Playbook: Adopting Carbon capture, utilization & storage (CCUS) in 90 days

Global CCUS capacity reached 49.3 million tonnes of CO2 per year across 44 operational facilities in 2025, according to the Global CCS Institute, yet Asia-Pacific accounts for fewer than 15% of those projects despite emitting over 50% of global CO2. For investors evaluating CCUS opportunities across the region, the gap between policy ambition and deployed capacity represents both risk and opportunity. This playbook maps the first 90 days from investment decision to operational deployment readiness, covering stakeholder alignment, technology selection, vendor due diligence, and pilot structuring specific to Asia-Pacific markets.

Why It Matters

Asia-Pacific carbon emissions totaled 18.6 billion tonnes in 2024, with China, India, Japan, South Korea, and Australia collectively accounting for over 40% of global CO2 output. Decarbonizing heavy industry across these economies without CCUS is arithmetically implausible: cement, steel, chemicals, and power generation produce process emissions that electrification and renewables alone cannot eliminate. The International Energy Agency estimates that CCUS must capture 6 Gt CO2/year by 2050 to meet net-zero targets, up from roughly 50 Mt today, a 120-fold scale-up.

Policy momentum across the region is accelerating. Japan's GX (Green Transformation) strategy allocates $150B in transition bonds through 2032, with CCUS designated a priority technology. South Korea's Carbon Neutrality Act mandates 10 Mt/year capture capacity by 2030. Australia's Safeguard Mechanism reforms create compliance demand for CCUS credits from facilities exceeding 100,000 tonnes CO2/year. China's 14th Five-Year Plan identifies CCUS as a strategic technology, with Sinopec, CNOOC, and PetroChina collectively announcing 15+ pilot projects since 2022.

For investors, the capital deployment window is narrowing. Early movers securing storage permits, pipeline corridors, and offtake agreements now will establish durable competitive positions as regulatory demand for capture capacity intensifies. Projects that begin structured deployment planning today can reach financial close 12-18 months ahead of competitors still conducting feasibility studies.

Key Concepts

The 90-Day Adoption Framework

A structured 90-day timeline moves an investor from decision to deployment-ready status, compressing activities that typically sprawl across 12-18 months of unstructured exploration.

Days 1-30: Assessment and Alignment Conduct CO2 source mapping, storage basin screening, and regulatory landscape analysis. Identify the 3-5 highest-priority emitter sites based on CO2 concentration (>15% preferred), annual volume (>500,000 t/year), proximity to storage (<200 km), and regulatory readiness. Deliverables: investment thesis document, preliminary site shortlist, initial stakeholder map.

Days 31-60: Technology Selection and Vendor Due Diligence Evaluate capture technologies against site-specific requirements. Post-combustion amine scrubbing suits coal and gas power plants with flue gas CO2 concentrations of 4-15%. Oxy-combustion fits new-build facilities. Pre-combustion technologies apply to hydrogen production and gasification plants. Direct air capture (DAC) operates independently of point sources but at 3-5x the cost. Deliverables: technology recommendation report, vendor shortlist with commercial terms, storage site appraisal initiation.

Days 61-90: Pilot Design and Partnership Structuring Structure the pilot project financial model, negotiate key commercial agreements (CO2 offtake, storage lease, EPC framework), and secure board approval for Phase 1 capital commitment. Deliverables: pilot project plan with budget, timeline, and risk register; heads of terms for 2-3 critical agreements; regulatory application strategy.

Cost Architecture for Asia-Pacific CCUS

Component	Cost Range (USD/t CO2)	Key Drivers	Asia-Pacific Considerations
Capture (industrial)	$30-70	CO2 concentration, scale	Lower labor costs offset higher equipment import duties
Capture (power generation)	$50-100	Flue gas volume, retrofit complexity	Coal fleet retrofit opportunities in China, India
Transport (pipeline)	$5-15	Distance, terrain, volume	Island geography increases costs in Japan, Indonesia
Transport (shipping)	$15-30	Distance, port infrastructure	Emerging Japan-Australia, Korea-Malaysia corridors
Storage (onshore)	$5-15	Geology, monitoring requirements	Extensive saline formations in Australia, China
Storage (offshore)	$10-25	Water depth, well count	Depleted gas fields in Southeast Asia

Total chain costs in Asia-Pacific range from $50-130/t CO2 depending on configuration, compared to $45-120/t in North America and $55-140/t in Europe. The region's competitive advantage lies in lower construction and operational labor costs, offset by higher equipment import costs and less developed pipeline infrastructure.

Storage Readiness Classification

Not all storage sites are equal. Investors should classify potential storage by readiness level:

Tier 1: Bankable (characterized and permitted): Australia's Gorgon CCS (Chevron), Japan's Tomakomai CCS site. Fewer than 10 such sites exist in Asia-Pacific.

Tier 2: Appraised (geological data available, permits pending): Multiple basins in Australia's Bonaparte, Browse, and Carnarvon regions. Malaysia's offshore Sarawak formations. 2-4 years to permit.

Tier 3: Screened (basin-level data only): India's Deccan Traps basalt formations. Indonesia's East Java and South Sumatra basins. 4-7 years to characterize and permit.

Storage readiness directly determines project timeline. Investors should prioritize Tier 1 and Tier 2 sites for 90-day adoption frameworks.

What's Working

Hub-and-Cluster Development Models

Rather than building standalone capture-to-storage chains for individual emitters, hub models aggregate CO2 from multiple sources into shared transport and storage infrastructure. This approach reduces per-tonne costs by 25-40% and de-risks individual projects by socializing infrastructure investment.

Case evidence: Japan's CCS Long-term Roadmap designates seven hub regions, with the Tomakomai CCS hub in Hokkaido serving as the prototype. The hub aggregates CO2 from refining, petrochemical, and power facilities within a 50 km radius, transporting captured CO2 to offshore storage via a shared pipeline network. JOGMEC's Phase 1 demonstration injected 300,000 tonnes between 2016 and 2019 with zero leakage. Phase 2, operational since 2024, targets 1 Mt/year from six industrial sources sharing a $1.2B infrastructure investment.

Cross-Border CO2 Shipping Networks

Asia-Pacific's maritime geography creates opportunities for CO2 shipping that do not exist in continental settings. Liquefied CO2 transport by ship enables emitters without proximate geological storage to access offshore storage basins across national boundaries.

Case evidence: The Australia-Japan CCS Value Chain Partnership, signed in 2023, establishes a framework for shipping CO2 captured from Japanese industrial facilities to storage sites in Australia's offshore basins. Santos and INPEX are developing the Bayu-Undan CCS project in the Timor Sea, repurposing depleted gas fields to store up to 10 Mt CO2/year. First commercial shipments are projected for 2027. Separately, South Korea's Korea National Oil Corporation has signed agreements with Malaysian partner PETRONAS to explore CO2 storage in depleted offshore gas fields in Sarawak, with pilot injections planned for 2026.

Enhanced Oil Recovery Integration

Using captured CO2 for enhanced oil recovery (EOR) provides revenue that offsets capture costs while permanently sequestering CO2 in depleted reservoirs. While EOR is not a long-term climate solution at scale, it provides critical early-stage revenue that validates capture technology and builds operational experience.

Case evidence: China's Jilin Oilfield CO2-EOR project, operated by PetroChina, has injected over 2.5 million tonnes of CO2 since 2008, increasing oil recovery by 10-15% while storing CO2 at a net cost of $15-25/t (after EOR revenue). Sinopec's Qilu-Shengli project, commissioned in 2022, captures 1 Mt CO2/year from a petrochemical complex and transports it via a 75 km pipeline for EOR injection, making it Asia's largest integrated CCUS project at commissioning.

Government-Backed Feasibility Programs

Several Asia-Pacific governments have created structured pathways that accelerate private sector CCUS adoption by funding feasibility studies, de-risking storage exploration, and providing offtake certainty.

Case evidence: Australia's Carbon Capture and Storage Flagships Program and the subsequent $250M CCS Development Fund have supported geological appraisal of 20+ storage basins. The Gorgon CCS project (Chevron), while facing injection shortfalls against targets, has stored over 9 Mt CO2 since 2019 and generated operational learnings that inform the next generation of Australian projects. The Australian government's Safeguard Mechanism reforms now create a compliance market valued at $800M-1.2B annually that CCUS projects can access.

What's Not Working

Underestimating Storage Characterization Timelines

The most common failure mode in Asia-Pacific CCUS adoption is treating storage as an afterthought. Investors frequently commit capital to capture technology before confirming storage availability, then discover that geological characterization requires 3-7 years and $50-200M of appraisal drilling. Without confirmed storage, capture investments become stranded assets.

Japan's experience illustrates the risk: multiple industrial capture projects completed technical feasibility in 2020-2022 but remain unable to secure domestic storage permits. The country's limited onshore storage potential forces reliance on offshore sites requiring extensive seismic surveys and appraisal wells, each costing $10-30M.

Fragmented Regulatory Frameworks

Asia-Pacific lacks harmonized CCUS regulation. Australia has mature CCS-specific legislation (Offshore Petroleum and Greenhouse Gas Storage Act 2006). Japan passed its CCS Business Act in 2024. South Korea is developing frameworks under its Carbon Neutrality Act. India, Indonesia, and most Southeast Asian nations have no CCUS-specific legal frameworks, creating uncertainty around storage liability, monitoring obligations, and cross-border CO2 transport.

Investors operating across multiple jurisdictions face significant legal complexity. A CO2 shipping project from Japan to Australia must navigate maritime regulations, bilateral agreements, London Protocol amendments, and divergent monitoring requirements in each jurisdiction.

Capture Cost Overruns at Retrofit Sites

Retrofitting existing industrial facilities with post-combustion capture consistently exceeds initial cost estimates by 20-40%. Integration with existing process flows, space constraints at brownfield sites, and unplanned shutdowns for tie-in work drive cost escalation. Projects that budget based on greenfield reference costs consistently underperform.

Limited Carbon Pricing Signals

Outside of a few jurisdictions (Australia's Safeguard Mechanism, South Korea's ETS, China's national ETS covering power generation), Asia-Pacific carbon prices remain too low to incentivize CCUS adoption on economics alone. China's ETS carbon price averaged $12/t CO2 in 2024, well below the $50-70/t required to make most CCUS projects commercially viable without subsidies. This pricing gap means most projects depend on government grants, tax incentives, or EOR revenue to close the business case.

Key Players

Established Leaders

• Chevron: Operator of the Gorgon CCS project in Western Australia, the world's largest dedicated CO2 injection facility with 4+ Mt/year capacity. Over 9 Mt stored since 2019. Investing in next-generation storage projects across the Browse Basin.

• Santos: Australian energy company developing the Moomba CCS project in South Australia (1.7 Mt/year, operational 2024) and the Bayu-Undan CCS project in the Timor Sea (10 Mt/year target). Leading proponent of cross-border CO2 shipping from Asia to Australian storage.

• Sinopec: Chinese state-owned company operating Asia's largest integrated CCUS project at Qilu-Shengli (1 Mt CO2/year). Active in CO2-EOR research with 10+ field trials across Chinese oil basins. Committed to 3 Mt/year CCUS capacity by 2025.

• JOGMEC (Japan Organization for Metals and Energy Security): Japanese government agency leading storage site assessment and the Tomakomai CCS demonstration. Coordinating Japan's seven designated CCS hub regions and managing bilateral storage agreements with Australia and Malaysia.

Emerging Startups

• Carbon Clean (India/UK): Developer of modular, skid-mounted capture systems using proprietary APBS solvent technology. Targeting small-to-medium emitters (50,000-500,000 t CO2/year) that conventional capture vendors overlook. Active deployments in India and Japan.

• Carbyon (Netherlands, Asia-Pacific expansion): DAC technology developer using solid sorbent contactor systems. Targeting sub-$100/t CO2 DAC costs through modular manufacturing. Partnership with Japanese industrial partners for Asia-Pacific deployment.

• Deep Sky (Canada, Asia-Pacific partnerships): Carbon removal project developer aggregating multiple capture technologies at single hub sites. Establishing Asia-Pacific partnership framework for cross-border storage access.

Key Investors and Funders

• Asian Development Bank: Committed $1.5B+ to CCUS-related projects across developing Asia. Providing technical assistance for storage characterization in Indonesia, Vietnam, and the Philippines.

• Japan Bank for International Cooperation (JBIC): Financing cross-border CCS value chains under Japan's GX strategy. Provided $200M+ in project finance for Asia-Pacific CCUS infrastructure.

• Breakthrough Energy Ventures: $2B+ climate technology fund with investments in next-generation capture technologies including Carbon Engineering (now Occidental subsidiary) and CarbonCure.

• Australia's Clean Energy Finance Corporation (CEFC): $10B mandate including CCUS project finance. Cornerstone investor in Moomba CCS and evaluating Bayu-Undan participation.

Action Checklist

• Days 1-5: Assemble cross-functional adoption team: Include technical (process engineering, geology), commercial (offtake, carbon markets), legal (regulatory, permits), and financial (project finance, tax) capabilities. Appoint a single decision-maker with board-level authority.

• Days 5-15: Complete CO2 source audit and site screening: Map all CO2 sources within portfolio or target geography by concentration, volume, and proximity to Tier 1/Tier 2 storage sites. Prioritize sources with >15% CO2 concentration and >500,000 t/year.

• Days 15-25: Conduct regulatory landscape assessment: Document jurisdiction-specific CCUS regulations, permitting requirements, carbon pricing mechanisms, and available subsidies. For cross-border projects, map bilateral agreements and London Protocol compliance requirements.

• Days 25-40: Issue vendor RFIs and evaluate capture technologies: Contact 5-8 capture technology providers with site-specific specifications. Evaluate proposals on capture rate, energy penalty, capital cost, modular expandability, and Asia-Pacific reference installations.

• Days 40-55: Initiate storage site due diligence: For Tier 1 sites, negotiate access and injection terms. For Tier 2 sites, commission independent geological review. Confirm storage capacity exceeds 20-year project injection volume with >2x safety margin.

• Days 55-70: Structure pilot project financial model: Build bottom-up economic model incorporating capture capex, transport costs, storage fees, carbon credit revenue, and applicable subsidies. Stress test at carbon prices of $25, $50, and $75/t CO2.

• Days 70-85: Negotiate key commercial agreements: Secure heads of terms for CO2 offtake (or storage lease), EPC framework, and any government grant funding. For cross-border projects, initiate bilateral agreement discussions with relevant government agencies.

• Days 85-90: Secure board approval and launch Phase 1: Present investment committee with pilot plan, budget ($20-80M typical for Asia-Pacific industrial capture pilot), risk register, and 18-month milestone roadmap. Establish monthly governance cadence.

FAQ

Q: What is the minimum project scale that makes economic sense for CCUS in Asia-Pacific? A: Economic viability depends on CO2 source concentration and local carbon pricing, but generally projects capturing fewer than 100,000 t CO2/year struggle to achieve acceptable unit economics due to fixed infrastructure costs. The sweet spot for first projects is 200,000-500,000 t CO2/year, large enough to amortize capture equipment and pipeline costs but small enough to limit capital exposure during the learning phase. Modular capture systems from vendors like Carbon Clean are lowering the minimum viable scale to 50,000 t/year for high-concentration sources (>20% CO2), but transport and storage economics still favor larger volumes.

Q: How should investors evaluate geological storage risk in Asia-Pacific? A: Storage risk assessment should follow a three-tier framework. First, confirm basin-level geology through existing seismic data and published geological surveys (typically available from national geological agencies at no cost). Second, commission independent review of injectivity, capacity, and containment by a qualified subsurface consultancy ($500K-2M). Third, for Tier 2 sites, budget for appraisal wells ($10-30M each) to confirm reservoir properties before committing to full development. Key risk factors include caprock integrity, induced seismicity potential, and monitoring well requirements. Australia's regulatory framework requires operators to demonstrate <0.1% annual leakage probability over 1,000 years.

Q: What returns can investors expect from Asia-Pacific CCUS projects? A: Project-level returns vary significantly by configuration. CO2-EOR projects in China generate unlevered IRRs of 12-18% at current oil prices, benefiting from EOR revenue. Industrial capture projects with government subsidies (Japan GX bonds, Australian CCS Development Fund) target 8-12% equity returns. Pure geological storage projects without EOR or utilization revenue depend heavily on carbon credit pricing and currently target 6-10% returns in Australia's Safeguard Mechanism market. Cross-border shipping projects remain in pre-commercial stages with returns highly sensitive to shipping cost assumptions. Portfolio-level returns for diversified CCUS investors are projected at 10-15% over 10-year horizons as carbon pricing strengthens across the region.

Q: What are the biggest regulatory risks for cross-border CCUS projects? A: Three regulatory risks dominate cross-border CCUS: (1) long-term storage liability transfer, as most jurisdictions have not clarified when liability passes from operator to government, creating open-ended contingent liabilities; (2) London Protocol compliance, which was amended in 2009 to allow cross-border CO2 transport for sub-seabed storage but requires bilateral agreements that few Asia-Pacific nations have finalized; and (3) carbon accounting treatment, specifically whether exported CO2 counts as an emissions reduction for the source country or the storage country. Japan and Australia have addressed this bilaterally, but most other country pairs have not.

Sources

• Global CCS Institute, "Global Status of CCS Report 2025," March 2025
• International Energy Agency, "CCUS in Clean Energy Transitions 2024," September 2024
• Japan Ministry of Economy, Trade and Industry, "CCS Long-term Roadmap," May 2024
• Australian Government Department of Climate Change, Energy, the Environment and Water, "Safeguard Mechanism Reforms Implementation Update," December 2024
• Santos Limited, "Bayu-Undan CCS Project Update," November 2024
• Sinopec, "CCUS Development Strategy and Progress Report," August 2024
• Asian Development Bank, "Carbon Capture and Storage in Developing Asia," June 2024
• BloombergNEF, "Asia-Pacific CCUS Market Outlook 2025-2035," January 2025