Europe is heading towards a new era of mandatory carbon pricing, with the expansion in coverage of the EU Emissions Trading System (EU ETS), the start of the new EU ETS 2 to cover the buildings and road transport sectors, and the accelerated phase out of free allowances to many industries. From 2027, almost 80% of all CO₂ emissions in the EU will have to be paid for through a compliance mechanism. As we have covered in recent Energex insights pieces, the cost of carbon to many industrial sectors, including refining, is projected to increase significantly. Many companies will therefore be keenly searching for ways to reduce their CO₂ emissions and resulting compliance costs over the coming years.

Each of the main decarbonisation pathways of energy efficiency, Carbon Capture Utilisation and Storage (CCUS), green and low carbon hydrogen and electrification will have their merits and some will be relevant to certain sectors more than others. The cost of these various options is determined by a wide range of factors including geographical location of installations, availability of necessary infrastructure, the specific technology installed (and its configuration) and local regulations. 

But it is clear that all methods will be necessary to achieve the mandated and recently proposed highly ambitious EU emission reduction targets. In this article we explore in more detail the role of green hydrogen in the decarbonisation of European industry and specifically the refinery sector, exploring some of the challenges that are currently being faced. 

High regulatory hurdles 

“Green” or renewable hydrogen is produced through the process of electrolysis, where renewable electricity is used to split water into hydrogen and oxygen. When combusted, hydrogen produces only water and heat, therefore potentially displacing fossil fuels and reducing associated CO₂ emissions. It can also be used in certain industrial processes where grey hydrogen is commonly used, in particular the refinery sector. 

The European Commission classifies green hydrogen as a Renewable Fuel of Non-Biological Origin (RFNBO) and assigns a zero-emission factor to green hydrogen when used as a fuel. However, in order to be recognised as a qualifying RFNBO, a number of stringent criteria need to be satisfied. The below requirements apply to both green hydrogen produced and imported into Europe: 

1. Additionality
   Renewable electricity used to produce green hydrogen must come from new installations (commissioned no more than 36 months before the hydrogen plant itself) and must not come from existing renewable generation. However, this additionality test is waived for green hydrogen projects that are commissioned before 2028.
2. Temporal Correlation
   Production of renewable electricity must be matched to consumption and therefore hydrogen production. This must be done on a monthly basis until 2030 and on an hourly basis thereafter.
3. Geographic proximity
   The renewable electricity plant must be in the same or an interconnected bidding zone on the grid.
4. Life cycle emissions
   The carbon intensity of green hydrogen must not exceed 3.4kg of CO₂ per kg of H₂. This is influenced by technology choice, feedstocks and site design. 

Cost 

These rather onerous conditions will inevitably increase the cost and make it significantly more difficult to produce green hydrogen within Europe than in some other jurisdictions, where such requirements do not currently exist. 

Indeed, there has been a strong push back from hydrogen businesses and industry bodies, including some demands that the European Commission should rapidly ease these requirements in order to enable the nascent green hydrogen industry to establish itself.  

We have recently seen a number of projects around the world cancelled. In many cases, reasons for project cancellation have included lack of regulatory clarity and lack of economic feasibility, often driven by insufficient financial support or lack of firm offtake. With buyers reluctant to commit to term offtake, many projects are understandably struggling to reach FID. In Europe this may perhaps be compounded by the onerous regulatory requirements of additionality and temporal correlation that we outlined above. 

Availability of supply 

According to BNEF data, there is currently c.0.2 mtpa of green hydrogen produced in Europe, with around 0.99 GW of electrolyser capacity currently commissioned. In Europe, the total amount of grey hydrogen used by refineries that could theoretically be replaced by green hydrogen is we believe approximately 4.5 mt/year. This represents a significant opportunity to displace grey hydrogen production and therefore reduce refinery emissions in Europe significantly.  

However, when we compare that potential refinery demand to the existing project pipeline, it becomes clear that at the current rate of project commissioning, there could be a significant supply shortfall.  There is growing nameplate capacity amongst European green hydrogen projects yet financing constraints and phased project approaches are likely to delay operational capacity in the short term.  

Supply is likely to be centred around certain industrial zones and hubs, feeding for example existing large refineries who are a natural offtaker and who require it for their processes. We believe that production will most likely, at least initially, be centred around Northern Europe, potentially creating supply problems for refineries in other locations.  

Examples include Air Liquide’s 200MW green hydrogen project in France, which is making steady progress and is believed to be on track for completion, backed by an offtake agreement with TotalEnergies to supply the Gonfreville refinery in the second half of 2026. A smaller example is the green hydrogen plant developed by Everfuel, next to Fredericia refinery in Denmark. 

However, the current planned projects are not all destined for the refinery sector. A number of industries will require green and low carbon hydrogen to reach their own decarbonisation objectives. Green hydrogen is also a key feedstock for ammonia and methanol production, which potentially have a number of applications, including as a fuel for maritime transport. A number of sectors could therefore be competing with refineries for a relatively small supply, certainly in the early years of the market.       

Conclusion  

Green hydrogen is believed to be key to enabling large scale decarbonisation of much of heavy industry in Europe. In theory, it can be applied to many sectors and can enable rapid decarbonisation while enhancing energy security. The current target in Europe is to achieve 40 GW of renewable hydrogen electrolyser capacity by 2030 and to produce up to 10 Mt of green hydrogen annually.   

However, many projects have seen delays and even cancellation. In recent months, we have seen the cancellation of several large planned green hydrogen projects, including Repsol’s 130 MW project in Puertollano, Spain in July this year and LEAG’s plans for a major energy hub in Germany. 

According to the recent IEA hydrogen review (September 2025), on a global basis the expected annual green and low carbon hydrogen production in refineries for self-consumption will be approximately 0.5Mt by 2030. This production figure increases by a further 0.7 Mt to a total of 1.2 Mt per annum if we include projects at earlier development stages. This could represent only approximately 3% of today’s global hydrogen demand in refining.        

There is certainly a great deal of ambition for green hydrogen in Europe as a way to decarbonise harder to abate sectors and achieve Europe’s decarbonisation targets. For the refinery sector, availability of green and low carbon hydrogen is likely to be essential.  However, the regulation implemented by the European Commission under the various delegated acts, although intended to provide clarity and encourage investment, have created additional and perhaps unnecessary complexity. With a few exceptions, the commissioned green hydrogen projects in Europe are mostly pilot projects of limited size and capacity, which are not of the scale that will be required to meet refinery demand. 

If the refinery industry does not build or procure sufficient green hydrogen, or invest in other decarbonisation pathways in the coming years, they will be faced with buying more EU ETA’s and at a higher cost. With Energex’s outlook of carbon pricing to rise to over 150 EUR CO₂ per kg of H₂ after 2030, the cost of emissions will rise and improve the economics of green hydrogen projects. However, in order to reduce emissions at the rate required to align with Europe’s targets, green hydrogen production needs to be ramped up quickly and decisions to invest made now both in refineries and industry. For these decisions to be made the economic incentives need to be more robust.  Without them, European refineries, many of which are counting on it to aid decarbonisation, may be facing a highly punitive carbon compliance cost that could impact their ability to operate competitively.  

If you would like to discuss the contents of this article, carbon markets or refining in more detail, please contact Michael Fulton (Senior Advisor) mfulton@energex.partners or Liz Martin (Partner) lmartin@energex.partners.

Thanks to Andrew Winship, Tera Brower and Tom Staveley who have researched this article