Renewables + Hydrogen = Industry Reimagined
Hydrogen has been closely associated with key aspects of the new energy transition for many years. Its properties as a storage medium and energy carrier make it a key point in any serious discussion about energy storage, and its consequent role in increasing renewable penetration in energy generation, transmission and distribution. Hydrogen fuel cells are also high on the agenda for expanding the number of light electric vehicles on the road.
However, what we are discussing here, and the area that is starting to attract attention from governments and municipalities looking to reduce overall greenhouse gas emissions, is green hydrogen. This is defined as hydrogen that is produced from renewable electricity by electrolysing water, or from fossil fuels with carbon capture and sequestration (CCS). It produces relatively pure hydrogen, with the added benefit of oxygen as a by-product.
The idea of green hydrogen has been around for some time. But it comes with a number of inherent challenges, the most obvious of which is that it is not hugely energy efficient. The input energy required to power the electrolysis and produce end product is much greater than the energy output that can be liberated from it.
For example, our high-level analysis of the hydrogen supply chain and the export of renewable energy to South East Asian countries for use as transport fuel shows that, when hydrogen is converted to ammonia to make it possible to transport safely, only 30 per cent of the renewable electricity originally used to power the electrolysis actually ends up moving vehicles. Seventy per cent is lost in the various conversion processes.
However, this might be a case of allowing the search for a perfect solution to obscure the value of a merely good one. A key reason those South East Asian countries might consider green hydrogen in the first place is that many are relatively short of indigenous energy supply. For countries like Japan and South Korea, for example, with their energy-hungry economies that rely heavily on energy imports, green hydrogen could provide a low-carbon alternative to coal, natural gas and oil.
In the transport sector, hydrogen would be displacing comparatively expensive liquid fuels with relatively low thermal efficiency. And although this green hydrogen route is less efficient and more expensive than using electric batteries directly, it could provide the additional travel range that batteries are yet to achieve. That enables renewable-powered electric buses, trucks, ships and trains to transport passengers and goods over the long distances needed to make them a truly viable option. And of course there’s the added bonus of reduced air and noise pollution levels.
And in theory at least, hydrogen is transportable over long distances via shipping and could evolve into a liquid global market; the alternative being a commitment to import electricity via transmission lines to neighbouring countries.
To illustrate the point, South Korea has recently announced its commitment to convert 26,000 buses using hydrogen fuel cells instead of natural gas. South Korea has negligible renewable energy generation resources, and what it has is largely in the form of offshore wind – always more expensive than onshore. So it is in discussion with the Governments of other countries to provide green hydrogen.
However, to meet this kind of demand, South Australia would need to build approximately 17 electrolysing facilities; and to power these facilities it would need to develop around 8,700 megawatts (MW) of renewable energy projects. This is where we hit the next challenge around green hydrogen: the overall price. To date, renewable energy has not been available at a price to make this kind of installation commercially viable.
This is where we see the impact of the downward trajectory of renewable electricity prices, notably solar and onshore wind. The price used for renewable electricity in current modelling and projections is $60 per MW per hour (MWh). Technological advances have dramatically improved conversion efficiency of solar panels, as well as wind-farm capacity factors, and the price could conceivably fall to $30 or even $20 per MWh, particularly in areas with high levels of renewable energy resources.
Solar power auctions in Denmark, Egypt, India, and the United Arab Emirates last year were all priced below both fossil-fuel and nuclear alternatives, and in its latest round Mexico established the lowest price yet for solar power. For a plant producing 8,000MW or more that’s a transformative difference that makes green hydrogen competitive with, or even cheaper than, gas-powered sources of energy.
By the same token, we can realistically expect the costs of electrolyser capacity to come down over the next decade or so. In addition to economies of scale derived from wider deployment, new materials for the electrolysers’ membrane process are being developed all the time. Whereas, each MW of electrolyser capacity currently costs around 1 million US dollars, there are hopes that the figure could halve by 2030 to bring down costs of whole cycle still further.
Niche or mainstream
Assuming that the costs of renewable energy and electrolysing plants continue on their downward path, what might be the additional uses for green hydrogen?
One of the more interesting ideas currently being discussed is that of the mine of the future. In many countries, like Australia, South Africa, and Chile, mines are often located in areas with abundant renewable energy. The limits of current renewable energy in transport mean that these mines are often dependent on billions of litres of diesel to power mobile plant within the mine and often for power generation. Green hydrogen and batteries could however provide the electricity storage for stability, and be used high-density transport fuel – with fuel cells being recharged by the movement of the haul trucks in and out of the mine in a closed-loop system.
Steel manufacture is another area where hydrogen could be used to reduce carbon emissions. Steel from iron ore is made by adding coking coal to reduce iron oxide to iron – producing CO2 as a by-product. However, by using hydrogen as the de-oxidising agent, steel manufacturers can reduce iron ore and create water as a by-product. Current trials in Germany are looking at this possibility.
But it is in areas such as chemical production that the greatest opportunities are likely to be found. Take ammonia: as we have seen it can be used as a transport vector for hydrogen. But greater value is likely come from ammonia as the chemical precursor to fertilisers. Instead of reforming natural gas to synthesise ammonia, manufacturers could take green hydrogen and combine it with nitrogen to create the end product and eliminate carbon-intensive gas as feedstock. This is a proven pathway and in fact how ammonia was produced in Norway before they found gas.
Once again, it is the electricity and electrolyser costs that make the difference. A world-scale ammonia plant produces around 2,000 tonnes of ammonia per day. This kind of plant has a high-level capital estimate of around $400 million. For the additional electrolyser plant to produce the green hydrogen, the capital cost is likely to be in the $700 million ballpark.
The plant requires one tonne of hydrogen to produce 5.7 tonnes of ammonia: that’s around 350 tonnes of hydrogen every day and significant amount of electricity. At current and projected prices of ammonia – assuming real prices steadily increase from less than $600 per tonne today to $660 per tonne in 2035 – the financial return is daunting. However, we can realistically expect capital and operational costs for electrolyser capacity to improve as the technology uptake increases and renewable energy prices fall. Not only would the volume of required electrolyser capacity come down, but so would overall electricity demand.
The next big thing?
Ammonia plants such as these also raise the question of whether a more distributed solution is possible instead of large centralised facilities. This would follow the decentralisation of electricity generation, and enable power production and consumption to be co-located, reducing transmission and distribution requirements.
We’re already seeing closed-loop systems using green hydrogen to power datacentre networks in the US, while Siemens in Mainz, Germany is using hydrogen to store energy in support of its own network.
This is just a relatively short overview of the potential of green hydrogen. There is plenty of room for further examination, modelling, and testing. There’s also plenty to be optimistic about. Developing the market further is a question of identifying the most promising niche applications with their limited commercial scope, applying the technology, refining and improving the process, and then moving on to the next, slightly more problematic application and repeat – constantly testing, learning and improving.
The potential is there. If a low-loss hydrogen carrier can be developed, hydrogen could become competitive not only with liquid fuels, but also with natural gas. If the costs of electrolyser plant come down – as we can realistically expect – then hydrogen could become a key part of a more decentralised energy network.
Equally, should renewable energy prices continue to fall, hydrogen may even become a future high-growth market – and fundamentally reshape the way we think about, plan and operate all kinds of industrial processes. It is certainly an area worthy of further exploration.
Phil O’Neil is the Senior Associate of New Energy at Advisian, a WorleyParsons company.
Drax advances biomass strategy with Pinnacle acquisition
The Group’s enlarged supply chain will have access to 4.9 million tonnes of operational capacity from 2022. Of this total, 2.9 million tonnes are available for Drax’s self-supply requirements in 2022, which will rise to 3.4 million tonnes in 2027.
The £424 million acquisition of the Canadian biomass pellet producer supports Drax' ambition to be carbon negative by 2030, using bioenergy with carbon capture and storage (BECCS) and will make a "significant contribution" in the UK cutting emissions by 78% by 2035 (click here).
This summer Drax will undertake maintenance on its CfD(2) biomass unit, including a high-pressure turbine upgrade to reduce maintenance costs and improve thermal efficiency, contributing to lower generation costs for Drax Power Station.
In March, Drax secured Capacity Market agreements for its hydro and pumped storage assets worth around £10 million for delivery October 2024-September 2025.
The limitations on BECCS are not technology but supply, with every gigatonne of CO2 stored per year requiring approximately 30-40 million hectares of BECCS feedstock, according to the Global CCS Institute. Nonetheless, BECCS should be seen as an essential complement to the required, wide-scale deployment of CCS to meet climate change targets, it concludes.