While most industry attention seems to be on green and blue hydrogen, neither of the two is the cheapest clean hydrogen pathway in Europe today. According to the trade association Hydrogen Europe, that title goes to turquoise hydrogen.

Turquoise hydrogen is produced through methane splitting, or what is commonly referred to as methane pyrolysis. The process involves the thermal decomposition of methane at temperatures above 1000°C in the absence of oxygen in a reactor. At the end of the process, methane is split into hydrogen and solid carbon – or “carbon black.” Provided it is powered by renewable energy, it is deemed to be a zero-emission solution.

In a recent report titled Clean Hydrogen Production Pathways 2024, the trade body notes methane splitting offers the lowest cost of decarbonisation, among different types of hydrogen and production methods in Europe.

Assuming hydrogen would be used to replace grey hydrogen, which is derived from fossil fuel without carbon capture and storage tech, “the estimated costs of producing low-carbon hydrogen through various pathways combined with the carbon intensity of those production pathways allows to estimate the cost of decarbonisation,” the report explains.

Currently, the European Union Allowance (EUA) under the EU Emissions Trading System (ETS) is at around €80/tonne of CO2. EUAs are essentially a type of carbon allowance that enables companies to emit a certain amount of CO2 and reflects the cost of reducing emissions. Alongside this, grey hydrogen has a current production cost of €3.3 per kilogram, as per the report.  

The base-case levelised cost of turquoise hydrogen (LCOH) could be as low as €2.3/kg at February 2024 gas prices, considering a European average level. For it to reach cost parity with grey hydrogen, the ETS price would have to be at €100/tCO2. On the other hand, blue hydrogen – produced through reforming of natural gas with carbon capture – has an LCOH of around €4/kg. It would require a CO2 abatement price of €160/tCO2, to reach cost parity with grey hydrogen.

“If the ETS market prices would double, both of these technologies would be financially profitable without any subsidies,” the report claims.

Moreover, methane splitting offers an advantage in greenhouse gas (GHG) emissions: the process facilitates the “almost complete avoidance of direct CO2 emissions” due to the production of solid carbon instead of CO2. Transporting and storing carbon is also cheaper and less energy-intensive than storing and transporting CO2, the report adds. That said, turquoise hydrogen’s GHG emission intensity would depend on the source of gas used.

Meanwhile, green hydrogen, produced using water electrolysis and renewable energy, is currently the most expensive clean hydrogen pathway, requiring a carbon price ranging from €180/tCO2 to over €600/tCO2 to be competitive with grey hydrogen. It has an LCOH of €6-7/kg under basic modelled conditions.

“However, since costs are mostly driven by renewable electricity costs and capex – both of which are expected to fall –, water electrolysis also has the largest cost reduction potential among the analysed technologies,” the report adds.

For both blue and turquoise hydrogen, the cost of natural gas is their largest cost driver. Also, as methane splitting is a less mature technology than natural gas reforming, it has higher upfront capital expenditures, Kallanish notes.

However, Hydrogen Europe says revenues from the solid carbon by-product can cut the final LCOH of methane splitting by 34% – from €5.3/kg to €3.3/kg. The latter assumes a base case with gas prices at €40/megawatt-hour and solid carbon at €500/t. Carbon black, which is used for manufacturing tyres, pigments, plastics, and other materials, can go as high as €1,000-1,800/t. 

“With gas hovering around €20/MWh in February 2024 and assumed solid carbon around €1,000/t, the theoretical project could reach LCOH of €0.8/kg,” the trade body notes. “That is well below the €2/kg for an existing SMR [steam methane reforming] unit at same gas price levels.”

But Hydrogen Europe cautions that due to the limited deployment of methane splitting technology for H2 production at an industrial scale, both capex costs and solid carbon revenues are uncertain.

Initial commercial-scale methane splitting facilities focused on carbon black production instead of hydrogen. This includes Norwegian company Aker Solutions’ (previously Kværner) facility in Karbomont, Canada, which was decommissioned in 2003. Another is Monolith Materials’ carbon black focused commercial size plant deployed in 2020 in Nebraska, US. It has a carbon black production capacity of 14,000 tonnes/year and hydrogen at around 4,600 t/y.

Projects focusing on hydrogen production are only just entering demonstration and commercial phases, meaning, there can be relatively high capex and technological deployment risks. 

“With increasing hydrogen production from methane splitting and saturating the existing solid carbon demand, future demand for solid carbon allotropes as well as their price levels are crucial for methane splitting project economics and scaling this technology,” the report adds. “In the long term, its reliability on gas infrastructure and solid carbon revenues are the largest scalability challenges for methane splitting.”

Moreover, methane splitting – alongside other low-carbon hydrogen technologies – faces significant regulatory challenges. 

In methane splitting’s case, its carbon intensity would depend on the CO2 allocation method in the upcoming delegated act (DA) on low-carbon fuels, expected by year-end. This means determining how the total CO2 emissions during the process will be distributed among various products, which in this case, are hydrogen and solid carbon. However, this is yet to be defined for methane splitting.

In addition, solid carbon is still not recognised as a carbon storage solution. The current carbon capture and storage (CCS) strategies in Europe only recognise captured CO2 emissions and “neglect” the potential of “precombustion” CCS methods like solid carbon from methane splitting, the association argues.

For green hydrogen, the strict additionality and hourly temporal correlation requirements in the EU continue to be “a significant cost obstacle,” the report adds. “The deployment of clean hydrogen technologies is held back by persisting regulatory barriers and the lack of a framework for calculating GHG emissions.”

The lack of GHG calculation rules for low-carbon hydrogen impacts most pathways, Hydrogen Europe warns. Therefore, the “simplicity and speedy adoption” of the new GHG accounting rules within the upcoming DA is “essential” for the entire hydrogen sector. These rules should also be consistent with the existing rules for renewable fuels of non-biological origin (RFNBOs) and recycled carbon fuels (RCFs).

“It is of utmost importance to design a strong regulatory framework, which would promote sustainable solutions, while, at the same time, not create unnecessary investment barriers – as has happened with renewable electrolytic hydrogen,” the trade body concludes.