The carbon capture and storage industry stands at an inflection point that will define whether the technology becomes a multi-trillion-dollar pillar of the net-zero transition or remains an expensive footnote in the history of climate policy. With global CCS capacity reaching 361 million tonnes per annum in operational and advanced development stages, and an investment pipeline exceeding $140 billion, the economics of carbon capture have never mattered more. This analysis examines the cost structures, scale dynamics, and learning curves that will determine the commercial trajectory of CCS through 2035.
The Cost Landscape: A Technology in Three Tiers
Carbon capture is not a single technology — it is a family of approaches with radically different cost structures, and conflating them leads to fundamental misunderstanding of the sector’s economics.
Tier 1: Industrial Point-Source Capture ($15–$45/tCO₂). The most economically mature form of carbon capture involves separating CO₂ from concentrated industrial exhaust streams. Natural gas processing, ethanol production, and ammonia manufacturing produce exhaust streams with CO₂ concentrations of 90–99%, making capture technically straightforward and commercially viable even without carbon pricing in many jurisdictions. The Century Plant in Texas, operated by Occidental Petroleum, captures approximately 8.4 million tonnes of CO₂ annually from natural gas processing at costs below $25 per tonne. At these economics, carbon capture is not a climate subsidy — it is a profitable industrial process.
Tier 2: Power and Heavy Industry Capture ($45–$120/tCO₂). Capturing CO₂ from coal and gas-fired power plants, cement kilns, and steel blast furnaces is significantly more expensive. The CO₂ concentration in flue gas from a coal plant is approximately 12–15%, and from a gas plant approximately 3–5%. The lower concentration means more energy is required for separation. The Boundary Dam project in Saskatchewan, the world’s first commercial-scale power plant CCS installation, has demonstrated costs in the range of $100–$115 per tonne, though operating challenges and lower-than-designed capture rates have complicated the economic picture. Newer solvent-based systems from companies like Shell Cansolv and Mitsubishi Heavy Industries claim cost trajectories toward $50–$65 per tonne at scale, but these figures remain largely prospective.
Tier 3: Direct Air Capture ($250–$1,000/tCO₂). Extracting CO₂ directly from ambient air, where concentrations are approximately 420 parts per million (0.042%), is thermodynamically demanding and correspondingly expensive. Climeworks, the Swiss-based leader in solid sorbent DAC, operates its Orca facility in Iceland at estimated costs of $600–$800 per tonne. Their larger Mammoth facility, which began operations in 2024 with a capacity of 36,000 tonnes per year, targets costs below $400 per tonne by 2030. Carbon Engineering (now owned by Occidental) pursues a liquid solvent approach with target costs of $250–$350 per tonne at their planned Stratos facility in Texas, which will have a capacity of 500,000 tonnes per year. These costs must decline by 70–90% to compete with nature-based solutions and industrial decarbonization alternatives.
Learning Curves and the Scale Question
The central investment thesis for carbon capture rests on technology learning curves — the observed phenomenon that costs decline predictably as cumulative deployed capacity increases. Solar photovoltaics demonstrated a learning rate of approximately 24% (costs fell 24% for every doubling of cumulative capacity), wind power approximately 15%, and lithium-ion batteries approximately 18%. The question for CCS is whether similar dynamics will apply.
Historical evidence is mixed. Point-source capture from natural gas processing has been commercially operational since the 1970s, and costs have declined modestly — perhaps 20–30% over five decades. This suggests a learning rate of approximately 5–8%, far below solar or batteries. The explanation is partly that CCS is fundamentally a chemical engineering process rather than a manufacturing process. Solar panels benefit from semiconductor-style mass production efficiencies. CCS systems are bespoke industrial installations, each tailored to specific flue gas compositions, site conditions, and storage geology.
However, proponents argue that historical learning rates are misleading because cumulative deployment has been negligible. Total global CCS capacity today is roughly 50 million tonnes per year of actual operational capture. Compare this to solar, which deployed 420 GW in 2023 alone. The argument is that CCS has not yet reached the deployment threshold where manufacturing standardisation, supply chain optimisation, and design iteration begin to accelerate cost reduction. The IEA’s Net Zero Emissions scenario requires approximately 1.2 billion tonnes of annual CCS capacity by 2030 and 6 billion tonnes by 2050 — a 120-fold increase from current levels. If even modest learning rates apply at that scale, cost reductions could be substantial.
Direct air capture has the strongest theoretical case for rapid cost decline precisely because it is so early in its deployment curve. With total global DAC capacity below 50,000 tonnes per year, the technology is roughly where solar was in the early 1990s. If DAC achieves a learning rate of even 15%, costs could decline from $600 to below $100 per tonne by the time cumulative capacity reaches 100 million tonnes — though reaching that scale requires the very cost reductions it is supposed to produce. This circularity is the fundamental challenge.
The Role of Carbon Pricing
Carbon capture economics cannot be evaluated in isolation from carbon pricing policy. The EU Emissions Trading System, the world’s most developed carbon market, has established a price floor that increasingly rationalises CCS investment.
EU ETS allowance prices have traded between €55 and €100 over the past three years, with current prices around €68. At these levels, point-source industrial capture is economically rational for many emitters. The European Commission’s proposed ETS reforms, including accelerated allowance reduction and CBAM implementation, suggest structural support for prices above €80 by 2028 and above €100 by 2030.
The United States has taken a different approach through the Inflation Reduction Act’s enhanced 45Q tax credit, which provides $85 per tonne for geological storage and $180 per tonne for direct air capture with storage. These credits have fundamentally altered the investment calculus for CCS in America, making even relatively expensive capture projects financially viable on a pre-tax basis. The 45Q credit is particularly transformative for DAC: at $180 per tonne, the gap between current DAC costs ($600) and the policy incentive is approximately $420 per tonne — steep, but within range of projected cost reductions within the credit’s 12-year window.
Storage Infrastructure: The Overlooked Bottleneck
Much CCS investment analysis focuses on capture technology while underestimating the challenge of CO₂ transport and storage infrastructure. Capturing CO₂ is only valuable if it can be permanently stored in geological formations — saline aquifers, depleted oil and gas reservoirs, or basalt formations.
Global characterised storage capacity is theoretically enormous — the IPCC estimates at least 2,000 gigatonnes in deep saline formations alone. But “characterised” does not mean “permitted” or “operational.” The process of identifying, appraising, permitting, and developing a CO₂ storage site takes 5–10 years and costs $50–$200 million per site. Pipeline infrastructure for CO₂ transport is equally capital-intensive, with costs of $1–$5 million per kilometre depending on terrain and diameter.
The Northern Lights project in Norway, a joint venture of Equinor, Shell, and TotalEnergies, represents the most advanced commercial CO₂ storage infrastructure in Europe. Phase 1, operational since 2024, provides 1.5 million tonnes per year of storage capacity in sub-seabed formations in the North Sea. Phase 2 will expand to 5 million tonnes per year. The project demonstrates that cross-border CO₂ transport and storage is technically feasible, but also that it requires sovereign-level capital commitment and regulatory coordination.
In the United States, the EPA’s Class VI well permitting process for CO₂ injection has been a significant bottleneck. As of early 2026, fewer than 30 Class VI permits have been issued, despite hundreds of applications. Recognising this constraint, several states including Louisiana, North Dakota, and Wyoming have obtained primacy to administer their own permitting programmes, significantly accelerating approvals.
The Utilisation Question: EOR and Beyond
Enhanced oil recovery (EOR) — injecting CO₂ into oil reservoirs to increase extraction — has historically been the primary commercial use of captured CO₂, particularly in the United States. Approximately 70% of currently operating CCS capacity is linked to EOR. This creates a paradox: the most economically viable application of carbon capture involves producing more fossil fuels.
Climate advocates have increasingly challenged the inclusion of CO₂-EOR in CCS accounting, arguing that the lifecycle emissions benefit is marginal at best. However, the economic reality is that EOR provides a revenue stream of $20–$40 per tonne of CO₂ (based on oil prices), which closes the gap to commercial viability for many capture projects. Without EOR revenue, many existing CCS facilities would be uneconomic.
The emerging CO₂ utilisation market offers alternative revenue streams. CO₂ can be used as a feedstock for building materials (carbon-cured concrete), chemicals (methanol, synthetic fuels), and food and beverage applications. CarbonCure, a Canadian company, injects CO₂ into concrete during mixing, permanently mineralising the carbon and improving concrete strength. The total addressable market for CO₂ utilisation is estimated at $70–$300 billion by 2040, but current commercial volumes are negligible relative to the gigatonne-scale capture required for climate targets.
Investment Implications
The CCS investment landscape is bifurcating. Tier 1 point-source capture in favourable jurisdictions (United States with 45Q, EU with ETS, Norway with Northern Lights access) is increasingly bankable. Major energy companies including ExxonMobil, Chevron, Shell, BP, and Occidental have committed over $50 billion in combined CCS capital expenditure through 2030.
Direct air capture remains a venture-stage technology with significant execution risk but enormous optionality if learning curves materialise. The entry of Occidental Petroleum as a large-cap sponsor (through its $1.1 billion acquisition of Carbon Engineering and planned STRATOS hub) provides industrial credibility, but commercialisation timelines remain uncertain.
The critical variable is policy durability. CCS projects have 25–40 year asset lives. Investors need confidence that carbon prices, tax credits, and regulatory frameworks will persist across multiple political cycles. The revocation risk of the 45Q credit under future US administrations, and the potential dilution of EU ETS ambition under industrial competitiveness pressure, represent the most significant risk factors for the sector.
For institutional investors, the near-term opportunity lies in CCS infrastructure — pipelines, storage hubs, and shipping logistics — which benefits from the growth of the sector regardless of which capture technologies ultimately prevail. The analogy to picks-and-shovels in a gold rush is apt: the companies building CO₂ transport networks may generate more reliable returns than those betting on specific capture chemistries.
Conclusion
Carbon capture economics are not a single story but three distinct narratives operating on different timescales. Point-source industrial capture is commercially viable today in supportive policy environments. Power and heavy industry capture is approaching viability as carbon prices rise and technology improves. Direct air capture remains a decade or more from competing on cost, but its theoretical importance for achieving net-negative emissions ensures continued policy support and venture investment.
The question is not whether CCS will play a role in the net-zero transition — it will. The question is how large that role will be, and whether the industry can scale fast enough to matter for the 2030 and 2050 targets that define the climate trajectory. The answer depends on learning curves, policy durability, and storage infrastructure build-out — three variables that remain deeply uncertain but increasingly investable.