Myth-busting Carbon capture, utilization & storage (CCUS): 10 misconceptions holding teams back

With global CCUS capacity surpassing 50 million tonnes of CO₂ per year across 44 operational facilities and over $15 billion in announced project investments since 2022, carbon capture has evolved from experimental technology to a critical component of industrial decarbonization strategies. Yet despite the sector's rapid growth and $85 billion in available 45Q tax credits under the Inflation Reduction Act, persistent misconceptions continue to stall project development, misallocate capital, and undermine stakeholder confidence. This article systematically dismantles ten of the most damaging myths holding CCUS teams back.

Why It Matters

The International Energy Agency's 2024 Net Zero Roadmap identifies CCUS as essential for capturing 6 Gt of CO₂ annually by 2050—a 100-fold increase from current levels. As of early 2025, the global pipeline includes over 700 announced CCUS projects, with 196 in advanced development stages. The United States alone has witnessed a 350% increase in project announcements since the IRA's passage, with the enhanced 45Q credit now offering $85 per tonne for geological storage and $180 per tonne for direct air capture (DAC).

The financial stakes are substantial. The IRA allocates $3.5 billion for four regional DAC hubs, while the Bipartisan Infrastructure Law provides $2.5 billion for carbon storage commercialization. The European Union's Innovation Fund has committed €3.6 billion to CCUS projects through 2030. In emerging markets, the Carbon Management Strategy frameworks in countries like Indonesia, Malaysia, and Nigeria are opening new frontiers for cross-border CO₂ storage partnerships.

However, misconceptions about technology readiness, economics, and permanence continue to impede progress. Teams that understand the evidence can position themselves to capture first-mover advantages in what McKinsey projects will be a $150 billion annual market by 2035.

Key Concepts

Point Source Capture

Point source capture involves installing equipment at large industrial emitters—power plants, cement kilns, steel mills, and refineries—to capture CO₂ from flue gases before atmospheric release. Capture rates typically range from 85% to 95%, with amine-based solvents representing the dominant commercial technology. Modern facilities achieve capture costs between $40-$120 per tonne, depending on CO₂ concentration in the source stream.

Direct Air Capture (DAC)

DAC technologies extract CO₂ directly from ambient air, where concentrations hover around 420 ppm—roughly 300 times more dilute than power plant flue gases. This thermodynamic challenge translates to higher costs ($400-$1,000 per tonne currently) but offers location flexibility and permanent carbon removal potential. Leading approaches include solid sorbent systems (Climeworks, Global Thermostat) and liquid solvent methods (Carbon Engineering, now 1PointFive).

Geological Storage

Saline aquifers, depleted oil and gas reservoirs, and basalt formations provide secure, long-term CO₂ sequestration. The Sleipner project in Norway has safely stored over 20 million tonnes of CO₂ since 1996, demonstrating storage integrity across nearly three decades. Modern monitoring, verification, and accounting (MVA) protocols use seismic imaging, wellbore integrity testing, and satellite-based surface deformation detection to ensure containment.

Utilization Pathways

Carbon utilization converts captured CO₂ into products including synthetic fuels (e-methanol, sustainable aviation fuel), building materials (carbonated concrete, aggregates), chemicals (methanol, urea, polymers), and enhanced oil recovery (EOR). While utilization currently represents 70% of captured CO₂ globally, permanent storage is increasingly prioritized as climate targets tighten.

45Q Tax Credit Structure

The reformed 45Q credit provides predictable per-tonne incentives: $85 for geological storage, $60 for EOR, $180 for DAC with geological storage, and $130 for DAC with utilization. Credits are available for 12 years from project startup, with direct pay options for the first five years enabling project financing without tax equity partners.

CCUS Performance Metrics

Metric	Current State (2025)	Target (2030)	Best-in-Class
Point Source Capture Cost	$40-$120/tonne	$30-$50/tonne	$35/tonne (high-purity streams)
DAC Capture Cost	$400-$1,000/tonne	$150-$300/tonne	$250/tonne (demonstration)
Capture Rate	85-95%	>95%	99% (Boundary Dam optimization)
Energy Penalty	15-30%	8-15%	10% (next-gen solvents)
Storage Permanence	>99% over 1,000 years	>99.9%	100% (mineralization)
Project Lead Time	5-7 years	3-4 years	2.5 years (streamlined permitting)
Capacity Factor	70-85%	>90%	95% (mature facilities)

What's Working and What Isn't

What's Working

Industrial Clusters and Shared Infrastructure: The Port of Rotterdam's Porthos project demonstrates how shared CO₂ transport and storage infrastructure can reduce per-tonne costs by 30-40%. By aggregating emissions from multiple refineries and chemical plants, clusters achieve economies of scale impossible for standalone projects. Similar hub models are advancing in the Houston Ship Channel, Teesside (UK), and the Alberta Carbon Trunk Line.

Enhanced Oil Recovery Economics: With over 40 years of commercial operation, CO₂-EOR provides proven revenue stacking opportunities. Occidental Petroleum's operations in the Permian Basin inject 40 million tonnes of CO₂ annually, generating both oil production and carbon credits. While EOR faces scrutiny regarding net climate benefits, it provides crucial infrastructure learning and de-risks storage geology.

Policy Support Alignment: The convergence of 45Q credits, state-level incentives (California's LCFS at $80+ per tonne), and emerging compliance markets creates compelling project economics. Developers can now stack incentives to achieve effective carbon prices exceeding $150 per tonne, transforming previously marginal projects into attractive investments.

Technology Maturation: Second and third-generation capture technologies are entering commercial deployment. Membrane systems, solid sorbents, and cryogenic separation offer pathways to reduced energy penalties and capital costs. Svante's MOF-based systems and MTR's membrane technology represent genuine cost reduction trajectories.

What Isn't Working

High First-of-a-Kind Costs: Despite technology readiness, FOAK projects continue to face 40-60% cost premiums versus nth-of-a-kind estimates. The Petra Nova retrofit, at $1 billion for 1.4 million tonnes per year capacity, illustrated the challenges of pioneer projects. Reducing FOAK premiums requires standardized designs and experienced engineering teams.

Energy Penalty Burden: Conventional amine capture systems impose 15-30% parasitic energy loads, reducing net power output and increasing operating costs. For coal plants already facing competitive pressure, this energy penalty can be economically prohibitive. Advanced solvent systems and process integration are essential but require further scale-up.

Public Perception and Permitting: Community opposition has stalled or killed numerous projects, including the Summit Carbon Solutions Midwest pipeline. Concerns about pipeline safety, induced seismicity, and perceived fossil fuel lifelines require sophisticated stakeholder engagement. The Class VI well permitting backlog—with EPA approval timelines exceeding three years—compounds delays.

Utilization Market Limitations: Despite enthusiasm for carbon-to-products pathways, current utilization markets absorb less than 300 million tonnes of CO₂ annually, with EOR representing the vast majority. Synthetic fuel economics remain challenging without substantial carbon pricing, and many utilization pathways offer only temporary storage.

Key Players

Established Leaders

Equinor: The Norwegian energy company operates the world's longest-running CO₂ storage project at Sleipner and leads the Northern Lights joint venture, offering the first open-access CO₂ transport and storage service. Northern Lights Phase 1 will store 1.5 million tonnes annually starting in 2025.

Shell: Shell's Quest CCS facility in Alberta has safely stored over 8 million tonnes of CO₂ since 2015, demonstrating saline aquifer storage reliability. Shell is also developing the Polaris CCS hub and participates in multiple joint ventures across North America and Europe.

Occidental Petroleum: Through its 1PointFive subsidiary (partnered with Carbon Engineering), Occidental is building the world's largest DAC facility in Texas, targeting 500,000 tonnes per year capacity. The company integrates DAC with its extensive EOR operations and geological storage expertise.

Emerging Innovators

Climeworks: The Swiss DAC pioneer operates the Orca (4,000 tonnes/year) and Mammoth (36,000 tonnes/year) facilities in Iceland, leveraging geothermal energy and basalt mineralization for permanent storage. Climeworks has secured over $600 million in advance purchase agreements from Microsoft, Stripe, and other corporate buyers.

Heirloom Carbon: Using limestone looping and enhanced weathering, Heirloom offers a distinct DAC approach with lower energy requirements. The company's first commercial facility in Louisiana targets costs below $200 per tonne by 2030.

CarbonCure Technologies: Specializing in concrete carbonation, CarbonCure injects captured CO₂ into ready-mix concrete, permanently mineralizing carbon while improving compressive strength. The technology is deployed at over 700 concrete plants globally.

Key Investors and Funders

U.S. Department of Energy: DOE's Office of Fossil Energy and Carbon Management administers $12 billion in CCUS funding, including the $3.5 billion Regional DAC Hubs program and $2.5 billion Carbon Storage Validation and Testing program.

Breakthrough Energy Ventures: Bill Gates' climate fund has invested heavily in CCUS, with portfolio companies including Carbon Engineering, CarbonCure, and Heirloom.

Oil and Gas Climate Initiative (OGCI): This consortium of major oil companies has committed $1 billion to CCUS projects and technology development, with member companies leading many of the world's largest capture facilities.

10 Misconceptions About CCUS

Misconception 1: CCUS Is Unproven Technology

Reality: CCUS has over 50 years of commercial operating history. The Terrell Gas Processing Plant in Texas has captured CO₂ since 1972. The Sleipner project has safely stored 20+ million tonnes since 1996. As of 2025, 44 commercial facilities operate globally, with 196 in advanced development. The technology is not experimental—deployment is the primary challenge.

Misconception 2: Captured CO₂ Will Leak From Storage

Reality: Geological storage in properly characterized formations demonstrates exceptional permanence. The IPCC estimates 99%+ retention over 1,000 years for well-selected sites. Natural CO₂ accumulations have remained trapped for millions of years. Comprehensive MVA programs detect potential leakage pathways, and remediation protocols exist for wellbore integrity issues. Mineralization pathways (as used by Climeworks and Carbfix in Iceland) convert CO₂ to stable carbonate minerals within 2-4 years, eliminating leakage risk entirely.

Misconception 3: CCUS Only Extends Fossil Fuel Dependence

Reality: While early CCUS applications focused on coal power and EOR, the technology's primary growth areas are now hard-to-abate industrial sectors. Cement production, steelmaking, and chemical manufacturing generate process emissions that cannot be eliminated through electrification or fuel switching alone. Cement kilns release CO₂ from limestone calcination regardless of fuel source. CCUS is essential for these industries' decarbonization pathways, not a competitor to renewable energy deployment.

Misconception 4: DAC Is Too Expensive to Scale

Reality: Current DAC costs of $400-$1,000 per tonne reflect early-stage technology on steep learning curves. Solar PV costs fell 99% over four decades of deployment. Analysis by Rhodium Group suggests DAC could reach $150-$200 per tonne by 2035 with continued investment. The IRA's $180/tonne DAC credit already enables positive project economics for first-mover facilities. Corporate advance purchase agreements from Microsoft, Stripe, and others at $500-$600 per tonne demonstrate willingness to pay for verified permanent removal.

Misconception 5: CCUS Cannot Scale Fast Enough to Matter

Reality: The current pipeline of 700+ announced projects represents 350 million tonnes per year of potential capacity—a 7x increase from today's levels. Historical precedent exists for rapid infrastructure buildout: the U.S. constructed 3,000+ miles of CO₂ pipeline for EOR operations over two decades. The constraint is not technological capability but investment and permitting timelines. Streamlined Class VI well permitting and increased workforce development can accelerate deployment trajectories.

Misconception 6: All Carbon Credits From CCUS Are Low Quality

Reality: CCUS-based credits vary dramatically in integrity. Point source capture with geological storage, verified by third-party MVA programs, provides highly measurable, additional, and permanent emission reductions. DAC with mineralization offers even stronger permanence guarantees. The challenge lies in distinguishing these high-integrity credits from questionable utilization claims. The Integrity Council for Voluntary Carbon Markets (ICVCM) Core Carbon Principles and ISO 14064 standards provide frameworks for quality differentiation.

Misconception 7: CCUS Competes With Renewable Energy Investment

Reality: Integrated energy system modeling by the IEA, IPCC, and national laboratories consistently shows CCUS and renewables as complementary, not competitive. Net-zero scenarios require massive renewable buildout AND CCUS for residual emissions. Investment data supports this: companies and governments are simultaneously increasing funding for both technology pathways. Shell, TotalEnergies, and BP have substantial portfolios spanning wind, solar, and CCUS.

Misconception 8: The Energy Penalty Makes CCUS Counterproductive

Reality: While conventional amine systems do impose 15-30% energy penalties, life cycle analysis confirms substantial net climate benefits. A coal plant with 90% capture and a 25% energy penalty still reduces net emissions by 65-75% compared to unabated operation. Next-generation capture technologies (advanced solvents, membranes, solid sorbents) target energy penalties below 10%. For industrial applications with waste heat availability, parasitic loads can be further reduced through thermal integration.

Misconception 9: Liability Risks Make CCUS Projects Uninsurable

Reality: The insurance and reinsurance industry has developed products specifically for CCUS projects. Long-term liability transfer mechanisms exist in jurisdictions including Alberta, Australia, and the EU. The U.S. EPA's Class VI well program includes post-injection site care requirements and eventual transfer to long-term stewardship programs. Swiss Re, Munich Re, and specialty insurers offer coverage packages addressing operational, construction, and long-term storage risks.

Misconception 10: Emerging Markets Cannot Pursue CCUS

Reality: Several emerging markets possess exceptional CCUS potential due to geological storage capacity, existing oil and gas infrastructure, and industrial emission profiles. Indonesia's offshore basins could store 400+ Gt of CO₂. Malaysia's Kasawari project will be among the world's largest offshore CCS operations. Nigeria and Senegal are exploring cross-border CO₂ storage frameworks. World Bank and Asian Development Bank financing, combined with emerging carbon markets, is enabling project development. The challenge is building local technical capacity and regulatory frameworks, not fundamental feasibility.

Action Checklist

• Conduct a comprehensive emissions inventory to identify capture-eligible point sources and prioritize by CO₂ concentration, volume, and proximity to storage
• Evaluate 45Q eligibility and stack with state incentives (LCFS, RGGI, state tax credits) to model project economics under multiple scenarios
• Engage geological consultants to assess storage options including saline aquifers, depleted reservoirs, and mineralization pathways within 150 miles of emission sources
• Initiate pre-filing communication with EPA for Class VI well permits and evaluate state primacy options in jurisdictions with delegation authority
• Develop stakeholder engagement and community benefit plans addressing environmental justice considerations, local employment, and emergency response protocols
• Explore industrial cluster opportunities with neighboring emitters to share transport and storage infrastructure costs
• Structure advance purchase agreements or offtake contracts with corporate buyers seeking verified permanent removal
• Establish monitoring, verification, and accounting protocols aligned with ICVCM Core Carbon Principles and ISO 14064 standards

FAQ

Q: How long does CO₂ remain sequestered in geological storage? A: Properly characterized geological storage provides permanence exceeding 10,000 years, with IPCC estimates of 99%+ retention over 1,000 years for well-selected sites. Mineralization pathways convert CO₂ to stable carbonates within 2-4 years, providing essentially permanent storage. Ongoing MVA programs detect and address any potential migration, though evidence from natural CO₂ accumulations and 50+ years of injection operations confirms exceptional long-term containment.

Q: What is the realistic cost trajectory for direct air capture? A: DAC costs have already declined from >$1,000/tonne in 2020 to $400-$600/tonne for current commercial facilities. Industry projections target $150-$300/tonne by 2030-2035 as manufacturing scales and technology improves. The learning rate observed in analogous technologies (solar PV, batteries) suggests 10-15% cost reduction per doubling of cumulative capacity. However, reaching <$100/tonne—necessary for widespread deployment—will require breakthrough innovations in sorbent materials or energy integration.

Q: How does CCUS compare to nature-based carbon removal? A: CCUS and nature-based solutions (afforestation, soil carbon, etc.) serve complementary roles. Nature-based approaches offer lower costs ($10-$50/tonne) but face permanence concerns (fire, disease, land-use change) and saturation limits. CCUS provides verified permanence and scalability to gigatonne levels but at higher costs. Portfolios balancing both approaches maximize climate impact while managing cost and risk. High-integrity carbon removal portfolios typically include 20-40% engineered removal (CCUS/DAC) with the remainder from nature-based methods.

Q: What regulatory framework governs CO₂ storage in the United States? A: The EPA's Underground Injection Control (UIC) program regulates CO₂ injection under Class VI well permits, established in 2010 specifically for geologic sequestration. Permits require demonstration of containment, comprehensive MVA plans, financial assurance, and post-injection site care. As of 2025, EPA has delegated Class VI primacy to North Dakota, Wyoming, and Louisiana, with several additional states pursuing delegation to accelerate permitting. The permitting backlog exceeds 100 pending applications with 2-4 year approval timelines.

Q: Can CCUS help companies meet Scope 3 emission reduction targets? A: CCUS can contribute to Scope 3 reductions through multiple pathways. Suppliers implementing capture at their facilities reduce product-embedded carbon (Scope 3 Category 1 for purchasing companies). Carbon-negative products (carbonated concrete, CO₂-derived fuels) can offset Scope 3 emissions in categories like business travel or purchased goods. Corporate carbon removal purchases from DAC providers also address residual Scope 3 emissions. Science-based target frameworks increasingly recognize high-quality CCUS credits for beyond-value-chain mitigation.

Sources

• International Energy Agency. (2024). CCUS Projects Database. Paris: IEA. https://www.iea.org/data-and-statistics/data-tools/ccus-projects-explorer
• Global CCS Institute. (2024). Global Status of CCS Report 2024. Melbourne: GCCSI.
• U.S. Department of Energy. (2024). Carbon Capture Program: Technology Development and Demonstration. Office of Fossil Energy and Carbon Management.
• IPCC. (2005). Special Report on Carbon Dioxide Capture and Storage. Cambridge University Press. (With 2022 supplement on geological storage permanence)
• Rhodium Group. (2024). The Future of Direct Air Capture: Cost Reduction Pathways and Market Development. New York: Rhodium Group.
• Congressional Research Service. (2024). The Section 45Q Tax Credit for Carbon Oxide Sequestration. Washington, DC: CRS Report R47494.
• Northern Lights JV. (2024). Open-Access CO₂ Transport and Storage: Commercial Framework and Technical Specifications. Stavanger: Equinor/Shell/TotalEnergies.