PANTHEON Project | Horizon Europe | Grant Agreement No. 101137905
Hydrogen has become one of the most talked-about solutions in the global decarbonisation toolkit. Governments are backing it. Industries are piloting it. Investment roadmaps are betting on it. But behind the momentum lies a harder question: under what conditions, at what cost, and at what scale can clean hydrogen actually deliver on its promise — not in optimistic projections, but in the messy reality of blast furnaces, cement kilns, steam crackers, and oil refineries?
This is the question that PANTHEON’s latest research report directly confronts. Deliverable D2.4, Assessment of feasibility space of scaling up green hydrogen (April 2026), produced by UCL’s team under Work Package 2, provides a rigorous, sector-by-sector analysis of the technological, economic, and deployment landscape for clean hydrogen in four of the world’s highest-emitting industrial sectors: iron and steel, cement, oil refining, and primary chemicals.
Mapping the Technology Landscape Across Hard-to-Abate Sectors
The starting point is a systematic inventory of relevant clean hydrogen technologies — green hydrogen (produced via electrolysis powered by renewable energy) and blue hydrogen (produced from fossil fuels with carbon capture) — and their readiness levels across the four sectors examined. The picture that emerges is one of genuine but uneven potential.
Energy-related processes dominate emissions in these sectors. In iron and steel, energy consumption accounts for between 49% and 96% of total emissions depending on the production route. In cement, the requirement to heat kilns to temperatures reaching 1,400°C drives the majority of energy demand. In primary chemicals, processes such as steam cracking (operating at 800–900°C), catalytic cracking, and coal gasification are the dominant energy consumers. Across all four sectors, the substitution of fossil fuels with clean hydrogen offers a structurally credible pathway to reducing these energy-related emissions.
The technology readiness picture, however, is less uniform. Hydrogen as a fuel in blast furnaces and in direct reduced iron (DRI) processes is currently at Technology Readiness Levels (TRL) 5–6, meaning large-scale prototype stage. Hydrogen as a fuel in cement kilns sits at TRL 5. In contrast, solar PV electrolysis for green hydrogen production in oil refining has already reached TRL 9 — fully commercial. Most strikingly, green hydrogen as a feedstock for ammonia production has reached the pre-commercial stage in the primary chemical sector. These distinctions matter enormously for investment decisions and policy design: the sectors and applications where hydrogen is still in prototype phase require fundamentally different support than those approaching commercial viability.
The Cost Reality: Green Premiums, Abatement Costs, and What Drives Them
PANTHEON’s analysis is refreshingly direct about the economic barriers. The green premium — the additional cost of switching from conventional, high-carbon processes to clean hydrogen-based alternatives — exceeds 70% across high-emitting sectors, and reaches 193.7% in ammonia production, where the comparison with conventional steam methane reforming is most stark. The underlying driver is well-identified: 60–70% of green hydrogen’s cost is attributable to the price of renewable electricity, and producing a tonne of green hydrogen requires roughly 50–83 MWh of electricity.
The abatement cost picture — what it costs to avoid a tonne of CO₂ — varies significantly by sector and application. Using green hydrogen as a feedstock in iron and steel averages around 244 $/t CO₂, and around 100 $/t CO₂ in primary chemicals. As a fuel, however, costs escalate sharply: abatement costs for green hydrogen as fuel in the DRI-EAF steel process reach 1,000 $/t CO₂ — more than three times the cost of blue hydrogen in the same application. In cement, hydrogen-as-fuel abatement costs average around 219 $/t CO₂, while in primary chemicals they reach around 472 $/t CO₂.
An important nuance emerges from the analysis: while blending up to 30% hydrogen into existing natural gas streams requires minimal process modifications, pushing substitution levels higher demands significant infrastructure upgrades — enhanced kiln or furnace materials, advanced temperature control systems, and extensive retrofitting of equipment not designed for hydrogen’s different combustion characteristics. The jump from partial blending to near-full substitution is not linear in cost or complexity.
Deployment Is Not Just a Technology Problem: Regional and Plant-Level Realities
Even where hydrogen technologies are technically mature and economically competitive, deployment is constrained by geography, infrastructure, and plant-specific operational realities. PANTHEON’s analysis treats these constraints seriously rather than assuming them away.
At the regional level, the gap between leading and lagging contexts is stark. Countries like Germany and the Netherlands, with established renewable energy capacity and existing natural gas pipeline networks that can be adapted for hydrogen transport through surface coatings and inhibitor additions, are substantially better positioned for large-scale adoption. In contrast, regions with limited grid capacity, underdeveloped renewable sectors, or absent hydrogen transport networks — including parts of South and Southeast Asia — face prohibitive production costs and logistical barriers that pure technology progress cannot resolve.
At the plant level, the transition involves a complex interplay of technical retrofits, process optimisations, and economic trade-offs. In steel plants operating on traditional blast furnace technology, integrating hydrogen as a fuel or reducing agent requires substantial furnace modifications, precisely because hydrogen’s combustion characteristics — its temperature profile and reaction rate — differ markedly from those of fossil fuels. The analysis advocates a phased retrofit approach: begin by blending hydrogen with natural gas at low substitution ratios, then progressively increase the share as retrofitting progresses and operational experience accumulates. In primary chemicals, replacing grey hydrogen with clean hydrogen may require adjustments to reactor design and process conditions to maintain product quality and stability.
Plant location is also a cost variable. Facilities located near abundant renewable electricity and established hydrogen distribution infrastructure benefit from lower operational costs and reduced capital exposure. Isolated plants, or those in regions with underdeveloped infrastructure, face substantially higher costs for hydrogen transport and storage. Actionable plant-level strategies therefore extend beyond technical retrofits to include developing on-site renewable energy capacity, forming partnerships to access regional hydrogen hubs, and optimising energy sourcing logistics.
Clean Hydrogen in the Emission Gap Roadmap
Scaled to the system level, the stakes are clear. Clean hydrogen is expected to account for around 11.4% of cumulative emission reductions in iron and steel and around 20.2% in primary chemicals by mid-century. The sector-wide deployment required to achieve this scale involves installing over 190–230 GW of electrolyser capacity globally. Yet current announced investments reach only around $450 billion against an estimated $700 billion needed by 2030. Europe’s hydrogen pipeline network is projected to reach 53,000 km by 2040, with over 60% of that capacity repurposed from existing natural gas infrastructure — a reminder that the transition depends as much on adaptive reuse of existing assets as on building new ones.
The trajectory is not hopeless. Recent projections indicate that advances in renewable energy and electrolyser technology could reduce green hydrogen production costs by 32–56% compared to 2022 levels by 2030. If realised, this cost reduction could fundamentally alter the economics of hydrogen deployment across all four sectors examined.
Critically, PANTHEON’s analysis positions clean hydrogen not as a standalone solution but as a component of an integrated decarbonisation portfolio — complementing electrification, carbon capture and storage (CCS), and energy efficiency improvements. Hydrogen closes the residual emission gap that remains after other strategies have been deployed: it addresses the high-temperature heat and chemical feedstock applications where electricity-based solutions face their own physical and economic limitations.
What Comes Next
D2.4 directly feeds into PANTHEON’s wider analytical architecture. The sector-specific technology maturity and cost data it establishes will inform the project’s net-zero pathway assessments and scenario modelling, providing the empirical grounding needed to build credible, technology-disaggregated transition pathways for the most challenging corners of the global economy.
For full access to the report and other PANTHEON project outputs: www.pantheon-decarbonisation.com
PANTHEON is funded by the European Union’s Horizon Europe programme under Grant Agreement No. 101137905. Views expressed are those of the authors and do not necessarily reflect those of the European Union.
