A first, rough estimate of LH2 tanker demand
It’s not easy to get an idea of how big the global market for hydrogen as a fuel is going to be. In April this year, a US research company called Reports and Data forecast that the global liquid hydrogen market will grow 5.5% annually between 2019 and 2027. That though is just the beginning. There are plenty of indications that hydrogen demand is going to be much bigger.
You may have read over the weekend that Denmark, a nation at the forefront of decarbonisation – is to stop issuing oil extraction licenses on its continental shelf. This is meant as a statement of intent to move the country over to renewables including hydrogen, which will be produced by new power stations such as the Power to X project in Copenhagen.
Readers of www.ship.energy, where I am a contributing editor, will know about the billions of dollars of investment that are already being poured into hydrogen by those countries who are traditional importers and exporters of natural gas.
By the middle of this decade, South Korea will have three whole neighbourhoods fully powered by hydrogen. The US is building a network of hydrogen filling stations (currently around 70 are operational compared to over 700 gasoline filling stations on the major highways). Japan has vowed to be a “hydrogen-economy” by 2050 and has launched agreements with Australia to import hydrogen – more on this in a moment. Other countries across the world are lining up behind hydrogen as one of the pillars of meeting their Paris Agreement commitments to cap then reduce greenhouse gas emissions.
Hydrogen then will have applications in generating electricity for municipalities. It also has a role in the hard-to-decarbonise transport sector. Over 70 per cent of every barrel of oil is processed into transport fuels. Hydrogen will have to replace some of this.
Let’s not get too ambitious here. If hydrogen were to replace just one third of pre-pandemic global gasoil consumption, that would mean dislodging around 11 million barrels per day of gasoil per day. Probably the market will be larger than that in the future as hydrogen trains are already in operation in Germany, hydrogen planes are already on the drawing board, and hydrogen is a contender for marine fuel, either by itself, in a fuel cell, or blended with LNG, or in a hydrogen “carrier” fuel like ammonia.
Still, let’s go with replacing 11 Mn bpd of gasoil as an achievable target. How much hydrogen would that take? If we work on the idea of replacing liquid gasoil with liquid hydrogen, then we have to account for energy density differences. Liquid hydrogen has only around one quarter of the energy content of gasoil – not least because liquefying one litre hydrogen uses equivalent to 300 millilitres of hydrogen. So to replace 11 Mn barrels of gasoil, industry must produce 44 Mn barrels of hydrogen a day.
Moreover, creating renewable hydrogen means using wind farms, hydro energy, solar or nuclear power to create and store hydrogen by using the surplus electricity generated during off-peak electricity demand to produce the hydrogen as a store of energy, then to liquefy it. That energy can then be released by the hydrogen as electricity via a fuel cell, or as kinetic energy via an engine. (This is the principle behind the Power-to-X concept).
Not every country will have the wind, solar or hydro capacity to produce all the hydrogen it needs. And for some countries, the nuclear option is unfavourable. Japan for instance relies on imports of oil and gas – and was until last year the biggest importer of LNG with China on course to overtake it this year.
Since Fukushima, Japan has a policy of not building more nuclear reactors, but insufficient wind and solar resources mean that it cannot build enough Power-to-X plants to be self-sufficient in hydrogen. Japan will have to import it.
Building on its LNG experience, Japan is developing a hydrogen supply chain. A plant in Victoria, Australia, is creating hydrogen from brown coal. This is being shipped in prototype 8,500 tonne, 1,250 m3 liquefied hydrogen (LH2) tanker to Kobe for regassification and use. In time, basis Japan’s LNG shipping experience, it may be able to build much larger LH2 tankers. The most modern LNG tankers load around 180,000 m3.
Japan has consumed around 0.8 Mn bpd of gasoil this year. To replace that, it would need (very roughly) 2.4 Mn barrels of hydrogen, which works out (again very roughly) at about 380,000 m3. If LH2 tankers of around 180,000 m3 could be built, Japan would need two a day to call to replace its gasoil with hydrogen.
If those LH2 tankers sailed at 12 knots from Melbourne to Kobe, and spent four days in port at each end, they could each perform just shy of eight Australia-Japan round trips a year. If two a day would be necessary for Japan’s import demand, then a fleet of 92 LH2 tankers would have to be constructed.
Once we begin to think about the potential scale of global hydrogen trade, the demand for hydrogen tankers could easily be ten times that of Japan, which is a top five global energy consumer.
There are around 850 VLCCs and around 600 LNG tankers in operation. The size of those fleets may give us some indication of the potential size of the LH2 shipping market.
That’s potentially good news for tanker owners, though the question remains, what will the LH2 shipping market look like? Will bit be like the oil tanker market, with diverse ownership and a spot freight trading arena in which around 130 VLCC fixtures take place every month? Or will it be more like the LNG shipping market in which around 70 per cent of all volumes are shipped as part of long-term contracts? The latter seems more likely as LH2 tanker cost structures may look more like those of an LNG tanker than an VLCC, meaning that long-term employment is the best way to get financing to build them.
We are in the realm of science fiction here but on the cusp of technological fact. An LH2 shipping market is pretty much a dead certainty. That may be a consolation to ship owners wondering what will become of them if and when we pass peak demand for coal, then oil, then natural gas.