Trend watch: Carbon transport & storage infrastructure in 2026 — signals, winners, and red flags

Carbon transport and storage infrastructure is entering what may prove to be its most consequential year. After decades of pilot projects and false starts, the combination of regulatory mandates, industrial demand, and bankable revenue models is driving the first wave of commercial-scale CO2 pipeline and storage networks. The UK alone has committed GBP 21.7 billion in support for carbon capture, usage, and storage (CCUS) through Track-1 and Track-2 cluster selections, while the European Commission has approved over EUR 7 billion in state aid for cross-border CO2 infrastructure projects. But the gap between announced capacity and operational infrastructure remains vast, and 2026 will reveal which projects clear the engineering and commercial hurdles and which join the long list of CCS ambitions that never reached final investment decision.

Why It Matters

The Intergovernmental Panel on Climate Change's Sixth Assessment Report identifies CCS as essential for limiting warming to 1.5 degrees Celsius, with modeled pathways requiring 5.9 to 8.3 gigatonnes of annual CO2 capture and storage by 2050. Current operational storage capacity globally stands at approximately 45 million tonnes per year (Mtpa), meaning a 130-fold to 185-fold increase is required within 25 years. This scale-up depends entirely on transport and storage infrastructure: without pipelines, ships, and verified geological storage sites, capture facilities have nowhere to send their CO2.

The infrastructure challenge is particularly acute for hard-to-abate industrial sectors. Cement production, steelmaking, chemicals manufacturing, and refining account for approximately 30% of global CO2 emissions and have limited pathways to decarbonization beyond CCS. These industries cannot electrify their process emissions (as distinct from energy emissions), making permanent geological storage the primary abatement option. The International Energy Agency estimates that 70% of the CO2 captured in net-zero scenarios comes from industrial point sources, all of which require connection to transport and storage networks.

For the UK specifically, the stakes are existential for industrial competitiveness. The Humber industrial cluster alone accounts for approximately 12.4 Mtpa of CO2 emissions from refineries, chemicals plants, power stations, and steelworks. Without CCS infrastructure, these facilities face either closure or relocation to jurisdictions with weaker carbon pricing. The UK government's 2025 Autumn Budget confirmed ongoing support for the East Coast Cluster and HyNet North West, but conditioned continued funding on projects meeting construction milestones by mid-2026.

Key Signals to Watch

Pipeline Permitting Acceleration

The single most important signal for 2026 is whether CO2 pipeline permitting timelines compress to match political ambitions. In the UK, the Planning Inspectorate granted development consent for the Northern Endurance Partnership's offshore CO2 pipeline in 2025 after a 30-month examination process. For context, the Longship project in Norway secured permits in approximately 18 months. The UK government's 2024 planning reform package included provisions to classify CO2 transport infrastructure as "nationally significant," potentially reducing determination periods by 6 to 12 months. Engineers should monitor whether the first Track-2 projects (Viking CCS and Acorn) achieve planning milestones on accelerated timelines, as this will set the cadence for all subsequent UK infrastructure.

On the European continent, the European Commission designated six CO2 transport projects as Projects of Common Interest (PCIs) under the revised TEN-E regulation, qualifying them for streamlined permitting and EU co-financing. The Porthos pipeline connecting Rotterdam's industrial zone to depleted gas fields in the Dutch North Sea secured all permits by late 2025 and began construction, making it a bellwether for continental infrastructure delivery.

Ship-Based CO2 Transport Maturation

The emergence of ship-based CO2 transport represents a potentially transformative development for markets where pipeline economics are challenging. Northern Lights, the Norwegian state-backed storage project, commissioned its first CO2 carrier vessel in 2024 with a capacity of 7,500 cubic meters of liquefied CO2 per voyage. The project's Phase 1 storage capacity of 1.5 Mtpa is fully contracted, with customers including Heidelberg Materials (cement capture in Brevik) and Yara (fertilizer production). Phase 2, expanding capacity to 5 Mtpa, reached final investment decision in 2025 with additional customers from Belgium, Sweden, and the Netherlands.

Ship-based transport fundamentally changes the economics of CCS for emitters distant from storage sites. A cement plant in southern England or a waste-to-energy facility in Denmark can ship captured CO2 to Norwegian storage sites at costs of EUR 40 to 70 per tonne (including liquefaction, shipping, and injection), competitive with dedicated pipeline connections for volumes below approximately 1 Mtpa. Dan-Unity CO2, a joint venture between Ultragas and Evergas, ordered four 12,000 cubic meter CO2 carriers in 2025, signaling commercial confidence in the maritime transport model.

Storage Appraisal Results

Geological storage capacity is theoretically abundant but commercially proven capacity remains scarce. The UK's North Sea Transition Authority (NSTA) awarded 21 carbon storage licenses in its first licensing round in 2023, covering an estimated 200 Mtpa of theoretical capacity. However, moving from licensed acreage to bankable storage capacity requires detailed geological appraisal: seismic surveys, appraisal drilling, and reservoir modeling that typically costs GBP 50 to 150 million per site and takes 3 to 5 years.

In 2026, several critical appraisal wells will report results. bp's Northern Endurance Partnership (supporting the East Coast Cluster) completed its first appraisal well in the Endurance aquifer in late 2025, confirming initial capacity estimates of approximately 450 million tonnes total storage. Harbour Energy's Viking CCS project in the Southern North Sea is drilling appraisal wells targeting depleted gas reservoirs with estimated capacity of 300 million tonnes. These results will either confirm or undermine the UK's assumption that sufficient storage capacity exists to support its CCUS ambitions. A negative appraisal result at any major site would trigger a significant reassessment of the national CCS strategy.

Emerging Winners

The East Coast Cluster (Teesside and Humber)

The East Coast Cluster, encompassing the Net Zero Teesside and Zero Carbon Humber initiatives, is positioned as the UK's flagship CCS infrastructure project. The cluster connects approximately 20 industrial emitters to shared pipeline infrastructure routing CO2 to offshore storage in the Endurance aquifer beneath the Southern North Sea. bp leads the transport and storage company (Northern Endurance Partnership), while individual capture projects are led by operators including Kellas Midstream, Mitsubishi Chemical, and CF Industries.

The cluster's competitive advantage lies in emitter density: over 50% of the UK's industrial emissions are concentrated within 30 miles of the planned pipeline corridor. This density reduces per-tonne transport costs to approximately GBP 10 to 15 per tonne, compared to GBP 25 to 40 for more dispersed configurations. The UK government allocated GBP 2 billion in capital grants and 15-year transport and storage regulated asset base (RAB) contracts in its Track-1 negotiations, providing revenue certainty that enabled project financing. Construction of onshore pipeline sections began in late 2025, with first CO2 injection targeted for 2028.

Northern Lights (Norway)

Northern Lights has established itself as Europe's open-access CO2 storage provider, offering commercial storage services to any qualified emitter willing to ship CO2 to its facilities near Bergen. The project's commercial model, charging a per-tonne storage fee rather than requiring equity participation, lowers barriers to entry for industrial emitters that lack the capital or expertise to develop their own storage. Phase 1 operations commenced in 2025, processing CO2 from Heidelberg Materials' Brevik cement plant in the world's first commercial cross-border CO2 transport and storage operation.

The project's significance extends beyond its own capacity. Northern Lights has created a reference price for CO2 storage in Europe (approximately EUR 50 to 80 per tonne for Phase 1, declining toward EUR 35 to 50 for Phase 2), enabling emitters across the continent to calculate the cost of CCS with reasonable precision. This price transparency is accelerating investment decisions by industrial emitters who previously faced unquantifiable storage cost uncertainty.

Carbon Capture and Storage Association (CCSA) Member Companies

Engineering firms with demonstrated CCS expertise are experiencing unprecedented demand. Worley, Technip Energies, and Wood have secured front-end engineering design (FEED) contracts across multiple UK and European clusters. Aker Carbon Capture, which provides the proprietary solvent technology for several European capture projects, saw its order backlog increase by 340% between 2023 and 2025. For engineering professionals, CCS project experience has become a differentiating career asset, with project engineer salaries for CCS specialists exceeding conventional oil and gas roles by 15 to 25% in the UK market.

Red Flags

Business Model Uncertainty for Transport Operators

The regulated asset base (RAB) model proposed for UK CO2 transport and storage infrastructure remains untested for this asset class. Under RAB, transport operators receive a guaranteed return on capital regardless of utilization, similar to the model used for electricity transmission networks. However, CO2 pipeline utilization depends on capture project timelines that are controlled by separate entities with different financial structures and risk profiles. If capture projects delay (as has happened historically with CCS), transport operators could operate at low utilization while still receiving regulated returns, creating a stranded infrastructure risk borne by consumers or taxpayers. The UK's Track-1 contract negotiations addressed this partially through "ramp-up" provisions, but the risk remains material for Track-2 and subsequent clusters.

Cost Escalation in Offshore Infrastructure

Offshore pipeline and well construction costs have escalated significantly since the original cost estimates for most UK CCS projects were developed. The offshore construction vessel market is experiencing capacity constraints, with day rates for pipelay vessels increasing by 40 to 60% between 2022 and 2025 due to competition from offshore wind and oil and gas decommissioning projects. Steel pipe costs have similarly increased. Several industry sources indicate that Track-1 project costs have increased by 25 to 35% from initial estimates, requiring renegotiation of government support levels. If this cost inflation persists, later clusters may face capital costs that undermine the economic case for CCS relative to alternative decarbonization pathways.

Monitoring, Reporting, and Verification (MRV) Gaps

Permanent geological storage requires continuous monitoring over decades to centuries to verify that injected CO2 remains contained. The regulatory framework for long-term storage monitoring in the UK and EU has been established in principle (under the EU CCS Directive and its UK equivalent), but operational MRV protocols for commercial-scale storage remain immature. Key unresolved questions include: Who bears liability for stored CO2 after the operator's license period expires? What monitoring frequency and technology standards are sufficient to satisfy regulators and insurers? How will monitoring costs (estimated at GBP 2 to 5 per tonne stored, annually, for 20+ years post-injection) be funded? Northern Lights' operational experience will provide initial answers, but regulatory clarity on these questions is essential for scaling storage beyond first-mover projects.

Hydrogen Pivot Risk

Several planned CCS projects in the UK are linked to blue hydrogen production, where natural gas is reformed into hydrogen with the resulting CO2 captured and stored. However, the economics of green hydrogen (produced via electrolysis powered by renewables) have improved faster than most projections, with electrolyzer costs declining by approximately 40% between 2022 and 2025. If green hydrogen reaches cost parity with blue hydrogen before CCS infrastructure is operational, blue hydrogen facilities may become stranded assets, reducing demand for CO2 transport and storage capacity. The HyNet North West cluster, where hydrogen production represents a significant portion of planned CO2 volumes, is particularly exposed to this risk.

Action Checklist

• Track planning consent decisions for Track-2 CCS projects (Viking CCS and Acorn) as indicators of permitting velocity
• Monitor Northern Lights Phase 1 operational performance data for real-world storage costs and injection rates
• Assess appraisal well results from the Endurance aquifer and Viking CCS storage sites for capacity confirmation
• Evaluate ship-based CO2 transport options for emitters located more than 200 km from planned pipeline corridors
• Review RAB contract terms for CO2 transport as templates for future infrastructure investment decisions
• Budget for 25 to 35% cost contingency on offshore pipeline and well construction based on current market inflation
• Engage with NSTA on carbon storage license applications before the next licensing round (expected 2027)
• Develop MRV protocols aligned with the UK Storage of Carbon Dioxide (Licensing etc.) Regulations

FAQ

Q: What is the current cost range for CO2 pipeline transport in the UK? A: Onshore CO2 pipeline transport costs range from GBP 5 to 15 per tonne for distances under 100 km, depending on throughput volumes and pipeline diameter. Offshore pipeline costs are significantly higher, ranging from GBP 15 to 35 per tonne due to subsea installation, corrosion protection, and compression requirements. Shared infrastructure models (where multiple emitters use a common pipeline) reduce per-tonne costs by 40 to 60% compared to dedicated single-emitter pipelines, which is the fundamental economic rationale for the UK's cluster approach.

Q: How does ship-based CO2 transport compare to pipelines on cost? A: Ship-based transport (including onshore liquefaction, port handling, voyage, and offshore injection) currently costs EUR 40 to 70 per tonne for distances of 500 to 1,500 km. Pipelines are more economical for high-volume, short-distance transport (below EUR 15 per tonne for onshore routes under 100 km), but ships become competitive for distances exceeding approximately 300 km or volumes below 1 Mtpa. Ships also offer flexibility: emitters can access storage sites in different jurisdictions without committing to fixed pipeline infrastructure, and shipping contracts can be structured for shorter terms than pipeline tolling agreements.

Q: What geological formations are suitable for CO2 storage? A: Three formation types are used for CO2 storage: depleted oil and gas reservoirs (well-characterized geology with proven containment, but limited total capacity), deep saline aquifers (vast theoretical capacity but requiring more extensive appraisal to confirm seal integrity), and basalt formations (where CO2 mineralizes into stable carbonates, as demonstrated by Iceland's CarbFix project). The UK's North Sea offers both depleted gas reservoirs and saline aquifers, with estimated total storage capacity of 70 to 80 billion tonnes, sufficient for over 200 years of industrial emissions at current rates.

Q: What are the primary safety considerations for CO2 pipelines? A: CO2 pipelines operate at high pressure (typically 100 to 150 bar) to maintain CO2 in a dense or supercritical phase. The primary risks are pipeline rupture leading to CO2 release (CO2 is an asphyxiant at concentrations above 5%), impurity-induced corrosion (water and hydrogen sulfide in the CO2 stream can cause internal corrosion), and fracture propagation in cold climates (CO2 depressurization causes significant cooling, potentially embrittling steel). These risks are well understood from existing CO2 pipeline operations: over 8,000 km of CO2 pipelines operate safely in the United States, primarily serving enhanced oil recovery operations. UK and European standards (BS PD 8010 and DNV-ST-F101) address CCS-specific design requirements.

Q: When will UK CCS infrastructure be operational? A: The East Coast Cluster targets first CO2 injection in 2028, with ramp-up to full capacity of approximately 4 Mtpa by 2030. HyNet North West targets first injection in 2028 to 2029. Track-2 projects (Viking CCS and Acorn in Scotland) are approximately 2 to 3 years behind Track-1 timelines, with first operations expected in 2030 to 2031. The UK government's target of 20 to 30 Mtpa of CO2 capture and storage capacity by 2030 is widely regarded by industry as achievable only if Track-1 projects remain on schedule and Track-2 projects reach final investment decision by mid-2026.

Sources

• UK Department for Energy Security and Net Zero. (2025). Carbon Capture, Usage and Storage: Track-1 and Track-2 Project Updates. London: DESNZ.
• International Energy Agency. (2025). CCUS in Clean Energy Transitions: 2025 Update. Paris: IEA Publications.
• Northern Lights JV DA. (2025). Annual Report 2024: Europe's First Commercial CO2 Transport and Storage Service. Bergen: Northern Lights.
• North Sea Transition Authority. (2025). Carbon Storage Licensing Round 1: Progress Report. Aberdeen: NSTA.
• Global CCS Institute. (2025). Global Status of CCS 2025. Melbourne: GCCSI.
• IPCC. (2023). AR6 Synthesis Report: Climate Change 2023. Geneva: IPCC Secretariat.
• Carbon Capture and Storage Association. (2025). UK CCS Delivery Plan: Infrastructure Requirements and Timeline Assessment. London: CCSA.
• Bloomberg New Energy Finance. (2025). CCS Market Outlook: Costs, Policy, and Project Pipeline. London: BloombergNEF.