CCS Has One Job No Other Technology Can Do, And the Race to Do It Cheaply Is Accelerating
Carbon capture has crossed from demonstration to commercial deployment, but the technology landscape is diverse, and the winner will be decided by a single variable: how dilute is your CO2?
Carbon dioxide emissions are not a monolith. An ethanol fermentation plant exhales a stream that is more than 95% pure CO2, practically demanding to be captured. A natural gas combined cycle (NGCC) power plant produces exhaust at roughly 3–4% CO2 — a fraction of the concentration, requiring far more energy and equipment to process the same amount of carbon. The open atmosphere sits at 0.04%, a dilution so extreme that capturing a tonne of CO2 from it requires processing an enormous volume of air.
That gradient — from 95% to 0.04% — is the most important variable in all of carbon capture economics. It determines cost. It determines technology choice. It determines which projects get built and which stay on whiteboards. It is why the global carbon capture and storage (CCS) industry is bifurcating sharply between approaches that work at reasonable cost today and approaches that remain expensive but strategically necessary for the long term.
The scale of what is at stake is large. The International Energy Agency’s (IEA) Net Zero Scenario requires roughly 1.2 billion metric tonnes of CO2 captured and stored per year by 2030, rising to 6.2 billion tonnes by 2050.1 Current operating capacity globally stands at 51 million metric tonnes per year — across 50 commercial projects.13 The gap between where we are and where we need to be is roughly 120x over 25 years. That is not a rounding error. That is an industry that needs to be built.
The IEA estimates that closing that gap requires $160 billion in cumulative investment through 2030 alone — a 10x increase from the prior decade.1 The US Energy Information Administration (EIA), in its 2025 Annual Energy Outlook, projects US CO2 capture peaking at just under 71 million metric tonnes in 2039 — less than 2% of the country’s overall energy emissions, even with 45Q tax credits at $85 per tonne driving deployment.3
CCS will not solve the climate problem alone. But it is necessary for a category of emissions that cannot be decarbonized any other way — and the technology choices being made right now will determine which projects are economic, which are not, and which industries emerge from the energy transition with a credible path forward.
This is Part 1 of a two-part series. This article maps the technology landscape, explains the concentration gradient that drives all CCS economics, and examines where the industry’s honest track record stands. Part 2 will cover the industrial acquisition wave, the commercial models emerging from it, and why a deal signed in October 2025 between Google and a Decatur, Illinois power developer signals that CCS is about to find its largest new customer: the data center.
The Last Mile, Explained
The phrase “last mile” in CCS is not rhetorical. It describes a technical reality that applies across the decarbonization landscape: most emissions can be addressed by switching fuels, deploying renewables, or improving efficiency. A shrinking but significant category cannot.
Cement production emits roughly 2.4 billion tonnes of CO2 per year globally — approximately two-thirds of which comes from the calcination reaction that converts limestone to clinker.2 This process CO2 is chemically unavoidable: it is the product of the reaction itself, not a byproduct of burning fuel. Electrification cannot eliminate it. Fuel switching cannot avoid it. Only carbon capture removes it.
Steel production, chemical manufacturing, and several other industrial processes share a similar structure. The IEA estimates that carbon capture and utilization/storage (CCUS) delivers 38% of emissions reductions in the chemicals sector and roughly 15% in cement and iron and steel under its Sustainable Development Scenario.2 These are not sectors where CCS competes with renewable electricity — they are sectors where CCS is the only option.
The IPCC’s Sixth Assessment Report (AR6) makes this point in aggregate. All scenarios limiting warming to below 2°C rely on some degree of carbon dioxide removal. Even the most renewable-heavy 1.5°C pathway requires more than 3 billion tonnes captured annually by 2050.4 The IPCC’s median scenario for low-overshoot 1.5°C pathways requires 196 billion tonnes cumulative stored through 2050.4
That number is not achievable through direct air capture at current costs, nor through a single technology. It requires scaling every viable approach — industrial point-source capture, natural gas generation with CCS, bioenergy with CCS, and eventually DAC — simultaneously. The question is not whether CCS matters. The question is which technologies get there fastest, at what cost, and under what conditions they work.
The answer starts with a chart you won’t see discussed enough.
The Concentration Gradient Is Everything
NETL’s 2022 study of industrial CCS costs across nine sectors is one of the most useful datasets in the field.5 It separates sources into two categories that explain almost everything:
High-purity streams (greater than 95% CO2): Ethanol fermentation, ethylene oxide production, ammonia synthesis, natural gas processing. Average capture cost: $17.50 per tonne. The economics are favorable today, in many cases without 45Q credits.
Low-purity streams (less than 50% CO2): Cement, steel, gas-to-liquids. Average capture cost: $62.00 per tonne. These require policy support — specifically the 45Q credit at $85 per tonne for geological storage — to be economically viable.
NGCC power plants sit at the challenging end of the dilute-stream category. At 3–4% CO2 in the exhaust, capturing 90% requires a $61-per-tonne process based on NETL’s updated 2023 baseline.6 That is marginal economics with 45Q, which is why the first large-scale NGCC project with integrated CCS required a Google power purchase agreement (PPA) to anchor the financing — the credits alone were not sufficient. As we examined in our analysis of hyperscaler carbon accounting and the structural disclosure gap between climate commitments and physical power infrastructure, the data center sector’s simultaneous expansion of fossil generation and CCS contracting reflects a deep tension in how large technology companies are managing scope emissions obligations.
DAC sits at the extreme. The Stratos project (1PointFive/Occidental, West Texas) is targeting $400–$500 per tonne at current scale.16 The Harvard Belfer Center’s analysis of long-term cost trajectories projects $341 per tonne for liquid solvent systems and $374 per tonne for solid sorbent systems at 1 billion tonnes of cumulative deployment — the frequently cited $100-per-tonne DAC target is not achievable at any near-term scale.17
The concentration gradient is therefore the deployment sequence. High-purity industrial streams first. Then coal combustion (10–14% CO2). Then gas combustion (3–4%). Then DAC. Each step down the concentration curve requires either better technology, higher subsidies, or a customer willing to pay a premium — and usually all three.
Five Approaches to the Same Problem
The CCS technology landscape is commonly simplified to “amine scrubbing” — a characterization that captures the dominant commercial approach but obscures the dynamic competitive environment forming beneath it. Five distinct capture approaches exist, each with specific strengths, limitations, and trajectories. Understanding them is prerequisite to evaluating which projects will succeed.
Amine Absorption: The Established Standard
Amine absorption — specifically liquid-solvent scrubbing using amines such as monoethanolamine (MEA) or proprietary advanced formulations — is the TRL 9 benchmark of CCS technology. It is how 18 of the world’s commercial-scale post-combustion CCS plants operate, including those using Mitsubishi Heavy Industries’ (MHI) KM CDR Process.18 It works. It is commercially proven. And it carries a set of operational challenges that are motivating every alternative technology in this space.
The mechanism: CO2-containing flue gas contacts the amine solvent in an absorber tower, where CO2 binds to the amine at low temperatures. The CO2-laden solvent is then heated to 120–150°C in a stripper column, releasing concentrated CO2. The regenerated solvent cycles back to the absorber. The captured CO2 is compressed for transport or injection.
Performance at commercial scale: MHI’s KM CDR Process guarantees 90% CO2 removal efficiency, with purity of 99.9%.18 The energy penalty — the parasitic load imposed by operating the capture system — runs 15–30% of a plant’s net electrical output. For a 550-megawatt plant capturing at full design rate, that equates to 125 or more megawatts of additional generation capacity required just to power the capture process.12
The drawbacks deserve direct treatment. MEA, the most common benchmark solvent, degrades through two pathways: oxidative degradation from oxygen in the flue gas, and thermal degradation at high regeneration temperatures. The degradation products include nitrosamines and nitramines, compounds classified as potentially carcinogenic.29 Measured solvent loss at Technology Centre Mongstad in Norway reached 1.5 kilograms of MEA per tonne of CO2 captured — significantly above the theoretical range of 0.01 to 0.8 kilograms.29 A life-cycle analysis found that adding MEA-based CCS increases freshwater toxicity impact by a factor of ten from MEA emissions alone.
Physical footprint is a constraint that project developers consistently underestimate. The absorber column for a 500-megawatt plant at 90% capture can exceed 150 meters in height. This is not a trivial retrofit on a plant not designed to accommodate it.
Water consumption increases 38–90% per megawatt-hour when adding CCS, depending on cooling configuration.12 In water-scarce regions, this is a genuine siting barrier.
Why does amine scrubbing dominate despite these drawbacks? TRL 9 maturity. An established vendor ecosystem — MHI, Shell CANSOLV (used in Shell’s Quest project), BASF/Linde, Fluor Econamine — provides engineering certainty and proven performance guarantees. For dilute streams in the 3–14% CO2 range, amine scrubbing achieves higher CO2 recovery at lower energy cost than any competing alternative currently at commercial scale. The toxicity and footprint issues are manageable. The capital cost is known. Lenders will finance it.
For the next 5–7 years, amine scrubbing will win most large-scale project competitions on industrial and power sources. The question is whether the challengers can close the gap.
Cryogenic Separation: High Performance, Pre-Commercial
Cryogenic carbon capture (CCC) exploits the physical behavior of CO2 at low temperatures: CO2 desublimes (transitions directly from gas to solid) when cooled below approximately -78°C, allowing it to be separated from flue gas and collected as a frost-like solid on heat exchanger surfaces. The CO2 is then melted, compressed, and collected.
The technology was developed by Sustainable Energy Solutions (SES), whose assets were acquired by Chart Industries. DOE/NETL-funded technoeconomic analysis found the CCC process achieves 30–50% lower overall energy and economic costs than competing processes involving air separation units or solvents, with a parasitic load below 17% of plant output — roughly half the energy demand of equivalent amine scrubbing.26 Projected cost: under $45 per tonne, well below amine scrubbing benchmarks at comparable conditions.26
An additional advantage: cryogenic separation simultaneously removes co-contaminants — sulfur oxides (SOx), nitrogen oxides (NOx), and mercury — from the flue gas, potentially reducing downstream treatment requirements.2730
The limitation is concentration sensitivity. Energy requirements for cryogenic capture range from 2.4 to 5.2 gigajoules per tonne of CO2, varying significantly with inlet CO2 concentration.27 At 20% CO2 concentration, the process requires approximately 350 kilowatt-hours per tonne. At 10%, that rises to 550–600 kilowatt-hours per tonne.27 For NGCC exhaust at 3–4% CO2, the energy penalty becomes steep — cryogenic is not the preferred approach for dilute gas streams. It suits medium-to-high concentration industrial sources (cement, steel, waste-to-energy) far better.
Commercial status: TRL 5–7. Field pilot testing completed at Laramie, Wyoming. No full commercial-scale installations as of 2025. Chart Industries is pursuing commercialization.30
Membrane Separation: Lowest Capex, Highest Power for Dilute Streams
Polymer membranes exploit differential permeability — CO2 passes through the membrane material faster than nitrogen or other gases due to higher solubility and diffusivity. Multi-stage membrane cascades can achieve high CO2 recovery and purity from flue gas streams.
The leading commercial technology is MTR Carbon Capture’s Polaris membrane, which is approximately 20 times more permeable than prior commercial CO2-selective membranes. A patented selective recycle process concentrates CO2 in the flue gas before membrane separation, reducing energy and capital cost. In October 2024, MTR announced completion of the world’s largest membrane-based carbon capture plant at the Wyoming Integrated Test Center — 150 tonnes per day from Basin Electric’s Dry Fork coal power plant, achieving 90% capture rate and producing 99.9%-plus pure liquid CO2.2832 This is the first commercial-scale membrane CCS plant to enter operation.
The economic profile is specific: membrane systems offer the lowest capital expenditure among post-combustion separation technologies because the design is mechanically simple — no regeneration columns, no liquid solvent inventory, no heat exchangers for solvent cycling. The capital cost advantage is real.
The energy cost disadvantage is also real. Separation relies on pressure differential as the driving force, and for dilute flue gas at 3–14% CO2, creating sufficient driving force requires significant compression or vacuum work. For NGCC applications, membrane system costs run $50–$100 per tonne — above amine benchmarks at equivalent CO2 concentrations. At higher concentration sources like coal flue gas or natural gas processing, cost competitiveness improves substantially.
The practical implication: membrane separation is well-suited to high-concentration streams, natural gas processing plants, and applications where capital cost minimization is the primary constraint. It is not currently the preferred approach for dilute NGCC exhaust at 3–4% CO2.
Commercial status: TRL 7. MTR’s Wyoming plant represents the frontier.
Adsorption: Three Sub-Types, One Commercial Breakthrough
Adsorption-based capture uses solid materials that bind CO2 selectively, then release it when conditions change. Three distinct sub-types have different performance profiles and application niches.
Pressure swing adsorption (PSA) and vacuum pressure swing adsorption (VPSA) cycle solid adsorbents — typically zeolite 13X or activated carbon molecular sieves — between CO2-loaded and regenerated states using pressure as the driving force. CO2 adsorbs at elevated pressure; desorbs when pressure drops. PSA is TRL 6–7 for pre-combustion and high-concentration applications, where it is already commercially proven for hydrogen purification. Application to dilute post-combustion flue gas (3–14% CO2) faces selectivity challenges at low CO2 partial pressures. Operating costs are roughly comparable to MEA amine at moderate concentration conditions.
Metal-organic frameworks (MOFs) represent the most strategically interesting advancement in the adsorption category. MOFs are crystalline porous materials constructed from metal ions linked by organic ligands, creating extraordinarily high surface area and tunable pore chemistry. The key commercial breakthrough: BASF announced in October 2023 that it became the first company to produce MOFs at scale of “several hundred tons per year” for CCS applications.31 The specific MOF is CALF-20 (Calgary Framework 20), developed in partnership with Canadian CCS company Svante. CALF-20 captures up to 95% of CO2 from industrial point sources using rapid thermal swing adsorption with low-pressure steam. A demonstration at a cement plant in Richmond, Canada captured approximately 1 tonne of CO2 per day from flue gas. Svante claims the CALF-20-based system can capture CO2 at less than half the capital cost of existing amine solutions — an aggressive claim that lacks commercial-scale validation but reflects the real cost structure advantages of solid adsorbents over liquid solvent systems.31
Current TRL: 5–6. The production-scale MOF supply chain is in place. Commercial-scale validation is not yet complete.
Thermal swing adsorption (TSA) uses temperature rather than pressure as the regeneration driving force: CO2 adsorbs when the sorbent bed is cool, desorbs when the bed is heated. This creates a specific advantage for engine and gas compression applications: the waste heat in engine exhaust — at 450–550°C for reciprocating engines, far above the 80–200°C needed for most sorbent regeneration — powers the desorption cycle at minimal additional energy cost.
Caterpillar’s Oil & Gas division developed a three-bed TSA system using molecular sieves and ran a 1,000-hour pilot at an active gas compression site in Northwest Texas using a Cat G3606 natural gas compression engine rated at 1,875 horsepower.35 The pilot captured up to 20 tonnes of CO2 per day. Projected commercial-scale performance: greater than 95% capture rate, under $40 per tonne, capable of 100-plus tonnes per day.35 Regeneration requires no additional electricity — the energy comes from exhaust heat that would otherwise be rejected to atmosphere. Caterpillar’s positioning here mirrors its broader strategy in the data center market, where — as we documented in our analysis of the $42 billion onsite generation boom — the company is building carbon management capabilities into the same engine product lines it sells to oil and gas operators and industrial customers.
This is distinct from Caterpillar’s 2021 acquisition of CarbonPoint Solutions, whose Semi-Closed Cycle (SCC) technology concentrates exhaust CO2 from 3–6% to up to 25% before amine capture, targeting distributed power generation at 1–25 megawatts.23 The TSA approach is for gas compression equipment. Both leverage the unique thermal properties of engine exhaust; both target markets that traditional amine scrubbing at power-plant scale does not efficiently serve.
The Storage Question: What Does “Permanent” Actually Mean?
Carbon captured from an industrial stack has no climate value unless it stays captured. The permanence question — how confident are we that stored CO2 will remain stored? — gets too little attention in most CCS analysis. It should not.
Geological Storage: The 10,000-Year Case
Deep saline aquifers hold the largest identified geological storage potential globally and operate through four trapping mechanisms on overlapping timescales:
Structural trapping is immediate: a confining cap rock prevents upward CO2 migration. This is the primary mechanism at most operating projects.
Residual trapping operates over years to decades: CO2 becomes immobilized in pore spaces as a discontinuous phase, too fragmented to migrate.
Solubility trapping operates over decades to centuries: CO2 dissolves into formation brine, becoming denser than the surrounding fluid and sinking rather than rising. After roughly 1,000 years, this mechanism dominates.
Mineral trapping — the most permanent mechanism — operates on timescales of 500 to 10,000 years: dissolved CO2 reacts with dissolved metals and minerals to form carbonate rock, permanently incorporating the carbon into the geological matrix.
Sleipner, the Equinor CCS project on the Norwegian continental shelf that began injection in 1996, provides the most extensive long-term monitoring dataset in existence. Over 16 million tonnes of CO2 had been stored in the Utsira Formation by 2020 — and continuous injection across 28-plus years of operation has produced zero detected leakage.2 Sleipner is the empirical foundation for geological storage permanence claims, and the data it has generated over nearly three decades makes it the most important monitoring dataset in the field.
The primary leakage risk for geological storage is not cap rock failure — it is existing wells. Abandoned wellbores from prior drilling activities provide migration pathways if well integrity is not maintained. This drives the critical importance of site characterization and the bottleneck discussed below: the EPA Class VI well permitting program.
CO2-Enhanced Oil Recovery: The Permanence Controversy
CO2-enhanced oil recovery (CO2-EOR) injects CO2 into mature oil reservoirs to improve production. One-third to one-half of the injected CO2 is permanently trapped in the reservoir; the remainder is produced with oil, separated, and re-injected in a closed loop.11 Whether CO2-EOR represents carbon storage depends heavily on accounting boundaries.
The Clean Air Task Force’s lifecycle analysis found that CO2-EOR operations initially appear carbon-negative in a short-term accounting window — the CO2 injected for storage exceeds the CO2 produced by combustion of the additional oil recovered. But after roughly 10 years, EOR operations typically turn net carbon-positive when full lifecycle emissions — including combustion of the produced oil — are included.19 ISO Standard 27916:2019 attempts to standardize CO2-EOR accounting but excludes full lifecycle combustion emissions, a significant methodological gap.
Under the One Big Beautiful Bill Act (OBBBA), signed July 4, 2025, the 45Q credit for EOR utilization was equalized with the geological storage rate at $85 per tonne — up from $60 per tonne under the original IRA rate.14 This removes the prior policy differential that had disadvantaged geological storage relative to EOR. Whether EOR-based CCS delivers genuine climate benefit remains contested; what is clear is that the financial incentive structure now treats both equally.
The Concrete Option: Mineralization at Scale
CarbonCure Technologies has deployed more than 750 carbon capture systems in 30-plus countries using a different permanence pathway: injecting captured CO2 into fresh concrete during mixing, where it reacts immediately with calcium silicate hydrates in the cement paste to form nano-sized limestone particles permanently embedded in the concrete matrix. Even if the concrete is demolished, the carbon remains mineralized.
The theoretical scale potential if 10% of global construction materials incorporated CO2 mineralization: 1.6 billion tonnes of CO2 per year — roughly 4.5% of global emissions. Whether that scale is achievable depends on supply chains and cement industry adoption, but the permanence is unambiguous and the deployment pathway is fully commercial today.
The Food-Grade Paradox
Atmospheric CO2 concentration is rising. Commercial CO2 supply is simultaneously declining.
These two facts describe completely decoupled systems. Commercial CO2 supply — the liquid CO2 used for beverage carbonation, food refrigeration, modified atmosphere packaging, and numerous industrial applications — depends on production byproducts from specific industrial processes: primarily ammonia synthesis and ethanol fermentation. Over 60% of global liquid CO2 supply comes from these byproduct streams.36 As European ammonia plants shut down due to high natural gas prices and US ethanol production fluctuates, commercial CO2 supply constricts.
Olivon Advisors estimated that US merchant CO2 supply could fall 33% over the next decade while demand grows approximately 2% per year.36 During shortage periods in 2024–2025, prices reached $600–$1,000 per tonne for some buyers — against a normal bulk rate of $100–$120 per tonne.36
Food-grade CO2 requires purity of 99.9%-plus by volume, with strict limits on specific impurities including acetaldehyde, benzene, and sulfur compounds. Ethanol fermentation CCS — the ADM model in Decatur, Illinois — already produces near-food-grade CO2 as a process byproduct, since the fermentation stream contains no combustion impurities. With standard drying, deodorization, and liquefaction, the food-grade spec is achievable at modest cost premium.
Amine capture from combustion flue gas faces a harder path. MEA degradation products — particularly nitrosamines — must be completely removed before food-grade qualification, requiring additional activated carbon treatment steps. Cryogenic capture and MTR’s membrane process produce 99.9%-plus pure CO2 streams that are potentially compatible with food-grade qualification after standard purification.
The strategic implication: CCS projects co-located with ethanol plants, biogas facilities, or other high-purity sources have a second offtake channel — food-grade CO2 sales at $100–$120 per tonne — that supplements 45Q credit revenue and reduces policy dependency. The incremental cost of upgrading from pipeline-grade to food-grade CO2 adds an estimated $10–$25 per tonne, and the resulting product commands a price premium well above the 45Q credit for geological storage. For a narrow but real category of projects, food-grade CO2 offtake makes the economics work without subsidies.
The technology taxonomy and storage permanence framework above is the reference layer — the five capture approaches, their honest tradeoffs, and what “permanent” actually means across geological storage, CO2-EOR, mineralization, and food-grade utilization. Paid subscribers get the harder analysis: where these projects have actually performed versus design specs, the subsidy math that most CCS coverage sanitizes, which economics work without government support, and the OEM acquisition wave that signals where the real commercial scaling is happening.
Where the Technology Pencils Out: Project Economics, Honestly Assessed
