Green hydrogen projects at the hundred-megawatt or gigawatt-scale are often touted as key to moving the dial on emissions reduction, while also decreasing the overall cost of the molecule due to economies of scale.

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But executives at the recent Investing in Green Hydrogen conference in London warned that scaling up will be almost impossible in the current financial, regulatory and technology landscape—and certainly not in time to meet some roadmaps for net zero.

The International Energy Agency (IEA) this month forecast that H2 use would have to reach 150 million tonnes per year by 2030, with 40% from new sectors such as steel, shipping and aviation, to keep emissions reduction in line with net zero by 2050.

But companies behind gigawatt-scale projects point out that meeting anywhere close to this target with green hydrogen will be impossible based on development costs and timelines.

“I’m optimistic about the future and what’s being done… we could get there but we’d need a time machine," said Alex Hewitt, CEO of CWP, in a panel discussing a slightly lower target of 100 million tonnes a year of hydrogen. "We’d need to go back ten years and be at exactly this point.”

He flagged as an example his firm’s 25GW Australian Renewable Energy Hub, which BP took a 40% stake in last year.

“If it is built today, it would be the largest power project on Earth. It [will] produce 1.8 million tonnes per annum, when fully built,” Hewitt said. “It’s a $40bn project, so to get to 100 [million tonnes by 2030]… it’s around $2.5 trillion to get there.”

He added that this would also require 1.5-1.8TW of upstream renewables. “The scale is just mindboggling, and we’ve got six years. So that’s the reason I say it can’t be done — not to say we shouldn’t try, but the lead times on these big projects, they’re ten years… you’ve got six years of development [and] four years of construction.”

Too much noise

James Henry, chief commercial officer for power-to-X at Denmark's Ørsted, argued that the proliferation of project announcements — many with unclear business cases and optimistic promises of low-cost hydrogen — was holding the industry back.

“At Ørsted actually, we’ve taken the unconventional approach of really looking to slim down our pipeline in the last six months,” he said.

“We have been developing projects across products and across markets, and frankly, because of the scale of the opportunity that we see in this market, it can actually be quite distracting, quite overwhelming, when prioritising allocation of capital and human resource,” he said, adding that the developer is now pushing forward with “what we believe to be truly the strongest projects”.

Pierre-Germain Marlier, investment director at hydrogen-focused fund Hy24 agreed, saying: “We went from a pipeline of hundreds of projects, to call it ‘natural selection’ in the current environment of projects that we think right now are bankable for us."

Henry noted that Ørsted had already taken final investment decision (FID) on a 50,000 tonnes-a-year e-methanol plant in Denmark without seeking debt for the project. “We see it as our responsibility to prove this concept can work before we ask the banks to step in and share that risk with us.”

“The noise is unhelpful,” he continued. “I would have thought that, at a conservative guess, 5% of announced projects will ever actually be executed, which means we have a lot of projects competing for the attention of finance or the attention of regulators, and of offtakers, and we essentially cannibalise one another.”

“I would encourage [banks] to continue to just say ‘no’. And the reason for that is I think the industry needs the discipline,” he said.

“We speak to a number of really, really serious developers, household names, really credible institutions, who are making what we consider to be extremely aggressive assumptions around the availability and pricing. And then that feeds into this really unhelpful cycle, where projects are being promoted to customers and setting unrealistic expectations around price, so actually, what I would like to see is a bit of a reality check, which I think will help to clean up some of the noise in the industry.”

‘Not cost-competitive’ for any end use

Part of the problem is that projects need long-term offtake agreements in order to give banks confidence that they will have revenue during debt payback — but customers have been slow to actually sign off on contracts for low-carbon H2 because prices are so high.

“With the right regulatory structure and mandates, there are starting to be use cases where it’s viable to use low-carbon hydrogen… refining for example,” said Felipe Arbelaez, senior vice president for hydrogen and carbon capture and storage (CCS) at oil major BP on a panel at the conference.

“But those are not generalised, and what is clear today is that, what we perceive as all the end use cases for hydrogen today are not cost-competitive.”

Grete Tveit, senior vice president for low-carbon solutions at Norwegian energy company Equinor called on developers to diversify their prospective customer base.

“[Large] projects need to find a different hydrogen market then what we have had for the past 10, 20, 50 years,” she said, flagging steel, shipping and other hard-to-abate sectors are potential new sources of demand for large quantities of H2

“That industry is not there yet to enter into long-term contracts for clean hydrogen,” she cautioned, noting that in new industries, this is because “they need to retrofit their processes and they need to take really heavy investments”.

However, Marlier also noted that green steel is an easier route to securing revenue for project developers if they integrate more of the value chain into their operations. He cited H2 Green Steel, in which Hy24 led an equity investment earlier this month, as an example.

“They’ve been able to get a lot of attention and commitments from banks to access project finance. The way they did this is by integrating pieces of the value chain — it’s not only a hydrogen project, it’s a hydrogen project with green iron and green steel,” he said, adding that these are “easier to sell to end-customers”.

“Maybe tomorrow, when we’ll have pipelines and hydrogen will be a globally traded commodity, it will be different, but today, in fact, by integrating and turning the hydrogen into something more tradeable, they’ve been able to de-risk the project even though they increased the capex,” he added.

But Henry raised that there is also no room for the first projects to fail when it comes to delivering supply to consumers.

“If you’re running a shipping company and you require that fuel to power your vessel, it better arrive. If it doesn’t, you’re not going to place your confidence in larger orders from the larger projects, so these first projects absolutely must succeed,” he said.


Regulations were also raised as a key driver for end-customers to commit to volumes of clean H2 by legally requiring they reduce their emissions.

German energy company Uniper’s team lead for hydrogen project partnerships, Aminta Hall, warned that that there is still some ambiguity as to how the RED III targets, such as 42.5% industrial H2 use being renewable, will be mandated in legislation.

“Even if there is incentive, even if there is legislation, the customer will not go ahead unless he has to," she said. "So the legislation needs to be stronger and clear, I think, no room for interpretation."

Developers at the conference also argued that part of the reason for the high cost of producing green H2 in the EU — or to meet European demand — are the Delegated Acts, which regulate what renewable power sources an electrolyser can use. Until 2030 this means hydrogen must be produced within the same month as the equivalent renewable electricity is generated. After 2030, it is scheduled to switch to hourly matching, which some in the industry say will add to the final cost of the H2.

Arbelaez argued that this telegraphed switch actually makes it harder for projects to be designed in a way that companies — and their financial backers — can take FID on.

“If you’re creating a business model, and you have a project that by definition will have a long payback, if in the middle of that project, you have to completely restructure how you set up the energy system around it, it’s not going to help your final investment decision, believe me,” he said.

“It makes all the boards of the companies very nervous that in year five or year seven of the project you’re going to have to re-draw the business model, [at a point] when you haven’t recovered your full capital.”

“The projects we’re looking at are industrial-scale, hundreds of millions of dollars per project. I’m not talking 5MW, 10MW — more 100MW, which is what we’re going to need if we’re going to move the needle,” he added, noting that it is difficult to “write the cheque” if commercial contracts have to change late in the project’s life cycle.

The European Commission is set to deliver a report to the rest of the European Union on the impact of the Delegated Acts by 1 July 2028, which could prompt a review of rules such as hourly matching of renewable power generation and hydrogen production, before they kick in from 2030.


On the flip side, the industry also raises that while Europe offers generous subsidies, delays in awarding grants and some of the strings attached are actively holding back projects from moving forward.

“What we see is, initially the subsidies — because of the huge amounts of capital that were announced available for subsidies — attracted a lot of initial capital, project development, initiatives and things like that, so initially it was actually very virtuous and very positive,” said Benjamin Haycraft, executive vice president for EMEA at US-based green hydrogen technology company Plug Power.

“Today, we see some projects that are fully engineered, investment decision is kind of taken, but if you want to get access to subsidies, you need to show to the member state or the European Union or to whomever, that you basically have a funding gap. If you don’t have a funding gap, then you don’t get a subsidy,” he said.

This means that projects otherwise ready to take FID — but for the notification that they will receive a subsidy — are left in limbo.

“If getting access was a two-three month process, not too big a deal, but very often it’s a one-year or multi-year process. If you applied for the Innovation Fund, most of the developers will know that applying to the Innovation Fund, you have far higher chances of success the second year you apply than the first year you apply,” Haycraft added.

“I do think that today, the way the subsidies are being structured is highly convoluted and complex, to the point where it features a lot of inefficiencies. I have in my advanced pipeline hundreds of megawatts, that could become backlog tomorrow, if they have confirmation of subsidies. And when I see that flat for several months, close to a year, I’m thinking, ‘yeah, there’s something that doesn’t work well here’.”

The European Commission is set to launch the pilot auction for the European Hydrogen Bank, which offers up to €4.5/kg in fixed premiums to cover the cost gap between green and grey H2.

However, some developers decry that many of their projects will not be eligible due to a rule against seeking capex support as well.

“It is good that we are seeing now the European Hydrogen Bank coming — fantastic — but when you read the conditions, it says you cannot participate if you have applied or are applying for other subsidies,” said Hall.

Since projects currently require “a large amount of funding at the moment because the price is very high”, the company has to patchwork together different subsidies to meet a percentage of the development or capital costs, she added. “It is only by accumulating funding that you can make these projects come alive.”

“We cannot have those kind of conditions on that kind of funding, that you cannot apply if you have applied to other,” Hall argued, calling for percentage caps on subsidies rather than a total restriction.

And even if subsidies, regulations, offtakers and finance fell into line, projects are still at risk of major delays on equipment, speakers agreed.

“Today, the supply chain is already significantly challenged,” said Chris Gill, a senior vice president for global hydrogen at Worley, going on to note that this is not only the case for electrolysers, but for every piece of equipment that goes into a green hydrogen facility, from the upstream renewables to the electrical equipment to downstream processing.

“So, say, if you order a high-voltage transformer, you’re probably waiting 18 months,” Gill said.

This could require new ways of developing projects, he explained, such as moving away from traditional design-then-bid development towards engaging with suppliers early to understand potential bottlenecks.

But beyond this, there is still uncertainty on what equipment types will ultimately prevail.

“There will need to be a race to establish which technology is the optimal technology that we as an industry are going to support and manufacture at scale,” Henry noted, adding that it was key that projects ultimately perform to their design and can be operated in such a way that supports cost reductions.

“It’s only with those cost reductions that you can ultimately get to the scale that the customer demands.”