Carbon Capture Cost Trends and Projections Through 2035

Introduction

Carbon capture cost trends and projections are shaping climate investment strategies worldwide. In this article, we explore how costs have evolved, where they’re headed by 2035, and what it means for businesses and policymakers. Carbon capture and storage (CCS) encompasses a family of technologies that remove carbon dioxide from combustion flue gases or from the ambient air. Two broad classes dominate today: point‑source capture, which is applied to the exhaust stream of power plants and industrial facilities, and direct air capture (DAC), which scrubs CO₂ directly from ambient air. Other variants such as bioenergy with carbon capture and storage (BECCS) integrate biomass combustion with CCS to achieve net‑negative emissions. Each of these technologies has different cost structures and technological maturity, which makes understanding carbon capture cost trends essential for assessing future deployment.

The cost of capturing CO₂ is typically reported as a levelised cost of CO₂ capture (LCOT) in US $/t CO₂. This metric combines the upfront capital expenditure (CAPEX) for capture equipment, compression and transport infrastructure with ongoing operating expenditure (OPEX) such as energy consumption, maintenance and solvent replacement. In addition, capture facilities usually impose an energy penalty on the host plant. Because these costs are sensitive to plant scale, maturity and financing conditions, the literature often distinguishes between first‑of‑a‑kind (FOAK) projects, which are early deployments, and nth‑of‑a‑kind (NOAK) plants, which benefit from learning and standardisation. Throughout this report the term carbon capture cost trends is used to describe how these costs evolve over time.

This report synthesises historical data, case studies and technology‑specific modelling to analyse carbon capture cost trends for key carbon capture technologies. Where available, projections out to 2035 are developed and presented using cost curves. Inflection points relevant to policymakers and investors are highlighted, along with the drivers underlying cost reductions. Readers interested in the quantitative modelling can jump to the section on modelling carbon capture cost trends for details.

Historical Carbon Capture Cost Trends and Case Studies

This section reviews carbon capture cost trends across historical projects and sectors.

Power‑sector post‑combustion capture

The IEAGHG 2024 benchmarking report provides detailed cost estimates for natural‑gas combined‑cycle (NGCC) and coal power plants with and without post‑combustion capture. For a state‑of‑the‑art NGCC plant without capture the capital cost is 746 £/kW, whereas adding a 90 % capture unit increases CAPEX to 1 470 £/kW; fixed OPEX rises to 41 £/kW yr and variable OPEX to 1.13 £/MWh (publications.ieaghg.org). For supercritical pulverised‑coal (SCPC) plants the CAPEX increases from 3 668 £/kW to 4 530 £/kW when a 90 % capture system is added (publications.ieaghg.org). These values correspond to FOAK plants designed around proprietary amine‑based capture systems.

Historical deployments offer additional insight:

• Boundary Dam Unit 3 – SaskPower retrofitted a 1960s 150 MW lignite unit with CCS in 2014. The retrofit cost roughly US $1.3 billion, including $800 million for the CCS process and $500 million for refurbishing the ageing boiler (ourenergypolicy.org). The energy penalty reduced net output by about 45 MW (≈30 %) (ourenergypolicy.org). Revenue from selling captured CO₂ for enhanced oil recovery (EOR) was around $20/t CO₂ (globalccsinstitute.com), which was insufficient to cover costs without substantial government support.
• Shand CCS feasibility study – A 2018 study assessed a second‑generation capture system at the 305 MW coal‑fired Shand plant in Saskatchewan. By scaling equipment and optimising heat integration, the levelised cost of captured CO₂ was estimated at ≈$45/t – a 67 % reduction per tonne compared with Boundary Dam – while integration costs were reduced by 92 % (ccsknowledge.com). This illustrates the dramatic learning potential between FOAK and NOAK projects.
• Petra Nova – NRG and JX Nippon constructed a 240 MW slipstream capture unit at the W.A. Parish coal plant near Houston in 2017 at a cost of roughly $1 billion (with $195 million of U.S. DOE funding). Instead of capturing 90 % of plant emissions, the project captured roughly 7 % of the total plant emissions because only a portion of the flue gas was processed (energyandpolicy.org). Viability depended on selling CO₂ for EOR; the scheme required oil prices around $75/bbl to break even (energyandpolicy.org). When oil prices slumped, the plant was mothballed in 2020.

Industrial sector capture

Industrial processes such as cement and steel manufacturing emit CO₂ as an inherent part of chemical reactions. The IEAGHG (2018) review compiled cost data across capture technologies. For steel, vacuum pressure swing adsorption (VPSA) offers the lowest CO₂ avoidance cost (≈ $52/t, 2016 US$) (publications.ieaghg.org); advanced smelting reduction with VPSA can reduce it to $34/t (publications.ieaghg.org). Traditional chemical absorption costs $56–82/t (publications.ieaghg.org). In cement plants, solids‑based capture and oxyfuel systems have avoidance costs of $38–86/t, while membranes cost $69–78/t (publications.ieaghg.org). Capture costs per tonne of CO₂ (excluding avoidance denominators) range from $11–63/t for cement and $7–14/t for steel using VPSA (publications.ieaghg.org).

Direct air capture (DAC)

DAC facilities operate at much smaller scales than power‑plant CCS and currently exhibit high unit costs. The Energy Transitions Commission’s 2022 analysis estimated a per‑unit CAPEX of approximately $1 470/t CO₂ capacity for current DAC plants (energy-transitions.org). Their “average DAC” levelised cost of capture (including energy costs) was about $455/t in 2020 and projected to decline to $225/t by 2030, $130/t by 2040 and $85/t by 2050 under 10–15 % learning rates (energy-transitions.org). Expert surveys and the IEA suggest slightly higher long‑term costs ($80–120/t by 2050) (energy-transitions.org). Commercial deployments illustrate the gap between current and projected costs:

• Climeworks’ Mammoth plant (Iceland) – A 2024 article reported that the plant captures around 36 000 t CO₂ yr⁻¹ and currently operates at about $600/t, with a goal of reducing the cost to $300/t by 2030 (cen.acs.org). High costs reflect small plant scale, bespoke equipment and the need to purchase renewable energy.
• Cost of CO₂ storage – The UK’s Offshore Energies UK trade group noted that the cost to transport and store CO₂ offshore currently ranges from $150 to $220/t (cen.acs.org), illustrating that capture costs must be considered alongside transport and storage when evaluating project viability.

Bioenergy with carbon capture and storage (BECCS)

Because BECCS involves biomass combustion followed by CO₂ capture, its costs vary widely depending on feedstock price, plant scale and whether the biomass facility is new‑build or retrofitted. A survey of literature indicates a cost range of $60–250/t CO₂ (en.wikipedia.org). BECCS can deliver net‑negative emissions, so higher costs may be justified in markets with negative‑emissions credits.

Summary of cost components

Across technologies the main drivers of CAPEX include solvent or sorbent systems, heat exchangers, compressors, and auxiliary equipment. OPEX is dominated by energy requirements – amine‑based systems typically consume 15–30 % of plant output – and solvent make‑up. Early FOAK projects bear additional engineering, contingency and financing costs. Learning effects, modularisation, and larger scale are therefore expected to drive down costs for NOAK plants.

Modelling cost trends through 2035

To compare technologies on a consistent basis, we developed simple cost projections using published data and learning assumptions. For each technology, a baseline cost in 2020–2024 was identified from the literature and case studies, then a reduction trajectory to 2035 was assumed based on reported learning rates or FOAK→NOAK reductions. Key assumptions include a 7 % weighted average cost of capital, 30‑year plant life, and a 25 % FOAK→NOAK CAPEX reduction for NGCC and coal CCS consistent with DOE portfolio insights (energy.gov). Table 1 summarises the baseline values used in the model.

Technology	Baseline cost (2020‑24)	Source & rationale
Direct air capture (DAC)	$455/t CO₂ in 2020 declining to $225/t in 2030 and $85/t in 2050 (energy-transitions.org); cost curve fitted exponentially.	Energy Transitions Commission estimate for average DAC with learning rate 10–15 %.
NGCC with CCS	FOAK capital cost intensity $1.7 M/MW and OPEX 4 % of capex from DOE portfolio case study (energy.gov). Capture amount assumed 2 430 t CO₂ MW⁻¹ yr⁻¹. NOAK capex reduces to $1.3 M/MW by 2035 (energy.gov).	DOE 2024 Portfolio Insights; FOAK→NOAK reduction ~25 %.
Coal CCS	FOAK capex assumed $4.5 M/MW (higher than NGCC because of flue‑gas sulphur removal and lower efficiency). Capture amount 5 500 t CO₂ MW⁻¹ yr⁻¹. NOAK capex reduced by 25 % by 2035.	Derived from IEAGHG coal PCC data (publications.ieaghg.org) and DOE learning assumption.
Steel CCS	Cost per tonne today ≈ $12/t based on VPSA capture cost (publications.ieaghg.org). A modest 20 % reduction by 2035 is assumed due to incremental improvements.	IEAGHG industrial survey.
Cement CCS	Base cost $40/t derived from solids‑based capture costs (publications.ieaghg.org). 20 % reduction by 2035 reflects process optimisation and economies of scale.	IEAGHG industrial survey.
BECCS	Mid‑range cost $150/t in 2024 (within the $60–250/t range (en.wikipedia.org)). Decline to $120/t by 2035 is assumed as biomass supply chains improve.	Literature survey and conservative assumption.

Using these baseline values, a simple projection was calculated for each year from 2020 to 2035. Figure 1 plots the resulting cost trajectories. DAC shows the steepest decline, from roughly $450/t in 2020 to $175/t by 2035. NGCC CCS falls modestly from ≈$84/t in 2020 to ≈$62/t in 2035 as FOAK plants give way to NOAK units and financing costs fall. Coal CCS exhibits similar absolute costs but higher values (≈$107/t in 2020 declining to ≈$80/t in 2035) because of higher CAPEX and lower efficiency. BECCS costs remain relatively high (≈$150→$120/t), while industrial applications such as steel and cement show low costs (<$12/t and $40→$32/t respectively) reflecting the absence of large energy penalties. These projections are illustrative; actual costs depend on site‑specific factors.

Break‑even analysis for NGCC capture

We examined the cost components of NGCC CCS more closely using the DOE case study. A FOAK capture retrofit with CAPEX of $1.7 M/MW and OPEX equal to 4 % of CAPEX yields a levelised cost of capture of about $56/t from capital and $28/t from O&M under typical capacity factors. For an NOAK plant with $1.3 M/MW CAPEX and OPEX equal to 3.5 %, the cost falls to $43/t (capital) and $19/t (O&M). Figure 2 visualises this cost breakdown. Policy incentives such as the U.S. 45Q tax credit can reduce the net cost further; the DOE notes that 45Q can reduce the levelised cost of electricity by more than 25 % (energy.gov).

Break‑even conditions for DAC and EOR

DAC plants currently rely on voluntary carbon markets and corporate offtake agreements. With costs around $600/ttoday at the Climeworks Mammoth plant (cen.acs.org), break‑even requires carbon prices well above current compliance market values. The Energy Transitions Commission suggests that costs could fall below $200/t by the early 2030s under optimistic learning, approaching the U.S. DOE target of $100/t by 2030 and $85/t by 2050 (energy-transitions.org).

For point‑source CCS, break‑even depends on revenue from captured CO₂. Projects selling CO₂ for EOR typically realise ≈$20/t CO₂ (globalccsinstitute.com) and require high oil prices (≈$75/bbl) to cover CAPEX and OPEX (energyandpolicy.org). Policy instruments such as 45Q in the U.S. (up to $85/t for geological storage and $60/t for EOR) or the U.K.’s Contract‑for‑Difference mechanism are therefore critical to making CCS investments attractive.

Policy and investment inflection points

Several milestones and inflection points emerge from the historical data and projections:

• DOE cost targets – The U.S. Department of Energy aims to reduce capture costs to < $40/t by 2025 and < $30/t by 2035 (www2.itif.org). Achieving these targets would make point‑source CCS competitive with many abatement options and create a strong investment case. Current projections for NOAK NGCC CCS approach $60/t by 2035, indicating a need for further innovation or policy support.
• FOAK→NOAK transition – The Shand feasibility study demonstrated that second‑generation designs can cut costs by two‑thirds compared with Boundary Dam (ccsknowledge.com). Our modelling suggests that moving from FOAK to NOAK reduces NGCC capture costs by about 25 %, but larger reductions are possible through modularisation, improved solvents and integration with plant heat recovery (publications.ieaghg.org).
• Market price of carbon – For DAC, large cost declines are needed to intersect with plausible carbon prices. If learning rates of 10 % persist and the cost drops below $200/t by the early 2030s, corporate buyers and compliance markets may scale up purchases; if costs remain near $300–400/t, DAC may remain niche.
• Infrastructure and storage costs – Transport and storage currently add $150–220/t (cen.acs.org), though costs are expected to fall as pipeline networks and storage hubs are developed. Projects clustering around shared infrastructure (e.g., U.K. industrial clusters) can reduce these costs dramatically.
• Negative emissions demand – BECCS offers net‑negative emissions but remains expensive. If regulatory frameworks begin valuing negative emissions at > $100/t, BECCS could become attractive despite its high cost range ($60–250/t) (en.wikipedia.org).

Conclusion

Carbon capture technology costs have historically been high because of bespoke designs, significant energy penalties and limited deployment experience. Evidence from projects such as Boundary Dam, Shand and Petra Nova illustrates both the financial challenges and the potential for rapid cost reduction. Industrial applications and BECCS already achieve relatively low per‑ton capture costs but require supportive market mechanisms to be deployed at scale. Our modelling indicates that under plausible learning rates, DAC costs could fall by roughly 60 % by 2035, NGCC CCS by 25 %, and coal CCS by 25 %. Achieving the U.S. DOE’s cost targets will require continued R&D into advanced solvents, process intensification, and improved heat integration. Investment decisions should therefore consider not only current costs but also the steepness of projected learning curves and the value of policy incentives.

In sum, carbon capture costs are trending downward, but the pace of decline varies widely across technologies. Near‑term investments in FOAK projects, supported by mechanisms like 45Q or Contracts‑for‑Difference, can unlock learning that drives costs toward the $30/t level needed for widespread deployment. Policymakers should prioritise infrastructure development and long‑term market signals to ensure that capture, transport and storage systems mature in tandem.

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