Case study: Carbon transport & storage infrastructure — a startup-to-enterprise scale story

Global investment in CO2 transport and storage infrastructure surpassed $5.2 billion in 2025, a threefold increase from 2022, yet fewer than 15% of announced pipeline and storage projects have reached final investment decision (Global CCS Institute, 2025). This case study traces how three companies navigated the journey from early-stage CO2 transport and storage ventures to enterprise-scale operations, revealing the permitting strategies, financing structures, and geological risk management approaches that separated projects that advanced from those that stalled.

Why It Matters

Decarbonizing heavy industry requires not only capturing CO2 at the source but also moving it safely to permanent storage sites. The International Energy Agency estimates that achieving net-zero emissions by 2050 will require approximately 1.2 gigatonnes per year of CO2 transport and storage capacity by 2030, compared to roughly 45 megatonnes per year operational today (IEA, 2025). The gap between current capacity and what is needed represents one of the largest infrastructure buildouts in the energy transition.

Regulatory momentum is accelerating on both sides of the Atlantic. The US Inflation Reduction Act's enhanced 45Q tax credit provides $85 per tonne for dedicated geological storage, making previously uneconomic projects viable. The EU's Net-Zero Industry Act sets a target of 50 megatonnes per year of CO2 injection capacity by 2030, with member states required to identify and permit storage sites. The UK's Track-1 and Track-2 cluster sequencing process has allocated over $22 billion in support for CCS infrastructure clusters in Teesside, Humberside, and the Scottish Cluster.

For policy and compliance professionals, understanding how CO2 transport and storage startups scale is essential for evaluating infrastructure readiness, permitting timelines, and the commercial viability of decarbonization pathways that depend on CCS. Projects that fail to scale leave industrial emitters without viable compliance strategies and delay emission reductions in sectors where alternatives to CCS remain limited.

Key Concepts

CO2 pipeline transport involves moving captured carbon dioxide from emission sources to storage sites through dedicated pipelines. CO2 is typically transported in a dense or supercritical phase at pressures above 73 atmospheres and temperatures between 13 and 44 degrees Celsius. Pipeline materials, compression station spacing, and route selection all affect project economics and permitting complexity.

Geological sequestration is the permanent storage of CO2 in deep underground formations, typically depleted oil and gas reservoirs or saline aquifers at depths exceeding 800 meters. Storage site characterization requires seismic surveys, well testing, and reservoir modeling to confirm that the formation has sufficient capacity, injectivity, and containment integrity to hold CO2 for thousands of years.

Class VI wells are the regulatory classification under the US Environmental Protection Agency's Underground Injection Control program specifically designed for CO2 geological sequestration. Class VI permits require extensive site characterization, monitoring plans, financial assurance, and post-injection site care commitments of at least 50 years. As of early 2026, the EPA has issued fewer than 20 Class VI permits, creating a significant bottleneck for US storage projects.

Hub-and-cluster models aggregate CO2 from multiple industrial emitters within a geographic area and transport it through shared pipeline infrastructure to common storage sites. This approach reduces per-tonne transport costs by 40 to 60% compared to point-to-point connections and distributes permitting and geological risk across multiple offtakers.

What's Working

Northern Lights: From Joint Venture Concept to Europe's First Open-Access CO2 Storage

Northern Lights, a joint venture between Equinor, Shell, and TotalEnergies, represents the most advanced example of a CO2 transport and storage project scaling from concept to commercial operation. The project, located offshore Norway beneath the North Sea, began as part of Norway's Longship CCS initiative in 2020 and reached operational status in 2025. Phase 1 provides 1.5 megatonnes per year of CO2 injection capacity, with Phase 2 expansion to 5 megatonnes per year approved and under development (Northern Lights, 2025).

The company's business model as an open-access transport and storage provider was critical to its scaling trajectory. Rather than building infrastructure tied to a single capture source, Northern Lights structured itself as a commercial service available to any industrial emitter willing to pay the transport and storage fee. This approach attracted customers beyond Norway's borders: the first commercial agreements included a cement plant in Brevik, Norway (Heidelberg Materials) and a waste-to-energy facility in the Netherlands. By Q4 2025, Northern Lights had signed memoranda of understanding with emitters in Germany, Belgium, and the UK, with aggregate contracted and prospective volumes exceeding 8 megatonnes per year.

The capital structure illustrates how public-private partnerships enable CCS infrastructure scaling. The Norwegian government provided approximately 80% of the $1.7 billion Phase 1 capital cost, with the three joint venture partners contributing the remainder. Phase 2, with an estimated cost of $1.1 billion, is being financed with a higher private capital share of approximately 50%, reflecting reduced geological and commercial risk after successful Phase 1 operations.

Summit Carbon Solutions: Building America's Largest CO2 Pipeline Network

Summit Carbon Solutions, headquartered in Ames, Iowa, is developing a 3,200-kilometer CO2 pipeline network designed to transport captured CO2 from 57 ethanol plants across five Midwestern US states to a sequestration hub in North Dakota. The project represents the largest proposed CO2 pipeline in US history, with a total capital cost estimated at $8 billion and injection capacity of 18 megatonnes per year (Summit Carbon Solutions, 2025).

Summit's scaling strategy was built around the ethanol industry's unique position: ethanol fermentation produces a nearly pure CO2 stream that requires minimal additional processing for capture, reducing capture costs to $25 to $35 per tonne compared to $60 to $100 per tonne for flue gas capture at power plants or cement kilns. This cost advantage, combined with the enhanced 45Q tax credit of $85 per tonne for geological storage, created a compelling unit economics case that attracted over $1 billion in committed equity from investors including Tiger Infrastructure Partners and TPG Rise Climate.

The project's primary scaling challenge has been right-of-way acquisition and state permitting. Pipeline routes cross thousands of private landholdings, and Summit faced organized opposition from landowner coalitions in South Dakota and Iowa. The company secured eminent domain authority in North Dakota and Iowa but was initially denied a permit in South Dakota in 2024 before reapplying with a modified route. By early 2026, Summit had acquired approximately 85% of required easements and secured permits in three of five states, with construction underway on initial segments in Iowa and North Dakota. The experience highlighted that for CO2 pipeline startups, community engagement and permitting strategy are as important as engineering and financing in determining scaling timelines.

Storegga and the Acorn Project: Repurposing Oil and Gas Infrastructure for CO2 Storage

Storegga, a UK-based company, developed the Acorn CCS project in northeast Scotland to repurpose existing oil and gas pipeline infrastructure for CO2 transport and storage. The Acorn project leverages the existing Goldeneye pipeline and platform, originally built for gas production, to transport CO2 from the St. Fergus gas terminal to depleted reservoirs beneath the North Sea. This infrastructure reuse strategy reduced estimated capital costs by approximately 40% compared to greenfield pipeline construction (Storegga, 2025).

The Acorn project's journey from concept to near-commercial status illustrates the challenges of government-dependent CCS scaling. Despite being technically the most advanced project in the UK's cluster sequencing process, Acorn was initially excluded from the Track-1 funding allocation in 2023, receiving Track-2 status instead. The decision created an 18-month delay in project timelines and forced Storegga to restructure its financing approach. The company responded by securing additional private investment, including a strategic partnership with a major energy company, and by expanding the project scope to include a CO2 import terminal capable of receiving shipborne CO2 from European emitters.

By 2025, the Acorn project had completed its front-end engineering and design (FEED) study, secured storage licenses from the North Sea Transition Authority, and established commercial agreements with industrial emitters representing approximately 3 megatonnes per year of CO2 supply. The project's storage capacity in the depleted Goldeneye reservoir and surrounding saline aquifers exceeds 100 megatonnes, providing decades of operational headroom.

What's Not Working

Permitting timelines remain the single largest obstacle to scaling CO2 transport and storage infrastructure. In the United States, Class VI well permit applications submitted to the EPA have averaged 3 to 5 years for review, with some applications pending for more than 6 years. While the EPA has delegated primacy to North Dakota, Wyoming, and Louisiana to issue their own Class VI permits, the delegated state programs are still developing capacity, with average review times of 12 to 24 months. These delays cascade through project timelines, affecting financing terms, offtake agreement validity, and construction schedules.

Pore space ownership disputes create legal uncertainty for storage projects. In many US states, the legal framework for subsurface pore space ownership is ambiguous or untested. Surface landowners, mineral rights holders, and the state itself may all assert claims to the geological formations where CO2 would be stored. Several projects have faced litigation from landowners who argue that CO2 injection beneath their property constitutes a trespass, even when the injection well is located on a different parcel. Legislative efforts to clarify pore space ownership are advancing in key states but remain incomplete.

Counterparty risk in long-term storage agreements deters commercial lenders. CO2 storage requires monitoring and liability management for 50 years or more after injection ceases. Lenders question whether startup or project-company counterparties will remain solvent over these timeframes. The absence of established government long-term stewardship frameworks in most jurisdictions, apart from Norway, means that storage operators must carry contingent liabilities on their balance sheets that reduce their ability to raise additional capital.

Ship-based CO2 transport economics remain uncertain at scale. While Northern Lights has demonstrated ship-based transport from continental Europe to Norway, costs of $40 to $70 per tonne for shipping, liquefaction, and intermediate storage are significantly higher than pipeline transport costs of $8 to $15 per tonne for distances under 500 kilometers. For emitters located far from pipeline networks, shipping costs can erode the economic case created by tax credits and carbon pricing.

Key Players

Established Companies

• Equinor: Norwegian energy company and lead operator of Northern Lights, providing geological expertise and offshore operations capability
• Shell: joint venture partner in Northern Lights and operator of multiple CCS projects including Quest in Alberta, Canada
• ExxonMobil: developing the largest proposed CCS hub in the US Gulf Coast with planned capacity exceeding 100 megatonnes per year
• Heidelberg Materials: global cement company and first commercial customer of Northern Lights, operating CCS at its Brevik plant in Norway

Startups

• Summit Carbon Solutions: developing the largest proposed CO2 pipeline network in the US, connecting 57 ethanol plants to geological storage in North Dakota
• Storegga: UK-based company leading the Acorn CCS project and developing CO2 shipping and import infrastructure in Scotland
• Deep Sky: Canadian startup developing CO2 storage hubs and direct air capture integration sites in Quebec
• Carbon Vault: US-based company developing in-situ mineralization storage technology that converts CO2 to solid carbonates in basalt formations

Investors and Funders

• TPG Rise Climate: climate-focused investment fund providing growth capital to Summit Carbon Solutions and other CCS infrastructure developers
• Brookfield Renewable Partners: infrastructure investor backing large-scale CCS transport projects in North America and Europe
• UK Infrastructure Bank: government-backed institution providing financing for the Acorn and HyNet CCS clusters

Action Checklist

• Assess the regulatory status of CO2 transport and storage permitting in your jurisdiction, including Class VI well permit timelines in the US, storage license availability in the EU, and government funding allocation timelines in the UK
• Evaluate hub-and-cluster models versus point-to-point CCS connections for your facility, comparing per-tonne transport costs, shared infrastructure benefits, and counterparty diversification
• Review pore space ownership and subsurface rights frameworks applicable to proposed storage sites, engaging legal counsel with specific CCS regulatory experience
• Structure offtake agreements with storage providers to include volume flexibility, force majeure provisions for permitting delays, and clear allocation of long-term monitoring liability
• Engage with community stakeholders along proposed pipeline routes early in project development, allocating 12 to 18 months for landowner engagement before beginning formal permitting applications
• Monitor government funding rounds and tax credit qualification requirements, ensuring project milestones align with application deadlines and safe harbor provisions
• Develop contingency plans for alternative CO2 transport modes including rail and ship where pipeline permitting faces extended delays

FAQ

Q: What is the typical cost range for CO2 pipeline transport per tonne? A: Pipeline transport costs vary significantly with distance, volume, and terrain. For onshore pipelines transporting 2 to 5 megatonnes per year over distances of 100 to 300 kilometers, costs typically range from $8 to $15 per tonne of CO2. Longer distances or lower volumes increase per-tonne costs, with cross-country pipelines of 1,000 kilometers or more reaching $20 to $30 per tonne. Offshore pipelines cost approximately 40 to 60% more than onshore equivalents due to higher construction and maintenance costs. Shared infrastructure in hub-and-cluster models can reduce per-tonne costs by 40 to 60% compared to dedicated point-to-point pipelines.

Q: How long does it take to permit and build a CO2 storage facility? A: From initial site characterization to first injection, CO2 storage projects typically require 5 to 8 years in the United States and 4 to 6 years in Europe. Site characterization including seismic surveys and appraisal wells takes 2 to 3 years. Permitting adds 1 to 5 years depending on jurisdiction, with US EPA Class VI permits historically requiring 3 to 5 years and European storage licenses requiring 1 to 2 years. Construction of injection wells and surface facilities takes 12 to 24 months. Projects that repurpose existing oil and gas wells and infrastructure, such as Acorn, can compress timelines by 2 to 3 years.

Q: What financing structures are most common for CO2 transport and storage projects? A: Most scaling CCS infrastructure projects use blended financing combining government grants or tax credits with private equity and project finance debt. In the US, the 45Q tax credit of $85 per tonne for geological storage can be monetized through tax equity partnerships or transferred via the Inflation Reduction Act's transferability provisions. In Europe, government capital grants (as in Norway's Longship model) typically cover 50 to 80% of first-of-a-kind project costs. As projects demonstrate operational track records, the private capital share increases and debt financing on commercial terms becomes available, as evidenced by Northern Lights Phase 2 financing.

Q: What are the key geological risks in CO2 storage and how are they managed? A: Primary geological risks include insufficient injectivity (the formation cannot accept CO2 at planned rates), containment failure (CO2 migrates out of the target formation through faults or abandoned wells), and induced seismicity. These risks are managed through extensive pre-injection site characterization including 3D seismic imaging, core sample analysis, and injection testing. During operations, continuous monitoring using downhole pressure sensors, microseismic arrays, and periodic seismic surveys tracks the CO2 plume and confirms containment. Depleted oil and gas reservoirs generally carry lower geological risk than saline aquifers because their containment has been proven by millions of years of hydrocarbon retention.

Sources

• Global CCS Institute. (2025). Global Status of CCS 2025. Melbourne: Global CCS Institute.
• International Energy Agency. (2025). CCUS in Clean Energy Transitions. Paris: IEA.
• Northern Lights JV. (2025). Annual Review 2025: Open-Access CO2 Transport and Storage. Stavanger: Northern Lights JV DA.
• Summit Carbon Solutions. (2025). Project Update: Midwest Carbon Pipeline Network. Ames, IA: Summit Carbon Solutions.
• Storegga. (2025). Acorn CCS Project Development Report. Aberdeen: Storegga Geotechnologies Ltd.
• US Environmental Protection Agency. (2025). Underground Injection Control Program: Class VI Well Status Report. Washington, DC: EPA.
• UK Department for Energy Security and Net Zero. (2025). Carbon Capture, Usage and Storage: Cluster Sequencing Update. London: DESNZ.