As the government finalises its Low Carbon Hydrogen Agreement (LCHA), industry executives are keeping their fingers crossed for a last set of supportive tweaks. But even if their wish lists are not quite fulfilled, the LCHA is a solid enough platform for the first-generation of hydrogen projects – and sometimes you just can’t please everyone.

The UK government published the first draft of the LCHA in early August. Clocking in at a daunting 657 pages, the document outlined the 15 year contracts and support framework for the UK’s nascent hydrogen sector. The draft’s sheer length and complexity is more a feature than a bug – building a new industry from scratch is complicated – but it does potentially raise an issue for smaller producers.

“We make things like this extremely complicated,” says Becky McLean, Sustainability Director – Energy, Water & Environment, at SWECO. “One of my concerns is that only companies of a certain size with large legal teams can decipher the terms and therefore this could place a potential barrier to entry for smaller operators and prevent market innovation.”

This issue of size appears elsewhere when discussing the LCHA, which some worry risks neglecting the potential for smaller developers of low single digital MW projects. “There’s really clear stipulated qualifying volumes, and small production cases that might fall under that production cap won’t be covered by the LCHA,” said Jacob Martin, Haskel hydrogen business development manager. “No-one doubts the need for scale, but we don’t want to stop anyone that’s trying to break into the market and produce hydrogen in a more rural environment.”

There are 17 projects representing a combined capacity of 262MW in the shortlist from the government’s first electrolytic hydrogen allocation round. This gives an average project size of just over 15MW. A second green hydrogen allocation round targeting another 750MW is expected to launch this year. The government has a target to reach 10GW of hydrogen online by 2035, 5GW of which will be electrolytic. But analysts see this as unrealistic given the current landscape. “We’re moving in the right direction, but we’re not on the trajectory to hit that 10GW target,” says Emma Woodward, hydrogen advisory lead at Aurora Energy Research. “It’s not impossible, but there’s more work to be done.”

Price discovery

The hydrogen industry has other concerns with the LCHA in its draft form. One is around the price. For each unit of hydrogen, project developers will receive the difference between a sales price – agreed with the off takers – and a strike price negotiated with the government. Some industry figures think developers will be put off by the variance in strike price. But many others point out that the same approach worked well for offshore wind. Bilateral agreements will provide vital learning opportunities for developers and the government, which aims to shift to letting projects compete on price after its second allocation round.

Consensus is clearer when it comes to criticism of the incentives for price discovery. As a reference price, the LCHA uses either natural gas prices or the hydrogen sales price – whichever is higher. Producers will receive 10% of the difference between the reference price and the price floor. Or if the reference price exceeds the strike price, then 10% of the difference between the strike price and the price floor.

Under normal circumstances this means that for every £1 worth of hydrogen a producer sells above the gas price, they receive an additional 10 pence. But the 10% figure may prove too paltry to prompt real price discovery. “Our view is that the government will get better value for money and more price discovery by introducing a more generous price discovery incentive,” says Clare Jackson, chief executive at trade association UK Hydrogen. “At this early stage, price discovery is particularly important.”

Price hedging has also come under the spotlight. For carbon capture-enabled blue hydrogen projects, a portion of the strike price is indexed to gas prices. Because natural gas is the main feedstock, blue hydrogen producers have less need to hedge their fuel costs, and the level of revenue they will receive via the subsidy will rise in response to their main input costs.

For green hydrogen, the strike price is entirely linked to the consumer price index. Developers have to either take on the cost of an electricity price hedge, or take on the project risk of leaving it unhedged. “If you’re trying to be technologically neutral, then you shouldn’t be surprised if de-risking the main input prices for one technology and not the other drives cost differentials,” says Alex Savvides, Statkraft’s UK hydrogen policy and strategy lead.

Blue hydrogen projects do have their own uncertainties. CCS enabled projects will by definition rely on CO2 infrastructure, and are therefore exposed to the risk of it being inoperable for an extended period of time. “The industry would like to see the government take on a little bit more of that risk, especially in the early stages of the development of projects,” says Jackson.

The Brande Hydrogen pilot site in Denmark. Source: SSE

A hammer to crack a nut

The volume support the LCHA provides has become distinctly less generous as the agreement has taken shape. Volume support is provided on a sliding scale, but only kicks in when produced volumes fall to 50% of the agreed output. The problem, say developers, is that by the time volumes fall to 40% – let alone 50% – a project will already be in a serious amount of trouble. Industry executives point to countries like Germany, where support schemes essentially underwrite the offtake. Even if the UK does not want to go quite so far, support could be ramped up.

This limited volume support is particularly problematic when combined with the LCHA’s restrictions on who producers can sell their hydrogen to. This includes a ban on selling to anyone who will export the hydrogen, or any entity acting as a risk-taking intermediary (RTI). The rigorous due diligence producers have to do on their offtakers means that selling to a large number of small end users is deeply problematic. Essentially, the only qualified off-takers are large end-users in the UK. This in turn gives producers very limited flexibility if – for whatever reason – demand falls or proves highly volatile. Neither scenario is unrealistic in a nascent market.

Many in the hydrogen industry would like to see far less broad definition RTIs. This could include exemptions for RTIs in the transport sector, where intermediaries will be crucial in providing hydrogen for fuel use cases. Government understandably wants to stop third-parties from trading hydrogen at a profit. But this blanket approach to RTIs means there is no room for a legitimate refuelling operator acting as an intermediary between a hydrogen producer and the end customer.

There is already a Renewable Transport Fuel Obligation (RTFO), which requires fuel providers to prove that a certain percentage of their fuel comes from renewable sources. Green hydrogen qualifies as a renewable fuel, and so hydrogen producers could sell to a large transport offtaker. But again, the due diligence requirements that electrolytic producers face means selling to a large number of small transport users is administratively prohibitive. “The offtaker requirements are quite restrictive for certain business models and it seems there’s been a policy decision to use the RTFO for smaller-scale transport use cases and the HBM [Hydrogen Business Model] only for the largest scale projects,” says Savvides. UK Hydrogen notes that producers have claimed very limited volumes under the RTFO – just 163MWh in 2022.

Producers also face restrictions if demand proves greater than anticipated. This restriction is in the form of a hard volume cap, something prospective producers have argued long and hard against during consultations. A volume cap on subsidised green hydrogen is entirely defensible; the government wants to know how much it is on the hook for on any given project. But producers understandably feel that if there is demand for green hydrogen that can be produced and sold without a government subsidy, that is a win for everyone.

“That would be a great example of initial subsidised support enabling a wider market that gets more electrolyzer in the ground [which] benefits the whole,” says Savvides. But developers are specifically prevented from doing so. It seems likely that instead, a producer would have to sign a new LCHA and produce the additional hydrogen using a subsidy – even though it could have avoided doing so. “One of the easiest wins would be to remove the upper limit on production and allow unsubsidized volumes,” he says.

Off to a good start

Even if these wins do not emerge in the short term, the LCHA has provided enough confidence to generate a solid pipeline of electrolytic projects. “As a broad framework it is a very well designed policy and held up as a global benchmark,“ says Jackson. And despite concerns that too much tweaking creates uncertainty, there is nothing intrinsically wrong with adjusting the hydrogen subsidy system over time.

As the hydrogen economy evolves, the level of support policy makers deem necessary will shift. Emerging transport and storage networks, higher load factors and cheaper technology will change project economics. “The rules that are put in place for this first stage shouldn’t be set in stone,” says Woodward. “The market is developing so quickly and the support schemes will have to adapt.”

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