Weekend read: The changing geopolitics of green hydrogen
Francesco La Camera, the director general of the International Renewable Energy Agency (IRENA), believes that renewable energy is the only way we can effectively transform today’s energy system to reach climate goals. Renewables build resilience and avoid energy price shocks, ensure compatibility with the Paris Agreement, and ensure an energy system that is fair. Alongside renewables, hydrogen will play a significant role in decarbonisation. “Renewables are the only technologies that can get us to our targets, complemented by green hydrogen, although blue hydrogen will play a role,” he said. IRENA projections to 2050 have two-thirds of hydrogen as green and one-third as blue.
The shift from fossil-fuel dependence to a model of renewable energy and green hydrogen is going to remake economic, political, and energy relationships around the world. The development of a global hydrogen market could regionalise energy relations in a similar vein to renewables, feeding into changing power dynamics. This is the message of the latest analysis from the International Renewable Energy Agency (IRENA), with the publication of its latest report, “Geopolitics of the Energy Transformation: The Hydrogen Factor.”
The report projects that hydrogen could cover up to 12% of global energy consumption in 2050. Over 30 countries and regions are already actively planning for a hydrogen future, and by 2050 IRENA believes that 30% of hydrogen could be traded across borders – more than the current cross-border trade in natural gas. Replacing and decarbonising existing grey hydrogen demand of around 71 million to 120 million tonnes per year (including on-site production and consumption) with green hydrogen as a key driver behind market activity. Rising natural gas prices are having an impact, as that’s the biggest input for both grey and blue hydrogen. But it is the use of hydrogen generated from renewable energy that’s a potential game changer.
Green hydrogen can be used within the electricity system, for the decarbonisation of hard-to-abate sectors, for long-term seasonal and regional storage, and as a base for other alternative fuel solutions. This is nothing new – the “hydrogen economy” has been part of the debate for decades. “What is new is decarbonisation applications and related innovations and how they can be applied,” said Elizabeth Press, director of planning and program support at IRENA, and a co-author of the report.
There are two different but potentially complementary visions for the future of the hydrogen market. The first is that those economies that have created wealth through the export of hydrocarbons will replace part of that income with clean energy, building large scale centralised production, using the best renewable sources to bring the cost down. As a useful approach to diversifying their economies, countries like Australia, Oman, Saudi Arabia and the United Arab Emirates are already making commitments to green hydrogen.
The second vision is that new centres of production could spring up in places where there is high technical potential for renewable energy and, of course, water. Countries with an abundance of low-cost renewable power could become producers of green hydrogen, with significant geo-economic and geopolitical consequences. “The versatility of hydrogen is that you can decentralise everything,” said Manuel Kuehn, head of new energy for MEA at Siemens Energy.
Those countries with significant renewables potential could become sites of green industrialisation, using their potential to attract energy-intensive industries.
China, Japan and Europe have already developed a head start in production, and Chile has announced a national strategy to become a green hydrogen exporter by 2040. Europe is likely to become a major importer, and European additionality rules mean that renewable energy used for electrolysis must be additional to that used in power generation.
According to Press, the important thing to do is prioritise. “Where electrification is reasonable, rather than go to another carrier and then decarbonise, you should electrify,” she said. The important point is that in the early days it’s necessary to create the market. “You should focus on applications that centralise [to take advantage of infrastructure and create demand] and those that don’t have alternatives … focus should be targeted towards those applications where the climate imperative demands it,” Press added.
Robin Baillie, partner at Crowell & Moring’s energy practice, said that “this is primarily a question of numbers. There is virtually no green hydrogen produced at scale at the moment (less than 1%), however, adding carbon capture technology to existing hydrogen infrastructure (which is virtually all grey) is a quick win and would enable roughly 80% to 90% of the CO2 produced to be captured and either used elsewhere or sequestrated.”
Another argument about the use of green hydrogen is efficiency and the power cycle losses in its transformation. Hydrogen is not an energy source, but an energy carrier, and its generation, transportation and transformation carry heavy energy penalties. Baillie believes that given the low cost of renewables, this isn’t necessarily a problem.
“Conversion losses lose impact once a wide-scale adoption in both production and storage becomes established,” said Baillie. “Longer term it is possible to generate electricity from hydrogen and indeed companies such as Siemens and GE have developed turbines that can run on hydrogen.”
Chris Jackson, chief executive at Protium Energy, said that the issue isn’t as simple as energy efficiency. Rather, he suggests that the focus should be on the efficient use of resources. The amount of land and rare earth metals required for batteries to balance the grid could lead to far greater waste than the efficiency losses in transforming hydrogen. Of course, the question for the green hydrogen market is when, not if, it’s going to become cost competitive. Harry Morgan, senior analyst at Rethink Energy, thinks it should be cost competitive within two years.
As production of hydrogen from electrolysers comes down the cost curve, it should present new supply opportunities and other essential services such as managing the grid when there is excess renewable energy. Morgan believes that economies of scale will reduce the cost of electrolysers more than 85% by 2030 to $340 per kW, a faster fall in price than predicted by many. He points to the history of the PV market in terms of cost curve expectations and argues that while individual component prices may have seen recent spikes due to supply chain issues, there is little overall growth in project cost.
Morgan sees the learning rate (how much the cost per unit falls on a doubling of global manufacturing capacity) of building out production capacity at around 14% – in context, the learning rate of solar has been 23%. Global pipelines for projects and electrolyser production facilities have seen four-figure growth recently, with 35GW of electrolyser capacity in gigafactory announcements alone in the past 18 months. In just a few years electrolyser capex per kg has fallen to $1,400 today from $600,000 at NASA in the 1960s. Projections of $200 per kW are no longer considered extraordinary.
As of January 2022, 26 countries have national hydrogen strategies in place, of which half were launched in the past year and many include electrolyser capacity targets. The hydrogen market is going to have an impact on the energy system, affecting everything from geopolitics to the development of solar PV.
“The role of hydrogen is dwarfed by the role of direct electricity in the 2050 scenario,” said Dolf Gielen, director of the IRENA Innovation and Technology Centre. “It’s four to five times as important as hydrogen.”
For hydrogen to constitute 12% of the energy market in the scenarios, two-thirds are set to be provided by 4TW to 5TW of electrolysers needing 8TW to 10TW of renewable electricity, or three times the renewable capacity installed today.
|Type of hydrogen production||Method|
|Black hydrogen||This process generates just a smaller amount of emissions than black or brown hydrogen, which uses black (bituminous) or brown (lignite) coal in the hydrogen-making process. No CO2 capture.|
|Grey||Generated through steam reforming of natural gas or methane. No CO2 capture.|
|No colour yet assigned. Can be considered either grey or blue dependent on process||Biomass or waste gasification, sometimes used with carbon capture and storage|
|Blue||Stream methane reforming (SMR) with CCS – where the carbon generated from steam reforming is captured and stored underground through industrial carbon capture and storage (CSS). Although 10-20% of generated carbon cannot be captured|
|Turquoise||Methane pyrolysis resulting in hydrogen and solid CO2. No need for CCS and the solid carbon can be used as a product|
|Green||Renewable electricity used to split water using electrolysis, hydrogen captured from the reaction|
|Yellow||Solar energy used to split water using electrolysis, hydrogen captured from the reaction|
|Pink||Nuclear power used to split water using electrolysis, hydrogen captured from the reaction|
Author: Felicia Jackson
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