The government announced an array of hydrogen updates last week, including project awards for Hydrogen Allocation Round 1, a transport and storage pathway and a new consultation on hydrogen to power. But all this was overshadowed by a decision to cancel the only remaining village trial for home heating, which many see as a death stroke for the highly controversial use case.

Village trials were supposed to be a key input to a scheduled 2026 policy decision on hydrogen for home heating, which has become one of the most acrimonious and politicised use case debates. The government committed to supporting local hydrogen heating trials by 2023 and a larger-scale village trial by 2025. Local trials have already happened. The HyDeploy project completed a 10 month trial at Winlaton near Gateshead last year, where Northern Gas Networks (NGN) supplied over 600 houses with a blend of up to 20% hydrogen.

Gas network operator Cadent proposed a village trial in Whitby and NGN a trial in Redcar. The government confirmed in July it had declined Cadent’s proposal, and last Thursday said it would not be proceeding with Redcar either. The Whitby village trial was dropped due to a lack of local support. The Redcar trial also encountered significant local opposition, although the government framed the cancellation as due to “issues in obtaining a robust, local hydrogen supply”.

It is slightly ironic that Redcar is near Teesside – the site of a proposed hydrogen hub that is supposed to facilitate the trial use of hydrogen.

Can’t take the heat

The lack of any village trials is a serious blow for hydrogen home heating. Juliet Phillips, senior policy advisor at E3G, said that without Redcar it will be “nearly impossible for the government to make a positive decision to permit nationwide hydrogen heating in 2026”. With Redcar gone, however, the government said its 2026 decision will be based on evidence from its wider R&D operations, an H100 trial in Fife and similar trials in Europe.

The H100 trial will see 300 customers of gas network operator SGN supplied with 100% green hydrogen gas produced from renewable energy. But this involves building a new network from scratch, not blending hydrogen into existing infrastructure. That trial is scheduled to start in 2024 and SGD will collect data on the project and its participants until 2027.

Supporters of hydrogen home heating include gas grid operators and other owners of legacy fossil fuel infrastructure. This is understandable. If their networks end up carrying hydrogen then their assets remain active and profitable. If not, then they will eventually become stranded and the value written-down. The opposition to hydrogen home heating is based less on engineering – it is clearly possible – and more on simple economics.

The government made clear that blending would be a ‘last resort’ for hydrogen producers, rather than a priority end-use
Juliet Phillips, E3G

The strike price that the first batch of UK green hydrogen will receive (see below) makes green hydrogen roughly eight times more expensive than natural gas on a per-MWh basis. On the same day as the government announcement, Jan Rosenow, director of European Programmes at global NGO the Regulatory Assistance Project, published a meta-review of 55 studies on hydrogen heating.

The studies found hydrogen for heating leads to energy system costs being on average 24% higher than with electrification. The median increase for consumer prices under a hydrogen scenario was 86%. None of the studies supported hydrogen heating at scale. “We’re almost sure that hydrogen for domestic and commercial heating is not going to happen because it’s so expensive,” said Lorenzo Sani, a power analyst at Carbon Tracker.

If the economics are not sufficient to convince the government, its own consultation on Future Homes and Buildings Standards may do the job. Also published last week, that consultation said hybrid and hydrogen-ready boilers “will not meet the proposed standards” for new zero-carbon ready homes. Instead, the consultation clearly supports the roll out of heat pumps.

Levenmouth in Fife, at the site of land marked for the H100 project.

Blending fact and fiction

The hydrogen and natural gas industries were also eagerly awaiting a government decision on whether to allow hydrogen to be blended into the existing gas network. This was due by the end of 2023.

What emerged last week could only charitably be described as a decision. The closest the government came was stating that “based on current evidence” it sees “potential strategic and economic value” in supporting blending “in certain circumstances that align with blending’s strategic role”. Essentially, the government reaffirmed an existing ‘minded to position’ on supporting blending – nothing more.

Clare Jackson, CEO of Hydrogen UK, described the announcement as “a positive decision to support hydrogen blending into the gas grid”. The hydrogen industry wants blending as another potential source of demand should appetite from other off takers prove weaker than expected. This could help support and de-risk early stage hydrogen projects.

Opposition to blending is – in many quarters – heavily related to opposition to hydrogen for home heating. E3G published an argument against blending in June. Their key point was that blending risks “locking in” hydrogen for home heating, directing hydrogen away from more efficient use cases and derailing domestic heat decarbonisation.

Value over volume

Where the latest government announcement does provide clarity is with regard to blending’s “strategic role”. Until last week, there was still debate as to whether blending could be a tool for decarbonisation, or simply a transitional measure to support the nascent hydrogen market. But in the announcement on blending the government stated that it “should only be a transitional option”, and reaffirmed that hydrogen will be most valuable in industries where direct electrification is not an option.

“The government made clear that blending would be a ‘last resort’ for hydrogen producers, rather than a priority end-use,” said Philips at E3G. “Some gas companies are claiming that hydrogen blending is the first step to decarbonising the gas networks, in statements which run counter to the government position – and could act as misleading greenwash to installers and consumers.”

In addition, the government placed clear emphasis on not “distorting the offtaker market” for hydrogen. This means that even if blending becomes an option it will never offer a higher price than either the floor price of the hydrogen business model or the wider market.

If we want green hydrogen to be able to compete with blue hydrogen by 2030 the strike price figure needs to be at least three times lower.
Lorenzo Sani, Carbon Tracker

If green hydrogen costs many times the price of natural gas then why, say blending critics, would it ever make sense to pour excess hydrogen into a gas grid. Especially when long term energy storage is likely to be a key use case. On top of this, adding hydrogen to the gas grid would almost certainly incur system costs relating to issues like billing and safety. Michael Liebreich, chairman and CEO of Liebreich Associates, described the idea of blending as “utter madness”.

Priority projects progress

These debates have detracted from the more unambiguously positive news of the Hydrogen Allocation Round (HAR) 1 projects, and some progress on the pathway for transport and storage. Of the 17 projects that entered final negotiations for HAR1, two withdrew. The 15 projects that submitted final offers totalled 243MW of capacity, of which four were rejected leaving 11 projects totalling 125MW. This is well short of the 250MW the government was aiming for.

“It’s positive to see that things are moving forward, although it was a bit disappointing to see the announced capacity being basically half the initial target,” said Sani at Carbon Tracker.

The projects will receive a weighted average strike price of £241/MWh, and the government expects the projects to become operational in 2025. It is only the first round and costs will almost certainly fall as the market develops, but even so the price raised some eyebrows.

“The strike price is a bit worrying because it equates to around £9.5 per kg, and if we want green hydrogen to be able to compete with blue hydrogen by 2030 that figure needs to be at least three times lower,” Sani said.

Maintaining momentum on allocation rounds and deployment will be key. Helpfully, the government has already launched HAR2, which aims to support up to 875 MW capacity and hit the target of 1 GW of electrolytic hydrogen production capacity – in operation or construction – by 2025.

A new Hydrogen Production Delivery Roadmap outlines 1.5GW capacity targets from HAR3 and HAR4, which are expected to launch in 2025 and 2026 respectively. All this provides the hydrogen industry with a clear long-term view on the government’s ambitions.

In a similar vein, a new Hydrogen Transport and Storage Networks Pathway sets out high-level strategic ambitions for the vital infrastructure to carry and store hydrogen. Here the government aims to ensure up to two hydrogen storage projects and associated regional pipeline infrastructure is in operation or under construction by 2030.

Transport and storage business models are being designed for 2025, and the government aims to provide guidance on the first allocation rounds for projects in Q2 2024. By summer of 2024, the government also aims to consult on how the Future System Operator can formally take on responsibility for strategic hydrogen transport and storage planning in 2026.

H2 for power generation

Finally, the government announced a new consultation on hydrogen to power (H2P), which will run until February 2024. “H2P could provide key low carbon flexible generation capacity to ensure the power system remains balanced at all times – it can play multiple roles in the power sector, from mid-merit to peaking, whilst creating a decarbonisation pathway for existing unabated gas power plants,” the consultation said. Government analysis suggests H2P could provide 5GW to 12GW of low carbon electricity generation capacity by 2035, rising to between 20 GW and 90 GW by 2050.

In Q1 2024, the government intends to publish a response and “supporting legislative changes” to a consultation on Decarbonisation Readiness requirements. These would require all new build and substantially refurbishing combustion power plants to be built in such a way that they could easily decarbonise by converting to either 100% hydrogen firing or retrofit carbon capture technology within the plant’s lifetime.

Blending – if it is ever allowed – will be transitional and even then is unlikely to make economic sense

Some H2P plants could deploy through existing markets, but capex requirements will likely be prohibitive for others. As part of the solution, the government wants to see these plants able to participate in the capacity market as soon as possible. “As the primary mechanisms for investment support in capacity, enabling participation in the CM is considered to be a key step in providing routes to deployment for H2P through existing markets, particularly for less CAPEX-intensive plants in the early stages of the hydrogen economy,” according to the consultation.

Although the government is prepared to intervene in the market to support H2P, the consultation makes it clear this will not be long term. “We consider that any H2P intervention which might be brought forward by the government should be short term,” the consultation says. “We would look to transition any bespoke support onto the enduring low carbon flexibility support mechanism, the proposed design of which we intend to outline in the second REMA consultation.”

Intertwined sub-sectors

H2P also touches on the need for transport and storage. Large power plants using hydrogen would likely require pipeline delivery. As hydrogen is a flexible source of low carbon generation, the variation in consumption and load profile means storage will be critical. “The link between H2P capacity and storage availability will be especially important to ensure the appropriate build out of both technologies,” the consultation said. “Internal modelling shows that the lower the load factor for H2P plants (more peaking), the greater the hydrogen storage capacity required.”

The government also notes that the exclusion on selling hydrogen to Risk Taking Intermediaries (RTIs) – a bugbear for the hydrogen industry – could create problems for storage solutions. The consultation states that the government is not seeking to exclude non-RTIs from playing a role in the market. These entities could charge a fee to a hydrogen producer or end user for a service like brokerage or hydrogen storage. As long as they did not take ownership of the hydrogen this would comply with the business model. One of the consultation questions is whether such commercial arrangements could still develop between hydrogen producers, storage providers, and electricity generators given the RTI rules.

Taken as a whole, the wave of hydrogen updates looks broadly positive for a sensible energy transition. Hydrogen home heating seems far less likely. Blending – if it is ever allowed – will be transitional and even then is unlikely to make economic sense. The UK has its first round of projects, and although the price of green hydrogen is prohibitive it will fall as long as the government pushes on with HAR 2, 3 and 4. Transport, storage and H2P are tricky and intertwined problems, but the new year should hopefully bring more clarity around the government’s approach.

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