There is no credible path to Net Zero by 2050 that does not include significant quantities of green hydrogen – estimates vary between 500-700 million tonnes (or 10-14% of global energy demand) annually by 2050.  It is light, easily swapped-in for fossil fuel in energy intensive industries and suitable for long-term energy storage. Yet making the product is complicated, expensive and energy intensive and compliance with existing regulation (in particular in the EU) adds to the cost and complexity.

Some basic information

Green hydrogen is created by the electrolysis of water, splitting it into its two constituent parts - Hydrogen and Oxygen. 

It is a resource-intensive process, requiring large quantities of water and energy. This means the green hydrogen plant will normally be located near its input factors – a lake, river or the sea (for water) and an abundant source of renewable energy (normally wind or solar).  Since, it is not (currently) possible to electrolyse salt water to create hydrogen, if the water input is salt water from the sea, then the plant needs electricity to desalinate the salt water as well as electricity to then electrolyse the desalinated water.  To comply with the definition of green hydrogen, the electricity used in the process of creating it must come from renewable sources.

A green hydrogen plant requires:

- between 3 - 5 KWh of electricity to desalinate one cubic metre (one metric tonne) of water;

- approximately 55 KWh of electricity to electrolyse 1 kg of water; and

- 10 tonnes of water to produce just over one tonne of hydrogen.

In total, this means the process requires 30 - 50 KWh to create 10 tonnes of desalinated water and a further approximately 55,000 KWh (50 MWh) to convert that water into one tonne of green hydrogen - which delivers between 33 - 39 MWh of energy (an efficiency level of between 60-70%).

Costs of production vary quite widely. The ICCT’s central case scenario has a delta between $4,000 - $8,000/tonne. The World Bank calculates current production costs at around $4.6 / kg of green hydrogen, or $4,600/tonne. Other estimates based on capital expenditure amortised over the lifespan of the project come out at $62 per MWh (or $2,000/tonne). It is worth noting that costs of production will fall as economies of scale and learning cycles improve - Bloomberg predicts the cost of producing green hydrogen will fall to $0.70 – $1.60 per kg by 2050.

Electricity and Electrolyser Demand

Availability of renewable electricity and electrolysers are two other important limiting factors in the production of green hydrogen.

The UK’s Ten Point Plan of November 2020 (as revised by the Hydrogen Strategy) set the UK energy sector a target of 10 million tonnes of green hydrogen production by the end of the decade.  The UK currently consumes approximately 300 Terrawatt Hours (TWh) of electricity a year - 57 of which comes from N Sea wind. Producing one million tonnes of green hydrogen will require approximately 55 TWh: equivalent to almost the entire renewable electricity production from the N Sea. Reaching the UK’s 10 million tonnes goal would require 550 TWh of energy - two-thirds more electricity than the entire current electricity consumption of the UK.  The required increase in installed capacity to meet the UK’s green hydrogen goals would come on top of existing projections of a significant increase in demand as other sectors of the UK’s economy switch from reliance on fossil fuels to electricity.

Meeting the IEA estimate of future global demand for hydrogen (between 500 - 680 million tonnes by 2050) will have significant impacts on global demand for electricity.  Even if learning curves drive efficiency improvement in the desalination process from 10% to 75%, the world will still need between 22 - 25,000 TW/H of electricity. Since total global electricity consumption was around 27,000 TWh in 2022 (with around 40% of that coming from renewable sources), it is clear that meeting the need for hydrogen the world will require huge increases in installed renewable capacity.  The cost of installing that amount of renewable capacity has been estimated at around $8 trillion.

And it is not just the amount of installed capacity which will have to dramatically increase. Meeting the IEA estimate will require a huge increase in the number of deployed electrolysers - some estimates suggest 6000 times the current supply. To put this figure in context, producing 10 million tonnes of green hydrogen (the UK and EU targets) will require around 100 GW of electrolyser capacity: in 2021, the total global capacity of electrolysers was 600MW.  The cost of reaching this number of deployed electrolysers has been estimated at around $7 trillion.

The Transport Question

Whilst some Governments are considering hydrogen for domestic heating and appliance use, the main assumption is that hydrogen production will be localized to hard-to-decarbonise sectors (cement, steel and glass for example) as well as for long-distance and heavy-haulage transport. For those places where local production is not realistic (or for markets which better lend themselves to Hydrogen production), there are (as for fossil fuels) two main transport routes for green Hydrogen - shipping or pipelines.

Whilst shipping clearly offers greater flexibility, there are significant technical and energy downsides. Hydrogen is difficult to compress, which means that Ammonia (rather than liquid Hydrogen), is emerging as the most efficient means of ship transportation (despite its corrosive and taxic qualities), adding a number of capital-intensive stages to the production and delivery chain. 

Converting Hydrogen into Ammonia (by combining it with Nitrogen) is an energy-intensive process, requiring high temperatures (400°C) and pressure (200 atmospheres). Re-cracking it to deliver the Hydrogen at the other end of the transportation also has to be done at very high temperatures - 900+°C and 50-100 atmospheres of pressure. It requires approximately 4 MWh of energy to create one tonne of Ammonia and crack it back to Hydrogen (and Nitrogen – which will need to be managed). Once the input energy costs are taken into account, the final energy value of the Hydrogen is between 2-3 MWh/tonne of Ammonia.

Until more efficient processes of shipping hydrogen can be found/discovered/invented, it therefore seems likely that where Hydrogen cannot be produced near to the offtake location, it will be transported through the existing natural gas pipe network exists (although some re-purposing will be necessary to convert pipes from gas to hydrogen molecules, which could cost up to $5 trillion). 

The existence of a pipeline network, as well as the more reliable provision of significant quantities of renewable electricity suggest that the EU and the UK should look to N Africa and the Middle East for near to medium-term piped hydrogen supplies through long-term supply contracts, rather than relying on an LNG and spot-style hydrogen market. 

Policy Implications

There is no credible path to Net-Zero that does not envisage a significant role for hydrogen in the energy market by 2050.  That hydrogen will need to be green. The green hydrogen sector is dynamic and fast-changing. Market actors will need to be able to follow, understand and comply with the emerging and evolving regulatory environment in a number of important jurisdictions (including the EU, the UK and the US). They will need to understand the novel project finance requirements of putting together significant and many-phased projects under a new regulatory environment and to consider the future risk of stranded infrastructure if international transport options change.

But the capital investment required for a functioning Hydrogen market is huge and current investment is drastically inferior to that needed to reach green hydrogen targets.  Without significant subsidies, it is unlikely that the offer will respond upstream of an increase in demand.  To give an indication of the gap that subsidies will have to bridge, gas is available on the market at around $30-$50 / MWh: green hydrogen currently costs around $150 / MWh…

The EU and the US are approaching this problem from different ends.  The US is using the carrot of the Inflation Reduction Act, whilst the EU is using the stick of hard targets.

The IRA offers green hydrogen producers a tax credit of up to $3 per kg.  This subsidy has galvanized the US market in green hydrogen which according to some estimates now accounts for 70 per cent of committed clean hydrogen production globally. But IRA production credits only last for 10 years: the uncertainty about what (if anything) might replace those credits beyond the decade makes it difficult for businesses to take long-term investment decisions (particularly the case for energy-intensive industries such as steel, glass or cement, which currently rely on gas or coal for their energy needs), as well as for the Government to begin to create a strategic market and infrastructure for production transport and storage.

Meanwhile, the EU has mandated industry to use green hydrogen – setting a 2030 target of 42% of green hydrogen in industry. Given the difference between green hydrogen and gas costs noted above, the EU’s approach effectively forces industry to incur costs by switching from a cheaper to more expensive input energy source. It doesn’t help that the EU has designed a restrictive definition of renewable hydrogen: green hydrogen must be produced off-grid and may not displace other renewable electricity from the grid (effectively limiting the production of green hydrogen to those periods when there is an excess of renewable electricity) and in the process increasing the cost of producing hydrogen. The launch of the European Hydrogen Bank (running auctions to finance competitive hydrogen production) could be seen as tacit acknowledgement by the EU of the implications of its own self-constraint, but this runs up against the same problem as the IRA: it is hard for business to develop projects on the basis of the promise of future subsidies.

There are potentially broader policy implications of an efficient hydrogen market.  Given a) Hydrogen inputs are somewhat inflexible (nearby supplies of water and renewable power); b) the difficulties and inefficiencies of transporting Hydrogen; and c) Hydrogen is most efficiently used in hard-to-decarbonise sectors, the most effective market model appears to be the creation of industrial hubs centred around hydrogen production.  This model challenges the assumption that a future international Hydrogen market will simply overlay the existing LNG market - IRENA estimates that only 25% of Hydrogen will be traded internationally by 2050 (interestingly the exact inverse of the current oil market). 

With the future Hydrogen market requiring entirely new supply (and value)-chain models and significant new infrastructure investment, the importance of this new energy source also offers policy-makers an opportunity to re-imagine what a future global energy market might actually look like, with potentially significant implications for emerging markets.