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| Fig. 1: Comparison of Backup Electricity from various sources. [10] (Image Source: N. Mishra) |
The cheapest and most commonly deployed renewables (wind and solar) are inherently intermittent- their energy generation varies throughout the day. Their generation profile doesn't necessarily match with the consumption profile of grid loads. An example of this mismatch is California's infamous Duck Curve. [1] A potential solution to this problem is deferring the dispatchment of renewable electricity on to the grid by storing them in different forms such as electrochemical batteries or pumped-hydro. [2] Another solution that is now being frequently talked about is hydrogen storage. As opposed to battery and mechanical/thermal storage, it is proposed that hydrogen can be produced with excess renewable electricity through electrolysers and stored for deferred dispatchment. [3] Arguments are made that while batteries are economically infeasible for grid scale storage, and there are very limited locations available for pumped-hydro storage, long duration storage can be achieved using hydrogen. [3,4] In this article, we take a look at the costs associated with storing electricity in the form of hydrogen across compressed and liquified states. We shall also compare this cost with the levelized cost of Energy from resources that are presently used as peaking plants.
The cost of hydrogen storage for grid backup is influenced by several factors, including the production method, storage technology, and infrastructure requirements. First, we take a look at the production cost of green hydrogen from green electricity. Hydrogen produced through electrolysis requires electrolysers. There is a huge variability in the cost of green hydrogen as it depends on the source of the green electricity used for the hydrogen. This cost has been reported to be between $4-6 kg-1. [5] We will assume the lower bound of $4 kg-1 for our calculation. We can convert this to a $/Joule figure using the Lower Heating Value (LHV) of Hydrogen, which is reported as 1.21 × 108 J kg-1. [6]
| TCO | = | $4 kg-1 1.21 × 108 J kg-1 |
= | $3.31 × 10-8 J-1 |
Compressed Storage: Compressed storage is the most mature hydrogen storage technology today. [7] Compressed hydrogen can be stored in salt caverns or special metallic pressure vessels such as tanks. Due to the limited availability and geographical constraints of salt caverns, we will only consider tank storage for this calculation, where hydrogen is compressed at 700 bar. The estimated levelized cost of storage (LCOS) using this technology is $1.73 kg-1 of H2 (note that the currency conversion was performed referencing the average exchange rate of the GBP and USD in 2023, ie. 1 GBP = 1.24 USD). [8] This figure includes the cost of compression and storage as well as the costs of equipment required to perform various processes involved in compression of hydrogen. The LCOS can be converted to a $/Joule figure as follows:
| LCOS (Compressed) | = | $1.73 kg-1 1.21 × 108J kg-1 |
= | $1.43 × 10-8 J-1 |
Liquified Storage: Liquified storage is often used to increase the volumetric energy density of hydrogen, in place where storage space is a constraint. It also involves much more energy for conversion given the temperature at which hydrogen liquifies. However, since the volume of hydrogen is much less, the capital required in terms of land acquisition and tanks for storage are significantly lower, meaning the overall costs of compression and liquefaction are competitive. The same report estimates the LCOS for liquified H2 to be $1.73 kg-1 of H2. [8] This means that LCOS for energy in the form of liquified hydrogen is $1.43 × 10-8 J-1.
There are two primary ways by which electricity can be generated from hydrogen-fuel cells or turbines. However, there are no reliable data on turbines producing electricity from combusted hydrogen, so we will focus on fuel cell efficiencies alone. We will take as an example the Hanwha Daesan plant in Seosan, South Korea, which has a plant production cost of $4.20 W-1. Assuming the OPEX of the fuel cell to be similar to that of a natural gas plant, we can calculate this to be around $0.042 W-1. [6,9] This means that the total amortised cost of a fuel cell with 60% efficiency run over 60,000 cycles would be
| TCO | = | 4.242 W-1 0.6 × 60000 cycle hrs × 3600 sec hr-1 |
= | $3.27 × 10-8 J-1 |
The total cost of ownership of our system would therefore come to be
| TCO | = | $3.31 × 10-8 J-1 + $1.43 × 10-8 + $3.27 × 10-8 J-1 | = | $8.01 × 10-8 J-1 |
Converting to MWh, we obtain
| TCO | = | $8.01 × 10-8 J-1 × 3.6 × 109 J MWh-1 | = | $288.21 MWh-1 |
Fig. 1 shows the additional price per MWh above the existing electricity price, that would be paid to maintain grid reliability at times when backup is needed. This figure does not include a realistic cost of electricity that went into producing the hydrogen from the electrolyzer, which could range from $50-$70 MWh-1, making hydrogen more expensive (>$6 kg-1), therefore increasing the total cost of storage even further. [5] These calculations also assume no losses in the process of storage of hydrogen. With the best case-assumptions, the price for stored electricity would be nearly 5-7 times the price of electricity dispatched in business-as-is scenarios. Fig. 1 also shows the cost of electricity from other dispatchable sources to the total cost of electricity from hydrogen storage to give a better picture of why hydrogen storage has not yet become feasible.
© Naman Mishra. The author warrants that the work is the author's own and that Stanford University provided no input other than typesetting and referencing guidelines. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.
[1] M. Burnett, "Energy Storage and the California 'Duck Curve'," Physics 240, Stanford University, Fall 2015.
[2] P. Denholm et al., "Overgeneration from Solar Energy in California: A Field Guide to the Duck Chart," U.S. National Renewable Energy Laboratory, NREL/TP-6A20-65023, November 2015.
[3] M. Melaina and J. Eichman, "Hydrogen Energy Storage: Grid and Transportation Services," U.S. National Renewable Energy Laboratory, NREL/TP-5400-62518, February 2015.
[4] "Utility-Scale Batteries," International Renewable Energy Agency, 2019.
[5] "Making the Breakthrough: Green Hydrogen Policies and Technology Costs", International Renewable Energy Agency, 2021.
[6] R. B. Laughlin and S. W. Freund, "Economics of Hydrogen Fuel," in Machinery and Energy Systems for the Hydrogen Economy, ed. by K. Brun and GT. Allison (Elsevier, 2022).
[7] C. Martnez de León et al., "Levelized Cost of Storage (LCOS) For a Hydrogen System," Int. J. Hydrogen Energy 52A, 12274 (2024).
[8] "Hydrogen Transport and Storage Cost Report," U.K. Department for Energy Security and Net Zero, December 2023.
[9] "Capital Cost and Performance Characteristics for Utility-Scale Electric Power Generating Technologies," U.S. Energy Information Administration, January 2024.
[10] "Levelized Costs of New Generation Resources in the Annual Energy Outlook 2022," U.S. Energy Information Administration, March 2022.