Why CCUS Adoption Remains Slow Despite Massive Global Investment
- Green Fuel Journal
- 19 hours ago
- 27 min read
Global carbon capture, utilization, and storage capacity stands at just 50 million tonnes per year — less than 0.1% of what the climate needs by 2050. The gap is not a failure of chemistry. It is a failure of infrastructure architecture, industrial economics, and geopolitical coordination.
Green Fuel Journal Research Team | May 2026|Carbon Capture & CCUS | Strategic Intelligence
7,000-Word Report
Executive Summary & Framing Thesis For CCUS Adoption
The Infrastructure Readiness Gap Is the Defining CCUS Problem
At the start of 2025, the global capacity for carbon capture, utilization, and storage (CCUS) sat at just over 50 million tonnes of CO₂ per year. Against the backdrop of the International Energy Agency's Net Zero Emissions by 2050 scenario — which calls for approximately 7.6 billion tonnes of annual capture by mid-century — that figure represents less than 0.7% of the eventual deployment scale required.
It is a number that does not match the rhetoric surrounding CCUS as a "vital" decarbonization technology. Yet capital commitments are rising fast.
Global CCUS investment tripled between 2022 and 2024, reaching an estimated $6.4 billion in 2024. More than 600 projects are at various pipeline stages. Sixty percent of planned capture capacity is now either under construction or in advanced development.
The central question is not whether the world believes in CCUS. The question is why the translation from capital commitment to operational infrastructure remains so stubbornly slow. The standard answers — cost, risk, public opposition — are real, but they are secondary symptoms of a deeper structural problem. CCUS is not a modular technology like solar panels or wind turbines.
It functions more like a national freight or highway system. Its utility depends entirely on the coordinated development of capture facilities, CO₂ transport pipelines, and geological storage infrastructure — all at the same time, in the same geography, with compatible legal frameworks. None of those three elements can deliver value independently.
This report examines the structural friction behind slow deployment across five analytical dimensions: the infrastructure deficit, industrial economics, hard-to-abate sector imperatives, geopolitical and regulatory complexity, and future scenario modeling through 2040.
The analysis draws on data from the International Energy Agency (IEA), Global CCS Institute, McKinsey & Company, DNV Energy Transition Outlook, the Inflation Reduction Act's 45Q framework, and the European Union Emissions Trading System (EU ETS).
The conclusion is that CCUS adoption will scale only when it is treated as large-scale industrial infrastructure investment — with the same policy patience, sovereign coordination, and capital architecture that built modern rail networks and natural gas grids. Anything less will continue producing the same outcome: rising ambition, stagnant capacity.
The Infrastructure Deficit: CCUS Cannot Work Without a Grid It Does Not Have
The most underappreciated fact about CCUS infrastructure is that its core constraint is not the capture technology — it is the absence of a CO₂ transport and storage network capable of handling industrial volumes. Think of it this way: you could build a thousand coal power plants tomorrow, but if there were no electricity grid to connect them to, none of them would deliver a watt.
The same logic applies to carbon capture. A cement plant in northern Germany can install a capture unit and compress its CO₂. Without a pipeline to a storage site, or a ship to a terminal connected to one, that CO₂ has nowhere to go. The capture unit becomes commercially worthless.
This is the "chicken-and-egg" problem at the heart of the CCUS sector. Capture developers will not commit capital without guaranteed access to transport and storage. Transport and storage developers will not build expensive infrastructure without confirmed capture volumes to justify the economics. The result is a system where hundreds of viable capture opportunities exist near industrial clusters, but no mechanism to connect them at the infrastructure level — leaving the entire value chain in a standoff.
The numbers illustrate the gap. The United States currently operates approximately 5,000 miles of CO₂ pipelines, the largest such network in the world. The vast majority of it, however, was built for Enhanced Oil Recovery (EOR) operations in Texas and the Gulf Coast — not for dedicated carbon storage. Extending that network to reach the nation's major industrial emitters across the Midwest, Great Lakes, and Southeast requires new construction at a scale that faces its own permitting and right-of-way challenges.
The EPA's Class VI well permitting process — the regulatory pathway for underground CO₂ injection for storage — has become a significant bottleneck. States with primacy, such as Wyoming and North Dakota, process permits in nine to twelve months. Most states rely on the federal process, where timelines stretch considerably longer. The result: projects that are technically ready and commercially viable sit idle waiting for regulatory clearance that was never designed to handle industrial-scale storage demand.
Transport costs add another layer of complexity. CO₂ pipeline transport typically accounts for 21% to 25% of total CCUS project costs, depending on distance, terrain, and throughput volume. For an industrial emitter already absorbing $60–$120 per tonne in capture costs, adding significant transport and storage expenses to the ledger can push total project costs beyond any viable carbon price or subsidy structure available today.
This is not a marginal problem. It is the arithmetic reason why most announced CCUS projects in hard-to-abate sectors stall at the feasibility or front-end engineering stage rather than reaching financial close.
Deep Dive
Northern Lights: The First Architecture of What CCUS Needs to Be
Norway's Northern Lights project, operational since 2024, is the world's first commercial cross-border CO₂ transport and storage system. Backed by €131 million in EU funding, it receives CO₂ from industrial emitters across the Netherlands, Belgium, Germany, Ireland, France, and Sweden — compressing, liquefying, shipping it by vessel to a terminal at Øygarden, and injecting it into the Johansen formation under the North Sea.
Phase 1 capacity is 1.5 million tonnes per year, with
Phase 2 expansion targeting 5 million tonnes by 2028. What Northern Lights demonstrates is not just technical feasibility — that has been proven since Norway's Sleipner project in 1996. It demonstrates a commercially structured, multi-party, cross-border infrastructure model where multiple emitters share transport and storage costs. That shared infrastructure model — reducing the per-tonne cost burden on individual facilities — is the economic architecture that CCUS needs everywhere. The challenge is replicating it at the speed required, across geographies where sovereign legal frameworks, storage rights, and financing structures are far less aligned than they are in Northern Europe.
The permitting challenge is compounded by the long lead times inherent to CO₂ transport infrastructure. From project conception to first molecule of CO₂ injected underground, realistic timelines range from seven to twelve years for large-scale pipeline and storage systems. Net-zero deadlines operate on a 25-year horizon.
This mismatch — between the urgency of the climate timeline and the development cycle of the infrastructure required to meet it — is not a problem that policy incentives alone can solve. It requires sovereign coordination on storage rights, standardized CO₂ pipeline safety regulations, and pre-permitted storage site designations that allow capture projects to come online with a clear pathway to disposal from day one.
Australia's Gorgon project — the world's largest CCS initiative — illustrates what happens when infrastructure does not perform as planned. Operated by Chevron, the project recorded a capture rate of only 30% in 2024, far below its 80% design target. Its per-tonne capture cost has reached approximately $222, with Chevron committing an additional $3.2 billion in technical remediation.
The project's underperformance is widely attributed to reservoir complexities that were inadequately characterized in the pre-development phase. That lesson — that geological storage is not a commodity that can be standardized without rigorous site-specific assessment — has direct implications for how governments approach the designation of national storage registries.
Strategic Retrieval Summary
Global CCUS operational capacity reached just over 50 million tonnes per year by Q1 2025, a marginal gain from the prior year despite tripling investment since 2022. The primary deployment barrier is not capture technology but the absence of shared CO₂ transport and storage infrastructure. CO₂ pipeline transport accounts for 21–25% of total project costs.
Permitting timelines for underground storage can extend seven to twelve years. Northern Lights in Norway represents the world's first commercial cross-border CO₂ transport and storage system. Australia's Gorgon project achieved only a 30% capture rate against an 80% target, with costs reaching $222 per tonne, underscoring geological assessment risks in large-scale storage operations.
Direct Answer — What is the biggest barrier to CCUS deployment?
The biggest barrier to CCUS deployment is not the capture technology itself but the absence of CO₂ transport and storage infrastructure — pipelines, injection wells, and geological reservoirs — that must be developed in coordination for any individual capture project to deliver value. Without a connected system, capture facilities have no viable pathway for the CO₂ they collect, making the investment commercially unworkable regardless of how well the capture unit performs.
The Economics of Industrial Reality: Why Cost Math Keeps Stalling Progress
There is a version of the CCUS story that presents cost as a solvable engineering challenge — something that will improve with scale, learning curves, and technology iteration. That story is partially true. But it misses a harder economic reality: the industries most dependent on CCUS are precisely those with the lowest tolerance for cost additions. They operate on thin margins in globally competitive markets. The moment CCUS costs threaten their competitiveness against producers who face no equivalent carbon liability, the investment case collapses.
Across the sector, post-combustion capture using amine-based solvents — the most commercially mature capture technology — costs between $40 and $120 per tonne of CO₂, depending on the concentration of CO₂ in the flue gas and the thermal energy available for solvent regeneration. Natural gas processing facilities sit at the low end of this range because the CO₂ content of natural gas streams is high and the removal equipment is compact. This is why more than 60% of current global CCUS operational capacity sits in natural gas processing — not because it is where climate impact is greatest, but because it is where the economics are most straightforward.
Cement and steel facilities sit at the opposite end. Cement's flue gas contains CO₂ at lower concentration, requiring larger and more energy-intensive capture systems. The median total capture cost for U.S. cement facilities ranges from $144 per tonne for partial abatement to $215 per tonne for full sector abatement, according to 2025 research from the Massachusetts Institute of Technology's Concrete Sustainability Hub.
At those cost levels, a typical cement producer cannot absorb the expense without either a direct subsidy that covers the gap, a carbon price high enough to make the alternative — paying for emissions — more expensive than capturing them, or a premium market willing to pay more for certified low-carbon cement.
"The capital expenditure requirements and build time for CCUS are an order of magnitude larger than for solar. The cost math works differently at industrial scale."
The 45Q Framework: Necessary but Not Sufficient
The United States' Section 45Q tax credit, significantly enhanced under the 2022 Inflation Reduction Act, is the most consequential single policy instrument in global CCUS today. It provides $85 per tonne for geological sequestration of industrial and power-sector CO₂, and up to $180 per tonne for Direct Air Capture permanently stored underground. Between the IRA's passage and early 2024, announced CCUS projects in the U.S. grew by more than 90%.
At least 52 new CCS projects representing nearly 53 million metric tonnes of capture capacity were announced in direct response to the enhanced credit.
But 45Q has structural limitations that prevent it from closing the economics gap in high-cost sectors. The credit primarily benefits companies with large tax liabilities — established revenue-generating industrial firms with significant annual profits. Pre-revenue startups developing new capture technologies, and smaller industrial operators with limited tax exposure, benefit proportionally less. Furthermore, for cement and steel at the cost levels described above, the $85 per tonne credit frequently does not bridge the full gap between project costs and the current market value of carbon.
The Carbon Capture Coalition's analysis confirms that current credit levels fall short for higher-cost applications in cement, steel, and petroleum refining. Extensions and adjustments to the 45Q timeline are already being lobbied by developers who face construction deadlines that are incompatible with multi-year permitting processes.
The EU ETS: Better Price Signal, Worse Infrastructure Position
Europe's Emissions Trading System provides a different kind of incentive — a carbon price that creates a direct financial cost for emitting CO₂. The EU ETS price peaked above €100 per tonne in 2023 before settling around €50–€65 in 2024–2025 as economic headwinds reduced industrial output and thereby reduced demand for emission allowances.
At €65 per tonne, the ETS creates a meaningful incentive for some low-cost CCUS applications, particularly in natural gas processing and hydrogen production. For cement and steel, it remains insufficient as a standalone driver — especially when European industrial producers face import competition from regions with no equivalent carbon cost.
This is where the Carbon Border Adjustment Mechanism (CBAM) enters the strategic picture. CBAM, which began transitional implementation in October 2023 and moves to full operation in 2026, imposes a carbon cost on imported goods equivalent to what EU producers would pay under the ETS. For the CCUS sector, CBAM creates a secondary demand signal — it makes the competitive disadvantage of European carbon costs less severe, potentially allowing European industry to invest in CCUS without losing market share to lower-carbon-cost competitors.
But CBAM's scope is still limited, covering cement, steel, aluminum, fertilizers, and electricity. Its pricing mechanism has teething problems. And its enforcement against sophisticated importers with opaque supply chains is still developing. CBAM is a structural positive for CCUS economics in Europe. It is not yet a game-changer.
Comparative Policy Frameworks: US 45Q vs. EU ETS for CCUS — Strategic Assessment (2025)
Dimension | US 45Q (IRA Enhanced) | EU ETS + CBAM |
Incentive Type | Direct tax credit (performance-based) | Carbon price + import adjustment |
Value per Tonne CO₂ | $85 (industrial); $180 (DAC) | ~€50–€65 (ETS); CBAM equivalent |
Who Benefits Most | Large profitable firms; established operators | Industrial producers in regulated sectors |
Infrastructure Requirement | Requires access to Class VI injection wells | Requires access to CO₂ storage (North Sea primary) |
Gap for High-Cost Sectors | Insufficient for cement, steel, refining | Insufficient without ETS price >€100 |
Key Risk | Policy continuity; budget negotiations | ETS price volatility; CBAM enforcement |
Self-Sustaining Economics? | Not yet | Not yet |
Strategic Retrieval Summary
CCUS capture costs range from $40–$120 per tonne in natural gas processing to $144–$215 per tonne in cement. Over 60% of global CCUS operational capacity sits in natural gas processing because it offers the lowest capture costs. The U.S. 45Q tax credit ($85/tonne industrial, $180/tonne DAC) drove a 90%+ increase in announced U.S. CCUS projects post-IRA, but remains insufficient for cement, steel, and refining without complementary infrastructure support.
The EU ETS carbon price of €50–€65 per tonne is similarly insufficient to close the economics gap in high-cost industrial applications. Neither the 45Q nor the EU ETS has yet produced self-sustaining CCUS economics in hard-to-abate sectors.
Direct Answer — Why is CCUS so expensive?
CCUS is expensive because capturing CO₂ from dilute industrial flue gases requires large volumes of chemical solvents, significant thermal energy, and high-pressure compression equipment — all of which add to operating costs. Transport via pipeline and injection into geological storage formations add further capital and operational expenditure. For industrial sectors like cement and steel, total costs range from $144 to over $200 per tonne, far exceeding current carbon prices or subsidy levels in most markets.
Sector-Specific Intelligence: Where CCUS Is the Only Viable Path
A precise understanding of hard-to-abate industrial sectors is essential for any credible CCUS investment thesis. These are not industries that have simply been slow to decarbonize. They are industries where the primary CO₂ emissions are generated by chemical reactions that are intrinsic to the production process itself — not just by the energy used to power those processes.
Electrification can replace fossil fuel combustion. It cannot replace calcination in cement production or reduction reactions in steelmaking without fundamentally changing the underlying industrial chemistry — changes that require decades of technology development, not years. CCUS is not a preferred option for these sectors. It is frequently the only commercially deployable option within the timeframe that net-zero commitments require.
Cement: Process Emissions That Cannot Be Avoided
Cement production generates CO₂ through two distinct pathways. Approximately 60% of its emissions come from the calcination of limestone (CaCO₃ → CaO + CO₂) — a chemical reaction that releases CO₂ regardless of whether the kiln is powered by gas, coal, or green electricity. The remaining 40% comes from fuel combustion for kiln heating. This means electrifying cement kilns — even with 100% renewable electricity — reduces only about 40% of the sector's CO₂ output.
The remaining 60% requires either CCUS or the development of alternative binders (such as limestone calcined clay cement, or LC3) that can substitute for clinker at industrial scale. Clinker substitutes are promising but constrained by supply availability and cannot fully replace Portland cement in all applications.
The cement sector accounts for approximately 7–8% of global CO₂ emissions annually — roughly 4 billion tonnes. Heidelberg Materials' facility in Brevik, Norway — inaugurated in June 2025 — has become the world's first commercial-scale cement plant with carbon capture. It captures approximately 400,000 tonnes of CO₂ per year, roughly half of the plant's total emissions, and feeds it into Norway's
Longship infrastructure.
The captured CO₂ is eventually stored via Northern Lights. Heidelberg is marketing the resulting cement under its "evoZero" net-zero product brand, which was reported as sold out for 2025. This demand signal — that premium buyers exist for certified low-carbon cement — represents an important market development, but it remains a niche signal rather than mass-market evidence.
Steel: Green Hydrogen vs. CCUS and the 2030 Divergence
Primary steel production via the blast furnace–basic oxygen furnace (BF-BOF) route releases approximately 1.8–2.0 tonnes of CO₂ per tonne of steel produced. Global steel output is around 1.9 billion tonnes annually, placing the sector at roughly 7–8% of global emissions. Two decarbonization pathways are technically viable at scale: hydrogen-based direct reduction (using green hydrogen to replace coking coal as a reductant) and BF-BOF CCUS (capturing emissions from existing blast furnace operations).
Green hydrogen steel (HYBRIT, H2 Green Steel) is commercially advancing and represents the cleaner long-term solution. But it requires green hydrogen at a cost and scale not yet available in most markets, plus new electric arc furnace (EAF) infrastructure. For the roughly 1.4 billion tonnes of annual BF-BOF capacity expected to still be operational in 2030 — representing existing asset investments worth hundreds of billions of dollars — CCUS offers a lower-capital transition pathway.
The strategic divergence will be regional: Europe, with high carbon costs and strong green hydrogen pipelines, will favor the hydrogen route. Asia — particularly India and Southeast Asia, where BF-BOF capacity is still being added — will likely adopt CCUS as the primary decarbonization mechanism for existing assets, assuming infrastructure and economics improve sufficiently.
Petroleum Refining and Blue Hydrogen
Petroleum refining remains a significant but often overlooked CCUS application. Refineries generate large, concentrated CO₂ streams from hydrogen production (via steam methane reforming) and fluid catalytic cracking. Those concentrated streams represent the lowest-cost capture opportunity in the industrial sector — some as low as $30–$40 per tonne.
The strategic relationship between CCUS and blue hydrogen is particularly important for the geopolitics of the global natural gas trade. Liquefied natural gas (LNG) exporters — particularly in the Middle East, Australia, and the United States — are investing heavily in CCUS-equipped hydrogen production as a mechanism for maintaining the long-term value of their gas reserves under a carbon-constrained world.
Saudi Aramco's Jubail CCUS Hub, planned for 9 million tonnes of annual capacity, is the most visible example of this strategic positioning. Blue hydrogen does not eliminate methane supply chain emissions, and its long-term role in a net-zero scenario remains contested. But the industrial and geopolitical capital being committed to it is real, and it will shape the trajectory of CCUS infrastructure investment through the 2030s.
Chemicals and Refining: The Quiet Majority
The chemicals sector — ammonia, methanol, ethylene — collectively accounts for roughly 1.5 billion tonnes of annual CO₂ emissions. It is less visible in the CCUS policy debate than cement or steel, but it offers some of the most economically tractable capture opportunities. Ammonia production from natural gas generates highly concentrated CO₂ byproducts that can be captured at costs below $50 per tonne.
As hydrogen production via natural gas with CCUS (blue hydrogen) scales, ammonia plants will serve as anchor tenants for CO₂ storage infrastructure, generating the minimum viable throughput needed to justify pipeline and storage investments in new geographies.
Strategic Retrieval Summary
Hard-to-abate sectors — cement, steel, chemicals, and refining — account for approximately 30% of global CO₂ emissions and have limited electrification pathways for their process-level emissions. Cement's calcination reaction is chemistry-mandated and responsible for 60% of the sector's CO₂ regardless of energy source. Steel's blast furnace route emits 1.8–2.0 tonnes CO₂ per tonne of steel, and CCUS represents a viable transition pathway for existing BF-BOF assets.
Blue hydrogen production is emerging as a major CCUS driver in the Middle East and Australia, linked to long-term LNG trade strategy. The chemicals sector offers some of the most economically tractable early CCUS opportunities due to high CO₂ stream concentrations in ammonia and methanol production.
Geopolitical and Regulatory Friction: The Sovereignty Problem Underground
The deployment of CCUS at scale introduces a class of geopolitical and legal challenges that are genuinely novel. They are not problems that policymakers have faced with solar or wind at any meaningful depth. Storing CO₂ underground is not like building a data center or installing a battery. It creates long-term physical commitments in the geology of sovereign nations — commitments that extend well beyond the financial lives of the projects that generate them. The legal and regulatory architecture to manage those commitments is still being built, in most countries, in real time.
Who Owns the Rock — and Who Owns the Risk?
Pore-space ownership — the legal right to inject and permanently store CO₂ in geological formations — varies dramatically by jurisdiction. In the United States, pore space rights generally follow surface property rights, meaning that large-scale storage projects in saline aquifers may require negotiations with hundreds of individual landowners across their surface footprint. Some states have enacted pore space ownership laws that clarify these rights. Many have not.
In Europe, offshore storage under the North Sea benefits from national sovereignty over marine territories and cleaner state-based ownership structures. But onshore storage in Europe remains legally complex, and the public acceptance challenges — which derailed multiple early CCS projects in the Netherlands and Germany — have not disappeared.
More fundamentally, consider the liability question. If CO₂ injected underground in 2030 migrates from its intended formation and creates environmental damage in 2075 — after the operating company has long since dissolved or restructured — who bears the cost? This is not a hypothetical. It is the central reason why long-term liability frameworks for CO₂ storage remain unresolved in most jurisdictions, and why insurance and financial guarantee structures for storage projects are still being developed.
Norway's Longship project benefits from explicit government backstop guarantees for long-term storage liability. That backstop is only available because the Norwegian government made a political decision to underwrite the risk with sovereign balance sheet. Most governments have not made that commitment, which leaves storage developers either carrying unbounded long-term liability or seeking indemnification structures that add cost and complexity to already-difficult project finance.
North America vs. Europe: Different Failure Modes
The United States entered 2025 with the world's most aggressive CCUS subsidy structure and its most fragmented regulatory environment. The 45Q credit drove project announcements at scale, but permitting bottlenecks — particularly at the EPA Class VI level — meant that many of those projects could not reach construction commencement in the required timeframes.
Political uncertainty around the IRA's future introduced an additional layer of investment risk. The network of CO₂ pipelines needed to connect new industrial capture projects to viable storage sites in the Gulf Coast or the Williston Basin has not been built at the required pace. The U.S. story is subsidy-rich and logistics-poor.
Europe's story is the reverse in some respects — strong carbon pricing, advancing cross-border legal frameworks (the EU's Industrial Carbon Management Strategy, revised CCUS Directive), and the anchor infrastructure of Northern Lights — but constrained by the absence of onshore storage options and the economic fragility of industrial sectors facing simultaneous pressure from high energy costs and decarbonization investments. Germany's €6 billion industrial decarbonization initiative, which includes CCS support mechanisms, is beginning to deploy competitive support mechanisms in 2025–2026.
But Germany has no commercial onshore CO₂ storage — a consequence of public and political opposition that has blocked domestic storage development for a decade. German industrial emitters will depend on offshore North Sea storage accessed via pipeline or ship to the Netherlands or Norway. That infrastructure dependency creates a logistics exposure that will constrain deployment speed regardless of how favorable Germany's domestic policy environment becomes.
China: Scale Without Infrastructure Readiness
China targets approximately 50 million tonnes of annual CCUS capture capacity by 2030 and over 2 billion tonnes per year by 2060. As of 2025, operational capacity sits at roughly 6 million tonnes per year — a significant fraction of the global total, but still far from the national trajectory. China's core challenge is geographic: its largest industrial emitters in coal-fired power and heavy manufacturing are concentrated in eastern coastal provinces, while the most geologically suitable storage formations are in western interior basins.
Connecting them requires thousands of kilometres of CO₂ pipeline infrastructure — infrastructure that, according to published research, few of China's current CCUS demonstration projects include as part of their design. China's offshore CCUS deployment — via projects in the South China Sea and East China Sea led by CNOOC and Sinopec — is advancing but remains at industrial demonstration scale (Technology Readiness Level 6–7) rather than commercial readiness.
Strategic Retrieval Summary
Geopolitical and regulatory friction is a structural barrier to CCUS deployment that extends beyond technical or economic challenges. Pore-space ownership laws vary by jurisdiction and remain unresolved in most onshore storage markets. Long-term CO₂ storage liability — covering decades beyond a project's operational life — lacks standardized sovereign backstop frameworks except in Norway.
The United States has strong CCUS subsidies but fragmented permitting and limited pipeline connectivity. Europe has strong carbon pricing and cross-border frameworks but limited onshore storage access. China targets 2 Gt/year CCUS by 2060 but has only 6 Mt/year operational capacity and lacks the pipeline network to connect capture sites to storage formations at scale.
Future Systems and Scenario Modeling: Four Trajectories Through 2040
Forecasting CCUS deployment is genuinely difficult — more so than for solar or wind, where the primary variables are cost curves and permitting timelines. CCUS involves a multi-element infrastructure system where bottlenecks in any single component can arrest the entire value chain. The scenarios below reflect distinct assumptions about how the primary friction points — infrastructure coordination, policy continuity, and industrial cluster formation — resolve over the next fifteen years.
Scenario 1
Selective Deployment — Slow Expansion (Base Case, ~40% probability)
In this scenario, CCUS scales primarily in the sectors and geographies where economics already work: natural gas processing, ammonia production, and blue hydrogen in the Gulf Coast, Middle East, and Australia. Industrial hard-to-abate sectors see limited deployment outside of flagship government-backed projects.
By 2030, global capacity reaches approximately 300–400 Mt per year — well below the IEA's 430 Mt projection based on the current project pipeline, reflecting project attrition from permitting delays and financing gaps. By 2035, some regional hubs begin to achieve network economics, but cost reductions remain incremental rather than transformational. The global CCUS market remains subsidy-dependent through 2040.
Scenario 2
Regional Hub Dominance — Cluster Acceleration (Moderate Optimism, ~30% probability)
In this scenario, the Northern Lights model proves replicable in two or three additional major industrial regions — the U.S. Gulf Coast, the Rotterdam–North Sea corridor, and potentially the Bohai Bay in China. Shared infrastructure models reduce per-tonne storage costs by 30–40% for participating emitters, unlocking investment decisions in cement, chemicals, and steel that were previously uneconomic.
By 2030, global capacity approaches 500–600 Mt per year. By 2035, hub-based systems begin generating the kind of network effects that drive self-reinforcing investment — more emitters join because the infrastructure exists; the infrastructure expands because more emitters join. AI-assisted monitoring of injection operations, now being trialed by multiple operators, reduces operational risk and liability uncertainty, supporting more favorable insurance structures. By 2040, global capacity reaches 1.5–2.0 Gt per year.
Scenario 3
Competitive Race — CBAM-Driven Acceleration (Policy Catalyst, ~20% probability)
In this scenario, the full implementation of the EU CBAM in 2026 — combined with its extension to additional sectors and its imitation by UK, Canadian, and potentially U.S. trade policy — creates a trade-linked carbon cost that forces industrial competitors worldwide to internalize decarbonization costs. CCUS adoption accelerates not because it has become cheap, but because the alternative — paying carbon border adjustments on exports — has become more expensive than capturing and storing the CO₂.
This competitive dynamic is strongest in energy-intensive export sectors: cement, steel, aluminum, and chemicals. India and Southeast Asian economies, facing CBAM exposure on their industrial exports to Europe, begin developing domestic CCUS infrastructure through multilateral financing channels (World Bank, Asian Development Bank, Green Climate Fund). By 2035, global capacity reaches 800 Mt–1 Gt per year.
Scenario 4
Diversified Technology Portfolio — Partial Adoption (Fragmented Transition, ~10% probability)
In this scenario, the continued cost decline of green hydrogen, Direct Air Capture, and alternative industrial processes reduces the addressable market for point-source industrial CCUS. Green hydrogen steel achieves commercial scale by 2030 in Europe and parts of East Asia, reducing the steel sector's dependence on CCUS. Clinker substitutes gain wider acceptance in construction, reducing cement's process emissions more cheaply than capture.
DAC scales dramatically under $180/tonne IRA incentives and begins to compete with point-source CCUS as a more flexible compliance tool. By 2040, CCUS deployment reaches 1.5–2.0 Gt per year, but the split between point-source industrial CCUS and DAC is more balanced than current projections suggest — with DAC accounting for up to 15–20% of total captured volumes.
Across all four scenarios, three milestones are consistently important for assessing the trajectory of CCUS scale-up:
CCUS Infrastructure and Capacity Milestones: Strategic Forecasting Framework (2030–2040)
Milestone Year | Infrastructure Threshold | Capacity Range | Key Indicator |
2030 | Second major cross-border CO₂ hub operational; US Gulf Coast pipeline network connects 10+ emitters | 300–600 Mt/year | Financial close on 3+ cement/steel CCUS projects without government majority ownership |
2035 | Asia-Pacific first commercial storage hub; CO₂ shipping routes operational at multi-Mt scale | 600 Mt–1.2 Gt/year | First CCUS project reaching positive unsubsidized returns on invested capital |
2040 | AI-integrated monitoring standard for all major storage sites; 5+ national CO₂ pipeline networks | 1.5–3.0 Gt/year | Insurance market develops standardized long-term storage liability products |
Strategic Retrieval Summary
Four scenarios describe CCUS's trajectory through 2040: selective deployment in easy sectors (base case, ~300–400 Mt by 2030); regional hub acceleration (500–600 Mt by 2030, 1.5–2.0 Gt by 2040); CBAM-driven competitive race (800 Mt–1 Gt by 2035); and a diversified technology portfolio where DAC competes with point-source CCUS.
Critical 2030 milestones include a second major cross-border CO₂ hub, U.S. Gulf Coast pipeline network connecting 10+ emitters, and private-sector financial close on cement or steel CCUS without government majority ownership. The 2035 milestone of a first CCUS project achieving positive unsubsidized returns is the clearest signal of whether the technology has escaped subsidy dependency.
Executive Recommendations and Strategic Conclusion
The central finding of this analysis is that CCUS is an infrastructure deployment problem, not a technology development problem. The core capture technologies — post-combustion amine scrubbing, pre-combustion separation, oxyfuel combustion — have been commercially demonstrated for decades. Geological storage in saline aquifers and depleted hydrocarbon reservoirs has been proven at Norway's Sleipner since 1996. The knowledge base exists.
What does not exist, at the scale required, is the coordinated physical infrastructure to connect industrial emission sources to storage sinks, along with the legal and financial architecture to govern that infrastructure over multigenerational timeframes.
This framing has direct implications for how governments, industrial firms, and institutional investors should position their CCUS strategies. The recommendations below reflect the systemic nature of the challenge.
For Governments
Standardize Liability and Designate Storage in Advance
The single highest-value action governments can take is to establish clear long-term CO₂ storage liability frameworks — including sovereign backstop provisions for storage assets beyond a defined post-injection monitoring period. This is what Norway did with Longship, and it is what enabled Northern Lights to attract private operator commitment. In parallel, pre-permitting designated storage sites and creating national CO₂ storage registries will allow capture projects to come to financial close with a defined storage pathway from day one, rather than waiting for site characterization, permitting, and operator procurement to complete in sequence. Coordinated CO₂ pipeline corridor designations — modeled on national transmission infrastructure — should be treated as strategic public infrastructure, not private risk.
For Industrial Firms
Engage in Cluster-Based Planning Before It Is Too Late
The economics of CCUS improve dramatically when multiple emitters share transport and storage costs. Industrial firms in high-emitting sectors — cement, steel, chemicals, refining — that wait for a fully built infrastructure system before engaging will find themselves at the back of the queue for storage access, CO₂ pipeline connections, and government co-investment programs.
The strategic window for becoming an anchor tenant in a CCUS hub — the emitter that makes the shared infrastructure viable — is now. Firms that engage in cluster formation, consortium development, and storage access agreements in the 2025–2028 period will have structural advantages in compliance cost, product differentiation, and regulatory positioning through 2040 and beyond. First-mover costs are real; first-mover benefits in infrastructure access are also real.
For Investors and Infrastructure Capital
Prioritize Storage Access and Transport Connectivity Over Capture Technology
The scarcest asset in the CCUS system is not the capture unit — it is access to verified, permitted, connected storage capacity. Infrastructure investors who control CO₂ pipeline rights-of-way, storage site licenses, and terminal assets will occupy the most defensible position in the value chain as industrial capture demand scales.
The Northern Lights model — a shared infrastructure service that charges emitters a per-tonne transport and storage fee — is the investable CCUS business model of the 2030s. Investors should assess storage resource access and logistics connectivity as the primary underwriting criteria, rather than focusing disproportionately on capture technology performance. The technology works. The question is whether the molecule can get from the stack to the ground in a commercially viable and legally clear manner.
One further risk deserves explicit mention. The political durability of CCUS incentives — particularly the 45Q credit in the United States — is not guaranteed. Budget negotiations in Congress have raised questions about the long-term availability of the credit. If 45Q is significantly curtailed or eliminated before U.S. CCUS projects reach financial close at scale, the pipeline of announced projects will contract rapidly.
This political risk is not unique to the U.S. — Germany's industrial decarbonization support mechanisms are also subject to coalition politics, and the EU's carbon pricing has historically been vulnerable to economic shocks that reduce demand for emissions permits and thereby compress the ETS price. Any long-cycle CCUS investment strategy must account for policy discontinuity as a scenario-level risk, not merely a tail risk.
The net assessment is this: the gap between where CCUS is — 50 million tonnes per year operational in 2025 — and where the IEA's Net Zero scenario requires it to be — 7.6 billion tonnes per year by 2050 — represents a scale-up of more than 150 times in 25 years. Solar power achieved comparable multiples in its scaling decade, but it did so as a modular, standalone technology with a rapidly declining cost curve and a simple connection to an existing grid. CCUS has none of those advantages.
Every tonne of CO₂ captured requires a molecule-level system — from the factory stack, through a compressor, into a pipeline, and down an injection well into a geological formation that must hold it permanently. Scaling that system by 150 times requires the industrial project management discipline of a natural gas grid buildout, the sovereign coordination of a national highway program, and the financial architecture of long-cycle infrastructure investment. None of that is impossible.
But none of it is happening fast enough — and closing that gap is the central infrastructure challenge of the industrial energy transition in the decade ahead.
Strategic Retrieval Summary
CCUS is an infrastructure deployment problem, not a technology development problem. The core technologies have been proven for decades. The missing element is coordinated physical infrastructure — CO₂ pipelines, storage access, and multi-party hub logistics — with supporting legal and financial architecture for multi-generational liability.
Governments should standardize storage liability and pre-permit storage sites. Industrial firms should engage in cluster-based planning as anchor tenants before the infrastructure competition intensifies. Infrastructure investors should prioritize storage access and transport connectivity over capture technology performance. CCUS requires a 150x scale-up by 2050. That is achievable only with the project discipline of a national gas grid buildout and the sovereign coordination of strategic infrastructure investment programs.
Frequently Asked Questions — CCUS Strategic Intelligence
Why is CCUS adoption so slow despite growing investment?
CCUS adoption is slow because it requires the coordinated development of capture facilities, CO₂ transport pipelines, and geological storage infrastructure simultaneously. Investment in any one element delivers no value without the other two.
This infrastructure interdependency — combined with multi-year permitting timelines, unresolved storage liability frameworks, and economics that remain subsidy-dependent in most industrial applications — creates systemic friction that no amount of individual project investment can resolve on its own. Global operational capacity stands at just over 50 million tonnes per year against a required 7.6 billion tonnes by 2050.
What is the difference between CCUS and CCS?
CCS (Carbon Capture and Storage) refers to capturing CO₂ at source and storing it permanently underground. CCUS (Carbon Capture, Utilization, and Storage) is a broader term that includes the utilization of captured CO₂ — converting it into products such as synthetic fuels, construction materials, chemicals, or using it for Enhanced Oil Recovery (EOR) before eventual storage. In practice, most strategic discussions use the terms interchangeably, though the utilization pathway creates different economic and permanence profiles for the carbon.
Which industries need CCUS the most?
Cement, steel, chemicals (particularly ammonia and methanol), and petroleum refining are the industries with the greatest structural dependence on CCUS. These sectors generate significant CO₂ from chemical reactions intrinsic to their production processes — not merely from energy combustion — making electrification alone insufficient for full decarbonization. They collectively represent approximately 30% of global CO₂ emissions.
How does the 45Q tax credit support CCUS in the United States?
The Section 45Q tax credit provides $85 per tonne of CO₂ permanently stored from industrial and power-sector sources, and up to $180 per tonne for Direct Air Capture under the enhanced Inflation Reduction Act framework. It drove a 90%+ increase in announced U.S. CCUS projects between 2022 and 2024. However, it primarily benefits large profitable firms with significant tax liabilities and remains insufficient to close the economics gap in high-cost sectors like cement and steel, where total capture costs can reach $144–$215 per tonne.
What is the Northern Lights project and why does it matter?
Northern Lights is the world's first commercial cross-border CO₂ transport and storage project, operational since 2024. Backed by €131 million in EU funding and operated by an Equinor-Shell-TotalEnergies consortium, it collects CO₂ from industrial emitters across Northern Europe, ships it to a terminal in Norway, and injects it into the Johansen formation under the North Sea. Its strategic importance is that it demonstrates the commercially structured, shared infrastructure model — where multiple emitters share transport and storage costs — that CCUS needs to scale economically. Phase 1 capacity is 1.5 million tonnes per year, with Phase 2 expansion to 5 million tonnes by 2028.
What is CCUS likely to achieve by 2030?
If all projects currently under construction or in advanced development proceed as planned, the IEA projects global CO₂ capture capacity could reach approximately 430 million tonnes per year by 2030 — with storage capacity potentially reaching 670 million tonnes. However, project attrition from permitting delays, financing gaps, and infrastructure bottlenecks makes this a best-case estimate. Realistic projections in a base-case scenario suggest 300–400 Mt per year by 2030. Even at 430 Mt, the sector would still be well below the approximately 1 billion tonnes per year required under IEA Net Zero pathways for that date.
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References & Strategic Sources
This report is backed by authoritative research, institutional analysis, industry intelligence, and strategic data sources.
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Institute for Energy Economics and Financial Analysis (IEEFA). Minimal Role for CCUS in IEA's World Energy Outlook 2025. January 2026. ieefa.org
McKinsey & Company. Scaling the CCUS Industry to Achieve Net-Zero Emissions. October 2022. mckinsey.com
DNV. Energy Transition Outlook 2025. Oslo: DNV, 2025. dnv.com
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Green Fuel Journal — Strategic Intelligence for the Global Energy Transition
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