Fieldfisher spoke to Charlie Newbold, Chief Operations Officer at Emerald Green Hydrogen, about the opportunities and obstacles for developing commercial green hydrogen production in the UK.
What are the main commercial opportunities for green hydrogen?
The industries that are going to start using hydrogen first are those which are (a) hard to electrify, and (b) need very high heat capacity.
Any energy user that needs to generate heat up to and above 800 degrees Celsius is going to be extremely difficult to electrify, especially when paired with requirements for connection to Grid infrastructure.
There are lots of large industrial users in this bracket, but also food producers that need to run large boilers and fryers.
Heavy transport is another clear early use case, because large trucks and lorries face operational and duty cycle (i.e., how much they can be used) issues with fully electric technologies – unlike small passenger vehicles – so hydrogen could really help decarbonise this sector.
There is a lot of interest in testing hydrogen among many potential offtakers in these hard to electrify industries.
For example, they are looking to test its potential by augmenting 5% of their natural gas supply with hydrogen, as a first step to see if they could ultimately move to 100% hydrogen.
What are the main hydrogen business models?
At the most basic level, you can either sell hydrogen, or you can sell electrolysers.
Potentially, companies might be more disposed to buy electrolysers, as this is a cost they can just write-off.
But for the ones that don't want to spend that capital outlay, it comes back to negotiations about the price of supplying hydrogen to them.
That arrangement would probably resemble a standard gas agreement.
What are the main challenges for buying and selling hydrogen in the UK?
The key challenges for UK hydrogen developers and users include a lack of clarity on how to price hydrogen in the absence of an operating market and demand forecasts, and a lack of guidance on how to buy and sell hydrogen.
From a supplier perspective, pricing is a technical as well as a commercial issue, since hydrogen has very different energy, volume and density characteristics to natural gas.
From a user perspective, greater guidance is needed from plant manufacturers to confirm the level of hydrogen that existing boilers and other energy appliances – both commercial and domestic – can take without needing adjustments or upgrading.
Going '100% hydrogen' also incurs potential capex costs for users, along with changing opex costs, so these need to be scoped out and estimated to give users confidence to switch to hydrogen.
Does the UK Low Carbon Hydrogen Standard (LCHS) effectively regulate the types of hydrogen produced?
At the moment, the LCHS is set at 20 grams of CO2 per megajoule, meaning hydrogen produced with emissions below this level is classed as low-carbon hydrogen.
But this doesn't deal with the spread of hydrogen under this level – in theory you could have hydrogen which is 1 gram of CO2 and hydrogen which is 19.99 grams of CO2 per megajoule, and all of it will be classed as the same quality.
This is very likely to change in the future, since it currently misses quite a lot of key issues with hydrogen generation by theoretically placing green and blue hydrogen in the same low carbon levels, but with very different production methods.
At the very least there should be some sort of tiered system, that incentivises production of the highest quality green hydrogen and deals with the fact that producing it is more expensive than hydrogen with higher emissions.
How are support schemes likely to evolve as the UK hydrogen market matures?
The support schemes that exist probably need to be expanded to enable the market for hydrogen in the UK to mature.
Once this has happened, we can expect to see support schemes being refined and tapered as the economics of hydrogen projects become self-sustaining, we can expect to see schemes being tapered as greater differentiation is made between green and blue hydrogen generation projects.
Economic self-sufficiency will also prompt a winding down of subsidies.
What are the main sticking points of commercial agreements?
Aside from price negotiations, a key issue is how contracts deal with reliability of supply.
If we get to the point where power plants can only run on hydrogen alone, meaning that blending with natural gas is not an option, there needs to be some provision in the contract for what happens when hydrogen supply runs short or is cut off.
There is also an added risk for green hydrogen, in that its reliance on renewable energy leaves it open to the vagaries of wind and solar energy supply.
There is a question over what happens if the renewable energy source fails, and the extent to which mitigations are encompassed within plant designs such as onsite storage capacity.
One of the biggest challenges is getting both those agreements – with the electricity supplier and the hydrogen offtaker – in place at the same time.
Can hydrogen compete on price with natural gas?
Hydrogen is currently more expensive than natural gas, so there needs to be a substantial decrease in price, or some sort of price supplement like a contract for difference (CfD) to make switching economically appealing.
When gas prices were at their peak in 2022, hydrogen wasn't far off price parity, so this illustrates the kind of price shift we need to see for hydrogen to be competitive.
It's not a massive decrease, but it is significant.
In the absence of a price support mechanism, hydrogen users are going to have to accept it will cost more than natural gas, at least in the beginning.
But they need to weigh this against the benefits it could bring in terms of reaching their net zero goals.
Fieldfisher's specialist energy lawyers can help businesses grappling with hydrogen regulations, permitting issues and securing funding. For more information on the regulatory and commercial environment for hydrogen projects, download a copy of Fieldfisher's "Shaping Europe's hydrogen economy" report.
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