Cost breakdown: Carbon capture, utilization & storage (CCUS) economics — capex, opex, and payback by use case

Carbon capture, utilization and storage (CCUS) costs have fallen 35% since 2020 for point-source capture on concentrated CO₂ streams, yet the technology remains one of the most capital-intensive decarbonization pathways. Understanding the true cost structure across different capture types, CO₂ sources, and storage options is essential for project developers, industrial operators, and investors evaluating CCUS as a compliance or abatement strategy. This guide breaks down the economics by use case, scale, and region, with real-world benchmarks from operational projects.

Why It Matters

Global CCUS capacity must scale from roughly 50 million tonnes per annum (Mtpa) captured today to over 1 gigatonne by 2050 to meet Paris Agreement targets, according to the International Energy Agency. The economics of this scale-up determine which projects get financed, which industries adopt capture first, and where public subsidies deliver the highest carbon abatement per dollar. With the US 45Q tax credit now offering $85 per tonne for geological storage and $180 per tonne for direct air capture (DAC), the financial calculus has shifted dramatically. Yet cost ranges remain wide, and project-level economics vary by a factor of five depending on CO₂ concentration, location, and storage configuration.

Key Cost Categories

CCUS project costs divide into three primary buckets: capture (typically 60-75% of total cost), transport (10-20%), and storage (10-25%). Each has distinct cost drivers and scaling characteristics.

Capture Costs by CO₂ Source

The concentration of CO₂ in the flue gas or process stream is the single largest determinant of capture cost. Higher-concentration sources require less energy and smaller equipment to separate CO₂.

CO₂ Source	Concentration	Capture Cost ($/tonne CO₂)	Maturity
Natural gas processing	90-95%	$15-25	Commercial
Ethanol fermentation	95-99%	$20-30	Commercial
Ammonia production	95-99%	$25-35	Commercial
Hydrogen (SMR)	15-25%	$50-80	Commercial
Cement production	15-30%	$60-120	Demonstration
Steel (blast furnace)	20-27%	$65-130	Demonstration
Coal power plant	10-15%	$60-100	Commercial
Natural gas power plant	3-5%	$80-140	First-of-a-kind
Direct air capture	0.04%	$250-600	Early commercial

Capital Expenditure (Capex)

Capex for CCUS projects is heavily front-loaded, with capture equipment, compression systems, and pipeline infrastructure requiring significant upfront investment.

Point-source capture (1 Mtpa capacity):

• Amine scrubbing system: $400-800 million
• Compression and dehydration: $50-100 million
• Heat integration and utilities: $30-80 million
• Total capture capex: $500-1,000 million

Transport infrastructure:

• Onshore pipeline (per km): $1-3 million
• Offshore pipeline (per km): $3-8 million
• Ship transport (per vessel, 10,000 m³): $60-80 million
• Truck transport (per unit): $0.5-1 million

Storage infrastructure:

• Saline aquifer well (per well): $10-30 million
• Depleted oil/gas reservoir well: $5-15 million
• Monitoring and verification systems: $5-20 million
• Surface facilities: $20-50 million

Operating Expenditure (Opex)

Annual operating costs are dominated by energy consumption for capture (the "energy penalty") and ongoing monitoring requirements.

Energy penalty by capture technology:

• Post-combustion amine capture: 25-40% parasitic energy load
• Oxyfuel combustion: 20-30% parasitic energy load
• Pre-combustion (IGCC): 15-25% parasitic energy load
• Membrane separation: 15-20% parasitic energy load
• DAC (liquid solvent): 5-8 GJ thermal + 1.5-2.5 GJ electric per tonne CO₂
• DAC (solid sorbent): 4-6 GJ thermal + 0.5-1.5 GJ electric per tonne CO₂

Annual opex benchmarks (1 Mtpa facility):

• Solvent/sorbent replacement: $5-15 million
• Energy costs: $30-80 million (varies with energy prices)
• Labour and maintenance: $10-20 million
• Monitoring and reporting: $2-5 million
• Insurance and regulatory: $3-8 million

Cost Breakdown by Use Case

Industrial Point-Source Capture

Cement plant retrofit (1 Mtpa):

• Total capex: $300-600 million
• Annual opex: $40-80 million
• Levelized cost: $60-120 per tonne CO₂
• Payback with 45Q credit ($85/t): 8-15 years
• Payback with EU ETS at EUR 80/t: 10-18 years

Heidelberg Materials' Brevik CCS project in Norway represents the first full-scale cement capture facility, targeting 400,000 tonnes per year with an estimated capex of EUR 300 million. The project benefits from Norwegian government co-funding covering roughly 80% of costs through the Longship programme.

Steel plant integration (0.5-1 Mtpa):

• Total capex: $250-500 million
• Annual opex: $35-70 million
• Levelized cost: $65-130 per tonne CO₂
• Payback with subsidies: 10-20 years

ArcelorMittal's Ghent facility in Belgium is piloting carbon capture on a blast furnace, targeting 1 Mtpa by 2027 with integration into the Antwerp@C CO₂ hub for offshore storage in the North Sea.

Natural Gas Processing and Hydrogen

Blue hydrogen with CCS (200,000 tonnes H₂/year):

• Capture capex: $150-300 million
• Transport and storage: $50-150 million
• Levelized hydrogen cost: $1.50-2.50 per kg (vs. $1.00-1.50 without CCS)
• CO₂ abatement cost: $50-80 per tonne
• Payback: 5-10 years (with 45Q)

The Quest CCS facility in Alberta, operated by Shell, captures approximately 1.2 Mtpa of CO₂ from the Scotford hydrogen plant. Reported costs are approximately CAD $1.35 billion capex, with operating costs of CAD $30-40 million annually. The project received CAD $745 million in government funding.

Direct Air Capture

Small-scale DAC (1,000-5,000 tonnes/year):

• Capex: $3-10 million
• Annual opex: $1-3 million
• Cost per tonne: $400-600
• Payback with 45Q ($180/t): Not profitable at current costs without additional revenue

Large-scale DAC (100,000-500,000 tonnes/year):

• Capex: $300-800 million
• Annual opex: $60-200 million
• Target cost per tonne: $250-400 (current), $100-200 (projected 2035)
• Payback: Requires carbon removal credits at $300+ per tonne or stacked subsidies

Climeworks' Mammoth plant in Iceland, operational since 2024, captures 36,000 tonnes per year at an estimated cost of $800-1,000 per tonne. The company targets $300-350 per tonne at its next-generation 100,000+ tonne facility planned for 2028.

Power Sector CCS

Natural gas combined-cycle with post-combustion capture (400 MW):

• Capture capex: $600-1,200 million
• Additional levelized cost of electricity (LCOE): $20-40 per MWh
• CO₂ abatement cost: $80-140 per tonne
• Payback: 12-20 years (policy-dependent)

Coal power with retrofit CCS:

• Capture capex: $500-900 million (for 500 MW unit)
• Additional LCOE: $30-50 per MWh
• CO₂ abatement cost: $60-100 per tonne
• Payback: Rarely economic without strong carbon pricing (>$80/t)

Regional Cost Variations

United Kingdom

UK projects benefit from the CCUS cluster model, where shared transport and storage infrastructure reduce per-project costs by 20-40%. The East Coast Cluster (Teesside and Humberside) and HyNet North West are anchored by the Track-1 programme with government support of up to GBP 20 billion over 25 years.

• Typical onshore pipeline cost: GBP 1.5-2.5 million per km
• Offshore storage cost (North Sea): GBP 10-25 per tonne CO₂
• Industrial capture cost premium vs. US: 10-20% higher (smaller scale, higher energy costs)

United States

The US offers the most generous capture subsidies globally through the enhanced 45Q tax credit:

• $85 per tonne for geological storage
• $60 per tonne for enhanced oil recovery
• $180 per tonne for DAC with geological storage
• $130 per tonne for DAC with utilization

These credits, combined with lower energy and construction costs, make the US the most attractive jurisdiction for CCUS investment. The DOE's Regional Direct Air Capture Hubs programme has allocated $3.5 billion across four initial hubs.

European Union

EU economics are driven by the EU Emissions Trading System (ETS) carbon price, which has ranged from EUR 50-100 per tonne since 2023. At EUR 80 per tonne, industrial point-source capture becomes marginally economic for high-concentration sources. The Innovation Fund has allocated EUR 4.8 billion for CCUS projects through 2030.

What's Working

Cost reductions in point-source capture on high-concentration streams have made several applications commercially viable with existing policy support. The US 45Q credit has triggered over $30 billion in announced CCUS investment since the Inflation Reduction Act passed. Shared infrastructure models like the UK's cluster approach and Norway's Northern Lights project reduce transport and storage costs by distributing them across multiple capture projects. Second-generation solvent technologies from companies like ION Clean Energy and Carbon Clean have demonstrated 30-40% lower energy penalties compared to conventional amine systems.

What's Not Working

Cost overruns remain common for first-of-a-kind projects. SaskPower's Boundary Dam Unit 3 in Saskatchewan, the world's first commercial power-sector CCS project, experienced 30% capex overruns and achieved only 60-65% of its design capture rate in early years. DAC costs remain 5-10x higher than point-source capture, and learning rates are uncertain given limited deployment. Storage capacity characterization remains slow and expensive, with individual well appraisals costing $10-30 million. Many announced projects lack final investment decisions, creating a gap between pipeline aspirations and committed capital.

Key Players

Established Leaders

• Exxon Mobil: Largest operator of CCS by volume, capturing over 9 Mtpa globally across multiple projects including Shute Creek and LaBarge in Wyoming.
• Shell: Operates Quest CCS in Alberta and co-develops the Northern Lights CO₂ transport and storage project in Norway.
• Equinor: Leads the Northern Lights project providing open-access CO₂ storage in the Norwegian North Sea, with capacity scaling to 5 Mtpa.
• Linde: Major provider of gas separation and capture technology, supplying equipment for hydrogen and industrial capture projects worldwide.

Emerging Startups

• Climeworks: Pioneer in solid sorbent DAC with operational plants in Iceland, targeting cost reduction to $300-350 per tonne by 2028.
• Carbon Clean: Develops modular, lower-cost capture systems with a rotating packed bed design reducing capital costs by up to 50% versus conventional columns.
• Svante: Produces solid sorbent capture systems for cement and hydrogen applications, with deployments in North America.
• CarbonCure: Injects captured CO₂ into concrete during mixing, permanently mineralizing it while improving concrete strength.

Key Investors and Funders

• Breakthrough Energy Ventures: Bill Gates-backed fund with investments in DAC, novel capture chemistry, and mineralization startups.
• US Department of Energy: Allocated $12 billion for CCUS through the Bipartisan Infrastructure Law and IRA, including $3.5 billion for DAC hubs.
• UK Department for Energy Security and Net Zero: Committed up to GBP 20 billion for Track-1 and Track-2 CCUS cluster support.

Action Checklist

1. Identify CO₂ sources by concentration to prioritize lowest-cost capture opportunities
2. Model project economics with applicable subsidies (45Q, EU ETS, UK cluster support) and sensitivity to carbon price scenarios
3. Evaluate shared infrastructure options including pipeline networks and storage hubs to reduce per-project transport and storage costs
4. Assess energy supply contracts for capture facilities, as energy costs typically represent 40-60% of opex
5. Engage with storage operators early, as site characterization and permitting can take 3-5 years
6. Consider modular capture solutions from companies like Carbon Clean or Svante for industrial sites under 500,000 tonnes per year
7. Factor in revenue from CO₂ utilization pathways (concrete, chemicals, enhanced oil recovery) where applicable
8. Build contingency of 20-30% on capex estimates for first-of-a-kind projects based on historical overrun data

FAQ

What is the cheapest form of carbon capture? Capture from high-concentration industrial streams such as natural gas processing and ethanol fermentation costs $15-30 per tonne CO₂, making these the most economic applications. These sources produce nearly pure CO₂ requiring minimal separation.

How does the 45Q tax credit change project economics? The 45Q credit at $85 per tonne for geological storage can cover 60-100% of the levelized cost for industrial point-source capture on medium-concentration streams. For projects capturing from sources costing $60-85 per tonne, 45Q can make the project cash-flow positive from year one. DAC projects benefit from the higher $180 per tonne credit but still face a cost gap at current technology levels.

What is the payback period for a typical CCUS project? Payback varies widely by application. Natural gas processing CCS with 45Q credits can achieve payback in 4-7 years. Industrial capture on cement or steel typically requires 8-15 years with subsidies. DAC projects do not achieve payback under current economics without stacked incentives and premium carbon removal credit pricing above $300 per tonne.

How much does CO₂ storage cost? Geological storage in saline aquifers typically costs $10-30 per tonne including well drilling, injection, monitoring, and long-term liability. Depleted oil and gas reservoirs cost $5-15 per tonne due to existing geological characterization and well infrastructure. Offshore storage in the North Sea costs GBP 10-25 per tonne.

Will CCUS costs continue to fall? The Global CCS Institute projects 20-30% cost reductions by 2035 for point-source capture through next-generation solvents, modular designs, and manufacturing scale-up. DAC has a steeper potential learning curve, with industry targeting $100-200 per tonne by the mid-2030s, though this requires deployment scaling by a factor of 100x from current levels.

Sources

1. International Energy Agency. "CCUS in Clean Energy Transitions." IEA, 2024.
2. Global CCS Institute. "Global Status of CCS 2025." GCCSI, 2025.
3. US Department of Energy. "Carbon Capture, Transport, and Storage: Supply Chain Deep Dive Assessment." DOE, 2024.
4. Heidelberg Materials. "Brevik CCS Project Update." Heidelberg Materials, 2025.
5. Climeworks. "Mammoth Plant Operations Report." Climeworks, 2025.
6. UK Department for Energy Security and Net Zero. "CCUS Cluster Sequencing: Track-1 and Track-2 Delivery Plan." DESNZ, 2024.
7. BloombergNEF. "Carbon Capture Economics: Cost Benchmarks and Outlook." BNEF, 2025.