The momentum behind green hydrogen has notably decelerated, with developers being hit with some hard home truths. Far fewer projects have taken the final investment decision (FID) this year than anticipated. As of May 2024, less than 7% of the announced electrolytic capacity had passed the FID stage globally, according to data by the Hydrogen Council. Several large-scale hydrogen projects have been cancelled or delayed, including the 17MW Hannover project and the 12 GW HyEnergy project in Australia.  

Developers point fingers at cost escalations across the value chain, uncertainty around the customer offtake, difficulty getting grid connections, and hard-to-access regulatory schemes. At the Investing in Green Hydrogen 2024 event in London last month, there was a lot to learn on the subject. 

Regulatory Quagmire 

The U.S. The Inflation Reduction Act (IRA) held promise of lowering green hydrogen prices, with a subsidy that translates into $3/kg – one of the most generous tax subsidies on green hydrogen in the world. However, the hourly matching requirement, which means that to qualify for the subsidy producers must show that they have used renewable power sources every hour to produce hydrogen, has made it difficult for developers to access the tax subsidy.  

So, the average cost of green hydrogen in the U.S. is currently estimated at $5/kg, with the IRA subsidy already deducted. Meanwhile, the cost of grey hydrogen, which is produced from fossil fuels without carbon capture and storage, is currently estimated at $0.5/kg.  

In early October 2024, U.S. project developer Hy Stor’s Mississippi Clean Hydrogen Hub (MCHH) cancelled a 1 GW hydrogen order. Hy Stor did not state the reason for the delay, but the project was unsuccessful in receiving funds from the U.S. government’s $7B Regional Clean Hydrogen Hubs scheme.   

Escalating Project Costs 

Many hydrogen projects were announced with the expectation of the availability of cheap power as well as costs declining across the value chain as the industry scales. In Europe, the expectation that power prices will decline has not materialized and the high-interest rate environment has put upward pressure on project costs across the value chain.  

Developers reported an average three-fold cost to the upfront CAPEX. A report from the Hydrogen Council at the end of December 2023 suggested that projects faced cost escalation of up to 65%. The cost and availability of components has also not improved, with the average wait for transformers estimated at two years. There is up to a ten year wait in many countries for a grid connection. 

As a consequence, the forecast price declines have not materialized, and green hydrogen prices remain too high to attract any long-term offtake interest, and less than ten FIDs on European plants have been made this year. It is also becoming increasingly clear that hydrogen will remain too expensive compared to some of the competing decarbonizing technologies, and so is likely to only be suited for some niche applications. For example, it is unlikely that hydrogen will ever play a major role in space heating. 

Long-term offtake agreements (Hydrogen Offtake Agreements (HOAs)) are crucial to secure project financing. With very little visibility into hydrogen pricing and consequently reduced opportunity for price risk hedging, buyers are understandably reluctant to sign on the dotted line. It is estimated that between 100-200 offtake agreements in Europe have been signed with tenures of 5-15 years. Meanwhile, banks and other project financiers need to see at least 12-year deals to provide project capital.  

It is difficult to align the buyer’s and seller’s expectations. Large-scale electrolyzers are still a fairly nascent technology and so it’s hard for developers to give performance guarantees that would satisfy customers.  

One way to circumvent the price risk is for buyers to obtain a stake in a hydrogen production facility. As a great example, Scania signed a supply agreement with the H2 Green Steel project, and also participated in its $105B Series A round. Project developers can also build business models on tolling agreements, where an offtaker provides an input, such as electricity or water, and only pays for its conversion into hydrogen. A tolling agreement typically stipulates minimum offtake volumes.    

As developers are scaling up, more problems have emerged. Optimizing the balance of plant (BoP) is proving to be a learning curve, developers conceded. Furthermore, it is difficult to match the production profile with the demand curve. Developers underlined that it was easier to get smaller projects over the finish line than gigaprojects. Indeed, only 9% of clean hydrogen gigaprojects globally have passed the FID, according to the Hydrogen Council data.  

Still some projects have indeed managed to progress over the FID line, offering learnings to those who follow. Shell took a final investment decision on its 100MW PEM electrolyzer at the Chemicals Park Rhineland production site in Germany. Tim Calver, VP of Commercial at ITM Power, the technology provider for the Rhineland project, noted that the success of the project’s progress can be attributed to receiving clarity around subsidy schemes, including the grid exemption subsidy, a financial incentive provided to entities that generate and consume their own electricity without relying on the traditional power grid. 

Furthermore, new hydrogen use cases, such as distributed ammonia production, are emerging. Ammonia production is mostly done via the Haber-Bosch process which typically requires an uninterrupted power supply and economies of scale. However, start-ups like Ammobia require lower temperatures and ten times lower pressure to produce ammonia than the traditional Haber-Bosch process, making distributed production case possible.