Case study: Carbon capture, utilization & storage (CCUS) — a city or utility pilot and the results so far

In September 2024, the Alberta Carbon Trunk Line (ACTL) reached a cumulative milestone of 10 million tonnes of CO2 captured and permanently stored since it began full commercial operations in 2020. The 240-kilometer pipeline, connecting industrial emitters in Alberta's Industrial Heartland to aging oil reservoirs for enhanced oil recovery (EOR) and permanent geological storage, now handles approximately 14.6 million tonnes of CO2 per year at full capacity. According to the International Energy Agency, global operational CCUS capacity reached 49 million tonnes per year by the end of 2025, a 72% increase from 2022, yet still captures less than 0.15% of the 36.8 billion tonnes of CO2 emitted annually from energy and industrial processes (IEA, 2025). For sustainability professionals evaluating municipal and utility-scale CCUS deployments, these pilots offer critical lessons on what works, what costs more than expected, and what can be transferred to other jurisdictions.

Why It Matters

Municipal utilities and city governments face mounting pressure to decarbonize hard-to-abate infrastructure. Cement plants, waste-to-energy facilities, natural gas power stations, and industrial boilers produce concentrated CO2 streams that cannot be eliminated through electrification alone. The US Department of Energy estimates that industrial process emissions account for 23% of total US greenhouse gas emissions, and roughly 40% of those emissions come from sources where CCUS is the most technically viable abatement pathway (DOE, 2024).

Federal incentives have fundamentally changed the economics. The Inflation Reduction Act's enhanced 45Q tax credit now provides $85 per tonne for geological storage and $60 per tonne for CO2 used in EOR, up from $50 and $35 respectively before 2022. For direct air capture (DAC), credits reach $180 per tonne. The Congressional Budget Office projects that 45Q credits will support approximately 110 million tonnes per year of new capture capacity by 2032 (CBO, 2024). Several city and utility pilots launched since 2022 are now generating operational data that reveals the gap between modeled projections and real-world performance.

Key Concepts

CCUS encompasses three distinct process stages. Capture involves separating CO2 from flue gas or process streams using chemical solvents (typically amine-based), physical sorbents, membrane systems, or cryogenic separation. The capture step alone accounts for 60 to 75% of total CCUS system costs. Utilization converts captured CO2 into products such as building materials, chemicals, fuels, or uses it for enhanced oil recovery. Storage involves injecting CO2 into deep geological formations, typically saline aquifers or depleted oil and gas reservoirs, at depths exceeding 800 meters where pressure and temperature keep CO2 in a supercritical fluid state.

For municipal and utility applications, post-combustion capture using amine solvents remains the dominant technology. The energy penalty for capture, defined as the additional energy required to operate the capture system, ranges from 15 to 30% of a power plant's gross output, depending on the technology and CO2 concentration in the flue gas. Higher CO2 concentrations, such as those found in cement plants (15 to 30%) and waste-to-energy facilities (8 to 12%), yield lower capture costs per tonne than dilute sources like natural gas combined cycle plants (3 to 4%).

What's Working

Boundary Dam Unit 3: SaskPower's Utility-Scale Learning Curve

SaskPower's Boundary Dam Unit 3 in Saskatchewan, Canada, became the world's first commercial-scale post-combustion capture system on a coal-fired power plant when it commenced operations in 2014. The 110-megawatt unit was designed to capture 1 million tonnes of CO2 per year using Shell Cansolv amine solvent technology. Initial performance was rocky: during its first full year of operation in 2015, the facility captured only 405,000 tonnes, achieving a 40% utilization rate due to frequent solvent degradation issues, heat exchanger fouling, and compressor reliability problems.

By 2024, SaskPower reported that Boundary Dam Unit 3 had achieved a cumulative capture total of 5.8 million tonnes, with annual capture rates stabilizing at 750,000 to 800,000 tonnes, representing a 75 to 80% utilization factor. Key operational improvements included: switching to a modified amine solvent formulation that reduced degradation rates by 40%, installing online solvent quality monitoring to optimize reclaimer operations, and redesigning the direct contact cooler to handle variable flue gas conditions. The levelized cost of capture declined from approximately $105 per tonne in 2015 to $68 per tonne by 2024 through operational learning and reduced chemical consumption (SaskPower, 2024).

Illinois Industrial Carbon Capture and Storage Project

The Illinois Industrial Carbon Capture and Storage (ICCS) project at Archer Daniels Midland's (ADM) ethanol production facility in Decatur, Illinois, represents one of the most successful municipal-adjacent CCUS pilots in North America. The project captures CO2 from ethanol fermentation, a nearly pure (99%+) CO2 stream that requires only dehydration and compression rather than chemical separation, dramatically reducing costs. Since commencing injection in 2017, the project has stored over 3.5 million tonnes of CO2 in the Mount Simon Sandstone formation at a depth of approximately 2,100 meters.

The Illinois project demonstrated geological storage feasibility at costs of $20 to $25 per tonne (capture plus compression plus injection), substantially below the $85 per tonne 45Q credit, making it economically self-sustaining. Monitoring data from 2017 through 2025 confirmed that the CO2 plume behaved within modeled predictions, with no evidence of leakage detected by the comprehensive monitoring, verification, and accounting (MVA) program that includes seismic surveys, groundwater sampling, soil gas monitoring, and satellite-based surface deformation tracking (Illinois State Geological Survey, 2025).

Edmonton Region Hydrogen Hub and CCUS Integration

The Edmonton region in Alberta has emerged as a model for city-scale CCUS infrastructure integration. The Capital Region Hydrogen Hub, announced in 2023 and now under construction, combines blue hydrogen production from natural gas with carbon capture and storage. Air Products' $1.6 billion Net-Zero Hydrogen Energy Complex, expected to begin operations in 2026, is designed to capture and store over 3 million tonnes of CO2 per year using autothermal reforming with a capture rate exceeding 95%.

The project benefits from existing CCUS infrastructure: the ACTL pipeline provides CO2 transport, and the Heartland region has 30+ years of geological characterization data for storage reservoirs. The City of Edmonton's climate strategy explicitly relies on the hydrogen hub to reduce municipal emissions from transit, building heating, and waste management, projecting a 15 to 20% contribution to the city's 2035 net-zero pathway (City of Edmonton, 2024).

What's Not Working

Petra Nova: Economics Without Policy Support

The Petra Nova project at NRG Energy's W.A. Parish power plant near Houston, Texas, captured approximately 3.8 million tonnes of CO2 between 2017 and 2020 before being mothballed due to low oil prices that made EOR uneconomical. The $1 billion facility captured CO2 from a 240-megawatt slipstream of a 610-megawatt coal unit, using Mitsubishi Heavy Industries' KM CDR Process (advanced amine). When West Texas Intermediate crude oil fell below $30 per barrel in 2020, the revenue from EOR could not cover operating costs. The project demonstrated a critical vulnerability: CCUS projects dependent on utilization revenue from commodity markets face existential risk from price volatility. NRG announced plans to restart Petra Nova in 2023 under the enhanced 45Q credits, but progress has been slow, with the facility remaining offline as of early 2026 (NRG Energy, 2025).

Permitting Delays and Class VI Well Bottlenecks

The US EPA's Class VI well permitting process for CO2 injection has created a significant bottleneck for new CCUS projects. As of January 2026, EPA had received over 180 Class VI permit applications but had issued only 12 final permits. The average review timeline exceeds 3.5 years, with some applications pending since 2020. Several states, including Louisiana, North Dakota, Wyoming, and West Virginia, have received or applied for primacy to administer their own Class VI programs, which is expected to reduce timelines to 12 to 18 months, but transfer of authority creates its own transition delays. For city and utility planners, permitting uncertainty adds 2 to 4 years of project risk that complicates financing and procurement timelines (Clean Air Task Force, 2025).

Cost Overruns in First-of-a-Kind Projects

Capital cost overruns remain common. The Gorgon Carbon Dioxide Injection System in Western Australia, operated by Chevron, experienced a 50% cost overrun ($3.1 billion final cost versus $2.0 billion estimate) and multi-year delays in reaching target injection rates. While Gorgon is an upstream oil and gas project rather than a municipal utility, its experience echoes across the sector: first-of-a-kind CCUS installations consistently cost 30 to 60% more than engineering estimates, primarily due to integration complexity between the capture system and the host facility, procurement delays for specialized equipment, and commissioning challenges (Global CCS Institute, 2024).

Key Players

Established Companies

ExxonMobil: operates the largest portfolio of CCUS projects globally, with 9 million tonnes per year of capture capacity and major investments in the Houston Ship Channel CCS hub.

Shell: developer of the Quest CCS facility in Alberta (capturing 1.3 million tonnes per year from oil sands upgrading) and licensor of Cansolv capture technology.

Mitsubishi Heavy Industries: supplier of the KM CDR Process amine capture technology deployed at Petra Nova and multiple facilities in Japan and Southeast Asia.

Linde: provides CO2 compression, purification, and liquefaction equipment for CCUS projects worldwide.

Startups and Growth-Stage Companies

Svante: develops solid sorbent-based carbon capture technology targeting cement and industrial facilities, with a 30-tonne-per-day demonstration unit operational in British Columbia.

Carbon Clean: offers modular, skid-mounted capture systems (CycloneCC) designed to reduce capital costs by 40 to 50% compared to conventional amine plants.

CarbonCure Technologies: injects captured CO2 into fresh concrete during mixing, permanently mineralizing it while improving compressive strength, with over 800 installations across North America.

Investors and Funders

US Department of Energy: allocated $12 billion for CCUS through the Bipartisan Infrastructure Law, including $3.5 billion for four regional Direct Air Capture hubs.

Canada Infrastructure Bank: committed CAD $2.5 billion for CCUS infrastructure in Alberta and Saskatchewan.

Breakthrough Energy Ventures: invested in Carbon Clean, CarbonCure, and other capture technology developers through its climate technology fund.

Action Checklist

• Conduct a CO2 source characterization study for all municipal emitters exceeding 25,000 tonnes per year, including flue gas composition, flow rates, and spatial concentration
• Evaluate proximity to geological storage formations using US Geological Survey CO2 storage atlas data and state geological survey assessments
• Model project economics under current 45Q credit values ($85/tonne storage, $60/tonne EOR) with sensitivity analysis for credit expiration and extension scenarios
• Engage EPA Region office or state primacy agency early on Class VI well permit requirements and expected timelines
• Assess shared infrastructure opportunities, including multi-source CO2 pipeline corridors and regional storage hubs, to distribute capital costs across emitters
• Establish monitoring, verification, and accounting protocols aligned with EPA Subpart RR reporting requirements and ISO 27914 geological storage standards
• Include community engagement and environmental justice assessment in project planning, particularly for pipeline routing and injection site selection

FAQ

Q: What CO2 concentration threshold makes capture economically viable for municipal emitters? A: Sources with CO2 concentrations above 10% (cement plants, waste-to-energy, some industrial boilers) typically achieve capture costs of $40 to $70 per tonne, well within the $85 per tonne 45Q credit. Natural gas power plants with 3 to 4% CO2 concentrations face capture costs of $60 to $90 per tonne, making economics marginal without stacking additional revenue streams. Ethanol fermentation and hydrogen production produce nearly pure CO2, enabling capture at $15 to $30 per tonne. Municipal planners should prioritize high-concentration sources for initial CCUS deployment.

Q: How do cities manage long-term liability for stored CO2? A: Under current US regulations, the operator bears liability during the injection period and for a post-injection site care period of at least 50 years. After demonstrating non-endangerment, the operator may petition EPA for site closure, at which point long-term stewardship responsibility may transfer to the state or federal government. Several states, including North Dakota, Wyoming, and Louisiana, have enacted legislation establishing state-managed long-term stewardship funds financed by per-tonne fees during the injection phase. For municipal utilities, structuring CCUS projects through public-private partnerships can allocate liability between the utility (which retains the emissions reduction benefit) and the private operator (which manages injection and monitoring).

Q: What is the minimum project scale for cost-effective CCUS at a municipal facility? A: Engineering studies consistently show that CCUS capital costs per tonne decline significantly with scale up to approximately 1 million tonnes per year, beyond which cost reductions flatten. For municipal emitters, a minimum capture capacity of 100,000 to 200,000 tonnes per year (roughly equivalent to a 30 to 60 MW natural gas plant or a 500,000-tonne-per-year cement facility) is generally needed to achieve costs below $80 per tonne. Smaller emitters can achieve viable economics by connecting to shared transport and storage infrastructure rather than building dedicated pipelines and injection wells.

Q: How reliable is geological CO2 storage over long time horizons? A: Monitoring data from over 30 large-scale geological storage projects worldwide, combined with natural analogue studies of CO2 reservoirs that have held gas for millions of years, indicate that properly characterized and managed storage sites retain more than 99% of injected CO2 over 1,000-year timescales. The Sleipner project in Norway has monitored its CO2 plume in the Utsira Formation since 1996, with 4D seismic surveys confirming plume behavior consistent with models and no evidence of leakage. The key risk factor is not geological containment itself but inadequate site characterization, particularly failure to identify legacy wellbores or transmissive faults that could create leakage pathways.

Sources

• International Energy Agency. (2025). CCUS in Clean Energy Transitions: Global Status Report 2025. Paris: IEA.
• US Department of Energy. (2024). Carbon Capture, Utilization, and Storage: A Roadmap for Industrial Decarbonization. Washington, DC: DOE Office of Fossil Energy and Carbon Management.
• Congressional Budget Office. (2024). Budgetary Effects of the Inflation Reduction Act: Section 45Q Tax Credit Projections. Washington, DC: CBO.
• SaskPower. (2024). Boundary Dam Carbon Capture Project: 10-Year Performance and Lessons Learned Report. Regina, SK: SaskPower.
• Illinois State Geological Survey. (2025). Illinois Basin Decatur Project: Comprehensive MVA Results 2017-2025. Champaign, IL: Prairie Research Institute, University of Illinois.
• City of Edmonton. (2024). Edmonton's Community Energy Transition Strategy: 2024 Progress Report. Edmonton, AB: City of Edmonton.
• NRG Energy. (2025). Petra Nova Project Status Update and Restart Assessment. Houston, TX: NRG Energy Inc.
• Clean Air Task Force. (2025). Class VI Permitting Progress: Status of CO2 Injection Well Applications in the United States. Boston, MA: CATF.
• Global CCS Institute. (2024). Global Status of CCS 2024: Capital Cost Benchmarking and Lessons from First-of-a-Kind Projects. Melbourne: Global CCS Institute.