Carbon capture’s limiting factor in Europe is increasingly the business model around it. Capture equipment can remove CO2 from industrial exhaust, but projects still need buyers for the service, dependable transport and storage, and contracts that give investors confidence in future revenue. Without those pieces, technically ready facilities can remain unbuilt or underused.
The scale of Europe’s ambitions makes that gap consequential. The European Commission’s Industrial Carbon Management Strategy sets a goal of at least 50 million tonnes of annual CO2 storage capacity by 2030. Its modelling points to roughly 280 million tonnes of captured CO2 each year by 2040 and around 450 million tonnes by 2050. Those targets imply an industrial system, not a string of isolated demonstration plants.
Projects depend on one another
A capture plant may face high costs without a clear premium for its lower carbon product. A transport operator needs committed volumes to justify investment. A storage developer needs customers prepared to deliver CO2 over time. Each party’s financing case depends on commitments from the others, leaving projects stuck in a cycle of mutual hesitation.
That is why project announcements alone tell us little about whether a market is forming. The more meaningful signal is a final investment decision backed by contracts that specify volumes, prices, performance and responsibility when parts of the chain are delayed or unavailable. Europe also needs common specifications, measurement rules and infrastructure access so customers can connect without negotiating every technical detail from scratch.
Here’s the thing: capture is only one stage. CO2 must be measured, moved and stored, and the entire chain must work together. A plant that captures carbon without an available route to permanent storage hasn’t solved the commercial problem.
Northern Lights puts storage into a service model
Norway’s Northern Lights project offers one answer to the infrastructure challenge. Rather than requiring each emitter to build its own pipeline and storage site, the project lets customers liquefy captured CO2, ship it to a receiving terminal and buy transport and permanent storage as a service.
Phase 1 provides 1.5 million tonnes per year of capacity. The first injection took place in 2025, using CO2 from Heidelberg Materials’ Brevik cement plant, and the initial capacity is fully booked. A second phase is intended to lift capacity to at least 5 million tonnes annually from 2028. Contracts include planned biogenic CO2 volumes from Stockholm Exergi.
Those volumes are modest beside Europe’s 2040 ambition, but the commercial structure matters beyond the project’s immediate scale. Shipping can connect emitters in different locations before pipeline networks become dense. A standardized storage service also gives industrial companies a clearer cost and operating model to use in financing decisions. They can access storage without becoming experts in building and operating an entire CO2 chain.
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Different emitters need different contracts
The United Kingdom is pursuing a cluster approach, connecting capture projects to shared transport and storage networks. Its contract models reflect the fact that a cement plant, waste-to-energy facility, gas power station and engineered carbon-removal project have different revenue sources and operating risks.
UK industrial carbon-capture contracts are designed to cover part of the gap between the cost of producing a lower-carbon product and the market value of its conventional alternative. Transport and storage networks, meanwhile, receive a regulated framework intended to support investment before utilization reaches mature levels.
In late 2025, the government reported final contracts for the Padeswood cement capture project and the Protos waste-to-energy project. These agreements are a more concrete marker of progress than a long project pipeline: they show that policy is beginning to allocate commercial risks through contracts.
That support can create large, long-term obligations. Poorly designed contracts could shield operators from risks they can manage, reward weak capture performance or leave users paying for infrastructure that remains expensive. Those concerns call for careful contract terms and performance conditions. But without a way to share the initial risk, projects may continue to depend on public targets without reaching construction.
Carbon prices are only part of the financing case
The EU Emissions Trading System can improve capture economics. When an emitter stores a tonne of CO2, it avoids surrendering an allowance for that tonne. A higher carbon price can therefore strengthen the case for capture.
But allowance prices can move, while construction debt, operating costs and transport charges still need to be covered. A market price alone may not provide the predictable revenue investors seek for assets designed to operate over decades. It also doesn’t settle questions about who pays if a storage network is delayed, a capture plant is ready before its pipeline, or contracted volumes fail to arrive.
Different tools can cover different exposures. Carbon contracts for difference can reduce revenue uncertainty; regulated-asset models can support shared networks; minimum-volume commitments can give infrastructure owners greater certainty about demand. Government-backed storage development and green public procurement may also help establish early markets. The design challenge is to assign each risk to the party best placed to manage it, rather than removing every risk from project operators.
Clusters could change the value of the infrastructure
A standalone capture plant is an expensive retrofit. A shared network serving cement, chemicals, waste, refining and carbon-removal projects can become regional industrial infrastructure. More customers may help lower unit costs, while common transport and storage let businesses participate without owning every link in the chain.
Shared systems may also provide options for biogenic CO2 and direct-air-capture projects, which can use the same storage network to support permanent removals. CO2 utilization could add demand where it has a credible market, though using carbon does not count as permanent storage if that carbon is soon released back into the atmosphere.
That said, scale should not become a goal detached from emissions outcomes. Electrification, efficiency, material substitution and renewable energy may offer cheaper, more direct reductions for some facilities. Carbon capture makes the strongest case where emissions are hard to avoid and captured CO2 can be verified as permanently stored.
Bankability is the next measure of progress
The strongest early markets are likely to include cement, lime, some chemical processes, waste-to-energy and selected carbon-removal projects. These sectors combine concentrated emissions or limited alternatives with policy support. Gas power with carbon capture may contribute where power systems value dispatchable, lower-carbon capacity, but its economics depend heavily on utilization and fuel prices.
For developers, the first commercial question should be who will pay for the avoided or removed tonne, under what contract, for how long and subject to which performance requirements. Capture rates and energy consumption remain important engineering measures, but they cannot substitute for a credible route to revenue and permanent storage.
Europe has shown that carbon can be captured. Its next test is whether emitters, transport operators and storage providers can contract as parts of one investable service. The projects that answer that question will offer a clearer measure of progress than another round of capacity announcements.