Many of the world’s most prominent hydrogen and Carbon Capture, Utilisation and Storage (CCUS) projects are either operating, reaching final investment decision, or facing deferral. This moment matters because it will reveal the practical limits of today’s hydrogen build-out models. It will also show which pathways can move from demonstration to repeatable, financeable delivery.

This article examines the key technical factors that will define hydrogen and CCUS scale through 2026. It draws on global market data, publicly available project information, and operating insights reported across the sector.

1. Electrolyser scale-up is becoming a manufacturing and integration challenge

Electrolysis remains central to long-term hydrogen decarbonisation strategies. However, scaling installed capacity is not simply a question of electrolyser availability. While global manufacturing capacity has expanded rapidly, installed and operational capacity remains below announced volumes.

According to the International Energy Agency (IEA), only a limited share of announced electrolysis capacity is currently under construction or operational.¹ Project progress is slowed by several factors, including grid access, permitting timelines, balance-of-plant complexity, workforce availability, and limited Engineering, Procurement and Construction (EPC) experience. While permitting and financing remain important parallel issues, technical integration increasingly causes project delays.

From an engineering perspective, system performance under real operating conditions remains uncertain. Stack degradation under variable renewable power, load-following capability, water treatment requirements, and compression losses now play a larger role in design choices. These factors also influence operating cost assumptions.

In 2026, the first wave of large-scale electrolysis facilities (hundreds of megawatts) outside China will begin generating operating data. This data will materially influence design assumptions, technology selection, and execution risk assessments. For project sponsors and financiers, it will shape utilisation assumptions, contingency allowances, and scrutiny of EPC capability.

What will define progress:
If large-scale projects commissioned over the next two years demonstrate stable operation and predictable degradation rates, confidence will improve and execution risk should fall. Repeatable EPC delivery models would then support a shift from bespoke engineering toward more standardised project delivery.

2. Cost trajectories remain sensitive to system-level inputs

Despite expectations of long-term cost reduction, low-carbon hydrogen remains more expensive than incumbent fossil-based alternatives in most regions, particularly for industrial applications.

The IEA’s Global Hydrogen Review 2025 highlights several reasons for this. Capital costs have been higher than expected, electricity prices have been volatile, and project delivery has been slower in many markets. While regional exceptions exist where power prices, utilisation rates, and policy support align favourably, overall project economics remain highly sensitive to system-level inputs.¹

Cost sensitivity increasingly sits outside the electrolyser stack itself. Electrical interconnection, grid reinforcement, power electronics, water sourcing and purification, compression, storage, and safety systems often account for a large share of total installed cost.

As projects move from modelling into operation, delivered hydrogen costs become decisive. These real costs, rather than projected learning curves, influence whether industrial users commit to long-term offtake. They also shape whether investors view projects as scalable or as one-off solutions.

What will define progress:

As operating data replaces assumptions, uncertainty around utilisation and system efficiency should narrow. Where projects demonstrate high availability and predictable performance, confidence in long-term cost trajectories is likely to improve. This would support both offtake commitments and capital deployment.

3. CCUS integration is shifting from pilot systems to shared infrastructure

For blue hydrogen and many industrial decarbonisation pathways, CCUS is no longer optional. The technical focus has moved beyond capture technology alone. Integration across capture, transport, and storage systems at scale is now the central issue.

Independent analysis shows that CCUS becomes economically and operationally viable when developed as shared infrastructure. Shared networks allow multiple emitters and hydrogen producers to use common CO₂ transport and storage networks.² This approach shifts risk and capital exposure away from individual projects and toward system-level assets. Such structures are generally preferred by long-term infrastructure investors once regulatory frameworks stabilise.

The transition introduces new technical and organisational challenges. Pressure management, materials performance, system reliability, and long-term monitoring all become critical, while capture rates, methane leakage management, and storage integrity remain key variables. Their performance under continuous industrial operation has not yet been fully demonstrated at scale.

What will define progress:

In 2026, the first operational CCUS clusters will begin generating operating data on uptime, utilisation rates, and long-term system performance. This evidence will be essential in assessing whether shared CCUS infrastructure can deliver the reliability and cost profiles required to support large-scale hydrogen production and industrial decarbonisation.

4. Infrastructure readiness is emerging as a binding factor

Hydrogen production cannot scale independently of transport, storage, and distribution infrastructure. Unlike electricity or natural gas, hydrogen does not yet have a mature delivery network.

Hydrogen pipelines face materials challenges related to embrittlement, leakage, and compression, while large-scale storage – particularly geological storage – remains geographically limited and capital-intensive. The IEA notes that infrastructure development continues to remain below production ambitions in most regions.¹

This creates a clear risk. If infrastructure is not available when needed, production assets may be under-utilised, undermining project economics. From an investment perspective, infrastructure sequencing has therefore become as critical as technology selection. In response, hub-based and corridor-based development models are emerging as the most viable near-term approach. These models co-locate supply, demand, and infrastructure to reduce integration risk.

What will define progress:

If early hubs demonstrate effective sequencing and high asset utilisation, they will provide a template for replication. Projects coming online in 2026 will be an important test of whether hub-based infrastructure planning can deliver reliable hydrogen flows at scale. Where that evidence is positive, perceived infrastructure risk should fall, supporting expansion beyond first-of-a-kind clusters.

5. Measurement, Reporting and Verification (MRV) is becoming a design requirement

As hydrogen markets internationalise, MRV frameworks are becoming technical requirements rather than policy concepts. For electrolytic hydrogen, compliance increasingly depends on clear criteria which include renewable electricity additionality, temporal correlation between power generation and hydrogen production, and full lifecycle emissions accounting.

Clear and credible MRV frameworks are now widely seen as prerequisites for long-term offtake agreements and project finance. The IEA emphasises that uncertainty around certification and emissions accounting continues to slow demand formation¹, particularly in cross-border and compliance-driven markets.

What will define progress:
As compliance requirements are applied to early hydrogen transactions, existing MRV frameworks will begin to be tested at scale. Whether they can be implemented without excessive complexity or cost will be critical in reducing uncertainty for buyers and investors.

Conclusion: What to watch as hydrogen moves toward scale

2026 will measure progress less by announcements and more by operating data. Engineers, developers, policymakers, and investors will be watching the same signals. These include performance data from large-scale electrolysis projects, verified cost data from operating facilities, utilisation of CCUS transport and storage networks, commissioning of hydrogen infrastructure, and the practical application of MRV standards across regions.

Together, these signals will determine which hydrogen pathways become repeatable and investable, and which remain constrained by system complexity. They will also shape how quickly experience from first-of-a-kind projects can be transferred, compared, and applied across regions and sectors. The opportunity for hydrogen and CCUS remains significant, but the next phase will be defined by disciplined execution, credible operating data, and collaboration across the full value chain – from technology and infrastructure through to markets, policy, and capital.

Sources

1. International Energy Agency (IEA): “Global Hydrogen Review 2025”; 09/2025;  https://www.iea.org/reports/global-hydrogen-review-2025
2. World Economic Forum: “Defossilizing Industry: Considerations for Scaling-up Carbon Capture and Utilization Pathways”; 09/2026;  https://reports.weforum.org/docs/WEF_Defossilizing_Industry_Scaling-up_CCU_2025.pdf
3. Wood Mackenzie: “Energy Transition Outlook 2025-26: Insights and Scenarios”; 10/2025;  https://www.woodmac.com/market-insights/topics/energy-transition-outlook/ 
4. Eliseo Curcio: “Techno-Economic Analysis of Hydrogen Production: Costs, Policies, and Scalability in the Transition to Net-Zero”; 02/2025; https://arxiv.org/abs/2502.12211