Deep dive: Carbon transport & storage infrastructure — the fastest-moving subsegments to watch

Global CO2 pipeline capacity surged past 12,500 kilometers of permitted or under-construction routes in 2025, a 340% increase from 2022 levels, according to the Global CCS Institute's annual status report. Yet less than 30% of announced carbon transport and storage projects have reached final investment decision, revealing a sector where ambition vastly outpaces execution and where procurement teams must distinguish genuine infrastructure buildout from speculative announcements.

Why It Matters

Carbon capture, utilization, and storage (CCUS) only works at scale if captured CO2 can be moved efficiently from emitters to permanent storage sites. The transport and storage midstream segment has emerged as the critical bottleneck. The International Energy Agency estimated in its 2025 Net Zero Roadmap update that global CO2 transport and storage capacity must reach 1.2 gigatonnes per annum (Gtpa) by 2030 to remain on track for net zero by 2050, compared to roughly 50 million tonnes per annum (Mtpa) of operational capacity at the end of 2025.

The economic case is shifting rapidly. The US Inflation Reduction Act's Section 45Q credit provides $85 per tonne for geological storage and $60 per tonne for enhanced oil recovery, creating a revenue floor that supports infrastructure financing. The EU's Net Zero Industry Act targets 50 Mtpa of CO2 injection capacity by 2030, with member states required to identify and permit storage sites. In the Asia-Pacific region, Australia's Safeguard Mechanism reforms and Japan's Green Transformation (GX) strategy have catalyzed investment in offshore storage hubs, with over $14 billion committed across six major projects since 2024.

For procurement professionals, the implications are direct. Industrial emitters in hard-to-abate sectors (cement, steel, chemicals, refining) face tightening emissions regulations and carbon border adjustments. Access to reliable, cost-competitive CO2 transport and storage is becoming a procurement requirement alongside traditional energy and raw materials sourcing.

Key Concepts

CO2 Pipeline Networks remain the most cost-effective method for transporting large volumes of CO2 over distances of 100 to 1,500 kilometers. Supercritical CO2 (maintained above 31.1 degrees Celsius and 73.8 bar) flows through carbon steel pipelines at densities approaching liquid phase, enabling throughput of 5 to 30 Mtpa per pipeline depending on diameter. Design, permitting, and construction timelines range from 4 to 8 years for major trunk lines. The US Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) finalized updated CO2 pipeline safety regulations in late 2024, addressing ductile fracture propagation risks that had stalled several proposed routes.

Ship-Based CO2 Transport has emerged as a viable alternative for offshore storage access and cross-border CO2 trade. Liquefied CO2 carriers operating at approximately -50 degrees Celsius and 7 bar pressure can transport 10,000 to 50,000 cubic meters per voyage. Northern Lights, the Norwegian state-backed project, demonstrated commercial-scale ship transport in 2024 with its first carrier deliveries to the Langskip terminal. Ship transport becomes cost-competitive with pipelines at distances exceeding 500 to 700 kilometers for volumes below 5 Mtpa.

Geological Storage Site Characterization involves detailed assessment of subsurface formations for CO2 injection capacity, injectivity, and containment integrity. Saline aquifers represent the largest global storage resource (estimated at 8,000 to 55,000 Gt of theoretical capacity), followed by depleted oil and gas reservoirs (900 to 1,200 Gt). Commercial storage operations require extensive appraisal drilling, 3D seismic surveys, and reservoir simulation modeling over 2 to 5 years before injection can begin.

CO2 Hubs and Clusters aggregate emissions from multiple industrial sources into shared transport and storage infrastructure, reducing per-tonne costs through economies of scale. The hub model allows smaller emitters (those producing fewer than 500,000 tonnes per year) to access storage that would be uneconomic on a standalone basis. Hub development requires complex multi-party agreements covering tariff structures, capacity allocation, and liability frameworks.

Monitoring, Verification, and Accounting (MVA) encompasses the technologies and protocols that confirm CO2 remains permanently stored. Regulatory frameworks typically require monitoring for 20 to 50 years post-injection, including pressure monitoring, groundwater sampling, surface flux measurements, and periodic seismic surveys. The cost of long-term MVA adds $3 to $8 per tonne to total storage costs.

Carbon Transport & Storage KPIs: Benchmark Ranges

Metric	Below Average	Average	Above Average	Top Quartile
Pipeline Transport Cost (per tonne per 250km)	>$8	$5-8	$3-5	<$3
Ship Transport Cost (per tonne per 1,000km)	>$25	$18-25	$12-18	<$12
Storage Cost (per tonne injected)	>$20	$12-20	$8-12	<$8
Storage Site Utilization Rate	<50%	50-70%	70-85%	>85%
Permitting Timeline (pipeline, years)	>7	5-7	3-5	<3
Hub Anchor Tenant Commitment	<2 Mtpa	2-5 Mtpa	5-10 Mtpa	>10 Mtpa
MVA Cost (per tonne, lifecycle)	>$8	$5-8	$3-5	<$3

What's Working

US Gulf Coast Pipeline Buildout

The US Gulf Coast has become the global epicenter of CO2 pipeline development, with over 4,800 kilometers of new routes permitted or under construction as of early 2026. Denbury (acquired by ExxonMobil in 2023 for $4.9 billion) operates the largest existing CO2 pipeline network in the US at approximately 1,300 miles, providing a backbone for expanded industrial capture projects. The Section 45Q credit structure has attracted major pipeline developers including Summit Carbon Solutions, Navigator CO2 Ventures, and Wolf Carbon Solutions. Summit's Midwest Carbon Express, designed to transport 12 Mtpa from ethanol facilities to storage in North Dakota, represents the largest single pipeline project globally. The combination of established permitting pathways, proven geological storage in Gulf Coast formations, and strong policy incentives has created the most investable environment for CO2 transport infrastructure worldwide.

Northern Lights and European Ship Transport

Northern Lights, a joint venture between Equinor, Shell, and TotalEnergies, achieved a milestone in 2024 by commencing commercial CO2 shipping operations from continental European capture sites to offshore storage beneath the Norwegian continental shelf. Phase 1 provides 1.5 Mtpa capacity with Phase 2 expansion to 5 Mtpa approved in mid-2025. The project has signed offtake agreements with Yara (fertilizer production capture), Heidelberg Materials (cement capture), and multiple industrial emitters in Belgium and the Netherlands. Northern Lights has demonstrated that ship-based transport enables cross-border CO2 trade, decoupling capture locations from storage geology and creating a genuinely flexible market.

Australia's Offshore Storage Hubs

Australia has leveraged its extensive offshore sedimentary basins to develop large-scale storage infrastructure. Santos' Moomba CCS project in South Australia began injection in 2024, targeting 1.7 Mtpa into depleted gas reservoirs. The Gorgon CO2 injection project, despite early operational challenges, has stored over 8 million tonnes since 2019 and provides critical operational learning. Japan's JOGMEC and Inpex have jointly invested in the Bonaparte Basin CCS hub in northern Australia, designed to receive CO2 shipped from Japanese industrial sources. The Australian government's Offshore Petroleum and Greenhouse Gas Storage Act provides a mature regulatory framework for storage permitting, giving the country a significant first-mover advantage in the Asia-Pacific region.

What's Not Working

Permitting Delays and Community Opposition

CO2 pipeline permitting has proven far more contentious than project developers anticipated. Summit Carbon Solutions' Midwest Carbon Express faced permit denials in South Dakota in 2024, requiring route modifications and extensive re-engagement with landowners. Navigator CO2 Ventures cancelled its Heartland Greenway pipeline in late 2023 after failing to secure eminent domain authority in Iowa and South Dakota. These setbacks reflect broader public concerns about pipeline safety, particularly following the 2020 Satartia, Mississippi CO2 pipeline rupture that hospitalized 45 people. Updated PHMSA safety rules address technical risks but do not resolve the fundamental challenge of securing right-of-way across hundreds of private landholdings.

Storage Capacity Uncertainty and Appraisal Costs

While theoretical global storage capacity is enormous, commercially viable capacity (sites with adequate injectivity, proximity to transport routes, and acceptable geological risk) is far more limited. The US Department of Energy's CarbonSAFE program has funded characterization of over 80 potential storage sites, but fewer than 15 have advanced to the detailed site characterization phase. Appraisal costs for a single storage complex typically range from $50 million to $200 million over 3 to 5 years, creating significant pre-FID capital requirements. Several high-profile projects have been downscoped or abandoned after appraisal drilling revealed lower-than-expected injectivity or caprock integrity concerns.

Liability and Long-Term Stewardship Frameworks

The question of who bears responsibility for stored CO2 over centuries remains incompletely resolved in most jurisdictions. The EU CCS Directive requires operators to maintain responsibility for a minimum of 20 years post-closure before transferring liability to the state. US EPA's Class VI well permits require financial assurance but lack a clear federal mechanism for long-term liability transfer. This uncertainty increases the cost of capital for storage projects and deters risk-averse institutional investors. Insurance markets for CO2 storage liability remain nascent, with Munich Re and Swiss Re offering limited coverage at premiums that add $2 to $5 per tonne to project economics.

Key Players

Infrastructure Developers

ExxonMobil has positioned itself as the dominant US player through the Denbury acquisition, controlling the largest existing CO2 pipeline network and pursuing multiple Gulf Coast storage hubs with a stated target of 50 Mtpa capacity by 2030.

Equinor leads European storage development through Northern Lights and has announced additional storage licenses in the UK and Danish North Sea, targeting 30 Mtpa of total managed storage capacity by 2035.

Santos operates Australia's most advanced onshore CCS project at Moomba and is developing additional storage capacity in the Cooper Basin and offshore Browse Basin.

Technology and Service Providers

Schlumberger (SLB) provides integrated subsurface characterization, well design, and monitoring services for CO2 storage, leveraging decades of oil and gas reservoir expertise.

Aker Carbon Capture supplies modular capture equipment designed for integration with transport infrastructure, with standardized compression and conditioning packages for pipeline-ready CO2.

Key Investors and Funders

US Department of Energy has allocated over $12 billion through the Bipartisan Infrastructure Law for CCUS, including $2.5 billion for carbon storage validation and testing.

European Investment Bank has provided concessional financing for Northern Lights Phase 2 and several EU Innovation Fund-supported transport projects.

Japan Bank for International Cooperation (JBIC) has financed cross-border storage projects in Australia and Southeast Asia, reflecting Japan's strategic commitment to CCS as an industrial decarbonization pathway.

Action Checklist

• Map your facility's CO2 emissions profile (volume, purity, pressure) against regional transport and storage options within 500 kilometers
• Assess eligibility for Section 45Q credits, EU Innovation Fund support, or equivalent regional incentives before evaluating transport contracts
• Engage with hub developers early to secure capacity allocation and negotiate favorable tariff structures for anchor or near-anchor tenant status
• Require storage operators to demonstrate Class VI permit status (US) or equivalent regulatory approvals before committing to long-term offtake agreements
• Include force majeure, liability transfer, and monitoring obligation clauses in all transport and storage contracts
• Evaluate ship-based transport alternatives for offshore storage access, particularly where pipeline routes face permitting or social license challenges
• Budget for 3 to 5 year lead times between project commitment and first CO2 delivery to storage

FAQ

Q: What is the realistic cost of CO2 transport and storage in 2026? A: All-in costs (transport plus injection plus monitoring) range from $15 to $35 per tonne for pipeline-connected onshore storage and $25 to $55 per tonne for ship-based transport to offshore storage. These costs are before policy incentives. With Section 45Q ($85 per tonne for geological storage), most projects generate positive economics for emitters with capture costs below $50 to $60 per tonne.

Q: How do I evaluate whether a storage project will actually be operational when I need it? A: Look for three indicators: final investment decision (FID) backed by named equity investors, Class VI or equivalent regulatory permits in hand, and signed engineering, procurement, and construction (EPC) contracts with named contractors. Projects that have only announced memoranda of understanding or completed feasibility studies have a historically high attrition rate of 60 to 70%.

Q: Is ship-based CO2 transport commercially proven? A: Yes, as of 2024-2025. Northern Lights has demonstrated commercial-scale ship transport with purpose-built carriers. Several additional shipping companies, including Dan-Unity CO2 and Larvik Shipping, are building CO2 carrier fleets. Ship transport is particularly attractive for emitters located near ports but far from onshore storage formations, and for cross-border CO2 trade where pipeline construction faces jurisdictional complexity.

Q: What are the biggest risks in signing a long-term CO2 storage contract? A: Key risks include: storage operator insolvency or project abandonment (mitigate through parent company guarantees and escrow arrangements); regulatory changes affecting storage permits or liability frameworks; storage capacity underperformance requiring alternative disposal arrangements; and transport infrastructure delays or capacity constraints. Contracts should address each of these scenarios with clear remedies and exit provisions.

Q: How does Asia-Pacific CO2 storage compare to North American and European options? A: Asia-Pacific storage development lags North America and Europe by 3 to 5 years in regulatory maturity but offers substantial geological potential, particularly in Australia's offshore basins, Southeast Asian depleted gas fields, and Japan's sub-seabed formations. Costs are generally 10 to 20% higher due to offshore locations and less developed supply chains. Cross-border transport (primarily Japan to Australia and Southeast Asia) adds complexity but is commercially viable via ship transport.

Sources

• Global CCS Institute. (2025). Global Status of CCS 2025. Melbourne: GCCSI.
• International Energy Agency. (2025). CCUS in Clean Energy Transitions: 2025 Update. Paris: IEA Publications.
• US Department of Energy, Office of Fossil Energy and Carbon Management. (2025). Carbon Transport and Storage Infrastructure: Progress Report under the Bipartisan Infrastructure Law. Washington, DC: DOE.
• Northern Lights JV. (2025). Annual Report 2024: Commercial Operations and Phase 2 Expansion. Stavanger: Northern Lights DA.
• Pipeline and Hazardous Materials Safety Administration. (2024). Final Rule: Safety of Carbon Dioxide Pipelines. Federal Register, 89 FR 48254.
• Santos Limited. (2025). Moomba CCS Project: First Year Operations Report. Adelaide: Santos Limited.
• European Commission. (2025). Implementation of the Net Zero Industry Act: CO2 Storage Capacity Targets Progress Report. Brussels: EC.