Some 3% of global energy consumption today is used to produce hydrogen. Only 0.002% of this hydrogen, about 1,000 tonnes per annum, is used as an energy carrier¹, the rest is used in industrial processes, mostly as feedstock. In a world that is seeking clean energy carriers, hydrogen can carve out a more prominent niche in the energy mix. It is an especially attractive option for countries with an existing natural gas infrastructure, as demonstrated by the United Kingdom which is already implementing large scale hydrogen projects.  However, the question remains; what is the most cost and carbon efficient way to produce hydrogen? The next decade could provide the answer.

There are two competing (and maybe complimentary) narratives on how hydrogen will be produced.  Blue hydrogen is made from fossil fuels with carbon capture and storage (CCS) but requires parallel development of large-scale CCS infrastructure. Green hydrogen is produced from electrolysis of water powered by renewables, and although currently expensive, we believe that green hydrogen can compete against the blue method by 2030. This is based on the assumptions of significantly reduced capital costs for electrolysers and that they will operate only when electricity prices are ‘low.’ In this scenario, electrolysers operate intermittently in step with fluctuating power prices, and either hydrogen storage or complimentary blue hydrogen production is available to ensure hydrogen supply.

However, despite its carbon neutral potential described in the green and blue pathways above, the current most common method is gas reforming without carbon capture and storage.

Opportunities and market impact

Several countries may see hydrogen heated buildings as a good decarbonization option. Australia, Canada, the Netherlands, South Korea, UK and US are the most likely to adopt this at significant scale. These countries predominantly use gas for heating buildings, and have infrastructure that can be adapted to hydrogen distribution and storage. However, this application requires substantial policy push and public co-funding to materialize¹.

Northern Gas Networks in the United Kingdom has already unveiled a blueprint which would supply 3.7 million homes and 40 000 commercial premises with hydrogen instead of natural gas by 2034. The project will cost an estimated 22.7 bn pounds with the first homes in northern England converted in 2028².

In the manufacturing industry hydrogen has the potential to replace coal and gas for cleaner heating processes where electric heating with heat pumps or direct, is not suitable. It can also start replacing cokes as a reduction agent in iron and steel production beyond 2030, which could significantly reduce emissions.

Hydrogen fuel cells will have an impact on transportation, although the business case for passenger cars is not as strong as for long distance heavy vehicles. Even though the refueling ranges of passenger fuel cell electric vehicles (FCEVs) will be on a par with those of internal combustion engine vehicles (ICEVs) for the next decades – superior to those of battery electric vehicles (BEVs) – our Energy Transition Outlook concludes this not to be enough to offset the FCEV cost disadvantage, where high costs associated with hydrogen-refueling infrastructure play a prominent role. However, for commercial use, FCEVs are another matter and heavy long-haul vehicles require driving ranges for which battery-based propulsion will remain inadequate³.

The penetration of FCEVs will correlate with regions that will use hydrogen more broadly, where the distribution network will also enable FCEV uptake.

Risk and uncertainties

Both blue and green hydrogen contain their own significant uncertainties.  For the blue camp, CCS is a well-established technology but has so far failed to scale to an industrial level, whilst the success of green hydrogen is dependent on the cheapening of electrolysers and proliferation of renewables.  Both are possible but both need the right government policy.

Calculations about the viability of hydrogen in areas where existing natural gas infrastructure exists is based on the assumption that it can be distributed by retrofitting current gas grids at a minimum cost.  Hydrogen can be blended with natural gas for distribution – with blend rates up to about 20% – which will then burn like natural gas, but eventually also by piping pure hydrogen through the grid. The latter technology will require an additional total upgrade of appliances.

Depending on the penetration of variable renewable electricity generation, industrial scale economic hydrogen production from electricity will emerge before 2035 in most countries, supplementing conventional hydrogen production from natural gas or coal. Whether the business case will be mainly driven by economics, utilizing of low electricity prices caused by large amounts of variable renewable energy or by avoiding CO₂ emissions by utilizing variable renewable energy remains to be determined and will depend on legislation and certification schemes, which are emerging now.

Contributors

Main author: Marcel Eijgelaar

Contributor: Mats Rinaldo

Editor: Peter Lovegrove