# Hydrogen Production from Offshore Wind Parks: Current Situation and Future Perspectives
## 5 State-of-the-Art Review
The lowest LCOH obtained was 2.49-2.74 \(\epsilon\)/kg for AEL (2.26-3.01 \(\epsilon\)/kg for PEMEL) with underground storage in a real-time pricing scheme in Ontario; this is competitive with hydrogen produced using Steam Methane Reform (SMR) with carbon capture, which is around 2.51-3.45 \(\epsilon\)/kg. A similar study on offshore hydrogen production with underground storage was developed by [PERSON] et al. [24], where the CAPEX and OPEX used were consistent with the forecast for offshore wind power and electrolyzers in the year 2030. The results show that for a 101.3 MW wind farm 15 km off the coast of Arklow, Ireland, at a selling price of 5 \(\epsilon\)/kg, the Discounted Payback Period (DPB), considering storage for 2, 7, 21, and 45 days of average hydrogen production, is 7.8, 8.6, 11.1, and 16.2 years, respectively. The wind potential in Patagonia is enormous, being anywhere from 4100 to 5200 full-load hours on average, which leads to an LCOE of electricity as low as 25.6 \(\epsilon\)/MWh. In 2018, [PERSON] et al. [44] analyzed a link between Japan and Patagonia, where hydrogen is produced and liquefied in Patagonia and shipped to Japan. The analysis estimated that the LCOH is 2.16 \(\epsilon\)/kg at the output of the electrolyzer, with an increase of 0.57 \(\epsilon\)/kg after transport to the shipping port and a further 0.58 \(\epsilon\)/kg to liquefy the hydrogen and store it in liquid form, which brings the final LCOH to 3.31 \(\epsilon\)/kg. The cost of transport to Japan is 1.13 \(\epsilon\)/kg, so the cost of hydrogen upon arrival in Japan is 4.44 \(\epsilon\)/kg. With the increasing presence of renewable energy in the grid, higher levels of curtailment in renewable power plants will take place. Considering this reasoning, a study was conducted to compare three scenarios using an offshore wind farm [45]: sell all electricity to the grid (scenario 1), convert all electricity to hydrogen (scenario 2), or a hybrid system where electricity is sold to the grid when prices are high and converted to hydrogen when curtailment occurs or electricity prices are low (scenario 3). A model was developed for a 504 MW wind farm located 14.5 km off the coast of Arklow, Ireland, and all three scenarios were simulated. The results obtained were an LCOE in scenario 1 of 38.1 \(\epsilon\)/MWh for 0% curtailment and 47.6 \(\epsilon\)/MWh for 20% curtailment, while the LCOH for scenario 2 was 3.77 \(\epsilon\)/kg. For scenario 3, if the hydrogen price was 4 \(\epsilon\)/kg, only at curtailment levels higher than 17% could adding hydrogen generation provide an equal or higher Net Present Value (NPV). If the hydrogen price was 4.25 \(\epsilon\)/kg, then the level of curtailment for which hydrogen generation becomes profitable is 10%. Another article comparing the three scenarios described above was written by [PERSON] et al. (2020) in 2020, where the model was developed for a wind farm in Denmark. Here, the electricity price for the first and third scenarios varied from 80 \(\epsilon\)/MWh to 160 \(\epsilon\)/MWh, depending on the time of day, with the hydrogen price fixed at 6.27 \(\epsilon\)/kg in the scenarios where hydrogen was produced. The article concluded that the hybrid approach yields greater economic interest compared to the other scenarios, with most of the hydrogen being produced at night when the electricity price is lower. A slightly different approach was taken by [PERSON] et al. (2020), where a 72 MW offshore wind farm was considered for the production of hydrogen, with two possible operating scenarios. In the first scenario, all of the energy was converted to hydrogen in an electrolyzer, stored, and then converted back to electricity in a fuel cell to sell to the grid during peak hours. In the second scenario, the electricity generated by the wind turbines could be sold to the grid or fed into an electrolyzer, with the possibility of buying energy from the grid when prices are extremely low. The electricity prices considered were the electricity prices for Denmark in 2015.