Lex in depth: how the hydrogen hype fizzled out
Roula Khalaf, Editor of the FT, selects her favourite stories in this weekly newsletter.
Not so long ago, hydrogen looked like the next big thing, offering a way to decarbonise great swaths of the economy and perhaps even heat homes.
At one point, scenarios for low-carbon hydrogen saw demand rising from virtually nothing to as much as 800mn tonnes per annum (Mtpa) by 2050, or around 20 per cent of the global net zero energy mix. The vast majority of this was expected to be “green”, produced by splitting water molecules using renewable electricity, with a residual share for “blue”, made by stripping out and capturing the carbon in natural gas.
As well as big, hydrogen appeared to be imminent. To be on track for 2050, the world needs perhaps 70Mtpa of green hydrogen capacity by 2030, according to the International Energy Agency’s 2021 net zero scenario. Europe alone set itself a target of 20Mtpa.
Such sizeable near-term numbers galvanised the hydrogen ecosystem. Developers fell over themselves in their haste to announce projects, equipment manufacturers pledged to scale up and reduce prices, and policymakers promised hefty subsidies.
Last year Lex took its own look at the hydrogen industry’s projected development, describing how it was being held up by the high cost of the first waves of projects — even though governments in the EU and the US were hoping to get the ball rolling with subsidies
Fast forward 12 months, and the mood is increasingly despondent. Costs for the first lot of hydrogen projects have been revised up, in some cases as much as doubling. Subsidies have not yet delivered anything like the required shove. Indeed, Michael Liebreich of Liebreich Associates calculates that perhaps $200bn of subsidies may be disbursed in time to generate hydrogen by 2030 — compared to the $2tn-4tn that would be required to meet the targets proposed by policymakers who have enshrined hydrogen at the heart of their plans for net zero. Hydrogen’s ramp-up is much slower than expected, and 2030 targets now look woefully unattainable.
The problem is not just that scaling up hydrogen is harder than hoped. There is also rising uncertainty over how useful it will actually turn out to be.
Electricity-based technologies such as electrothermal batteries and heat pumps have surged ahead, becoming viable options in sectors where hydrogen was expected to play a leading role. Should these deliver on their promise, Lex calculates that hydrogen’s role in a net zero 2050 may be closer to 350Mtpa, less than half as much as the most bullish estimates.
To some extent, such swings in sentiment are typical of new technologies, which go through a cycle of excitement and disillusionment before settling into a final configuration. Hydrogen is still making progress; it will play a role in a net zero energy mix. But the original vision of a superfuel, that could decarbonise large chunks of the economy with minimal disruption to livelihoods or consumer comforts, has shrunk dramatically.
The hydrogen speed bump
The first problem facing green hydrogen is that — so far — there is very little of it around.
The hydrogen in use today is overwhelmingly of the so-called “grey” variety, extracted from natural gas (CH4) while the carbon is emitted. About 100Mtpa is consumed annually, in refineries and fertiliser plants.
The only green hydrogen projects in operation are demonstration or pilot plants. The total annual production is less than 0.1Mtpa combined, about a fifth of what developers had reckoned on achieving by 2022.
Those with an interest in the fuel’s future are making a valiant effort to keep momentum going. Developers are still announcing projects, swelling the potential pipeline to 45Mtpa by 2030, according to a McKinsey report for the Hydrogen Council.
Yet investors have been loath to sink money into the ground. Very few projects have made it off the drawing board and into more advanced stages of development.
Final investment decisions (FID) — the crucial step after which capex starts to flow in earnest — has been taken on 3Mtpa of production capacity. That makes the idea that we might have 70Mtpa of capacity by 2030 look outlandish. Indeed, a recent report by consultancy BNEF estimates that the achievable figure might be closer to 16Mtpa.
To some extent, a delay in the ramp up of green hydrogen was to be expected. It is, at least in part, a consequence of the giddy expectations for the fuel. Developers have an incentive to show ambition as they seek clients and policy support for a nascent industry. And the rapid growth of low-carbon technologies in “net zero” models is the result of working backwards to meet increasingly unrealistic decarbonisation targets.
“Expectations were too high, and failed to take account of real-world constraints” says David Hart of global sustainability advisory firm ERM. “It takes several years to get at-scale technologies right, and this teething time cannot be compressed”.
On top of this, the first wave of projects has been held up by higher costs. Today, an electrolysis plant will set you back perhaps $2,000 per kW of capacity, according to Markus Wilthaner at McKinsey, with large differences between projects, depending on how they are configured. That’s up to 65 per cent more than developers had expected to pay by this time, according to the Hydrogen Council.
The problem goes beyond the electrolyser itself, to everything that one needs to get an electrolyser up and running. An increase in the cost of materials and labour means that pipes, cables, coolers, pumps, water-purification facilities and any building work roughly double the cost of the electrolyser delivered by the manufacturer, according to Jérémie Bertrand of P3 Energy Solutions.
Add in higher financing costs, and projects have seen their investment requirements balloon. The 30MW Bad Lauchstädt Energy Park in Germany, for instance, will require investment of €210mn, 50 per cent higher than originally envisaged.
In many areas of the world, the green electricity needed to power electrolysers is also more expensive than hoped. Add all that together and near-term green hydrogen production is forecast to cost $4.50 to $6.50 per kilogramme. The most optimistic estimates had foreseen the cost falling to some 3 $/kg in the same timescale.
That is a lot to pay for energy. Considering that 1kg of hydrogen contains 33.3kWh, at the top of the range it translates to about $200/MWh, (€185/MWh). And that is just to produce the stuff. Should the project require transport and storage, costs can quickly rise further.
By way of comparison, natural gas costs $8/MWh in the US, and around €30/MWh in Europe. Grey hydrogen costs perhaps €80/MWh, including the carbon price for its emissions.
The implication is that hydrogen’s “green premium” — the extra cost for existing consumers of hydrogen such as refiners and fertiliser producers to go green — is a chunky €105/MWh.
Hardly anyone can afford to buy hydrogen at those prices. Firm purchasing agreements only cover 2Mtpa of hydrogen, thinks Boston Consulting Group. Promised policy support, which could in theory bridge some or all of the price gap, has been slow off the mark.
Lawmakers in the US, for instance, are still discussing the criteria that would enable green hydrogen projects to claim a $3/kg subsidy — guidance issued at the end of 2023 suggested that these may be relatively strict. Until the fog clears, it is hard to see a lot of project developers deciding to pull the trigger.
Delayed or derailed?
In theory, hydrogen’s delay should not necessarily dim the fuel’s long-term future as a significant component of the energy transition.
After all, using green electricity to make hydrogen and then burning it is a wildly inefficient use of the original renewable. It was only ever meant to decarbonise sectors of the economy which electricity could not decarbonise directly — such as long distance transportation and some industry — either because of technical constraints or costs.
Other proposed use cases for hydrogen have long looked tenuous. Hydrogen is not an energy-efficient way to power cars, and heat pumps offer a far more effective alternative for domestic heating. In the UK, a proposed trial to use hydrogen for winter heating has recently been shelved. Given hydrogen’s competitive disadvantage in these segments, most scenarios had already excluded them from long-term forecasts. That includes Lex, whose last stab at estimating the potential size of the hydrogen economy came in at around 500Mtpa.
The trouble is, even this more limited playing field appears to be shrinking. Advances in electricity-based technologies have threatened hydrogen’s potential role in industrial heat. Hydrogen trucking also looks more challenging given improving battery technology and the difficulty in providing hydrogen refuelling infrastructure.
While no two scenarios agree on likely demand by sector, road transport and industrial heat combined were expected to account for perhaps 150Mtpa of hydrogen consumption by 2050. That creates hefty downside risks to forecasts.
Industry’s hot new thing
Industrial processes need a lot of heat — from the relatively low temperatures required to produce food, packaging and textiles to the much higher ones needed in chemicals, cement, and iron and steel plants. Indeed, industrial heat accounts for 25 per cent of final energy use globally.
Electricity was always going to play a major role in decarbonising this sector. Industrial heat pumps, in particular, were considered viable contenders to deliver temperatures up to 150C. Yet that only accounts for 30 per cent of the energy used in the sector, according to the Long Duration Storage Council.
For the remaining 70 per cent of energy which is today used to deliver higher temperatures, viable electricity-based technologies were few and far between. That helps explain why hydrogen — a clean molecule which can be burnt in much the same way as natural gas — was touted as a potential solution.
Recently however, hydrogen’s role is being threatened by the development of electrothermal batteries that use electricity to heat bricks and rocks, which can then be used to provide industrial high-temperature heat. Such technologies can currently deliver 400C-600C, and a report by energy consultancy Systemiq suggests they may reach up to 1,500 degrees.
That would be a game-changer for the industry. Heat batteries are not only much more efficient than burning hydrogen. They will also be able to access cheaper green electricity because they can be charged when renewables are abundant and costs are lower.
A moving target
Hydrogen’s role in heavy trucking is also under threat. The green fuel’s use in transport is predicated on the fact that, compared to batteries, it packs a lot of energy into a given weight. That makes it a potentially viable solution to decarbonise vehicles that have to carry vast quantities of energy onboard, such as planes, ships and big trucks. Batteries are already the preferred option for smaller trucks that make shorter trips.
One challenge, for hydrogen, is that as batteries improve, electric trucks will increase their payloads and ranges. The newest trucks from Daimler, Volvo and Tesla are expected to have a range of 500km-800km.
Another issue, for hydrogen, is that to fuel trucks it needs to be widely distributed, at least along major routes. Scenarios in which a lot of trucks run on hydrogen tend to assume the existence of widespread hydrogen infrastructure. As the range of use cases shrinks, however, hydrogen may end up increasingly confined to industrial clusters, making it harder for trucking to piggyback on existing infrastructure and adding cost and complexity.
The new hydrogen economy
As some of hydrogen’s earlier promise wanes, it is easy to become too pessimistic about its prospects.
Electrification has its own bottlenecks — literally, in the case of overcongested grids which are struggling to keep up with the energy transition. And, despite advances in battery technology, there are still a number of sectors in which hydrogen remains the most viable decarbonisation option.
That includes industries which today use grey hydrogen to make ammonia, fertilisers and the like — which might account for some 60-85Mtpa of green hydrogen demand by 2050. A further 120Mtpa of hydrogen may be consumed in industries which require it as a feedstock, rather than simply to provide heat, such as steelmaking. Decarbonising heavy transport, chiefly ships and planes, might require 175Mtpa of hydrogen, according to the Energy Transitions Commission.
These figures are broad estimates, and there are wide discrepancies between different scenarios. Yet they suggest that hydrogen demand of 350Mtpa by 2050 might be a reasonable ballpark assumption. On top of that, as the role of renewable electricity in the energy system increases, the need for long-term storage — from summer to winter, perhaps — tends to go up. That opens up a greater role for hydrogen to stabilise the grid.
Meanwhile, while slower than hoped, there are still signs of progress. The giant Neom hydrogen project in Saudi is planned to start up in 2026. In Europe, where the Renewables Energy Directive created an obligation to substitute 42 per cent of grey hydrogen with green by 2030, there have been a few final investment decisions focused on refineries and chemicals plants. These include BP’s Lingen compound in Germany and Shell’s 200MW electrolyser in Rotterdam.
Another early positive sign has been the result of the first auction run by Europe’s Hydrogen Bank, set up to provide subsidies to the cheapest new projects. The process selected seven projects out of 132, with the capacity to provide 1.58Mtpa. The projects received less than €0.50 of subsidies per kg produced, highlighting that in some, small niches at least there are potentially viable business cases at reasonable prices. Five of the seven winning projects were located in sunny Iberia, which also points to the vast differentials that will exist between European locations where clean energy is more plentiful, and those which will have to import the hydrogen they need.
In some of Europe’s least sunny and windy locations, the cost of importing hydrogen may well make some uses non-competitive. Because steel, or even intermediate products, are easier to ship around than this hard-to-compress fuel, over time some industries could shift production facilities to hydrogen-rich areas, which would further curtail the market for the molecule in Europe.
A seductive hydrogen narrative has been replaced with one in which the fuel’s complexities and limitations are more apparent. But even its much reduced role could still prove challenging to deliver. Even at 350Mtpa, the potential future market is still more than three times all the hydrogen that we use now, and 400 times the amount of all low carbon hydrogen available in the world.
Hydrogen was once promoted as a miracle fuel for a decarbonised world. Yet delivering on even a more reduced level of ambition remains daunting — and its prospects are ill-served by hydrogen hype that glosses over the difficulties.
This article has been amended to clarify the costs of ‘green’ and ‘grey’ hydrogen.
The colours of the hydrogen rainbow
Green hydrogen Made by using clean electricity from renewable energy sources to electrolyse water (H₂O), separating the hydrogen atoms from the oxygen they are coupled to. Currently expensive but costs are falling.
Blue hydrogen Produced using natural gas but with carbon emissions being captured and stored or reused. Negligible amounts in production because of a lack of carbon capture projects.
Grey hydrogen The most common form of hydrogen production, it involves reacting natural gas with steam — so called steam methane reformation — but without capturing the resulting carbon emissions. Costs have risen this year following global disruption to natural gas supplies.
Brown hydrogen The cheapest way to make hydrogen but also the most environmentally damaging because of the use of thermal coal in the production process.
Pink/purple hydrogen Made using nuclear energy to power the electrolysis.
Turquoise hydrogen Uses a process called methane pyrolysis to produce hydrogen and solid carbon. Not proven at scale. Concerns around methane leakage.
Yellow hydrogen Made from a mixture of renewable energy and fossil fuels.
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