The cost of green hydrogen has often been projected to fall dramatically over the coming years as electrolyser manufacturing scales and renewable electricity costs drop — a similar trajectory to solar over the past decade, which saw the cost of PV modules fall by more than 80% since 2010 mainly due to mass manufacturing in China.

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The US government had even explicitly set a target for the cost of green hydrogen to reach $1/kg by 2031 without subsidies. And while the EU has not put an exact price target on renewable H2, it will only provide €4.5/kg ($4.78/kg) in its upcoming auction to fill in the cost gap with fossil-based hydrogen — which generally costs less than €2/kg.

However, developers speaking at the Investing in Green Hydrogen conference in London earlier this month warned that not only are these costs not going to fall as quickly as other renewables, but are actually on the rise.

“The costs are rather getting up,” said Andreas Bieringer, business development and commercial director at Emirati renewables developer Masdar, although he tempered this increase in green H2 production cost as “a bit of a spike we see at the moment”.

“Ultimately it will come down again,” he added.

But Benjamin Haycraft, executive vice president for EMEA at green hydrogen technology firm Plug Power, on a separate panel argued that there will continue to be a green premium on electrolytic hydrogen.

“The price of renewable electricity for multiple reasons will probably increase,” he said, noting that since power represents 60% of the cost of producing H2 via electrolysis, this would counteract any efficiency or capex gains on the electrolyser.

“If you have electricity at €50/MWh, you’re probably going to get a variable cost of €2/kg, and then you need to amortise the asset,” Haycraft added.

As such, he anticipates that producing green H2 will remain expensive compared to running a steam methane reforming (SMR) unit on gas.

“And so, how does that meet the end-consumers, which would then need to absorb a significant green premium? And I think that’s a fundamental issue — today we’re trying to hide this natural green inflation with subsidies, but the reality is, this green premium in my opinion is not going to go away.”

The biggest factor behind the rise in cost is simply that the upstream renewables for hydrogen production are highly exposed to increases in the cost of capital.

“We are seeing… kind of a challenge because renewables cost, capex is increasing,” said Sopna Sury, chief operating officer for hydrogen at German utility RWE, although she notes that once the renewables plants are actually up and running, there is a “marginal cost of zero”.

While this means that green hydrogen is better shielded than grey or blue H2 from spikes in gas prices — which last year led to some projections putting the cost of electrolysis below traditional steam methane reforming — it also means that renewable H2 is more likely to get much more expensive with rising inflation.

“We also see in our projects some increasing capex numbers unfortunately,” German energy firm Uniper’s CEO for hydrogen Axel Wietfeld admitted in a separate presentation at the conference.

He did not disclose the exact impact of rising capex on the levelised cost of renewable H2 production, but he noted that “grey and blue are a bit lower in terms of cost” while citing forecasts that green hydrogen costs are only likely to fall below blue by 2035.

Electrolyser prices

Developers are split on whether the price of electrolysers — which accounts for up to 40% of the final cost of H2 production—will also be a meaningful roadblock to reducing costs this decade.

“It is still going to be quite difficult to bring down the cost,” said Ganapathy Swamy,Linde's vice president for large project development in Europe, Middle East and Africa.

“The production cost of these electrolysers will not follow the kind of curve one may expect in solar or others, where it’s different economics there,” he cautioned.

Swamy noted that not only are electrolyser manufacturers likely to be stretched between different regions — albeit with a focus on the US due to more green hydrogen projects expected to take off due to the Inflation Reduction Act (IRA) — but also may have to increase prices due to a short supply of raw metals such as titanium and iridium.

However, fellow panellist Didier Holleaux, executive vice president at French utility Engie, pushed back on Swamy’s concerns about shortages of raw materials, citing reductions in the use of critical metals in other renewable technologies in response to shortages. “I’m optimistic the same will happen with electrolysers.”

Instead, he raised that the biggest problem with electrolysers on the market is in fact their operating costs.

“Today, the reliability of electrolysers is not yet to the point where it needs to be if we want to develop the hydrogen economy,” Holleaux said. “We need to have electrolysers which are working reliably, with low maintenance cost and with very limited number of outages.”

At least one electrolyser series — the HyLyzer 500, supplied by Cummins’ Accelera business — is known to have been shut down in the field due to a technical defect, leading to months of lost production for some of the projects using this model.

Cost of regulation

Sury raised that the delegated acts defining what hydrogen will count as a renewable fuel of non-biological origin (RFNBO) — and therefore eligible for subsidies and counting towards industrial use mandates— make green H2 production “certainly a fair bit more expensive, at least once the temporal correlation changes to hourly correlation”.

A study published earlier this month estimated that the requirement for hydrogen to be produced in the same one-hour period as renewable electricity generation would increase costs by 27.5% compared to monthly matching, with little impact on emissions.

“If this is the rule of the game, I think regulation is just one part of it,” Sury added.

“We have to talk about funding support, because at the end of the day, from a consumer’s perspective, from an offtaker’s perspective, they need to understand what are they going to pay? So if we are making rules more complicated, it needs to have another mechanism to fill the gap.”

She cited upcoming European Hydrogen Bank’s pilot auction offering up to €4.5/kg to plug the cost gap between green and grey hydrogen production, as well as carbon contracts for difference for end-users in some markets, such as Germany.

Less risk of losing out?

This expectation that prices will not fall dramatically over the next decade could be a blessing in disguise for developers when it comes to actually getting customers to commit to long-term offtake agreements — generally considered a must-have by banks to prove revenue certainty over the debt payback period.

“Everybody is a bit afraid to lock himself too early in this technology,” Bieringer said, with end-users wary that they will end up paying significantly more for H2 that will be cheaper if they hold off for another couple of years. As such, while “costs will come down over time”, he anticipates that this risk of losing out on substantially lower prices is unlikely to come to fore “for another ten years”.

But this still depends on customers agreeing to pay the green premium, which Sury noted would require a greater push from government to drive in the short term.

“If you have the demand side lock themselves in now into longer-term contracts, which might be a bit too costly… that’s why regulation and funding support needs to start helping de-risking,” she said.