Benchmarking green hydrogen in India’s energy transition

This paper examines the economics of producing and using green hydrogen in India, focusing on the 2030 timeframe. Green hydrogen is intended to decarbonise ‘hard-to-abate’ industries, such as fertiliser and steel, and certain end-use applications in transport, such as shipping and long-distance road freight.
Green hydrogen is produced by the electrolysis of water using renewable or green electricity. In our analysis, we link green hydrogen production costs with the cost and availability of renewable energy (RE) generation, which is measured by its capacity utilisation factors (CUFs). We also calculate the premium, if any, of using green hydrogen compared to energy-basis equivalent costs of fossil fuels for a range of applications.
Green hydrogen is an emerging technology globally, and India plans to increase its domestic production from a few kilo-tonnes at present to five million tonnes per annum (Mtpa) by 2030. Currently, India produces about six Mtpa of hydrogen from fossil fuels (mostly by steam reforming of natural gas, i.e., grey hydrogen), which is used primarily for fertiliser production and oil refining. While the cost of green hydrogen is expected to decline in the coming years from its current range of four to six $/kg, it is unlikely to reach the oft-stated target of one $/kg by 2030 in India. Based on forward-looking assumptions about electrolyser efficiency, we estimate that the input cost of RE for green hydrogen production alone would be at least 1.4 $/kg in 2030 (even after factoring in rupee depreciation), which would be about two-thirds of the total production cost. Other costs include electrolyser capital expenditure (capex) and operation and maintenance (O&M) costs, including those of pure water supply. Incentives, such as a waiver of inter-state RE transmission charges and capital subsidies of up to 0.55 $/kg for green hydrogen production, under the National Green Hydrogen Mission of the Government of India, could potentially help bring the total costs under two $/kg.
Cheaper and more efficient electrolysers are important to lower the cost of green hydrogen production. Achieving high electrolyser utilisation (i.e., CUF) will be necessary for a faster payback of electrolyser capex (i.e., improved amortisation costs), which requires a steady supply of RE. There is an explicit trade-off between RE cost and CUF, and the most cost-effective RE supply is obtained from hybrid (wind plus solar) power plants with oversizing, i.e., a total RE generation capacity much larger than the nameplate capacity of the electrolyser. Based on high CUF solar and wind capacity, using 2019 actual RE output data for India as a benchmark, we find that the lowest cost of producing green hydrogen is achieved when the capacity of RE generation (with wind to solar in the ratio 2:1) is about twice that of the electrolyser, resulting in over 60% electrolyser CUF. If electrolyser capex is higher, a higher CUF will be required to achieve the lowest production cost.
Considering only the cost of green hydrogen production, however, ignores the costs associated with handling, storing, transporting, and using hydrogen, which are significant compared to other fossil fuels due to the low volumetric energy density and high chemical reactivity of hydrogen.
To determine the cost-efficiency of replacing fossil fuels with green hydrogen, we suggest using the marginal cost of CO2 abatement ($/tonne-CO2), which considers end-use efficiency and the carbon-intensity of alternative fuels, as a more useful metric than $/kg-H2. We calculate abatement costs for the most commonly referred end-uses of green hydrogen: steelmaking, fertiliser, oil refining, transport, and heating/cooking. Even at an optimistic price of two $/ kg-H2 in 2030, we find that abatement costs across applications range between 70–175 $/tonne-CO2, depending on whether green hydrogen displaces inexpensive but carbon-intensive domestic coal or price-controlled natural gas in India. This is very high compared to alternative abatement options, particularly electrification. It is also important to note here the significant effect of energy taxes on fuel costs.
Decarbonisation by displacing coal-based electricity with RE in the grid is more cost-effective (i.e., has a lower marginal cost of CO2 abatement) than displacing other fossil fuels elsewhere with green hydrogen, some of which are less carbon-intensive than coal (e.g., natural gas). Direct electrification of possible end-uses will also result in higher system efficiency due to reduced conversion losses (for instance, battery electric vehicles have a much higher roundtrip efficiency than hydrogen fuel-cell vehicles). This is a crucial consideration, as the production of the targeted five Mtpa of green hydrogen will require 115 GW of dedicated RE capacity (under optimistic technology assumptions). Integration of RE into the grid and electrification of all viable end-uses in transport and industrial heating should, therefore, be prioritised as a more cost-efficient mitigation option.
In the medium-to-long term, green hydrogen will be needed to decarbonise sectors where alternative solutions are unlikely to be available, such as fertilisers, steelmaking, and refining—all of which use fossil fuels as chemical feedstocks. This will also reduce dependence on the import of natural gas and coking coal in the future. In the short term, we suggest promoting the use of green hydrogen in applications with relatively low marginal abatement costs, such as oil refining, as a steppingstone towards developing a green hydrogen ecosystem in India. In oil refining, switching to green hydrogen would not require significant changes in downstream processes and is, therefore, less capital-intensive compared to other processes, such as Haber-Bosch synthesis for fertilisers or iron ore reduction for steel.
Finally, we emphasise that defining the conditions for green electricity is essential to ensure that green hydrogen and its derivatives, thus produced, have low or zero carbon emissions. This is especially important if the products are to meet international emission standards. Current green hydrogen standards in India allow electricity banking with the electricity distribution company (DisCom) for up to 30 days, where an RE generator can overproduce RE at some times of the day and feed it into the grid and reclaim it from the DisCom when RE is not available. This means that some of the electricity consumed for electrolysis may not actually come from renewable sources, and the hydrogen so produced may have significant carbon emissions. The conditions to define green, hence, should be based on the additionality, deliverability, and timing of the RE supply. This is key to determining the cost and availability of RE, which disproportionately affects the cost of green hydrogen production and, thus, the cost of decarbonisation.
This paper can be accessed here.
This paper is authored by Rahul Tongia, senior fellow and Utkarsh Patel, visiting associate fellow, CSEP. New Delhi.