All but a tiny percentage of hydrogen is produced from hydrocarbon feedstocks and the International Energy Agency (IEA) estimates the co-produced CO2 emissions match those of the UK and Indonesia combined.
Since policymakers are demanding a drop in overall carbon emissions, the growth of hydrogen depends on its production becoming ‘clean’. Though other processes do exist or are emerging, near-future production of clean hydrogen will depend on two methods.
Blue hydrogen takes conventional production, largely reforming of natural gas, and adds another step—capture and storage of co-produced CO2 (CCS).
Green hydrogen dispenses with hydrocarbon feedstocks and splits hydrogen from water, utilising the process of electrolysis. For the hydrogen to be green, the electricity must be from renewable sources.
The cost of extracting conventional, carbon-emitting grey hydrogen from natural gas depends on the price of that gas—so it varies by region. Where gas is cheap, such as in the US or Middle East, 1kg of hydrogen can be produced at large scale for c.$1. The biggest capacity plants from vendors such as Air Liquide and Honeywell UOP can produce hydrogen at 17-22 t/hr.
Where gas is more expensive—for example in Asia—production costs can double. Economies of scale matter too, as smaller plants push cost/kg higher.
Estimates for green hydrogen costs vary more. In the best circumstances, the International Renewable Energy Agency (Irena) estimates cost at c.$3/kg, while Bloomberg New Energy Finance (BNEF) has them even lower at $2.5/kg. At worst, both suggest costs of c.$7/kg. This range stems mostly from renewable electricity price variations from country to country; those with excellent solar and wind resources can produce the cheapest hydrogen.
Current electrolysis is small-scale. A 10MW electrolyser system—for example, the largest available from ITM Power—produces about 100 times less hydrogen per hour than the largest gas reforming plants.
The costs of blue hydrogen are harder to gauge as they depend on the cost of adding CCS to conventional production. The Global CCS Institute, in its 2019 Global Status Report, lists just 19 large-scale CCS facilities operating worldwide, so costs come with large uncertainties. Nevertheless, the IEA, Irena and others conclude that it adds around 50pc to conventional production costs. So, the cheapest blue hydrogen should be around $1.5/kg.
On the face of it, the cost of blue hydrogen can be half that of the cheapest green form. It builds upon conventional plants one hundred times the scale. So, surely blue will lead growth towards hydrogen economies?
Not necessarily. Current metrics matter less than future ones, as do the practicalities of getting new capacity deployed.
Carbon capture and clustering
Blue hydrogen requires two infrastructure projects. Hydrogen needs to be produced and distributed to customers, with co-produced carbon captured onsite. Then, that carbon must be transported to a site and stored. In both cases, low costs are created by economies of scale. Therefore, blue hydrogen project proposals tend to be ambitious.
They also tend to focus on industrial clusters or so-called hydrogen hubs; HyNet in northwest England and H-Vision around Rotterdam are examples.
This approach allows both hydrogen and CCS infrastructure costs to be recouped through access to multiple, pre-existing industrial customers situated close by (to minimise costly hydrogen transportation). Carbon sequestration reservoirs such as depleted gas fields should be nearby too. Costs can be saved by repurposing infrastructure; switching from natural gas extraction and export to CO2 import and injection, for example.
Therefore, blue hydrogen projects will be large and location specific, making sense where multiple deployment advantages converge. Even then, they depend on managing multiple organisations in a coordinated rollout of infrastructure for both hydrogen and CCS supply chains.
As a result, even cluster approaches are not quick wins. Both HyNet and H-Vision, assuming they can be financed, hope initial operations will start around 2025, but do not foresee full ambitions will reach fruition until the 2030s.
Falling costs and easier deployment
The cost of green hydrogen depends mainly on the cost of the electrolyser, the price of electricity used to power it and how often it operates (which impacts fixed cost recovery per unit of production).
Electrolyser costs are already falling. Unlike large gas reforming plants, smaller electrolysers will roll off increasingly optimised and automated production lines. Like solar panels and lithium-ion batteries before them, their costs will drop along ‘learning curves’. The Hydrogen Council predicts they could be 70-80pc cheaper within five to ten years.
Since renewable electricity is also becoming ever cheaper, most analysts forecast green hydrogen production will become cost-competitive with its blue cousin. Some predict that cost parity will happen in the sunniest and windiest countries within five years, and potentially everywhere from 2030.
Projects are getting bigger too. Wood Mackenzie recently predicted that by 2027 average electrolyser system size will exceed 600MW. The NortH2 proposal in the Netherlands envisages that by 2030 up to 4,000MW of dedicated offshore wind could provide annual hydrogen production around four times that of a large-scale gas reforming plant today.
So, by the time blue hydrogen clusters become operational, green hydrogen could be just as cheap and its projects just as large.
Deploying such large projects will not, however, mean creating huge individual electrolysers. Instead, they will be manufactured at much smaller scale, containerised for easy transport and stacked together in a modular fashion onsite. The same approach is used to create big, utility-scale battery deployments today. Along with the lack of an additional requirement for CCS infrastructure, green hydrogen projects will be easier and faster to build—and more flexible in both scale and choice of location.
Indeed, away from large-scale deployments, the modularity of green hydrogen also makes it uniquely able to deliver distributed solutions. Co-locating small-scale production with its end-use application removes the economic and practical barriers of hydrogen transport. For example, fuel cell truck company Nikola has partnered with Nel to use onsite electrolysis to supply its planned network of hydrogen fuel stations across the US.
None of this means blue hydrogen will not find significant opportunities, where favourable deployment conditions exist.
But focusing on current metrics to dismiss green hydrogen’s prospects is a risky game. Both cost trends and capacity deployment lessons from other sectors point to a future competitive environment very different from today.
John Massey is the managing director of Grey Cells Energy