Much has been written to date about the cost to produce green hydrogen and how this compares to other colours, such as grey (through steam methane reforming of natural gas), or blue (which is grey hydrogen, but with the 10 kilo of CO2e emitted per kg of hydrogen captured and permanently stored). The argument is that, unless green hydrogen can come down in cost to below blue, it will struggle to get a foothold. A price on carbon would clearly favour green hydrogen, which is made without any carbon emissions, but there is not yet such a universal mechanism in many countries, including Australia.
Purists also often lambast the efforts from fossil fuel companies who promote blue hydrogen. There is evidence that blue hydrogen may in fact emit more greenhouse gases than coal (!), if the natural gas upstream fugitive emissions are properly taken into account; and plenty of scepticism that any captured CO2 can effectively be locked away forever.
Those arguments are important considerations to estimate the likely growth of the industry and potential for decarbonisation. But the potential for a solid start in the short term will be determined by those who can create a project encompassing the full supply chain, from production to storage/transport, and end use.
What are the real prospects for Australian green hydrogen? It will be a contest between two kinds of projects. One is the export project, the other a project for domestic use.
Hydrogen for export
In the last 18 months we have seen many announcements to develop hydrogen export hubs. In addition to Australia’s , most states now have a local hydrogen strategy as well, each declaring their own respective competitive advantages. However, there are many sceptics.. Surely countries like Japan could produce themselves with offshore wind at a lower cost, rather than importing from Australia? And, even if Japan wanted to import hydrogen, why would Australia have an advantage over other countries with equally ample supply of sun and wind, or massive hydro?
Let us explore Japan as an example; in its latest Strategic Energy Plan, high ambitions for hydrogen were stated, despite it being only a small part of their wider energy diversification strategy. The plan quotes numbers from 500 ktpa by 2025, rising to 4 Mtpa by 2040. This demand could be satisfied in two ways:
Domestic: Japan could create H2 locally. Like most countries, it has some wind and solar, but is certainly not blessed in this regard. On-shore there isn’t much space for either solar or wind, and offshore wind will require wind turbines of the floating kind, able to deal with low average wind speeds, and the occasional typhoon and tsunami. Energy would require being transported to shore,and need either expansion of the transmission network, or hydrogen plants. In terms of planning, regulation, feed-in tariff vs auction pricing, among other factors, there would be many obstacles to overcome. Furthermore, any electricity produced is likely to be consumed first as electricity, not hydrogen.
International: Japan could import hydrogen. Japan enjoys established supply chains, with more than 90 per cent of their energy currently imported. Therefore making the tweaks to convert existing import facilities to hydrogen could be easier to overcome than expanding transmission networks. Japan already knows how to transport hydrogen, so they would just need to find the supply.
As with the rest of their energy strategy, they’ll look at a diverse supply of imported hydrogen from more than one country. Apart from cost, geopolitical considerations will be as important. This includes political and regulatory stability of the exporting country, and a secure passage to Japan. Australia has a good scorecard in this, being a stable country at a modest distance through safe waters to Japan. We have strong trade links with Japan. Some commentators suggest also that other countries with a good geopolitical score, like Norway and the US, may choose to produce first for their own use before looking to export.
On the cost side, Acil Allen’s report for ARENA places Australian hydrogen cost on par with Qatar, for example, and lower than Norway and US. Our own internal modelling suggests that hydrogen made in Qatar or Chile may be cheaper to produce, but much of this depends on core assumptions. This includes factors such as utilization, capital cost and labour productivity, driving the levelized cost of electricity (LCOE) of the renewable energy used, and the construction cost of the hydrogen plant. For example, in Australia one can get a blended solar/PV supply in the one location, leading to good utilisation of the electrolyser. By contrast, in Chile the best solar resource in the world is in the Atacama desert, over 1,000km removed from the onshore wind resources to the south of the country. The LCOE estimates of these resources vary a lot as well. For example, the International Energy Institute prices solar in Chile between $20 and $60 per MWh – quite a spread! A blended rate of wind and solar for Australia using puts the resource at $75/MWh, but using the latest draft CSIRO GenCost 2021-22 report pegs combined wind and solar at around $50MWh.
Australia may not yet win out on generation cost, but transporting hydrogen from Chile to Japan will be more expensive than from Australia, reducing the gap. Chile doesn’t have an LNG export industry to lean on to establish hydrogen ports. Plus, it takes over 17,000 km to travel to Japan from Chile, versus only 6,800 km or so from a place like Gladstone. If the transport has to be zero emissions as well, that’d tip the balance to be more in favour of suppliers closer to Japan.
In the end, Japan will take H2 from a variety of sources, both domestic and international. If we took only a quarter of Japan’s projected demand by 2040, that’s 1,000ktpa or one average “mega-project”. Add South Korea, Singapore and other countries, and there’s surely space for a few more mega-projects.The key lesson is that general modeling can only take you so far, and only assessing an individual project will reveal its competitiveness against alternatives.
Hydrogen for domestic use
The second big opportunity is domestic use. Various federal and state hydrogen strategies all call out “hydrogen hubs”, collocating hydrogen production and use. It is not very clear what these would look like but, through conversations with our clients, we do see obvious partnership possibilities. Fertiliser and explosives manufacturers, for example, could be among the first off-takers of green hydrogen. Green steel, aluminium, etc. may later follow, and there is of course opportunity in long-haul transport. Creating a hydrogen project with these customers in mind could be beneficial as the lead developer is also the customer; and thus designs can be optimised to the demand. This opportunity is further enhanced if there is space for ‘behind the meter’ renewables, or the project is located in a state with frequent negative prices. If the manufacturer is close to a community, new technology may even enable municipal solid waste to be converted to hydrogen.
As these projects directly help reduce emissions for the manufacturer, they will also easily attract green finance at favourable terms. Being both producer and customer, cost plays a lesser role, particularly in the presence of an (internal) carbon price.
One important hurdle for electrolyser-based projects will be how to deal with the variability of renewable energy supply. Electrolysers can ramp up and down easily with variable renewables, but the production of ammonia for example needs a more constant flow of hydrogen.
Apart from decarbonizing industries, hydrogen is likely to play a role in the decarbonization of transport as well, especially long haul trucking, and potentially in rail. Given the location of rest stations across the country and the cost to transport hydrogen, we might see smaller, local generations emerge, dotted along our highways. These may create hydrogen from grid energy, or dehydrogenate ammonia trucked to location.
Conclusion
The key to a successful hydrogen project will be establishing the full supply chain, from generation to off-take. Opportunities exist domestically, and we expect some of the early projects to be driven by companies wanting to decarbonise beyond pure electrification. If they have an internal carbon price, this will put additional momentum behind such a project. There will be opportunities for export as well. Given the complexities introduced by different countries and cultures, these projects will rely on building strong partnerships aligned to a common goal.
