In Table 1, the input values for installed energy production units at the island can be seen. The dominant electricity sources are thermal power plants that use fuel oil as an energy source. They account for approximately 2.48 TWh or 75% of electricity production. Moreover, there is notable production from onshore wind farms (0.505 TWh), while the PV potential remains mostly unused with a total installed capacity of only 96 MW and annual production of 0.162 TWh.

Table 2 presents the input values used when building a Reference scenario, which corresponds to current fuel consumption by an energy source. The data are directly obtained from Hellenic Electricity Distribution Network Operator. Electric heating and cooling are subtracted in the simulation due to seasonality, but the total electricity demand in 2017 was 3.219 TWh. Figure 3 presents the annual electricity demand on an hourly basis in 2017 for the Crete case. As can be seen, the load is constant throughout the year, with several peaks in the summer and winter periods. The primary energy source is diesel in the residential sector, followed by renewable biomass and solar thermal primarily used for heating purposes. Various fossil fuels represent half of the consumption in the industry, while the other half is covered by biomass.

The precise, latest available data for 2017 and 2019 were used in the industry and power production sector. Nevertheless, when building future scenarios, fuel consumption for residential and industrial purposes did not change since the focus was on integrating renewable energy sources, especially offshore wind, when the island is connected to the mainland with interconnection cables. Therefore, there are four considered scenarios in this work. The first is the reference case where the island is an isolated system with thermal power plants, onshore wind, and photovoltaics. The second scenario considers the installation of a maximum of 300 MW of offshore wind on the east side of the island (Figure 1) and operating one interconnection cable of 400 MW capacity. In the third scenario, power plants are shut down, and the interconnection capacity is increased to 1400 MW. The last scenario considers the additional deployment of 480 MW of PV and onshore wind to reach the maximum capacity for the RES with a total interconnection capacity of 1400 MW. Interconnection capacities are obtained from the system and grid operator. According to the Greek national energy strategy, the shares of additional RES capacities are equally divided between PV and onshore wind (Hellenic Republic, 2019).

When building future scenarios, the following assumptions were used:

• The maximum offshore wind capacity is 300 MW.

An interconnection cable of 400 MW has been operational since the beginning of 2022, while an additional cable with 1000 MW will be deployed by the end of 2023. Thermal power plants, currently the backbone of the isolated energy system, will be shut down once interconnections are fully operational and the maximum capacity of renewable energy sources is installed. Interconnection of 1400 MW capacity allows for deployment of 300 MW offshore wind and an additional 480 MW of other RESs, which are equally divided on PV and onshore wind, following the guidelines from the national strategy (Hellenic Republic, 2019).

The future scenarios are named in the following manner: Reference (REF), Transition (TR), Blue Energy (BE), and Renewable (RE). Except for the Reference scenario, all others are investigating the potential of renewable sources in the context of interconnection with the mainland. Table 3 presents the considered parameters for each investigated scenario.

In this subsection, Reference and Transition scenarios are compared more in-depth since they have operational thermal power plants included in the model. Moreover, this comparison shows the impact of offshore wind farms on energy system stability while there is no full connection to the mainland. There is no visible difference between the Reference and Transition scenarios in the case of PV and onshore wind electricity production. The power output remains the same in both cases, which is expected since the system is modeled to maximize renewables’ production. Nevertheless, the introduction of offshore wind farms had a notable effect on power output from thermal power plants. The capacity of 300 MW ensures the annual production of 1.17 TWh of electricity from offshore wind, with an average load factor of 42%, and the highest production in August, even though winter months, in general, express better energy potential. Deployment of offshore wind directly reflects in power output from thermal power plants, which is reduced from 2.55 to 1.51 TWh. Moreover, offshore wind turbines and connection to the mainland with underwater cables allows some electricity export when production is higher than electricity demand. Figure 5 presents the electricity production from offshore and onshore wind in a one-year period. It is evident that offshore wind has a significantly higher energy potential, resulting in higher load factors and electricity output. The production from the offshore wind farm is more than doubled compared to the onshore, even though the difference in considered capacity is less than 100 MW.

Figure 6 presents the monthly production from considered energy sources for these two scenarios. The figure shows that the introduction of offshore wind farms directly reduces output from thermal power plants, while the share of renewables is increasing.

The analysis of results on an hourly basis gives a good insight into system components’ interaction and reveals the potential spots where grid stability could be disturbed. With the operational thermal power plants, the supply side is stable since the production is following the demand side. The RESs are currently used to satisfy the peak demand, and the total share in the electricity mix is around 26%. The inclusion of offshore wind farms reduces the power output from thermal power plants, but even more, it opens the possibility for electricity export via the interconnection cable of 400 MW capacity. Figure 7 presents the influence of offshore wind on electricity export. The figure shows that electricity export occurs only when the offshore wind farm is at its peak production. The export is around 130 GWh annually in the Transition scenario, which might be utilized on the island by introducing electric vehicles (EVs) or heat pumps for heating. Nevertheless, this would require cross-sectoral integration and a systematic approach to develop a decarbonization strategy.

This section analyzes the energy system of Crete Island with fully operational interconnection cables with a capacity of 1400 MW and independent from fossil fuels for electricity production since the thermal power plants are phased out. The difference between Blue Energy and Renewable scenarios is in the total installed capacities of renewable energy sources. While the Blue Energy scenario considers offshore wind and currently installed PV and onshore wind capacities, an additional 480 MW of RES is added in the Renewable scenario. In total, 780 MW of renewables, compared to that in the Reference scenario, is the maximum capacity that could be installed with fully operational interconnection cables. Since the Greek energy strategy considers PV and onshore wind as the backbone of the future energy system, 480 MW is equally divided between these two sources. Therefore, the new capacity for PV is 336 MW, and the total capacity for onshore wind is 443 MW. It is necessary to ensure grid stability in both cases since installed renewables are strongly variable. The analysis shows that at least 25% of interconnection capacity needs to be used constantly for grid balancing to ensure undisrupted electricity supply to consumers. Moreover, to maintain grid stability in the Renewable scenario, it is necessary to ensure an operating grid stability strategy due to high-RES capacities. This can be done by electricity export, curtailment of the production from offshore and onshore wind farms, or utilizing electricity surplus to produce electrofuels. The exporting strategy was applied in this work, followed by the curtailment in extreme cases. Storing the electricity excess or utilization for electrofuel synthesis requires cross-sectoral coupling. This is not possible to assess with limited data or with the lack of a decarbonization strategy.

In the Blue Energy scenario, renewables can provide up to 57% (∼1.8 TWh) of electricity demand on an annual basis, while the rest comes from import (∼1.5 TWh). The electricity export accounts for 100 GWh on a yearly basis. Further increment of onshore renewables could theoretically cover up to 89% of electricity demand. Nevertheless, since the demand is not following the supply curve, a significant amount of electricity needs to be exported (∼515 GWh). Due to that fact, import remains a vital part of the system operation and stability, and it accounts for 0.9 TWh or 27% of electricity demand. Monthly production for considered renewables is given in Figure 8. As can be seen, the power output from offshore wind farms remains at the same level for both scenarios, 1.17 TWh, and is the major contributor to the power production sector with a share of 36%. The offshore wind production in these scenarios is identical to that in the Transition scenario, which is expected since simulations are carried out to maximize the power output from offshore wind farms to enhance their economics. Therefore, this value represents the maximum theoretical potential of offshore wind energy with the current level of technology development. For the Renewable scenario, increment of installed capacity for onshore wind farms doubled the production from this source to 1.11 TWh, and its share is approximately 35%. An additional 240 MW of PV increases power output from this source to 0.57 TWh, accounting for 18% of electricity production.

Figure 9 compares electricity supply by source for all considered scenarios. Currently, renewable electricity production is 0.67 TWh on an annual basis. Deployment of only 300 MW offshore wind turbines can increase this value to 1.85 TWh. Further increment in renewable capacities can increase renewable production on the island to 2.85 TWh, which corresponds to 89% of the current annual electricity demand. In terms of primary energy supply, fuel oil consumption for thermal power plants is 6.4 TWh for the Reference scenario, which can be reduced to 3.8 TWh in case that the offshore wind farm is installed. In general, the fuel oil used for power generation represents the vast majority of fossil fuels used on the island (∼80%) when the transport sector is not considered. Energy consumption in the residential and industrial sectors is kept at the same level (∼1.2 TWh) for all scenarios since electrification for heating, cooking, or industrial purposes is not considered.

In terms of fuel consumption, it should be emphasized once again that this analysis is done without the inclusion of the transport sector for which the data were not available. Having this in mind, it can be concluded that the introduction of offshore wind and the increase in other renewables’ capacities can dramatically reduce the consumption of fossil fuels. As mentioned above, this is because the vast majority of fossil fuel consumption in considered sectors comes from thermal power plants where fuel oil is used. The remaining share of fossil fuel consumption (coal, natural gas, and some oil) is still used for industries and households. Still, their overall share is dramatically reduced compared to the reference case. The results are given in Figure 10.

Figure 11 sums up the share of renewable energy sources in electricity production and primary energy supply for assessed sectors. The share of renewables in electricity production increases from 25 to 100% when the offshore wind is deployed in combination with additional PV and onshore wind capacities, and thermal power plants are phased out. Nevertheless, it should be emphasized that a significant amount of electricity comes from import in this case, for which the production source is not known. In terms of primary energy supply, the share of renewables, including biomass, increases from 15 to 83%. For the case of the Blue Energy scenario, it is noted that the percentage of renewables in PES surpasses the share in electricity production, which is a direct consequence of the dramatic drop in fuel oil consumption. For complete decarbonization, it is necessary to electrify heating and, where possible, industrial sector and include alternative renewable fuels (Stančin et al., 2020). With the inclusion of the transport sector into the assessment, the share of fossil fuels in TPES would dramatically increase. Therefore, it is necessary to establish a strategy for transport decarbonization, which is inevitably related to the power production system once when there is a high share of electric vehicles.

Since there are no available data regarding the CO₂ emission for Crete Island, the results given in Figure 12 can only be used as indicative values. Even more, this analysis is limited since the software cannot calculate the values of CO₂ emissions from imported electricity. For this reason, we have carried out a separate analysis to determine the level of emissions from imports, taking into account the average emission factor of Greek national systems, which is 487 kgCO₂/MWh. In this case, for the BE scenario, the imported emissions are 0.73 Mt, and for the case of the RE scenario, they are approximately 0.44 Mt. On the contrary, the emission generated at power plants reduces from reference 1.53 Mt to only 0.18 Mt. Only the introduction of offshore wind farms reduced the CO₂ emission by one-third to 1.0 Mt. From this preliminary analysis, it can be concluded that importing electricity from the mainland in combination with RES production at the island is a better solution than running thermal power plants.

To evaluate the economic feasibility of proposed scenarios, the simplified levelized cost of electricity (LCOE) analysis is carried out. Simplified means that some rough estimations have been used, predominately on the investment side, due to the limited data availability. Table 4 summarizes the data used for this economic assessment. All data regarding the technology costs are taken from the Danish Energy Agency (Technology Data, 2022). The weighted average cost of capital (WACC) is taken from the Energy Post platform (Energy Post, 2022), but for the onshore wind in the case of Greece, since the data for offshore are not available. The calculation also included the investment for interconnector cables, even though this investment would happen with or without deployment of considered RESs (Greece commissions Crete-Peloponnese power interconnection, 2022; Independent Power Transmission Operator, 2022).

The analysis shows that, in the case of TR or BE scenarios where only offshore wind and interconnector are considered, the LCOE is around 120 EUR/MWh. This value is in the range of LCOE values for offshore wind farms published in the study (Energy and Climate, 2022). When additional PV and onshore capacities are deployed, such as in the RE scenario, the LCOE is further reduced to 90 EUR/MWh. This reduction can be expected since the investment and operating and maintenance (O&M) costs are comparably lower for PV and onshore wind than offshore wind. The technology lifetime was considered 27 years, with the 12% WACC used to discount the costs and energy production. Once again, these values should only be taken as orientational values due to used approximations and uncertainties regarding the technology costs.