs of $50 to $80 per tonne yield positive margins after the credit.

For new-build hydrogen production, pre-combustion capture integrated with autothermal reforming or gasification offers the lowest incremental cost, as the CO2 separation step is inherent to the hydrogen purification process. Shell's Quest facility demonstrates that pre-combustion capture at existing hydrogen plants can achieve costs of $55 to $70 per tonne with over 95% uptime.

For founders building carbon removal businesses, DAC represents the only pathway that generates genuine carbon removal credits rather than emission reduction credits. The voluntary carbon market increasingly distinguishes between these categories, with removal credits commanding $200 to $600 per tonne compared to $10 to $50 per tonne for avoidance credits. The premium reflects buyer willingness to pay for permanence and additionality.

Membrane systems offer compelling economics for niche applications with high CO2 concentrations (biogas, fermentation off-gas, ethanol production) and represent the most attractive option for modular, distributed deployment.

What to Watch

Several developments in 2026 and 2027 will materially affect the competitive dynamics between these approaches. The first commercial-scale NET Power plant will provide validated cost and performance data for oxy-combustion in power generation. Occidental's STRATOS facility will establish whether DAC costs below $500 per tonne are achievable at scale. The Class VI well permitting backlog at the US Environmental Protection Agency, with over 100 applications pending, will determine whether storage infrastructure can keep pace with capture project development. The EU's planned revision of the CO2 transport directive will shape cross-border CCUS deployment across Europe.

Action Checklist

• Map emission source CO2 concentration, volume, and purity to identify the optimal capture technology
• Evaluate retrofit feasibility versus new-build for each target facility
• Assess proximity to geological storage formations and existing CO2 pipeline infrastructure
• Model project economics using verified reference plant data rather than vendor projections
• Engage early with Class VI well permitting to secure storage capacity ahead of pipeline growth
• Structure 45Q credit monetization strategy (direct use versus transfer versus direct pay)
• Evaluate hybrid configurations that combine membrane pre-concentration with solvent polishing
• Monitor NET Power and STRATOS commissioning data for updated cost benchmarks

Sources

• International Energy Agency. (2025). CCUS in Clean Energy Transitions: Global Status Report. Paris: IEA Publications.
• Global CCS Institute. (2025). Global Status of CCS Report 2025. Melbourne: GCCSI.
• US Department of Energy, National Energy Technology Laboratory. (2025). Carbon Capture Technology Compendium: Cost and Performance Baselines. Pittsburgh: NETL.
• Boundary Dam Carbon Capture Project. (2025). Operational Performance Summary 2014-2025. SaskPower.
• NET Power. (2025). Allam-Fetvedt Cycle: Demonstration Results and Commercial Plant Design Update. Durham, NC.
• Climeworks. (2025). Mammoth Plant: First-Year Operational Data and Cost Trajectory. Zurich.
• 1PointFive / Occidental Petroleum. (2025). STRATOS Direct Air Capture Facility: Engineering and Cost Update. Houston, TX.
• National Academies of Sciences, Engineering, and Medicine. (2024). Carbon Dioxide Removal and Reliable Sequestration: Research Agenda. Washington, DC: National Academies Press.