Myths vs. realities: Carbon transport & storage infrastructure — what the evidence actually supports

Carbon capture without carbon transport and storage is an expensive exercise in futility. The CO2 has to go somewhere, and the infrastructure connecting capture facilities to permanent geological storage represents the least glamorous but most operationally critical segment of the entire CCS value chain. As of early 2026, the United States operates approximately 5,300 miles of dedicated CO2 pipelines, mostly concentrated in the Permian Basin for enhanced oil recovery. The Department of Energy estimates that reaching net-zero targets by 2050 will require 30,000 to 65,000 additional miles of CO2 pipeline capacity, a buildout rivaling the scale of the interstate natural gas pipeline network constructed over decades. Yet public discourse around carbon transport and storage remains clouded by persistent myths that distort investment decisions, misallocate policy attention, and slow permitting processes.

Why It Matters

The Inflation Reduction Act's enhanced 45Q tax credits, now offering $85 per metric ton for dedicated geological storage and $60 per ton for enhanced oil recovery, have catalyzed over $30 billion in announced CCS project investments since August 2022. The Bipartisan Infrastructure Law added $12 billion in direct federal funding for carbon management, including $2.1 billion for CO2 transport infrastructure and $3.5 billion for regional direct air capture hubs. These policy signals have transformed the economics of carbon transport and storage from speculative to commercially viable for the first time at scale.

However, translating policy incentives into operational infrastructure requires navigating a complex landscape of geological assessment, pipeline permitting, liability frameworks, and public acceptance. The EPA's Class VI well permitting backlog, which reached 109 pending applications by late 2025, illustrates the regulatory bottleneck. Meanwhile, state-level opposition to CO2 pipelines in Iowa, South Dakota, and Illinois has delayed multiple major projects, including Navigator CO2 Ventures' Heartland Greenway and Summit Carbon Solutions' Midwest Carbon Express.

For investors evaluating the $100+ billion in projected US carbon transport and storage investment through 2035, separating evidence-based assessments from industry hype and activist counter-narratives is essential. The reality, as documented by peer-reviewed research and operational data from existing projects, is more nuanced than either side typically presents.

Key Concepts

CO2 Pipeline Transport moves captured carbon dioxide in a dense or supercritical phase through steel pipelines at pressures typically between 1,200 and 2,200 psi. The US CO2 pipeline network has operated commercially since the early 1970s, with the Cortez Pipeline (1984) running 502 miles from southwestern Colorado to West Texas. CO2 pipelines share engineering principles with natural gas pipelines but require different metallurgy due to CO2's corrosive properties when combined with moisture, and different safety considerations given CO2's density (heavier than air) and asphyxiation risk at concentrations above 7-10%.

Geological Sequestration injects CO2 into deep saline formations, depleted oil and gas reservoirs, or basalt formations where it is trapped through structural, residite, dissolution, and mineral trapping mechanisms. The Sleipner project in Norway has stored over 20 million tonnes of CO2 since 1996 without detectable leakage, providing the longest operational dataset for saline aquifer storage. The US Geological Survey estimates domestic saline formation storage capacity between 2,400 and 21,200 billion metric tons, sufficient for centuries of industrial emissions at current rates.

Enhanced Oil Recovery (EOR) uses injected CO2 to increase oil production from mature reservoirs while permanently storing a portion of the injected gas. Approximately 80% of current US CO2 pipeline capacity serves EOR operations. While EOR provides revenue that improves project economics, its net climate benefit depends on lifecycle analysis including the additional oil produced and combusted, making its role in decarbonization contested.

Class VI Wells are the EPA-designated injection well category for long-term geological storage of CO2. The permitting process requires operators to demonstrate containment integrity, monitor injection zones, and maintain financial assurance for post-injection site care spanning at least 50 years. As of early 2026, EPA has issued only a handful of Class VI permits, with the majority of applications still under review.

CO2 Transport and Storage KPIs: Benchmark Ranges

Metric	Below Average	Average	Above Average	Top Quartile
Pipeline Transport Cost (per tonne per 100 mi)	>$4.50	$2.50-4.50	$1.50-2.50	<$1.50
Injection Rate (tonnes/day per well)	<1,500	1,500-3,000	3,000-5,000	>5,000
Storage Containment Verification	Unverified	Annual surveys	Continuous monitoring	Real-time with redundancy
Permitting Timeline (Class VI)	>48 months	30-48 months	18-30 months	<18 months
Storage Cost (per tonne)	>$20	$10-20	$6-10	<$6
Pipeline Utilization Rate	<50%	50-70%	70-85%	>85%
Monitoring Cost (annual per site)	>$3M	$1.5-3M	$0.8-1.5M	<$0.8M

What's Working

Established Pipeline Operations

The existing US CO2 pipeline network provides compelling operational evidence. The Denbury-operated Gulf Coast system, spanning approximately 1,300 miles across Mississippi, Louisiana, and Texas, has transported over 200 million tonnes of CO2 since the early 2000s with a safety record comparable to natural gas pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) data shows CO2 pipeline incident rates averaging 0.6 incidents per 1,000 miles per year, below the 0.8 rate for hazardous liquid pipelines overall. Occidental Petroleum's acquisition of Denbury for $12 billion in 2023 underscored the strategic value institutional capital places on existing CO2 transport assets.

Saline Aquifer Storage Demonstrations

Beyond Sleipner, the Illinois Basin Decatur Project operated by the Midwest Geological Sequestration Consortium injected over 1 million tonnes of CO2 into the Mount Simon Sandstone between 2011 and 2014. Monitoring through 2025 confirmed zero detectable leakage, with the CO2 plume behaving consistently with geological models. The Quest project in Alberta, operated by Shell, has stored over 8 million tonnes since 2015, maintaining 99.99% containment rates verified by third-party monitoring. These demonstrations validate geological storage as technically proven at commercial scale.

State-Level Primacy Programs

Louisiana became the first state to receive EPA approval for Class VI well primacy in January 2024, enabling the state to issue its own injection permits with substantially faster review timelines. North Dakota, Wyoming, and Texas have also received or are pursuing primacy authority. Louisiana's program approved its first Class VI permits within 9 months of receiving primacy, compared to the 24-48 months typical of EPA's federal process. This regulatory innovation has concentrated project development in primacy states.

What's Not Working

Permitting Bottlenecks

The EPA's Class VI permitting process remains the primary obstacle to storage deployment. With over 100 applications pending and fewer than 10 permits issued by early 2026, the timeline mismatch between 45Q credit-driven project planning (targeting operations by 2030-2032) and actual permitting capacity threatens to strand billions in announced investments. The Government Accountability Office's 2025 report found that EPA's Underground Injection Control program had fewer than 30 staff dedicated to Class VI reviews nationally.

Pipeline Siting Opposition

Three major Midwest CO2 pipeline projects, Navigator CO2 Ventures' Heartland Greenway, Summit Carbon Solutions' Midwest Carbon Express, and Wolf Carbon Solutions' Mount Simon project, have faced sustained opposition from landowners and environmental groups. Navigator abandoned its project entirely in late 2023 after failing to secure eminent domain authority in multiple states. Summit's project, the largest proposed at 2,500 miles, secured South Dakota Public Utilities Commission approval on its third attempt in 2025 but continues to face legal challenges. The opposition reflects both legitimate landowner concerns about easement terms and safety, and broader skepticism about whether CCS infrastructure extends fossil fuel dependence.

Cost Overruns and Financing Gaps

The Petra Nova project in Texas, which captured CO2 from a coal plant for EOR, suspended operations in 2020 after three years due to low oil prices undermining project economics. While it resumed limited operations in 2023, its troubled history illustrates the financial fragility of projects dependent on commodity price assumptions. The International CCS Knowledge Centre estimates that first-of-a-kind transport and storage projects typically exceed initial budgets by 25-40%, reflecting geological uncertainty, regulatory delays, and construction cost inflation.

Myths vs. Reality

Myth 1: CO2 pipelines are fundamentally more dangerous than natural gas pipelines

Reality: PHMSA data covering 5,300 miles of US CO2 pipeline operations over four decades shows comparable or lower incident rates relative to natural gas and hazardous liquid pipelines. The 2020 Satartia, Mississippi pipeline rupture, which hospitalized 45 people, was a significant incident, but subsequent investigation attributed it to geological instability (landslide) rather than pipeline engineering failure. Updated PHMSA safety regulations proposed in 2024 address CO2-specific risks including odorant requirements and valve spacing, further reducing residual risk.

Myth 2: Geological storage will inevitably leak, making it pointless

Reality: Over 25 years of monitoring data from Sleipner, Quest, Decatur, and smaller projects consistently demonstrate containment rates exceeding 99.9%. Geological formations that have held oil, gas, and brine for millions of years provide inherent sealing capacity. The IPCC's Special Report on CCS concluded that appropriately selected and managed sites are "very likely" to retain over 99% of stored CO2 for more than 1,000 years. The key qualifier is "appropriately selected." Poor site characterization, inadequate caprock assessment, or proximity to legacy wellbores can compromise containment.

Myth 3: CO2 transport and storage is prohibitively expensive without subsidies

Reality: At current 45Q credit levels ($85/tonne for saline storage), dedicated geological storage generates positive returns for projects with transport distances under 150 miles and injection rates above 1 million tonnes per year. However, without policy support, storage costs of $8-20 per tonne plus transport costs of $3-10 per tonne remain below carbon prices in most markets. The European Emissions Trading System, trading above EUR 60 per tonne in 2025, approaches economic viability for short-distance storage without additional subsidies. The honest assessment: current US deployment depends on policy support, but cost curves are declining as the industry scales.

Myth 4: CCS infrastructure is merely a lifeline for fossil fuel companies

Reality: While EOR-linked projects dominate today's CO2 pipeline network, the emerging project pipeline increasingly targets industrial emitters (cement, steel, chemicals) and direct air capture, sectors with limited decarbonization alternatives. The DOE's Regional Clean Hydrogen Hubs and Direct Air Capture Hubs are explicitly designed for non-fossil applications. Analysis by the Princeton Net-Zero America project found that even aggressive electrification and renewable deployment scenarios require 0.9 to 1.7 billion tonnes per year of CO2 storage by 2050 to address hard-to-abate sectors.

Key Players

Established Leaders

ExxonMobil Low Carbon Solutions has committed $17 billion in low-carbon investments through 2027, with the Houston CCS Hub targeting 50 million tonnes per year of storage capacity by 2030.

Occidental Petroleum (1PointFive) is constructing the world's largest direct air capture facility in the Permian Basin, with integrated CO2 transport and storage infrastructure leveraging Denbury's acquired pipeline network.

Equinor operates the Northern Lights project in Norway, the world's first open-access CO2 transport and storage service, with Phase 1 capacity of 1.5 million tonnes per year operational in 2025.

Emerging Players

Summit Carbon Solutions is developing the largest US CO2 pipeline network dedicated to ethanol plant capture, with 2,500 miles of proposed pipeline across five states.

Svante Technologies provides modular CO2 capture systems designed for integration with shared transport and storage infrastructure, reducing single-project scale requirements.

CarbonFree Chemicals develops mineralization-based CO2 storage as an alternative to geological injection, converting captured CO2 into construction materials.

Key Investors and Funders

US Department of Energy has allocated $12 billion under the Bipartisan Infrastructure Law for carbon management infrastructure, the largest public investment in CCS globally.

Brookfield Asset Management has committed substantial capital to carbon management infrastructure through its transition fund, reflecting institutional appetite for regulated, infrastructure-like CCS assets.

Oil and Gas Climate Initiative (OGCI) member companies have collectively committed $4.6 billion to CCUS investments, with transport and storage representing the primary focus.

Action Checklist

• Evaluate project economics using independently verified cost data, not vendor projections, with sensitivity analysis for 45Q credit phase-down scenarios
• Prioritize storage sites in states with Class VI primacy authority for faster permitting timelines
• Assess pipeline routing feasibility early, including landowner engagement and state-level eminent domain frameworks
• Require geological site characterization meeting or exceeding EPA Class VI standards, including 3D seismic surveys and legacy wellbore assessments
• Structure financial assurance for post-injection monitoring spanning minimum 50 years, as required under Class VI regulations
• Develop community engagement plans informed by lessons from Navigator and Summit project opposition
• Monitor PHMSA rulemaking on updated CO2 pipeline safety standards and incorporate compliance costs into project models
• Consider shared infrastructure models (multi-user pipelines and storage hubs) to reduce per-project costs and improve utilization rates

FAQ

Q: What is the realistic cost range for building a new CO2 pipeline in the US today? A: Capital costs range from $1.5 million to $4 million per mile depending on diameter (8-inch to 24-inch), terrain, and right-of-way complexity. A 100-mile, 16-inch pipeline carrying 5 million tonnes per year typically costs $200-300 million, translating to transport costs of $2-4 per tonne. Urban crossings, river crossings, and mountainous terrain can increase costs by 50-100%. Projects should budget 15-25% contingency for permitting delays and construction cost escalation.

Q: How long does it take to develop a CO2 storage site from initial assessment to first injection? A: In states with Class VI primacy (Louisiana, North Dakota, Wyoming), timelines of 3-5 years from site selection to operational injection are achievable. Under EPA's federal permitting process, timelines extend to 5-8 years. Key milestones include: geological characterization (12-24 months), permit application preparation and review (18-48 months), well drilling and completion (6-12 months), and operational testing (3-6 months). Early investment in geological characterization data reduces permitting risk and timeline.

Q: What happens to stored CO2 over thousands of years? A: CO2 injected into deep saline formations undergoes four trapping mechanisms that increase security over time. Structural trapping (beneath caprock) provides immediate containment. Residual trapping occurs within decades as CO2 becomes immobilized in pore spaces. Solubility trapping dissolves CO2 into formation brine over centuries. Mineral trapping converts dissolved CO2 into solid carbonate minerals over millennia. Geochemical modeling and natural analogues (natural CO2 reservoirs that have persisted for millions of years) confirm long-term stability.

Q: Is there enough storage capacity in the US for meaningful climate impact? A: The US Geological Survey estimates saline formation storage capacity between 2,400 and 21,200 billion metric tons. Even using the lower bound, this exceeds 400 years of total current US CO2 emissions. The constraint is not total capacity but the availability of characterized, permitted, accessible storage sites near emission sources. The DOE's CarbonSAFE program is systematically characterizing high-priority storage formations to convert theoretical capacity into bankable reserves.

Q: How do investors evaluate storage permanence risk? A: Leading investors require: site-specific geological characterization meeting EPA Class VI standards, independent third-party review of containment risk, long-term monitoring plans with defined contingency responses, and financial assurance mechanisms (insurance, bonds, or trust funds) covering post-injection care. The emerging market for carbon storage liability transfer, where specialized insurers assume long-term containment risk, is reducing investor exposure and enabling project-finance structures for storage assets.

Sources

• Global CCS Institute. (2025). Global Status of CCS 2025: Infrastructure and Investment Report. Melbourne: GCCSI.
• US Geological Survey. (2024). National Assessment of Geologic Carbon Dioxide Storage Resources: Updated Estimates. Reston, VA: USGS.
• Pipeline and Hazardous Materials Safety Administration. (2025). CO2 Pipeline Safety Incident Data, 1986-2025. Washington, DC: PHMSA.
• IPCC. (2005, updated 2023). Special Report on Carbon Dioxide Capture and Storage. Geneva: Intergovernmental Panel on Climate Change.
• Princeton University. (2024). Net-Zero America: Potential Pathways, Infrastructure, and Impacts (Interim Update). Princeton, NJ: Andlinger Center for Energy and the Environment.
• US Department of Energy. (2025). Carbon Management Strategy and Multi-Year Program Plan. Washington, DC: DOE Office of Fossil Energy and Carbon Management.
• Government Accountability Office. (2025). Carbon Capture and Storage: EPA Needs to Improve Class VI Well Permit Review Capacity. Washington, DC: GAO.
• International CCS Knowledge Centre. (2025). Lessons Learned from CCS Project Development: Cost, Schedule, and Risk Factors. Regina, SK: ICCSCK.