How much does a kilogram of green hydrogen currently cost? It’s such a simple, straightforward question, but one that is very difficult to answer.
To start with, green hydrogen barely exists today. It is only made in small quantities, mainly on an experimental basis, and those companies producing it often do not reveal their costs, arguing that current pricing will not be representative of large-scale manufacturing.
This presents major problems for reaching the lofty goals set out by the green hydrogen industry: how can buyers agree to purchase volumes from future projects if they don’t know how much a kilogram of H2 actually costs now, let alone in five or ten years’ time?
Similarly, can governments be sure that their subsidy schemes will be generous enough to ensure that green hydrogen will be cheaper than grey, without taxpayers overcompensating companies — including oil majors that are already making huge profits?
While individual companies can calculate the cost of producing hydrogen from a given project based on their specific set-up — such as the electrolyser, renewable energy source, etc — big business and governments really need to base their decisions on an agreed market price.
This is why analysts and consultants have developed a number of different models and indices that attempt to give more definitive answers to the question of how much green hydrogen costs today — and therefore what price companies will need to sell it at in order to break even.
Both producers and potential buyers “are deeply interested in having a market price”, according to Sirko Beidatsch, natural-gas markets expert at the European Energy Exchange (EEX), which last month launched its own “Hydrix” index claiming to list prices for real green-hydrogen trades in Germany on a weekly basis (see below for more details).
“It is fundamental to have price transparency. Consumers can decide to switch from grey to green, or even open their long-term existing contracts, but they first need that price indication,” he tells Hydrogen Insight.
The variability of current pricing models
The pricing models and indices that have so far been developed take one of two different approaches.
The first is to tally up the prices agreed in what few contracts have been signed — a difficult task given the signatories are often unwilling or unable to disclose any details of these offtake agreements. The second is to calculate prices on paper, based on publicly available clues.
The latter method tends to focus on the cost of production, rather than the cost to the buyer, which may include the cost of storing, processing and transporting the green hydrogen — additional costs that can be just as expensive as making it in the first place.
“Generally speaking, there’s a misconception that the levelised cost of hydrogen that we and other research houses produce are reflective of delivered prices,” says Adithya Bhashyam, associate for hydrogen at BloombergNEF (BNEF), which recently released a paper on expected green H2 costs in different markets. Its results ranged from $2.38-12/kg.
Instead, he cautions that these analyses are meant to assess changes in the underlying cost of green hydrogen production, namely the electrolyser and the renewable electricity supplying it. Both of these are expected to fall in the long term as production scales up and more units are deployed, although “in the near term, commodity inflation could affect both”, Bhashyam points out.
The costs of electrolysers and renewable energy vary wildly between countries, with Chinese alkaline electrolysers being around a quarter of the purchase price of Western models, according to BNEF.
The costs of electrolysers and renewable energy vary wildly between countries
So the lower end of its calculations tend to be reflective of projects using Chinese alkaline electrolysers. However, these low costs are unlikely to be achieved in Western markets since there are very few exports from China at present and transporting the heavy machines from Asia to the West would be costly.
Jake Stones, hydrogen editor at market intelligence service ICIS, tells Hydrogen Insight that there can be “some variation” from the calculated levelised cost of hydrogen between individual projects based on how they have set up the electrolyser and upstream renewables.
However, he adds that the indices and models “can give a daily, centralised case for the cost of hydrogen when looking at current spot power and gas market prices”, which can be agreed on in the market as a fair value.
“It gives market participants a useful indicator of where prices can be, but the price at which they sell will depend on their own production cost, which will be unique to them,” he explains.
Other factors can also influence — and complicate — price calculations.
For example, in June, Dutch green hydrogen exchange HyXchange, an industry coalition, unveiled a green-hydrogen price indicator called Hyclicx. This combines spot prices on the Dutch electricity market over the past month with the cost of renewable-energy Guarantee of Origin certificates, while also accounting for efficiency losses and projected maintenance costs.
But unusual spot prices can skew results for any given time period.
For example, between 1-24 July, the cost of green H2 production was calculated to average €86.23 ($95.95) per MWh (equivalent to around €2.59/kg) — skewed by a single day of extreme negative pricing on 2 July when a windy and sunny day meant that supply exceeded demand.
This put it close to the cost of grey hydrogen made from unabated fossil gas, which was averaging €64.13/MWh (€1.92/kg) over the same time period.
Hyclicx also calculates the expected marginal cost of producing grey hydrogen and blue hydrogen in the Netherlands based on gas and carbon prices.
A further complication is that Hyclicx’s prices do not include fixed costs such as the capital expenditure needed to make hydrogen. So Hyclicx’s cost of blue hydrogen can be lower than grey due to the EU’s carbon price.
But HyXchange founder Bert den Ouden concedes to Hydrogen Insight that “the investment cost [for blue] is higher, so blue will have a higher price” at first.
Additionally, for green hydrogen, Hyclicx calculates two different prices. The first is based on bidding for the same two fixed six-hour blocks of what tend to be the cheapest hours for electricity in the early morning and afternoon. The other is based on the lowest-priced 50% of hours in a month “if you had perfect foresight on a monthly basis”, den Ouden explains.
Another problem is that because Hyclicx uses spot prices, “we only know the historical [cost of production]”, den Ouden says, noting that the organisation is currently considering an index based on renewable power-purchase agreements (PPAs), from which it could publish forward curves.
ICIS takes a similar approach to hydrogen price calculations, albeit working on the assumption that project developers are likely to sign PPAs with renewable-energy generators to lock in electricity supply that complies with the EU Delegated Acts, such as using wind and solar power that would not have otherwise been built (so-called “additionality”).
The company’s green hydrogen price is calculated from factors including the current spot price of electricity, the efficiency of an electrolyser, and the production profile of different renewable technologies, such as solar, onshore wind and offshore wind. And the platform also works in expected capital and operating costs to calculate a separate “breakeven” levelised cost of hydrogen (LCOH) — in other words, the average cost per kg of H2 produced over the lifetime of a plant.
ICIS data estimates that for a green hydrogen project financed between 18-24 July using two-year futures for spot power market values, the developer would need to sell volumes ranging from €7.74-9.13/kg to break even (depending on which European market they were made in).
That is a far cry from Hyclicx’s €2.59/kg figure for a similar period, reflecting how different these calculations can be, depending on the variables and assumptions used.
How much does the power cost?
Power price is the biggest factor in determining how much green H2 costs, accounting for 60-75% of the final cost of hydrogen production.
This should be good news for green hydrogen, since the levelised cost of electricity from wind and solar is set to drastically decrease over the coming decades — right?
Not quite. “Most electrolysers today need to run on a high utilisation rate, which requires close-to-stable electricity input,” Bhashyam says, adding that this can also be the case for balance-of-plant equipment.
Similarly, offtakers in heavy industry require large, consistent volumes of H2 to run their processes, which requires either large-scale storage or constant production.
This means that most green H2 producers will need to have back-up power from either a battery (a huge addition to capex) or the grid.
And developers opting to connect to the grid and cover their renewable electricity supply requirements with a PPA may quickly learn that these contracts are “not necessarily reflective of the cost of renewable electricity production alone”, Bhashyam says.
“PPAs are highly influenced by the spot power price [on the wholesale electricity market],” says Stones, although he notes that the grid will have a higher share of renewables over time and therefore be impacted by the trend of wind and solar power prices going down over time.
While PPAs are generally getting cheaper in Europe as electricity and other commodity prices fall, contracts that are shorter in length may be more expensive for the buyer, according to UK-based Aurora Energy Research.
“In today’s market conditions, we observe strong interest from corporate buyers in entering into PPA contracts, creating pressure on the PPA demand side that is pushing prices towards discounted long-term forward price levels,” says Marco Pellegrino, the research firm’s PPA advisory lead.
In general, these contracts are front-loaded, meaning that the power provider earns more in the first few years of operation — to partly cover the high upfront costs — than in later years, when future wholesale electricity prices on a renewables-heavy grid may be lower.
This means that “a short-term PPA results in higher PPA prices”, Pellegrino explains.
So the price of green hydrogen also varies depending on the length of the power supply contract.
Yet hydrogen project developers in Europe may be more likely to seek shorter PPAs, such as the three-year agreement recently signed by Air Liquide and Statkraft, with an eye towards complying with the EU’s Delegated Acts defining renewable H2.
These require projects to match hydrogen production and renewable electricity generation on a monthly basis up to 2030, after which the renewable power has to be consumed by the electrolyser in the same one-hour period as it is produced. In addition, the acts also contain a clause that allows member states to enact the hourly matching rules early, from mid-2027.
Hourly matching is controversial among green hydrogen developers as it limits the number of hours an electrolyser can be operational and increases the intermittency of production — both of which are expected to bump up the cost of production and the final price at which renewable H2 can be sold.
While it is unlikely that countries will pull the trigger early, uncertainty means that developers will either have to design projects around the assumption of hourly matching from the start, or sign short-term PPAs up to mid-2027 or 2030 — with both these options adding to the cost of green hydrogen.
So what are companies in Europe actually paying today?
Some reports and studies, including those by industry association Hydrogen Council and climate think tank the Energy Transitions Commission, have estimated that the cost of producing renewable hydrogen will fall below $2/kg by 2030.
But the proliferation of these extremely low price estimates — without also including caveats around methodology, technology, electrolyser efficiency, capacity factor, market, or additional costs of storage or transportation — has been criticised by some developers.
“I think there has been... wrong information. There have been a lot of reports saying you can produce green hydrogen at €2/kg, and this is not real. The cost of electricity is what it is,” said Iberdrola’s head of global hydrogen development Jorge Palomar Herrero at a conference earlier this month in Madrid.
He referred to Spain’s most recent renewable energy auction, which was undersubscribed and had an average electricity price of €42.78/MWh — which indicates a green hydrogen production cost of around €6/kg (assuming a 50kWh/kg electrolyser efficiency and 60% capacity factor) — noting that estimates often assume much lower power prices.
This makes discussing the final cost of green H2 with offtakers particularly difficult. “Demand is [asking], ‘Why should I pay €7 [per kilogramme]?’” Palomar Herrero added, estimating that green hydrogen prices in Germany and the Netherlands will generally range from €7-8/kg.
EEX’s Hydrix index, which claims to list actual traded green hydrogen prices in Germany on a weekly basis, said the latest weekly price of renewable H2 was €224.34 per MWh at lower heating value, which works out to around €6.73/kg.
However, this index has also been met with scepticism, particularly around how many trades could actually feed into a weekly price calculation, how representative it is of a future market given that volumes bought and sold today are so low, and methodology that would imply the inclusion of price signals from buy or sell offers.
EEX’s Beidatsch clarifies that Hydrix considers prices from mid-to-long term offtake agreements, spot sales of volumes to customers, and agreements that have not closed but have “a final negotiated contract ready to sign for that delivery week”. That third type of data will also only be included as a “sell” or “buy” price, depending on which side of the contract sent in the information.
“There is a big difference between production-based assessments already in the market to Hydrix, which already has supply-demand considered,” Beidatsch says.
He adds that a sole focus on production does not consider “the willingness of customers to pay for green hydrogen”, particularly since offtakers (depending on the sector and the market) may have different stackable subsidies or incentives feeding into their decision to purchase renewable H2 volumes, even at prices that would appear to be uncompetitive with grey.
While Hydrix currently only lists prices for Germany, EEX is considering further indices for other markets, albeit within national borders due to the range of different subsidy schemes that might influence price.
EEX’s director for political and regulatory affairs, Daniel Wragge, adds that “the next step is auction prices, such as those derived from the H2Global mechanism”, referring Germany’s double-sided tendering scheme which will buy imported hydrogen volumes at the lowest price and sell them to domestic users at the highest. The government-supported company running H2Global’s auctions, Hintco, recently agreed to hold future tenders on EEX’s platform.
The European Commission is also set to begin offering subsidies of up to $4/kg through an auction mechanism from this December to cover the cost gap between grey and green hydrogen — in a process where producers bid to receive the lowest subsidy.
Stones points out that the results of this tender will show “which geographies and environments really do support the lowest costs”.
So once auction results are public — and demonstrate what price companies are actually buying and selling at — will calculated estimates still be necessary?
Since electrolyser and wind or solar technologies are evolving all the time, it stands to reason that regular LCOH calculations will still be necessary to give an estimate to guide business and policy decisions. But full transparency will still need real prices.