Economic comparison of offshore wind-to-hydrogen production routes based on a unit energy transmission assessment model

At present, offshore wind-to-hydrogen development primarily follows three technical routes: offshore distributed wind-to-hydrogen, offshore centralized wind-to-hydrogen, and onshore wind-to-hydrogen using offshore power. Building on existing techno-economic models for power transmission, transformation, hydrogen production, and transportation, this study incorporates scenarios that combine transmission lines with hydrogen pipelines to establish a comprehensive economic model for offshore wind-to-hydrogen production and delivery. The economic performance of different hydrogen production routes is evaluated under various scenarios using combinations of seven installed capacities (1–1000 MW), offshore distances (50–150 km), and capacity factors (0.3 and 0.4). The results indicate that higher capacity factors significantly reduce costs, particularly for large-scale projects (≥400 MW). For projects with a capacity ≤400 MW, scale has a pronounced effect on costs, but this effect diminishes beyond the threshold. Moreover, a cost crossover point between distributed and centralized routes appears when the offshore distance is ≤ 90 km, and higher capacity factors narrow the cost gap for near-shore distributed systems. This study elucidates the effects of installed capacity, offshore distance, and seawater desalination technology on economic feasibility, providing valuable insights for the optimization of offshore wind-to-hydrogen infrastructure.

1 Introduction

As a clean and renewable energy source, wind power plays a vital role in mitigating climate change and advancing the realization of global “carbon neutrality” targets (Feng et al., 2024). In recent years, the rapid expansion of wind power projects has significantly increased the share of renewables in the global energy mix (Ji et al., 2023). According to the “2025 Global Wind Energy Report” (Global Wind Energy Council, 2025) released by the Global Wind Energy Council (GWEC), the global newly installed wind power capacity reached a record-high 117 GW in 2024 (see Figure 1). The cumulative grid-connected capacity of offshore wind power reached 83.2 GW, and the offshore wind industry is projected to achieve a compound annual growth rate of 21% over the next decade (2025–2034), demonstrating strong long-term growth potential.

Figure 1

Figure 1. The newly installed capacity of wind power globally.

Compared with onshore wind power, offshore wind power offers higher power generation efficiency owing to greater wind speed and stability. However, the expansion of offshore wind capacity faces significant challenges, including delays in grid infrastructure development and the inherent volatility and intermittency of wind power (Ren et al., 2017), both of which threaten grid stability, a persistent issue for the sector. Therefore, large-scale offshore wind power transmission is a pressing issue that needs to be addressed, and hydrogen production from offshore wind power is one of the promising solutions (Taylor et al., 2025).

Hydrogen, as an emerging energy source, not only has a high energy density but also exhibits excellent storability. By the end of 2024, global hydrogen production was approximately 150 million tons per year, with a year-on-year increase of about 2.9%. Relevant studies show that the current hydrogen supply is still dominated by “grey hydrogen” produced from fossil fuels and only 1% of “green hydrogen” is generated from renewable energy (see Figure 2) (Obanor et al., 2024). With the advancement of global “carbon neutrality” goals, green hydrogen is expected to accelerate the replacement of grey hydrogen, with its share projected to reach 15% by 2030 and exceed 70% by 2050 (see Figure 3) (Tuluhong et al., 2024). Integrating offshore wind power with water electrolysis for hydrogen production presents three major advantages (He and Shen, 2021):

1. Wind energy, being an “instantaneous” source, can be converted into hydrogen and stored long-term in the form of high-pressure gas or cryogenic liquid with minimal energy loss.

2. Hydrogen production can mitigate grid instability caused by wind fluctuations, serving as a “peak-shaving and valley-filling” resource and reducing curtailment (Eladl et al., 2024).

3. Hydrogen can be transported via ships or repurposed oil and gas pipelines, lowering reliance on expensive submarine cables (Schell et al., 2017) and enabling the development of large-scale deep-sea wind projects.

Figure 2

Figure 2. Proportion of different hydrogen production processes.

Figure 3

Figure 3. Prediction of the proportion of future hydrogen production processes.

According to the 2025 analysis of the economics of offshore wind-to-hydrogen, costs are on a rapid downward trajectory, falling to approximately $7 per kilogram in 2025, and expected to decline to below $1 per kilogram by 2050. This improvement in economics is primarily attributed to advances in electrolyzer technology, large-scale production, optimized system integration, integrated power transmission, and refined offshore site planning. Although the current cost remains higher than that of hydrogen produced from fossil fuels, non-economic factors and policy support continue to serve as important drivers of its development (Rezaei et al., 2024).

This paper conducts a quantitative analysis and comparison of the unit energy transmission costs of three technical routes for hydrogen production from offshore wind power: offshore distributed wind-to-hydrogen, offshore centralized wind-to-hydrogen, and onshore hydrogen production from offshore wind power. Based on existing typical techno-economic models of power transmission and transformation as well as hydrogen production and transportation, it innovatively incorporates scenarios of combined energy transmission through transmission lines and hydrogen pipelines, and defines seven installed capacity levels to further construct an economic model for hydrogen production and transportation from offshore wind power.

2 Projects of offshore wind-to-hydrogen production

“China Hydrogen Energy Development Report (2025)” (National Energy Administration, 2025) indicates that by the end of 2024, the cumulative capacity of global renewable energy electrolysis hydrogen production projects of various types had exceeded 250,000 tons per year, with more than 70,000 tons per year of new capacity added in 2024, representing a year-on-year increase of approximately 42%. According to the International Hydrogen Council’s “2025 Global Green Hydrogen Development Report” (International Renewable Energy Agency, 2021), by mid-2025, the global installed electrolyzer capacity had surpassed 30 GW, with this growth largely driven by large-scale offshore hydrogen production projects in China, the United States, and Europe. The large-scale offshore hydrogen production projects currently under development worldwide are listed in Table 1.

Table 1

Table 1. Global offshore wind-to-hydrogen engineering projects.

Overall, the ten representative global offshore wind-to-hydrogen projects listed in the table adopt three technical routes: offshore distributed wind-to-hydrogen, offshore centralized distributed wind-to-hydrogen, and onshore hydrogen production from offshore wind power. The application of each route is relatively balanced: the number of projects adopting the three technical routes is 3, 3, and 4, respectively, with only minor differences in quantity, indicating a generally balanced application trend.

From the perspective of installed capacity, some projects still under construction have significantly larger installed capacities than those already completed. For example, the world’s first offshore wind-to-hydrogen project, the PosHYdon project in the Netherlands, has an installed capacity of only 1 MW, whereas the NortH2 project, also in the Netherlands and scheduled for completion in 2030, is expected to reach 4,000 MW. It demonstrates that offshore wind-to-hydrogen projects are evolving toward “large-scale” and “base-oriented” development.

From the perspective of water electrolysis technology, 50% of the projects presented in the table adopt alkaline water electrolysis (ALK) technology, 40% use proton exchange membrane electrolysis (PEM) technology, and only 10% apply high-temperature solid oxide electrolysis (SOEC) technology. At present, ALK technology is the most mature and cost-effective, but its adaptability to wind power fluctuations is limited (minimum operating load of 20%–100%). It is more commonly applied in scenarios with relatively stable operating conditions, such as onshore hydrogen production, and can be utilized for offshore wind-to-hydrogen applications in the short term. PEM technology, with a minimum operating load as low as 5%–10% and the capability for rapid start-up and shutdown, can effectively match the variability of renewable energy sources. It is particularly well suited for renewable energy-based hydrogen production (Wilberforce et al., 2023), and its output pressure is favorable for pipeline transportation. However, its current cost remains relatively high. In the long term, PEM technology is considered the optimal choice for offshore wind-to-hydrogen projects. For SOEC technology, only Norway’s Deep Purple project is exploring its application. Since SOEC requires a high-temperature environment (500 °C–1,000 °C) and imposes stringent material requirements, its large-scale deployment remains infeasible at present, despite its high efficiency potential (Zhou et al., 2025).

From a national perspective, Europe leads the exploration of multiple technical routes, emphasizing PEM technology and centralized development in far-offshore regions. China, relying primarily on the mature ALK technology, mainly adopts onshore hydrogen production as its core model, which offers clear scale advantages but limited technological diversity. In the future, as PEM technology costs decrease and offshore wind power expands toward far-offshore regions, the combination of centralized hydrogen production and PEM technology is expected to become mainstream. China needs to accelerate the localization of PEM technology to better accommodate the variability of offshore wind power.

3 Classification of offshore wind-to-hydrogen production technologies

There are three main technical routes for offshore wind power hydrogen production: offshore distributed wind power-to-hydrogen, offshore centralized distributed wind power-to-hydrogen, and onshore hydrogen production from offshore wind power (Taylor et al., 2025). Analysis of the engineering cases presented in Chapter 1 shows that the application of these routes is relatively balanced. This balance reflects that each route currently has suitable application scenarios and development potential, and also indicates that the industry has not yet formed a strong preference for a single technical route, remaining in a stage of exploring multiple parallel pathways.

The first route is the offshore distributed wind power-to-hydrogen system. As shown in Figure 4, electrolysis units are installed on the floating platform of each wind turbine. The wind power is directly converted into hydrogen, which is then transported to onshore storage through hydrogen pipelines. The advantage of this configuration is that each electrolyzer operates independently and is paired with a single wind turbine. Therefore, if one electrolyzer stops operating due to a wind turbine failure or insufficient power generation below its minimum operating level, the other electrolyzers and turbines can continue producing hydrogen. However, because the hydrogen production equipment is installed on the wind turbine platforms, it is affected by turbine operation, and the complex hydrogen pipeline system entails high installation costs. The economic feasibility of this hydrogen production mode still requires further validation and optimization.

Figure 4

Figure 4. Offshore distributed wind power for hydrogen production.

Next is the offshore centralized wind power-to-hydrogen system. Hydrogen is produced on independent floating platforms (or ships), as shown in Figure 5. In this configuration, the electricity generated by each wind turbine is first collected and transmitted to an offshore substation. After the alternating current is converted to direct current at the substation, it is supplied to the electrolysis equipment on the floating platform through high-capacity direct current cables. The produced hydrogen is then transported to shore via hydrogen pipelines. The advantages of this approach are that it is not limited by water depth, eliminates the need to construct offshore booster stations, and can utilize existing offshore oil and gas platforms by converting them into hydrogen production platforms, effectively reducing project investment (Franika et al., 2024). This scheme enables large-scale wind-to-hydrogen production in far-offshore areas and represents an important direction for the future development of the offshore hydrogen production industry.

Figure 5

Figure 5. Offshore centralized wind power for hydrogen production.

Finally, there is the onshore hydrogen production system using offshore wind power, as shown in Figure 6. The electricity generated by offshore wind turbines is first transmitted to an offshore substation via submarine AC cables. After conversion and voltage boosting, it is transformed into high-voltage direct current (HVDC) and delivered to onshore electrolyzers through high-voltage cables. This system offers the advantages of convenient installation and maintenance of the hydrogen production equipment, relatively low space constraints, high adaptability to wind power variability, and the ability to serve as an effective means for grid peak regulation (Calado and Castro, 2021). However, as the offshore distance increases, the costs of submarine cables and offshore booster or converter stations also rise. Additionally, due to energy losses during power transmission, the economic efficiency of this system gradually declines.

Figure 6

Figure 6. Offshore wind power for onshore hydrogen production.

4 Unit energy transmission model for the economic evaluation

The economic Model for Evaluating Unit Energy Transmission in Offshore Wind-to-Hydrogen can be generally written as (Hu et al., 2022)

$C_{Ytotal}=C_{Ycap}+C_{O\&M}(1)$

where $C_{Ytotal}$ is the total annual cost; $C_{Ycap}$ is the annual depreciation of the fixed investment cost, using linear depreciation with a residual value set to 0. $C_{O\&M}$ is the annual operation and maintenance cost of the system.

The cost per unit of energy transmission can better reflect the economic comparison of offshore wind-to-hydrogen. It is defined as the ratio of the total annual cost to the annual transmitted energy (electrical energy, hydrogen energy)

$C_{spec}=\frac{C_{Ytotal}}{E_{Ytotal}}(2)$

where $C_{spec}$ is the unit energy transmission cost; $E_{Ytotal}$ is the annual transmission energy.

4.1 Offshore distributed wind power to hydrogen production

In the technical route of offshore distributed wind power for hydrogen production, this paper assumes that each wind turbine in the wind farm is equipped with a PEM electrolyzer to produce hydrogen, which is then transported to onshore storage via submarine pipelines. Therefore, the fixed investment in power transmission includes offshore substations, seawater desalination equipment, PEM electrolyzers, and submarine hydrogen pipelines. The annual depreciation of the fixed investment cost can be expressed as

$C_{Ycap\_H}=\frac{C_{cap\_OS}}{Y_{cap\_OS}}+\frac{C_{cap\_SD}}{Y_{cap\_SD}}+\frac{C_{cap\_PEM}}{Y_{cap\_PEM}}+\frac{C_{cap\_pipe}}{Y_{cap\_pipe}}(3)$

where $C_{cap\_OS}$, $C_{cap\_SD}$, $C_{cap\_PEM}$ and $C_{cap\_pipe}$ are the fixed investment costs of the offshore substation, seawater desalination, electrolysis, and hydrogen pipeline respectively; $Y_{cap\_OS}$, $Y_{cap\_SD}$, $Y_{cap\_PEM}$ and $Y_{cap\_PEM}$ are the equipment lifespans of the offshore substation, seawater desalination, PEM electrolyzer, and hydrogen pipeline respectively.

The annual operation and maintenance cost of each device is estimated based on a certain proportion of the fixed investment as follows

$\begin{array}{ll}\hfill C_{O\&M\_H}& =C_{cap\_OS}·{\eta }_{cap\_OS}+C_{cap\_SD}·{\eta }_{cap\_SD}+C_{cap\_PEM}·{\eta }_{cap\_PEM}\hfill \\ \hfill & +C_{cap\_pipe}·{\eta }_{cap\_pipe}\hfill \end{array}(4)$

where ${\eta }_{cap\_OS}$, ${\eta }_{cap\_SD}$, ${\eta }_{cap\_PEM}$ and ${\eta }_{cap\_pipe}$ are the ratios of the annual operation and maintenance costs to the fixed investments (operation and maintenance ratios) for the offshore substation, seawater desalination, PEM electrolyzer, and hydrogen pipeline, respectively.

Annual energy transfer can be defined as

$E_{Ytotal\_H}={\sum }_{i=1}^{8760}\left(P_{wind,i}-P_{loss\_OS,i}-P_{SD,i}\right)·{\eta }_E·\Delta t(5)$

It satisifies

$P_{loss\_OS,i}=P_{wind,i}·{\eta }_S(6)$

where $P_{wind,i}$ is the power of the offshore wind farm at the $i$-th hour, $P_{loss\_OS,i}$ is the power loss of the offshore substation, $P_{SD,i}$ is the power consumption for seawater desalination, ${\eta }_E$ is the electrolysis efficiency of the electrolyzer. In this paper, electrolysis loss is ignored, ${\eta }_E=1$ and ${\eta }_S$ is the power loss ratio. For high-voltage alternating current (HVAC) systems, its value is usually around 0.8%, $\Delta t$ is the discrete time interval, which is set as 1 in this paper.

4.2 Offshore centralized wind power to hydrogen production

In the technical route of hydrogen production from offshore centralized wind power, this paper assumes that an offshore floating platform for centralized hydrogen production is installed at the midpoint of the line connecting the wind farm and the onshore hydrogen storage facility. The platform is equipped with PEM electrolyzers to produce hydrogen. Offshore wind power is transmitted to the hydrogen production platform via high-voltage cables, and the produced hydrogen is transported to onshore storage through submarine pipelines. Therefore, the fixed investment in power transmission includes offshore substations, HVAC systems, seawater desalination equipment, PEM electrolyzers, and submarine hydrogen pipelines. The annual depreciation of the fixed investment cost can be expressed as:

$C_{Ycap\_H}=\frac{C_{cap\_OS}}{Y_{cap\_OS}}+\frac{C_{cap\_SC}}{Y_{cap\_SC}}+\frac{C_{cap\_SD}}{Y_{cap\_SD}}+\frac{C_{cap\_PEM}}{Y_{cap\_PEM}}+\frac{C_{cap\_pipe}}{Y_{cap\_pipe}}(7)$

where $C_{cap\_SC}$ is the fixed cost of the submarine cable; $Y_{cap\_SC}$ is the equipment life of the submarine cable.

$\begin{array}{ll}\hfill C_{O\&M\_H}& =C_{cap\_OS}·{\eta }_{cap\_OS}+C_{cap\_SC}·{\eta }_{cap\_SC}\hfill \\ \hfill & +C_{cap\_SD}·{\eta }_{cap\_SD}+C_{cap\_PEM}·{\eta }_{cap\_PEM}+C_{cap\_pipe}·{\eta }_{cap\_pipe}\hfill \end{array}(8)$

$E_{Ytotal\_H}={\sum }_{i=1}^{8760}\left(P_{wind,i}-P_{loss\_OS,i}-P_{loss\_SC,i}-P_{SD,i}\right)·{\eta }_E·\Delta t(9)$

$P_{loss\_SC,i}=3·{\left(\frac{P_{wind,i}}{\sqrt{3}U\cos \phi }\right)}^2·R·L(10)$

where $U$ is the transmission voltage of the cable. $\cos \phi$ is the power factor, usually equals to 0.9. $R$ is the resistance of the cable, which is 0.02 Ω/km in this paper. $L$ is the length of the cable.

4.3 Offshore wind power for onshore hydrogen production

In the technical route of onshore hydrogen production from offshore wind power, this paper assumes that the electricity generated by the offshore wind farm is collected at the offshore substation, transmitted to the onshore substation through high-voltage alternating current cables, and then converted to hydrogen through an ALK electrolyzer after step-down and commutation. Therefore, the fixed investment in power transmission includes offshore substations, HVAC systems, onshore substations, and ALK electrolyzers. The annual depreciation of fixed investment costs can be expressed as

$C_{Ycap\_H}=\frac{C_{cap\_OS}}{Y_{cap\_OS}}+\frac{C_{cap\_pipe}}{Y_{cap\_pipe}}+\frac{C_{cap\_LS}}{Y_{cap\_LS}}+\frac{C_{cap\_ALK}}{Y_{cap\_ALK}}(11)$

where $C_{cap\_LS}$ is the fixed cost of the onshore substation, and $Y_{cap\_LS}$ is the equipment life of the onshore substation.

$\begin{array}{ll}\hfill C_{O\&M\_H}& =C_{cap\_OS}·{\eta }_{cap\_OS}+C_{cap\_SC}·{\eta }_{cap\_SC}+C_{cap\_LS}·{\eta }_{cap\_LS}\hfill \\ \hfill & +C_{cap\_ALK}·{\eta }_{cap\_ALK}\hfill \end{array}(12)$

$E_{Ytotal\_H}={\sum }_{i=1}^{8760}\left(P_{wind,i}-P_{loss\_OS,i}-P_{loss\_SC,i}-P_{loss\_LS,i}\right)·{\eta }_E·\Delta t(13)$

where

$P_{loss\_LS,i}=P_{loss\_OS,i}(14)$

To clarify the data sources and calculation background, it is hereby stated that the investment assumption results in this table are all derived based on the current actual situation of China’s hydrogen energy market. The investment costs may vary slightly from country to country, but the feasibility of the economic assessment model still has reference value.

5 Results and discussion

Based on the techno-economic model of power transmission, transformation, hydrogen production, and transportation constructed in Section 4, this section conducts a quantitative calculation and comparative analysis of the unit energy transmission costs for three technical routes: offshore distributed wind power-to-hydrogen, offshore centralized wind power-to-hydrogen, and onshore hydrogen production from offshore wind power. In the calculation process, model parameter values refer to Tables 2, 3. Multiple sets of comparison scenarios are established using the control variable method, as follows:

1. Installed capacity scale gradient: Seven typical installed capacities—1 MW, 10 MW, 200 MW, 400 MW, 600 MW, 800 MW, and 1000 MW—are selected to analyze the impact of project scale on economics;

2. Offshore distance range: Set between 50 and 150 km, covering nearshore wind farms (50–100 km) and far-reaching offshore wind farms (100–150 km);

3. Capacity factor differences: Two capacity factors, 0.3 and 0.4 (reflecting wind power generation efficiency), are adopted to evaluate the impact of wind energy utilization efficiency on cost.

Table 2

Table 2. Assumptions about general parameters of the case.

Table 3

Table 3. Electrolysis equipment parameters.

The unit energy transmission costs under different scenarios are calculated using the model, and cost–offshore distance relationship curves are plotted (Figures 7–13). The results indicate that the economics of the three technical routes vary significantly and are comprehensively influenced by installed capacity, offshore distance, and capacity factor. The specific patterns are as follows:

1. Under the same installed capacity and offshore distance, an increase in capacity factor significantly reduces the unit energy transmission cost. This is because a higher capacity factor improves the utilization efficiency of wind energy resources, thereby lowering the fixed investment and operation and maintenance costs allocated per unit of energy. This effect is particularly pronounced in large-scale installations (≥400 MW), as shown in Figures 9–13.

2. The effect of installed capacity on economics exhibits phased characteristics. When the installed capacity is ≤ 400 MW, the unit energy transmission cost declines markedly with scale expansion, reflecting a clear scale effect—directly related to the diminishing marginal cost of equipment investment (e.g., improved allocation efficiency of shared facilities such as submarine pipelines and substations). When the installed capacity exceeds 400 MW, the cost reduction trend flattens, indicating that the scale effect approaches saturation, and further expansion has limited impact on economic efficiency.

3. For scenarios with installed capacity ≥200 MW, there is a clear intersection point between the unit energy transmission cost curves of offshore distributed and centralized wind power-to-hydrogen. To the left of the intersection, i.e., at shorter offshore distances, the cost of the distributed route is higher than that of the centralized route. The main reason is that decentralized hydrogen pipeline installation in the distributed scheme accounts for a higher proportion of costs. Comparing the abscissas of intersection points under different installed capacities and capacity factors (see Table 4) shows that the critical offshore distance where the distributed route is more expensive than the centralized route does not exceed 90 km, and the critical distance for lower capacity factors is smaller than that for higher capacity factors. This indicates that improved wind energy utilization can mitigate the cost disadvantage of the distributed route in nearshore scenarios.

4. The unit energy transmission cost analysis shows that onshore hydrogen production from offshore wind power is consistently more economical than offshore distributed and centralized hydrogen production. The primary factor driving this difference is the high energy consumption and cost of seawater desalination in offshore hydrogen production. To evaluate the impact of desalination costs, a supplementary calculation is performed assuming zero energy consumption for seawater desalination (i.e., using seawater directly for electrolysis) for a 400 MW installed capacity case, with results shown in Figure 14. Eliminating desalination energy consumption significantly reduces the unit energy transmission cost of offshore distributed and centralized hydrogen production, narrowing the cost gap with onshore hydrogen production to 10%–15%, with further convergence as capacity factor increases. This demonstrates that breakthroughs in seawater desalination technology will substantially enhance the economics of offshore hydrogen production.

Figure 7

Figure 7. Unit Energy Transmission Cost - Offshore Distance Curve of 1 MW wind farm.

Figure 8

Figure 8. Unit Energy Transmission Cost - Offshore Distance Curve of 10 MW wind farm.

Figure 9

Figure 9. Unit Energy Transmission Cost - Offshore Distance Curve of 200 MW wind farm.

Figure 10

Figure 10. Unit Energy Transmission Cost - Offshore Distance Curve of 400 MW wind farm.

Figure 11

Figure 11. Unit Energy Transmission Cost - Offshore Distance Curve of 600 MW wind farm.

Figure 12

Figure 12. Unit Energy Transmission Cost - Offshore Distance Curve of 800 MW wind farm.

Figure 13

Figure 13. Unit Energy Transmission Cost - Offshore Distance Curve of 1000 MW wind farm.

Table 4

Table 4. Comparison of the abscissas of the intersection points.

Figure 14

Figure 14. Unit Energy Transmission Cost - Offshore Distance Curve of 400 MW wind farm (zero power consumption for seawater desalination).

6 Conclusion

This paper focuses on the core issue of economic optimization of offshore wind-to-hydrogen technology routes, emphasizing three mainstream routes: offshore distributed wind power-to-hydrogen, offshore centralized wind power-to-hydrogen, and onshore hydrogen production from offshore wind power. It aims to quantify the cost differences and key influencing factors of each route under various scenarios, providing a scientific basis for the planning and technology selection of offshore wind-to-hydrogen infrastructure.

Based on existing typical techno-economic models of power transmission, transformation, hydrogen production, and transportation, the scenario of “joint energy transmission via transmission lines and hydrogen pipelines” was first innovatively incorporated to construct an economic evaluation model for unit energy transmission in offshore wind power hydrogen production, covering the full chain of “hydrogen production – transportation – storage.” The unit energy transmission cost was identified as the core evaluation indicator. Basic parameters were set with reference to the actual situation of China’s hydrogen energy market, and multi-dimensional comparative scenarios were designed using the control variable method, covering seven installed capacity gradients (1 MW–1000 MW), offshore distances including nearshore and far-reaching sea areas (50–150 km), and two capacity factors (0.3, 0.4) reflecting wind energy utilization efficiency. Finally, based on the constructed economic model, quantitative calculations were performed for the unit energy transmission costs of the three technical routes under multiple scenarios, and cost–offshore distance relationship curves were plotted. Supplementary verification was also conducted using the “zero energy consumption for seawater desalination” assumption to clarify the impact of the seawater desalination link on the economy of offshore hydrogen production.

Based on the above research, the following core conclusions are drawn: a) Under the same installed capacity scale and offshore distance, an increase in capacity factor can significantly reduce the unit energy transmission cost, and this effect is particularly pronounced in large-scale projects (≥400 MW). This is because a higher capacity factor improves the utilization efficiency of wind energy resources and reduces the fixed investment and operation and maintenance costs allocated per unit of energy. b) The impact of installed capacity scale on economic efficiency exhibits a “diminishing marginal effect.” When the installed capacity is ≤ 400 MW, the unit energy transmission cost decreases significantly as the scale expands; however, when the capacity exceeds 400 MW, the cost reduction tends to flatten, indicating that the scale effect is approaching saturation and that further expansion of installed capacity has a limited effect on improving economic efficiency. c) For scenarios with installed capacity ≥200 MW, there is a clear intersection point in the unit energy transmission costs between offshore distributed and centralized hydrogen production. The critical offshore distance corresponding to this intersection does not exceed 90 km. When the offshore distance is below this critical value, the cost of the distributed route is higher than that of the centralized route. A high capacity factor can reduce the cost disadvantage of the distributed route in nearshore scenarios, while the critical distance corresponding to a low capacity factor is smaller. d) The economic efficiency of onshore hydrogen production using offshore wind power is consistently significantly better than that of offshore distributed and centralized hydrogen production. The main limiting factor is the high energy consumption and cost associated with the seawater desalination link in offshore hydrogen production scenarios. Supplementary verification shows that if the energy consumption of seawater desalination is eliminated, the cost gap between offshore distributed, centralized, and onshore hydrogen production can be reduced to 10%–15%, and it further converges with increasing capacity factor. This indicates that breakthroughs in seawater desalination technology are key to improving the economic efficiency of offshore hydrogen production.

Future reductions in key technological costs, particularly for PEM electrolyzers and seawater desalination systems, are expected to significantly enhance the economic viability of offshore hydrogen production routes. As these and other components, such as subsea hydrogen pipelines, become more cost-effective, the current cost advantage of onshore production is likely to diminish. This progression could make centralized offshore systems, especially in far-offshore areas, a more competitive and mainstream solution for large-scale green hydrogen supply.

Data availability statement

The original contributions presented in the study are included in the article/supplementary material, further inquiries can be directed to the corresponding author.

Author contributions

HJ: Conceptualization, Funding acquisition, Methodology, Writing – original draft, Writing – review and editing. LX: Conceptualization, Data curation, Funding acquisition, Writing – review and editing. WC: Data curation, Formal Analysis, Methodology, Software, Writing – original draft. DG: Conceptualization, Data curation, Writing – review and editing. BX: Writing – original draft, Writing – review and editing.

Funding

The author(s) declare that financial support was received for the research and/or publication of this article. The Science and Technology Project from China Renewable Energy Engineering Institute.

Conflict of interest

The authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

Generative AI statement

The author(s) declare that no Generative AI was used in the creation of this manuscript.

Any alternative text (alt text) provided alongside figures in this article has been generated by Frontiers with the support of artificial intelligence and reasonable efforts have been made to ensure accuracy, including review by the authors wherever possible. If you identify any issues, please contact us.

Publisher’s note

All claims expressed in this article are solely those of the authors and do not necessarily represent those of their affiliated organizations, or those of the publisher, the editors and the reviewers. Any product that may be evaluated in this article, or claim that may be made by its manufacturer, is not guaranteed or endorsed by the publisher.

References

Calado, G., and Castro, R. (2021). Hydrogen production from offshore wind parks: current situation and future perspectives. Appl. sciences-Basel 11 (12), 5561. doi:10.3390/app11125561

CrossRef Full Text | Google Scholar

Eladl, A., Fawzy, S., Abd-Raboh, E., Elmitwally, A., Agundis-Tinajero, G., Guerrero, J. M., et al. (2024). A comprehensive review on wind power spillage: reasons, minimization techniques, real applications, challenges, and future trends. Electr. Power Syst. Res. 226, 109915. doi:10.1016/j.epsr.2023.109915

CrossRef Full Text | Google Scholar

Feng, S., Wang, W., Wang, Z., Song, Z., Yang, Q., and Wang, B. (2024). Global wind-power generation capacity in the context of climate change. Engineering 51, 86–97. doi:10.1016/j.eng.2024.09.018

CrossRef Full Text | Google Scholar

Franika, R. V., Ridwan, M. K., and Perdana, A. (2024). Techno-Economic analysis of utilization offshore platform in the Java Sea to produce hydrogen with offshore wind turbine-based energy sources. J. Phys. Conf. Ser. 2828 (1), 012029. doi:10.1088/1742-6596/2828/1/012029

CrossRef Full Text | Google Scholar

Global Wind Energy Council (2025). Global wind energy report 2025. Brussels, Belgium: GWEC.

Google Scholar

He, Q., and Shen, Y. (2021). Development status of technology for wind-hydrogen coupled energy storage system. Therm. Power Gener. 50 (08), 9–17. doi:10.19666/j.rlfd.202102013

CrossRef Full Text | Google Scholar

Hu, X., Yuan, X., Li, B., Ge, Y., and Lin, R. (2022). “Techno-Economic comparison between power transmission and hydrogen production and transportation for offshore-wind,” in 2022 2nd international conference on electrical engineering and control science (IC2ECS).

Google Scholar

International Renewable Energy Agency (2021). Global green Hydrogen Development report 2025. Abu Dhabi, United Arab Emirates: IRENA.

Google Scholar

Ji, Z., Qin, J., Cheng, K., Zhang, S., and Wang, Z. (2023). A comprehensive evaluation of ducted fan hybrid engines integrated with fuel cells for sustainable aviation. Renew. Sustain. Energy Rev. 185, 113567. doi:10.1016/j.rser.2023.113567

CrossRef Full Text | Google Scholar

Jiangsu, G. (2021). Dafeng 850,000-kilowatt offshore wind power Project commences full-scale Construction[EB/OL]. Available online at: https://www.jiangsu.gov.cn/art/2025/3/13/art_60085_11515812.html.

Google Scholar

Jiangsu, Y. (2023). Announcement on the investment and construction of Yancheng Jidian Green Hydrogen production, storage, transportation, refueling and utilization integration (Phase I) demonstration Project[EB/OL]. Available online at: https://m.10jqka.com.cn/sn/20240828/49029689.shtml.

Google Scholar

Lee, J., Choi, Y., Che, S., Choi, M., and Chang, D. (2022). Integrated design evaluation of propulsion, electric power, and re-liquefaction system for large-scale liquefied hydrogen tanker. Int. J. Hydrogen Energy 47 (6), 4120–4135. doi:10.1016/j.ijhydene.2021.11.004

CrossRef Full Text | Google Scholar

Li, X., and Yuan, L. (2022). Development status and suggestions of offshore wind power hydrogen production technology. Power Gener. Technol. 43 (02), 198–206. doi:10.12096/j.2096-4528.pgt.22032

CrossRef Full Text | Google Scholar

National Energy Administration (2025). Department of energy conservation and science, technology and equipment, national energy Administration. China hydrogen energy Development report. Beijing, China: National Energy Administration.

Google Scholar

Obanor, E. I., Dirisu, J. O., Kilanko, O. O., Salawu, E. Y., and Ajayi, O. O. (2024). Progress in green hydrogen adoption in the African context. Front. Energy Res., 12–2024. doi:10.3389/fenrg.2024.1429118

CrossRef Full Text | Google Scholar

Ren, G., Liu, J., Wan, J., Guo, Y., and Yu, D. (2017). Overview of wind power intermittency: impacts, measurements, and mitigation solutions. Appl. Energy 204, 47–65. doi:10.1016/j.apenergy.2017.06.098

CrossRef Full Text | Google Scholar

Rezaei, M., Akimov, A., and Gray, E. M. A. (2024). Techno-economics of offshore wind-based dynamic hydrogen production. Appl. Energy 374, 124030. doi:10.1016/j.apenergy.2024.124030

CrossRef Full Text | Google Scholar

Schell, K. R., Claro, J., and Guikema, S. D. (2017). Probabilistic cost prediction for submarine power cable projects. Int. J. Electr. Power and Energy Syst. 90, 1–9. doi:10.1016/j.ijepes.2017.01.017

CrossRef Full Text | Google Scholar

Taylor, M., Strezov, V., Best, R., Pettit, J., Cho, H., Hammerle, M., et al. (2025). Offshore renewable hydrogen potential in Australia: a techno-economic and legal review. Int. J. Hydrogen Energy 152, 149923. doi:10.1016/j.ijhydene.2025.06.113

CrossRef Full Text | Google Scholar

Tuluhong, A., Chang, Q., Xie, L., Xu, Z., and Song, T. (2024). Current status of green hydrogen production technology: a review. Sustainability 16 (20), 9070. doi:10.3390/su16209070

CrossRef Full Text | Google Scholar

Wilberforce, T., Olabi, A. G., Imran, M., Sayed, E. T., and Abdelkareem, M. A. (2023). System modelling and performance assessment of green hydrogen production by integrating proton exchange membrane electrolyser with wind turbine. Int. J. Hydrogen Energy 48 (32), 12089–12111. doi:10.1016/j.ijhydene.2022.12.263

CrossRef Full Text | Google Scholar

Zhou, J., Ji, C., Li, R., Song, X., Wu, K., and Cheng, Y. (2025). Development status of water electrolysis hydrogen production technology and its application progress in the new power system. High. Volt. Eng. 51 (05), 2096–2113. doi:10.13336/j.1003-6520.hve.20242050

CrossRef Full Text | Google Scholar