The world’s commitment to hydrogen needs an assessment of which regions can make it the cheapest. Herib Blanco at IRENA and Jacopo de Maigret at Fondazione Bruno Kessler describe their study of the range of factors that affect the future cost and therefore the potential for clean renewable hydrogen, estimated for 2030 and 2050. The main drivers are the capital cost of the renewable generation and the electrolyser, the cost of capital, and the full load operating hours in a year. They will be different for different parts of the world. Constraints include land and water availability. The estimates of future costs per kgH₂ are boiled down to a colour-coded map of the globe. For regions wanting to understand their own potential for future hydrogen production, this study can be a starting point.

One of the main barriers for renewable hydrogen is its higher cost when compared to other low-carbon technologies. The main parameters defining the cost of renewable hydrogen are the capital cost of the renewable generation and the electrolyser; the cost of capital; and the full load operating hours in a year.

From these, the main cost driver is the electricity input which can constitute 60-80% (depending on the other parameters) of the total production cost. Renewable hydrogen is today in the range of USD 3-5/kgH₂. The levers reducing this cost are making the modules larger and scaling-up manufacturing (economies of scale), increasing the global scale of deployment (learning by doing), and innovation to improve the technology (e.g. efficiency of the electrolyser).

The other main factor for renewable hydrogen is its potential. Most countries have renewable energy in one form or another, but given land availability constraints and high population density, some countries might not have enough to satisfy their entire energy needs domestically or at least they would be able to satisfy them more cheaply if imports are considered.

A recent IRENA report explores these two aspects for various time horizons (2030 and 2050) and scenarios (considering low and high technology costs). An online dashboard also allows exploring the cost of every (1×1 km) area in the world across multiple scenarios.

Land availability for powering Hydrogen production

The analysis considers the land available for solar PV and onshore wind considering several exclusion criteria like protected areas, forests, permanent wetlands, croplands, urban areas, slope ( >5% [PV] and >20% [onshore wind]), population density and water stress with a resolution of 1×1 km. Figure 1 shows the fraction of land that is eligible for renewable technologies for selected countries. When considering green hydrogen production, this fraction is further reduced due to water stress constraints.

Potential is 20 times what we need

Using this approach, the global green hydrogen technical potential is almost 20 times the estimated global primary energy demand in 2050.

…but some countries are better suited than others

While global green hydrogen potential is more than enough, there are specific countries where potential is restricted. Due to the nature of their territory, Japan and the Republic of Korea are the most restricted: 91% and 87% of the country land respectively is excluded for hydrogen production. Furthermore, the quality of the resources is relatively poor (a capacity factor lower than 14% for the majority of PV and lower than 30% for wind) and most of this scarce potential is used to satisfy electricity demand rather than hydrogen. Other countries that would require a relatively high share of their renewable potential to satisfy their domestic hydrogen demand are India (89% of the land is excluded mainly due to population density, cropland, savannahs and forests); Germany (66% excluded mainly by forests and cropland); Italy (62% excluded mainly due to slope, population density and croplands); and Saudi Arabia (94% excluded mainly due to water stress).

Calculating the LCOH

The hydrogen production cost is determined by optimising the configuration (i.e. capacities for solar PV, onshore wind, and the electrolyser) for each (1×1 km) cell considering the specific hourly profiles and resource quality. Figure 2 shows the relationship between levelised cost of hydrogen (LCOH) and the optimal capacity ratios between generation and electrolysis for different resource qualities.

Based on Figure 2, the lower the quality of the resource (i.e. lower number of full load operating hours in a year), the higher the optimal capacity ratio between generation and electrolysis is. This effect is more pronounced for solar PV, which can reach capacity ratios of two for poor quality solar resource (annual PV capacity factor of 10%). This leads to a very wide capacity ratio of generation to electrolysis for solar PV (1.3 to 2.15) whereas for onshore wind, the range is narrower (1.15 to 1.5).

At the same time, the cost curve for a good quality resource is relatively flat so even with a sub-optimal capacity ratio the cost penalty is small (for both onshore wind and solar PV). The land eligibility assessment criteria might in some cases coincide for both solar PV and onshore wind giving way to hybrid hydrogen generation systems. Following the same philosophy of the single-technology hydrogen generation system, optimal ratios exist among the capacities of the three system components that ensure the lowest LCOH, given the local solar and wind resources and regional techno-economic assumptions. This optimisation approach allows calculating the LCOH for every point in the world resulting in the costs in Figure 3.

Costs and potential are not absolute numbers for each country, instead they are a continuous relationship between cost and renewable capacity. As the best sites are used, the average capacity factor decreases, and correspondingly the cost increases until all the land available is used (Figure 4 shows this behavior for selected African countries).

Lower costs by 2050

By 2050, several drivers could lead to low hydrogen production costs. Economies of scale, learning from global deployment and innovation can lead to lower electrolyser costs, but more importantly global renewables deployment could lead to lower electricity costs, in particular for solar PV. In a future where almost 14 TW of solar PV, 6 TW of onshore wind and 4-5 TW of electrolysis are deployed, hydrogen production costs can reach levels below USD 1/kgH₂ for most countries in the most optimistic scenario. In a less optimistic scenario with higher technology costs, still for 2050, most countries have access to costs below USD 1.5/kgH₂.

The uncertainties in these costs are a potential slowdown of the cost decrease for renewable energy and electrolysis (i.e. a lower learning rate). This could be because of supply chain constraints, higher commodity prices, inflation (as experienced across the world in 2021-2022). Another key uncertainty is the floor costs for renewable energy and electrolysis (i.e. the minimum capital cost that they can reach even with large cumulative capacities deployed). Lastly, the cost of capital is also a determining factor since it is all based on infrastructure and there are limited running costs and no fuel. The long-term cost will depend on how those parameters evolve over time and their difference across countries. Regarding potential, this analysis estimates technical potential which needs to be further reduced by aspects such as social acceptance, proximity to existing infrastructure, costs of accessing remote locations, among others which might result in further countries facing supply challenges.

This work is part of a series of IRENA reports looking at global hydrogen trade. The other two parts look at: technoeconomic assessment of hydrogen transport at large scale; demand, a scenario for 2050, and enabling actions for the coming ten years.

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Herib Blanco is an expert on Hydrogen Energy and Power to X at IRENA

Jacopo de Maigret is a Researcher at Fondazione Bruno Kessler