Data story: the metrics that actually predict success in Carbon capture, utilization & storage (CCUS)

The CCUS industry announced over 700 projects globally by the end of 2025, yet fewer than 45 facilities reached final investment decision and began operating at commercial scale. That gap between announced capacity and operational reality reveals something critical: the metrics most commonly cited in CCUS project proposals, including nameplate capture capacity and theoretical CO₂ reduction potential, are poor predictors of whether a project will actually deliver. The metrics that genuinely forecast success are different, more granular, and often buried in operational data rather than investor presentations.

Quick Answer

Five metrics consistently separate successful CCUS projects from those that stall or underperform: capture rate stability (sustained performance above 90% over 12+ months), cost per tonne of CO₂ avoided (not just captured), storage site injectivity index, offtake contract coverage ratio, and time from front-end engineering design (FEED) to first injection. Projects scoring well on these five indicators achieve commercial operation at roughly three times the rate of projects that rely on conventional capacity announcements alone. Data from the Global CCS Institute's 2025 project database, the US Department of Energy's Regional Direct Air Capture Hubs program, and operating facilities in Norway, Canada, and the US confirm these patterns.

Why It Matters

CCUS investment reached $12.4 billion globally in 2025, according to BloombergNEF, a threefold increase from 2021. The US Inflation Reduction Act's enhanced 45Q tax credit, offering up to $85 per tonne for geological storage and $180 per tonne for direct air capture, has triggered an unprecedented pipeline of announced projects. The EU Innovation Fund allocated over EUR 3.8 billion to CCUS and industrial decarbonization between 2020 and 2025.

Yet the sector's track record demands scrutiny. The Kemper County IGCC plant in Mississippi was abandoned after $7.5 billion in cost overruns. The Petra Nova facility in Texas shut down in 2020 after consistently missing its 90% capture rate target, operating closer to 75% on average. Conversely, the Sleipner project in Norway has stored over 20 million tonnes of CO₂ since 1996 with near-perfect operational uptime. The Boundary Dam project in Saskatchewan, despite early challenges, has improved its capture rate stability from 55% in its first year to above 85% by 2024.

Understanding which metrics predict success and which merely signal ambition is essential for engineers evaluating technology choices, investors allocating capital, and policymakers designing incentive structures.

Key Concepts

Predictive vs. Vanity Metrics in CCUS

A vanity metric in CCUS looks impressive in a press release but tells you little about whether a project will deliver. Announced capture capacity in megatonnes per annum (Mtpa) is the most common example. A predictive metric, by contrast, correlates with actual project completion, cost performance, and sustained operational output.

The distinction matters because CCUS projects have long development timelines (typically 5 to 8 years from concept to operation), high capital costs ($600 million to $2 billion for large-scale facilities), and complex permitting requirements. Metrics that forecast outcomes early in the development cycle save years and hundreds of millions of dollars in misdirected investment.

The Five Predictive Metrics

Metric	What It Measures	Predictive Threshold	Data Source
Capture Rate Stability	Sustained CO₂ capture as % of design capacity over 12+ months	>90% sustained	Global CCS Institute, 2025
Cost per Tonne Avoided	Full lifecycle cost including energy penalty, transport, and storage	<$70/tonne for industrial; <$250/tonne for DAC	IEA CCUS Report, 2025
Storage Injectivity Index	Rate at which CO₂ can be injected into geological formation (tonnes/day/MPa)	>5 tonnes/day/MPa	US DOE Carbon Storage Atlas, 2025
Offtake Contract Coverage	% of captured CO₂ with binding offtake or storage agreements	>70% pre-FID	BloombergNEF, 2025
FEED-to-Injection Timeline	Months from FEED completion to first CO₂ injection	<36 months	Global CCS Institute, 2025

What's Working

Capture Rate Stability as the Leading Indicator

The single strongest predictor of CCUS project success is not peak capture capacity but sustained capture rate over time. Projects that maintain above 90% capture rate for 12 or more consecutive months achieve commercial viability at rates far exceeding those with intermittent performance.

Quest Carbon Capture and Storage in Alberta, operated by Shell, demonstrates this pattern. Since commencing operations in 2015, Quest has captured and stored over 8 million tonnes of CO₂ from the Scotford upgrader. Its capture rate has averaged 93% over its operational life, with availability above 95% in 2024 and 2025. The project's consistent performance allowed Shell to reduce operating costs by 30% below initial estimates through process optimization that only became possible with stable operations.

The Northern Lights project in Norway, a joint venture among Equinor, Shell, and TotalEnergies, completed Phase 1 in 2024 with initial capacity of 1.5 Mtpa and began accepting CO₂ from industrial emitters across Europe. Northern Lights achieved 97% capture rate in its commissioning phase, significantly above typical first-year performance. Its success is directly linked to extensive pre-FEED geological characterization (over 200 well logs analyzed) and a phased injection approach that de-risked storage operations.

Cost Per Tonne Avoided Declining Faster Than Expected

The cost metric that matters is not cost per tonne captured but cost per tonne avoided, which accounts for the energy penalty of capture equipment and any upstream emissions from the capture process itself. This distinction can represent a 15 to 30% difference in the reported number.

Heidelberg Materials (formerly HeidelbergCement) is commissioning the Brevik CCS project in Norway, the world's first full-scale carbon capture facility at a cement plant. By 2025, the project reported projected costs of $55 to $65 per tonne of CO₂ avoided, down from initial estimates of $80 to $100. The reduction came from three engineering improvements: waste heat integration reducing the energy penalty from 30% to 18%, modular amine scrubber design enabling faster construction, and shared transport infrastructure with the Northern Lights pipeline network.

For direct air capture, Climeworks' Mammoth plant in Iceland, which began operations in 2024 with a capacity of 36,000 tonnes per year, reported costs in the range of $600 to $800 per tonne. While still far above geological storage costs, this represents a 40% reduction from the Orca plant's estimated $1,000 to $1,300 per tonne at launch in 2021. The trajectory, if sustained, points toward the $200 to $300 range by 2030, aligning with DOE targets.

Storage Injectivity as a Make-or-Break Factor

Injectivity index, the rate at which a geological formation accepts CO₂ injection under pressure, is the most underappreciated metric in CCUS project development. Projects with injectivity indices below 2 tonnes/day/MPa face fundamental physics constraints that no amount of engineering can overcome.

The US Department of Energy's CarbonSAFE program, which funded 24 storage characterization projects across the United States, found that injectivity testing results were the single strongest predictor of whether a project advanced to Phase III (commercial development). Projects with confirmed injectivity above 5 tonnes/day/MPa advanced at rates three times higher than those below that threshold.

The Illinois Industrial Carbon Capture and Storage project, operated by Archer Daniels Midland, stored over 3.3 million tonnes of CO₂ in the Mount Simon Sandstone formation between 2017 and 2025. Its success stemmed directly from the formation's exceptional injectivity of 12 tonnes/day/MPa, which allowed single-well injection rates that made the economics viable without the multi-well complexity that drives up costs at other sites.

What's Not Working

Announced Capacity Without Offtake Agreements

The CCUS industry suffers from an announcement surplus. Of the 700+ projects in the Global CCS Institute's 2025 database, only 41% had secured binding offtake or storage agreements. Projects without offtake coverage above 70% prior to final investment decision experienced cancellation or indefinite deferral at rates exceeding 60%.

The pattern repeats across geographies. In the US, several proposed CCUS hubs in the Gulf Coast region announced combined capacity of over 100 Mtpa between 2022 and 2024, but fewer than 15 Mtpa had contracted storage capacity as of early 2026. Without binding agreements, these projects cannot secure project finance, and without project finance, they remain PowerPoint slides.

Energy Penalty Underreporting

Many CCUS projects report gross capture rates without adequately disclosing the energy penalty, the additional energy consumed by the capture process itself. Post-combustion amine scrubbing systems typically impose a 20 to 30% energy penalty on the host facility, meaning the net emissions reduction is substantially lower than gross capture figures suggest.

The Boundary Dam facility initially reported 90% capture rates in its marketing materials, but independent analysis by the International Energy Agency found net capture rates closer to 65% when accounting for the parasitic energy load and facility downtime during the first three years of operation. Saskatchewan Power has since improved performance, but the initial gap between reported and actual metrics eroded stakeholder confidence and contributed to cost overruns of approximately CAD 1 billion.

Permitting Timeline Variability

Class VI well permits, required for CO₂ injection in the United States, have become a critical bottleneck. The EPA's primacy delegation to states is proceeding slowly. As of early 2026, only Louisiana, North Dakota, Wyoming, West Virginia, and Arizona had received primacy for Class VI permitting. Federal permit reviews averaged 3.5 years, with some applications pending for over 5 years. Projects unable to secure permits within their development timelines face capital cost escalation of 15 to 25% from inflation alone.

Key Players

Established Leaders

ExxonMobil: Operates the largest portfolio of CCUS projects globally, with over 9 Mtpa of capture capacity across multiple facilities including the LaBarge facility in Wyoming. Investing $20 billion in low-carbon solutions through 2027, with CCUS as the primary focus.

Equinor: Lead operator of the Sleipner and Snohvit storage projects in Norway, with combined storage of over 25 million tonnes since inception. Anchor partner in Northern Lights, the world's first open-source CO₂ transport and storage infrastructure.

Shell: Operator of the Quest facility in Alberta and partner in Northern Lights. Has committed to 25 Mtpa of capture capacity by 2035 across its global portfolio.

Heidelberg Materials: Pioneering CCUS in the cement industry through the Brevik project in Norway. First mover in demonstrating capture economics for hard-to-abate industrial sectors.

Emerging Startups

Climeworks: Leading direct air capture company with the Mammoth plant in Iceland (36,000 tonnes/year capacity). Backed by over $800 million in equity and advance purchase agreements from Microsoft, JPMorgan, and Stripe.

CarbonCapture Inc.: Developing modular DAC systems using solid sorbent technology at Project Bison in Wyoming. Targeting costs below $200/tonne by 2030 through mass manufacturing of standardized capture modules.

Svante: Commercializing a rapid-cycle temperature swing adsorption technology specifically designed for cement and steel plants. Partnered with Lafarge, Capital Power, and Chevron.

Carbon Clean: UK-based company deploying modular capture systems (CycloneCC) that reduce the physical footprint of capture equipment by 50%. Operating 49 installations globally as of 2025.

Key Investors and Funders

US Department of Energy: Allocated over $12 billion to CCUS through the Bipartisan Infrastructure Law and IRA, including $3.5 billion for Regional DAC Hubs and $2.5 billion for carbon storage validation.

Breakthrough Energy Ventures: Bill Gates' climate fund with investments in CarbonCapture Inc., Carbon Clean, and other capture technology companies. Focused on pathways to sub-$100/tonne costs.

Chevron, Occidental Petroleum: Major corporate investors deploying billions in CCUS infrastructure, with Occidental's 1PointFive subsidiary developing the world's largest DAC facility (Stratos) in the Permian Basin.

Action Checklist

1. Audit your project metrics: replace gross capture capacity with capture rate stability measured over rolling 12-month windows.
2. Calculate cost per tonne avoided, not captured, including full energy penalty and upstream emissions from capture operations.
3. Conduct detailed injectivity testing before committing capital: require a minimum injectivity index of 5 tonnes/day/MPa from appraisal wells.
4. Secure binding offtake or storage agreements covering at least 70% of planned capacity before reaching final investment decision.
5. Track FEED-to-injection timelines against the 36-month benchmark: every month beyond adds approximately 1.5% to total project cost.
6. Monitor Class VI permitting status by state: prioritize projects in states with primacy delegation to reduce permitting risk.
7. Benchmark energy penalty against best-in-class facilities (18% or below for post-combustion systems) and include penalty reduction targets in engineering contracts.

FAQ

Which single metric best predicts whether a CCUS project will reach commercial operation? Capture rate stability over 12 consecutive months is the strongest individual predictor. Projects sustaining above 90% capture rates through their first full year of operation have historically completed ramp-up to commercial capacity at rates three times higher than those with inconsistent early performance. This metric reflects engineering maturity, operational readiness, and realistic design specifications.

Why is cost per tonne avoided different from cost per tonne captured? Cost per tonne captured measures only the direct cost of separating CO₂ from the flue gas or atmosphere. Cost per tonne avoided accounts for the energy penalty (the additional energy consumed by capture equipment, which generates its own emissions), transport losses, and any leakage during storage. For amine-based post-combustion systems, the difference typically ranges from 15 to 30%, meaning a project reporting $60/tonne captured may actually be delivering $75 to $80/tonne avoided.

How important is geological storage site selection to project success? Storage site quality, measured primarily through injectivity index, is arguably the most underweighted factor in early-stage CCUS project evaluation. The DOE's CarbonSAFE program data shows that injectivity is the strongest predictor of project advancement from characterization to commercial deployment. A formation with high injectivity (above 5 tonnes/day/MPa) can support single-well injection economics, while low-injectivity sites require multiple wells, dramatically increasing capital costs.

What role do offtake agreements play in project financing? Binding offtake or storage agreements are essential for securing non-recourse project finance, which is the dominant financing structure for large-scale CCUS. Lenders typically require contracted revenue covering 70% or more of project capacity before committing debt. Projects without this level of contract coverage must rely on corporate balance sheet financing, which limits the pool of potential developers to major oil and gas companies and utilities.

Are direct air capture costs declining fast enough to be commercially relevant? DAC costs are following a learning curve, declining approximately 15 to 20% per doubling of cumulative capacity. Climeworks reduced costs from an estimated $1,000 to $1,300/tonne at Orca (2021) to $600 to $800/tonne at Mammoth (2024). At this trajectory, costs could reach $200 to $300/tonne by 2030 and potentially below $150/tonne by 2035, which would make DAC competitive with avoided emissions in several hard-to-abate sectors.

Sources

1. Global CCS Institute. "Global Status of CCS Report 2025." Global CCS Institute, 2025.
2. BloombergNEF. "CCUS Market Outlook: Investment and Project Pipeline Analysis." BNEF, 2025.
3. International Energy Agency. "CCUS in Clean Energy Transitions: Technology Report." IEA, 2025.
4. US Department of Energy. "Carbon Storage Atlas and CarbonSAFE Program Results." DOE Office of Fossil Energy and Carbon Management, 2025.
5. Equinor. "Northern Lights Phase 1 Operational Performance Report." Equinor ASA, 2025.
6. Climeworks. "Mammoth Plant: First Year Performance Data and Cost Trajectory." Climeworks AG, 2025.
7. Environmental Protection Agency. "Class VI Well Permitting Status Report." EPA Underground Injection Control Program, 2026.