One of the many far-reaching impacts of Russia’s invasion of Ukraine was a flurry of announcements by governments in Europe to build new liquefied natural gas (LNG) terminals, as the continent outlined its ambitious plan to phase out imports of Russian pipeline gas. According to GlobalData, Energy Monitor’s parent company, there are currently 32 LNG terminals planned or under construction in Europe. These include two in Ireland, three in Italy, five in Greece and eight in Germany.
Even as energy security became a key policy priority in 2022, LNG expansion plans were criticised in some quarters as being unnecessary and incompatible with the EU’s plan to reach net-zero greenhouse gas emissions by 2050. The NGO Food & Water Action Europe pointed out in spring 2022 that between January 2021 and January 2022, only 40% of EU LNG terminals’ capacity was utilised, questioning the need to build more. The Institute for Energy Economics and Financial Analysis argued that LNG imports would be more expensive than boosting domestic renewables, and future LNG prices and supply would remain unpredictable.
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As it turned out, the EU was able to sufficiently boost LNG imports this winter without major new LNG terminals, even as Russia significantly squeezed its gas supply.
European nations are continuing to plan and build new LNG terminals, however, and another way that governments are justifying the projects is the possibility that they can one day be retrofitted to import liquefied ‘green’ hydrogen. German Chancellor Olaf Scholz in particular has made this case, and in August 2022, it was reported that Canada and Germany intend to establish a transatlantic hydrogen supply corridor that would see German companies import green hydrogen produced from Canadian renewables.
In January 2022, the world’s first-ever shipment of liquefied hydrogen travelled between the Port of Hastings in Victoria, Australia, and Kobe, Japan, marking a significant milestone in Australia’s Hydrogen Energy Supply Chain (HESC) Pilot Project, and potentially signalling a new era of transoceanic energy supply.
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“Liquefying hydrogen reduces its volume by 1/800th, ideal for transoceanic trade,” a spokesperson for HESC told Energy Monitor. “The achievements so far give us confidence that producing hydrogen in Victoria’s Latrobe Valley and exporting it to Japan is both technically possible and will be commercially viable.”
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By GlobalDataHow realistic is a global scale-up, however? Is it likely LNG terminals will play a role in shipping and storing liquefied hydrogen that is internationally traded? Evidence suggests both these outcomes are unlikely.
No liquid hydrogen ships soon
Liquefying natural gas, and transporting it in a tanker at -162°C for thousands of kilometres across the ocean, remains a technical marvel, even if the hundreds of millions of tonnes that are transported this way each year make the process seem routine.
However, liquefying and transporting hydrogen is even more complex. Hydrogen molecules are significantly smaller than methane molecules, making the gas much leakier, and meaning that it requires more robust storage tanks and pipelines. Hydrogen’s boiling point is also significantly lower at -250°C, meaning that much more energy is required to cool it, and pipes and storage tanks also need to be much better insulated.
The International Energy Agency (IEA) notes in its Global Hydrogen Review 2022 that hydrogen liquefaction and storage are “mature technologies that have been used for decades”. Liquefied hydrogen has, for example, long been the fuel of choice for rockets used by Nasa. However, ships for transporting liquefied hydrogen are “not yet commercially available”, the IEA adds.
Indeed, the aforementioned Australia to Japan pilot project cost a massive $500m and commercial viability is yet to be determined. What is more, the hydrogen transported was made by reacting oxygen and coal under high pressures – as opposed to electrolysis using renewable electricity – and hydrogen safety concerns appeared justified after a fire broke out on the ship during loading.
It is for these reasons that Michael Liebreich, energy consultant and founder of research company BloombergNEF, believes that political promises of a commercial liquid hydrogen supply chain are “incredibly disingenuous”.
“Hydrogen is a totally different gas to natural gas,” he told Energy Monitor. “It is not like where we were with solar and wind 20 years ago, where the commercial problem was to do with material science and manufacturing. With hydrogen, it is a question of thermodynamics, not technology. We are not about to change the physical properties of hydrogen that make it so difficult to transport in ships.”
Ammonia and LOHCs
Liquefying pure hydrogen molecules is not the only means by which hydrogen can be transported in ships: It can also be reacted with nitrogen and transported as ammonia or transported in another organic carrier, known as a liquid organic hydrogen carrier (LOHC). However, there are also serious doubts over the viability of these technologies.
Ammonia is a more convenient option in that it only needs to be cooled to -33°C to be liquefied for transport and around 20 million tonnes of it is already transported each year, with 195 ammonia terminals at more than 120 ports around the world. However, converting ammonia back into hydrogen is extremely energy-intensive – requiring around 30% of the energy content of the ammonia – and would require huge amounts of clean power to ensure the process is zero-emissions.
The situation is similar with LOHCs. They do not even have to be cooled to be transported, but the chemical reactions required to hydrogenate and dehydrogenate the molecule corresponds to around 35–40% of the energy content of the transported hydrogen, says the IEA.
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Ammonia and LOHC transportation and cracking (to re-extract the hydrogen) trials are taking place around the world.
In the UK, for example, the Tyseley Ammonia to Green Hydrogen Project has been awarded £6.7m of public funding to build a demonstration ammonia cracking unit to supply hydrogen to a refuelling station in Birmingham.
Meanwhile, in Singapore, five companies – Sembcorp, City Energy, PSA, Jurong Port and Singapore LNG – have signed a deal with Japanese industrial giants Chiyoda and Mitsubishi to assess the technical and commercial feasibility of importing LOHCs. The consortium is aiming to fully commercialise the technology by 2030.
However, experts spoken to by Energy Monitor are sceptical these carriers will ultimately be the main means by which hydrogen is transported.
“There are already massive ammonia requirements in the chemical industries, notably in fertiliser production, while LOHCs like methanol may well be required in shipping fuel or the chemical industry,” says Thomas Koch Blank from the think tank RMI. “It is much more likely that when these products are created using green hydrogen, [they] will remain the end product. There is little point in using a huge amount of energy to convert them back into hydrogen.”
Mathias Koch from the think tank E3G says: “Given the many technical hurdles, [it is] unlikely that transoceanic trade in hydrogen will be economically viable in the near future.” Many of the studies envisaging massive transoceanic trade are likely overestimating the reach of hydrogen fuel in the energy transition, he adds.
“More and more studies suggest hydrogen will not play a role for household heating or for individual transportation, and even in use cases that were previously considered [such as hydrogen for trucks] other energy forms may end up being the most efficient solution,” Koch [from E3G] says. “While there will be significant demand for hydrogen in a decarbonised world, this demand may be smaller than what many people expect – raising doubts that importing hydrogen from outside the immediate neighbourhood will ever be necessary.”
Hydrogen-incompatible LNG terminals
The contrasting physical properties of natural gas and hydrogen mean that converting the world’s LNG terminals to hydrogen is likely to be a very complex, if not insurmountable, challenge.
According to the IEA, a liquefied hydrogen tank at a liquefaction or regasification plant would require insulation with ten-times higher thermal resistance than for LNG, posing a major retrofitting challenge, and likely meaning it would be more economical to simply build a new tank. At LNG terminals, tanks represent around half the capex – so making the necessary tank adjustments to receive liquid hydrogen would involve significant additional costs.
The IEA adds that a newly built liquefied hydrogen tank would be able to store 60% less energy than an LNG tank of the same size. It would also require massively enhanced safety precautions, given that nitrogen and oxygen from the air – with respective boiling points of -196°C and -183°C – are at risk of condensing, which is not the case in a tank containing LNG, which has a higher boiling point.
A report from the Fraunhofer Institute for Systems and Innovation Research in Germany commissioned by the European Climate Foundation, a philanthropic initiative working towards net zero, concludes: “It is uncertain if there is a future use case for LNG terminals with renewable energy carriers, which poses a risk for them to become stranded assets in the medium term”. The only way for “some components” of terminals to be reused for ammonia and liquefied hydrogen is if “a concept for the conversion has been made in the construction phase of the terminal and has been taken into account in the material selection of the terminal”.
Liebreich concurs there is no easy switch from LNG to liquefied hydrogen at terminals.
“LNG terminals are designed with LNG in mind: for the temperature of LNG, the physical characteristics of LNG and the pumping requirements of LNG,” he says. “You need to completely redesign all of these characteristics for hydrogen: different steel, different pumps, different valves, different heat exchangers.
“Only if you design your LNG terminal incredibly smartly is there a possibility that it could maybe be ammonia-ready.”
At the European Green Energy Hub in Wilhelmshaven, Germany, a joint venture between TES, Engie and E.ON is pursuing another method still: reacting green hydrogen with CO2 to produce synthetic methane. The facility plans to switch from importing conventional natural gas to 'green' synthetic methane by 2027. However, there are currently no plans in place to carry out this process at a commercial scale.
The likely future of traded hydrogen
Currently, the physical properties of hydrogen mean it is most economical to produce the gas in clusters close to where it is used. For E3G’s Koch, even as hydrogen production switches from grey (produced from natural gas) to green (produced by electrolysis using renewable electricity), the likely future of traded hydrogen in Europe is to remain oriented towards domestic production, or pipeline imports from near-neighbours with high renewable energy potential, such as countries in North Africa.
“In technical terms, Europe has more than enough wind and solar capacity to cover its hydrogen demand with domestic production,” says Koch. “Europe's potential for renewable energy calls into question whether long-distance transports of hydrogen are necessary at all.”
Koch's conclusion from various cost estimates for hydrogen production is that the cost of transporting hydrogen for 600km via pipeline is around half the cost of transporting liquefied hydrogen the same distance by ship.
Converting natural gas pipelines is more likely than converting LNG terminals to hydrogen, suggests the IEA. There are more than 1.2 million kilometres of installed natural gas transmission pipelines worldwide, with approximately another 200,000km under construction or in pre-construction development. In practice, compressors would need to be replaced, and there would need to be a thorough inspection of components, before they can be considered hydrogen-ready, the agency says.
In 2022, the CEOs of 31 European gas infrastructure companies presented a pledge to the European Commission to establish hydrogen supply corridors by 2030. However, practical experience of hydrogen conversion remains very limited: the only example is a 12km repurposed pipeline in the Netherlands.
Geographical isolation, limited renewable energy potential and high industrial demand may make liquified hydrogen shipments viable on a small scale to some countries, notably Japan and South Korea.
“A pipeline is going to be option number one,” says RMI’s Koch Blank. “When this is not possible, most recent studies suggest ammonia and LOHCs are the likely front-runners. Transporting pure hydrogen via these methods remains an expensive, technical challenge, but they still look more viable than liquefying and regasifying hydrogen.”
However, even for these countries, the jury is still out: Liebreich suggests it is more likely Japan will harness its vast offshore wind potential in the Pacific to produce hydrogen than import from countries via Australia.
Doubts over demand and technical specifications make it unclear what hydrogen trading will look like in a net-zero world. What is clear is that transoceanic supply corridors, as currently exist for oil and LNG, seem unlikely to emerge in the hydrogen industry any time soon.
