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The $100/ton figure for the Levelized Cost of Captured CO₂ (LCoCO₂) has become a widely cited benchmark in the Direct Air Capture (DAC) industry. But this number is frequently misunderstood, often conflated with a market price, a guaranteed future cost or a universal industry standard.
In reality, LCoCO₂ is not a universal figure.
The original $100/ton reference emerged from a 2018 peer-reviewed study by Carbon Engineering, which projected long-term costs between $94 and $232 (in 2016 dollars) under specific assumptions. Adjusted for inflation to 2024, that $100 target is already closer to $130 per ton. By 2030, assuming modest 2% annual inflation, it would approach $145.
More importantly, the figure was never intended as a universal benchmark across geographies, energy systems or deployment models.
Two DAC providers can present similar cost figures and arrive there using entirely different assumptions about energy integration, utilization rate, storage infrastructure, and financial structure. Without understanding those assumptions, the number alone is incomplete.
To move from a mythical figure to a more realistic estimate, decision-makers must understand what actually drives LCoCO₂.
The LCoCO₂ calculation combines cost inputs, financial assumptions and system performance. Not every variable is a direct cost, but each one affects the final cost per ton.
Capital expenditure (CAPEX): Depreciation of core equipment, installation, and infrastructure.
Fixed operating expenses (OPEX): Labor, insurance, maintenance, consumables.
Capital Recovery Factor (CRF): The financial factor used to spread upfront CAPEX over the lifetime of the project, based on the cost of capital and operating years. This reflects financing conditions, not system performance.
Energy requirements and energy pricing: Electricity and/or heat needed for regeneration and compression.
Annual net CO₂ removed: The amount CO₂ captured over a year of operation. This is not a cost factor, but the output used to calculate cost per ton.
These variables do not operate independently. Design choices in one area influence performance and cost elsewhere. LCoCO₂ is therefore the result of a system architecture versus a standalone equipment price.
The following variables illustrate why no single universal cost can apply to a DAC project.
Energy can be the largest long-term cost component of a DAC project. A 2021 assessment by the International Energy Agency Greenhouse Gas R&D Programme (IEAGHG) found that energy can account for up to 50% of total cost.
Cost is driven by how much energy is needed to "regenerate" or release the CO₂. There are two main ways to release the CO₂ once it has been captured from the air:
Using heat: Most established systems use heat to release the gas from the capture material. The cost drops significantly if a project can use "low-grade" waste heat (around 80°C) from nearby factories, data centers, power plants or geothermal. Using this heat can reduce the machine's electricity needs by over 60%.
Using electricity: Other methods use electrical power or chemical changes instead of heat to release the CO₂. These "all-electric" systems do not need a heat source, but are generally still in early stages of development. While promising for the future, they currently face high costs for specialized components like chemical membranes.
Beyond the choice between heat and electricity, system design and local energy integration play an important role in determining overall energy costs. Strategic co-location with renewable energy and behind-the-meter power can further reduce grid exposure, transmission costs and tariff risks.
Energy integration decisions can materially shift the final LCoCO₂ outcome.
Ambient temperature and humidity influence capture chemistry performance. Cold and humid conditions can reduce capture costs, while hotter or drier climates may increase energy requirements.
Transport distance to storage also introduces measurable cost. Even modest per-kilometer penalties accumulate at scale.
Storage type matters significantly:
Onshore saline aquifers may cost only a few dollars per ton.
Offshore or technically complex reservoirs can increase storage costs dramatically due to infrastructure and injection requirements. Site flexibility is a benefit of DAC, but infrastructure proximity remains economically relevant.
If a DAC system operates only when intermittent solar energy is available, capacity factors may fall to 25–30%, spreading capital over fewer captured tons. Integrating storage or hybrid energy systems can raise utilization above 80%, materially lowering cost per ton.
System design also affects efficiency. Continuous processes typically avoid the energy losses associated with frequent start-stop cycles, improving performance and the longevity of capture material.
The intended use of captured CO₂ determines downstream processing.
Industrial uses may accept ~98% purity. Food and beverage applications require ~99.9% purity.
Permanent geological storage requires compression (often ~150 bar), increasing both CAPEX and energy demand.
End-use CO₂ specification directly influences system design and cost structure.
Subsidies contribute to accelerating DAC market viability. They bridge the gap between the gross LCoCO₂ (the technical cost) and the net cost customers actually pay. This distinction is critical, but widely misunderstood:
Gross LCoCO₂: The technical cost of capture.
Net delivered cost: The cost after CapEx subsidies, tax credits or Contracts for Difference.
Incentives do not change physics, but they do alter project viability and risk profile. CapEx support, operating subsidies and early-stage grants can bridge early market gaps and accelerate deployment.
For decision-makers, evaluating both gross and net cost scenarios contribute to realistic financial modeling.
Early DAC projects may secure favorable access to transport networks, storage capacity or incentive frameworks. Delayed deployment may mean different regulatory conditions, infrastructure costs or competitive pressure.
It is also important to distinguish between temporary on-site storage and permanent geological sequestration, as these have different long-term cost implications and risk profiles.
Universal cost claims provide a false sense of security and do not help companies accurately build, plan or finance successful DAC projects.
The relevant question is not just, “What is the cost per ton?” It is, “What assumptions is that cost built on?”
For decision-makers evaluating DAC technologies, having transparency around these variables is key to setting a DAC project up for success.
Skytree Stratus is engineered to optimize these cost drivers: from a moving-bed Temperature Vacuum Swing Adsorption (TVSA) architecture that lowers electricity consumption and extends sorbent life, to AI-driven dynamic process control that delivers a consistent, stable and reliable flow of CO₂ in any location and environment. We model LCoCO₂ as a system-level outcome, incorporating a site’s specific energy sources and infrastructure to provide a realistic, bankable economic path for any DAC project.
Interested in assessing the levelized cost for your next DAC project? Request a project-specific LCoCO₂ assessment to understand how these variables shape your project’s outcome.