Regional spotlight: Carbon capture, utilization & storage (CCUS) in US — what's different and why it matters

The United States captures and stores more CO2 annually than any other country, yet the structure of US CCUS differs fundamentally from projects in Europe, the Middle East, and Asia-Pacific. Understanding these differences is essential for product teams, project developers, and investors evaluating CCUS opportunities, because assumptions imported from global narratives frequently misrepresent the economics, regulatory landscape, and deployment pathways that define the US market.

Why It Matters

The US accounts for approximately 60% of global operational CCUS capacity, with over 30 million tonnes per annum (Mtpa) of CO2 captured across 35 facilities as of early 2026. The Inflation Reduction Act's enhanced 45Q tax credit, providing up to $85 per tonne for geological storage and $180 per tonne for direct air capture (DAC), has triggered the largest pipeline of proposed CCUS projects in history. The Department of Energy's CCUS project tracker lists over 200 proposed facilities representing more than 250 Mtpa of potential capture capacity, a figure that exceeds the combined proposed capacity of all other countries.

But scale alone does not explain what makes the US market distinctive. Three structural factors set the US apart. First, the US has the most favorable geology for CO2 storage of any major economy, with estimated storage capacity exceeding 8,600 billion tonnes in saline formations, depleted oil and gas reservoirs, and unmineable coal seams, according to the National Energy Technology Laboratory. Second, the 45Q tax credit structure creates a fundamentally different financial model from the European Emissions Trading System (EU ETS) or national carbon pricing mechanisms used elsewhere. Third, the US regulatory framework for CO2 injection, built on decades of enhanced oil recovery (EOR) experience and the EPA's Underground Injection Control (UIC) program, provides a more established permitting pathway than most other jurisdictions, despite recent permitting delays that have generated significant concern.

For product and design teams building CCUS technologies, monitoring systems, or project management platforms, these differences translate into specific technical requirements, integration challenges, and market opportunities that do not exist in the same form elsewhere.

Key Concepts

Section 45Q Tax Credit provides a per-tonne tax credit for CO2 captured and either stored in geological formations or utilized in qualifying processes. The Inflation Reduction Act increased the credit to $85/tonne for geological storage, $60/tonne for utilization, and $180/tonne for DAC with geological storage. Critically, 45Q is a production tax credit (not a grant or carbon price), meaning its value depends on the project owner's tax liability. The transferability provision added by the IRA allows credits to be sold to third parties at approximately $0.85-0.92 per dollar of face value, addressing the tax equity constraint that previously limited project development to large, profitable corporations.

Class VI Well Permits are required by the EPA for wells used exclusively for geological CO2 storage (as distinct from Class II wells used for EOR). The EPA has issued fewer than 10 Class VI permits directly as of early 2026, creating a significant bottleneck. Several states, including Louisiana, North Dakota, and Wyoming, have received primacy to administer their own Class VI programs, accelerating permitting in those jurisdictions. Texas submitted its primacy application in 2023, and approval is expected to substantially reshape the project development landscape given the state's dominant position in CCUS infrastructure.

Enhanced Oil Recovery (EOR) has been the primary use of captured CO2 in the US for over 50 years, with approximately 22 Mtpa of CO2 currently injected for EOR across the Permian Basin, Gulf Coast, and other formations. EOR creates a revenue stream beyond the 45Q credit (the value of incremental oil production), but it also introduces complexity: CO2 used for EOR qualifies for a lower 45Q credit ($60/tonne versus $85 for dedicated storage), and lifecycle accounting for EOR-associated emissions remains contested, with methodologies varying significantly between project developers.

CO2 Pipeline Infrastructure in the US spans approximately 5,300 miles, the largest network globally. This existing infrastructure, primarily serving the EOR industry, provides a logistical advantage that other countries lack. However, expansion is needed: the Princeton Net-Zero America study estimates that achieving net-zero emissions by 2050 would require approximately 65,000 miles of CO2 pipelines, a buildout comparable in scale to the interstate natural gas pipeline system constructed over several decades.

What's Different About the US Market

Tax Credit Economics vs. Carbon Pricing

The most fundamental difference between the US CCUS market and global alternatives is economic structure. In Europe, CCUS project economics depend on the EU ETS carbon price, which fluctuated between $55 and $100 per tonne in 2024-2025, creating revenue uncertainty that complicates project financing. In the US, the 45Q credit provides a fixed, predictable revenue stream for 12 years from the date equipment is placed in service. This certainty has enabled project financing structures that European developers cannot replicate.

However, 45Q's structure creates its own challenges. The credit begins only when capture equipment is operational, meaning developers bear 3-5 years of development and construction costs before receiving any revenue. The credit expires after 12 years, requiring projects to either achieve operational profitability without subsidies or find alternative revenue sources. And the transferability market, while growing, remains illiquid compared to established tax equity markets for wind and solar, with transaction costs of 8-15% eroding effective credit value.

Geological Advantage and Storage Hub Development

The US geological endowment for CO2 storage is unmatched. The Gulf Coast region alone offers estimated storage capacity exceeding 2,000 billion tonnes in saline formations with favorable permeability and seal integrity. This has enabled a "hub" development model where multiple industrial emitters share CO2 transport and storage infrastructure, reducing per-project costs.

Three major hub developments illustrate this approach. The Louisiana Clean Energy Complex, anchored by Air Products' blue hydrogen facility, plans to capture 5 Mtpa of CO2 and store it in saline formations beneath the Gulf Coast. The CarbonSAFE initiative has funded detailed site characterization for over 50 potential storage complexes across 20 states. Denbury (now acquired by ExxonMobil) operates the largest dedicated CO2 pipeline network in the US, providing backbone infrastructure connecting industrial emitters to storage sites along the Gulf Coast.

Permitting as the Binding Constraint

Despite favorable economics and geology, permitting has emerged as the primary bottleneck for US CCUS deployment. EPA's processing time for Class VI well permits has averaged 3-5 years, with some applications pending for over 6 years. This timeline exceeds the 45Q construction commencement deadline, creating a paradox where projects must begin construction to qualify for tax credits but cannot begin injection without permits.

State primacy programs are the primary response. Louisiana's program, operational since 2023, has processed permits in 12-18 months, dramatically faster than the EPA. North Dakota and Wyoming have similarly accelerated timelines. The practical implication for product teams is that CCUS monitoring and compliance platforms must accommodate both federal and state regulatory frameworks, with differing reporting requirements, monitoring protocols, and financial assurance standards.

What's Working

Industrial CCUS at Ethanol and Natural Gas Processing Plants

The lowest-cost CCUS applications in the US capture CO2 from high-purity industrial sources where CO2 concentration exceeds 90%, eliminating the need for expensive separation technologies. Over a dozen ethanol plants in the Midwest capture CO2 that would otherwise be vented, at costs of $15-25 per tonne, well below the 45Q credit value. Summit Carbon Solutions is developing a 2,000-mile pipeline network to connect 32 ethanol plants in five states to a storage site in North Dakota, representing the largest proposed CCUS infrastructure project in the US.

Direct Air Capture Demonstration

The US is leading global DAC deployment through the DOE's Regional Direct Air Capture Hubs program, which allocated $3.5 billion to two initial hub projects. Occidental Petroleum's Stratos facility in Texas, powered by 1PointFive's technology, represents the world's largest DAC plant under construction with a planned capacity of 500,000 tonnes per year. The $180/tonne 45Q credit for DAC with storage, combined with voluntary carbon credit sales at $400-600 per tonne to corporate buyers including Airbus, JPMorgan, and Shopify, creates a stacked revenue model unique to the US market.

Carbon Management as a Service

A distinctive US trend is the emergence of "CCUS-as-a-service" companies that handle capture, transport, and storage for industrial emitters who lack the expertise or capital to develop their own infrastructure. Carbon America, Carbonvert, and Battelle's carbon management division offer turnkey solutions where the emitter pays a per-tonne fee while the service provider captures 45Q credits. This model is particularly relevant for mid-sized industrial facilities (cement plants, steel mills, waste-to-energy facilities) that emit 100,000 to 1 million tonnes annually but are too small to justify dedicated CCUS infrastructure.

What's Not Working

Pipeline Siting and Community Opposition

CO2 pipeline development faces significant opposition from rural landowners and communities concerned about safety, eminent domain, and environmental justice. The Navigator CO2 Ventures Heartland Greenway project, proposed to connect ethanol plants across five Midwest states, was denied permits in South Dakota and Iowa following sustained community opposition. Summit Carbon Solutions' pipeline has faced similar resistance. Pipeline safety concerns intensified after a 2020 CO2 pipeline rupture in Satartia, Mississippi, that required evacuation of 200 residents. These challenges have forced developers to redesign routes, negotiate additional safety measures, and extend development timelines by 2-3 years.

Monitoring, Reporting, and Verification Gaps

The 45Q credit requires rigorous MRV to demonstrate that injected CO2 remains permanently stored. However, the monitoring technologies and protocols needed for long-term storage verification remain immature relative to the scale of proposed deployment. Subpart RR of EPA's Greenhouse Gas Reporting Program defines requirements for CO2 injection sites, but the monitoring plans submitted to date vary significantly in scope and rigor. Product teams developing MRV platforms face the challenge of building systems that satisfy both current regulatory requirements and the enhanced monitoring standards that are likely to emerge as the industry scales.

Utilization Pathway Limitations

Despite the $60/tonne utilization credit, commercially viable CO2 utilization pathways remain limited in scale. Enhanced oil recovery dominates, accounting for over 70% of utilized CO2. Mineralization into building materials (through companies like CarbonCure and Solidia Technologies) represents a growing but still small segment, with total US consumption under 1 Mtpa. CO2-to-fuels pathways remain pre-commercial at scale, with production costs of $3-6 per gallon for synthetic fuels, far exceeding conventional fuel prices. The utilization pathway that generates the most excitement, converting CO2 into chemicals and polymers, currently consumes less than 0.5 Mtpa across all US operations.

Myths vs. Reality

Myth 1: 45Q makes every CCUS project financially viable

Reality: The 45Q credit alone does not cover full-cycle costs for most applications. Post-combustion capture from power plants costs $50-120 per tonne depending on flue gas CO2 concentration, and when combined with transport and storage costs ($10-25 per tonne), total project costs can exceed the $85 credit. Only high-purity sources (ethanol, natural gas processing, ammonia production) achieve positive economics on 45Q alone. Power sector and cement applications typically require additional revenue from compliance markets, voluntary credits, or premium product pricing.

Myth 2: The US has unlimited CO2 storage capacity

Reality: While theoretical capacity is enormous (8,600+ billion tonnes), practical storage capacity is far more constrained. Detailed site characterization reduces theoretical capacity by 80-95% when accounting for injectivity limits, pressure management requirements, and proximity to infrastructure. CarbonSAFE projects have found that characterized storage capacity in mature basins is 5-20% of initial estimates. Additionally, pore space ownership and mineral rights conflicts in some states create legal barriers that further limit accessible storage.

Myth 3: CCUS is primarily about coal plants

Reality: Less than 5% of proposed US CCUS capacity targets coal-fired power plants. The dominant applications are industrial (cement, steel, chemicals, ethanol), natural gas processing, hydrogen production, and direct air capture. The coal narrative persists from early CCUS demonstrations like Petra Nova (which operated from 2017-2020 before suspending operations due to low oil prices), but the current project pipeline reflects a fundamental shift toward industrial and DAC applications where economics are more favorable.

Myth 4: Permitting delays will be resolved quickly through state primacy

Reality: State primacy addresses one bottleneck but introduces new complexities. Each state program has different standards, monitoring requirements, and financial assurance thresholds. Companies operating across multiple states must navigate a patchwork of regulations rather than a single federal framework. Additionally, primacy transfers regulatory liability to states that may lack the technical expertise and staffing to manage large-scale injection oversight.

Key Players

Project Developers

ExxonMobil has committed $17 billion to its Low Carbon Solutions division through 2027, with a focus on CCS hub development along the US Gulf Coast, leveraging Denbury's acquired pipeline infrastructure.

Occidental Petroleum / 1PointFive is developing the world's largest direct air capture facility in Texas, targeting 500,000 tonnes per year of atmospheric CO2 removal.

Summit Carbon Solutions is building the largest proposed CO2 pipeline in the US, connecting Midwest ethanol plants to storage in North Dakota.

Technology Providers

Fluor Corporation provides engineering and construction for large-scale amine-based capture systems, with involvement in multiple US industrial CCUS projects.

Carbon Engineering (Occidental) develops DAC technology using a potassium hydroxide liquid solvent process optimized for large-scale deployment.

Svante offers solid sorbent capture technology targeting industrial facilities, with US deployments in cement and hydrogen production.

Monitoring and Software

Schlumberger provides subsurface monitoring, modeling, and MRV solutions for CO2 storage through its End-to-End CCS offering.

Project Canary offers continuous emissions monitoring and certification for CCUS operations, addressing MRV requirements under Subpart RR.

Action Checklist

• Evaluate capture costs against 45Q credit values for your specific CO2 source concentration and volume
• Assess proximity to existing CO2 pipeline infrastructure and characterized storage sites before site selection
• Determine whether your project falls under EPA or state primacy jurisdiction and plan permitting timelines accordingly
• Model project economics including 45Q transferability discounts (8-15%) if your organization cannot use tax credits directly
• Develop MRV plans aligned with EPA Subpart RR requirements, incorporating continuous monitoring technologies
• Engage with communities along proposed pipeline routes or near storage sites early in the development process
• Explore CCUS-as-a-service options if your facility emits under 500,000 tonnes annually
• Monitor state primacy application status, particularly Texas, which will significantly impact Gulf Coast project timelines

FAQ

Q: What is the minimum facility size that makes CCUS economically viable under 45Q? A: For high-purity sources (ethanol, natural gas processing), facilities capturing as little as 12,500 tonnes per year can qualify for 45Q. For industrial sources requiring post-combustion capture, practical economics generally require at least 100,000 tonnes per year to amortize capture equipment costs. Direct air capture facilities are being designed at 100,000 to 1 million tonnes per year to achieve economies of scale, though smaller modular DAC units (1,000-10,000 tonnes) are under development.

Q: How does the 45Q transferability market work in practice? A: Project developers that cannot use tax credits directly can sell them to corporate buyers with tax liability. Transfer prices in 2025 ranged from $0.85 to $0.92 per dollar of credit face value, depending on project risk, credit vintage, and buyer creditworthiness. Transactions are typically structured as multi-year agreements where the buyer pre-commits to purchasing credits over the 12-year credit period. Brokers including Crux Climate and Reunion Infrastructure facilitate these transactions.

Q: What monitoring technologies are required for Class VI well permits? A: EPA requires a comprehensive monitoring plan including: pre-injection site characterization (seismic surveys, well logging, baseline groundwater testing), operational monitoring (injection pressure, rate, volume, and wellhead temperature), and post-injection monitoring (typically 50 years of groundwater and soil gas monitoring after cessation of injection). Technologies include downhole pressure and temperature gauges, groundwater sampling wells, surface deformation monitoring via InSAR, and periodic seismic surveys to track the CO2 plume.

Q: How does US CCUS policy compare to the EU ETS approach? A: The US provides a fixed per-tonne subsidy (45Q) that is independent of carbon market prices, while the EU relies on emissions trading where the carbon price fluctuates with market conditions. The US approach provides more revenue certainty for project developers but does not create the economy-wide price signal that drives emissions reductions across all sectors. The EU approach is more economically efficient in theory but creates financing uncertainty that has limited European CCUS deployment to date. Both approaches are increasingly being supplemented with additional policy tools.

Q: What happens to CCUS projects when the 45Q credit expires after 12 years? A: Projects must either achieve standalone profitability or secure alternative revenue. For industrial capture, ongoing operational savings from selling CO2 for utilization or avoided carbon compliance costs may sustain operations. For DAC, voluntary carbon credit markets could provide ongoing revenue if prices remain above operating costs ($200-400 per tonne for current technology). Some developers are structuring projects with the assumption that federal or state carbon pricing will be in place before 45Q expiration, providing a replacement revenue stream.

Sources

• US Department of Energy, National Energy Technology Laboratory. (2025). Carbon Storage Atlas, Sixth Edition. Morgantown, WV: NETL.
• Global CCS Institute. (2025). Global Status of CCS: 2025 Report. Melbourne: GCCSI.
• Internal Revenue Service. (2024). Final Regulations on Section 45Q Credit for Carbon Oxide Sequestration. Washington, DC: IRS.
• Larson, E. et al. (2021). Net-Zero America: Potential Pathways, Infrastructure, and Impacts. Princeton, NJ: Princeton University.
• Congressional Research Service. (2025). Carbon Capture and Sequestration: Status, Policy, and the 45Q Tax Credit. Washington, DC: CRS.
• Environmental Protection Agency. (2025). Underground Injection Control Program: Class VI Wells Status Report. Washington, DC: EPA.
• BloombergNEF. (2025). US Carbon Capture Market Outlook: Projects, Policy, and Investment Trends. New York: Bloomberg LP.