Investments in blue hydrogen will be riskier than those in green hydrogen, according to a new report by the International Renewable Energy Agency (Irena), which states that renewable hydrogen may be the cheaper option in most key markets by 2030, or even sooner.

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“Blue hydrogen [produced from natural gas with carbon capture and storage] is sometimes portrayed as a safe bet, because it allows producer countries to monetise natural gas resources and pipelines that might otherwise become stranded,” Irena says in its 118-page study, Geopolitics of the Energy Transformation: The Hydrogen Factor.

“But the expected cost reduction in green hydrogen, coupled with stricter climate mitigation policies, means that investments in supply chains based on fossil fuels (blue or grey) — especially assets expected to be in operation for many years — may end up stranded.

“Irena expects green hydrogen to undercut blue hydrogen on costs by 2030. It may do so even sooner in some countries, such as China, thanks to its cheap electrolysers, and Brazil and India, thanks to their inexpensive renewables and relatively high gas prices.”

Green vs Blue

Blue hydrogen is produced from natural gas feedstocks, with the carbon dioxide by-product from hydrogen production captured and stored. However, the process is not emissions free.

Green hydrogen is made using electrolysis powered by renewable energy to split water molecules into oxygen and hydrogen, creating an emissions-free fuel.

The report cites previous work by analyst BloombergNEF, which wrote last year that green hydrogen would be cheaper than blue in the key markets of China, India, Brazil, the US, Germany, France, Canada, Australia, the UK, Spain, Italy, the Netherlands and Canada by 2028 — and in Japan and South Korea by 2030.

This could pose an issue for blue hydrogen investors, with Tom Baxter, one of the co-founders of the Hydrogen Science Coalition think-tank, recently stating: “Once you’ve invested in blue hydrogen, you are invested for 30 years.”

Still room for blue in the short term

The Irena study says that blue hydrogen would account for about a third of all hydrogen by 2050 in its 1.5C scenario — with two thirds being green.

Under Irena's estimates, the demand for blue hydrogen would still be larger than the 120 million tonnes per annum that currently exists for grey hydrogen, but much lower than the projected 409 million tpa of green hydrogen Irena forecasts will be needed by 2050.

The report also suggests that blue hydrogen would mostly only play an important role over the short to medium term.

“If blue hydrogen meets strict emissions criteria, it could play an important role in scaling up hydrogen volumes in the short-to-medium term and drive the development of related infrastructure and technologies along the value chain,” it explains. “Moreover, blue hydrogen could offer additional flexibility in the hydrogen market. In the long run, however, green hydrogen is a zero-carbon solution and should therefore be the endgame.”

Price volatility

The report adds that blue hydrogen’s use of fossil fuels also exposes it to price fluctuations and market volatility noting the spike in gas prices seen late last year, mostly in Europe and Asia.

While fossil fuel prices are cyclical, the cost of green hydrogen would mostly be more stable, with the largest cost of producing green hydrogen being the cost of electricity, which would likely be bought using long-term fixed-price power-purchase agreements.

However, the report also notes that the levelised cost of renewables differs significantly across regions, meaning the cost of green hydrogen will also differ depending on location.

Clean fuel will most economical to produce in locations that have an optimal combination of abundant renewable resources, available land, access to water and the ability to transport and export energy to large demand centres.

Despite this, green hydrogen can still reduce countries’ dependency on imported fossil fuels, while the report notes “blue hydrogen would follow the patterns of gas markets, resulting in import dependencies and market volatilities”.

“If natural gas is used as the feedstock to produce hydrogen, it may extend or even increase imports of natural gas,” the report says.

“Existing import dependencies could be maintained, or increased, through continued dependence on a commodity prone to geopolitical and market volatility.”

Methane risk

Irena's report adds that blue hydrogen “does not support the goals of climate resilience or energy security”.

And, of perhaps more importance to would-be blue hydrogen developers is the geopolitical risk from upstream or midstream leakages of methane — a very potent greenhouse gas.

"Strong regulations around upstream methane leakages, for instance, could become a source of friction between blue hydrogen producers and importing regions looking for clean hydrogen. Carbon border adjustment mechanisms, such as the one proposed by the European Union, could cause international friction, as they may hurt trade-exposed, carbon-intensive industries in non-EU countries.”

Irena also points to other downsides of blue hydrogen:

  • The danger that countries or gas producers could under-report methane emissions
  • The high carbon capture rates promised by blue hydrogen proponents are yet to be demonstrated at scale
  • The ongoing costs of CO2 transportation and storage, including monitoring of the stored CO2.
  • Its production is more energy-intensive and requires more water than green hydrogen, adding to overall energy demand

The report adds: “Clean hydrogen can be an important part of the deep decarbonisation puzzle… but there are risks of carbon lock-in if hydrogen strategies prolong fossil-fuel demand and supply, and hinder energy efficiency and electrification.

“Concerning blue hydrogen, an agreed threshold for carbon capture and methane emissions will be necessary to ensure that blue hydrogen makes a meaningful contribution to decarbonisation.

“Transparency in how emissions are determined will be essential for the proper functioning of an international hydrogen market.”

(This article was first published by Upstream's renewable energy sister publication, Recharge, on 17 January.)