Floating offshore wind projects development in South Korea without government subsidies

The S. Korean government is committed to gradually eliminating coal and nuclear from the country's energy mix and advancing the nation's green energy transition by raising the percentage of renewable energy sources to 20% by 2030 and to 30–35% by 2040. As of 2020, the domestic wind power generation capacity is 1.64 GW (KWEIA n.d.). Although the capacity of offshore wind power is 142 MW, and that of offshore wind power in commercial operations is 124 MW (MOTIE 2021a), local governments and private business operators are actively developing offshore wind power generation projects, such as floating offshore wind power in Shinan, Jeollanam-do, the Southwestern region of Jeollabuk-do and the Southeastern region of Ulsan. As of August 2021, 43 projects have received licenses and business permits to engage in power generation, amounting to a capacity of approximately 9.6 GW (MOTIE 2021a). Furthermore, based on South Korea’s RE3020, which aims to achieve a 20% proportion of renewable energy generation by 2030, as well as the 3rd Energy Masterplan prescribing a 30–35% proportion by 2040, this industry will continue to expand in the future (MOTIE 2019b).

Ulsan, which faces the East Sea to the east, is a representative industrial city in South Korea. The East Sea is characterized by a wide continental shelf with a water depth of 100 to 200 m, exposed to the wind with an average annual wind speed of 8 m/s or more (Ulsan Metropolitan City 2021b). Moreover, due to its geographical conditions, the city is home to shipbuilding and offshore plant companies in addition to substantial human resources. Because the offshore wind power sector can converge with shipbuilding and marine technology, Ulsan is promoting its administrative target of launching the first floating offshore wind power generation complex in South Korea. By 2030, the world's largest floating offshore wind farm with a capacity of 6 GW will be built offshore of Ulsan (Ulsan Metropolitan City 2021a).

In general, it should be stressed that most offshore development is happening on the western side of the country due to higher electricity demand since most country’s major cities are located on the western part of the country and the wind power penetration will be easier compared to being focused on the  east side of the country and then having to transfer all the generated electricity to the west. However, since some large cities exist in the southeast part of the country, there are also offshore developments lately on this side.

The South Korean government selected the hydrogen economy as one of three strategic investment areas in August 2018 and announced the establishment of the Hydrogen Economy Roadmap in 2019 (Lee & Kim 2021). This roadmap contains macroscopic policy directions, goals, and promotional strategies for revitalizing the hydrogen economy by 2040 (Stangarone 2021). Regarding offshore wind power, the government plans to secure water electrolysis technology linked to MW-level renewable energy plants by 2022 and to mass-produce green hydrogen by linking it with large-scale solar and wind power generation (Zou et al. 2022). As seen in Fig. 3, the government aims to increase hydrogen production from 130,000 tons in 2018 to 5.26 million tons in 2040, providing a stable supply of a substantial amount of green hydrogen to induce a drop in the hydrogen price below 3,000 KRW/kg (MOTIE 2019a).

The governments of major countries have subsidized the new renewable energy industry to foster its development (Celsa & Xydis 2023). Beginning in 2015, many countries started introducing the auction system, as the yield of renewable energy production rapidly increases, and the financial burden becomes intolerable (IRENA 2015). In response to the changing policy environment, the wind turbine industry is moving in the direction of reducing development costs and enhancing power generation efficiency by scaling up wind turbines (Shields et al. 2021).

This trend of increasing turbine capacity will continue (Wiser et al. 2016). The industry currently plans to develop a large turbine with a capacity of 15–17 MW by 2025, and the development of an offshore wind turbine with a capacity of 20 MW is further expected (GWEC 2021b). The CapEx per MW for these large-scale turbines will increase, while the LCoE will decrease, as the yield of power generation increases due to high power generation efficiency and the cost required for the foundation structure or its installation decreases. The OpEx will further decrease due to improved reliability and ease of maintenance, resulting in a reduction in LCoE (COWI 2021).

Figure 4 shows the basic SLD for the project in the paper. As is indicated, the electricity produced by the wind turbine generators is connected with 66 kV AC offshore cables to the offshore substation where 66 kV/220 kV AC transformers are placed. The electricity is then transferred to the national grid through the transition joint bay, onshore substation, and common grid connection facility. The main purpose of TJB is to connect offshore cables with onshore cables. The onshore substation serves as an electrical interface point of the wind farm to the national grid system. It includes different electrical equipment such as 220 kV/345 kV AC main transformers, gas insulated switchgears, reactors, etc. Finally, CGCF is a changing station where different developers can connect their wind farm systems before sending the produced power to the national grid system.

There are no large-scale floating offshore wind farms in operation in South Korea. The collection of projects known as Korea Floating Wind (KFWind), with expected power generation capacity of 1300 MW, will be located off the coast of Ulsan City, taking into account the wind resource potentials of the east side of the country. The anticipated year of the final investment decision is 2025, while two years later the start of the commercial operations is expected. Thus, assuming project information, this study utilized the information available in the South Korean market, while applying some parameters obtained from overseas floating offshore wind farms and research results to the South Korean market. Table 1 indicates the assumed project parameters for the study in the paper.

The capacity of the offshore wind farm was selected accordingly because the publicly available capacity for a potential supplier to apply for the selection of a competitive bidder for a fixed price contract of wind power is 550,000 kW (KEA 2022b), and because the capacity of a bank of 345 kV, which is mainly used in South Korea, is 500 MVA. Currently, Vestas' V235 model has a 15-MW (Vestas, n.d.) WTG for floating offshore wind farm, and the total capacity of the floating offshore wind farm when the above 33 units of models becomes 495 MW.

Linkage distance refers to the straight-line distance between the coastline and the central position of the wind generator closest to the coastline (MOTIE 2021b). The water depth refers to the depth of the basic level surface to sea level of the wind farm where the floating WTG is installed (MOTIE 2021b). However, when several WTGs are installed in one offshore wind power plant, a weight is applied to the average depth of the WTGs (MOTIE 2021b). For the location of the floating offshore wind farm, the linkage distance and water depth were assumed by referring to the locations of the actual projects that are currently under development in the East Sea near Ulsan.

The CapEx cost was calculated under the subcategories of electrical cost and civil cost, and the price suitable for the South Korean market was calculated by referring to the 2022 standard unit price for the construction sector budget provided by the KEPCO. Additionally, the WTG price, OpEx, DevEx and AbEx were calculated based on the information obtained from overseas floating offshore wind power plants and the reports from overseas consulting companies. The Net capacity factor includes the gross capacity factor, wake loss, line loss and availability of the plant. This study selected the capacity of the hydrogen electrolyser and the wind power generation according to the curtailment rate, and further details are provided in Results and analysis.

The information provided by the Korean government was used for the issues related to taxation and financing. The cost for the green hydrogen project was calculated based on the hydrogen-related reports published by IRENA in the last three years. This study assumed that the PEM electrolyser was installed at sea. Moreover, because the produced hydrogen was assumed to be stored and transported domestically or abroad via a vessel, the transport price provided in Table 1 refers to the price of the hydrogen stored as ammonia and transported via a vessel. In addition, under the assumption that the electrolyser can be operated for an average of 8 h a day, the capacity factor of the PEM electrolyser becomes approximately 33%.

The NPV provides a comparative way to evaluate capital or financial products based on their current cash flows and is given by the formula (Eq. (1)) (Ucal and Xydis 2020):where R_t net cash flow (inflow-outflows) in year t., r discount rate, t year of the cash flow.

The IRR index is another way to assess the viability of future investments. The scope is to identify the rate by which the investor will get their capital back, and it is calculated via the formula (Eq. (2)):where C_t net Cash inflow in year t., C_o total capital cost, r internal rate of return.

The LCoE is calculated based on Equation (Eq. (3)) (Lai and McCulloch 2017):where I_t investment expenditures in year t, M_t operations and Maintenance expenditures in year t, E_t  electricity generation in year t, r discount rate, n life of the wind turbine systems.

The PPA is a system, in which a power producer of renewable energies selected through competitive bidding concludes a contract to supply RECs at a fixed price for 20 years with a potential supplier of RPS. While participating in fixed price bidding, the bidding price must be the sum of the SMP and REC costs. Thus, the revenue of a power plant can be said to be the sum of the electricity sales revenue and the REC sales revenue (KEA 2022a).

The PPA is calculated as Eq. (4) (KEA 2022b):

The REC is a certificate that verifies that a potential supplier has produced and supplied by utilizing new renewable energy facilities, in which the submission of 1 REC is considered to be an implementation performance of 1 MWh. The amount of REC issuance is calculated using Eq. (5) (KEA 2022b), and the REC weight is largely determined by the energy source, installation type and capacity. Table 2 indicates the applicable Basic REC weights to offshore wind only. The method for calculating compound weights is discussed in detail in 3.8. REC Weight Calculation for Offshore Wind.

The REC is calculated as Eq. (5). If a monthly SMP exceeds a fixed price, REC price is applied to ‘0’ (KEA 2022b).:

The fixed price is calculated as Eq. (6) (KEA 2022b):

REC weight is calculated based on Eq. (7) (MOTIE 2021b):where Weight_B  basic REC weight, Weight_Distance REC Weight according to grid connection distance, Weight_Depth REC Weight according to the depth of water, Weight_Distance is calculated based on the equations below:

According to the formula for calculating the compound weight of the offshore wind power linkage distance and water depth proposed by the Korean government as of September 2022, the maximum linkage distance standard and the maximum water depth were designated as “more than 15 km,” and “more than 30 m,” respectively. However, because the limit of the maximum compound weight value is not specified, the total offshore wind power REC weight increased as the length of the linkage increased, and the water depth increased. Thus, this study calculated a REC weight of 4.6 based on a linkage distance of 70 km and a water depth of 150 m, as well as a REC weight of 3.7 based on a linkage distance of 15 km and a water depth of 30 m, according to the project assumptions. Additionally, this study calculated the SMP1 + REC price, LCoE and IRR depending on the varied REC weight by reducing the REC weight from 3.7 to 0.5 at a certain rate. Furthermore, when there was no REC weight, the SMP1 + REC price, LCoE and IRR were calculated by dividing the operating period of the wind farms into 20 and 30 years.

As shown in Fig. 5, when a REC weight of 4.6 is given, the SMP + 1 REC was USD 397.46, which is approximately 5.7 times higher than the monthly SMP (USD 69.84) with an estimated IRR of 27.45%. As the REC weight decreased, the SMP + 1 REC and IRR decreased. However, because the IRR value with a REC weight of 0.9 is 7.12%, power producers can make profits from the business (Tables 3, 4, 5, 6).

When the REC weight was not applied, the SMP + 1 REC decreased from 107.13 to 70.39 USD/MWh, whereas the IRR decreased significantly from 3.92 to − 1.42%. Despite the change in the REC weight, there was no change in the LCoE value. However, when the operating period of the wind power plant was increased from 20 to 30 years, the LCoE decreased from 129.1 to 114.67 USD/MWh, and the IRR slightly increased from − 1.42 to 2.24%, which is insufficient for power producers to achieve the expected profit.

Would the utilization of the electricity wasted owing to curtailment of the offshore wind plant increase the overall profitability if the electricity is used to produce hydrogen through the PEM electrolyser? Figures 6 and 7 show the changes in the LCoE and IRR of the floating offshore wind farms according to the capacity of the PEM electrolyser when the operating period of the power plant was 20 and 30 years. The capacity of the PEM electrolyser varies depending on the curtailment rate of offshore wind power farms. In this case, as the curtailment rate increased, the amount of electricity generated through offshore wind power decreased, and the amount of hydrogen produced through the electrolyser increased. As shown in Fig. 6 when the curtailment rate was increased from 2 to 51% and the operating period of the power plant is 20 years, the capacity of the PEM electrolyser increased from 4 to 100 MW. Additionally, at a curtailment rate of 2%, the annual electricity output of offshore wind power generation was 1,679,785 MWh, whereas with an increase in the curtailment rate to 51%, the output reduced to 839, 982 MWh which decreased in the same ratio as the curtailment rate. Moreover, as the hydrogen production increased, the LCoE continuously increased (129.57 to 184.72 USD/MWh), whereas the IRR exhibited a decreasing trend (− 1.59 to − 5.89%).

A similar trend was also observed when the operating period of the offshore wind power plant was assumed to be 30 years. As the curtailment rate and hydrogen production increased, the IRR decreased and the LCoE increased. At a curtailment rate of 2%, the IRR was 2.11%, but shifts to a negative value (− 0.42%) with an increase in the curtailment rate to 40%. In addition, with an increase in hydrogen production, the LCoE increased from 115.10 USD/MWh. This value is higher than the LCoE of 114.67 USD/MWh when operating offshore wind power for 30 years without government support.

According to the data on the annual curtailment of wind power generation in Jeju Island, a curtailment of 3.36% occurred in the first half of 2020 (KPX 2020). The frequency of curtailment will increase as the ratio of electricity obtained from renewable energy increases. Thus, the annual power generation, hydrogen production and LCoH at curtailment rates of 2 and 10% were compared. When the curtailment rate of the wind farm is approximately 2%, a 4-MW PEM electrolyser can be installed. Under this condition, approximately 197,019 kg H₂ of hydrogen per year was produced while a production of annual electricity by wind power generation was 1,679,785 MWh. When the curtailment rate was approximately 10%, a PEM electrolyser of 20 MW can be installed. Accordingly, the annual hydrogen produced under this condition amounts to approximately 985,095 kg H₂ while a production of annual electricity by wind power generation was 1,542,659 MWh. When 4-MW and 20-MW electrolysers are installed, the LCoH at 20 and 30 years of operation is 3.17 and 2.62 USD/kg H₂, respectively, indicating that there was no significant difference in the LCoH under both conditions. If a 100-MW electrolyser is installed, the LCoH at 20 and 30 years of operation will be 3.14 and 2.60 USD/kg H₂, respectively, which is not significantly different from those under 4-MW and 20-MW conditions. This could be attributed to the fact that the capacity of the green hydrogen project is relatively smaller than that of the floating wind power plant. In addition, the low price of LCoH could be attributed to the fact that the cost of electricity to produce hydrogen is “0.”

The factors most directly related to the profitability of floating offshore wind power are the CapEx and OpEx costs, and SMP. To achieve profitability of the business only with floating offshore wind power generation without government support, it is necessary to examine the trends of the SMP, NPV, IRR and LCoE with a change in the two aforementioned factors. Thus, the following conditions were created.

Tables 7 and 8 indicate the results of the changes in IRR at different CapEx and OpEx reduction rate, and SMP increase rate when the operating period of the project was divided into 20 and 30 years, respectively.

As shown in the tables, when CapEx decreased or SMP increased in all assumptions, the value of IRR further increased. Under condition a, if the SMP becomes 104.77 USD/MWh (i.e., a 50% increase) when the wind power plant is operated for 30 years, the IRR becomes 6.32%, which is slightly below the expected discount rate (6.74%). Even under conditions b, c, and d, the IRR was never close to the expected discount rate for the 20-year operating period even with either an decrease in the CapEx or an increase in the SMP or both: Under condition b with an operating period of 30 years, at an SMP increase rate of 40% (97.78 USD/MWh), the IRR was 6.67%; under condition c, at an SMP increase rate of 20% (83.81 USD/MWh), the IRR was 6.23%; and under condition d, at an SMP increase rate of 7% (74.73 USD/MWh), the IRR was 6.37%, which is close to the discount rate. Under condition e with a plant operating period of 20 years and SMP increase rate of 10% (or the SMP is 76.83 USD/MWh), the IRR becomes 6.15%. Under the same conditions, when the operating period was 30 years, the IRR was 7.23%, which is larger than the discount rate, regardless of the increase in SMP.

Figure 8 indicates the changes in the LCoE as the CapEx and OpEx decrease.

The change in SMP was omitted because it exerted no effect on LCoE. As shown in the graph below, the overall LCoE also decreases as the CapEx and OpEx decrease. When the reduction rate of CapEx and OpEx was 0%, and the operating period of the offshore wind power plant was 30 years, the LCoE decreased by approximately 11.17% based on 20-year operation. Although this gap gradually decreased with a decrease in the reduction rate of CapEx and OpEx from 0 to 50%, the decrease was not significant. When the reduction rate was 50%, the LCoE decreased by approximately 11.07% based on a 20-year operation.

As presented in Comparison of SMP + 1 REC, LCoE and IRR at different REC Weights, according to the formula for calculating the compound weight of offshore wind power linkage distance and water depth announced by the Korea Energy Agency as of September 2022, the limit for the maximum value of the combined weight is not specified. Thus, if the project assumptions of this study (i.e., a linkage distance of 70 km and a water depth of 150 m) are applied, the final 4.6 REC weight can be obtained. If a REC weight of 4.6 is given, the SMP + 1 REC, (i.e., the revenue consumed by the power producers per 1 MWh of electricity produced from wind power) is USD 397.46, which is approximately 5.7 times higher than the monthly SMP (USD 69.84). In this case, the expected IRR is 27.45%. If the IRR is 27.45%, no power producers will be reluctant with their business. Because this IRR is an unrealistic value, the South Korean government would not sign a fixed contract with a power producer based on a REC weight of 4.6. As indicated in this study, a fluctuation in SMP is an important factor in determining the profitability of offshore wind power projects. To accurately calculate the profitability of offshore wind power projects and avoid confusion, the government should designate and announce the maximum value of REC weight to power producers. Moreover, as shown in Fig. 5, although the IRR decreases with a decrease in the REC weight, the IRR is 12.46% when the REC weight is 1.7. This indicates that business feasibility is still sufficient. Therefore, there is a need to adjust the calculation method of the REC weight by comparing the profits of the demonstration complex.

This study proposed the relationship between a floating offshore wind farm and a hydrogen power plant as a profitable method for ensuring the profitability of offshore wind farm without government support. Particularly, the utilization of electricity wasted owing to curtailment of the offshore wind plant would increase the overall profitability to a noticeable level. However, as shown in Comparison of SMP + 1 REC, LCoE and IRR at different REC Weights, the connection of the green hydrogen project with floating offshore wind power increased the LCoE of the overall project and decreased the IRR with an increase in the capacity of the PEM electrolyser and the hydrogen production. This result indicates that the feasibility of the project is low. Although the operating period of the power plant was divided into 20 and 30 years for calculation, the same trend was observed. Why did this result appear?

The capacity of the PEM electrolyser varies depending on the curtailment rate of offshore wind power, that is, as the curtailment rate increases, the amount of electricity generated through offshore wind power decreases and the amount of hydrogen produced through the electrolyser increases. This can be easily understood if the revenue generated by wind power and hydrogen power generation is calculated using 1 MWh of electricity. Using 1 MWh of electricity, approximately 17.24 kg of hydrogen can be produced, which corresponds to approximately KRW 103,448. Excluding the ammonia transport cost of 1,800 KRW/kg H2, hydrogen produced using 1 MWh of electricity can be utilized to generate a profit of approximately KRW 72,414. This amount is less than the 83,910 KRW/MWh for the SMP.

As mentioned previously, the factors most directly related to the profitability of floating offshore wind power are the prices of CapEx and OpEx, and SMP. To verify this, this study examined the change in IRR with a decrease in CapEx and OpEx, and an increase in SMP in Comparison of SMP and IRR at different SMP increase rate and CapEx & OpEx reduction rate. According to five floating offshore wind study cases conducted by NREL, the CapEx of floating offshore wind power was predicted to decrease by an average of approximately 35% from 2019 to 2035 (Beiter, Philipp, Walter Musial, Patrick Duffy, Aubryn Cooperman, Matt Shields, Donna Heimiller and Mike Optis, 2020). Based on this, the change in the IRR was examined when the reduction ratios of CapEx and OpEx are 30 and 40%. When the reduction ratios of CapEx and OpEx are 30%, and the operating period of the wind power farm is 30 years, the price of SMP must increase by 11% to achieve an IRR of 6.77%, which exceeds 6.74% of the discount rate. The SMP price in this case is 77,153 USD/MWh. When the reduction ratios of CapEx and OpEx are 40%, and the operating period of the power generation complex is 30 years, the IRR becomes 7.23% without an increase in SMP. Under this condition, power producers will be able to make profit without government support.

The study demonstrated that compared to a 20-year operating term, extending the wind power plant's operational lifetime to 30 years may reduce LCoE without significantly increasing costs. These results imply that floating offshore wind generation might become a lucrative worldwide trend in the future by lowering costs and increasing operation times.