Carbon capture in 2026: 45Q economics, project pipeline, and the gap between announcements and tonnes stored

Where the build-out actually stands #

The Global CCS Institute counted roughly fifty operational commercial CCUS facilities at the end of 2024, with combined capture capacity of about fifty million tonnes per year. The pipeline reached 392 projects across all stages of development, with a nameplate target near seven hundred million tonnes per year if every project reaches FID at design rate. That gap, fifty operational versus seven hundred announced, is the single most important number in the sector, because the historical conversion rate from early-stage announcement to operating tonnes has been low and timelines have been long.

The operational fleet is still dominated by gas processing, fertilizer, and ethanol. Shell Quest in Alberta has injected roughly nine million tonnes cumulatively since 2015 at a 1.4 million tonne per year nameplate. Equinor Sleipner and Snohvit remain the longest-running offshore storage projects. What shifted in 2024 and 2025 is the arrival of the first commercial-scale direct air capture plant, Stratos in the Permian, and the first cement-sector capture facility, Heidelberg Brevik in Norway at four hundred thousand tonnes per year. Both reset the operational frontier.

The pipeline is heavily weighted toward North America and Europe. The United States accounts for roughly forty percent of announced capacity, driven by 45Q. Europe is anchored by Northern Lights, Porthos and Aramis in the Netherlands, and the UK East Coast Cluster and HyNet, all operating under contracts for difference or equivalent revenue support. Asia is smaller but growing, led by the announced 4.6 billion dollar Petronas and Pertamina ASEAN LNG-CCS partnership and a wave of Chinese coal and chemical projects. 2026 is the year the sector finds out which announcements survive permitting, financing, and offtake.

The 45Q stack and what it actually pays #

Section 45Q as amended by the Inflation Reduction Act is the single most important policy lever in the sector. The credit pays eighty-five dollars per tonne for carbon dioxide captured from industrial or power sources and securely stored, sixty dollars per tonne for enhanced oil recovery or qualified utilization, and one hundred eighty dollars per tonne for direct air capture with geologic storage. The DAC utilization tier pays one hundred thirty dollars per tonne. Credits run for twelve years from the placed-in-service date. The IRA opened two new monetization paths: direct pay under section 6417, available to taxable entities for the first five years, and transferability under section 6418.

Direct pay was the more consequential change for the IRA-era pipeline. It let sponsors with limited tax appetite monetize the credit as a cash refund without raising tax equity, collapsing transaction costs for mid-sized projects. Transferability has emerged as the preferred path for sponsors with sufficient tax capacity. The 45Q transfer market traded at modest discounts to face value through 2025, generally three to seven cents on the dollar depending on vintage, project quality, and counterparty diligence.

The post-IRA stack is now large enough to close most point-source projects on a standalone basis when paired with a credible transport and storage solution. For a typical post-combustion retrofit on a cement plant or ammonia facility, full-cycle costs land between fifty-five and one hundred dollars per tonne captured, comfortably below the eighty-five dollar credit. The economics break down for high-cost segments, especially DAC and decarbonized cement at small scale, where the one hundred eighty dollar DAC tier is necessary and still not always sufficient. The April 2025 National Security Presidential Memorandum directed Treasury and DOE to review the DAC tier specifically, which has injected real policy risk into the next wave of DAC FIDs.

The flagship projects and what they signal #

Stratos, built by Occidental subsidiary 1PointFive in Ector County, Texas, started commissioning in late 2025 at a five hundred thousand tonne per year nameplate, making it the largest DAC facility in operation by an order of magnitude. The project closed offtake agreements with Microsoft, Amazon, AT&T, and Salesforce. DOE awarded the adjacent South Texas DAC Hub, Project Cypress, 1.2 billion dollars in August 2024. The signal Stratos sends is that DAC at a few hundred dollars per tonne can attract investment-grade hyperscaler offtake, but the gap to the IEA Net Zero target of one hundred to two hundred dollars per tonne by 2030 remains wide.

DOE OCED anchors the US first-of-a-kind portfolio. The August 2024 award of 1.4 billion dollars to the Heirloom and Battelle California DAC Hub, paired with Project Cypress, committed roughly 2.6 billion dollars to the first two regional DAC hubs. The October 2023 hydrogen hub awards, seven billion dollars across seven hubs, channel meaningful capital into blue hydrogen with CCS. Political risk under the second Trump administration is uneven: funded obligations are largely safe, but milestone disbursements and unobligated balances remain exposed.

On the point-source side, Heidelberg Brevik came online in Q4 2024 as the first cement CCS facility, capturing four hundred thousand tonnes per year with shipment to Northern Lights. Holcim Lagerdorf in Germany is following the same configuration. ExxonMobil Baytown, planned at one million tonnes per year of low-carbon hydrogen and roughly seven million tonnes per year captured, is the largest single US pipeline project but has slipped past its earlier FID target, hinging on 45V clarity and Class VI permitting. Northern Lights ramped its first phase to 1.5 million tonnes per year in Q3 2025, with Phase Two expansion to five million tonnes planned. Climeworks Mammoth came online in May 2024 at thirty-six thousand tonnes per year, the largest non-US DAC plant, at indicated all-in costs near six hundred dollars per tonne.

The bottlenecks that actually decide outcomes #

Class VI well permitting is the single largest bottleneck for US CCUS at scale. EPA retains primacy in most states. Only North Dakota, Wyoming, Louisiana, and West Virginia held delegated primacy through 2024, with Texas and Arizona advancing. EPA's historical average review time has been close to four years, though rulemaking and staffing increases have shortened active timelines and the wave of permits issued in 2024 and 2025 reflects that shift. The Summit Carbon Solutions saga, with permit denials in South Dakota and ongoing legal disputes through 2025, illustrates how state pipeline siting risk can stall multi-billion dollar projects regardless of 45Q economics.

Carbon dioxide pipeline siting is the second binding constraint. The US carbon dioxide pipeline network is roughly fifty-five hundred miles, almost entirely sized for enhanced oil recovery in the Permian and Gulf Coast. Princeton REPEAT analysis suggests meeting IRA-era ambitions requires twenty thousand to sixty thousand miles of new pipeline by 2050. PHMSA finalized updated safety standards in 2025 but did not address routing authority. European hubs sidestep much of this with shipping, the Northern Lights model proving a maritime backbone can substitute at moderate cost.

Hyperscaler offtake is the demand-side bottleneck for DAC and high-quality removals. Microsoft, Google, Amazon, Meta, Salesforce, JPMorgan, and Stripe Frontier have signed roughly fifteen million tonnes of cumulative removal contracts since 2023, with Microsoft accounting for the majority. Pricing sits in a wide band of one hundred fifty to seven hundred dollars per tonne for engineered durable removals. The market is concentrated and immature. A pullback by any one of the top three buyers would materially affect the bankability of the next wave of DAC FIDs.

Where the dollars are flowing and where the cost curve actually lands #

Capital deployed into CCUS through 2025 reflects the new economics. The IEA estimates announced CCUS investment globally exceeds eighty billion dollars across the active pipeline, with roughly thirty billion already committed through FID. Project finance for point-source retrofits is now closing on terms approaching conventional energy infrastructure when 45Q is bankable, with debt service coverage based on capture credits and long-term offtake.

Cost trajectories diverge sharply by archetype. Point-source capture at sixty to one hundred dollars per tonne is converging slowly, with single digit annual reductions from amine solvent improvements, heat integration, and modular designs. The IEA projects point-source costs at high learning facilities falling twenty to thirty percent by 2030, meaningful but not transformative. DAC is where the cost curve is genuinely contested. Stratos and Mammoth operate in the three hundred fifty to six hundred dollar per tonne band. The IEA Net Zero scenario requires DAC at one hundred to two hundred dollars per tonne by 2030, a three to fivefold reduction in five years that demands step changes in sorbents, low-cost clean power, and scale economics that are technically plausible but operationally unproven.

The intersection with Section 45V clean hydrogen rules matters more than most CCUS analysts acknowledge. Blue hydrogen producers can stack 45Q at eighty-five dollars per tonne with 45V at up to three dollars per kilogram for sufficiently low lifecycle emissions, although the final 45V Treasury rules issued in early 2025 set strict additionality, deliverability, and temporal matching requirements that constrain stacking. Projects that secure both credits and meet thresholds are highly competitive with grey hydrogen. Projects that fall short face materially weaker economics.

Recommendations by buyer type #

For industrial emitters in cement, ammonia, ethanol, gas processing, and refining, the right move is to develop a credible retrofit plan now, before EPA Class VI queues lengthen and pipeline siting becomes harder. Sponsors that secured permits in 2024 and 2025 hold durable optionality. The single most valuable early move is locking in storage offtake at a credible hub, because storage capacity is the binding constraint in several regions.

For hyperscaler and corporate offtakers buying durable removals, the discipline is portfolio construction. A portfolio that combines DAC, biomass with carbon removal and storage, mineralization, and high-integrity afforestation, balanced across vintage, geography, and technology risk, dominates a pure DAC strategy. The right structure is tiered: fixed-price reserved volumes for near-term obligations, milestone-based contracts for medium-term scale, and option contracts for long-term delivery.

For DAC firms, the priority is operational hours, sorbent cycle data, and verified tonnes at scale, not winning new awards. The constraint is no longer capital. It is engineering execution and the cost curve. Investors and offtakers will increasingly differentiate sponsors on kilowatt-hours per tonne, sorbent stability, and parasitic load. Firms that publish operating data credibly, even when early performance lags targets, will attract capital that values transparency.

For project finance and infrastructure investors, the underwriting opportunity is shifting from greenfield development risk to operational and aggregation risk. Storage hubs, carbon dioxide pipeline midstream, and 45Q transfer structures are now bankable products with tradable terms. The April 2025 NSPM review of the DAC tier is the most important political event for the sector through 2026. Investors who model the risk explicitly, with a base case where the tier holds, an adverse case where it narrows, and a stress case where it is curtailed, will price assets more accurately than those treating the credit as fixed.

Sources #

• Global CCS Institute, Global Status of CCS 2024
• IEA, CCUS Projects Database
• IEA, CCUS in Clean Energy Transitions
• IRS, Section 45Q Credit for Carbon Oxide Sequestration
• IRS, Final Regulations on Direct Pay and Transferability (sections 6417 and 6418)
• DOE Office of Clean Energy Demonstrations, Regional Direct Air Capture Hubs
• DOE OCED, Hydrogen Hubs Program
• EPA, Class VI Wells Used for Geologic Sequestration of Carbon Dioxide
• Occidental and 1PointFive, Stratos Direct Air Capture Facility
• Microsoft, Carbon Removal Portfolio and Stratos Offtake Announcement
• Climeworks, Mammoth Plant Commissioning
• Heidelberg Materials, Brevik CCS Project
• Equinor, Northern Lights Joint Venture
• ExxonMobil, Baytown Low-Carbon Hydrogen Project
• Shell, Quest Carbon Capture and Storage Project
• NETL, Carbon Capture Project Database
• PHMSA, Carbon Dioxide Pipeline Safety Standards
• Princeton REPEAT Project, Carbon Dioxide Pipeline Buildout Analysis
• Reuters, Trump NSPM Review of IRA Energy Tax Credits, April 2025
• Bloomberg, Petronas Pertamina ASEAN LNG-CCS Partnership
• Petronas, CCS Partnership Announcement