Carbon capture cost trends and projections through 2035

Introduction

Carbon capture and storage (CCS) encompasses technologies that remove carbon dioxide from industrial flue gases, power plants and even ambient air and either utilise it or permanently store it underground. Deployment is rising rapidly, driven by net‑zero pledges and tax incentives such as the United States’ §45Q credit. However, the cost of capture remains a key barrier and is highly sensitive to technology, plant scale and CO₂ concentration in the gas stream. This report synthesises historical capital and operating cost data, examines case studies from early commercial projects, models cost‑curve trajectories to 2035 and identifies inflection points for policy and investment decisions.

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Historical costs across sectors

Studies consistently show that capture costs vary widely by sector. The Energy Transitions Commission (ETC) summarised costs in 2022: capture from concentrated streams in hydrogen production and natural‑gas processing costs around US$30 per tonne, while dilute sources such as cement or coal power cost US$70–130 per tonne and direct air capture (DAC) can exceed US$350 per tonneenergy-transitions.org. The range reflects differences in CO₂ concentration, energy demand and plant scale. The IEA notes that adding CCS increases capital costs by 40–75 % for coal power, 95–110 % for gas combined‑cycle plants, 75–100 % for biomass power, 110–125 % for cement kilns and 30–45 % for steeliea.blob.core.windows.net. These increases explain why capture cost (CAPEX and OPEX) dominates the levelised cost of avoided emissions, while transport and storage typically add US$17–30 per tonnebelfercenter.org.

Table 1 – Representative cost ranges for first‑of‑a‑kind (FOAK) and nth‑of‑a‑kind (NOAK) CCS projects

Sector/technology	CO₂ concentration	FOAK cost of CO₂ avoided (US$/t)	NOAK cost (US$/t)	Notes
Natural‑gas processing / bio‑ethanol	High (>90 %)	**21–22 **globalccsinstitute.com	20globalccsinstitute.com	CO₂ removal is integral to processing; limited additional energy required.
Coal‑fired power	~15 %	**74–83 **globalccsinstitute.com	38–47globalccsinstitute.com	Includes steam extraction and amine solvent regeneration.
Natural‑gas combined‑cycle (NGCC) power	~4 %	89globalccsinstitute.com	65globalccsinstitute.com	Low CO₂ concentration; high energy penalty.
Cement	14–25 %	**90–205 **belfercenter.org	n/a	Emissions from calcination and combustion; emerging oxy‑fuel technologies not yet commercial.
Ethanol fermentation	Pure (>99 %)	26–36belfercenter.org	n/a	CO₂ is nearly pure; compression and dehydration dominate cost.
Hydrogen (steam‑methane reforming)	10–15 %	65–136belfercenter.org	30energy-transitions.org	Pre‑combustion capture reduces energy penalty; blue‑hydrogen turbines can outperform NGCC with post‑combustion capture at part‑loadpublications.ieaghg.org.
Steel	20–30 %	8–133belfercenter.org	n/a	Costs vary by process (BF‑BOF vs. DRI).
Direct air capture (DAC)	0.04 %	140–350energy-transitions.org	50–150 (2050 projection)energy-transitions.org	High energy input per tonne; learning rates expected but uncertain.

These ranges illustrate that capture costs for high‑concentration sources are already close to or below prevailing carbon prices, whereas dilute sources remain expensive. For small‑scale facilities (≤100 MW), a recent IEAGHG assessment found that a large combined‑cycle gas turbine (CCGT) retrofit had the lowest capture cost at US$44 /t, whereas energy‑from‑waste and lime kilns—plants with small emission volumes—had costs of US$90–103 /tpublications.ieaghg.org. As the plant scale shrinks, capital expenditure becomes the dominant component of the levelised cost of capturepublications.ieaghg.org. The analysis shows that small‑scale capture projects generally require higher carbon prices or greater incentives than large projects to break evenpublications.ieaghg.org.

Direct air capture costs

DAC technologies have attracted attention because they are unconstrained by point sources and can deliver net‑negative emissions. However, costs remain high. The Energy Transitions Commission estimated first‑of‑a‑kind DAC costs at US$140–300 per tonne and projected a decline to US$50–150 per tonne by 2050 if energy efficiency improves and equipment costs declineenergy-transitions.org. Academic critiques caution that these projections may be optimistic: MIT researchers note that capturing one tonne via DAC requires around 1.2 MWh of electricity, so at US$0.10 /kWh the electricity alone costs US$120 per tonne, far above the US$100–200 cost assumed in many analysesnews.mit.edu. World Economic Forum commentators similarly report that DAC currently costs US$600–1,000 per tonne (end‑to‑end) and may struggle to fall below US$300–400 per tonne without substantial policy supportweforum.org. Thus, while DAC plays a role in long‑term decarbonisation, it is unlikely to be cost‑competitive in the 2020s.

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Case studies: evidence from operating projects

Sleipner (Norway – natural‑gas processing)

The Sleipner project injects CO₂ stripped from natural gas into a saline aquifer. It has been operating since 1996 with a capital cost of ~US$300 million and annual operating cost of ~US$0.75 million, capturing about 1 MtCO₂ per yearcatf.us. High CO₂ concentration and existing offshore infrastructure make Sleipner one of the cheapest CCS projects.

Quest (Canada – hydrogen plant)

Shell’s Quest facility retrofitted a hydrogen (SMR) plant in Alberta. Construction cost CA$790 million with annual operating costs of CA$30–35 millioncatf.us. It captures roughly 1 MtCO₂ per year and benefited from government grants and carbon‑pricing credits. In 2022 Quest’s reported cost per tonne captured was ~CA$102catf.us, illustrating that OPEX (energy and solvent) can dominate costs even when the CO₂ stream is relatively concentrated.

Boundary Dam Unit 3 (BD3) and Shand (Canada – coal power)

SaskPower’s BD3 project is often cited as the first commercial post‑combustion capture unit on a coal plant. The retrofit cost CA$1.47 billion; roughly 50 % of the budget went to the capture system itself, and only about 30 % to the new boiler and turbinecatf.us. Technical problems reduced availability and the project captured less CO₂ than planned. Lessons from BD3 informed the Shand feasibility study, which proposed a second‑generation design. The study estimates a 67 % reduction in capture capital cost per tonne and 92 % reduction in integration cost relative to BD3, resulting in a levelised capture cost of US$45 per tonne for a plant capturing 2 MtCO₂ per yearccsknowledge.com. These improvements come from modular equipment, better integration, waste‑heat utilisation and larger scale.

Petra Nova (USA – coal power)

NRG and JX Nippon’s Petra Nova project retrofitted a 240 MW slipstream of the WA Parish coal plant. The capture plant cost US$637 million, the pipeline and oil‑field infrastructure cost US$300 million and the project received a US$167 million U.S. DOE grantcatf.us. By using an auxiliary natural‑gas cogeneration unit to supply steam and electricity, Petra Nova avoided derating the host power plant and reduced capture cost by 25–30 % relative to BD3belfercenter.org. Modified designs by Mitsubishi Heavy Industries claim further 30 % capital‑cost reductions through compact and modular equipmentcatf.us.

Illinois Industrial CCS (USA – ethanol fermentation)

At the Archer Daniels Midland plant in Decatur, Illinois, CO₂ from corn‑ethanol fermentation is dehydrated and injected into a deep saline aquifer. The project cost US$207 million, including a US$141 million DOE grantcatf.us, and captures about 1 MtCO₂ per year. Because the gas stream is pure CO₂, the capture system mainly compresses and dries the gas, resulting in relatively low operating costs.

Other notable cases

• Quest vs. Alberta Carbon Trunk Line – The Alberta Carbon Trunk Line network transports CO₂ from an oil refinery and a fertilizer plant to an oil field. The full project cost CA$1.2 billion, and in 2022 the cost per tonne of CO₂ captured and stored (including transport and storage) was about CA$102 per tonnecatf.us, similar to Quest.
• Emerging solvent technologies – Ion Clean Energy’s water‑lean solvent demonstrates capture costs of US$39–44 per tonne of CO₂ for coal plants, a 25–33 % reduction relative to conventional amine solventsglobalccsinstitute.com. Saipem’s enzymatic technology reports capture costs as low as US$28 per tonne when waste heat is availableglobalccsinstitute.com. These technologies exemplify the potential of process intensification and alternative solvents to cut costs.

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Cost drivers and policy signals

Capital vs. operating costs

For large-scale capture plants, energy consumption and solvent degradation drive OPEX. In the IEAGHG small‑scale study, CAPEX accounted for 37 % of the levelised cost for a large CCGT retrofit but increased to 49 % for a small‑scale plant and 59 % for plants operating at part‑loadpublications.ieaghg.org. Because smaller plants cannot spread the fixed cost over large volumes of captured CO₂, CAPEX becomes the dominant cost factor and makes such projects uneconomic under current incentivespublications.ieaghg.org. Strategies such as modular designs, waste‑heat utilisation and high capture rates (≥90 %) are critical for reducing capital costs and energy penalties.

Policy incentives

The United States §45Q tax credit provides US$85 per tonne of CO₂ stored in geologic formations and US$60 per tonne for EOR or other utilisation, while DAC projects receive US$180 per tonne for storage and US$130 per tonne for utilisationcarboncapturecoalition.org. This credit has driven a surge in project announcements—over 270 projects since the Inflation Reduction Act enhancementscarboncapturecoalition.org—but it still falls short of making small‑scale or high‑cost applications like cement or DAC profitablepublications.ieaghg.org. The IEA warns that raising the cost of capital from 5 % to 15 % increases levelised capture costs by 30–65 % in hydrogen, cement and power generation sectorsiea.blob.core.windows.net, underscoring the importance of low‑cost financing.

Economic risks

The Institute for Energy Economics and Financial Analysis (IEEFA) reports that Europe’s pipeline of CCS projects faces average capture, transport and storage costs of about US$198 per tonne, almost double projected carbon pricesieefa.org. The report highlights cost overruns—construction costs of a Dutch project more than doubled—and technology risks, warning that the majority of proposed European capture volumes come from projects still at prototype stageieefa.org. This suggests that investment decisions must carefully account for technical readiness and potential cost escalation.

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Modelling cost trends to 2035

To explore how capture costs might evolve, a simple model was developed using historical costs as baselines (Table 1). Annual cost reduction rates were assumed based on observed learning curves: 2–5 % per year for mature technologies (natural‑gas processing, ethanol, coal and gas power, hydrogen, cement, steel), 5 % for small‑scale plants and 8 % for DAC. U.S. §45Q credits were applied to estimate net costs (assuming storage). The resulting trajectories are illustrated below.

Projected capture costs

Figure 1 – Projected cost of CO₂ capture by technology (2025‑2035). Mature high‑concentration processes (natural‑gas processing, ethanol fermentation) start below US$30 per tonne and decline modestly. Coal and gas power capture decline from around US$60–90 per tonne to US$40–60 per tonne by 2035. Cement and steel start high and fall slowly but remain above US$80 per tonne. DAC costs decline from US$800 per tonne to US$345 per tonne by 2035 under an optimistic 8 % annual improvement, still well above conventional capture.

Break‑even analysis with §45Q credit

Figure 2 – Net cost after applying §45Q credit (US$85/t for most sources; US$130/t for DAC; US$60/t for ethanol). Under the assumed cost declines, many technologies become profitable (net cost ≤ 0) almost immediately because the credit exceeds the baseline cost. However, this outcome reflects the generous U.S. incentive and not the financial reality in most regions. Cement and DAC remain far above break‑even; even by 2035, DAC costs after credit are ~US$215 per tonne, implying that large subsidies or high carbon prices would be needed. The model therefore highlights that policy design (credit value, contract length and transferability) will determine which projects are viable.

Inflection points and uncertainties

• Second‑generation power capture – The transition from first‑of‑a‑kind projects (BD3, Petra Nova) to second‑generation designs (Shand) is an important inflection point. Modular equipment, larger capture volumes and waste‑heat integration reduce capital costs by 67 % and push capture costs to ~US$45 per tonneccsknowledge.com. Such designs could make coal and gas retrofits economically viable under current credits.
• Advanced solvents and process intensification – Water‑lean solvents and enzymatic systems claim capture costs of US$28–44 per tonneglobalccsinstitute.com, significantly below today’s amine systems. Commercial deployment of these technologies before 2030 would accelerate cost reductions and could make steel and cement capture competitive.
• Scale economies vs. small‑scale applications – IEAGHG analysis indicates that small‑scale capture (<100 MW or <100 kt CO₂ per year) has costs up to US$90–103 per tonne and negative net present value under current policiespublications.ieaghg.orgpublications.ieaghg.org. Unless design improvements dramatically cut CAPEX or bespoke incentives are offered, small projects will remain niche.
• Direct air capture – Even with an optimistic learning rate, DAC costs remain several hundred dollars per tonne by 2035. Policy signals such as the §45Q DAC credit (US$180–130/t) help but are insufficient for widespread deployment. Large‑scale demonstration and process breakthroughs would be necessary to create a step change in DAC costs.
• Policy and financing risk – European projects exhibit cost overruns and technology risk, with average capture costs of US$198 per tonneieefa.org, raising doubts about whether expected carbon prices will be adequate. Financing costs also strongly influence levelised cost; a higher cost of capital can raise capture costs by 30–65 %iea.blob.core.windows.net. Stable long‑term policy frameworks are therefore critical for investment decisions.

Implications for policy and investors

1. Prioritise high‑concentration, low‑cost applications – Natural‑gas processing, ethanol fermentation and hydrogen production offer capture costs below the §45Q credit and can supply relatively pure CO₂ streams. Scaling these early “low‑hanging‑fruit” projects can reduce emissions quickly and build transport‑storage infrastructure.
2. Support second‑generation power and industrial capture – Lessons from BD3 and Petra Nova highlight the importance of heat integration and modularisation. Investments in second‑generation coal and gas retrofits and advanced solvents could cut costs to US$40–60 per tonne, making projects economically viable under §45Q and similar incentives.
3. Address cement and steel – These sectors face high costs and limited revenue streams. Policies could include higher carbon prices, targeted tax credits, contracts for difference or material‐specific mandates. Technology innovation (e.g., oxy‑fuel combustion, calcium looping) and waste‑heat integration are essential.
4. Be cautious with direct air capture – DAC is unlikely to reach <US$200 per tonne before 2035news.mit.eduweforum.org. Investments should focus on R&D and demonstration rather than large‑scale deployment, and credible accounting rules for carbon removal are essential.
5. Mitigate financing and policy risk – High cost of capital can substantially increase capture costsiea.blob.core.windows.net, and European experiences show that costs may exceed forecastsieefa.org. Long‑term tax credits, low‑cost loans, and risk‑sharing mechanisms such as government‑backed contracts for difference can lower financing costs and attract private investment.

Conclusion

Carbon capture costs have declined over the last two decades, but the pace varies widely by sector. Concentrated industrial streams already achieve costs below US$30–50 per tonne, while cement, steel and power generation require US$60–120 per tonne today and will need substantial capital cost reductions or policy support to compete. Direct air capture remains several times more expensive and is unlikely to play a major role before 2035. Real‑world case studies show that learning from early projects and integrating waste heat, modular equipment and advanced solvents can cut costs dramatically. Policy incentives such as §45Q can make many projects economically viable but must be complemented by long‑term carbon pricing, low‑cost finance and targeted support for hard‑to‑abate sectors. Achieving cost‑effective carbon capture by 2035 is possible for many applications but will require sustained innovation, infrastructure build‑out and proactive policy design.

Figure 3 – Abstract representation of carbon capture, symbolising industrial flue gases being drawn into a futuristic capture system.