Offshire Grid Mediterreanée UE

Study on the offshore grid
potential in the Mediterranean

region
Written by :
Konstantin Staschus, Iza Kielichowska, Lou Ramaekers, Carmen Wouters, Barry Vree, Ainhoa Villar
Lejarreta, Lennard Sijtsma, Guidehouse Netherlands B.V.
Frank Krönert, Simon Lindroth, Gustaf Rundqvist Yeomans, SWECO
November – 2020
EUROPEAN COMMISSION
Directorate-General for Energy
Directorate B - Internal Energy Market
Unit B1 - Networks & Regional Initiatives
Contact: Miklos Gaspar

Email : Miklos.Gaspar@ec.europa.eu
European Commission
B-1049 Brussels
Study on the offshore grid
potential in the Mediterranean
region
Final Report
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Directorate-General for Energy

Internal Energy Market
2020 EN
Study on the offshore grid potential in the Mediterranean region
Advisory Board contribution

This study’s authors would like to express gratitude to the following members of the Advisory
Board, who actively contributed to the work’s progress and provided the consortium with their
strategic opinion and additional literature:
 Angelo Ferrante, Secretary General, Med-TSO, Italy

 Prof. Nikos Hatziargyriou, National Technical University of Athens, Greece
 Kostas Komninos, Director, Network of Sustainable Greek Islands, Greece
Executive summary
The Mediterranean Sea region is becoming increasingly interested in the application of clean
energy technologies, both on- and offshore. Therefore, there is a need to identify the potential
for a joint regional effort in developing offshore energy and supporting grid infrastructure,
following similar studies for the North and Baltic Seas.
Guidehouse (previously Navigant Netherlands B.V.)1 provided technical assistance to the

European Commission (EC) on the topic of offshore grid potential in the Mediterranean region
(request for services no, ENER/B1/2019-508 under framework contract MOVE/ENER/SRD/2016-
498 Lot 2). The geographical scope of this study includes nine European Union (EU) member
states in the Mediterranean region:
 Croatia  Malta
 Cyprus  Slovenia
 France  Spain
 Greece  Portugal
 Italy
The analysis covered five energy technologies: offshore wind (bottom-fixed and floating
technologies), wave and tidal energy, onshore wind, and solar technologies in islands. This final
study presents the results of the analysis followed by a broad stakeholder consultation.
Potential for offshore power generation

The deployment of offshore technologies for electricity generation in the Mediterranean Sea has
been relatively slow so far, consisting of floating offshore wind, wave, and tidal pilot projects.
Onshore wind and solar PV are widely spread across the Mediterranean islands. Most of the
countries in the region have set targets per technology for the coming decade as part of their
National Energy and Climate Plans (NECPs). The highest targets are set for offshore bottom-
fixed wind (France, Italy, Portugal) and onshore PV. Some other countries (Greece, Malta,
Cyprus) are also actively developing analyses of the renewable energy sources (RES) potential
so one may hope for even more ambitious developments in future policy targets.
In terms of forecasting, this study presents estimates for the technical and the economic
potential for offshore renewable energy and renewable energy on islands in the Mediterranean
region for the years 2030 and 2050. We have analysed the natural potential, limited by the
spatial constraints, nature protection areas, maritime and (partly) military use, and technology-
specific exclusions such as water depth and visual impact.
The assessment shows that floating offshore wind is the most suitable technology due to large
available areas with favourable wind speeds, suitable water depths, and relatively high capacity
factors, resulting in a technical potential of approximately 4,600 TWh/aby 2030 and 4,700
TWh/a by 2050. The technology is not fully mature, but it is promising as costs are expected to
fall. Onshore technologies on islands, such as onshore wind and rooftop and utility-scale solar
PV, are promising technologies due to their maturity level, regulatory readiness, projected cost
levels, and social acceptance (in the case of solar). The technical potential is 60 TWh/a for
onshore wind on islands in 2050 and 207 TWh/a for solar PV on islands in 2050. Wave energy
has a good technical potential at 4,500 TWh/a) by 2050, comparable to floating offshore wind.
However, this technology is still less mature and more expensive than the aforementioned
offshore and onshore technologies, and further research, development, and innovation (RDI)
investments are required to overcome these barriers. Bottom-fixed offshore wind technical
potential is rather limited due to water depth constraints in the Mediterranean Sea and is
estimated at 60 TWh/a in 2050. However, bottom-fixed offshore wind is a mature technology,
making it suitable for deployment in specific parts of the Mediterranean region. The role for tidal
energy will be more limited due to its limited technical resource potential (22 TWh/a in 2050),
technology immaturity and high cost levels.
1
Guidehouse LLP completed its acquisition of Navigant Consulting, Inc. and its operating subsidiaries on
October 11, 2019. For more information, see: https://guidehouse.com/news/corporate-
news/2019/guidehouse-completes-acquisition-of-navigant.
This study also presents the economic potential for renewable power production by estimating
the levelized cost of electricity (LCOE) for each of the technologies and countries analysed for
2030 and 2050. Among offshore technologies, LCOE values for bottom-fixed offshore wind are
lower than for floating offshore; however, the difference is expected to decrease through 2050.
For wave and tidal technologies, LCOE values are significantly higher, but they are also on a
decreasing trend. LCOE levels for onshore technologies (i.e., wind and solar PV on islands) are
generally much lower than those for offshore technologies.
Selected technology mix areas

Based on the results of the technical potential and the LCOE analysis, this study identified 10
technology mix areas (TMAs) with the greatest cost-effective potential for various technologies
or combinations thereof.
Some areas are prioritised above other regions for more practical reasons, such as the
availability of resources that can be utilised with more mature technologies or the possibility of
including the connection hub within a meshed grid. The final selection of TMAs covers a wide
range of the Mediterranean Sea from the Spanish Gulf of Cádiz to the Greek Aegean Sea,
presented in Figure ES-1.
Figure ES-1: Most interesting identified TMAs

(Source: Guidehouse)
The 10 TMAs proposed in the study do not cover the entire potential in the region. They simply
ranked highest in this study’s modelling, as presented in Table ES-1.
Table ES-1: TMA rankings

TMA Description Ranking Remarks
Label
01 Gulf of Lion 1 Low LCOE

Close to load centre
07 North Aegean Sea 2 Low LCOE
03 Sicily 3 Low LCOE
Large potential of onshore technologies on nearby islands
Close to planned grid connection Sicily-Tunisia
04 Gulf of Venice 4 Substantial bottom-fixed offshore wind with relatively low LCOE in
2030
08 Italy–Ionian Sea 5
09 Corsica–Sardinia 6 Large potential of onshore technologies on nearby islands
Close to planned grid connection
10 South Aegean Sea 7 Close to load centre

06 Gulf of Cádiz 8 Far from load centre
02 Malta 9 High LCOE
Far from load centre
05 Baleares 10 High LCOE
Therefore, a higher resolution analysis of the potentials is needed to fully understand RES
potential for each country in the region.
Production scenarios
Based on the identified economic offshore energy potential, this study develops two realistic
production scenarios for each of the selected countries for 2030 and 2050, focusing on the 10
selected TMAs. The scenarios differ regarding the ambition level (the amount of installed
offshore power generation capacity). The NECP scenario is less ambitious (2.4 GW offshore wind
in 2030 and 32.7 GW offshore wind in 2050) than the ambitious scenario (13.3 GW offshore
wind in 2030, about 76.0 GW offshore wind in 2050). Beyond these installations, there is
additional offshore capacity in France, Portugal, and Spain since not all of their coastline is
defined as Mediterranean.
Both scenarios are designed to reach or exceed the respective national renewables target for
2030. The ambitious scenarios add between 2% and 22% in RES share for 2030 for
each of the Mediterranean member states. This increase contributes to a higher RES share
in Europe and faster decarbonization.
Figure ES-2: Regional distribution of offshore generation capacity, NECP

scenario: 2030 (left), and regional distribution of offshore generation
capacity, ambitious scenario: 2030 (right)
(Source: Sweco)
Figure ES-3: Regional distribution of offshore generation capacity, NECP

scenario: 2050 (left), and regional distribution of offshore generation capacity,
ambitious scenario: 2050 (right)
(Source: Sweco)
Impact on CO2 emissions

The analysis of this study also shows that CO2 emissions fall significantly in most Mediterranean
countries between 2020 and 2030, most significantly in Portugal, Spain, Italy, and Greece.
Substantial additional gains can be made in almost all Mediterranean countries by introducing
more offshore generation, as presented in Figure ES-5.
120
100
CO2-emissions ]Mt]]
80
60
40
20
0
Portugal Spain France Italy Slovenia Croatia Greece Cyprus Malta
Reference_2020 Med Offshore - NECP_2030 Med Offshore - Ambitious_2030
Med Offshore - NECP_2050 Med Offshore - Ambitious_2050
Figure ES-4: CO2 emissions from power production 2020, 2030, and 2050 in
the different production scenarios
(Source: Sweco)
Grid options
This study concludes that the region does not require one meshed grid solution covering the
entire region. On the contrary, this study’s recommendation is considering several sub regional
hubs linking offshore installations with interconnectors.
This study develops two grid connection alternatives for connecting the identified production
blocks within the TMAs to the onshore transmission grid and to each other, if feasible: radial
and hub connections. For two of the TMAs, a cross-country interconnection was also
investigated as a third option.
The hub connection requires lower capital investment costs than the radial connection
alternatives because the hub connection utilizes a common interconnection for several
production blocks in a given area, thereby limiting the construction and material costs. On the
downside, this interconnection means a limited decrease in security of supply, as the outage of
a cable could mean loss of the output from more than one production block. Another difference
between the radial connection and the hub connection is that the former does not require
coordination of the different production blocks, whereas the latter assumes that the whole group
of production blocks is realized as a common project. A common hub project is more difficult to
achieve with a step-by-step approach and generally requires a bigger commitment in terms of
investments and policies. Thus, a comparison between the two options needs to consider not
only the summary costs but also the strategic choices involved.
A third option is feasible cross-country interconnectors based on the hub grid connection
alternative. This study found that the cross-country interconnection from Italy to Croatia in the
Gulf of Venice was not economically beneficial, whereas the interconnection from France to
Spain in the Gulf of Lion was economically beneficial.
Socioeconomic benefits
For 2030, this study concludes that the ambitious scenario with 13 GW RES
integration yields more benefits than the NECP scenario with 2 GW installed offshore
capacity by lowering power prices. The analysis disregards the cost for onshore grid
reinforcement, which was not quantified in this study. However, both scenarios require
considerable investments in offshore power generation, its connection to the land, and the
onshore grid, in addition to considerable reinforcement of the onshore grid itself.
To reach the RES integration of about 76 GW of offshore wind power capacity in the
Mediterranean in the ambitious scenario for 2050, about €120-130 billion of accumulated
investments is needed until 2050. These investments include investments in offshore production
assets and their grid connection to land but exclude onshore grid reinforcements and other
production assets or energy storage. However, opportunities for substantial socioeconomic gains
exist with the modelled investments in RES, as presented in Figure ES-5.
Figure ES-5: Summary of CAPEX, RES integration, change in socioeconomic

welfare, and CO2 savings in the various 2030 and 2050 scenarios
(Source: Sweco)
Key barriers
This study identifies a list of barriers and implementation challenges for offshore grid and
renewable development and groups them into 10 broader categories. Next, these barriers and
implementation challenges were ranked based on their impact on offshore grid and renewable
development in the Mediterranean.
The categories of barriers with the highest priority at a regional level are:
 Offshore grid and renewable generation technologies: grid connection and technology
maturity
 Offshore RES generation related to support schemes
 Administrative/governance processes
 Social and environmental constraints
The study proposes a series of measures to overcome these hurdles, presented below.
Key recommendations
Regional cooperation in energy, grid, and spatial planning is key for cost optimisation of the
deployment of offshore RES technologies in the region. Following the analysis and the achieved
result of the study, the study’s authors propose the following recommendations.
This study recommends the following activities on the member state level:
 Execute a more detailed analysis of potential for economically viable variable renewable
energy sources (vRES)- offshore and on islands, including detailed environmental and
spatial analyses.
 Consider increasing the national level of ambition.
 Revisit grid development plans, including development of sub regional hubs and linking
them to planned interconnectors the entire Mediterranean region.
 Perform detailed analysis of RES costs.
 Discuss ways of aligning support schemes/balancing and grid services within the specific
subregions.
 Initiate programs promoting sustainable tourism.
 Develop RES education programs to create more RES skills capacity in the job market
and expand the RES job skill base in the region across the entire value chain.
The EC plays a crucial role in facilitating sub regional and regional coordination of efforts also in
the Mediterranean region. Therefore, this study proposes that the EC prioritize the following:
 RES potential and development

 Consistent methodology for analysis of RES potentials for offshore energy and the
energy in islands
 Structured guidance on the regional/cross-border coordination of maritime spatial
planning and energy planning in the region
 Discussion on support scheme designs and balancing and grid services solutions in
the subregions and across the region
 Grid developments
 Coordination of offshore, onshore, and cross-border grid development and
operational standards via Med-TSO and ENTSO-E for a dedicated regional RES
growth strategy
 Development of models via Med-TSO/ENTSO-E
 Minimal requirements for grid/onshore delivery models for Projects of Common
Interest (both infrastructure and cross-border RES projects)
 Rules for cross-border capacity allocation and a regional grid maintenance strategy
with active participation of the Mediterranean countries, Med-TSO, MEDREG,
ENTSO-E, and ACER
 Development of aligned rules for onshore grid infrastructure development, serving
offshore energy sources
 Market design
 Market coupling efforts coordination
 Regional bidding zone arrangements with active participation of the Mediterranean
countries, Med-TSO, MEDREG, ENTSO-E, and ACER
 Cross-border cost allocation (CBCA) framework for cost sharing supporting the
ongoing efforts of Med-TSO.
 Coordination of CBCA principles via leading a dialogue with member states or even
developing the methodology
 Financing
 Providing measures to reduce the risks for projects in south and south eastern
Europe via an EU Renewable Energy Cost Reduction Facility or other facilitating
programs supported by EIB or EBRD
 RDI
 Supporting RDI for less mature technologies, such as wave, tidal, and floating
offshore
 Optimization of grid planning on a regional level
 Impact of various bidding zone configurations in the offshore area

This study identified and ranked 10 TMAs and identified technology production blocks for each
TMA. The most interesting ones are:
 Gulf of Lion has high floating offshore wind and wave potential, combined with the
interconnection between Spain and France.
 Gulf of Venice possesses a very interesting opportunity in bottom-fixed offshore wind,
which could be connected to the shore with a hub connection and Italy-Croatia.
 North Aegean Sea has substantial floating offshore wind and wave potential, with the
possibility of linking these offshore resources with the extended submarine grid for
interconnection of major islands in the Aegean Sea.
 The TMA southwest of Sicily offers floating and bottom-fixed offshore wind
opportunities, large wave potential, and large onshore technology opportunities in Sicily
and nearby islands; it is possible to envisage technical solutions where the connection of
the production blocks is realised in parallel with the HVDC link in Italy-Tunisia or the two
projects being integrated as a single multipole HVDC link.
 TMA Corsica-Sardinia, similarly to Sicily, offers large offshore floating wind energy
potential and potential for onshore technologies in the nearby islands. These offshore
resources could be connected to Italy, but it is possible to consider connecting it to an
HVDC interconnection between northern Italy and Tunisia, in parallel with the
connection of the production blocks, or being integrated as a single multipole HVDC link.
Further recommended work includes:
 Analysis of the offshore RES potential for the whole region, including the non-EU
countries, in coordination with institutional partners such as Med-TSO, MEDREG or
(partly) the Energy Community, along with its potential impact on the environment and
potential interference with other economic activities in the sea
 Bottom-fixed offshore wind potential around the Greek and Croatian islands as well as in
the Gulf of Venice
 Onshore vRES potential in islands
 Analyse the potential for novel technologies, such as floating PV, CSP, and P2X solutions
(green hydrogen generation) and (green) gas transmission.
 Analyse flexibility potential including storage and demand response options
 Further onshore grid reinforcement analysis for the whole region, taking into
consideration the RES potential and EU 2030 target realisation for interconnectivity, is
needed to understand the trade-offs between the lower cost of energy, a decrease in
CO2 emissions, and the cost of new infrastructure.
1.0 POTENTIAL FOR OFFSHORE POWER GENERATION

Task 1 identified areas in the Mediterranean region with the greatest cost-effective offshore energy
potential with a performance ranking for use in Task 2 and Task 3. This task used a spatial
constraint analysis to determine suitable locations for renewable power generation in the
Mediterranean Sea. Following identification of these locations, their technical energy potential was
determined by using a raw resource map for each technology under investigation. Technology cost
figures then helped determine economic potential. The study collated the locations within a
(flexible) spatial grid (120x120 km) to identify potential technology mix areas (TMAs). Then, the
study ranked these areas according to their levelized cost of electricity (LCOE) and selected 10
TMAs for further assessment. At a representative location of each selected area, hourly production
time series data were extracted to inform Task 2 and Task 3 for each relevant renewable energy
technology.
The geographic scope of this study includes nine European Union (EU) member states in the
Mediterranean region: Croatia, Cyprus, France, Greece, Italy, Malta, Slovenia, Spain, and Portugal.
This report provides an assessment of four technology categories:
1. Offshore wind (bottom-fixed and floating technologies)

2. Solar on the region’s islands (interconnected and non-interconnected)
3. Wind on the region’s islands (interconnected and non-interconnected)
4. Wave and tidal energy (floating technology)
Figure 1-1 presents the approach to Task 1.
A1 Literature and Regulatory Review for Mediterranean Region

Potential for offshore power generation
ENTSO-E TYNDP2018 ENTSO-E TYNDP2020 k m² Spatial
Technology Assessment
Scenario 2030 Scenario 2050 Constraints
Performance Ranking
Analysis
A3
• Additional performance ranking criteria for potential zones A6 MWh Renewable

• Production time series Potential
(Technical)
A4
Technology mix areas with associated ratings €/MWh Economic

Potential
(LCoE)
A5 A2
Scenario 2030 Scenario 2050 Challenges
A7 Recommendations on Potential for Offshore Power Generation
Output to Task 2 Activity w ithin Task Major External Input
Figure 1-1: Approach to Task 12

Tasks 1 and 2 investigated the current level of renewable energy sources (RES) development and
included performing a technology assessment. Task 3 used publicly available geographic
information system layers to limit potential offshore renewable areas in the Mediterranean with
key exclusion variables. Based on the available areas found, Tasks 4 and 5 calculated the available
resource potential in those areas and the LCOE, representing economic potential. Task 6 took a
detailed look at selected high potential areas in the Mediterranean and determined performance
2
This task used TYNDP 2018 (ENTSO-E, 2018d) as the TYNDP 2020 is not finalized yet. Although scenarios
and market studies are available for TYNDP 2020, specific projects of European relevance and their cost-
benefit analyses will only become available later in 2020.
ranking cost curves. The detailed methodology and key findings are presented in the following
section.
1.1 Current RES development in the Mediterranean region

The deployment of offshore technologies in the Mediterranean region is currently very limited.
Existing installed offshore capacities consist of mainly floating offshore wind located off the Atlantic
coast of Portugal and wave and tidal pilot projects located mainly in Italy and Greece. The projects
are rather small and in a precommercial phase in the case of floating wind or a R&D stage in the
case of wave and tidal.
Although Portugal does not have a Mediterranean Sea shore, it is involved in offshore
developments taking place in the south of Europe and could be interested in offshore grid
connections directly related to other Mediterranean offshore grid links. Portugal is in the process of
commissioning the first precommercial floating offshore wind project in the region (PrinciplePower,
2020). Meanwhile, the Spanish Canary Islands and the northern region touched by the Cantabrian
Sea have positioned themselves as two innovation hubs in southern Europe. These regions have
seen interesting developments with existing and future deployments of various floating structures
on different test sites: Oceanic Platform of the Canary Islands (PLOCAN) and Biscay Marine Energy
Platform (BiMEP) (Recharge News, 2020a; Recharge News, 2020b). In both of these regions,
several developers have recently expressed interest in deploying precommercial (50-60 MW) and
full-scale floating offshore wind farms (200 MW) that could become live as early as 2021 and
2024, respectively (Recharge News, 2019a; Recharge News, 2019b; The Olive press, 2020). If
these developments take place, the Canary Islands would be close to achieving its target of 310
MW by 2025 (AEE, 2019.). Although these regions are out of the geographical scope of this study,
ongoing prototype testing developments are directly linked to the future potential of floating wind
technology in Spanish Mediterranean waters, where no projects are currently in place.
Italy is well advanced in research studies for several wave energy prototype devices (Soukissian et
al., 2017). Spain and Portugal had installed a few wave prototype devices between 2008 and 2010
but decommissioned them shortly afterward (Soukissian et al., 2017). Since 2015, Greece has also
started testing and developing wave energy modules, and additional research activities have been
ongoing since 2017 (SINN Power Projects, 2020). Notably, the ongoing projects are still focused
on analysing the technical requirements of such technologies for further expansion to other areas
in the Mediterranean (WindPlus, 2017; Coiro, Troise, & Bizzarini, 2018).
Bottom-fixed offshore wind is the most mature technology among the considered offshore
technologies but has not seen any developments in the Mediterranean region (Soukissian et al.,
2017). This fact is primarily due to the characteristic bathymetry of the Mediterranean Sea and its
waters that are generally too deep (beyond 50 meters) to deploy this technology cost-effectively.
Due in part to the latter, regional policymakers have not focused on bottom-fixed offshore wind
(Soukissian et al., 2017). This trend partly explains the absence of an incentive to develop large-
scale offshore wind farms in the Mediterranean Sea. Table 1-1 gives a country overview of the
current state of deployment of offshore technologies in the Mediterranean region.
Table 1-1: Current state of deployment of offshore technologies in the

Mediterranean region (MW)
Location Total offshore Bottom-fixed Floating Tidal energy Wave energy
wind offshore wind offshore wind
Croatia 03 03 03 03 03
Cyprus 04 04 04 04 04
France 05 05 06 07 07
Greece 05 05 06 07 0.058 7
Italy 05 05 06 0.559 2.8510 7 11 12
Malta 05 05 06 013 013
Portugal 8.405 14 05 8.4015 6 14

012 0.359
Slovenia 016 016 016 016 016
Spain 05 05 06 017 18
017 18
Portugal has set the precedent for floating offshore wind in the region within the scope of the
study, and the country has concrete plans to reach 200 MW of installed capacity in the medium
term after the precommercial phase of the project is complete (Direção-Geral de Energia e
Geologia, 2019). Italy and Portugal are the frontrunners with respect to wave R&D projects, while
Greece has also reported some pilot activities in wave energy. Currently, no commercial tidal
projects exist, and development projects for tidal energy in the region are very scarce. A few
coastal locations in Croatia, Gibraltar, and the Strait of Messina (Italy) have caught the attention
of ocean energy experts to further assess the available wave and tidal resources (Soukissian et al.,
2017). Slovenia has limited offshore potential that is not yet fully recognised.
Onshore technologies on Mediterranean islands have seen a considerably greater deployment,

though it remains rather modest compared to the deployment of these technologies on the
mainland. Clean Energy for European Islands—a program designed to implement decarbonisation
3
(Ministry of Environment and Energy, 2019)
4
(Department of Environment Cyprus, 2020)
5
(WindEurope, 2019b)
6
(WindEurope, 2019a)
7
(Collombet, 2018)
8
(SINN Power Projects, 2020)
9
(Ocean Energy Europe, 2017)
10
(Pisacane, Sannino, Carillo, Struglia, & Bastianoni, 2018)
1111
(Ocean Energy Europe, 2017)
12
(Ocean Energy Systems, 2020)
13
(Government of Malta, 2019)
14
(Direção-Geral de Energia e Geologia, 2019)
1515
(Soukissian et al., 2017)
16
(Ministrstvo za infrastrukturo, 2020)
17
(Spain's Ministry for Ecological Transition and Demographic Challenge, 2020a)
18
(Curto & Trapanese, 2018)
of energy islands—may facilitate the process substantially and reduce the cost of renewable
energy in island communities (European Commission, 2020).
Some regional differences are worth noting in the relative deployment and renewable energy
resource penetration rates on the islands’ gross final electricity generation compared with the
mainland. This development is mainly driven by countries’ island-specific regulatory schemes put
in place in the past few years. Corsica (France) exceeds the national share of renewable electricity
generated, mainly thanks to hydropower (77% of renewable generation) and solar PV (18% of
renewable generation).23 The largest Italian islands, Sicily (32%) and Sardinia (32%), have similar
shares as the national averages.23 However, the smaller Italian and Greek islands have
significantly lower RES shares but have policies in place to change that, which will be discussed in
Section 1.1.2. On the other hand, the renewable electricity share is especially low in the Spanish
Balearic Islands compared with the national average at less than 10%.23 Similarly, Malta and
Cyprus have low shares of renewable electricity generation, around 5% and 8%, respectively. 23
For Croatian islands, it was not possible to establish the share of gross final renewable electricity in
relation to the national average.23 Slovenia has no islands, and therefore no onshore renewable
potential in the scope of this study.
Table 1-2 shows an overview of the deployed capacities solar PV and onshore wind on islands.
Solar PV capacities include both large-scale utility solar plants and rooftop solar PV systems.
Table 1-2: Current state of onshore technologies in Mediterranean islands (MW)

Location Solar PV Onshore wind
Croatia 2 MW (Vis)19 020

6.5 MW (Cres)19
Cyprus 360 MW (Island Vis)19 157.5 MW
6.5 MW (Island Cres)19
France 152 MW (Corsica)21 18 MW (Corsica)21
Greece 100.03 MW (Crete) 22
200.29 MW (Crete)22
56.87 MW (NII besides Crete)22 105.86 MW (NII besides Crete)22
Italy 2,077 MW (Italian islands)23 2,823 MW (Italian islands)23
1400 MW (Sicily)23 1,892 MW (Sicily)23
787 MW (Sardinia)23 1,055 MW (Sardinia)23
0.45 MW (Pantelleria)23 0.032 MW (Pantelleira)23
2.78 MW (Elba)23
0.3 MW (Lipari)23
0.09 MW (Ventotene)23
0.04 MW (Ustica)23
0.11 MW (Ponza)23
0.01 MW (Capri)23
21.72 MW (Capraia) 23
34.74 MW (Giglio) 23
18.4 MW (Tremiti) 23
232.5 MW (Favignana) 23
24 MW (Levanzo) 23
11 MW (Marettimo) 23
3 MW (Panarea) 23
119.6 MW (Vulcano) 23
69.12 MW (Lampedusa) 23
4.5 MW (Linosa) 23
Malta 178 MW 0
Portugal N/A N/A
19
(HEP Group)
20
(Institute of Public Finance, 2018)
21
(French Ministry for the Energy Transition, 2019)
22
Email correspondence with Permanent Representation of Greece to the European Union on March 9, 2020.
23
(Navigant & E3 Modelling, 2017), Working communication from the Italian Permanent Representation,
31.07.2020, based on GSE Communication 31/12/2018 and Atlaimpianti GSE.
Location Solar PV Onshore wind
Slovenia N/A N/A

Spain 78 MW (Balearic Islands) 11 MW (Balearic Islands)
Overall, large islands such as Cyprus, Corsica, Malta, Crete, Sicily, and Sardinia have already
installed a significant amount of wind and solar capacity. Solar PV technology is more abundant in
Cyprus, Corsica, and Malta, whereas onshore wind prevails more in Crete, Sicily, and Sardinia.
Smaller islands in Croatia, Italy, and Greece have installed rather modest capacities, but the
Spanish islands are lagging compared with other islands in terms of current RES capacity installed.
For example, the regulation in Spain did not incentivize the development of rooftop solar PV
systems until very recently. In 2018, Spain’s new administration abolished a set of fees that were
charged to behind-the-meter distributed generation and storage assets (unofficially referred to as
the sun tax) and a set of burdensome administrative requirements for new residential PV systems
that were enacted in 2015 (Spain's Ministry of Industry, Energy and Tourism, 2015). The new
regulation encourages collective self-consumption of energy and established frameworks to
distinguish compensation of self-produced and unconsumed energy (Valdivia, 2019; Spain's
Ministry for Ecological Transition and Demographic Challenge, 2019). Different types of self-
consumption are defined within the new framework. The novelty lies in the collective self-
consumption concept by which multiple consumers are associated with one PV generation system
that is not necessarily located on one’s own building. Also, the payment mechanism corresponding
to any surplus energy injected into the grid has been simplified. Consumers are now paid monthly
for systems up to 100 kW, and compensation amounts can go up to 100% of the value of the
energy consumed. In addition, administrative procedures have been simplified to a single-step
process for installations of up to 15 kW with surplus or 100 kW without surplus (Molina, 2019).
Therefore, solar PV deployment is expected to massively increase in Spain in the coming years.
More importantly, this new regulation will allow for lower energy system costs and prices,
especially on the islands (Navigant & E3 Modelling, 2017).
In Greece and Italy, however, onshore wind and rooftop solar PV are in a relatively advanced
stage of deployment. In addition, Greece enacted a new legislative framework for energy
communities in 2018 with the goal of opening the energy market to new civil cooperatives. This
framework would enable civil cooperatives to address the energy transition, increase the
penetration of RES and its local acceptance, and combat energy poverty (Ministry of Environment
& Energy of Greece, 2018). More recently, in May 2020, Greece enacted a new environmental law
(Law No. 4685/2020) that modernises the environmental regulation and establishes a simplified,
efficient, and fast licensing process for RES projects (Government of Greece, 2020). With this new
law, photovoltaic projects under 1 MW are exempt from obtaining a license. This law also
harmonises Greek law with EU Directives 2018/844/EU and 2019/692/EU and is anticipated to
accelerate the deployment of RES projects in the country even more. Already in 2016, the average
total RES integration in Greek islands amounted to 18.7%, reaching a 60% hourly penetration in
Crete (HEDNO, 2016).Overall, multiple factors explain the still limited development of onshore
wind farms and utility solar PV plants in the Mediterranean region:
 Limited space availability in islands (Government of Malta, 2019) and competition for other
land uses such as agricultural activities (RSE S.p.A., n.d.)
 A strong commitment to preserve the islands’ natural protected areas (RSE S.p.A., n.d.)
and safeguard the region’s key industry, tourism (Government of Malta, 2019; Conseil
Insular de Menorca)
 Policy frameworks that still incentivize the use of fossil fuels in the islands’ power systems
(Navigant & E3 Modelling, 2017)
 Lack of interconnections between islands and the mainland, which could provide additional
flexibility to manage RES fluctuations efficiently and further increase RES development
(The need for interconnections is emphasized by the high yearly load variability due to the
influx and outflux of tourists.) (Soukissian et al., 2017; RSE S.p.A., n.d.)
 Lack of adequate regulations and financial incentives, which is not encouraging the
installation of hybrid stations and storage that would significantly increase the deployment
and management of RES
1.1.1 Capacity targets up to 2030 and beyond

Most of the countries in the Mediterranean region have elaborated and submitted their final NECPs
with an outline of their climate strategy and set targets per technology for the coming decade.
Targets for offshore wind are clearly set in France’s draft NECP, which plans to hold several
bottom-fixed and floating offshore wind tenders in the coming years up to 2028 (French Ministry
for the Energy Transition, 2019). In 2022, a call for tenders for floating offshore wind is planned
for Mediterranean sites. The French government aims to organize an additional auction between
2024-2028 for two new projects in the Mediterranean Sea of around 500 MW each (2x40
turbines), in addition to the first two projects of 250 MW that call for tenders, which is planned for
2022 (2x20 turbines). The total installed capacity for offshore wind in the Mediterranean Sea is
estimated to be 1,500 MW by 2040.28
Portugal and Italy aim to install significant offshore wind capacity by 2030. However, Portugal has
not yet specified how that goal will be achieved (Direção-Geral de Energia e Geologia, 2019), and
Italy has not finalized the split between bottom-fixed and floating technologies at the time of
preparing this report (Ministry of Economic Development (Italy), 2019).
Other countries display interest in and commitments to offshore wind but lack specific offshore
wind targets. Malta, for example, confirmed the current technological and economic infeasibility of
developing offshore wind farms in Maltese waters but is continuing to monitor further
developments in the technology (Government of Malta, 2019). Malta also considers floating solar
as a potential technological solution to the country’s specific context.
In its target scenario, Spain outlines a total joint onshore and offshore wind installed capacity of
approximately 40 GW in 2025 and 50 GW in 2030 (Spain's Ministry for Ecological Transition and
Demographic Challenge, 2020a). Spain’s NECP shows commitment to enabling public mechanisms
that will support the technologies that are not yet mature, such as offshore wind and ocean
energies; at the same time, it emphasizes addressing the peculiarities of the island territories
(Spain's Ministry for Ecological Transition and Demographic Challenge, 2020a).
The NECP also proposes specific recurring tenders with adaptable pre-arranged volumes of
capacity tendered for offshore wind and ocean energy technologies as a means of delivering
flagship projects. In the case of floating offshore wind, Spain already sees increasing potential
within the 2030 horizon. Therefore, it will adapt its support mechanisms and the capacity volumes
tendered in renewable energy auction rounds due to the technology’s increasing competitiveness
and synergy with other strategic economic sectors (electro-intensive and naval industries). Public
financing will be made available subject to the needs of each specific renewable energy tender
(Spain's Ministry for Ecological Transition and Demographic Challenge, 2020a).
Meanwhile, Spain’s Ministry for the Ecological Transition and the Demographic Challenge is
working on the roadmap for the development of offshore wind and marine energy and recently
launched the public consultation for these technologies. (Spain's Ministry for Ecological Transition
and Demographic Challenge, 2020b; The Institute for Diversification and Energy Saving, 2020). In
parallel, the ministry is working on an update of Directive 2014/89 that has a twofold objective:
identification and analysis of sites that could provide the greatest offshore wind energy potential.
This update would also provide the time window for projects and identification of new testing sites
that can foster the sector’s development, especially around the islands’ waters (Spain's Ministry for
Ecological Transition and Demographic Challenge, 2020c). This marine spatial planning (MSP)
update is expected to be ready no later than April 2021. While no specific target for offshore wind
is defined in Spain’s NECP today, this spatial planning update exercise could result in the addition
of concrete capacity targets in periodical NECP reviews (Spain's Ministry for Ecological Transition
and Demographic Challenge, 2020b). On the other hand, Cyprus, Croatia, and Slovenia have no
plans for offshore wind development in their NECPs (Ministry of Environment and Energy, 2019;
Department of Environment Cyprus, 2020; Ministrstvo za infrastrukturo, 2020).
Wave and tidal technologies remain outside of the scope of many countries’ NECPs. For example,
Malta expresses interest in monitoring the still immature technology (Government of Malta, 2019),
and Spain refers to enabling public mechanisms to support demonstration projects of ocean energy
technologies (Spain's Ministry for Ecological Transition and Demographic Challenge, 2020a).
Table 1-3 gives a country overview of the 2030 targets and 2040 long-term outlooks for offshore
technologies in the Mediterranean region.
Table 1-3: 2030 targets and long-term outlook for offshore technologies in the
Mediterranean region (MW)24
Location/target Total offshore Bottom-fixed Floating Tidal Wave
wind offshore wind offshore wind energy energy
Croatia 2030 No target No target No target No target No target
Croatia 2040 25 No target No target No target No target No target
Cyprus 2030 No target No target No target No target No target
Cyprus 204026 No target No target No target No target No target
France 2030 500 27

0 27
500 27
No target No target
France 2040 27 1,500 28

0 28
1,500 28
Greece 2030 No target No target No target No target No target
Greece 2040 22
Italy 2030 90029 No target30 No target No target 1231
Italy 204032 No target
Malta 2030 No target No target No target No target No target
Malta 2040 33 No target No target No target No target No target
Portugal 2030 300 No target 300 No target 70 MW
Portugal 204034 No target No target No target
Slovenia 2030 No potential 35

No potential 35
No potential 35
No No
potential35 potential35
Slovenia 2040
Spain 2030 No target No target No target 50
Spain 204036 No target No target
Among all countries, France is by far the most ambitious in setting targets with respect to offshore
wind technologies. Between 2020 and 2028, the total installed capacity in France should increase
24
Capacity targets for Spain refer to all coastal regions, including non-Mediterranean sites. These targets are
shown in italics in the table.
25
26
27
28
Email correspondence with France’s permanent representation to the European Union on 21 July 2020.
29
(International Energy Agency, 2019)
30
the Italian target capacity of 900 MW by 2030 can be supposed completely bottom-fixed. Elaborations based
on a RSE study (RSE report 10000251, 2010, http://www.rse-web.it/documenti/documento/2906) were
made, based on the information provided by the Italian Permanent Representation in the working
communication, 31.07.2020
31
The 2025 target for industrial plants based on ISWEC device could be 12 MW, Working communication from
the Italian Permanent Representation, 31.07.2020
32
(Ministry of Economic Development (Italy), 2019)
33
34
(Direção-Geral de Energia e Geologia, 2019)
35
Email correspondence with Slovenia’s permanent representation to the European Union on February 19th,
2020.
36
from 0 MW to between 5.2-6.2 MW, including 500 MW in the Mediterranean Sea. By 2040, a total
capacity of 1,500 MW of floating offshore wind should at least be in service in the Mediterranean
Sea. However, this forecast will greatly depend upon the decisions on new tenders made in the
second half of the French energy plan in 2024-2028 and upon the length of administrative
procedures.
Italy and Portugal also stand out with relatively high 2030 offshore wind targets in the region.
Italy’s general offshore wind target amounts to 900 MW while Portugal aims to reach 300 MW of
floating offshore wind capacity by 2030. The wind conditions off the western and northern shores
of Portugal, Spain, and France are generally more suitable for offshore wind generation than wind
conditions off the Mediterranean shores, so the Mediterranean will likely play a smaller part in
these three countries’ ambitious targets.
Only Portugal and Spain have defined targets for wave and tidal technologies in 2030. In general,
the Atlantic waters represent better wave and tidal resources than the Mediterranean Sea. It can
therefore be expected that a large share of the Spanish and Portuguese target will be located off
the Atlantic coast. These targets are, nevertheless, relatively smaller in size compared to the other
technologies in scope with set targets: 50 MW in Spain (Spain's Ministry for Ecological Transition
and Demographic Challenge, 2020a) and 70 MW in Portugal (Direção-Geral de Energia e Geologia,
2019).
Both onshore wind and solar PV national capacity targets will play a key role in achieving countries’
renewable goals. For Italy, France and Spain in particular, national targets in the NECPs count
solar PV technology as the main contributor to meeting the renewable energy targets of the
countries’ power systems. This technology is anticipated to experience the highest increase in
terms of installed capacity in the coming years on a national level. France, Italy, and Spain are
expected see their solar installed capacity increase by 34 GW,37 33 GW, and 33 GW, respectively,
by 2030 (French Ministry for the Energy Transition, 2019; Ministry of Economic Development
(Italy), 2019; Spain's Ministry for Ecological Transition and Demographic Challenge, 2020a).
However, many of the countries’ NECPs do not give a detailed explanation of specific targets or a
roadmap for islands to achieve sustainability goals by 2030 and beyond. Specific targets for islands
are mostly defined in Island Sustainable Energy Action Plans (ISEAPs), an initiative launched by
the EC to engage local authorities in implementing sustainable energy policies on islands.
Municipalities on islands in Croatia, Cyprus, Greece, Italy, Malta, and Spain submitted action plans
with differing ambition levels for 2020. Greek islands represented the highest level of ambition
overall (Navigant & E3 Modelling, 2017). However, only a few islands have submitted updated
targets and plans for 2030.
Except for some specific cases, overall NECPs and the data gathered from countries’ permanent
representations to the EU give an incomplete outlook on regional energy plans for Mediterranean
islands for the coming decade. Corsica in France and Menorca in Spain are two examples where
updated sustainability plans beyond 2020 have been made available. Therefore, determining how
ambitious the targets towards 2030 and beyond are in the Mediterranean region and substantial
differences within the region is not possible at this point.
Table 1-4 gives a country overview of the 2030 targets and 2040 long-term projections for
onshore technologies on Mediterranean islands.
Although little data is available on capacity rollout plans for onshore wind on islands, a very limited
increase in onshore wind deployment is expected in cases where 2030 island capacity targets are
known. This limited increase is mostly due to land use constraints on islands, including high
population density, and strong commitments to protect natural areas (Government of Malta,
2019). Corsica is an exception since it plans to increase its onshore wind capacity fivefold
compared to current 2020 deployments.
According to Cyprus and Malta 2030 targets, solar PV capacities will increase significantly
compared with onshore wind. However, according to a model-based projection of planned policies,
Malta’s 2040 solar PV projected capacity shows that its solar PV capacity deployment would
37
France is expected to reach 34 GW of additional solar capacity by 2028.
decrease from a total installed capacity of 266 MWp to 88 MWp from 2030 to 2040; meanwhile,
the estimated generated electricity from conventional sources and interconnections is expected to
increase in the same time period (Government of Malta, 2019).
Table 1-4: Targets and long-term outlook for onshore technologies in the
Mediterranean region (MW)38
Location/target Solar PV Onshore wind
Croatia 2030 768 1,364
Croatia 204039 1,245 1,684
Cyprus 2030 804 198

50 for concentrated solar power (CSP)
technology
Cyprus 204040,41 1,892 198

500 for CSP technology
France 2028 35,600-44,500 100
France 204042,43 No target No target
Greece 2030 No target No target
Greece 204022 No target No target
Italy 2030 52,000 of which CSP: 880 19,300
Italy 204044 No target No target
Malta 2030 266 0
Malta 204045 88 No target
Portugal 2030 N/A N/A
Portugal 2040 N/A N/A
Slovenia 2030 N/A N/A
Slovenia 2040 N/A N/A
Spain 2030 330 (Menorca) 10 (Menorca)
Spain 204046,47,48 No target No target
38
Capacity targets for Croatia, France and Italy refer to national targets, including the mainland. These targets
are shown in italics in the table.
39
40
41
Email correspondence with Cyprus’ permanent representation to the European Union on March 6 th, 2020.
42
43
(Dodd, 2019)
44
(Ministry of Economic Development (Italy), 2019)
45
46
47
(Regional Government of the Balearic Islands, 2019)
48
(Conseil Insular de Menorca)
Menorca remains one of the most ambitious Mediterranean islands in Spain with a full
decarbonisation plan prepared through 2030. Compared to its peers Mallorca and Ibiza, Menorca
announced that it aims to meet 85% of its electricity demand with renewable sources by 2030.
Additionally, Menorca plans to ramp up its deployment of rooftop PV systems (Conseil Insular de
Menorca). Similarly, the Croatian island Krk started its energy transition in 2011 with the
development of its ISEAP. Krk is now the frontrunner island in Croatia, and it plans to reach 100%
decarbonization by 2030 (Ministry of Environment and Energy, 2019). The ambitious trends set by
Menorca, Krk, and other islands could set an example for other islands to follow.
CSP technology, though not considered in the scope of this study, stands out in some islands’
energy plans. Due to this technology and others, Cyprus is expected to see an increase from 0 MW
in 2020 to 50 MW in 2030 and to 500 MW in 2040 (Biscay Marine Energy Platform (BiMEP)).
Technology capacity targets for the year 2050 are non-existent on a national level, let alone a
regional level. Only a few scenario estimates for onshore technologies have been provided in an
interview with Cyprus’ EC permanent representative. Table 1-5 shows a 2050 scenario estimate for
Cyprus. Given the significant increase in CSP capacity in Cyprus, other countries that include CSP
in their future energy mix might also see a significant rise in CSP installed capacity.
Table 1-5: 2050 scenario estimate for onshore technologies in Cyprus

Location/target Solar PV Onshore wind
Cyprus 2050 1,686 MW 198 MW

1,050 MW for CSP technology
1.1.2 Pathways to meet capacity targets

The pathways to reach to 2030 targets and beyond differ substantially per country. Some
countries have plans in place to carry out recurring tenders in the short and medium terms. France
plans to hold two floating offshore wind tenders in 2022 and annual offshore wind tenders from
2024 until 2028 (French Ministry for the Energy Transition, 2019). For wave and tidal technologies,
however, no plan yet exists to launch competitive tenders in any of the countries in the
Mediterranean region. However, most countries are willing to support wave and tidal projects, and
many count on ocean technologies to some extent in their future energy mix (Direção-Geral de
Energia e Geologia, 2019; Spain's Ministry for Ecological Transition and Demographic Challenge,
2020a).
On the other hand, France, Greece, Italy, and Spain49 have plans to schedule island-specific
competitive tenders for onshore wind and solar technologies (Navigant & E3 Modelling, 2017;
Tsagas, 2018; GlobalData Energy, 2020; Bellini, Spain’s Balearic Islands assign 362 MW of solar in
auction, 2019). Corsica (France) already held island-specific tenders in 2016 and 2017 for solar-
plus-storage projects. After the successful 2018 and 2019 tenders in the Canary Islands, Spain has
now held its first RES tender in the Balearic Islands (Navigant & E3 Modelling, 2017; Tsagas,
2018). Cyprus, Croatia, and Slovenia have no plans for offshore wind development in their NECPs
as indicated in Section 1.1.
Greece aims to reach RES penetration levels in excess of 60% in the non-interconnected islands
(NIIs). For this goal, the Greek Regulatory Authority for Energy (RAE) has issued competitive
tenders for smart islands, focusing especially on hybrid plants that include storage (Government of
Greece, 2019). More specifically, the issued competitive tenders concern the islands of Antipole,
Semi, and Merits, which are pending the relevant Ministerial Decision.50 In addition to these
tenders, Greece grants higher feed-in tariffs to projects on NIIs compared with projects on the
mainland (Navigant & E3 Modelling, 2017). Greece holds technology-specific auctions for projects
on the mainland and on islands that are interconnected to the mainland. The last two solar PV
49
The Spanish Wind Association (AEE) calls for at least 3 GW of offshore (from the 50 GW), source:
WindEurope, 16.07.2020
50
Email correspondence with Greece’s permanent representation to the European Union on 7th August, 2020
auctions took place in 2018. Projects on NIIs are excluded from participating in the auctions
(Government of Greece, 2019).
Table 1-6 and Table 1-7 summarize the approach taken by countries to reach their 2030 targets.
Only France’s offshore wind roadmap is known in detail according to NECPs. Other member states
have no clear strategy defined and are therefore excluded from the overview. Regarding onshore
technologies, some countries choose a support scheme based on competitive auctions and others
choose a feed-in tariff scheme.
Table 1-6: Offshore energy deployment strategy in countries in the

Mediterranean region: 2020-203051
Country Offshore wind Tidal energy Wave
energy
France  2x250 MW floating wind tenders planned in 2022 No tender No tender

planned planned
 Annual 1 GW offshore wind tenders from 2024-2028, no
precise location, Mediterranean or North Sea, is currently
specified
 At least two additional projects of 500 MW each should be
tendered between 2024 and 2028 in the Mediterranean Sea
(extensions of the first two projects)
51
Table 1-7: Onshore energy deployment strategy in countries in the

Mediterranean region: 2020-203052,53,54,55
Country Solar PV Onshore wind
Croatia No island-specific RES support

Pilot programmes
 Krk is frontrunner
 PRISMI project involves six Croatian islands: Korčula and Vis, among others
Cyprus  Capacity-based subsidy for PV systems N/A
 Net metering scheme for PV systems up to 10 kW
connected to the grid for all consumers (residential and
nonresidential)
 Self-consumption systems with compensation on energy
surplus for capacities ranging 10 kW-10 MW for
commercial and industrial consumers
France Island-specific support with solar-plus-storage auctions Onshore wind tenders as in the
mainland: tenders for projects of
wind turbines or more
Greece Technology-specific auctions for islands connected to mainland with feed-in premium
Feed-in tariffs for projects on NIIs
Italy Island-specific support for projects on the 20 smaller non-interconnected islands
 Competitive tender with investment subsidy (financing 60% of CAPEX for the realization of 2-3
innovative and integrated projects)
Technology-neutral auctions for projects > 1MW in larger islands, competing with projects on the
mainland, with a Contract for Difference scheme
 3 auctions in 2020
 3 auctions in 2021
Malta Feed-in tariff for solar PV projects
Portugal N/A
Slovenia N/A
Spain Technology-specific auctions on Balearic Islands
For Malta and the NIIs in Greece, a feed-in tariff scheme is in place to support the development of
solar PV projects in Malta and onshore wind and solar PV projects in Greece. For its part, Cyprus
has a net metering arrangement in place mainly for solar PV operating under the scheme Solar
Energy for All, launched by the Ministry of Energy in 2016. The scheme provides capacity-based
grants for the installation of PV systems in combination with a net metering billing scheme.
Prosumers will be liable to pay for the net electricity used (energy consumed minus energy
produced onsite). This scheme is aimed at small-scale residential and non-residential prosumers
with a capacity of up to 10 kW (In-Cyprus, 2019). Commercial and industrial consumers with
capacities ranging from 10 kW up to 10 MW are eligible to opt into the net billing scheme. Under
this scheme, the prosumer can sell any excess energy produced to the grid at cost, further
reducing the initial solar investment cost. Islands in Croatia, however, do not have any island-
specific support scheme in place. Renewable projects taking place mainly in Krk, Vis, and Korčula
are results of pilot programmes. An example is the PRISMI project of the Interreg MED Programme
that was financed by the European Regional Development Fund until 2018 (Navigant & E3
Modelling, 2017). As reported by Slovenia’s permanent representation to the European Union, no
offshore or onshore potential is available in Slovenia since it has no islands.
52
53
(Martín, 2020)
54
(Bellini, Spain’s Balearic Islands assign 362 MW of solar in auction, 2019)
55
(Dodd, 2019)
1.1.3 Existing and future offshore projects

Several offshore projects are currently in place in the Mediterranean region. Until now, the most
remarkable floating offshore wind developments in the region have taken place in Portugal and
France. In Portugal, the two remaining floating platforms of the WindFloat Atlantic (Phase 1)
offshore wind farm of 25.2 MW were commissioned in June 2020. Phase 1 of the project is
expected to be completed in 2020.
Best practise example

Name Country Key technology Type of project Status
Eoliennes
Floating
Flottantes du France Pilot project Under development
offshore wind
Gulf of Lion
The French government has set out to build a pilot floating wind farm in the
Gulf of Lion in the Mediterranean Sea. The commissioning of the wind farm is
expected in 2022. It is anticipated to be one of the first floating wind farms in
the Mediterranean Sea.
Project details
 The project received consent after a call for projects by the French
government in 2016.
 The consortium consists of three project partners: ENGIE Green, EDPR
Renewables Europe, and Caisse des Dépôts.
 The wind farm will consist of three turbines of 10 MW each (MHI Vestas
V164-10.0 MW turbines) located in the “Leucate” offshore zone about
16 km off the coastal towns of Leucate and Barcarès.
 In 2022 and 2023, France is expected to auction two 25 MW floating
offshore wind sites, which will further increase the floating wind
generation capacity in the Mediterranean. Figure 1-2. Schematic of EFGL
floating wind. Source: https://info-
Project findings efgl.fr/le-projet/le-parc/
 This project is one of the first floating offshore wind projects in the
Mediterranean Sea. This pilot project can enable the development of larger floating offshore wind farms
in the Mediterranean Sea.
More information: https://info-efgl.fr/
In France, ADEME launched a call for tenders in 2017 for which winners have been designated;
three out of four pilot projects between 24 MW and 30 MW each were assigned in the
Mediterranean and are expected to be commissioned by 2021 (French Ministry for the Energy
Transition, 2019)
Taranto Wind Bottom-fixed Commercial

Italy Planned
farm offshore wind project
The first offshore wind farm of the Mediterranean Sea is
expected to be built in 2020 off the coast of the Italian city
Taranto. The offshore wind farm will consist of bottom-fixed
wind turbines with a total capacity of 30 MW.
Project details
 The project reached financial close early 2019, and
development was expected to start at the end of 2019.
 The project is being developed by Italian developer Figure 1-3. Schematic of Taranto fixed-bottom wind
Renexia. farm.
 The wind turbines will be located nearshore and close to Source: http://www.belenergia.com/english-belenergia-
the port of Taranto. developpements-eolien-italie.php
 The Taranto project gained the right for 25 years of
support at a level of €161.70 ($184.20) per megawatt-hour through an Italian renewable energy auction
in December 2016 that mostly allocated support to onshore wind projects.
 The supplier of the turbines is the Germany-based company Senvion. The company has developed a new
offshore version of its 3.0M122 wind turbine for the project.
Project findings
 This project is the first bottom-fixed offshore wind project in the Mediterranean Sea. Lessons learned
from the deployment of this project can be used for further bottom-fixed projects.
 The nearshore wind farm will only consist of bottom-fixed wind turbines.
More information: https://www.rechargenews.com/wind/italy-on-pole-in-race-for-first-mediterranean-
offshore-wind/2-1-552007
Wave and tidal renewable energy technologies are still relatively immature in terms of the
technology development and the available potential in the Mediterranean (see Section 1.4).
However, Italy has been experimenting with these technologies, and some growth potential exists,
given that the technology develops further, and costs decrease substantially.
GEMSTAR Italy Tidal Pilot project Operational
A tidal energy system called Gemstar is deployed in the Strait of

Messina in Italy and has been operational since 2012.
Project details
 GEMSTAR is one of the products of Seapower SCRL, a

consortium with the University of Naples Federico II.
 The system has a capacity of 300 kW.
 The turbine was built by a consortium of Venetian companies.
 One key characteristic of the turbine is its ability to align itself
along the current direction, which allows for a higher yield. Figure 1-4. Illustration of GEMSTAR.
Source: https://tethys.pnnl.gov/project-
Project findings sites/seapower-gemstar-system
 This project explores the potential of tidal energy in the Mediterranean Sea and shows lessons applicable
to similar projects in the future.
More information: http://www.seapowerscrl.com/ocean-and-river-system/gem#slide_6
Table 1-8 gives an overview of offshore projects in the pipeline, which are mostly in the planned
and permitting development stages. For many of these projects, the delivery date is still unknown.
Most offshore wind pipeline activity concerns France, Greece, Italy, and Portugal. Italy also has
existing and planned wave prototype projects.
Table 1-8: Existing and future offshore projects in the Mediterranean

region56,57,58,59,60,61,62,63
Project Country Region Status Technology Commercial Total
Operation capacity
Date (COD) [MW]
GEMSTAR full- Italy Venice Lagoon Development Wave Existing64 0.02

scale prototype
PIVOT WEC Italy Civitavecchia Development Wave Existing Unknown

prototype harbour
Beleolico Italy Mediterranean With permits Bottom- 2020 30.0

fixed
WindFloat Portugal Atlantic Ocean Commissioned Floating 2020 25.2

Atlantic Phase 1
SINN POWER Greece Crete Development Wave 2021 0.75

Floating WEC
array
EolMed France Gulf of Lion Permitting Floating 2022-2023 28.5

(Gruissan)
Les éoliennes France Gulf of Lion Permitting Floating 2022-2023 30

flottantes du
Golfe du Lion
(EFGL)
(Leucate)
Provence Grand France Gulf of Lion Permitting Floating 2022-2023 24.0

Large (PGL)
(Faraman)
2022 Tender France Gulf of Lion Tender Zone Floating Unknown 250.0
zone I
2022 Tender France Gulf of Lion Tender Zone Floating Unknown 250.0
zone II
2024-2028 France Unspecified Tender Zone Bottom- Unknown 1,000

Tender zone fixed
Pleiades Aioliki Greece Gulf of Petalioi Development Bottom- Unknown 450

SA fixed
TERNA ENERGY Greece Thracian Sea Development Bottom- Unknown 585

and Aioliki fixed
Povata
Trainoupole Os
partnership
56
(WindEurope, 2019a)
57
(Hogan Lovells, 2020)
58
59
(4C Offshore, 2020)
60
(Ocean Energy Systems, 2020)
61
(Coiro, Troise, & Bizzarini, 2018)
62
(SINN Power Projects, 2020)
63
(Greek Regulatory Authority (RAE), 2020)
64
Existing wave prototype projects are undergoing further research and development, hence their status is still
under “development”

Operation capacity
Date (COD) [MW]
Thrakiki Aioliki Greece Sea Area South With permits Bottom- Unknown 216
1 SA of Alexandrou- fixed
polis
Kyon Greece Sea Area of With permits Bottom- Unknown 300

Municipality of fixed
Kymi and
Avlonas
City Electric SA Greece Plaka Development Bottom- Unknown 498

fixed
TERNA ENERGY Greece Methones-Keros Development Bottom- Unknown 320

fixed
Rokas Aioliki Greece Plaka-Keros- Development Bottom- Unknown 486

North Greece Agia Eirini fixed
Banco di Italy Adventure Bank Early Floating Unknown 228.0

Pantelleria e Development
Banchi di
Avventura
Golfo di Gela Italy Sicily/ Planned Bottom- Unknown 136.8

Mediterranean fixed
WindFloat Portugal Atlantic Ocean Planned Floating Unknown 125.0

Atlantic Phase 2
Kobold I Italy Mediterranean Operational Tidal Unknown 0.05
GEM Italy Mediterranean Consent Tidal Unknown 0.5

Demonstrator Authorized
In terms of onshore technologies on islands, solar PV capacity is increasingly coming online,

specifically in urban areas. This increase is especially the case for islands in France, Greece, Italy,
and Spain, where a significant growth in PV capacity is expected for small and large rooftops
(Rollet, 2019; Stavropopoulou, 2019). To a lesser extent, large-scale solar projects are expected
to increase. This is mainly driven by the new Spanish self-generation energy policy and the
scheduled auctions for French and Greek islands (Valdivia, 2019; Navigant & E3 Modelling, 2017).
Also, Greece and Cyprus are realising projects that may be developed under the following three
policy schemes: net metering; government-set feed-in tariffs; and feed-in tariffs via competitive
tenders (Balkan Green Energy News, 2019). In Croatia, solar projects can be developed under the
premium tariff support scheme allocated through tenders (Balkan Green Energy News, 2019).
Many of these projects are rather small in size; therefore, providing an exhaustive list of all
individual developments in the region within this project is not possible. Table 1-9 presents a list of
selected projects across the Mediterranean region.
Table 1-9: Selection of planned and ongoing onshore wind and solar PV projects
on Mediterranean islands65,66,67,68,69,70,71,72
Operation Capacity
Date (MW)
Pissouri Cyprus Cyprus Under Solar PV 2019 4.5

project construction
Solar project Cyprus Cyprus Advanced Solar PV 2019 4.0

development
Solar project Cyprus Cyprus Advanced Solar PV 2019 4.0

development
Solar project Croatia Vis Operations Solar PV 2020 3.5
Solar project Croatia Cres Advanced Solar PV Unknown 6.5

development
Solar project Croatia Krk Advanced Solar PV 2020 5.0

development
Rooftop solar Croatia Krk Planning Solar PV Unknown 36.8

PV systems
Utility-scale Croatia Krk Planning Solar PV Unknown 4.0

solar project
Wind project Croatia Krk Planning Wind Unknown 25.2
Tenesa France Corsica Advanced Wind 2020 12.0

development
Ersa-Rogliano France Corsica Unknown Wind Unknown 12.0

(repowering)
Giuncaccio France Corsica Planning Solar PV and 2019 2.0

project storage
Pancheraccia France Corsica Planning Solar PV and 2019 1.5

project storage
Giurone France Corsica Planning Solar PV and 2018 4.8

project storage
Solar PV and France Corsica Planning Solar PV and 2020 1.5

storage storage
project
Green Island Greece Agios Under study Wind, solar Unknown 0.9 (Wind)
Efstratios PV, and
storage 0.2 (PV)
65
(Balkan Green Energy News, 2019)
66
(Todovoric, 2019)
67
(Rollet, 2019)
68
(Stavropopoulou, 2019)
69
(Dodd, 2019)
70
(Rogulj, 2020)
71
(Reve, 2020)
72
(DEM - Energy, 2017)

Operation Capacity
Date (MW)
Smart Island Greece Symi Planning Wind, solar 2021 Unknown

Pilot 1 PV, and
storage
Smart Island Greece Astypalea Under study Wind, solar Unknown Unknown
Pilot 2 PV, and
storage
Smart Island Greece Megisti / Under study Wind, solar Unknown Unknown
Pilot 3 PV, storage
Kastelori-zo
Hybrid station Greece Ikaria Operation Wind and Unknown 2.7

project hydro
TILOS project Greece Tilos Operation Wind, solar Unknown 0.8 (Wind)
PV, and
storage 0.2 (PV)
Solar project, Italy Sardinia Early Solar PV 2022 5.0

RES auction development
Wind project Italy Sicily Advanced Wind 2021 20.0

development
Son Salomó Spain Menorca Advanced Solar PV Unknown 49.8

(ext.) development
Son Angladó Spain Menorca Early Wind Unknown 20.7

development
46 projects, Spain Mallorca Early Solar 2022 206.0

RES auction I development
6 projects, Spain Menorca Early Solar 2022 62.0

RES auction I development
1 project, RES Spain Ibiza Early Solar 2022 6.0

auction I development
1 project, RES Spain Forment- Early Solar 2022 2.0

auction I era development
Best practice example
Commercial
TILOS Greece Energy island Operational
project
Project TILOS concerns the development of a hybrid

energy system (smart microgrid) on the island of Tilos
solely based on renewable energy sources. The project’s
goal is to reduce dependency on imported, fossil-fuel
based electricity from the island of Kos, improve system
reliability, and potentially turn Tilos in an exporter of
renewable energy to Kos.
Project details
Figure 1-5. the Tilos project Source:
https://www.tiloshorizon.eu/
 The project is an EU Horizon 2020 (Grant Agreement
No 646529) demonstration and research project with 13 project partners from seven European states.
 Project TILOS develops solutions for reaching the goal of the European Agenda 2020 (Local / small-scale
storage-LCE-08-2014). The total cost of the project is around 15M€ for a European grant of 11
M€. TILOS started in February 2015 and ran for 4 years.
 TILOS is coordinated by the Technological Educational Institute of Piraeus (TEIP) from Athens in Greece.
 The island has a total of 500 inhabitants. In the summer, the population on the island grows to 3,000
people as a result of tourism.
 On Tilos an 800-kW wind turbine was installed together with a 160 kW PV park, a new type of NaNiCl2
FIAMM battery (2.4MWh/800kW), an energy management system and smart meters.
Project findings
 Besides the Danish island Samsø, Tilos is the first island that is fully running on locally generated
renewable electricity.
 As a frontrunner, this project can be an example for the development of fully renewable electricity
systems for other islands in the Mediterranean Sea.
More information and source picture: https://www.tiloshorizon.eu/
1.2 Technology assessment

Task 1.2 assessed the potential suitable generation technologies in the Mediterranean region. The
technology assessment was conducted for the categories and criteria detailed in Table 1-10.
Table 1-10: Framework for assessment of potential generation technologies

Assessment Assessment criteria Criteria description
category
Renewable energy Feasibility of the technology due to resource and

resource environmental conditions: water depth, distance from shore,
wind speeds, wave energy, insolation, tides, and other uses of
the sea such as fishing, shipping, etc.
Technical
Potential production per Capacity factors of technologies for 2030 and 2050
installed capacity
Scalability Degree to which the technology is easily scalable and the

impacts of other factors such as land availability, population
density, economic activity, maritime transport, and
environmental restrictions
Grid interconnectivity in Degree to which RES technology can easily be connected to

the region and integrated in the power system
Current investment and CAPEX and OPEX levels in 2020

operational cost levels
Economic Projected investment CAPEX and OPEX levels in 2030 and 2050
and operational cost
levels
Demand matching Extent to which power production occurs at times of high

production profile demand in bidding zones where it can be transported easily to
the grid
Impact on environment Impacts of the technology such as noise on the environment,

including wildlife and vegetation
Environmental
impact
Social acceptance Degree of acceptance by society due to visual impact from

shore and impact on tourism
Social
acceptance
Support schemes for Policy support in the form of RES auctions, financial incentives
RES technology (premium tariffs), or other initiatives (pilot programmes)
Permitting procedures Extent to which the current regulatory frameworks allow for
Regulatory for RES technologies, development of projects and whether caps on deployment
regulatory quantity exist
limits
A metric or key performance indicator (KPI) is defined to measure each assessment criterion. Each
RES technology is scored for each criterion based on the KPIs laid out in Table 1-10.
Table 1-11: Scoring methodology for assessment criteria

Indicator Description
Indicates that the RES technology has a poor performance with respect to the criterion
Indicates that the RES technology has a moderate performance with respect to the criterion
Indicates that the RES technology has a good performance with respect to the criterion
Table 1-12 gives an overview of the outcome of the qualitative technology assessment. Sections
1.2.1 through 1.2.5 show a qualitative analysis conducted per assessment criterion to explain the
KPI scoring presented in Table 1-12.
Table 1-12: Outcome of the qualitative technology assessment

Assessment criteria Bottom-fixed Floating Wave Utility-scale Rooftop Onshore
offshore wind offshore & tidal solar PV solar PV wind
wind energy
Technical
Renewable energy
resource
Potential production per

installed capacity
Scalability
v
Grid interconnectivity in
the region
Economic
Current investment and

v
operational cost levels
Projected investment
and operational cost
levels
Demand matching
production profile
Environmental impact
Impact on environment
Social acceptance
Social acceptance
Regulatory
Support schemes for

RES technology
Permitting procedures
for RES technologies,
regulatory quantity limits
1.2.1 Technical assessment

Many sites in the Mediterranean region are available for the development of floating offshore wind
farms (Soukissian et al., 2017), given the area available with a water depth up to 1,000 m within
200 km from shore (see Section 1.3 for the spatial constraint analysis). Floating offshore wind
technology has less stringent requirements for soil conditions and geotechnical studies, shorter
weather windows, and fewer, simpler, and less-costly operations during installation than bottom-
fixed offshore wind technology (WindPlus, 2017). Bottom-fixed offshore wind is limited mostly due
to the great water depths that characterize the Mediterranean Sea. However, a few sites exist in
the northern Adriatic Sea where bottom-fixed technology would be feasible (Soukissian et al.,
2017).
From a scalability perspective, floating offshore wind has the highest potential to scale up offshore
technologies. However, the current no existing offshore wind industry’s supply chain in the
Mediterranean region hinders its scoring compared to onshore wind and solar PV technologies,
which are already established.
Wave and tidal energy resources are rather low in the Mediterranean Sea compared to other areas
where the ocean energy sector is growing, such as in the UK. Tidal turbines require a minimum
current speed, and experts have been considering only a few sites such as Gibraltar and the Strait
of Messina. The lack of tides that meet these minimum requirements could limit the feasibility and
scalability of wave and tidal technologies in the Mediterranean region. All offshore technologies
could face scalability constraints in specific sites, such as nearshore coastal areas, due to
competing economic activity, including tourism, fishing, maritime, and shipping activities that take
place in the Mediterranean Sea (Government of Malta, 2019) as it is one of the busiest seas in the
world.
The lack of a sufficiently developed power grid in the region is another aspect that could slow down
the deployment of large-scale offshore technologies such as offshore wind. This situation would
impact wave and tidal technologies to a lesser extent since project capacities are generally lower.
The existing power grid around the islands would not be capable of integrating very large amounts
of variable renewable energy (Soukissian et al., 2017). To a lesser extent, increased penetration of
onshore wind, utility solar, and rooftop solar PV on islands may require upgrading the existing low
voltage and medium voltage distribution networks on islands. For onshore wind projects, grid
interconnectivity may become an important issue since wind sites tend to be located further away
from the grid.
Solar irradiation is possibly the most homogenous resource across the region. Mediterranean
islands have a relatively high wind resource potential (explored in Section 1.4) that is currently
largely untapped.23 However, large-scale solar PV and onshore wind encounter significant barriers
to their development. Mediterranean islands are highly populated (Navigant & E3 Modelling, 2017),
thereby limiting scalability due to land use restrictions. Rooftop solar PV, however, has a better
technical outlook as it can be deployed easily on small, medium, and large domestic and industrial
roofs.
In terms of potential production per installed capacity, all wind technologies benefit from reaching
the highest capacity of the technologies considered. The capacity factor for onshore and offshore
wind is approximately 40% based on the analysis in Section 1.4.1. Utility-scale and rooftop solar
PV have an estimated capacity factor per solar module of 19% in 2030 and 23% in 2050. The
capacity factor for wave energy is 14% while tidal energy reaches 6% in Italy and 10% in Spain.
1.2.2 Economic assessment

This section assesses the investment and operational costs of the RES technologies discussed in
this report. Note that the LCOE for each technology is assessed specifically in Section 1.5 based on
current and future cost levels and yield. Less mature technologies such as floating offshore wind,
wave, and tidal have higher CAPEX and OPEX levels compared to bottom-fixed offshore wind and
onshore technologies. Figure 1-26 gives an overview of the specific cost levels used for 2030 and
2050 per technology. The cost reduction potentials in the case of the less mature technologies will
determine the technology’s economic attractiveness and scalability in the mid to long term.
Floating offshore wind, for example, shares a large part of the cost base with bottom-fixed
offshore wind technology, especially in relation to turbine technology. The floating wind industry
can therefore already benefit from and build on the lessons learned from the traditional offshore
wind industry. The focus on cost reduction opportunities will naturally shift to the foundational
technologies. Cost reductions could be achieved in large part through industrialising the value
chain to optimise substructure and mooring designs, which would reduce the unitary cost per
tonne, and through identifying more efficient methods for installation, operations and maintenance
(O&M). However, uncertainty still exists regarding the lift off and subsequent cost developments of
this novel technology and industry, though some already expect cost parity with bottom-fixed
offshore wind by 2030 (Irena, 2016; Utility Week, 2020).
The production profile of each technology is evaluated by the extent to which power is produced
during periods of high demand. Despite competition from mainland onshore solar energy,
relatively high value of Mediterranean offshore energy is expected in the summer season due to
tourism and during daytime hours due to demand for air-conditioning. Solar PV technologies
therefore have a natural fit with periods of relatively high demand in the Mediterranean area
according to country-specific load patterns (ENTSO-E, 2019b). Other technologies such as
offshore and onshore wind, wave, and tidal have production patterns that do not necessarily
coincide with high demand periods as they also see high production occurring at night. Although
wind and wave power complement solar power on a seasonal level since they typically produce
most power during the winter months, they do not necessarily produce at the hour when the
demand or value of power is highest. For a more detailed and quantitative assessment, production
profiles of all technologies will be used in the power market modelling analysis in Tasks 2 and 3.
1.2.3 Environmental assessment

The Mediterranean Sea is home to very rich ecosystems with high levels of biodiversity and
autochthonous species. Many protected areas and natural reserves have been established by the
EU member states and the EU Natura 2000 network, which provides an overview of the number
and size of terrestrial and marine sites designated under the Birds and the Habitats Directives
(European Environment Agency, 2018). Conservation areas of high priority and ecological
relevance can be found in all Mediterranean marine subregions. The average size of Marine
Protected Areas (MPAs) located within the range of 1-12 nautical miles varies per subregion: ~350
km2 in the western Mediterranean Sea, ~30 km2 in the Ionian and central Mediterranean Seas,
~20 km2 in the Adriatic Sea, and ~100 km2 in the Aegean-Levantine Sea. For MPAs beyond 12
nautical miles, the western Mediterranean Sea hosts the largest MPAs with an average size larger
than 1,000 km2. In addition, approximately 70-80% of the MPAs within each Mediterranean
subregion have sizes of around 15 km2 (Environment European Agency, 2015).
Environmental impact assessments for offshore wind, wave, and tidal projects could face issues in
some locations, thereby limiting their potential deployment area. In Malta, for example, an
environmental impact assessment for the development of the Sikka l-Bajda wind farm determined
negative impacts on marine geology and marine life in the area (Government of Malta, 2019).
Consequently, the development of the wind farm was abandoned.
Large-scale onshore wind and solar PV plants could also negatively affect flora and fauna onshore
by influencing migrating birds (Zwart, Mckenzie, Minderman, & Withingham, 2016). For example,
in France, bird migration towards Africa through the Gulf of Lion is an essential environmental
constraint that must be taken into account when identifying the right zones for floating offshore
wind farms. Also, islands are rest areas for migrating birds. However, this impact can be mitigated
with proper monitoring prior to the investment. Rooftop solar PV systems generally do not
interfere with nature since many of these systems are located in urban or industrial areas.
1.2.4 Social acceptance assessment

Mediterranean economies rely heavily on tourism, as it represents more than 70% of production
value added in the region. The dependency on tourism has affected many offshore wind farm
developments along the coasts of France, Spain, Italy, and Greece. Many of the projects are now
cancelled or dormant, such as the Parco eolico Marino Gargano Sud project in Italy (Soukissian et
al., 2017; Foggia Today, 2013). Local authorities in coastal regions expressed strong opposition to
the realization of these projects, arguing that the visual impact could adversely affect tourism. Due
to their lower visual impact, wave and tidal technologies may attract less opposition from local
authorities and other stakeholders and, consequently, may be more suitable in areas with
abundant tourism and economic activities. Solar PV is mainly opposed on a utility scale, e.g. due
to competition with agricultural land (Bellini, Is solar eroding too much land? The EU thinks not,
2019). Project sizes for utility-scale solar PV on Mediterranean islands range 1.5-7.5 MW, with a
few cases reaching capacities of up to 50 MW. However, relatively small standalone PV projects of
0.1 MW or less would probably benefit from greater social acceptance since these could be
developed by individual investors such as local farmers. For similar reasons as utility-scale solar
PV, utility-scale onshore wind projects face opposition from multiple stakeholders.
The introduction of Multiuse Platforms at Sea (MUPs) could help overcome strong opposition from
local stakeholders. For example, in 2018, Sicily’s regional government decided to revoke licenses
that had been granted to new solar PV and onshore wind projects. The regional government’s aim
was to assess the impact on the landscape and develop new regional spatial planning.23 Projects
like MERMAID (Stuiver, et al., 2016) focus on the technical perspective to assess the feasibility of
combining different activities at sea and the visionary perspective to facilitate social acceptance
that will ensure the required support for future sustainable activities in European seas. Another
MUP project worth mentioning is the TROPOS project (European Commission, 2015). Its objective
was the development of a floating modular multiuse platform system for use in deep waters. The
TROPOS approach focuses on the modular development in a way that ensures that the multiuse
platform system can integrate a range of functions from the transport, energy, aquaculture, and
leisure sectors in a greater number of geographical areas than if it was a set platform design.
1.2.5 Regulatory assessment

The NECPs of different member states demonstrate an overall lack of adequate policies that could
constitute a solid regulatory framework favourable to the development and scalability of offshore
wind in the Mediterranean region and the implementation of more wave and tidal flagship projects.
A few countries have set targets for offshore wind towards 2030 and long-term, model-based
projections for 2040. Italy has expressed willingness to enhance regional cooperation with
neighbouring countries based on sharing project developments at sea (Direção-Geral de Energia e
Geologia, 2019; French Ministry for the Energy Transition, 2019; Ministry of Economic
Development (Italy), 2019). Spain has proposed introducing tenders aimed at boosting offshore
wind and ocean energy technologies by providing public financing if required. However, no further
calendar details are yet known. More certainty about potential volumes and timelines is expected
after the ongoing marine spatial planning in Spanish waters is finalized. At the time of this report’s
publication, only France is increasing certainty in the project pipeline by scheduling two upcoming
floating offshore wind tenders (French Ministry for the Energy Transition, 2019). Therefore, the
regulatory framework for offshore technologies does not yet sufficiently support concrete project
development of offshore energy projects in most parts of the region, as addressed in Section
1.1.2.
In terms of permitting procedures, countries such as Portugal have adapted the consenting
procedures to better suit wave energy developments. The deployment duration and the capacity
installed drive the need to issue either a license or a concession. A license is required for wave
energy devices that are deployed for less than 1 year and have an installed capacity below or
equal to 25 MW. For lengthier deployment periods and installed capacities higher than 25 MW, a
concession is mandatory (Simas, 2015). France has introduced a new set of rules gathered in
three different codes: the Energy Code, the Environment Code, and the Code of Public Property.
These new laws contribute to a clear governance of the steps in the process of offshore
developments and a simplification of permitting procedures (Hogan Lovells, 2020). In Spain, Royal
Decree 1028/2007 established two authorization processes for the development of offshore energy
generation plants: a simplified version for capacities lower than 50 MW and a regular process for
capacities above 50 MW. Currently, Spain’s marine spatial planning framework is under review,
and the authorization process may also undergo changes in the short term (The Institute for
Diversification and Energy Saving, 2020). From experience in the North Sea, marine spatial
planning highly influences the consenting process for proposed ocean energy and offshore wind
projects (Simas, 2015). Overall, this is currently lacking in Mediterranean member state countries.
In addition, limited, burdensome legal frameworks or lack thereof for offshore energy projects
creates further uncertainty among developers (WindPlus, 2017).
In contrast, the amount of existing island-specific policies with varying characteristics

demonstrates that islands’ energy challenges are high on the political agenda, as presented in
Section 1.1.2. As outlined in Table 1-7, support schemes for onshore wind and solar PV
technologies appear favourable across the region, especially for solar PV. Existing island-specific
RES support policies, including auction schemes, feed-in tariffs, and pilot programmes, aim to
achieve a reduction in energy system costs. This common issue is shared by many member states
in the Mediterranean region (Navigant & E3 Modelling, 2017).
1.3 Spatial constraint analysis

Task 1 aimed to identify the areas and sites in the Mediterranean region with the greatest cost-
effective potential and performance ranking, used in Task 2 and Task 3. Task 4 analyses
challenges and barriers in detail and provides part of the input to Task 1.
This task narrows down the Mediterranean Sea to suitable boundaries for applicable renewable
energy technologies. A spatial constraint analysis is employed to determine locations available for
power generation. Following identification of those locations, the technical energy potential is
determined by using a raw resource map for each technology under investigation. Economic
potential determination will follow by using technology cost figures.
1.3.1 Starting point geographical analysis

The scope of this study is limited to the European Mediterranean countries of Croatia, Cyprus,
France, Greece, Italy, Malta, Portugal, Slovenia, and Spain. The Exclusive Economic Zones (EEZ)
define the geographical regions allotted to different countries for resource potential calculation.
The countries have jurisdiction only on the EEZ seabed, and the sea surface is international
waters. Installing offshore technologies, even floating ones, requires use of the seabed. In
practice, international agreements are expected to form, giving the exploration right to the country
that controls the seabed with high probability; therefore, this report’s approach should be a good
approximation. In the spatial constraint analysis, no legal aspects were considered that could limit
using the EEZ zones for developing offshore renewables. Legal barriers will be discussed later in
Task 4.
The EEZ areas are the first exclusion criterion within the Mediterranean Sea for the geographical
and resource analysis. Note that some EEZs, though located within the European Mediterranean
Sea, belong to countries that are not members of the EU. These zones are also excluded from the
analysis.
Figure 1-6 shows the EEZs of EU countries in the Mediterranean Sea. The next section presents
the exclusion factors applied in the analysis.
Figure 1-6: EEZs of EU countries in the Mediterranean Sea73

(Source: (Vlaams Instituut voor de Zee (VLIZ), n.d.) )
1.3.2 Natural exclusion zones and conservation areas

Offshore wind farms have the potential to act as a new type of habitat for marine wildlife, leading
to an increased biodiversity of benthic organisms, marine mammals, and some bird species
(Lindeboom et al., 2011). However, in the development phase of a new offshore project, the
installation of and the presence of large vessels can lead to disturbances of the marine
environment and existing species. For this offshore energy potential analysis of the Mediterranean
Sea, existing nature protection zones are excluded. The analysis considered three distinct
datasets: Natura 2000, rocky reefs, and CoCoNet. It also investigated the influence of bird
migration routes.
Natura 2000 is a European network of protected areas, offering a haven to Europe’s most valuable
and threatened species and habitats. It covers 8% of the European marine territory, including the
Mediterranean Sea. The objective of these Natura 2000 sites is to ensure long-term survival of
Europe’s most valuable and threatened species and habitats (European Commission, 2020c).
Therefore, these protected sites are generally assumed to be not viable for the development of
offshore energy systems, so all Natura 2000 sites are classified as exclusion zones for this study.
Rocky reefs offer shelter to diverse marine wildlife species as well as corals (Sala et al., 2011) and
are therefore also classified as exclusion zones. The CoCoNet study is published by the European
Maritime Spatial Planning Platform and identifies groups of MPAs in the Mediterranean and Black
Seas. Figure 1-7 presents the exclusion of Natura 2000 sites and rocky reef areas.
Figure 1-7: Exclusion of Natura 2000 sites74 and rocky reef areas75
(Source: (European Environment Agency, n.d.), (National Center for Ecological Analysis and
Synthesis (NCEAS), 2008) National Center for Ecological Analysis and Synthesis (NCEAS),
retrieved from https://knb.ecoinformatics.org/view/doi:10.5063/F1JW8C4R)
Total exclusion of Natura2000 sites would result in dismissal of high development areas in terms of
resource potential and economic potential for floating wind turbines. The most important affected
area is in the Gulf of Lion, which has a high resource potential with one of the highest wind speeds
in the Mediterranean as shown in Figure 1-15. The location of the proposed production areas in the
Gulf of Lion are shown Section 1.6 in Figure 1-38 and are within the area labelled 01.
73
The EEZ areas are defined as the geographical regions allotted to the different countries for resource
potential calculation.
74
(European Environment Agency, n.d.)
75
(National Center for Ecological Analysis and Synthesis (NCEAS), 2008)
Figure 1-8 shows the impact of the Natura 2000 sites on the selected production areas. As this
specific Natura 2000 area in the Gulf of Lion is designated for sea bottom conservation, the effect
of floating wind turbines should be relatively insignificant as turbines are only anchored in the sea
bottom (compared with the immersive foundations of bottom-fixed wind turbines). Another reason
for the expected low impact is the assumed offshore wind resource density of 7 MW/km 2 (see
Section 1.4.1). Combined with increasing wind turbine sizes (already up to 7 MW), spatial impact
is expected to be mitigated easily. Furthermore, some projects are already developed in this area
in the Gulf of Lion, so this area is assumed to be available for development of floating technologies
with careful regard for restrictions.76
Figure 1-8: TMAs and production areas proposed in Section 1.6 overlap with
Natura 2000 areas in the Gulf of Lion
This report also considered protection areas identified in the CoCoNet study. Published by the
European Maritime Spatial Planning Platform, this study identifies groups of MPAs in the
Mediterranean and Black Seas (Grande & Foglini, 2016). This report investigated the extent to
which these MPAs will cause additional spatial exclusions other than those already identified in
other protection datasets. The most notable area identified is the Pelagos Sanctuary for
Mediterranean Marine Mammals. The Pelagos Sanctuary is the blue hatched area north of Corsica
shown in Figure 1-9. While this area is large and overlaps with one of the selected technology mix
and production areas, activity in the sanctuary is not restricted. The sanctuary seeks to ensure
that human activities are compatible with the presence of native species (Pelagos, 2012).
Therefore, the area is assumed to be available for development with careful regard for restrictions.
76
The area is too deep for bottom-fixed technologies.
Figure 1-9: National and international protected sites identified by CoCoNet

(Source: CoCoNet)
Bird migration routes in the Mediterranean Sea area are concentrated on the shortest stretches of
sea between Europe and Africa. These stretches are the Strait of Gibraltar and the crossing
between western Sicily and Tunisia. In the Strait of Gibraltar, migration routes should have little
impact because project development is not expected to occur there due to exclusion by high
intensity shipping lanes. However, a proposed development area remains between Sicily and
Tunisia that can potentially effect bird migration. This area southwest of Sicily is the area labelled
03 in Figure 1-38, and it overlaps with bird migration routes between Europe and Africa.
Several measures can mitigate the effects of offshore development on birds, including shutdown,
attraction avoidance, luring, and deterrence. This study considers shutdown. To reduce the bird
mortality rate, avian radars are available on a commercial level to detect migrating flocks and shut
down a wind farm’s production for brief periods of time. One manufacturer reports that these
shutdown periods are few (less than 4 hours during springtime) and have a very limited effect on
the availability of a wind farm (STRIX, 2017). Studies have shown that wind farm shutdowns can
lead to a 50% reduction in the bird mortality rate with only a 0.07% loss in energy production
(Lucas, 2012). The effects on bird migration can be mitigated, and this study includes the area
between Sicily and Tunisia with only a negligible decrease in resource potential.
1.3.3 Maritime use

The maritime use constraints considered in this study include:
 Artisanal fishing
 High intensity shipping lanes
 Munition dump areas
 Production platforms for oil & gas
Commercial and artisanal fishing are very important activities in the Mediterranean Sea. Artisanal
fishing refers to fishing practices undertaken by small-scale, low technology, individual fishing
households as opposed to commercial companies. These activities mostly take place close to shore
and have limited flexibility with displacement. Therefore, high intensity artisanal fishing areas have
been excluded from the available areas for offshore energy production.
Maritime transport is a traditionally strong economic sector in the Mediterranean Sea. The
Mediterranean Sea is among the world’s busiest waterways, accounting for 15% of global shipping
activity by number of calls.77 Therefore, high intensity shipping lanes are excluded from the
available area for offshore energy production. High traffic shipping lanes will most likely not be
identified as a potential offshore wind zone. A low traffic shipping lane might be willing to
accommodate a wind park.
Military activity in the Mediterranean Sea can form another obstacle for the development of
offshore energy development, but information on the location of military activities is very difficult
to come by. However, concerns do exist regarding dumped munitions. This is especially relevant in
the Adriatic-Ionian Sea (European Commission, 2019). The known munition dump areas are
excluded from the analysis in this study. While probably not all dump areas would exclude
renewable energy generation, their exclusion acts as a proxy for the unavailable military activity
area.
A standard 500-meter safety zone exists around offshore production platforms for oil & gas. This
zone requires that vessels keep a minimum distance of 500 m from a production platform.
Therefore, an exclusion zone with a 500-meter radius is defined around each production platform
in the European Mediterranean Sea in this study. Only existing oil & gas facilities are considered.
Figure 1-10 shows the available area after exclusion of artisanal fishing areas, high intensity
shipping lanes, military munition dump sites, and offshore production platforms.
Figure 1-10: Exclusion of artisanal fishing areas,78 main shipping routes,78

military munition dump sites,79 and offshore production platforms79
1.3.4 Technology-specific exclusions

The technologies considered have specific zonal exclusion criteria based on geographical
constraints. For reasons related to visibility from shore, in the Northern Seas, wind turbines are
generally built outside of the coastal region, defined by 12 nautical miles from shore. This holds
true for bottom-fixed and floating bottom wind turbines. This report did not consider hub heights
of offshore wind turbines to trigger any change in this spatial constraint.
Installation, operation, and maintenance costs are proportional to the distance to shore. From
200 km onwards, it is generally not economically viable to build and maintain offshore wind farms
and wave energy installations. Offshore hubs might allow for larger distances, but this option is not
considered here. Also, deep water hubs are difficult to develop. It turns out that 200 km is not a
77
Unique identifier of a ship or boat
78
(National Center for Ecological Analysis and Synthesis (NCEAS), 2008)
79
(EMODNET, 2020)
limiting factor anywhere because of the large depth and steep slope of the Mediterranean seafloor.
There were no other technical or legal reasons for the 200 km limit.
In addition to the distance to shore, depth is another determining factor (National Centers for
Environmental Information, n.d.).80 Bottom-fixed wind turbines are generally built in locations with
a maximum depth of 50 m (International Energy Agency, 2019). A 1000-meter maximum limit
exists for floating wind and wave energy installations. Table 1-13 summarises the distance and
depth limitations. The remaining areas available for the development of bottom-fixed wind,
floating wind, and wave energy installations are presented in
Figure 1-11, Figure 1-12, and Figure 1-13, respectively.
Table 1-13: Specific limitations of offshore energy production technologies

Limitation Bottom-fixed wind Floating bottom Wave energy
turbines wind turbines
Minimum distance to shore (km) 22.281 22.2 0

Maximum distance to shore (km) 200 200 200
Maximum depth (m) 50 1,00082 100,085
Figure 1-11 shows the available area for bottom-fixed wind turbines after applying additional
technology-specific exclusions, depth, and distance to shore. This figure shows the area available
for technology development with all geographic constraints considered.
80
This report uses the global ETOPO1 relief dataset from NOAA
(https://www.ngdc.noaa.gov/mgg/global/global.html). This dataset includes bathymetric data. The dataset
is checked and in accordance with the bathymetry from EMODNET (https://portal.emodnet-
bathymetry.eu/).
81
22.2 kilometres corresponds to 12 nautical miles, a customary minimal distance in offshore wind
development in the North and Baltic Seas.
82
Connection to installations at these depths is possible: Today a relevant number of cables running below
1,000 m sea depth. TERNA ENERGY’s cable SAPEI, interconnecting Sardinia with continental Italy, runs at
1,600 m depth.
Figure 1-11: Available area for bottom-fixed wind turbines based on

geographical constraints
Figure 1-12 shows the available area for floating wind after applying additional technology-specific
exclusions, depth, and distance to shore. This figure shows the area available for technology
development with all geographic constraints considered.
Figure 1-12: Available area for floating wind turbines based on geographical
constraints
Figure 1-13 shows the available area for wave energy installations after applying additional
technology-specific exclusions, depth, and distance to shore. This figure shows the area available
for technology development with all geographic constraints considered.
Figure 1-13: Available area for wave energy installations based on geographical
constraints
1.3.5 Technology-specific resource exclusions

To determine locations with suitable renewable resource potential, annual average resource values
are needed for all locations in the Mediterranean. The solar energy resource information was
obtained from NASA SSE in the form of solar irradiation given in kWh/m2/day (NASA SSE, n.d.).
Figure 1-14 shows the geographical variation of the solar irradiation.
Figure 1-14: Solar irradiation levels in the Mediterranean region

For wind energy technology, wind speed data in m/s at 10 m above sea level is available (National
Centers for Environmental Information Climatic Data, n.d.). From the available climatological
average wind speed data time series, quarterly and annual average wind speeds at hub height are
calculated at a 1/60-degree raster map. The climatological annual average wind speed data is
shown in Figure 1-15.
Figure 1-15: Annual average wind speed at 10 m above sea level

Wave energy resource data is available in kW/m. Annual average wave resource data is available
at individual buoy locations from two publications (Arena F. et al., 2015; Pontes M.T et al., 1998).
Using spatial interpolation techniques, an approximate wave resource map was created from the
point buoy data. The level of available wave resources is presented in Figure 1-16.
Figure 1-16: Wave energy resource level

In addition, locations are excluded where the resource value is below a certain critical value. This
cut-off can be thought of as reflecting the economic competition for wind power or wave energy
with other generation technologies and economic investments. Resource levels below the critical
value for a technology are assumed to be too low to make an economically feasible investment
possible for that technology.
In the case of wind energy, a location is excluded if wind speeds at hub height is below the global
critical value. Wave energy is excluded from locations having a resource level below a critical
average annual level.
Table 1-14 shows the critical resource levels for each offshore technology. The limit used for
offshore wind was established by Guidehouse’s in-house resource model. This limit has also been
confirmed in practice. No commercial-scale wind farms are developed in established markets that
have an average wind speed at hub height below 8 m/s. The critical value for wave technology is
based on observation, as no projects have been developed with an average wave resource level
below 5 kW/m.
Table 1-14: Resource limitations of offshore energy production technologies

Limitation Bottom-fixed wind Floating bottom wind Wave energy
turbines turbines
Minimum average > 8 m/s in at least one > 8 m/s in at least one > 5 kW/m
resource level quarter quarter
For each of the three technologies, this report also excludes areas where the resource level is
below the critical level. This results in an available area after critical resource exclusion. Figure
1-17, Figure 1-18, and Figure 1-19 show the area available to bottom-fixed wind, floating wind,
and wave technology after geographical constraints and the additional exclusion below critical
resource level.
Figure 1-17: Area available for bottom-fixed wind turbines after resource-
specific exclusion
Figure 1-18: Area available for floating wind turbines after resource-specific
exclusion
Figure 1-19: Area available for wave energy after resource-specific exclusion
1.4 Renewable technology potential

The following section presents the approach and results of this report’s RES potential analysis.
1.4.1 Offshore resource potential

The hub height of the wind turbines dictates offshore wind resource potential. The tip height of
offshore wind turbines has increased from 100 m in 2010 to more than 200 m in 2016. This trend
is anticipated to continue, given that turbines are currently in production with a tip height of 260
m and a hub height of 150 m (International Energy Agency, 2019). Larger hub heights result in a
higher average annual wind speed at hub height and allow for larger turbine blades and swept
areas. All these factors combined lead to increased capacity factors and yields for offshore wind
turbines. By 2030, a hub height of 150 m is expected to become the new standard, and that the
trend should continue to result in a commercially viable hub height of 180 m by 2050.
As this study also considers onshore wind energy from islands in the Mediterranean Sea, a similar
approach was conducted for onshore wind turbines. In recent years, the average hub height of
onshore wind turbines in Germany increased from 93 m in 2008 to 133 m in 2018 (Fraunhofer,
n.d.). Based on the expectation that this trend will continue, a hub height of 150 m is expected for
2030. However, in contrast to the increased growth expected in the development of offshore
turbines, onshore turbines experience more constraints, given social acceptance, environmental
concerns, and other height restrictions. For this reason, an average hub height of 150 m is
expected for 2050 as well.
The resource potential is determined for 2030 and 2050 for the available area shown in Figure
1-21, Figure 1-22, and Figure 1-23. The area is represented as a geographic raster with cells of
1x1 km. The calculations are carried out per raster cell and summarized per country or production
block (for production block definition, see Section 1.6).
1.4.1.1 Offshore wind

To determine the offshore wind resource potential, annual average wind speed is used. The
average wind speed is sampled at the geographic location of each raster cell. The wind speed,
given at 10 m above sea level, is extrapolated to hub height using the logarithmic wind speed
profile with a roughness length of 0.0002 m at sea (Suisse Éole, 2020).
The wind speed is input to a standard Full Load Hour-wind speed relationship (Held, 2010):
FLH = 728 v - 2,368 [hours/year]

This study assumes a wind farm installed power density of 7 MW/km2. Figure 1-20 from the
European Maritime Spatial Planning Platform (European MSP Platform, 2018a) gives the offshore
wind farm capacity densities of current projects. A clear trend is not visible, but 7 MW/km2 is very
much in the middle of the range.
Figure 1-20: Capacity density of European offshore wind farms

From the full-load hours (FLH),83 the assumed offshore wind power density of 7 MW/km2, and the
raster cell area (1 km2 in our case), the offshore wind resource potential is calculated in
MWh/year. This calculation also applies an operational efficiency of 90% and an array efficiency of
90%. The operational efficiency gives the share of time that the wind turbine is not offline for
maintenance. The array efficiency measures the loss that multiple turbines will cause because of
mutual interference. The efficiencies are combined by multiplication, resulting in an overall
efficiency of 81%.
The efficiency values are treated the same as Guidehouse’s in-house model for resource potential
calculation. The values are on the low side to remain conservative when determining maximal
technical resource potential. These values are also justified because offshore wind technologies are
relatively new in the Mediterranean.
1.4.1.2 Wave
For wave resource potential determination, this study uses a method comparable to the method
for offshore wind. For wave energy technology, the best estimate of the capacity factor is from the
Ocean Energy Systems/International Energy Agency LCOE report (OES & IEA, 2015). This
relationship can be approximated with the following mathematical relationship:
Capacity Factor = 0.0445 x phi0.552
Here phi is wave resource in kW/m at the raster cell location. The wave FLH are determined by
multiplying the capacity factor with 8,760 hours. The wave resource potential in MWh/year is then
83
FLH equal the number of hours resulting from dividing the energy output of the turbine over the year by its
rated power. In practice, a wind turbine will run for a longer time (load hours) than given by the FLH, as it
will often run at less than 100% rated capacity.
calculated from the full load hours, the assumed wave power density (12.5 MW/km2),84 the raster
cell area (1 km2), and a wave operational efficiency of 95% (OES & IEA, 2015).
This study could not find any indication of how wave energy technology will develop after 2030.
Therefore, the technical parameters are assumed to be the same in 2030 and 2050. However, as
explained by Figure 1-19, this study does assume further cost reductions for wave energy between
2030 and 2050, even if it is unknown which technological developments this will come from.
1.4.1.3 Tidal
In the Mediterranean, significant tidal resources are only available in two specific locations: the
straits of Messina and Gibraltar. This study found a resource potential of 125 GWh/year for the
Strait of Messina (Coiro et al., 2013). In the Strait of Gibraltar, this study found a tidal potential
capacity of 25 GW (Physical oceanography group, University of Malaga). With an expected capacity
factor of 10%, this study obtained a tidal resource potential of 22 TWh/year in that area. 85
1.4.1.4 Results
For all offshore technologies, the resulting available area within the EEZs of different countries
after resource specific exclusions is in shown in Table 1-15. This study does not provide an area
value for tidal technology, as it is available at only two specific locations.
Table 1-15: Available area in km2 for offshore technologies after resource-
specific exclusions
EEZ ID Country Bottom-fixed Bottom-fixed Floating Floating Wave
wind wind wind wind available area
available available available available 2030 and
area 2030 area 2050 area 2030 area 2050 2050(km2)
(km2) (km2) (km2) (km2)
1 Croatia 1,158 1,468 18,104 18,414 0
2 Cyprus 0 0 6,702 7,824 0
3 France 0 0 10,474 10,474 11,455
4 Greece 0 0 37,702 37,702 138,682
5 Italy 1,451 1935 83,797 84,917 44,844
6 Malta 76 76 22,652 22,652 25,309
7 Portugal 79 79 18,383 18,383 27,177
8 Slovenia 0 0 0 0 0
9 Spain 48 48 31,204 31,204 44,440
Total 2,812 3,606 229,018 231,570 291,907
The values given in Table 1-15 represent the technical potential available if all suitable areas would
be used to install RES technologies. In practice, legal, societal, economic, and other barriers will
limit the amount of potential area that can be used.
84
SWECO internal communication.
85
SWECO internal communication.
For both offshore wind technologies, the resource potential in 2050 is higher than the potential in
2030. This fact is a consequence of the increased wind turbine hub height by 2050. Turbine hub
height influences the resource potential in two different ways. Firstly, the increased hub height
results in a higher average wind speed at hub height and an increased local resource potential.
Secondly, the area available to offshore wind increases with an increased hub height. The higher
hub height means a higher wind speed at hub height. This fact results in more locations meeting
the minimum resource limit of 8 m/s windspeed at hub height. Therefore, more area is available,
and the total resource potential is higher.
Table 1-16: Annual technical resource potential for offshore technologies

EEZ Country Bottom- Bottom- Floating Floating Wave Tidal
ID fixed wind fixed wind wind wind potential2030 potential
potential potential potential potential and 2050 2030 and
2030 2050 2030 2050 (TWh/a) 2050
(TWh/a) (TWh/a) (TWh/a) (TWh/a) (TWh/a)
1 Croatia 17.9 22.9 313.2 325.3 0.0 0.0
2 Cyprus 0.0 0.0 109.7 128.1 0.0 0.0
3 France 0.0 0.0 271.0 276.5 174.6 0.0
4 Greece 0.0 0.0 840.3 858.4 1810.3 0.0
5 Italy 24.2 31.9 1,610.2 1,662.9 623.6 0.1
6 Malta 1.4 1.4 430.5 440.4 341.0 0.0
7 Portugal 1.9 1.9 427.3 436.3 887.9 0.0
8 Slovenia 0.0 0.0 0.0 0.0 0.0 0.0
9 Spain 1.0 1.1 580.5 594.0 660.8 22.0
Total 46.3 59.2 4,582.6 4,722.0 4,498.3 22.1
The increase in resource potential for floating wind is mainly due to the first reason: higher local
resource potential because of higher wind speeds at hub height. A relatively small increase of
about 4% occurs in resource potential for floating wind.
For bottom-fixed wind, the increase in resource potential is much larger and reaches 32%. This
increase is caused by the substantial increase in area available to the bottom-fixed technology
between 2030 and 2050. The bottom-fixed wind potential is mainly concentrated in the Adriatic
Sea. In that location, the most important limiting factor for resource potential is the area available
for generation, and the available area is in turn constrained by the minimum resource limit.
Table 1-17: Installed capacity potential for offshore technologies

EEZ ID Country Bottom- Bottom- Floating Floating Wave Tidal
fixed wind fixed wind wind wind installed installed
installed installed installed installed capacity capacity
capacity capacity capacity capacity 2030 and 2030 and
2030 2050 2030 2050 2050 2050
(GW) (GW) (GW) (GW) (GW) (GW)
1 Croatia 8.1 10.3 126.7 128.9 0.0 0.0
2 Cyprus 0.0 0.0 46.9 54.8 0.0 0.0
3 France 0.0 0.0 73.3 73.3 143.2 0.0
4 Greece 0.0 0.0 263.9 263.9 1,733.5 0.0
5 Italy 10.2 13.5 586.6 594.4 560.6 0.2
6 Malta 0.5 0.5 158.6 158.6 316.4 0.0
7 Portugal 0.6 0.6 128.7 128.7 339.7 0.0
8 Slovenia 0.0 0.0 0.0 0.0 0.0 0.0
9 Spain 0.3 0.3 218.4 218.4 555.5 25.0
Total 19.7 25.2 1,603.1 1,621.0 3,648.8 25.2
For floating wind, the important limiting factors are maximum depth and distance to shore.
Therefore, for this technology, the relative increase in available area is very small compared to
bottom-fixed wind.
Table 1-17 shows resource potential installed capacities. The values represent the capacities that
can be maximally installed in areas available to the different technologies for renewable
generation. The following figures show the geographic variation of the resource potential for
bottom-fixed wind turbines, floating wind turbines, and wave energy installations for 2030 and
2050.
Figure 1-21: Resource potential for bottom-fixed wind turbines in 2030 and 2050
Figure 1-21 shows the resource potential of bottom-fixed wind. The map indicates the areas
determined before by spatial exclusions. In the available areas, the colour code indicates the level
of the available resources in MWh/km2/year. Darker red colours mean higher resource levels. In
the same way, Figure 1-22 shows the resource potential of floating wind technology.
Figure 1-23 shows the resource potential of wave energy installations. Here, the resource levels
are indicated with blue colour scale, with darker blue corresponding to higher resource levels.
Resource levels are the same for 2030 and 2050.
Figure 1-22: Resource potential for floating wind turbines in 2030 and 2050
Figure 1-23: Resource potential for wave energy installations in 2030 and 2050
1.4.2 Resource potential on islands

This study considers the following technologies on islands: onshore wind, large-scale utility solar
PV, and rooftop solar PV. It determines the resource potential for these onshore renewable
technologies using an area-related method. This analysis does not look at individual islands but
determines the average annual resource potential over all islands per country.
From the Guidehouse in-house resource potential model (Deng, et al., 2015), country-level values
are known that express the percentage of the country’s area available for RES generation for each
technology. This study assumes that on islands alone, these percentages are the same as for the
whole country. Onshore wind and utility-scale solar PV use a percentage of available surface area.
For rooftop solar PV, the available rooftop area is translated into available area per capita by using
average values of rooftop area per capita. The values used are shown in Table 1-18.
Using this study’s geographical map, the coordinates of the location and area in square kilometres
of all islands on the map within the EEZs of each country under study were determined. Figure
1-39 shows the islands involved. This study also uses a population density map (SEDAC, 2015)
and combines it with the island areas to arrive at an estimate of the number of inhabitants of each
island.
Table 1-18: Factors of area available for onshore technologies

Country Suitable roof area Suitable roof area Area available for Area available for
per capita in 2030 per capita in 2050 utility PV (%) onshore wind (%)
(m2/capita) (m2/capita)
Croatia 7.9 8.1 1.9% 2.3%
Cyprus 7.5 7.9 3.8% 12.0%
France 11.6 12.1 1.2% 3.9%
Greece 7.8 8.1 1.2% 1.3%
Italy 7.5 7.9 1.2% 2.4%
Malta 6.6 7.1 2.4% 9.9%
Portugal 7.7 7.9 0.8% 2.1%
Slovenia 14.1 14.7 0.5% 0.1%
Spain 7.2 7.6 1.0% 1.9%
Table 1-19: PV conversion factors

Technology Year Module Performance Ground Overall
efficiency ratio coverage conversion
Utility PV 2030 24.0% 80% 23.0% 4.4%

Utility PV 2050 29.5% 80% 26.5% 6.3%
Rooftop PV 2030 24.0% 80% - 19.2%
Rooftop PV 2050 29.5% 80% - 23.6%
For onshore wind, the same method was used as the method for offshore wind, described in
Section 1.4.1. The average wind speed was sampled at the island location and calculated at hub
height. The hub height is taken to be 150 m in all cases. The same formula for FLH and value of
power density as for offshore wind are used to get the potential per square kilometre. Then, the
island area and the percentage of area available from Table 1-18 gave the resource potential per
island. For onshore wind, an operational efficiency of 98% and an array efficiency of 90% are
assumed. The resource potential per country is determined by summing up the values from all
islands within each country.
For solar photovoltaics, the study first determined the area available. For utility-scale solar PV, the
available area was determined by multiplying the island area with the percentage of area available
taken from Table 1-18. For rooftop solar PV, the available area was determined by multiplying the
rooftop area per capita from Table 1-18 with the number of inhabitants.
Then, this study calculated the PV resource potential using:
 The module efficiency (IEA, 2012)

 The performance ratio86; this ratio captures the system’s conversion efficiency from the
module’s output to usable electricity
 For large-scale utility PV, a ground coverage value87; this value is an estimate of the share
of land capturing energy, i.e., the share actually covered with PV cells
Values are shown in Table 1-19. The values are taken from Guidehouse’s in-house resource
potential model and are on the conservative side. In general, this report tries to use numbers on
the safe or low side when estimating maximal resource potential.
The conversion factors are multiplied together to get the overall solar conversion factor. Solar
irradiation in kWh/m2/day sampled at the location of each island is then translated into solar
resource potential in MWh/year by using this overall conversion factor and the previously
determined available area. The resource potential per country is determined by summing up the
values from all islands within each country.
The results of the resource calculations are shown in Table 1-20. Average resource values summed
per country are given in TWh/year. For onshore wind, the resource potential is the same in 2030
and 2050 as this study assumes that the onshore wind turbine hub height will be the same in both
years, as explained in Section 1.4.1. Table 1-21 presents the capacities of the different onshore
technologies that can be maximally installed on islands.
Table 1-20: Annual resource potential for technologies on islands

Country Onshore Onshore Rooftop PV Rooftop PV Utility PV Utility PV
wind wind potential potential potential potential
potential potential 2030 2050 2030 2050
2030 2050 (TWh/a) (TWh/a) (TWh/a) (TWh/a)
(TWh/a) (TWh/a)
Croatia 1.5 1.5 0.3 0.4 4.3 6.0
Cyprus 18.9 18.9 3.4 4.4 30.3 42.9
France 6.8 6.8 1.4 1.8 7.8 11.1
Greece 7.0 7.0 4.3 5.5 23.0 32.5
Italy 23.5 23.5 22.4 28.9 43.7 61.9
Malta 0.7 0.7 1.1 1.4 0.7 0.9
Portugal88 0.0 0.0 0.1 0.1 0.1 0.1
Slovenia 0.0 0.0 0.0 0.0 0.0 0.0
Spain 1.8 1.8 2.9 3.8 3.7 5.3
Total 60.3 60.3 36.0 46.4 113.6 160.8
86
The term performance ratio, also called the quality factor (Q), refers to the relationship between actual yield
and target yield. It indicates which portion of the generated current can actually be used.
87
The ground coverage is derived from typical power densities of solar farms (25-50 MW/km2) in comparison
with the raw module power density of a typical solar cell of 125-150MW/km2.
88
For Portugal, the islands are located in the Atlantic Ocean and not in the Mediterranean Sea.
Table 1-21: Installed capacity potential for technologies on islands

Country Onshore wind Onshore Rooftop PV Rooftop PV Utility PV Utility PV
installed wind installed installed installed installed
capacity 2030 installed capacity capacity capacity capacity
(GW) capacity 2030 (GW) 2050 (GW) 2030 (GW) 2050 (GW)
2050 (GW)
Croatia 0.6 0.6 0.2 0.3 3.1 4.4
Cyprus 7.9 7.9 2.1 2.7 18.4 26.0
France 2.4 2.4 0.9 1.1 4.9 6.9
Greece 2.1 2.1 2.6 3.3 13.7 19.4
Italy 8.3 8.3 13.1 16.9 26.1 36.9
Malta 0.2 0.2 0.6 0.8 0.4 0.6
Portugal88 0.0 0.0 0.0 0.1 0.0 0.1
Slovenia 0.0 0.0 0.0 0.0 0.0 0.0
Spain 0.7 0.7 1.8 2.4 2.3 3.3
Total 22.1 22.1 21.4 27.6 68.9 97.5
1.5 Economic potential

Task 1.5 determines the LCOE for each generation technology across the Mediterranean region in
the zones where they are applicable based on:
 Available area (derived in Task 1.3)

 Energy yield (derived in Task 1.4)
 Technology-specific CAPEX and OPEX projections for 2030 and 2050 scenarios based on
public literature and Guidehouse in-house cost modelling expertise.
LCOE maps illustrate the areas with economic potential for offshore energy in the region. Also,
costs curves that indicate the LCOE (€/MWh) versus generated power (TWh) for each of the
Mediterranean areas are used to assess the economic potential for offshore energy in the
Mediterranean.
1.5.1 LCOE methodology

The LCOE or the cost of generating electricity for a technology system over the system’s lifetime is
calculated using the following formula and associated parameters (NREL, n.d.):
𝐂𝐀𝐏𝐄𝐗 × 𝐂𝐑𝐅 + 𝐟𝐢𝐱𝐞𝐝 𝐎𝐏𝐄𝐗 𝐢(𝟏 + 𝐢)𝐧

𝐋𝐂𝐎𝐄 = ( ) 𝐂𝐚𝐩𝐢𝐭𝐚𝐥 𝐑𝐞𝐜𝐨𝐯𝐞𝐫𝐲 𝐅𝐚𝐜𝐭𝐨𝐫 (𝐂𝐑𝐅) =
𝟖, 𝟕𝟔𝟎 × 𝐜𝐚𝐩𝐚𝐜𝐢𝐭𝐲 𝐟𝐚𝐜𝐭𝐨𝐫 (𝟏 + 𝐢)𝐧 − 𝟏
The following parameters are included in the cost analysis:
 CAPEX: relates to the investment cost expressed in €/MW installed

 Fixed OPEX: relates to the operation and maintenance cost expressed as fixed €/MW/year
 Capacity factor: represents the share of the time in a year that a power plant generates
power
 i: represents the discount rate that depends on the technology’s cost of capital (cost of
debt and cost of equity) and the financial risk. The LCOE cost calculation uses different
weighted average cost of capital (WACC) rates per technology.
 Lifetime: years of the technology’s power plant
Grid connection costs, taxes, land costs, and decommissioning costs are excluded from the LCOE
cost calculation. Although grid connection costs may be significant in certain regions with limited
grid connectivity and this situation may vary between countries, these costs are not specific to the
cost development of each technology. Onshore and offshore transmission asset connection costs
(i.e., offshore substation and export cable) are not considered in this economic potential
assessment, which focuses on production technologies and production blocks. Only connection
costs between the different individual pieces of equipment within an offshore energy plant (e.g.,
the array cables that connect the turbines in an offshore wind farm to an offshore substation) are
included in these CAPEX and fixed OPEX estimates. The grid connection is subject to further
optimisation in Task 3.
In centralised grid delivery models, these costs are often borne by Transmission System Operators
and not by project developers (Navigant, 2019) Taxes are specific to each country and not intrinsic
to the cost development of each technology. Similarly, although land costs may have a particular
importance in certain densely populated regions or countries such as Malta, these may be very
specific to each country and have not been included as part of the CAPEX or OPEX input
assumptions of each onshore technology. Finally, decommissioning costs are very uncertain at this
point and do not have a large impact on the overall LCOE. Decommissioning costs are estimated to
represent a small share of the total undiscounted project costs between 2-3%. (Topham E. and
McMillan, 2017). In addition, the impact of decommissioning costs on the LCOE is estimated
around 1% (Department of Business, Energy and Industrial Strategy, 2018). Table 1-22 gives an
overview of the approach taken per technology on the cost inputs and calculation method.
Table 1-22: Cost modelling approach per renewable energy technology

Technology CAPEX/OPEX approach LCOE approach
Bottom-fixed CAPEX for 2030 and 2050 on a local level LCOE varies on a local level due to
offshore wind based on local water depth differences in costs (based on distance
to shore and water depth) and wind
OPEX for 2030 and 2050 on a local level yield (Task 1.4)
based on distance to shore
Floating Fixed CAPEX for 2030 and 2050. LCOE varies due to local differences in
offshore wind wind energy yield and OPEX (Task 1.4)
 Less dependency on water depth
 Higher cost uncertainty than for bottom-
fixed offshore wind, which is a more
mature technology
Average OPEX for 2030 and 2050 based on
local distance to shore
Solar PV Fixed CAPEX and OPEX for 2030 and 2050, LCOE varies due to differences in solar
irrespective of location as solar PV modules energy yield (Task 1.4)
are a European market:
 Utility solar PV
 Rooftop solar
Onshore wind Fixed CAPEX and OPEX for 2030 and 2050, LCOE varies due to differences in wind
irrespective of location as onshore wind energy yield (Task 1.4)
turbines are a European market
Wave energy Fixed CAPEX and OPEX for 2030 and 2050 LCOE varies due to differences in wave
energy yield (Task 1.4)
Tidal energy Fixed CAPEX and OPEX for 2030 and 2050 LCOE varies due to differences in tidal
energy yield (Task 1.4)
Importantly, CAPEX levels for bottom-fixed offshore wind depend on water depth. Guidehouse’s
offshore wind cost model is used as a basis to differentiate CAPEX costs for sites with differing
water depths. However, in this economic assessment, floating offshore wind CAPEX is assumed to
be independent from water depths. In the light of the aim of the study and of Task 1, the cost
analysis is used to identify the 10 most promising TMAs for further analysis in Tasks 2 and 3. The
error introduced through this cost simplification should not affect the outcome of the selected sites
strongly since there is a maximum water depth deemed feasible for floating offshore wind.
In terms of fixed OPEX cost levels, cost differentiation based on the project’s distance to shore
becomes relevant. Typically, both bottom-fixed and floating offshore wind projects include the use
of Service Operation Vessels in their operation and maintenance strategies for wind farms located
at distances to shore greater than 75 km. Therefore, this significant operational cost is included as
an OPEX element in the LCOE calculation only for sites at a distance to shore greater than 75 km
(The Crown Estate, 2013). Figure 1-24 and Figure 1-25 show the specific CAPEX and OPEX input
values used for 2030 and 2050 to calculate LCOE levels per technology.
Figure 1-24: CAPEX and OPEX for 2030 and 2050 for offshore technologies
Figure 1-25: CAPEX and OPEX for 2030 and 2050 for onshore technologies
Figure 1-24 and Figure 1-25 suggest that utility solar PV followed by rooftop solar PV and onshore
wind are the technologies with the lowest projected investment costs towards 2030 and 2050.
Investment costs for floating offshore wind are anticipated to remain higher than those of bottom-
fixed offshore wind. However, towards 2050, investment costs for floating offshore wind are
expected to reach similar cost levels as bottom-fixed offshore technology.
Wave and tidal energy technologies should remain the most expensive technologies. In 2030,
investment costs for wave and tidal are expected to remain approximately 5.5 times and 4 times
as high as the investment costs for onshore wind, respectively. Towards 2050, a significant decline
in investment costs is expected for wave energy technology. A detailed list of the investment and
operational input cost figures used for 2030 and 2050 and its sources is included in Figure 1-26
Multiple sources have been considered for each cost input assumption, and the cost inputs chosen
are in line with other well-known studies from the International Energy Agency, the International
Renewable Energy Agency, and ASSETS.
Table 1-23: WACC and lifetime per generation technology for LCOE cost analysis
Offshore energy Onshore energy on islands
Bottom-fixed Floating Tidal Wave Utility Rooftop Onshore

offshore offshore wind energy energy Solar PV Solar PV wind
wind
WACC 5.5%91 5.5%91 10.0%89 10.0%89 5.6%90 5.6%90 7.0%90

(%)
Lifetime 3091 2591 2089 2089 2590 2590 2590

(years)
The WACC is heavily dependent on each technology’s cost of debt financing, cost of equity
financing, and the financial risk of the markets considering these technologies. Values for the
technologies’ lifetime are taken from current standard industry practices. Table 1-23 shows an
overview of the estimated WACC assumed for the Mediterranean region and the lifetime used per
technology.
1.5.2 LCOE results per technology

LCOE are calculated per country based on the methodology explained in Section 1.5.1; the
available area and energy yields derived from Tasks 1.3 and 1.4, respectively; and the cost input
assumptions taken in Section 1.5.1. Figure 1-26 and Figure 1-27 show the LCOE levels in €/MWh
per technology and per country.
Figure 1-26: Average LCOE levels for offshore technologies per country for 2030
and 2050
Figure 1-26 shows the average LCOE results calculated based on the input parameters in Figure
1-24, Figure 1-25, and Table 1-23. Input assumptions are further detailed in Section 1.5. Average
LCOE results show that bottom-fixed offshore wind is most cost competitive in Portuguese and
89
(OES & IEA, 2015)
90
(Bachner et al., 2019)
91
(BVG Associates, 2017)
Spanish waters, with LCOE levels around 46-48 €/MWh in 2030 and 38-40 €/MWh in 2050.
Notably, the bottom-fixed offshore wind potentials in these areas remain low at 1.9 TWh/year and
1.1 TWh/year, respectively according to Table 1-16. Italy’s and Croatia’s potentials are higher at
24-32 TWh/year and 18-23 TWh/year, respectively.
Waters off the coasts of France and Portugal are the preferred locations for floating offshore wind
farms. LCOE levels in those areas range 66-71 €/MWh in 2030 and 41-44 €/MWh in 2050.
However, floating offshore wind potentials are highest in Italy (1610-1663 TWh/year), Greece
(840-858 TWh/year), and Spain (581-594 TWh/year).
For wave energy, Portuguese waters result in the best economic option again, with a significantly
lower LCOE in 2030 and 2050 compared to the rest of the member states, namely 328 €/MWh
(2030) and 149 €/MWh (2050). Portugal has the second highest wave energy potential (888
TWh/year) after Greece (1810 TWh/year).
Among the two selected sites for tidal energy, Spain hosts the site with a significantly lower LCOE
and the highest tidal energy potential compared to Italy. Tidal energy projects in Spain could
deliver a total of 22 TWh/year at an LCOE level of 812 €/MWh in 2030 and 543 €/MWh in 2050.
Finally, LCOE levels are not determined for countries where the resource potential is zero, as
derived in Task 1.4.
Figure 1-27: Average LCOE levels for onshore technologies on islands for 2030
and 2050
LCOE levels for onshore technologies are generally much lower than those for offshore
technologies (Figure 1-27). The LCOE levels are a result of our input assumptions and do not
include any costs for grid connection. Utility solar PV and rooftop solar PV show attractive
economic potential in all member states except in Slovenia, where the resource potential was set
to zero since there are no islands. LCOE levels for utility solar PV technology range 18-22 €/MWh
in 2030 and 10-12 €/MWh in 2050. For rooftop solar PV, LCOE levels amount to 29-36 €/MWh in
2030 and 18-23 €/MWh in 2050. Onshore wind LCOE levels are higher than those of solar
technologies but still below those of bottom-fixed offshore wind. Similar to solar energy, onshore
wind energy is an available resource on all countries’ islands except in Slovenia, with LCOE levels
ranging between 35-60 €/MWh (2030) and 29-49 €/MWh (2050).
1.5.3 Geographical analysis of LCOE

The LCOE has a geographical dependency through several factors. The annual yield depends on
the average resource potential of the technology, thereby strongly influencing the cost of
electricity produced over the lifetime of a production installation. The LCOE for bottom-fixed wind
turbines have a high dependency on the water depth. Deeper waters result in increased material
use for the foundations of the wind turbines and increased installation costs. The depth
dependency of bottom-fixed offshore wind turbines already led to an exclusion of all waters with a
depth over 50 m, resulting in a very limited available area for deployment.
Figure 1-28 and Figure 1-29 present the geographical variation of the LCOE of bottom-fixed wind
in 2030 and 2050.
Figure 1-28: LCOE of bottom-fixed wind in 203092

Figure 1-29: LCOE of bottom-fixed wind in 2050

Figure 1-30 presents the LCOE of floating wind in 2030, and Figure 1-31 presents the LCOE of
floating wind in 2050.
92
Please note that the available area for fixed bottom wind turbines is relatively small, mostly located in the
Adriatic Sea.
Figure 1-30: LCOE of floating wind in 2030
Floating wind turbines have less spatial constraints as they can be deployed up to a depth of
1,000 m. However, the technology is still in early phases of deployment and not nearly as mature
as bottom-fixed wind turbines.
Figure 1-30 shows that most of the available area has an LCOE of 60 to 100 €/MWh in 2030 (LCOE
values without grid connection costs to shore; see Section 1.5.1). Increased deployment in the
Mediterranean Sea and in other regions of the world is expected to drive down costs and increase
efficiency in the rollout of floating wind turbines. Figure 1-31 shows that spatial availability
increases slightly due to higher hub heights; meanwhile, LCOE decreases significantly for floating
wind turbines in 2050 due to reduced costs and increased efficiency.
Figure 1-31: LCOE of floating wind in 2050
Figure 1-32 and Figure 1-33 show maps of the LCOE of wave technology in 2030 and 2050. In
these figures, the geographic variation of LCOE levels of floating wave technology are shown.
Estimated spatial availability and wave resource potential is the same in both years investigated.
Low maturity of wave technology and lack of technological progress paths with clear and strong
cost reduction potential cause high LCOE levels. For 2030, an LCOE of up to 900 €/MWh is
expected. In 2050, the LCOE is expected to drop to a range of 100-400 €/MWh as the technology
is likely to develop.
Figure 1-32: LCOE of wave technology in 2030
Figure 1-33: LCOE of wave technology in 2050
1.5.4 Cost curves

Cost curves show the LCOE against the available cumulative resource potential for each
technology. By sorting the LCOE for all locations and summing the resource potential for each next
expensive location, the amount of resource potential available below a certain level of LCOE can be
shown. The cost curve plots in this section show the locations are colour coded according to EEZ.
Figure 1-34 shows the cost curves for bottom-fixed wind. Again, the potential for bottom-fixed
wind turbines is limited, but the maturity of the technology results in a low LCOE. Most potential
occurs in Italy and Croatia, which represents the resource potential of the area in the Adriatic Sea.
We see again the total potential in 2050 is higher because the assumption of an increased hub
height in 2050 and cost levels are lower for that year.
Figure 1-34: Cost curves for bottom-fixed wind in 2030 and 2050
Figure 1-35 shows the cost curves for floating wind technology in 2030 and 2050. The less mature
technology shows higher LCOE levels than for bottom-fixed wind. For floating wind in 2050, the
increased hub height results in a higher cumulative potential. In 2050, the technological
advancement results in a lower LCOE for floating wind turbines.
Figure 1-35: Cost curves for floating wind in 2030 and 2050
The cost curves for wave technology in 2030 and 2050 are shown in Figure 1-356. The substantial
wave resource potential of the Atlantic coast of Portugal and (to a lesser extent) of Spain remains
clearly visible. Higher waves in the Atlantic part of this area result in LCOE levels below 400
€/MWh in 2030. In the Mediterranean, less wave energy is available, resulting in clearly higher
LCOE levels of 500–900 €/MWh. Costs are expected to decrease significantly between 2030 and
2050. The LCOE for wave energy in the Portuguese part remains below 200 €/MWh in 2050. All of
these values are still significantly above those for wind energy and OV on islands as well as
offshore wind and tidal.
Figure 1-36: Cost curves for wave technology in 2030 and 2050
This study has also determined the combined cost curves with the following considerations:
 For each location in the offshore area under study, the study determined if at least one
technology has a resource potential above zero.
 Then, the study determined which technology has the lowest LCOE in those locations.
 Each location was then assigned the resource potential of its cheapest technology.
 After sorting by LCOE and taking the cumulative sum of the assigned resource potentials,
the combined cost curve was obtained.
The results for 2030 and 2050 are show in Figure 1-37. In these figures, the cost curves are colour
coded with the cheapest technology of the location. The potential for bottom-fixed wind turbines is
very low compared to floating wind turbines. Wave energy has the highest LCOE levels. Wave
energy LCOE drops in 2050 but remains expensive when compared with the other technologies.
Figure 1-37: Combined cost curves for all offshore technologies in 2030 and 2050
1.6 Performance ranking

For the Mediterranean region under study, this section provides a more detailed look at selected
areas that are most promising for offshore energy development. This study identifies the areas
with the greatest cost-effective potential for various technologies or combinations thereof, using a
manual ranking system.
1.6.1 TMAs and production zones

Within the areas available for power generation by wind and wave energy, TMAs are identified
where the power production is high. These 10 TMAs were chosen based on the available areas for
the four technologies. Area locations are carefully considered and chosen based on appropriate
levels of resource potential and LCOE. Some areas are prioritised above other regions for more
practical reasons. For example, the TMA in the northern part of the Adriatic Sea has not been
selected for the LCOE (which is relatively high) due to the availability of bottom-fixed wind turbine
development areas. As the technology readiness level of bottom-fixed wind turbines is higher than
that of floating bottom wind turbines, this area should be prioritized in an offshore energy
production rollout. Also, locations favourable for including the connection hub within a meshed grid
are given higher priority.
The TMAs have a size of roughly 120x120 km but are not always square. The aspect ratio can vary
to best fit regions of high resource potential. Within the TMAs, this study defines several
production blocks. Production blocks have a size of roughly 140 km2, which corresponds to a
typical offshore wind farm size of 1 GW having a power density of 7 MW/ km2. The production
blocks do not necessarily fill the entire TMAs but are defined only at locations with sufficient
resource potential. The locations of the production blocks remain the connection point for the grid
options analysis in Task 2. For each production block, this study calculated total resource potential,
maximum installed capacity, and average LCOE for all technologies. When considering resource
costs for LCOE calculations in production blocks, all connection costs within the production blocks
are considered. All other grid connection costs are part of the analysis in Tasks 2 and 3. Figure
1-38 presents the TMAs and defined production blocks.
Figure 1-38: TMAs and production areas within the TMAs

Table 1-24, Table 1-25, and Table 1-26 present the results summarised over the production blocks
defined in the TMAs. The results represent the total technical potential available if all production
blocks are used completely. Table 1-24 shows the installed capacity if the production blocks are
fully used.
Table 1-24: Installed capacity potential for each technology in production blocks
defined for TMAs
TMA Description Bottom- Bottom- Floating Floating Wave Wave
label fixed fixed wind wind installed installed
wind wind installed installed capacity capacity
installed installed capacity capacity 2030 2050
capacity capacity 2030 2050 (GW) (GW)
2030 2050 (GW) (GW)
(GW) (GW)
01 Gulf of Lion 0.0 0.0 49.2 49.2 89.9 89.9
02 Malta 0.5 0.5 68.8 68.8 126.1 126.1
03 Sicily 1.6 1.6 67.0 67.0 83.4 83.4
04 Gulf of Venice 12.9 17.2 42.7 47.0 0.0 0.0
05 Baleares 0.0 0.0 37.4 37.4 74.2 74.2
06 Gulf of Cádiz 0.2 0.2 34.5 34.5 64.2 64.2
07 North Aegean Sea 0.0 0.0 51.9 51.9 96.0 96.0
08 Italy - Ionian Sea 0.0 0.0 35.1 35.1 30.0 30.0
09 Corsica - Sardinia 0.0 0.0 36.3 36.3 0.0 0.0
10 South Aegean Sea 0.0 0.0 49.5 49.5 94.0 94.0
Total 15.2 19.4 472.5 476.8 657.8 657.8
Table 1-25: Total resource potential in production blocks defined for TMAs
TMA Description Bottom- Bottom- Floating Floating Wave Wave
label fixed wind fixed wind wind wind potential potential
potential potential potential potential 2030 2050
2030 2050 2030 2050 (TWh/a) (TWh/a)
(TWh/a) (TWh/a) (TWh/a) (TWh/a)
01 Gulf of Lion 0.0 0.0 202.2 206.2 110.5 110.5
02 Malta 1.4 1.4 184.3 188.5 134.5 134.5
03 Sicily 4.9 5.0 209.2 213.8 79.1 79.1
04 Gulf of Venice 28.2 38.0 97.2 108.7 0.0 0.0
05 Baleares 0.0 0.0 90.6 92.7 76.2 76.2
06 Gulf of Cádiz 0.6 0.6 99.4 101.7 138.7 138.7
07 North Aegean 0.0 0.0 184.2 188.0 96.3 96.3

Sea
08 Italy - Ionian 0.0 0.0 103.9 106.2 28.2 28.2

Sea
09 Corsica - 0.0 0.0 95.5 97.7 0.0 0.0

Sardinia
10 South Aegean 0.0 0.0 143.8 147.0 106.1 106.1

Sea
Total 35.1 45.0 1,410.3 1,450.5 769.5 769.5
Table 1-26: Average LCOE in production blocks defined for TMAs

TMA Description Average Average Average Average Average Average
label LCOE LCOE LCOE LCOE LCOE wave LCOE wave
bottom- bottom- floating floating 2030 2050
fixed wind fixed wind wind 2030 wind 2050 (€/MWh) (€/MWh)
2030 2050 (€/MWh) (€/MWh)
(€/MWh) (€/MWh)
01 Gulf of Lion 57.0 35.0 694.6 314.9
02 Malta 96.6 80.3 90.8 55.5 800.8 363.1
03 Sicily 55.2 45.7 75.1 46.1 906.1 410.8
04 Gulf of 73.4 61.4 103.4 63.6

Venice
05 Baleares 96.6 59.1 832.2 377.3
06 Gulf of Cádiz 48.2 39.8 81.7 50.0 398.0 180.5
07 North 66.4 40.8 851.4 386.0

Aegean Sea
08 Italy – 79.2 48.5 914.4 414.6

Ionian Sea
09 Corsica – 89.8 55.0

Sardinia
10 South 80.7 49.4 756.5 343.0

Aegean Sea
The onshore resource potential on islands will also be considered in Tasks 2 and 3. Figure 1-39
indicates the involved islands. To determine what percentage of islands will be connected to the
power grid under consideration, the distance to the nearest TMA is determined for all islands. This
distance can be used to establish whether a connection to an island is economically feasible.
Figure 1-39: Islands in the Mediterranean Sea with major onshore wind and solar
power capabilities
Table 1-27 shows the potential of onshore technologies on islands close to the TMAs. Nearby
islands are defined as islands whose midpoint is within 100 km of the centre of the closest TMA.
This distance roughly represents the size of the TMAs. Additionally, some nearby large islands that
have a part of their coast close to a TMA (such as Corsica, Sardinia, Sicily, and Crete) are included.
Table 1-27: Potential of onshore technologies on islands near TMAs

TMA Description Onshore Onshore Rooftop Rooftop Utility PV Utility PV
label wind wind PV PV potential potential
potential potential potential potential 2030 2050
2030 2050 2030 2050 (TWh/a) (TWh/a)
(TWh/a) (TWh/a) (TWh/a) (TWh/a)
01 Gulf of Lion 0.0 0.0 0.0 0.0 0.0 0.0
02 Malta 0.7 0.7 1.1 1.4 0.7 0.9
03 Sicily 11.5 11.5 16.1 20.7 22.8 32.2
04 Gulf of Venice 0.3 0.3 0.0 0.0 0.8 1.1
05 Baleares 1.5 1.5 2.6 3.4 3.2 4.5
06 Gulf of Cádiz 0.0 0.0 0.0 0.1 0.0 0.1
07 North Aegean 1.2 1.2 0.4 0.5 3.2 4.6

Sea
08 Italy – Ionian 0.2 0.2 0.3 0.3 0.6 0.8

Sea
09 Corsica – 18.4 18.4 7.1 9.1 28.0 39.7

Sardinia
10 South Aegean 2.7 2.7 2.0 2.6 9.6 13.6

Sea
Total 36.6 36.6 29.6 38.2 68.9 97.5
Table 1-28 shows the proposed ranking of the TMAs. Ranking is primarily based on lowest LCOE of
offshore wind but also considers:
 Available potential (offshore and onshore on nearby islands)

 Maturity of technology (e.g., bottom-fixed wind in the Adriatic)
 Closeness to expected grid expansion (e.g., from TYNDP 2018)
 Proximity to load centres
Remarkable ranking criteria are mentioned in the Remarks column in the table.
Table 1-28: TMA rankings

TMA Description Ranking Remarks
label
01 Gulf of Lion 1 Low LCOE

07 North Aegean Sea 2 Low LCOE
03 Sicily 3 Low LCOE

Large potential of onshore technologies on nearby islands,
Close to planned grid connection Sicily – Tunisia
04 Gulf of Venice 4 Substantial bottom-fixed offshore wind with relatively low

LCOE in 2030
08 Italy – Ionian Sea 5
09 Corsica – Sardinia 6 Large potential of onshore technologies on nearby islands

Close to planned grid connection
10 South Aegean Sea 7 Close to load centre
06 Gulf of Cádiz 8 Far from load centre
02 Malta 9 High LCOE

05 Baleares 10 High LCOE

Figure 1-40 shows the TMAs labelled with their ranking number.
Figure 1-40: TMA map with rankings

1.6.2 Time series data

For a detailed analysis of the production scenarios in Sweco’s power market model, normalised
time series were generated for each of the TMAs for all technologies considered. Normalised time
series characterise the shape of renewable generation in time. It also contains hourly capacity
factors that, when multiplied by the installed capacity of a renewable technology, give the hourly
power generation. The time series are defined per TMA and taken to be the same for each
production block within the TMA.
For technologies on islands, this study assumes that they have a time series profile equal to that
of the closest TMA.
For wind energy, this study uses the MERRA-2 global dataset93 to obtain a time series of hourly
capacity factor values (one year, 2014). Data from the Merra-2 database is available from
Renewables.ninja.94 For offshore wind, the wind speed data for 150-meter hub height was obtained
at the location of the TMA’s centre. Multiplying wind speed data by the logarithmic wind speed
factor obtained values at 180-meter hub height for the offshore wind 2050 time series. For
onshore wind on islands, wind speed data at 150 m was obtained for an onshore location near the
TMA under consideration.
Also available from Renewables.ninja is wind power production data. The website uses the
properties of a generic wind turbine to determine this power output. From the wind speed data,
the production data is obtained by using the power curve of the wind turbine.
Power output from Renewables.ninja is only available for 150 m hub height. By using the same
power curve as Renewables.ninja, this study calculated the offshore wind power production at a
hub height of 180 m from the wind speed values at 180 m hub height. The power generation time
series are normalised by dividing the wind power output by the nominal capacity of the generic
wind turbine used in determining the power curve.
For time series of solar PV on islands, this study determined the normalised power production for
each of the defined TMAs and calculated the time series for an onshore location close to each of
the TMAs. For a certain island, the PV time series of the TMA closest to the island was used. PV
time series are taken to be the same for large-scale utility PV and rooftop PV.
Solar PV time series were derived by using the standard solar energy tool PVsyst.95 This study
chose a generic solar PV module and alternating current (AC)/direct current (DC) inverter available
within PVsyst. Then, PVsyst calculates the solar power output time series of this system at each of
the chosen locations. The PV power production is calculated with the appropriate irradiation time
series for each location. The irradiation time series are available within PVsyst and specified for a
typical meteorological year. In the PV time series calculations, a time series for temperature
correction is employed. However, the temperature time series is not exported. The solar energy
time series are normalised by dividing the power output by the nominal capacity of the generic
solar module used in the calculation.
Wave energy output shows much less variation than wind or solar power. For wave energy, this
study used monthly averages. In each month, the time series has the same hourly value equal to
the average of that month. Time series are taken to be the same for the whole Mediterranean
region. Values are taken from monthly wave resources measured in Italy 96 and are normalised with
the installed capacity of wave energy technology in the referenced project.
1.7 Task 1 conclusions

The deployment of offshore technologies for electricity generation in the Mediterranean Sea has
been slow so far, and the existing installed offshore capacities consist of mainly floating offshore
93
(Rienecker et al., 2011)
94
(Staffel et al., 2016); data obtained from www.renewables.ninja.
95
https://www.pvsyst.com/
96
(Vicinanza, 2011)
wind, wave, and tidal pilot and demonstration projects. Onshore technologies such as onshore
wind and solar PV are widespread across the Mediterranean islands. Most of the countries in the
region have elaborated and submitted their final NECPs with an outline of their climate strategy
and targets per technology set for the coming decade. The highest targets are set for offshore
wind, followed by onshore energy, while wave and tidal energy targets are modest. The pathways
to reach 2030 targets and beyond differ substantially per country.
An assessment of the potentially suitable technologies for RES production in the Mediterranean
area shows that floating offshore wind remains a very promising technology. This fact is due to
large available areas with favourable wind speeds, suitable water depths, and relatively high
capacity factors, resulting in a technical potential of approximately 4,600 TWh/a by 2030 and
4,700 TWh/a by 2050. This data corresponds to an installed capacity potential of approximately
1,600 GW in 2030 and 1,620 GW in 2050.
Also, onshore technologies on islands, such as onshore wind and rooftop and utility-scale solar PV,
are promising technologies due to their maturity level, regulatory readiness, projected cost levels,
and social acceptance (in the case of solar). The technical potential for onshore wind is 60 TWh/a
or 22 GW in 2030 and 2050. For solar PV (rooftop and utility-scale combined), this study found a
technical potential of 150 TWh/a (90 GW) in 2030 and 207 TWh/a (125 GW) in 2050.
Wave energy has a significant technical potential at 4,500 TWh/a or 3,650 GW by 2050, 97
comparable to floating offshore wind. However, the technology is less mature and more expensive
than the aforementioned offshore and onshore technologies. Bottom-fixed offshore wind technical
potential is rather limited due to water depth constraints in the Mediterranean Sea and is
approximately 46 TWh/a (20 GW) in 2030 and 60 TWh/a (25 GW) in 2050. The role for tidal
energy will be more limited due to its limited resource and high cost levels; its technical potential
is limited to 22 TWh/a or 25 GW in 2050.
Figure 1-41: LCOE estimates of the most promising technologies

TMAs are identified where the resource potential is high within the areas available for power
generation by wind and wave energy. These 10 TMAs were chosen after careful consideration
based on the available areas for the three technologies with appropriate levels of resource
potential and LCOE. One area is identified because of the technology readiness level of bottom-
fixed wind. Areas that fit within a possible offshore meshed grid are prioritized. The final selection
of TMAs covers a wide range of the Mediterranean Sea from the Spanish Gulf of Cádiz to the Greek
Aegean Sea. For each of the TMAs, normalised time series are generated based on climatological
97
For wave technology, the technical potential is assumed to be the same in 2030 and 2050. See Section
1.4.1.2.
data. These time series quantify the resource generation profile in time for all considered
technologies.
Within the TMAs, this study defined several production blocks. Chosen production blocks have a
size of roughly 140 km2 and cover the available area for all technologies within the TMAs. This 140
km2 size corresponds to a typical offshore wind farm size of 1 GW with a power density of 7 MW/
km2. For each production block, the resource potential is calculated along with the maximum
installed capacity and the average LCOE for all technologies. A ranking for TMAs is proposed.
2.0 PRODUCTION SCENARIOS

Following the analysis of the technical – and economic potential, two offshore energy scenarios
with the onshore capacity and generation scenario in each country for 2030 and 2050 were
developed. Then, assessing the market context of the offshore generation share in terms of
electricity price and RES share was provided.
2.1 Scenarios
Based on the economic offshore energy production potential as identified in Task 1, this study
developed two realistic scenarios for each of the Mediterranean countries and for the years 2030
and 2050: the NECP scenario and the Ambitious scenario. These scenarios differ only with regards
to production capacity installed offshore; all other parameters such as fuel prices, demand, and
transmission capacity are kept constant. Also, LCOE for the different technologies are the same in
both scenarios, despite different volumes. These scenarios are essentially production scenarios,
only differing in installed offshore capacity. For each of the years 2030 and 2050, this study
developed one production scenario with NECP offshore energy generation and one production
scenario with ambitious offshore energy generation (see Figure). The NECP scenario fulfils the
targets in the NECPs, and the ambitious scenario has an increased share of offshore power
generation.
Figure 2-1: NECP production scenario versus ambitious production scenario

(Source: Sweco)
The production scenarios include all renewable and non-renewable technologies for EU-27, as the
power market model covers the EU as a whole (in addition to Norway and Switzerland). In the
model, Italy is divided into six bidding zones, and installed capacity and demand is defined for
each zone. For the other Mediterranean member states, installed capacity is defined at a national
level, meaning that intranational transmission systems are not explicitly modelled. Non-
interconnected systems are included in the model as part of the national systems. The production
scenarios were defined in two steps: by identifying the overall volumes and then assigning the
offshore Renewable Electricity Sources (RES-E) capacities to specific production blocks in the
TMAs.
Overall capacities are based on 2020 actuals and a thorough review of:
 Estimated phase out and potential renewal of existing production capacity

 Known plans for new capacity installations
 The integrated NECPs per country and their RES targets, especially existing plans for
offshore RES generation (NECP scenario)
 Decarbonization targets: the TYNDP’s National Trends scenario and the scenarios for 2030
and 2050 developed in the European Commission’s long-term strategy for a climate-
neutral economy.
As stated above, the NECP and ambitious scenarios only differ with regards to production capacity
installed offshore, and the scenarios share the same underlying assumptions regarding electricity
demand and deployment of onshore generation technologies. For both scenarios, overall volumes,
capacities, and electricity demand are aligned with explicit targets or indicative of trajectories
presented in the respective NECPs and other relevant long-term strategic documents. Therefore,
the scenarios can describe pathways with national efforts for achieving a climate-neutral economy
at the EU level by 2050. Even though cross-border transmission capacities have an important role
in balancing the variability of intermittent production sources and cover smaller energy
imbalances, the scenarios do not include large net producing countries supplying electricity to
other member states through large international power flows. On the contrary, each Member State
is assumed to cover its annual electricity demand nationally to a large extent.
Overall capacities are based on 2020 actuals and Sweco’s continuous scenario work updates, which
is described in Appendix B.1. For 2030, the capacities are aligned with the most updated NECPs
available at the time of writing with regards to:
 Targets concerning the share of RES in electricity consumption. Almost all NECPs
contain explicit targets concerning shares of renewable electricity generation in 2030 (for
some countries, such as Croatia, the target indicates achieving the overall target for share
of RES in energy consumption). The total installed RES capacity, onshore as well as
offshore, is determined to achieve the presented targets.
 Explicit targets or indicative trajectories of installed RES capacity in 2030. Most of
the NECPs contain technology-specific capacity targets or indicative trajectories for
reaching the general targets. Assumptions concerning installed capacity are aligned with
the targets or indicative trajectories in the respective NECPs as much as possible (primarily
the with additional measures scenarios).
 Targets concerning phase out of existing nuclear or fossil generation
technologies. Several of the NECPs contain targets concerning the phase out of nuclear
or fossil power generation. For example, Portugal, Spain, France, Italy, and Greece all
present targets of phasing out coal and lignite before 2030, and the NECPs for Spain and
France contain targets of reducing nuclear power generation.
As of the execution of this study, not all countries have submitted their final NECP to the European
Commission. When possible, capacities are aligned with targets and trajectories of the final NECPs;
otherwise the draft NECPs have been used.
For 2050, Sweco’s long-term scenarios are aligned with existing targets in the NECPs and national
long-term strategies. Relevant objectives presented in the documents are summarized in Table
2-1.
Table 2-1: Relevant objectives for the electricity system in 2050 for this study’s
scenarios
Country Target
Portugal 100% share of RES in electricity generation
Spain 100% share of RES in electricity generation
France Virtually carbon-free energy production by 2050 (with residual pollutants being
fossil fuels for air and sea transport and residual leaks)
Italy Climate-neutral economy
Slovenia Contribute to climate-neutral economy at an EU level
Croatia Contribute to climate-neutral economy at an EU level
Greece Climate-neutral economy
Cyprus Contribute to climate-neutral economy at an EU level
Malta Contribute to climate-neutral economy at an EU level
(Source: Sweco)
For 2050, the NECPs at most contain objectives concerning the share of RES in electricity
generation, and the NECPs do not contain technology-specific trajectories or targets for installed
capacity. Based on installed capacities in 2030, estimated phase out and potential renewal of
existing production capacity, and the relevant objectives in Table 2-1, overall capacities are
determined by the following principles:
 RES capacity is installed to meet existing targets concerning share of RES in

electricity generation and assumed electricity demand in 2050 (annually). For
member states without existing targets concerning RES shares in 2050, the expansion of
RES is based on Sweco’s long-term scenarios. The RES shares for these member states
have been computed in order to compare power generation in 2050 with more general
national and EU targets.
 Limited capacity increases are assumed for bio- and hydropower, and the
expansion of RES generation is mainly met by variable production sources from
solar PV and on- and offshore wind. Future expansions of hydropower are limited due
to resource limitations and environmental restrictions. Biogenic material also makes up a
limited resource, and the demand for bioenergy is expected to increase in other sectors as
the transition to a carbon-free energy system progresses. In these scenarios, hydropower
capacity within the Mediterranean member states remains basically constant between 2030
and 2050 while biopower capacity increases by 20%. This change can be compared with
variable production capacity, which increases by 60% during the same period. The
increase in biopower capacity mainly occurs for cogeneration plants, replacing current
fossil cogeneration.
 Pumped hydro and battery storage remain an unexplored potential. In the model,
pumped hydro and battery storage are used mainly to balance production and
demand variations within the day. At longer timescales, other types of electricity
storage will be necessary. The additional need for peak capacity is currently modelled by
natural gas, and the electricity cost at these hours is determined by the marginal cost of
natural gas generation. For countries with ambitions of zero or almost zero fossil
generation, this model can represent other dispatchable sources such as increased bio
generation or storage through hydrogen or power-to-X fuels.
 Coal and oil generation capacity is almost entirely phased out from the electricity
systems of the Mediterranean member states by 2050. Oil generation capacity is
phased out from baseload and cogeneration and is only used for peak generation in a few
member states. Baseload and cogeneration by natural gas are completely phased out in
Portugal, Spain, and France and to a large extent in Italy. Between 2030 and 2050, new
natural gas capacity is only introduced in Slovenia and Croatia to replace phased-out
nuclear and oil generation.
 Nuclear power capacity is based on current capacity, national targets, and
estimated phase out at the end of existing plants’ life cycles. French nuclear
capacity is reduced according to the national long-term target of reducing the nuclear
share of power generation to 50%by 2035. In Spain, nuclear capacity is assumed to be
phased out completely by 2050, based on the target scenario of the Spanish NECP. In
Slovenia, nuclear power generation is assumed to be phased out at the end of the existing
power plant’s life cycle between 2040 and 2045.
Assumed production capacities for the scenarios are shown in Figure 2-2 and Table 2-2. All
capacities are included per member state, regardless of location of offshore capacities
(Mediterranean Sea or other). The capacity assumptions in the model show a decrease in fossil-
based thermal capacity in all countries and a strong increase of solar and onshore wind power
production. In addition, offshore wind power is taking a substantial share of the renewable
capacity in Spain, France, Italy, and Greece.
Figure 2-2: Capacity assumptions in the different production scenarios for the
Mediterranean member states
(Source: Sweco)
Table 2-2: Capacity assumptions (MW)

Year Scenario Portugal Spain France Italy Slovenia Croatia Greece Cyprus Malta
Battery 2030 0 2 500 0 1 450 0 0 1 000 150 0

storage
2050 2 000 6 000 18 000 7 200 1 200 700 2 500 200 100
Coal 2030 0 0 0 0 600 300 2000 0 0
2050 0 0 0 0 0 0 0 0 0
Oil 2030 450 1 200 1 950 1 850 0 50 100 900 250
2050 0 0 1 050 300 0 0 100 0 0
Gas 2030 2 800 31 500 8 000 49 700 450 600 5 150 900 300
2050 2 000 20 100 5 150 24 700 450 250 3 900 900 400
Nuclear 2030 0 3 200 58 000 0 700 0 0 0 0
2050 0 0 40 200 0 1,000 0 0 0 0
Hydro 2030 8 500 24 150 26 400 22 200 1 300 2 600 3 900 0 0
2050 8 500 24 150 26 400 22 200 1 700 2 600 3 900 0 0
Biomass and 2030 1 400 2 350 2 000 4 000 100 200 500 50 0
waste
2050 2 000 2 750 2 950 3 750 50 150 900 50 0
Other RES 2030 150 100 250 950 0 50 100 0 0
2050 150 100 250 950 0 50 100 0 0
Solar 2030 9 450 50 750 45 900 52 000 1 650 600 6 850 850 250
2050 17 200 75 500 61 650 74 700 6 400 2 400 11 900 2 200 700
Year Scenario Portugal Spain France Italy Slovenia Croatia Greece Cyprus Malta
Wind 2030 9 000 48 600 37 150 18 400 150 1 300 7 650 200 0
onshore
2050 10 000 60 000 48 050 33 450 1 000 2 650 14 600 800 200
Wind 2030 NECP 300 0 5 400 1 000 0 0 0 0 0

offshore
Ambitious 1 500 4 000 8 900 5 350 0 450 2 200 0 0
2050 NECP 1 300 11 000 15 400 19 150 0 950 3 250 0 0
Ambitious 3 000 19 650 19 200 42 950 0 1 850 7 400 0 500
(Source: Sweco)
2.1.1 Offshore capacities in the scenarios

As described in Task 1, the deployment of offshore technologies in the Mediterranean region is
currently very limited, and the amount of targeted or projected offshore capacity in 2030
presented in the NECPs is relatively small. Based on explicit targets in the NECPs, installed
offshore capacity in the Mediterranean should amount to around 2,000 MW in 2030 (depending on
how much of the French target production is located to the Mediterranean). This amount can be
compared with the 22,000 MW currently installed in the northern seas (roughly half of which is
located in the UK) or the total offshore capacity of around 90,000 MW assumed in the EU’s
baseline scenario for 2030, presented in the European Commission’s vision for a climate-neutral
EU by 2050 (European Commission, 2018). Mediterranean offshore generation is also assumed to
be limited in the long-term scenarios for the European power system developed in the TYNDP
scenario report for 2020, where offshore wind capacity in 2040 ranges between 2,000-4,000 MW
(assuming 20% of French offshore capacity is in the Mediterranean).
Some key factors behind the low expectations of Mediterranean offshore generation are the high-
water depth (thus the limited potential for bottom-fixed offshore wind), the comparatively low
technology readiness level, and the high LCOE of floating wind and marine technologies. Based on
the findings of Task 1, the LCOE of wave and tidal remains considerably above a competitive level
through 2050, while the LCOE of floating offshore wind decreases towards current LCOE levels of
bottom-fixed turbines in 2030 and towards 2050. Both bottom-fixed and floating offshore wind
remain viable technology options for increasing renewable power generation in the Mediterranean
member states.
However, the future deployment of offshore power generation in general depends on its
competitiveness with alternative electricity sources, including other renewable electricity sources.
For the Mediterranean, the situation depends on its attractiveness compared to onshore wind and
solar power generation. Task 1 concluded that the LCOE of onshore wind and solar should continue
to drop and remain below the LCOE of offshore wind. This situation is most evident for utility-scale
solar PV, for which the estimated LCOE in 2030 and 2050 is roughly one-quarter of the LCOE of
floating offshore wind. The role of offshore wind in decarbonization of the Mediterranean power
system is influenced to a large extent by other factors limiting the potential of onshore wind and
solar or enhancing the attractiveness of offshore wind compared to the onshore alternatives, or
both. These important factors include:
 Availability of land and competing land or seabed uses

 Public acceptance of large deployments of wind and solar capacity
 Captured price of electricity (As the share of variable power generation grows larger, the
benefit of producing at different hours than other production sources increase.)
 Market barriers for distributed power generation
Although some of these aspects may be captured in predictive modelling of future power systems,
an adequate representation of national conditions is difficult to present in its entirety. The
objective of Task 2 is to develop two realistic power production scenarios for 2030 and 2050 for
use in the cost-benefit analysis and evaluation of grid options and bottlenecks in Task 3: one
production scenario with offshore energy generation compliant with NECPs and one production
scenario with higher ambitions. The amount of offshore generation in the two scenarios is not the
result of an energy investment model and should not be interpreted as the optimal deployment of
offshore generation based on specific sets of polices or LCOE estimations. Rather, offshore capacity
in each Member State is set based on technical potential, national targets, and judgments about
timing and likelihood for realization of ongoing projects up to 2030. The costs and benefits of the
proposed offshore generation are analysed more closely in Task 3.
2.1.1.1 NECP scenario

For 2030, the offshore capacity in the NECP scenario is based on the explicit targets of the most
recent NECPs presented in Table 1-3. For countries without explicit targets concerning offshore
generation in the Mediterranean, the installed Mediterranean capacity is based on existing offshore
projects listed in Table 1-8. Of the countries without any explicit targets concerning offshore
generation, only Greece has ongoing projects, with a total capacity of around 3,400 MW of
offshore wind projects in the planned or permitting development stages and a 0.75 MW wave
prototype project under development. However, the progress for offshore wind projects has been
slow, and 4C’s offshore database of global wind farm projects lists all projects as dormant (4C
Offshore, 2020). In the NECP scenario, installed Greek offshore wind capacity in 2030 is therefore
assumed to be zero. For 2050, the offshore capacity is based on a general assessment of each
Member State from relevant national objectives, EU targets, and electricity demand in 2050. Given
that each Member State is assumed to cover its annual electricity demand nationally to a large
extent, offshore capacity is then estimated from assumptions concerning demand and the future
development of other production technologies. For example, a large amount of offshore capacity is
assumed to be installed in Italy due to ambitious targets, a relatively high electricity demand, and
a limited potential for nuclear and onshore wind deployment.
Installed offshore capacity and the offshore share of power generation are presented for each
Member State in Table 2-3. In the NECP scenario, Mediterranean offshore wind capacity grows
from 2,400 MW in 2030 to 32,700 MW in 2050 while marine power technologies stay limited to
prototype projects and initial capacity targets throughout the period. Mediterranean offshore wind
is mainly located in Italy and Spain, but significant amounts are also found in France and Greece.
The offshore share of power generation in 2050 ranges between 0% and 15%.
Table 2-3: Installed offshore capacity and offshore share of power generation in
the NECP scenario
Country Offshore wind capacity Wave capacity (MW) Tidal capacity (MW) Offshore
(MW) share of
power
generation
2030 2050 2030 2050 2030 2050 2030 2050
Portugal 300 1,300 70 70 0 0 2% 6%
(0 Med.) (0 Med.) (0 Med.) (0 Med.)
Spain 0 11,000 50 50 0 0 0% 12%

(6,000 Med.)
(0 Med.) (0 Med.)
France 5 400 15,400 0 0 240 240 4% 11%

(1,400 (3,400 Med.) (0 Med.) (0 Med.)
Med.)
Italy 1 000 19 100 0 0 0 0 1% 17%
Slovenia 0 0 0 0 0 0 0% 0%
Croatia 0 950 0 0 0 0 0% 11%
Greece 0 3,250 0 0 0 0 0% 15%
Cyprus 0 0 0 0 0 0 0% 0%
Malta 0 0 0 0 0 0 0% 0%
Total 6,700 51,000 130 130 240 240 2% 12%

(2,400 (32,700 (0 Med.) (0 Med.) (0 Med.) (0 Med.)
Med.) Med.)
(Source: Sweco)
2.1.1.2 Ambitious scenario

Installed capacity and offshore share of power generation in the ambitious scenario are presented
in Table 2-4. The ambitious scenario assumes immediate measures and investments in offshore
wind throughout the Mediterranean, resulting in offshore wind capacity increasing to 13,300 MW in
2030. Given the long permitting and installation times for offshore wind projects, little capacity is
expected to be installed before 2027. Even by assuming a rather efficient development time of 7
years including permitting and a rapid, immediate increase of offshore wind development projects,
the assumed increase in offshore wind capacity in 2030 requires an average installation rate of
around 4.5 GW/a. between 2027-2030. This scenario can be compared with the installation rate in
the northern seas, which during the last 5 years has been around 3 GW p.a. on average. The 2030
offshore wind capacity in the ambitious scenario can therefore be regarded as very ambitious;
however, the proposed capacity can be realized. The rapid increase of offshore wind projects is
assumed to continue, and in 2050, the amount of installed offshore wind capacity is expected to
be twice as large as the installed capacity in the NECP scenario, with a total capacity of 76 GW.
This situation can be compared with Wind Europe’s vision for 2050, which allocates 70 GW in the
Mediterranean.
As for wave and tidal, no additional development is assumed compared with the NECP scenario.
The reason for the limited buildout of marine power is the high LCOE compared with offshore wind
and the large potential for offshore wind estimated in Task 1. Due to the very high potential for
offshore wind in the Mediterranean, the need for commissioning more expensive marine power
projects is assessed to be small.
Table 2-4: Installed offshore capacity and offshore share of power generation in
the ambitious scenario
Country Offshore wind capacity Wave capacity (MW) Tidal capacity (MW) Offshore
(MW) share of
power
generation
2030 2050 2030 2050 2030 2050 2030 2050
Portugal 1 500 3 000 70 70 0 0 9% 13%

98
(0 Med.) (1,500 Med.) (0 Med.) (0 Med.)
Spain 4 000 19 650 50 50 0 0 5% 20%
(2,000 (14,600 (0 Med.) (0 Med.)

Med.) Med.)
France 8 850 19,200 0 0 240 240 6% 14%

(3,350 (7,200 Med.) (0 Med.) (0 Med.)
Med.)
Italy 5 300 42 900 0 0 0 0 5% 33%
Slovenia 0 0 0 0 0 0 0% 0%
Croatia 450 1,850 0 0 0 0 7% 20%
Greece 2,200 7,400 0 0 0 0 13% 29%
Cyprus 0 0 0 0 0 0 0% 0%
Malta 0 500 0 0 0 0 0% 45%
Total 22,300 94,500 130 130 240 240 6% 21%

(13,300 (75,950 (0 Med.) (0 Med.) (0 Med.) (0 Med.)
Med.) Med.)
(Source: Sweco)
98
Portuguese islands are not included since they are located in the Atlantic.
Based on the above information, the concrete mix and location for offshore capacity to be added—
wave, tidal, bottom-fixed, or floating wind power—has been based on two main factors: ranking
the TMAs and a best LCOE approach for each of the production blocks within the TMAs, up to the
total annual generation volume required for the NECP or ambitious scenario and strategic
considerations for production location.
The best LCOE approach simply uses the production blocks with the lowest LCOE over those with
higher LCOE on a regional Mediterranean level and within a country. However, a strict best LCOE
approach would not necessarily lead to scenarios that are optimal from a wider perspective.
Therefore, the initial strategic considerations for location of the production blocks also included
basic considerations of where demand centres in the respective countries are located, meaning
that this study implicitly avoided the need to build out the transmission grid just to accommodate
the offshore volumes. As an example, for Italy, this study used the Gulf of Venice for bottom-fixed
and floating offshore wind due to its location close to the highly industrialized north of Italy instead
of the lower LCOE locations around Sicily. In addition, a regional spread to two or more offshore
locations for a country minimizes the risk for the same weather patterns impacting the variable
power production.
In this study, the capacity of complete production blocks was always added. Typically, as the size
of each production block is around 140 km2, each production block has roughly the capacity for an
offshore wind park of 1 GW. For power market simulations, this study has not yet allocated RES-E
capacity specifically to islands since these capacities are included in the capacities for the entire
bidding zone.
Figure 2-3: Regional distribution of offshore generation capacity in the NECP

(left) vs. ambitious scenario 2030 (right)
(Source: Sweco)
Figure 2-4: Regional distribution of offshore generation capacity in the NECP

(left) vs. ambitious scenario 2050 (right)
(Source: Sweco)
2.1.2 Other main assumptions

Fuel and carbon prices are key assumptions for determining the merit order of power generation
and, consequently, the price level of electricity prices. For the study, fuel prices are based on the
fuel price assumptions used in the national trend’s scenario of the TYNDP scenario report 2020.
The scenarios in the TYNDP report only stretch as far as 2040, so for 2050, the fuel prices are
based on the 2040 values. Although a simplification, an eventual price development between 2040
and 2050 is regarded to be small compared with the big uncertainty in the projections of future
fuel prices. For CO2, prices have been accommodated by the EC and are based on modelling
assessments within the development of EU’s long-term scenarios for 2050. Table 2-5 gives an
overview of the fuel price assumptions and a comparison with assumptions used in other ENTSO-E,
EU, and International Energy Agency scenarios. In most scenarios, the carbon price increases
dramatically towards 2040 and 2050, increasing the impact of the carbon price on electricity
prices. On the other hand, the impact of the prices of carbon and fossil fuels is expected to
decrease as the share of renewables in power generation increases.
Table 2-5: Fuel price assumptions used in the study compared with other ENTSO-
E, EU, and IEA scenarios99
Fuel Medgrid TYNDP 2020 EU LTS IEA Stated IEA Sustain.
offshore (€/MWh) scenarios policies Development
(€/MWh) (€/MWh) (€/MWh) (€/MWh)
2030 2050 2030 2040 2030 2050 2030 2040 2030 2040
Hard Coal 15.5 24.9 15.5 24.9 13.7 15.5 9.7 9.9 7.4 7.6
Natural Gas 24.9 26.3 24.9 26.3 37.2 46.5 24.3 27.0 22.8 22.8
Light Oil 73.8 79.9 73.8 79.9 80.6 95.6 57.2 66.7 40.8 38.9
Heavy Oil 52.6 61.9 52.6 61.9 50.4 60.0 35.6 41.7 25.0 23.7
Nuclear 1.7 1.7 1.7 1.7 - - - -
Lignite 4.0 4.0 4.0 4.0 - - - -
CO2 (€/ton) 28 250 27-53 75-100 28 250- 33 43 75 125

350
(Source: Sweco)
Cross-border transmission capacities for 2030 are based on current capacities and planned
projects in TYNDP 2020. Additional transfer capacities through 2050 have been added based on
the ST 2040 scenario in TYNDP 2020 and through Sweco’s identification of required capacities in
the iterative modelling process. The assumed interconnection levels of the Mediterranean member
states are shown in Table 2-6. Although increasing from 2017, the interconnection levels of
Portugal, Spain, Italy, and Greece are below the EU 2030 target in 2030 and 2050.
99
Prices have been transformed to comparable units and fuel types by Sweco.
Table 2-6: Assumed interconnection levels in the NECP scenario compared with
the EU 2030 target100
2017 2030 2050 EU 2030 target
(Actual)101
Portugal 9% 13%/11% 13%/10% 15%
Spain 6% 8%/9% 9%/9% 15%
France 9% 17%/20% 20%/22% 15%
Italy 8% 12%/9% 13%/10% 15%
Slovenia 84% 151%/128% 97%/83% 15%
Croatia 52% 103%/116% 70%/78% 15%
Greece 11% 12%/7% 17%/14% 15%
Cyprus 0% 69%/ 103% 15%
Malta 24% 24% 15% 15%
(Source: Sweco)
Another key parameter for the power market modelling is the future development of electricity
demand. European electricity demand is expected to increase significantly towards 2050 due to
electrification in the transport, heating, and industry sectors. However, the extent to which
electrification will affect electricity demand varies greatly between different scenarios and depends
on expectations of energy efficiency measures. In the analysis, electricity demand assumptions are
based on the national trends’ scenario of the TYNDP scenario report 2020. The national trends
scenario aims to reflect the commitments of each Member State in meeting the targets set by the
EC and includes the national objectives of the draft NECPs. The electricity demand in 2050 is based
on an extrapolation of ENTSO-E’s TYNDP national trend scenario for 2040 and Sweco’s long-term
demand scenarios, with the exception of Cyprus, whose demand has been adjusted to comply with
the long-term, 2050 projections in the NECP. The electricity demand in 2030 and 2050 is shown in
Figure 2-5 as relative to the demand in 2015. For the Mediterranean member states, the total
electricity demand is assumed to increase by 4% and 18% in 2030 and 2050, respectively. This
scenario can be compared with the European Commission’s long-term scenarios produced in the
in-depth analysis supporting the Commission’s vision for a climate-neutral EU by 2050 (European
Commission, 2018), where EU electricity demand increases by 16% to 2030 in the baseline
scenario and between 36-75% to 2050 depending on the scenario.
100
The interconnection level is calculated as the net transfer capacity (import/export) divided by the total
installed power generation capacity.
101
(European Commission, 2017)
Figure 2-5: Electricity demand increase relative to 2015

(Source: Sweco)
The load profile we currently use for 2030 and 2050 is not adjusted for the changes in
consumption within the different sectors.
2.2 Key results from the power market modelling

In this section, we present the key results of the power market modelling. In the analysis, we use
our power market model Apollo, described in detail in Appendix B, to analyse the defined
production scenarios in an energy-only market. Again, Apollo is not an investment model, and for
each scenario, installed capacities of production, transmission, and flexibility technologies are
defined by Sweco as described above. Based on installed capacities, electricity demand, and fuel
prices, Apollo optimizes generator dispatch by an hourly time resolution and provides information
on generation, transmission, emissions, and power prices.
2.2.1 Power generation share of renewable electricity produced on- and

offshore
Development of generation in the different scenarios is shown in Figure 2-6. Figures for each
Member State can be found in Appendix 0.
Figure 2-6: Generation in the four production scenarios compared with the
2020 reference scenario
(Source: Sweco)
To test the viability of the production scenarios, the generation results have been tested against
the national targets in terms of share of produced electricity, on- and offshore. In all four
scenarios, the resulting national RES shares (the green dots in Figure 2-7) reach at least the
national target for 2030 (grey bar). In most countries, the ambitious scenarios add a few
percentage points between 2% and 9% in RES-share for 2030. This contributes further to a higher
RES share in Europe and to decarbonization.
120%
100%
80%
60%
40%
20%
0%
Target 2030 (NECP) Target 2030 (NECP) (upper) Med Offshore - NECP_2030 Med Offshore - Ambitious_2030
Figure 2-7: RES share for the Mediterranean countries in the two offshore
generation scenarios in 2030
(Source: Sweco)
2.2.2 Assessing the market context of the production scenarios

To analyse the long-term market context, such as electricity price as an important precondition for
investment in these offshore RES-E assets, this study models the European power market with
Sweco’s European Power Market Model Apollo, reflecting SRMC in an energy-only market. Hourly
production time series for relevant production blocks from Task 1 are used as input for the
modelling.
140
120
100
Power price [EUR/MWh]
80
60
40
20
0
Med Offshore - NECP_2030 Med Offshore - Ambitious_2030 Med Offshore - NECP_2050 Med Offshore - Ambitous_2050
Figure 2-8: Power prices

(Source: Sweco)
Power prices defined as short-run, marginal cost-based power prices in our power market model
are rather comparable throughout all countries in 2030, and power price levels still hinge very
much on fuel price and the CO2 price. With a decreasing share of fossil-based thermal capacity and
increasing share of variable renewables with low or close-to-zero marginal costs, power prices in
2050 still hinge on the CO2 price, which is assumed as 250 €/t in our scenarios. Regardless of
scenario year, power prices fall significantly with increased offshore RES-E ambitions.
To assess the market context, this study also looked at prices for each technology and compared
these to the LCOE of the chosen production blocks. Since grid connection costs, taxes, and
decommissioning costs are excluded from the LCOE cost calculation, the comparison is
underestimating actual LCOE by a few €/MWh and will only give a rough result. Nevertheless,
interesting observations can be made.
In general, captured prices for offshore wind are slightly lower than the average power price in
respective bidding zones in both 2030 scenarios. For Spain (about 5 €/MWh) and Greece (about 11
€/MWh), captured prices for offshore wind are considerably lower than the power price in the
ambitious scenario due to the high share of RES installed and similar production patterns from
other regions pushing down power prices at times.
Figure 2-9: LCOE102 vs. power prices and captured prices in the 2030 NECP
scenario
(Source: Sweco)
Nevertheless, in most countries and TMAs, general power prices and captured prices are high
enough to cover a substantial part of the LCOE of the chosen production blocks with either bottom-
fixed or floating offshore wind power (see Figure 2-9 and Figure 2-10).
For Sicily, the results indicate that at least a large part of the assumed production (567 MW) could
be installed on its own merits without the need for RES support. However, there would be a RES
support need for floating wind in the Gulf of Lion both in France and Spain and the North Aegean
Sea in addition to bottom-fixed wind in the Gulf of Venice.
102
LCOE values are without the dedicated grid connection, as calculated in Task 1.
Figure 2-10: LCOE vs. power prices and captured prices in the 2030 ambitious
scenario
(Source: Sweco)
2.2.3 CO2 emissions

The analysis shows that CO2 emissions fall significantly in most Mediterranean countries between
2020 and 2030, most significantly in Portugal, Spain, Italy, and Greece (see Figure 2-11).
Figure 2-11: CO2 emissions from power production in 2020, 2030, and 2050 in
the different production scenarios
(Source: Sweco)
Furthermore, the biggest additional gains can be made in almost all Mediterranean countries by
introducing more offshore generation, especially within the 2050 horizon (see Figure 2-12).
Figure 2-12: Further CO2 emissions savings for the NECP and ambitious scenarios
(Source: Sweco)

Comparing all four scenarios designed to reach or exceed the respective national target for 2030,
the ambitious scenarios add a few percentage points between 2% and 22% in RES share for 2030.
This contributes further to a higher RES share in Europe and to decarbonization.
Power prices are rather comparable throughout all countries in 2030, and power price levels
depend still very much on fuel price and the CO2 price. With a decreasing share of fossil-based
thermal capacity and increasing share of variable renewables with low or marginal costs close to
zero, power prices in 2050 still hinge on the CO2 price but to a lesser degree, depending on how
much fossil-based capacity remains in the European power system. This study observes a strong
price volatility towards and an increasing number of hours with zero prices. Regardless of scenario
year, power prices fall significantly with increased offshore RES-E ambitions.
In general, captured prices for offshore wind are slightly lower than the average power price in the
respective bidding zones in both 2030 scenarios. For Spain and Greece, captured prices for
offshore wind are considerably lower than in the ambitious scenario due to the high share of RES
installed and similar production pattern from other regions pushing down power prices at times.
Nevertheless, in most countries and TMAs, general power prices and captured prices are high
enough to cover a substantial part of the LCOE of the chosen production blocks with either bottom-
fixed or floating offshore wind power. For Sicily, results indicate that at least a large part of the
assumed production could be installed on its own merits without the need for RES support.
However, there would be a RES support need for the floating wind in the Gulf of Lion (both in
France and Spain) and the North Aegean Sea in addition to bottom-fixed wind in the Gulf of
Venice. The analysis also shows that CO2 emissions fall significantly in most Mediterranean
countries between 2020 and 2030, most significantly in Portugal, Spain, Italy, and Greece, and
that substantial additional gains can be made in almost all Mediterranean countries by introducing
more offshore generation, especially with the 2050 horizon.
3.0 GRID OPTIONS

Building on the work in previous tasks, this section lays out options for grid connection in the 10
TMAs. In Task 1, the TMAs with associated production blocks were defined such that:
 Each TMA contains about 40-70 production blocks.

 Each production block, with a specified geographic location, has a given potential for
renewable energy production defined through a maximum installed power and a
production time series. The LCOE for each type of renewable energy technology has also
been determined.
In Task 2 we set up two scenarios, which describe projected outcomes in 2030 and 2050, with
conservative and ambitious expansions levels. The scenarios define:
 The total installed offshore renewable energy per country

 Which production blocks are activated
 Which technology is chosen for each activated production block
Thus, Task 3 suggests ways to connect the realised production blocks to the transmission grid
onshore, and, if deemed suitable, to each other.
3.1 Method
The grid connection was made in three steps. First, a base alternative was calculated. The base
alternative is a radial connection of each activated production block, meaning a straight line to
the nearest onshore 380 kV-400 kV transmission grid station in the same country as the
production block. Locations of grid stations have been retrieved from the ENTSO-E grid map and
further adjusted through other map studies where possible. The connection was designed (HVAC
or HVDC) and dimensioned based on the installed power of the production block and the
distance from the production block to the transmission grid station. The radial connection does
not have full redundancy, meaning that failure of a component might lead to the loss of an
entire production block. For certain cases with parallel cables, however, failure of a cable might
mean that the remaining cables can still transmit part of the production from the production
block. Failure of one component will not lead to the loss of production from more than one
production block.
As a second step, a partial optimization was made where production blocks were grouped
together to share one or more common links to shore, creating a hub connection. This situation
means that the connection can be built for higher powers and that the price per MW connected
decreases. The downside is that production blocks become dependent on each other. Failure of
a single cable might mean loss of production from several production blocks rather than just
one.
In a third step, the specific conditions at each TMA were assessed, and an optional grid
connection was considered, if deemed advantageous. Such a connection can include grouping of
several production blocks, connecting a production block to more than one onshore station, or
connecting production blocks so that two countries become interconnected. The benefits of the
optional grid connection have been described qualitatively, and the costs have been listed. If the
optional grid connection includes meshing (i.e., connection of a production block or a group of
production blocks to more than one onshore station), there will be a higher redundancy than in
the radial connection and hub connection. Loss of one component in this case does not lead to
loss of full production from a production block or group of production blocks. Figure 3-1
describes schematically the three different steps.
Figure 3-1: Grid connection steps

(Source: Sweco)
3.1.1 Assumptions for the radial connection

The following assumptions were made in the construction of the radial connection:
 Each production block has been connected to the nearest onshore 380-400 kV
transmission grid station in the same country as the production block.
 Only cables have been considered—no overhead lines.
 Cable routes have been calculated as the bird flies. For the subsea part of the cable, a
linear sea bottom slope has been assumed.
 No consideration has been given to the bottom topology, apart from the depth at the
production block.
 Technology (HVAC or HVDC) has been chosen based on the cable length and total cost
(CAPEX, OPEX, and losses) over 25 years. For AC, 220 kV has been assumed. The unit
cost figures and loss figures used are listed in Appendix C.
 Each connection has been dimensioned so that it can transmit the full power of the
production block.
 The maximum single connection has been assumed to be 2 GW for technical reasons.
3.1.2 Assumptions for the hub connection

The following assumptions were made in the construction of the hub connection:
 Each production block has been connected to the nearest onshore 380-400 kV
transmission grid station in the same country as the production block.
 Only cables have been considered—no overhead lines.
 All production blocks connecting to the same station have been grouped together, and
the connecting distance was assumed to be equal to the average distance from the
included production blocks to the station.
 The associated costs and losses for the connection have been calculated using the total
installed power of the grouped production blocks and the average distance.
 Technology (HVAC or HVDC) has been chosen based on the total cost (CAPEX, OPEX,
and cost of losses) over 25 years. For AC, 220 kV has been assumed. The unit cost
figures and loss figures used have been listed in Appendix C.
If the total power of the grouped production blocks exceeds 2 GW, the connection has been
calculated as a multiple of the costs for a 2 GW connection.
The above procedure means that no detailed design of how and where the production blocks
would be interconnected in reality was made. Instead, it is assumed that interconnection is
possible and that the cost for the total connection relates only to the total installed power and
the average distance. Thus, this is not an attempt to lay out a detailed connection option.
Rather, it is an indication at a general level of what cost benefits might come from market
forces, further developments of grid codes, and a more coordinated realization of projects in
comparison with the radial connection.
3.1.3 Considerations for optional grid connection design

The following considerations were made when determining whether there are advantageous
optional grid connections:
 Are there obvious benefits of connecting a production block or a group of production

blocks to more than one station in the same country? If so, is this extra connection
shorter or of the same magnitude as a connection between the stations onshore?
 Are there ways to connect production blocks belonging to different countries together,
thereby forming a link between the countries? If so, is the extra connection short in
relation to the option of directly connecting the two countries?
 Are there planned or ongoing interconnection projects in the vicinity of the TMA so that
there might be coordination benefits if an optional grid connection was used?
 Are there obvious ways to connect the production blocks to stations not belonging to the
380 kV-400 kV transmission grid that might mean significantly lower costs?
Based on the above analysis, a maximum of one optional grid connection was calculated for
each TMA. If there were other strong candidates, they are mentioned but not evaluated
numerically.
3.2 Grid Connection Results

In this section, the calculated grid connections for each TMA is described for each scenario.
Connection costs are also presented.
3.2.1 TMA: Gulf of Lion

Table 3-1 describes a summary of the outcome for the different scenarios for this TMA, with
production blocks connecting to the south of France and northeast of Spain.
Table 3-1: Activated production blocks for Gulf of Lion

Scenario Number of activated Total installed power (GW)
production blocks
Ambitious
Ambitious
Ambitious
Ambitious
NECP
NECP
NECP
NECP
2030
2030
2050
2050
2030
2030
2050
2050
France 2 4 4 8 1.4 3.3 3.3 7.2
Spain 0 3 8 16 0.0 1.8 5.8 10.8
Total 2 7 12 24 1.4 5.1 9.2 18.0
(Source: Sweco)
3.2.1.1 Radial connection

The radial connection for the four scenarios is illustrated in Figure 3-2, and the associated costs
are listed in Table 3-2. The individual connections are 35 km-111 km, connecting production
blocks with an installed power of 320 MW-990 MW. Blue squares are production block centres
while red circles are transmission grid stations.
Figure 3-2: Radial connection for Gulf of Lion

(Source: Sweco)
Table 3-2: Costs and losses for radial connection, Gulf of Lion
Scenar CAPEX (M€) OPEX (M€/year) Losses (GWh/year)
io
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
France 320 700 700 1,527 4 9 9 21 206 503 515 1,125
Spain 0 409 1,446 2,945 0 5 20 42 0 261 915 1,686
Total 320 1,109 2,146 4,473 4 15 29 62 206 764 1,430 2,811
(Source: Sweco)
3.2.1.2 Hub connection

The hub connection for the four scenarios is illustrated in Figure 3-3, and the associated costs
are listed in Table 3-3. The separate connections are 43 km-77 km, connecting production block
groups with a total installed power of 410 MW-7,350 MW. Blue squares are production block
centres while red circles are transmission grid stations.
Figure 3-3: Hub connection for Gulf of Lion

(Source: Sweco)
Table 3-3: Costs and losses for hub connection, Gulf of Lion
io
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
2030
2050
2030
2050
2030
2050
France 320 392 392 555 4 5 5 8 206 386 395 636
Spain 0 331 533 580 0 5 8 8 0 267 535 636
Total 320 722 924 1,135 4 10 13 16 206 653 930 1,272
(Source: Sweco)
3.2.1.3 Optional grid connection

In this TMA, production blocks that connect to France and Spain are quite close to each other.
Therefore, the chosen optional grid connection interconnects production blocks to create a link
between France and Spain, increasing the transfer capacity across the Pyrenees. This is feasible
for the ambitious scenario in 2030, the NECP scenario in 2050, and the ambitious scenario in
2050. The extra interconnection was made with the hub connection as a starting point and has
been illustrated in Figure 3-4. The added link is displayed in red.
No optional
connection for
this scenario
scenario
Figure 3-4: Optional grid connection for the Gulf of Lion

(Source: Sweco)
The dimensioning of the added link is not self-evident. Furthermore, the added link introduces
possibilities to change the dimensioning of the links to shore since there is now more than one
path from each production block to shore. The suitable dimensions depend on strategic choices:
 What is the value of extra redundancy for the grid connection versus the extra costs of a
link with a higher capacity?
 What is the value of having the possibility to sell the produced electricity to more than
one country versus the extra cost of a link with higher capacity?
 What are the projected possibilities for selling spare capacity in the created cross-
country link versus the extra cost of a link with higher capacity?
The necessary investigations to answer the above questions are beyond the scope of this study.
As a rough estimate, the extra link is dimensioned here so that its capacity is equal to the
greater of the two links to shore. Furthermore, the weaker of the two links to shore is also
upgraded so that its capacity is equal to the greater one. Thereby, the whole set of links has the
same capacity. The motivation for this upgrade is that the connection of France and Spain
across the Pyrenees is a known weak section of the grid. This topic is discussed further in
Section 3.4. The suggested design implies some possible operational choices:
 The set of links can be used as a cross-country interconnector, and its spare capacity
can be sold.
 The full power of either of the two groups of production blocks can be fed to either
country, in case of outage of the other group of production blocks.
The details of the optional connection are summarized in Table 3-4. Losses are not included
since they depend on how the meshed grid is operated.
Table 3-4: Costs for optional grid connection in the Gulf of Lion
Scenario CAPEX (M€) OPEX (M€/year)
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
France 320 504 728 1,362 4 7 10 19
Spain 0 558 924 1,670 0 8 13 24
Cross country 0 204 362 575 0 4 7 11
Total 320 1,266 2014 3,606 4 18 30 54
Link capacity (GW) 0 2.8 4.5 7.4
(Source: Sweco)
3.2.2 TMA: Malta

Table 3-5 describes a summary of the outcome for the different scenarios for this TMA with
production blocks connecting to Italy.
Table 3-5: Activated production blocks for Malta

Scenario Number of activated production blocks Total installed power (GW)
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Ambitious
Ambitious
Ambitious
Ambitious
2030
2050
2030
2050
Malta 0 0 0 1 0 0 0 0.5
(Source: Sweco)

Production blocks are only activated in the 2050 ambitious scenario. The radial connection is
illustrated in
No activated No activated
production production
block for this block for this
scenario scenario
No activated
production
block for this
scenario
Figure 3-5, and the associated costs are listed in Table 3-6. Because there is no 380 kV-400 kV
station on Malta, the connection is made to Italy instead. The size of the production block is
490 MW, and the connection length is about 160 km. Blue squares are production block centres,
and red circles are transmission grid stations.
scenario scenario
No activated
production
block for this
scenario
Figure 3-5: Radial connection for Malta

(Source: Sweco)
Table 3-6: Costs and losses for radial connection, Malta

Scenario CAPEX (M€) OPEX (M€/year) Losses (GWh/year)
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
2030
2050
2030
2050
2030
2050
Malta 0 0 0 278 0 0 0 4 0 0 0 51
(Source: Sweco)

Because only one production block is activated in this TMA, there is no possibility of group
production blocks for higher efficiency, so no hub connection is defined.

No 380 kV-400 kV transmission grid station exist on Malta. However, Malta has a 220 kV link to
Sicily. Therefore, the optional grid connection studied here will be to connect to Malta at 220 kV
instead of to Italy at 380 kV-400 kV. On a general level, the consequences of this choice are:
 The connection length decreases from 160 km to 35 km. The costs are thereby
drastically decreased.
 The possibility to export full power from the production block becomes dependent on:
 The capacity of the link between Malta and Sicily
 The need for power on Malta

The capacity of the current link between Malta and Sicily is 200 MW. Thus, it is unlikely that the
full power of the production block (490 MW) can be exported, as it would require full power flow
through the link and an excess load of 290 MW on Malta. A detailed study of the possibility to
export the power is beyond the scope of this report, but it is likely that curtailment would be
necessary. The details of the optional grid connection are illustrated in Figure 3-6 and in Table
3-7.
scenario scenario
No activated
production
block for this
scenario
Figure 3-6: Optional grid connection for Malta

(Source: Sweco)
Table 3-7: Costs for optional grid connection, Malta

io
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2030
NECP 2050
NECP 2050
NECP 2030
NECP 2050
Malta 0 0 0 99 0 0 0 1 0 0 0 44
(Source: Sweco)
3.2.3 TMA: Sicily

Table 3-8 describes a summary of the outcome for the different scenarios for this TMA with
production blocks connecting to Sicily.
Table 3-8: Activated production blocks, Sicily


production blocks
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 4 8 9 15 0.6 1.4 2.4 8.7
(Source: Sweco)

The radial connection for the four scenarios is illustrated in Figure 3-7, and the associated costs
are listed in
Table 3-9. The individual connections are 90 km-163 km, connecting production blocks with
installed power of 70 MW-1,060 MW. Blue squares are production block centres, and red circles
are transmission grid stations.
Figure 3-7: Radial connection for Sicily
(Source: Sweco)
Table 3-9: Costs and losses for radial connection, Sicily

Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 711 1,5 1,9 3,9 8 18 23 47 59 148 295 1,11
29 20 61 5
(Source: Sweco)

are listed in
Table 3-10. The separate connections are 127 km-136 km, connecting production block groups
with a total installed power of 570 MW-8,690 MW. Blue squares are production block centres,
Figure 3-8: Hub connection for Sicily
(Source: Sweco)
Table 3-10: Costs and losses for hub connection, Sicily

Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2030
NECP 2050
NECP 2050
NECP 2030
NECP 2050
Italy 211 423 789 2,173 2 6 8 26 60 172 143 1,099
(Source: Sweco)

For this TMA, no clear favourable optional grid connection was identified. However, in the
ENTSO-E 10-year network development plan, there is an HVDC interconnection project linking
Sicily with Tunisia. The status is in permitting, and the commissioning date is currently set to
2027 (see Figure 3-9). Procedural and political issues apart, it is possible to envisage technical
solutions where the connection of the production blocks is realised in parallel with the HVDC link
or where the two projects are integrated as a single multipole HVDC link. In either case, the two
links would have an impact on each other, though the economic outcome of such an impact is
beyond the scope of this study to describe. Section 3.4 contains some additional comments on
this issue.
Figure 3-9: Planned interconnection Italy-Tunisia103

(Source: (ENTSO-E, 2019b))
3.2.4 TMA: Gulf of Venice
103
From ENTSO-E 10-year network development map.
Table 3-11 summarises the outcome for the different scenarios for this TMA with production
blocks connecting to Italy and Croatia.
Table 3-11: Activated production blocks for Gulf of Venice

Scenario Number of activated production Total installed power (GW)
blocks
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 1 8 12 22 0.4 4 8 16.4
Croatia 0 1 2 3 0 0.4 1 1.9
Total 1 9 14 25 0.4 4.4 9 18.3
(Source: Sweco)

The radial connection for the four scenarios is illustrated in Figure 3-10, and the associated
costs are listed in
an installed power of 110 MW-970 MW. Blue squares are production block centres, and red
circles are transmission grid stations.
Figure 3-10: Radial connection for Gulf of Venice
(Source: Sweco)
Table 3-12: Costs and losses for radial connection, Gulf of Venice
Scenari CAPEX (M€) OPEX (M€/year) Losses (GWh/year)
o
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 102 1,031 1,977 3,912 1 14 29 57 24 221 474 978
Croatia 0 202 426 776 0 3 7 13 0 202 426 776
Total 102 1,233 2,403 4,687 1 17 36 70 24 423 900 1,754
(Source: Sweco)

are listed in
Table 3-13. The separate connections are 33 km-107 km, connecting production block groups
with a total installed power of 430 MW-10,010 MW. Blue squares are production block centres,
Figure 3-11: Hub connection for Gulf of Venice
(Source: Sweco)
Table 3-13: Costs and losses for hub connection, Gulf of Venice
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
2030
2050
2030
2050
2030
2050
Italy 102 532 1,183 2,369 1 8 18 36 24 228 487 1,004
Croatia 0 202 334 472 0 202 334 472 0 202 334 472
Total 212 423 789 2,173 2 6 8 26 60 172 143 1,099
(Source: Sweco)

In this TMA, the distance between production blocks belonging to Italy and Croatia is of the
same order of magnitude as or shorter than the distance from Croatian production blocks to the
Croatian shore. Therefore, the chosen optional grid connection is to add an extra offshore link
between production blocks belonging to Italy and Croatia, creating a link that can be used for
cross-country power flow. This is feasible for the ambitious scenario in 2030, the NECP scenario
in 2050, and the ambitious scenario in 2050. The extra interconnection was made with the hub
connection as a starting point and has been illustrated in
No optional
connection for
this scenario
Figure 3-12. The added link is displayed in red.

No optional
connection for
this scenario
Figure 3-12: Optional grid connection for Gulf of Venice
(Source: Sweco)
The dimensioning of the added link is not self-evident. Furthermore, the added link introduces
possibilities of changing the dimensioning of the links to shore since more than one path now
exists from each production block to shore. The suitable dimensions depend on strategic
choices:
 What is the value of extra redundancy for the grid connection versus the extra costs of a
link with a higher capacity?
 What is the value of having the possibility to sell the produced electricity to more than
one country versus the extra cost of a link with higher capacity?
 What are the projected possibilities for selling spare capacity in the created cross-
country link versus the extra cost of a link with higher capacity?
The necessary investigations to answer the above questions are beyond the scope of this study.
As a rough estimate, the extra link is here dimensioned so that its capacity is equal to the
weaker of the two links to shore (meaning the Croatian link). This implies several possible
operational choices:
 The set of links can be used as a cross-country interconnector, and its spare capacity
can be sold.
 The full power of the Croatian group of production blocks can be fed to either country in
case of an outage of the Italian group of production blocks.
 Part of the power of the Italian group of production blocks can be fed to either country
in case of an outage of the Croatian group of production blocks.
Figure 3-13 summarises the details of the optional connection. Losses are not included because
they depend on how the meshed grid is operated.
Figure 3-13: Planned projects in the vicinity of Gulf of Venice 104

Notably, there are three projects in the ENTSO-E 10-year network development plan that are
situated in the same region as this TMA: the Adriatic HVDC link, the Central Northern Italy
Connector, and the CSE1 New (see Figure 3-13). The two former projects exist to strengthen
the Italian transmission grid, and the latter project exists to strengthen the Croatian
transmission grid and enable cross-country flows to and from Bosnia and Hercegovina. Neither
of these projects have a direct impact on the layout of the optional grid connection, but if all of
them are realised, the respective transmission grids will be better equipped to accept injections
of power from the production blocks.
3.2.5 TMA: Gulf of Cádiz

blocks connecting to the south of Spain and Portugal.
Table 3-14: Activated production blocks for Gulf of Cádiz

production blocks
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Ambitious
Ambitious
Ambitious
Ambitious
2030
2050
2030
2050
Spain 0 1 1 7 0 0.2 0.2 3.8
Portugal 0 0 0 2 0 0 0 1.5
Total 0 1 1 9 0 0.2 0.2 5.3
(Source: Sweco)

costs are listed in Table 3-15. The individual connections are 54 km-90 km, connecting
104
production blocks with installed power of 190 MW-990 MW. Blue squares are production block
centres, and red circles are transmission grid stations.
No activated
production
block for this
scenario
Figure 3-14: Radial connection for Gulf of Cádiz
(Source: Sweco)
Table 3-15: Costs and losses for radial connection, Gulf of Cádiz
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Spain 0 142 142 1,249 0 2 2 17 0 17 18 386
Portugal 0 0 0 345 0 0 0 5 0 0 0 345
Total 0 142 142 1,594 0 2 2 22 0 17 18 731
(Source: Sweco)

The hub connection for the four scenarios is illustrated in
No activated
production
block for this
scenario
Figure 3-15. Only for the 2050 ambitious scenario does the hub connection differ from the
radial connection. The separate connections for the 2050 ambitious scenario are 58 km-80 km,
connecting production block groups with a total installed power of 1,180 MW-2,650 MW. Blue
squares are production block centres, and red circles are transmission grid stations.
No activated
production
block for this
scenario
Figure 3-15: Hub connection for Gulf of Cádiz

(Source: Sweco)

For this TMA, no clear favourable optional grid connection was identified. The southern group of
production blocks belonging to Spain could be connected to Morocco, creating an additional link
between the countries. However, such a link would be significantly longer and more complex to
operate compared with adding another cable along the same route as the existing ones. Thus,
no optional grid connection has been defined.
However, Portugal and Morocco have agreed on plans for a link connecting the two countries.
Procedural and political issues apart, it is possible to envisage technical solutions where the
connection of the production blocks is realised in parallel with the envisaged link or the two
projects are integrated as a single multipole HVDC link. In either case, the two links would have
an impact on each other, though the economical outcome of such an impact is beyond the scope
of this study to describe.
3.2.6 TMA: North Aegean Sea

Table 3-16 summarizes the outcome for the different scenarios for this TMA with production
blocks connecting to central Greece.
Table 3-16: Activated production blocks for North Aegean Sea

Scenario Number of activated production Total installed power (GW)
blocks
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Ambitious
Ambitious
Ambitious
Ambitious
2030
2050
2030
2050
Greece 0 2 3 4 0 2.2 3.3 4.3
(Source: Sweco)

The radial connection for the four scenarios is illustrated in
No activated
production
block for this
scenario
Figure 3-16, and the associated costs are listed in Table 3-17. The individual connections are
58 km-100 km, connecting production blocks with installed power of 1,085 MW. Blue squares
are production block centres, and red circles are transmission grid stations.
No activated
production
block for this
scenario
Figure 3-16: Radial connection for North Aegean Sea
(Source: Sweco)
Table 3-17: Costs and losses for radial connection, North Aegean Sea
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Greece 0 448 725 1,039 0 7 11 16 0 217 340 457
(Source: Sweco)

are listed in Table 3-18. The separate connections are 65 km-79 km, connecting production
block groups with a total installed power of 2,170 MW-4,340 MW. Blue squares are production
block centres, and red circles are transmission grid stations.
No activated
production
block for this
scenario
Figure 3-17: Hub connection for North Aegean Sea
(Source: Sweco)
Table 3-18: Costs and losses for hub connection, North Aegean Sea
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Greece 0 333 541 777 0 5 8 12 0 219 344 465
(Source: Sweco)

For this TMA, no clear favourable optional grid connection was identified. However, the Greek
TSO foresees an extended submarine grid for the interconnection of major islands in the Aegean
Sea, providing the capability for the connection of RES projects, in the 10-Year Network
Development Plan for 2021-2030 (ADMIE, 2020). Procedural and political issues apart, it is
possible to envisage technical solutions where such a grid is realized in parallel with the
connection of the production blocks in the area. The economic benefits of such an integration
are beyond the scope of this study to describe.
3.2.7 TMA: Ionian Sea

Table 3-19 summarizes the outcome for the different scenarios for this TMA with production
blocks connecting to the south of Italy.
Table 3-19: Activated production blocks for the Ionian Sea

Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 0 0 3 10 0 0 3.1 9.3
(Source: Sweco)

costs are listed in
installed power of 710 MW-1,040 MW. Blue squares are production block centres, and red circles
are transmission grid stations.
scenario scenario
Figure 3-18: Radial connection for the Ionian Sea
(Source: Sweco)
Table 3-20: Costs and losses for radial connection for the Ionian Sea
NECP 2030
NECP 2030
NECP 2050
NECP 2050
NECP 2030
NECP 2050
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
Ambitious
2030
2050
2030
2050
2030
2050
Italy 0 0 614 2,094 0 0 8 27 0 0 261 769
(Source: Sweco)

are listed in Table 3-21. The separate connections are 63 km-67 km, connecting production
block groups with a total installed power of 3060 MW-9,250 MW. Blue squares are production
block centres, and red circles are transmission grid stations.
scenario scenario
Figure 3-19: Hub connection for the Ionian Sea
(Source: Sweco)
Table 3-21: Costs and losses for hub connection, Ionian Sea
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 0 0 442 1,398 0 0 6 18 0 0 259 791
(Source: Sweco)

For this TMA, there is no obvious optional grid connection. Stations in Greece and Albania might
have been considered for connection; however, in both cases, the distances are quite large, and
in Greece’s case, there is already an HVDC connection. Thus, for this TMA, no optional grid
connection has been defined.
3.2.8 TMA: Corsica-Sardinia

blocks connecting to Italy.
Table 3-22: Activated production blocks for Corsica-Sardinia

Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 0 0 6 12 0 0 5.6 8.6
(Source: Sweco)
The radial connection for the four scenarios is illustrated in Figure 3-20: , and the associated
costs are listed in Table 3-23. The individual connections are 99 km-189 km, connecting
production blocks with installed power of 300 MW-1,010 MW. Blue squares are production block
centres, and red circles are transmission grid stations.
scenario scenario
Figure 3-20: Radial connection for Corsica-Sardinia

(Source: Sweco)
Table 3-23: Costs and losses for radial connection for Corsica-Sardinia
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 0 0 3,160 4,831 0 0 57 86 0 0 448 665
(Source: Sweco)

The hub connection for the four scenarios is illustrated in
scenario scenario
Figure 3-21, and the associated costs are listed in Table 3-24. The separate connections are
133 km-183 km, connecting production block groups with a total installed power of 1,010 MW-
5,516 MW. Blue squares are production block centres, and red circles are transmission grid
stations.
scenario scenario
Figure 3-21: Hub connection for Corsica-Sardinia
(Source: Sweco)
Table 3-24: Costs and losses for hub connection, Corsica-Sardinia

Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Italy 0 0 2,360 2,992 0 0 36 45 0 0 265 459
(Source: Sweco)

No obvious favourable optional grid connection was identified for this TMA. Though it would be
possible to connect the production blocks to Sardinia or Corsica, the main load centres are on
the mainland, rendering limited value to an additional and quite complex link from the islands to
the mainland via the groups of production blocks. Thus, for this TMA, no optional grid
connection has been defined.
Notably, in the ENTSO-E 10-year network development plan, an HVDC interconnection between
northern Italy and Tunisia exists (see Figure 3-22). Procedural and political issues apart, it is
possible to envisage technical solutions where the HVDC link is realised in parallel with the
connection of the production blocks or integrated as a single multipole HVDC link. In any case,
the projects would have an impact on each other, though the economic outcome of such an
impact is beyond the scope of this study to describe. Section 3.4 contains some additional
comments on this situation.
Figure 3-22: Planned projects in the vicinity of Corsica-Sardinia105

(Source: Sweco)
3.2.9 TMA: South Aegean Sea

blocks connecting to central Greece. Five of the eight activated production blocks are islands.
These contribute with about 0.5 GW of the total installed power.
105
Table 3-25: Activated production blocks for South Aegean Sea

Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Greece 0 0 0 8 0 0 0 3.5
(Source: Sweco)

Production blocks are only activated in 2050 ambitious scenario. The radial connection is
illustrated in
scenario scenario
No activated
production
block for this
scenario
Figure 3-23, and the associated costs are listed in Table 3-26. For the sea-based production
blocks, the individual connections are 58 km-75 km long, connecting production blocks with
installed power of 940 MW-1,100 MW. For the islands, the individual connections are 30 km-121
km long, connecting production blocks with an installed power of 65 MW-140 MW. Blue squares
are production block centres, and red circles are transmission grid stations.
Since island production blocks are rather small, the radial connection will give a relatively high
cost per installed GW. Lumping them together, which is done in the next step, will result in
better equipment utilization. The costs for the hub connection will significantly decrease.
scenario scenario
No activated
production
block for this
scenario
Figure 3-23: Radial connection for South Aegean Sea
(Source: Sweco)
Table 3-26: Costs and losses for radial connection, South Aegean Sea
Scenario CAPEX [M€] OPEX (M€/year) Losses (GWh/year)
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Greece 0 0 0 1,378 0 0 0 21 0 0 0 319
(Source: Sweco)

are listed in Table 3-27. For this particular case, the hub connection was split into two parts,
one connecting the sea-based production blocks and one connecting the islands. The separate
connections are 65 km-77 km, connecting production block groups with a total installed power
of 470 MW-3,070 MW. Blue squares are production block centres, and red circles are
transmission grid stations.
scenario scenario
No activated
production
block for this
scenario
Figure 3-24: Hub connection for South Aegean Sea
(Source: Sweco)
Table 3-27: Costs and losses for hub connection, South Aegean Sea
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
Ambitious 2030
Ambitious 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
NECP 2030
NECP 2050
Greece 0 0 0 654 0 0 0 10 0 0 0 325
(Source: Sweco)

For this TMA, no clear favourable optional grid connection was identified. However, there are
HVDC interconnection projects planned in this region. The Ariadne interconnector 106 and the
Southern Aegean interconnector107 should both connect Crete with mainland Greece, with
connection points in the Athens region (see Figure 3-25). Furthermore, as mentioned in Section
3.2.6.3, the Greek TSO foresees an extended submarine grid for the interconnection of major
islands in the Aegean Sea.108 Procedural and political issues apart, it is possible to envisage
technical solutions where the HVDC links or the submarine grid are realised in parallel with the
connection of the production blocks or being integrated as single multipole HVDC links. In any
106
http://www.ariadne-interconnection.gr/en/home-en/
107
https://tyndp.entsoe.eu/tyndp2018/projects/projects/293
108
https://www.admie.gr/sites/default/files/users/dssas/dpa-2021-2030-hartis.pdf
case, the projects would have an impact on each other, although the economic outcome of such
an impact is beyond the scope of this study to describe. Section 3.4 contains some additional
comments on this scenario.
Figure 3-25: Planned projects in the vicinity of South Aegean Sea from the
Ariadne Interconnection website (left) and the ENTSO-E 10-year network
development map (right)
(Source: Sweco)
3.2.10 TMA: The Baleares

For this TMA, no production blocks are activated in any of the scenarios.
3.3 Consequences for the transmission grids

In this section, the consequences for the transmission grids in the receiving countries are
outlined on a general level for the 2030 scenarios only. The content of this section is largely
based on interviews with people with insight into the transmission grid around the
Mediterranean Sea (a list of interviewees can be found in 0). The descriptions follow the
coastline of the Mediterranean Sea from west to east. Table 3-28 outlines the injections in each
of the scenarios for the different parts of the connecting countries. Only the power flow
corresponding to the radial and hub connections is displayed since the power flow in the
optional connections is not fully defined.
Table 3-28: Summary of power injections per country

Injected power per scenario (GW)
Scenario
NECP Ambitious NECP Ambitious
2030 2030 2050 2050
Portugal, south 0 0 0 1.5
Spain, total 0 2.0 6.0 14.6
Spain, southwest 0 0.2 0.2 3.8
Spain, northeast 0 1.8 5.8 10.8
France, south 1.4 3.3 3.3 7.2
Italy, total 1.0 5.4 19.1 43.5
Italy, northwest 0 0 5.6 8.6
Italy, Sicily 0.6 1.4 2.4 8.7
Italy, Sicily, from Malta 0 0 0 0.5
Italy, southeast 0 0 3.1 9.3
Italy, northeast 0.4 4.0 8.0 16.4
Croatia, west 0 0.4 1 1.9
Greece, total 0 2.1 3.3 7.8
Greece, south 0 0 0 3.5
Greece, southeast 0 2.1 3.3 4.3
(Source: Sweco)
In general, the transmission grid around the Mediterranean Sea is not very strong or well
meshed. Therefore, any major injection of power (in the order of GW) will likely need
reinforcements.
In the NECP 2030 scenario, injection of power is made at three locations: in the south of France
(Gulf of Lion), in the south of Italy (Sicily), and in the northeast of Italy (Gulf of Venice). An
injection of 1.4 GW from the Gulf of Lion is within the forecast for 2030 for that region of the
French transmission grid. Therefore, this injection might be handled without any major
additional reinforcements. Turning to Italy instead, the injection into Sicily is lower: 0.6 GW.
The grid is weak in this region with a known bottleneck between Sicily and mainland Italy. An
injection of power here would further increase the general power flow in Italy from the south to
the north. Thus, significant grid reinforcements would likely be necessary in Italy due to this
injection. The least demanding point of injection for the NECP 2030 scenario is in the north of
Italy. An injection here of 0.4 GW might alleviate the congestions stemming from the Italian
south-north power flow mentioned earlier. For this part, only minor grid reinforcements might
have to be made.
In the ambitious 2030 scenario, the injections mentioned in the previous paragraph are
increased. In addition, power is injected into the southwest of Spain (Gulf of Cádiz), the
northeast of Spain (Gulf of Lion), the northwest of Croatia (Gulf of Venice) and southeast of
Greece (North Aegean Sea). For the south of Spain, the injection is only 0.2 GW, meaning that
although the grid in general is not very strong in this region, it might suffice with only minor
reinforcements or no reinforcements at all. In the northeast of Spain, the injection is 1.8 GW,
meaning that major reinforcements are likely unavoidable. The injection into France in the Gulf
of Lion is increased from 1.4 GW in the NECP 2030 scenario to 3.3 GW. For such an injection,
major grid reinforcement will likely be necessary. The need for reinforcements increases for the
Italian grid since the injection into Sicily increases from 0.6 GW for the NECP 2030 scenario to
1.4 GW. For the Gulf of Venice, the injection into Italy is increased drastically, from 0.4 GW in
the NECP 2030 scenario to 4.0 GW. Thus, the necessary grid reinforcements also go from minor
to major. From the Gulf of Venice, injection of power into Croatia, with 0.4 GW in this scenario,
might be handled with only minor grid reinforcements. Finally, the ambitious 2030 scenario
includes an injection of 2.1 GW into the southeast of Greece from the North Aegean Sea—the
second largest injection in this scenario. However, this injection is made into the Athens region,
which is the main load centre in Greece with roughly 1/3-1/2 of the peak load. Thus, the
injected power might result in a less congested grid since it limits the need for power flow from
the northwest of Greece. Therefore, for Greece, minor grid reinforcements might suffice.
In summary, the NECP 2030 scenario necessitates major grid reinforcements in the Italian grid,
at least in the south. The ambitious 2030 scenario necessitates major grid reinforcements in the
north of Spain, the south of France, and in the south and north of Italy. For Greece and Croatia,
only minor grid reinforcements may be needed.
Although it is out of this report’s scope to assess the consequences of the 2050 scenarios region
by region, all involved countries except for Portugal should experience major needs for
reinforcements in the conservative scenario, whereas in the ambitious scenario, all countries will
be affected in a major way.
3.4 Connection of different TMAs and relations to other planned

projects
The option of connecting one or more of the TMAs to each other will be explored in this section.
There are two plausible options for interconnection:
 Direct connection. For this option to be feasible, there needs to be an obvious benefit
of the connection, relative to the option of connecting the transmission grids without
going through the TMAs.
 Connection in coordination with other planned infrastructure projects. The
ENTSO-E TYNDP project sheets will be used as input for this option.
Looking at the 10 TMAs and how they are spread out across the Mediterranean Sea (see Figure
3-26), the distances between any two TMAs are very large. Thus, the option of a direct
connection of two TMAs is not considered economically feasible for two reasons. First, the cost
of such a connection would be the same as or larger than the cost of connecting the national
grids to each other without going through a TMA; second, a cross-country link involving a
production site along its way has a capacity that is not as predictable as a dedicated
transmission link.
Figure 3-26: Overview of the 10 TMAs

(Source: Sweco)
Some possibilities exist for the option of integrating the TMAs with planned or envisaged future
infrastructure projects. In Figure 3-27 displays the ENTSO-E 10-Year Network Development Plan
(TYNDP), illustrating projects around the Mediterranean Sea in different stages of consideration.
Some of these projects have been described briefly in the earlier sections on optional grid
connections.
Figure 3-27: Planned transmission projects in or around the Mediterranean

Sea109
(Source: Sweco)
Studying Figure 3-26 and Figure 3-27, two of the TMAs are located close to projects that involve
interconnection of Italy and Tunisia, namely TMA Sicily and TMA Corsica-Sardinia. Thus, this is
one option for connecting TMAs to each other. The distances are very large, however, and such
an interconnection relies heavily on coordination of the four projects. In summary, coordinating
each of the TMAs with either of the HVDC interconnections seems more manageable than
considering a full interconnection.
The link connecting the Corsica-Sardinia TMA to shore (described in Section 3.2.8) has a 2050
maximum capacity of 6-9 GW depending on the scenario compared with the planned capacity of
the ENTSO-E TYNDP TuNur (Tunisia-Central Italy) link that is 2 GW. Integrating the two links
(assuming additional HVDC converters in the TMA) would decrease the total cost for the two
projects. Since the common cable path for the two projects is quite long (in the order of 100-
200 km), significant cost benefits could likely be achieved. However, integrating the two links
would add a factor of uncertainty in the cross-country transfer capacity since the capacity would
be dependent on the production from the TMA. In general, this situation is not desirable for
TSOs due to difficulties in planning. On the other hand, it could be argued that for a future case,
additional grid codes and market forces might provide a framework in which two entities share a
common link with certain limitations, low uncertainties, and a clear benefit to both parties.
A similar argument could be made for the integration of the TMA of Sicily (described in Section
3.2.3) with the ENTSO-E TYNDP Sicily-Tunisia interconnector. The planned capacity of the latter
is 0.6 GW, and the maximum capacity of the link connecting the TMA to shore is 0.6 GW-8.7
GW, depending on the scenario. The shared cable path would be in the order of 50 km or more,
again providing a possibility for cost benefits.
Finally, the possibilities of integration of the South Aegean Sea TMA (described in Section 3.2.9)
with the Ariadne interconnector could also be studied in the same way. The planned capacity of
the Ariadne interconnector is 1 GW, and the 2050 maximum capacity of the link connecting the
TMA to shore is 3.5 GW. The shared cable path would be in the order of 50 km or more,
providing a possibility for cost benefits here as well.
For Gulf of Lion, the optional grid connection (see Section 3.2.1.3) involved a link between
production blocks belonging to France and production blocks belonging to Spain, creating a
109
From the ENTSO-E 10-year network development map.
cross-country link. Such a link would increase the transfer capacity between the countries,
which might affect the planned grid reinforcements in the western part of the Pyrenees (marked
in red in Figure 3-27). The planned reinforcements would result in an estimated increase of
transfer capacity of 1.5+1.5 GW.110 The proposed offshore link in the TMA with a maximum
capacity of 2.8 GW, 4.5 GW, and 7.4 GW for the 2030 ambitious scenario, the 2050 NECP
scenario, and the 2050 ambitious scenario, respectively, could work as either a complement or
substitution for the planned reinforcements. Looking at a future situation with high amounts of
PV generation being transported from northern Africa through Europe, both the reinforcements
across the Pyrenees and an offshore link may be needed.
3.5 Cost-benefit analysis for the production scenarios and grid

options
On an overall level, the quantifiable differences between the different production scenarios and
grid options consist of:
 CAPEX and OPEX

 CAPEX and OPEX for offshore power generation
 CAPEX and OPEX for different grid configurations offshore including cost of hubs and
costs of RES curtailment
 CAPEX and OPEX for necessary grid reinforcements onshore
 Socioeconomic parameters such as:
 Socioeconomic welfare impact (producer surplus, consumer surplus, congestion
rent)
 Savings in CO2 emissions
 Other factors such as:
 Security of supply
 RES integration
Figure 3-28: Analysis of different production scenarios and grid options

(Source: Sweco)
In general, this study’s methodology is aligned with the latest draft of ENTSO-E’s cost and
benefit methodology from autumn 2019 as shown in Figure 3-28, focusing on the cost and
benefit elements without considering residual impacts.
110
ENTSO-E TYNDP 2018 Project sheets 270 and 276.
The analysis of CAPEX and OPEX for the different grid options, resistive losses, cost of RES
curtailment, and the evaluation of security of supply are explained in Section 3.1. The
socioeconomic parameters of producer surplus, consumer surplus, congestion rent, and CO2
emissions from power generation are the result of extensive power market modelling of the
different production scenarios and grid options.
The CAPEX and OPEX values for offshore power generation used in the scenarios are the results
from Task 1 and their deployment in the production scenarios. Then, the CAPEX and OPEX costs
were added for the different grid configurations offshore. Both CAPEX for power generation and
external grid connection are annualised with their respective life-length and WACC (see Table
1-23).
This study aimed at including rough CAPEX and OPEX cost estimates for necessary onshore grid
reinforcements due to the offshore generation for 2030, based on TSO expert interviews rather
than grid modelling. However, this study does not have quantification yet and therefore must
leave out these costs from the analysis. For 2050, estimates for onshore grid reinforcements will
not be possible since they would require a much more detailed understanding of the detailed
grid in 2050 in the reference scenario than can be made in this study.
Costs and benefits are summarised to show the effects on the system as a whole and for the
Mediterranean region as a whole rather than for each Member State, since positive effects in
one MS could cause negative impacts on one or more member states. The effects per Member
State are available, however.
3.5.1 Cost-benefit analysis for 2030 scenarios

The following production scenarios and grid options were analysed for 2030:
 2030_NECP_RC (the 2030 NECP scenario with radial connection from each production
block to shore)
 2030_NECP_HC (the 2030 NECP scenario with a hub connection to shore)
 2030_Ambitious_RC (the 2030 ambitious scenario with radial connection)
 2030_Ambitious_HC (the 2030 ambitious scenario with a hub connection to shore)
 2030_Ambitious-OC-TMA1 (the 2030 ambitious scenario with an interconnector between
France and Spain through TMA1)
Italy and Croatia through TMA5)
Socioeconomic effects and CO2 emissions are simulated with Sweco’s power market model
Apollo, described in Appendix B.1. All market modelling analysis is based on a single model
year, either 2030 or 2050, simulated with a single weather year, 2014. While this study does
compare scenarios for the same model year (e.g., the 2030 NECP and 2030 ambitious
scenario), comparisons are best made for smaller changes in generation, as the same
transmission capacities are assumed in both scenarios. Furthermore, for the evaluation of the
interconnector options, this study only compares the respective scenario without the
interconnector to the scenario with the interconnector.
3.5.1.1 CAPEX and RES integration

Figure 3-29 shows a comparison of the different levels of RES integration in the 2030 production
scenarios and their grid options compared to the CAPEX levels required for these investments.
The CAPEX levels are total levels expressed in 2019 real terms, not annualized values.
Therefore, these levels should be interpreted as investments that must made in offshore power
generation and grid connection up to 2030 to reach the RES integration of about 2.4 GW
offshore wind capacity in the Mediterranean in the NECP scenario (see Table 2-3) and 13.3 GW
of offshore capacity in the ambitious scenario as summarized in Table 2-4.
CAPEX and RES integration

35,000 14,000
RES integration, installed capacity [MW]

30,000 12,000
25,000 10,000
CAPEX external grid connection
CAPEX [MEUR]
[MEUR/year]
20,000 8,000 CAPEX floating wind [MEUR]
15,000 6,000 CAPEX bottom-fixed wind [MEUR]
RES-integration [MW]
10,000 4,000
5,000 2,000
0 0
Figure 3-29: CAPEX and RES integration for the various 2030 production
scenarios and grid options
(Source: Sweco)
The analysis shows that the hub connection provides a lower CAPEX than the radial connection,
regardless of production scenario. The total CAPEX of integrating about 2.4 GW of offshore
generation, including grid connection by 2030 in the NECP scenario, is around 6 billion €. The
total CAPEX of integrating 13 GW in the ambitious scenario is about 28-31 billion €, depending
on grid connection and whether an interconnector is integrated or not. Despite utilizing some of
the best sites for bottom-fixed offshore, this study is also using a significant amount of floating
offshore sites in 2030. Floating offshore wind stands for about two-thirds of the investments in
offshore power generation in our ambitious 2030 scenario.
3.5.1.2 Socioeconomic welfare results

Based on the power market modelling results with a single weather year (2014) with a
representative wind pattern, the ambitious scenario shows a significantly higher consumer
surplus and lower producer surplus due to generally lower prices. This situation occurs due to
new RES-E volumes being brought into the market and more congestion for the existing grid
resulting in higher congestion rent.
The two interconnector options connecting two countries show a diverse picture. The
interconnector from Spain to France yields higher socioeconomic welfare results mainly based
on a higher producer surplus in Spain and Portugal and increased congestion rent for France,
resulting in a positive result for the Mediterranean region. However, the decrease in congestion
in Croatia for the TMA5 interconnector is not offset by a higher consumer surplus.
Change in socio-economic welfare

Change in socio-economic welfare [MEUR/year] 10,000
8,000
Change in Congestion Rent other countries
6,000 [MEUR]
Change in Congestion Rent Mediterranean

4,000 [MEUR]
2,000 Change in Consumer Surplus other countries

[MEUR]
0 Change in Consumer Surplus Mediterranean
[MEUR]
-2,000
Change in Producer Surplus other countries
[MEUR]
-4,000
Change in Producer Surplus Mediterranean
-6,000 [MEUR]
2030_Ambitious-OC-TMA5
2030_Ambitious_RC
2030_Ambitious_HC
2030_NECP_HC
Total
Figure 3-30: Change in socioeconomic welfare for 2030 production scenarios

and grid options compared to the 2030 NECP scenario with radial connection
(Source: Sweco)
The interconnector option for TMA1 leads to increased export from Spain to France and from
Portugal to Spain, raising power prices in Portugal by 0.3 €/MWh and in Spain by 0.5 €/MWh
while slightly decreasing the power price in France as a bigger and more connected system with
0.1 €/MWh. In turn, this situation leads to a higher producer surplus in Spain and Portugal but a
lower producer surplus in France while consumer surplus increases in France and decreases in
Spain and Portugal as a consequence of higher prices. Congestion rent for the existing
interconnectors from Spain is dropping slightly, as these are used less, but congestion rent is
increasing for France (see Figure 3-30). From an overall Mediterranean perspective, the
socioeconomic results are also positive with 126 M€/year.
250
200
150
Welfare-economic Chnage [MEUR]
100
50
0
Portugal Spain France Italy Croatia
-50
-100
-150
-200
Producer surplus effect of MedOffshore_Ambitious_2030_OptionalGrid_TMA1

Consumer surplus effect of MedOffshore_Ambitious_2030_OptionalGrid_TMA1
Change in congestion rent with MedOffshore_Ambitious_2030_OptionalGrid_TMA1
Total welfare-economic effect of MedOffshore_Ambitious_2030_OptionalGrid_TMA1
Figure 3-31: Socioeconomic results for the 2030 ambitious TMA1

interconnector option compared with a non-interconnector base case (2030
ambitious)
(Source: Sweco)
The interconnector option for TMA5 leads to lower power prices in Croatia (-1 €/MWh) while the
power price in Italy remains largely unchanged. This situation leads to a lower producer surplus
in Croatia and a somewhat lower producer surplus in Italy while consumer surplus increases in
Croatia and Italy. Congestion rent for the existing interconnectors from and to Croatia are
dropping significantly. From an overall Mediterranean perspective, the socioeconomic results are
also slightly negative at -8 M€/year. However, results of this magnitude might very well change
if simulated with different weather years.
30
25
20
15
10
5
0
-5 Spain France Italy Croatia Greece
-10
-15
-20
-25
Producer surplus effect of MedOffshore_Ambitious_2030_OptionalGrid_TMA5

Consumer surplus effect of MedOffshore_Ambitious_2030_OptionalGrid_TMA5
Change in congestion rent with MedOffshore_Ambitious_2030_OptionalGrid_TMA5
Total welfare-economic effect of MedOffshore_Ambitious_2030_OptionalGrid_TMA5
Figure 3-32: Socioeconomic results for the 2030 ambitious TMA5

interconnector option compared with a non-interconnector base case (2030
ambitious)
(Source: Sweco)
3.5.1.3 Savings in CO2 emissions

Figure 3-33 shows the CO2 emission savings of the production scenarios and their grid options
compared with the NECP 2030 scenario with a radial connection. The ambitious scenario
produces savings of around 15 Mt of CO2 annually by replacing fossil-fuelled generation. While
the radial or hub grid configuration does not affect the market outcome, the integration of
markets using an additional interconnector in TMA1 and TMA5 does. Both interconnections could
contribute to annual CO2 emissions savings of about 0.2 Mt.
CO2 emission savings
2030_Ambitious_RC
2030_Ambitious_HC
2030_NECP_HC
0 0.0
-2 CO2 emission savings, other countries

-6.8 -6.8 -7.3 -7.0
-4
CO2 emission svaings [Mt]
CO2 emission savings, Mediterranean

countries
-6
-8
-10
-8.6 -8.6 -8.3 -8.6
-12
-14
-16
-18
Figure 3-33: CO2 emissions savings of the production scenarios and their grid
options compared with the NECP 2030 scenario with a radial connection
(Source: Sweco)
The CO2 savings for the Mediterranean countries alone are slightly higher for the TMA1
connection than for the TMA5 connection.
3.5.1.4 Summary
Table 3-29 summarizes the costs and benefits for including the additional benefit of avoided CO 2
emissions in relation to the 2030 NECP scenario with a radial connection. A positive figure in the
table means lower cost (e.g., a lower grid connection cost) and higher benefits while a negative
figure means higher cost or less benefits than the 2030 NECP scenario with a radial connection.
The societal cost of CO2 emissions is much higher than reflected in the current CO2 price.
However, to have a bottom line, the cost is varied between the current CO2 price (see Table
3-29 Figure 3-34) and 150 €/t111 (see Figure 3-35).
111
Value set to 150 EUR/t for comparison. The choice of value does not aim to quantify the abatement cost
but rather aims to illustrate the scenario if the abatement cost were at that level and included in the
analysis.
Table 3-29: Summary of costs and benefits112 for production scenarios and
grid options in 2030 in relation to the 2030 NECP scenario with radial
connection, societal cost for CO2=EU-ETS price
2030_NE 2030_ 2030_ 2030_ 2030_
CP_HC Ambitious_ Ambitious Ambitious- Ambitious-
RC OC-TMA1 OC-TMA5
Annual cost offshore 0 -2,238 -2,238 -2,238 -2,238

power generation
(M€/year)
Annual cost external grid 34 -239 -96 -181 -175

connection (M€/year)
Welfare economics 0 2,112 2,112 2,238 2,104

Mediterranean countries
(M€/year)
Welfare economics other 0 584 584 626 566

countries (M€/year)
Total monetized 34 218 362 445 257

effects
CO2 emissions avoided, 0 -15.4 Mt -15.4 Mt -15.6 Mt -15.6 Mt

Europe (Mt)
RES integration (MW) 0 10,871 10,871 10,871 10,871
(Source: Sweco)
CBA 2030 scenarios

8,000 500
Change in annual cost (-) and benefit (+) compared to
400
6,000
Change in total [MEUR]
2030_NECP_RC [MEUR/year]
300
4,000
Societal benefit of CO2 avoided other
200 countries [MEUR/year]
2,000 Societal benefit of CO2 avoided Mediterranean
countries [MEUR/year]
100
Welfare economics other countries
0 [MEUR/year]
0 Welfare economics Mediterranean countries
[MEUR/year]
-2,000 Annual cost external grid connection
-100 [MEUR/year]
Annual cost offshore power generation
-4,000 -200 [MEUR/year]
Total
Figure 3-34: Costs and benefits of the different 2030 production scenarios and
grid options with societal cost of CO 2 equal to EU-ETS price (28 €/t)
(Source: Sweco)
112
There are parameters that could significantly affect the cost-benefit analysis results, other than the cost
of onshore grid reinforcement and CO2 price, including: weather years examined, scenarios examined,
WACC for different components (where decisive policies can have a beneficial impact), the impact of
grid failures (this may have a significant impact on offshore connections; see for example the historical
low availability of the existing Italy-Greece interconnector). This study analysed one single normal
weather year, normal grid availability, and one WACC level.
With the analysed parameters for 2030, all ambitious scenarios with 13 GW RES integration
yield higher benefits than the NECP scenarios with 2 GW of installed offshore capacity by
lowering power prices and increasing consumer surplus, with and without a higher price than
EU-ETS as societal cost for CO2. However, this analysis disregards the cost for onshore grid
reinforcement, which could not be monetized.
In addition, of the analysed grid options, the hub connections always show better results than
the radial connections in 2030. Of the interconnector options, the results indicate that an
interconnector between Spain and France via the TMA 1 (Gulf of Lion) could be promising. This
TMA should be further analysed for onshore grid connection costs and indicators of security of
supply, as it provides benefits such as positive socioeconomic results and contributes to an
emissions reduction of 0.2 Mt of CO2 per year.
CBA 2030 scenarios

8,000 3000
Change in annual cost (-) and benefit (+) compared to
2500
6,000
2000
Change in total [MEUR]

2030_NECP_RC [MEUR/year]
4,000 1500
Societal benefit of CO2 avoided other
2,000 Societal benefit of CO2 avoided Mediterranean
Welfare economics other countries
0 0 [MEUR/year]
Welfare economics Mediterranean countries
-500 [MEUR/year]
-2,000 Annual cost external grid connection
-1000 [MEUR/year]
Annual cost offshore power generation
-4,000 -1500 [MEUR/year]
Total
Figure 3-35: Costs and benefits of the different 2030 production scenarios and
grid options with an assumed societal cost of CO2 of 150 €/t
(Source: Sweco)
3.5.2 Cost-benefit analysis for 2050 scenarios

This study analysed the following production scenarios and grid options:
 2050_NECP_RC (the 2050 NECP scenario with radial connection from each production
block to shore)
 2050_NECP_HC (the 2050 NECP scenario with a hub connection to shore)
 2050_NECP-OC-TMA1 (the 2050 NECP scenario with an interconnector between France
and Spain and TMA1)
 2050_NECP-OC-TMA5 (the 2050 NECP scenario with an interconnector between Italy
and Croatia and TMA5)
 2050_Ambitious_RC (the 2030 ambitious scenario with radial connection)
 2050_Ambitious_HC (the 2030 ambitious scenario with a hub connection to shore)
France and Spain and TMA1)
Italy and Croatia and TMA5)
3.5.2.1 CAPEX and OPEX and RES-integration

Figure 3-36 compares the different levels of RES integration in the year 2050 production scenarios
and their grid options compared with the CAPEX levels required for these investments. The CAPEX
levels are total levels expressed in 2019 real terms, not annualized values; therefore, these should
be interpreted as investments that have to be made in offshore power generation and grid
connection up to 2050 to reach the RES integration of about 82 GW of offshore capacity in the
Mediterranean, of which 76 GW are located in the Mediterranean TMAs defined in this study and
the remaining capacity- outside of it. As in the 2030 scenarios, the hub connection always provides
a lower CAPEX than the radial connection.
CAPEX and RES integration

140,000 90,000

80,000
120,000
70,000
100,000 CAPEX external grid connection
60,000
CAPEX [MEUR]
[MEUR/year]
CAPEX floating wind [MEUR]
80,000 50,000
CAPEX bottom-fixed wind [MEUR]
60,000 40,000
30,000
40,000
20,000
20,000
10,000
0 0
Figure 3-36: CAPEX and RES integration for the various 2050 production
scenarios and grid options
(Source: Sweco)
3.5.2.2 Socioeconomic welfare results

Similar to 2030, the 2050 ambitious scenario shows a significantly higher consumer surplus and
lower producer surplus due to generally lower prices. In this scenario, new RES-E volumes are
being brought into the market along with more congestion for the existing grid resulting in
higher congestion rent.
The two interconnector options connecting two countries show a diverse picture. The
interconnector from Spain to France yields higher socioeconomic welfare results mainly based
on a higher producer surplus in Spain and Portugal and increased congestion rent for France,
resulting in a positive result for the Mediterranean region. However, the decrease in producer
surplus is just offset by an increase in congestion rent for Croatia for the TMA5 interconnector.

Change in socio-economic welfare [MEUR/year] 40,000
30,000
20,000
10,000 Change in Congestion Rent other countries

[MEUR]
0 Change in Congestion Rent Mediterranean
[MEUR]
-10,000 Change in Consumer Surplus other
countries [MEUR]
-20,000
Change in Consumer Surplus
Mediterranean [MEUR]
-30,000
Change in Producer Surplus other countries
-40,000 [MEUR]
2050_Ambitious_RC
2050_Ambitious_HC
2050_NECP_HC
2050_NECP-OC-TMA1
2050_NECP-OC-TMA5
Change in Producer Surplus Mediterranean

[MEUR]
Total
Figure 3-37: Change in socioeconomic welfare for 2050 production scenarios

and grid options compared with the 2050 NECP scenario with radial
connection, CO2 price 250 €/t
(Source: Sweco)
600
400
200 Producer surplus effect of

MedOffshore_NECP_2050_OptionalGrid_TMA1
0 Consumer surplus effect of

Change in congestion rent with
-200
Total welfare-economic effect of
-400
-600
-800
Figure 3-38: Socioeconomic effects of an interconnector for TMA1 between

Spain and France, compared with base case (no interconnector), 2050 NECP
scenario
(Source: Sweco)
1,500
1,000
Producer surplus effect of

500 MedOffshore_Ambitious_2050_OptionalGrid_TMA1
Consumer surplus effect of
MedOffshore_Ambitious_2050_OptionalGrid_TMA1
0
Portugal Spain France Italy Croatia Change in congestion rent with
-500 Total welfare-economic effect of
-1,000
-1,500

Spain and France, compared with base case (no interconnector), 2050
ambitious scenario
(Source: Sweco)
300
250
200
150
50
0 MedOffshore_NECP_2050_OptionalGrid_TMA5
-100
-150
-200

Croatia and Italy, compared with base case (no interconnector), 2050 NECP
scenario
(Source: Sweco)
600
500
400
300
100
0 MedOffshore_Ambitious_2050_OptionalGrid_TMA5
-200
-300
-400

Croatia and Italy, compared with base case (no interconnector), 2050
ambitious scenario
(Source: Sweco)
3.5.2.3 Savings in CO2 emissions

Figure 3-42 shows the CO2 emissions savings of the production scenarios and their grid options
compared with the NECP 2050 scenario with a radial connection. The ambitious scenario
produces savings around 6 Mt-7 Mt of CO2 annually by replacing fossil-fuelled generation in
Europe. Also, about two-thirds of these savings can be made in other countries outside of the
Mediterranean. While the radial or hub grid configuration does not affect the market outcome,
the integration of markets using an additional interconnector in TMA1 and TMA5 does. Both
interconnections could contribute to annual CO2 emissions savings of about 0.3 Mt-0.5 Mt.

1
-0.1
0 -0.5
-1 -2.2 -2.2 -2.3
-2.7
-2
-3
-4
-4.3 -4.3 -4.6
-5 -4.2
-6 CO2 emission savings, other countries
-7
-8 CO2 emission savings, Mediterranean
2050_Ambitious_HC
2050_Ambitious_RC
2050_NECP_HC
2050_NECP-OC-TMA1
2050_NECP-OC-TMA5
countries
Figure 3-42: CO2 emissions savings of the production scenarios and their grid
options compared with the NECP 2050 scenario with a radial connection
(Source: Sweco)

For all production scenarios, the hub connection requires lower CAPEX than the radial
connection alternatives. The reason for this fact is that the hub connection utilizes a common
interconnection for several production blocks, thereby limiting the construction and material
costs. On the downside, this also means a limited decrease in security of supply, as the outage
of a cable could mean the loss of more than one production block. Another difference between
the radial connection and the hub connection is that the former can be realised without
coordination of the different production blocks, whereas the latter assumes that the whole group
of production blocks is realised as a common project. A common project is more difficult to
achieve with a step-by-step approach and generally requires a bigger commitment in terms of
investments and policies. Thus, a full comparison between the options needs to take into
consideration not only the summary costs but also the strategic choices involved.
As for the alternative of connecting several TMAs to each other, this study concludes that the
distances between TMAs are too large for this to be feasible in relation to the distances between
TMAs and the transmission grid. However, in a few cases, possible coordination benefits exist
for ongoing or planned projects in the region and the realisation of TMAs. More specifically, this
concerns the following TMAs: Sicily, Corsica-Sardinia, and the North and South Aegean Sea. For
Sicily, potential exists for the integration with the ENTSO-E TYNDP Sicily-Tunisia interconnector,
which shares an approximate cable path with the link from the TMA spanning some 50 km or
more. For Corsica-Sardinia, potential exists for the integration with the ENTSO-E TYNDP TuNur
(Tunisia-Central Italy) link, which shares an approximate cable path with the link from the TMA,
spanning some 100 km or more. For the North Aegean Sea, potential exists for coordination
with a foreseen submarine grid connecting major islands, laid out in the national TYNDP. For the
South Aegean Sea, potential exists for the integration with the Ariadne interconnector, which
shares an approximate cable path with the link from the TMA spanning some 50 km or more.
There is also potential for integration with a foreseen submarine grid connecting major islands,
laid out in the national 10-Year Network Development Plan and the ENTSO-E TYNDP Southern
Aegean interconnector.
All scenarios require considerable investments in offshore power generation and the connection
to the onshore grid, often including considerable reinforcement of the onshore grid. At the same
time, especially in 2030, limited RES support will be needed for the offshore wind generation
investments to be realised. The total CAPEX of integrating about 2.4 GW of offshore generation
including grid connection by 2030 in the NECP scenario is around 6 billion €. The total CAPEX of
integrating 13 GW in the ambitious scenario is about 28-31 billion €, depending on grid
connection and whether an interconnector is integrated or not. Despite utilizing some of the
best sites for bottom-fixed offshore, this study is also using a significant amount of floating
offshore sites in 2030. Floating offshore wind stands for about two-thirds of the investments in
offshore power generation in the ambitious 2030 scenario. To reach the RES integration of
about 82 GW of offshore capacity in the Mediterranean in the ambitious 2050 scenario (of which
76 GW is in the Mediterranean TMAs defined in this study), about 120-130 billion € of
accumulated investments are necessary until 2050.
The cross-country interconnection from Italy to Croatia in the Gulf on Venice was found to not
be economically beneficial, whereas the Gulf of Lion interconnector from France to Spain was
found to be economically beneficial. However, the French permanent representative has
expressed strong doubts as to the plausibility of the interconnector due to seabed conditions
and public acceptance, among other things.
2030 2050
CAPEX and RES integration CAPEX and RES integration 2030 CAPEX and RES integration 2050
140,000 90,000 140,000 90,000

80,000 80,000
120,000 120,000
70,000 70,000
CAPEX [MEUR]
100,000
CAPEX [MEUR]
100,000
60,000 60,000
80,000 50,000 80,000 50,000
60,000 40,000 40,000
60,000
30,000 30,000
40,000 40,000
20,000 20,000
20,000 10,000 20,000
10,000
0 0
0 0
CAPEX external grid connection [MEUR/year] CAPEX external grid connection [MEUR/year]
CAPEX floating wind [MEUR] CAPEX floating wind [MEUR]
CAPEX bottom-fixed wind [MEUR] CAPEX bottom-fixed wind [MEUR]
RES-integration [MW] RES-integration [MW]
Change in socio-economic welfare Change in socio-economic welfare 2050

40,000
2030 40,000
Change in socio-economic welfare [MEUR/year]
Change in socio-economic welfare [MEUR/year]

30,000 30,000
20,000 20,000
10,000 10,000
0 0
-10,000 -10,000
-20,000 -20,000
-30,000
-30,000
-40,000
-40,000
2030_NECP_HC
2030_Ambitious_HC
2030_Ambitious_RC
2050_NECP_HC
2050_NECP-OC-TMA1
2050_NECP-OC-TMA5
2050_Ambitious_RC
2050_Ambitious_HC
Change in Congestion Rent other countries [MEUR] Change in Congestion Rent other countries [MEUR]
Change in Congestion Rent Mediterranean [MEUR] Change in Congestion Rent Mediterranean [MEUR]
Change in Consumer Surplus other countries [MEUR] Change in Consumer Surplus other countries [MEUR]
Change in Consumer Surplus Mediterranean [MEUR] Change in Consumer Surplus Mediterranean [MEUR]
Change in Producer Surplus other countries [MEUR] Change in Producer Surplus other countries [MEUR]
Change in Producer Surplus Mediterranean [MEUR] Change in Producer Surplus Mediterranean [MEUR]
Total Total
CO2 emission savings 2030 CO2 emission savings 2050

1 1 -0.1
0.0 -0.5
-1 -1 -2.2 -2.2 -2.3
-2.7
-3 -6.8 -6.8 -3
-7.3 -7.0
-4.3 -4.3 -4.2 -4.6
-5 -5
-7 -7
-9 -9
-11 -8.6 -8.6 -11

-8.3 -8.6
-13
-13
-15
-15
-17
-17
2050_NECP_HC
2050_NECP-OC-TMA5
2050_NECP-OC-TMA1
2050_Ambitious_HC
2050_Ambitious_RC
2030_NECP_HC
2030_Ambitious_RC
2030_Ambitious_HC
CO2 emission savings, other countries

CO2 emission savings, other countries
CO2 emission savings, Mediterranean countries
CO2 emission savings, Mediterranean countries
Figure 3-43: Summary of CAPEX, RES integration, change in socioeconomic

welfare and CO2 savings in the various 2030 and 2050 scenarios
(Source: Sweco)
With the analysed parameters for 2030, all ambitious scenarios with 13 GW RES integration
yield higher socioeconomic benefits than the NECP scenarios with 2 GW of installed offshore
capacity by lowering power prices and increasing consumer surplus, with and without a higher
price than EU-ETS as societal cost for CO2. However, this analysis disregards the cost for
onshore grid reinforcement or additional support scheme costs, which could not be monetized.
Of the interconnector options, the 2030 and 2050 results indicate that an interconnector
between Spain and France via TMA 1 (Gulf of Lion) could be promising. This option should be
further analysed for onshore grid connection costs and indicators of security of supply, as it
provides positive socioeconomic results and contributes to an emission reduction of 0.2 Mt of
CO2 per year.
4.0 BARRIERS AND IMPLEMENTATION CHALLENGES

This section presents identified barriers and implementation challenges for offshore renewables
and an offshore grid in the Mediterranean. Developing a regional offshore electricity grid and
offshore renewable energy in the Mediterranean faces barriers on different levels. Identification
of these barriers is key for designing targeted solutions and mitigation measures. In Section
5.0, recommendations for solutions and mitigation measures are presented for the categories of
barriers most crucial to facilitating the next steps for development in the Mediterranean.
4.1 Identification of barriers and implementation challenges

This report reviewed the most up to date studies to identify a long list of the most impactful
barriers and implementation challenges for offshore grid and offshore renewable energy
developments.113 Prior studies identified challenges and barriers for the development of an
offshore grid in the North Sea and Baltic Sea among other areas. A share of identified
challenges thus pertains to offshore grid development in European sea basins in general.
Appendix D further details and provides regional context for each identified barrier and
implementation challenge. The identified barriers and implementation challenges are grouped
per category (see Table 4-1):
 Offshore grid and renewable generation technologies: Offshore grid development

needs specific mature technologies, such HVDC protection equipment for meshing and
long-distance connections. In the Mediterranean, certain renewable generation
technologies such as floating wind, wave, and tidal are required given the specific
regional conditions. Within the region, multiple technologies are already being
developed and tested as best practices for scaling up further.
 Offshore grid design and planning: Design and planning criteria are key to
kick-starting the development of an offshore grid in the Mediterranean region. Design
and planning range from availability of adequate marine spatial planning data, defining
common grid planning criteria and modelling tools, to regional cooperation and
communication on various levels.
 Offshore and onshore grid: Grid connections for offshore renewable energy
generators should be defined in terms of grid delivery model, connection regimes,
procedures, and priorities. An offshore grid delivery model defines the responsibilities
between stakeholders (developer, TSO, etc.) for the development of offshore grid
transmission assets for renewable generation units (see Appendix D). Currently most
countries in the Mediterranean have no defined model for the connection of offshore
renewables to the onshore grid, which hampers scaling up. For example, France is one
of the Mediterranean countries with a defined grid delivery model in place for offshore
wind, placing the responsibility of offshore grid development on the French TSO Réseau
de Transport d'Électricité rather than the developer.
 Market design specific to the offshore area: A meshed or regional offshore grid
might consist of hybrid projects and other large-scale offshore infrastructure. An
appropriate market design might be required for the offshore area to reflect the new
bottlenecks and behaviour of the interconnected system.
 Offshore RES generation: Operational requirements of offshore renewable energy
plants should be coordinated between countries. In addition, alignment of support
scheme design and support allocation mechanisms is important for ensuring optimal
offshore energy development in the region and facilitating offshore hybrid projects.
 Offshore grid operation: Grid operation in terms of dispatch regulation, cross-border
capacity allocation and congestion management (CACM), and operation should be
coordinated on a regional level to ensure secure operation of an offshore grid.
 Administrative/governance process: The development of an offshore grid and
offshore RES generation units requires administrative, governance, regulatory, and legal
113
(PROMOTioN, 2019c); (PROMOTioN, 2017a); (3E and Project Partners, 2015); (PwC, 2016); (Interreg,
2017); (Integrid, 2019); (MAESTRALE, 2016); (Intelligent Energy Europe, 2016); (3E and Project
Partners, 2015); (Soukissian et al., 2017); (Javier Serrano-González and Roberto Lacal-Arántegui,
European Commission, Joint Research Centre, Institute for Energy and Transport, March 2015); (Roland
Berger, 2019)
frameworks to be in place to ensure roles, processes, and responsibilities are clearly

defined for stakeholders.
 Cost allocation and financing: Offshore grid and offshore renewable development at
a regional level is highly capital intensive and will require views on cost developments of
technologies, financing options, and availability of capital. An important barrier is the
lack of a framework for cost-benefit sharing for joint projects at a regional level.
 Social and environmental constraints: Offshore grid and renewable developments
will need to overcome social and environmental barriers related to public acceptance in
touristic areas, the development of skilled personnel, and understanding the cumulative
environmental impact of large-scale offshore grid infrastructure.
4.2 Ranking and scoping of barriers and implementation

challenges
The identified barriers and implementation challenges are geographically scoped and ranked
based on their applicability and impact to the Mediterranean situation, respectively. The
geographical scope of each barrier can include:
 EU-wide barriers and implementation challenges that also play a role in the
development of offshore grids and offshore renewable energy across other European sea
basins, such as the Northern Seas and the Baltic Sea, and will most likely be solved
within those basins first.
 Region-specific barriers and implementation challenges applying to one or more
member states or localities in the Mediterranean, requiring specific attention to facilitate
regional offshore developments.
A rank is subsequently assigned to each barrier according to its level of impact for offshore
developments in the Mediterranean region: low, moderate, or strong. Offshore grid and
renewable developments in the Mediterranean region currently lag behind other European sea
basins, such as the Northern and Irish Seas and the Baltic Sea. Some of the barriers should be
solved during developments in those sea basins and should not have a strong impact when
developments move to a further stage in the Mediterranean. Further details on each barrier and
implementation challenge and their geographical scope and impact are provided in Appendix D.
Table 4-1 summarizes the results of the analysis. The list of barriers and implementation
challenges, their scope and impact have been reviewed by the Advisory Board and a selected
list of interviewees from key stakeholder associations in the offshore area 114 (see 0).
Table 4-1. Identified barriers and implementation challenges per category with
geographical scope and ranking115
Barrier Geographical scope Rank
Offshore grid and renewable generation technologies Strong
1 Availability of mature offshore renewable energy and Region-specific / EU-wide Strong
grid technologies suitable for the development of an
offshore grid in the Mediterranean
2 Coordinated offshore grid technologies and EU-wide Strong
interoperability of assets
3 Availability of supply chain for components, labour EU-wide / Region-specific Strong
force, and infrastructure to develop offshore renewables
and grid infrastructure
Offshore grid design and planning Moderate
1 Data availability for planning Region-specific Moderate
2 Regional communication and cooperation on various Region-specific Moderate
levels
3 Competing offshore activities limit exploitation of full Region-specific Strong
offshore renewables potential
4 Natural constraints Region-specific Moderate
5 Regional offshore grid development strategy Region-specific Moderate
114
Wind Europe; ENTSO-E; Med TSO; Ocean Energy; Med Reg.
115
See 1.1.1.1Appendix D for further details.

6 Offshore grid planning criteria EU-wide Moderate
7 Joint standard models and datasets for long-term grid EU-wide Moderate
planning
Offshore and onshore grid Moderate
1 (Aligned) grid transmission asset responsibility for Region-specific Strong
offshore energy generators (offshore grid delivery
model)
2 Aligned rules (regimes and procedures) for onshore grid Region-specific Moderate
infrastructure (connection, expansion, and
reinforcement)
Market design specific to the offshore area Moderate
1 Bidding zone arrangement for the offshore area Region-specific (/EU- Strong
wide)
Offshore RES generation Strong
1 Aligned balancing responsibility of offshore renewable EU-wide Strong
generators
2 Aligned requirements and standards for RES grid EU-wide / Region-specific Moderate
services
3 (Aligned) renewable energy support schemes and Region-specific Strong
support allocation mechanism
Offshore grid operation Moderate
1 Aligned priority dispatch regulation for offshore Region-specific Moderate
renewable energy
2 Alignment of cross-border CACM in offshore grid EU-wide Moderate
operation
3 Regional offshore grid maintenance strategy Region-specific Moderate
Administrative/governance process Strong
1 Development of national and joint regional marine Region-specific Moderate
spatial plan and integrated coastal zone management
2 Alignment of licensing, permitting, and consenting Region-specific Moderate
procedures for development of offshore renewable
energy
3 Legislative issues on a national level to clarify mandates Region-specific Strong
for offshore grid development by the national TSO
4 Regulatory framework for islands on a national and Region-specific Strong
regional level regarding renewables and fossil fuel
support
5 Jurisdictional definition regarding grid development Region-specific Strong
within EEZ
Cost allocation Moderate
1 Aligned grid charges/grid connection costs for Region-specific Moderate
renewable generation units
2 Cross-border cost allocation method (CBCA) for offshore EU-wide Strong
grid infrastructure (cost-benefit sharing)
3 Cost information of new technologies EU-wide Moderate
Financing Moderate
1 Availability and cost of capital for offshore grid and Region-specific Moderate
renewable energy generation assets
2 Common (and sharing of) financing mechanisms/ EU-wide Strong
financing rules for joint offshore renewable projects
3 Tailored and sufficient investment incentives for Region-specific Moderate
offshore grid and renewables
Social constraints Strong
1 Public acceptance of offshore renewable energy Region-specific Strong
developments
2 Availability of skilled personnel and targeted training Region-specific Moderate
and education programs
Environmental constraints Moderate

1 Environmental protection areas limiting exploitation of Region-specific Moderate
full RES potential
2 RES development restrictions due to impact on animal Region-specific Moderate
migration routes
3 Understanding cumulative environmental impact of Region-specific Strong
large-scale offshore grid infrastructure

Task 4 identified a list of barriers and implementation challenges for offshore grid and offshore
renewable development in the Mediterranean along several categories. Each barrier was
presented with its geographical scope and level of impact on regional developments (further
detail in Appendix D). The categories of barriers with the highest priority at a regional level are
identified as:
 Offshore grid and renewable generation technologies: grid connection and technology
maturity
 Administrative/governance processes
 Social and environmental constraints
The results feed into Section 5.0, where recommendations for solutions and mitigation
measures are presented for the categories of barriers most crucial to facilitating next steps for
development in the Mediterranean.
5.0CONCLUSIONS AND RECOMMENDATIONS

This section presents initial recommendations for further work on policy and regulatory
developments and provides initial proposals for pilot projects.
5.1 Key findings

One key finding of this study is that the economically sound renewable energy potential seems
higher than the potential represented by NCEPs for 2030, and this potential can further increase
by 2050. In all four scenarios, the resulting national RES shares (the green dots in Figure 2-7)
reach at least the national target for 2030 (grey bar). In most countries, the ambitious
scenarios add a few percentage points—between 2% and 9%—in RES share for 2030.
Figure 5-1: RES share for the Mediterranean countries in the two offshore
generation scenarios in 2030
(Source: Sweco)
This potential includes mainly floating wind technology, as this technology fits best the
geographic specificities of the Mediterranean region and its cost is expected to decrease in the
future. The analysis shows that additional offshore wind capacity, and floating wind in particular,
can be added to the Mediterranean energy systems in a cost-effective manner: 13 GW by 2030
and 80 GW by 2050 in the ambitious scenario. This addition would increase the share of RES
generation from 2% to 6% in the NCEP scenario in 2030 and from 12% to 21% in the ambitious
scenario in 2050. Other contributing technologies are mainly bottom-fixed wind and onshore
technologies such as solar PV and onshore wind. Although this study forecasts growth of wave
and tidal energy, it is not expected to develop in the Mediterranean region with the assumptions
adopted for the analysis for the following reasons: limited economic potential in the
Mediterranean region, relatively low maturity, small capacity of technologies under
development, and high costs. However, ocean energies may develop under specific conditions,
such as further support of R&D efforts.
For the Mediterranean region under study, this study identified selected areas (TMAs) that are
most promising for offshore energy development. The 10 areas with the greatest cost-effective
potential for various technologies or combinations thereof are the Gulf of Lion, Malta, Sicily, Gulf
of Venice, Gulf of Cadiz, North Aegean Sea, Ionian Sea, Corsica-Sardinia, South Aegean Sea,
and the Baleares. The analysis and scenarios focused on these identified TMAs. Based on the
economic offshore energy production potential in each of the areas, this study developed two
realistic scenarios (the NECP scenario and the ambitious scenario) in two-time perspectives:
2030 and 2050.
In the process, interesting developments were observed in specific locations (e.g., Greece and
Malta), and further analysis on the sub regional level may show interesting offshore
opportunities in countries not represented in this analysis. Increasing the share of renewable
energy should have positive CO2 reduction effects. It should decrease power prices from more
renewable investments, which will be particularly important to inhabited islands where (fossil-
based) energy has been commonly subsidized to assure comparable energy prices with the
mainland.
The other key conclusion is that the Mediterranean region does not require one meshed grid
solution covering the entire region. On the contrary, this study recommends considering several
sub regional hubs linking offshore installations with interconnectors. For all production
scenarios, the hub connection yields lower CAPEX than the strictly radial connection
alternatives. The reason is that the hub connection utilizes a common interconnection for
several production blocks, thereby limiting the construction and material costs. On the
downside, it requires coordination between production blocks and sometimes neighbouring
states and their policies. Additionally, some coordination benefits of ongoing or planned
interconnection projects are possible in the following TMAs: Sicily, Corsica-Sardinia, and the
North and South Aegean Seas. The following section proposes several interesting concepts that
should be further analysed and that leverage the established Med TSO and ENTSO-E processes.
A full comparison of the options needs to take into consideration not only the summary costs
but also the strategic choices involved.
5.2 Policy recommendations for member states

This section focuses on supportive policy and regulatory measures that would facilitate
deployment of offshore energies in the Mediterranean region, overcoming the barriers identified
in Section 4.0. The categories of barriers with the highest priority at a regional level were
identified as:
 Offshore renewable energy potential analysis and grid developments

 Social constraints and opportunities
Policy recommendations to remove these barriers on a regional level are presented in the
following section.
5.2.1 Offshore renewable potential analysis and grid developments

As stated in the findings of Task 1 and 2, substantial offshore renewable energy potential exists,
exceeding the current member states’ ambitions expressed in their NECPs (see Section 1.1). To
further understand this potential and possible offshore grid developments, this study proposes
the following measures on the member state level:
 Prepare detailed analysis of potential for economically viable variable renewables (vRES)
offshore and on islands.
 Analyse the potential constraints and potential multiuse of space in maritime spatial
plans, including possibilities to use the protected areas, limitations from bird migration
routes, existing oil and gas industry (O&G), and military sites.
 Support the development of environmental impact studies, including monitoring birds
and mammals, and procedures for pre-investment and post-investment for bird
migration routes in particular.
 Develop best practices for minimizing impacts on wildlife from energy generation
infrastructure.
 Consider increasing the level of RES ambition of the NECPs with an updated analysis of
the economic potential in the NECP review process.
 Revisit the grid development plans, including potential grid development of offshore
energy and additional interconnectors concepts, corresponding with the plans for RES
exploitation.
 Further develop offshore grid design and planning. This analysis is needed to facilitate
vRES (both on- and offshore) development and integration into the power grids on all
voltage levels. EU member states can further increase cooperation within
bilateral/multilateral working groups and Med TSO for grid planning for the most
attractive production blocks.
 Facilitate offshore and onshore grid connection models. Most Mediterranean countries do
not have offshore grid connection models (grid delivery model) for offshore RES in place
yet. Therefore, there is an urgent need to facilitate this process on the regional level
and with active EU support. This study recommends the following:
 Quantify the onshore grid effects of the two proposed scenarios.
 Discuss the proposed models for the connection of offshore RES with neighbouring
countries (both in the EU and outside of the EU, depending on the possible
interconnector), in particular for the development of joint hybrid offshore RES
projects.
 Coordinate within the subregions (e.g., Spain-Portugal-Morocco, Spain-France,
Italy-Tunisia, or Greece-Cyprus-Israel).
5.2.2 Offshore RES generation support

As mentioned in Section 4.0, most Mediterranean EU countries do not yet have support
schemes for offshore RES in place. Analysis of the costs of offshore renewable energies is one of
the priority recommendations for the entire region. Variable RES utilization will have a positive
cost effect on overall cost of energy in the region and specifically in islands, which will have a
crucial impact on the level (or availability) of any support schemes.
Developing rules for this element of RES plant operation (both on- and offshore) should also be
considered. Therefore, this study proposes the following activities:
 Initiate detailed cost analysis for exploiting the additional RES offshore potential and the
necessary support schemes.
 Align balancing and grid services markets and propose cross-border coordination where
RES producers could offer services.
 Address the cost and carbon intensity of energy on islands—a priority for prompt
decarbonization and the elimination of energy poverty; Italy and Greece indicate higher
levels of support for islands, but Italy also links dedicated support to system analysis on
islands. Another solution would be to redirect energy subsidies /tax allowances for
islands from fossil energy to renewable energy (Navigant & E3 Modelling, 2017).
 Propose and discuss ways of aligning support schemes/balancing and grid services
within the specific subregions.
5.2.3 Social constraints and opportunities

The Mediterranean region contains unique nature (including major bird migration routes from
Africa to Europe) and an abundance of various economic activities (such as fishing, shipping,
and tourism), but it is mainly the core touristic region in Europe. Therefore, social and
environmental constraints belong to key barriers to be addressed on the member state and EU
level. Section 5.5 provides some ideas for further research necessary to better understand these
constraints.
Also, a number of measures can be taken at the EU and member state level to overcome
unnecessary hurdles in these fields:
 Funding promotion and education programs to promote sustainable tourism and

sustainable touristic regions
 RES skills build up and expanding the RES job skill base in the region across the entire
value chain
 Support for the development of dedicated training and education programs, or programs
for knowledge sharing across EU member states.
 Support regional associations of TSOs, islands, industry, and communities with
cooperation and knowledge sharing in the region
5.3 The role of the EC

Regional cooperation in energy, grid, and spatial planning is key for cost optimization of the
deployment of offshore RES technologies in the region. The EC plays a crucial role in facilitating
sub regional and regional coordination of efforts also in the Mediterranean region. Therefore,
this study proposes that the EC prioritize the following:
 RES potential and development

 Support the development of a consistent methodology for analysis of potentials for
offshore energy and onshore energy on islands.
 Provide further structured guidance on the regional/cross-border coordination of

maritime spatial planning and energy planning in the region, including a framework
for competing offshore activities and multiuse of the offshore area to optimally
exploit offshore RES potential, in the shallower coastal waters in particular.
 Facilitate discussion on support scheme designs and balancing and grid services
solutions in the subregions and across the region (including non-EU countries) for
offshore RES and for joint offshore projects in particular.
 Grid developments
 Support the development and coordination of offshore, onshore, and cross-border
grid development and operational standards via Med TSO and ENTSO-E for a
dedicated regional RES growth strategy (including offshore energies, islands, and
interconnectors with non-EU member states).
 Facilitate the development of the models via Med TSO/ENTSO-E and support
bilateral and multilateral discussions.
 Develop the minimal requirements for grid/onshore delivery models in the calls for
Projects of Common Interest (for infrastructure and cross-border RES projects).
 Develop key rules for cross-border capacity allocation and a regional grid
maintenance strategy. The EU could play a leading role in this respect with active
participation of the Mediterranean region countries, Med TSO, Med Reg, ENSTO-E,
and ACER.
 Facilitate development of aligned rules for onshore grid infrastructure development
serving offshore energy sources.
 Market design
 Continue the coordination of market coupling efforts.
 Lead the discussion on regional bidding zone arrangements with active participation
of the Med countries, Med TSO, Med Reg, ENTSO-E, and ACER.
 Assist in the development of a cross-border cost allocation (CBCA) framework for
cost sharing supporting the ongoing efforts of Med TSO.
 Facilitate coordination of CBCA principles via leading a dialogue with member states
or even developing the methodology.
 Financing
 Facilitate overcoming the risk related to the cost of capital in south and south
eastern Europe via an EU Renewable Energy Cost Reduction Facility or other
facilitating programs supported by European Investment Bank or European Bank for
Reconstruction and Development.
 RDI
 Support RDI for less mature technologies such as wave, tidal, and floating offshore
wind.
 Facilitate RDI for the optimization of grid planning on a regional level.
 Encourage RDI on the impact of various bidding zone configurations in the offshore
area.
5.4 TMAs and recommendations on pilot projects

This analysis has identified the potential RES technologies for deployment offshore and on
islands. For each of the identified and ranked 10 TMAs, this analysis has identified technology
production blocks. The most interesting ones are:
 Gulf of Lion with high floating offshore wind and wave potential combined with the
interconnection between Spain and France
 Gulf of Venice with a very interesting opportunity in bottom-fixed offshore wind, which
could be connected to the shore with a hub connection and Italy-Croatia interconnection
 North Aegean Sea with substantial floating offshore wind and wave potential, with the
possibility of linking these offshore resources with the extended submarine grid for
interconnection of major islands in the Aegean Sea
 TMA southwest of Sicily offers floating and bottom-fixed offshore wind opportunities,
large wave potential, and large potential for onshore technologies in Sicily and nearby
islands; it is possible to imagine technical solutions where the connection of the
production blocks is realized in parallel with the HVDC link in Italy-Tunisia, or the two
projects being integrated as a single multipole HVDC link.
 TMA Corsica-Sardinia, similarly to Sicily, offers large offshore floating wind energy
potential and potential for onshore technologies on the nearby islands. These offshore
resources could be connected to Italy, but it is possible to consider connecting it to an
HVDC interconnection between northern Italy and Tunisia in parallel with the connection
of the production blocks or integrated it as a single multipole HVDC link.
Task 3 analysed possible grid concepts for all of these technology production blocks. All require
further analysis to clearly understand their potentials and cost-effectiveness, including with
additional novel technologies (e.g., floating PV, P2G).
For smaller scale, onshore and close-to-shore projects (not identified within the 10 TMAs but
potentially adding value to local RES generation), introduction of MUPs could help overcome
strong opposition from local stakeholders.
5.5 Recommendations for further work and analysis

This study is one of the first complex studies covering the entire EU Mediterranean region in
relation to offshore energy deployment and offshore grid potential. Therefore, it generates a
number of further research questions for each of the elements analysed. Below are some
recommendations for further analysis.
5.5.1 Geographical scope and timeline

The study focused on the EEZs of the EU member states and did not analyse the offshore RES
potential for non-EU countries, though it considered EU/non-EU transmission grid
interconnections. Further optimisation of the potential for offshore RES energy and grid
development in the region is possible if non-EU Mediterranean countries (e.g., the Balkans,
Turkey, and North Africa) are included in the analysis. The region has established facilitators for
this process, such as Med TSO, Med Reg, or (partly) the Energy Community.
This analysis confirms that most of the RES offshore potential could be unlocked around 2030
and afterward. Therefore, this study recommends starting long-term planning today and
considering 2035 and 2040 as additional important time horizons for further analysis.
5.5.2 Technology choices and RES potential

This study analysed the potential of offshore technologies (bottom-fixed and floating offshore
wind, wave, and tidal) and onshore technologies on islands (PV, onshore wind). The conclusions
reached about each technology and RES potential include the following:
 Floating offshore wind offers the largest technical potential in the region due to wind
speed and water depth. Additional analysis is recommended to understand the detailed
potential of this energy source, its potential impact on the environment, and potential
interference with other economic activities in the sea.
 Bottom-fixed offshore wind is the most mature offshore energy technology, offering
relatively low LCOE. Some bottom-fixed offshore wind potential exists around the Greek
and Croatian islands and in the Gulf of Venice. These may require further analysis, as
this technology could become the first one to contribute to a substantial growth of
offshore energy in the region.
 Wave and tidal have relatively low economic potential in the Mediterranean region
compared with offshore wind. They are relatively immature technologies and require
further support for technological development. On the other hand, they do not cause the
visual impact of wind power, and they could be further developed and considered for
smaller applications closer to islands and mainland shores.
 Onshore vRES potential in islands—in islands within the identified TMAs and with
relatively mature onshore wind and PV in particular (given the vast solar potential in the
region)—should be further explored for both inhabited and non-inhabited islands. This
exploration refers especially to PV in the built environment and small-scale commercial

installations in the inhabited Mediterranean islands. The benefit of installing vRES in
numerous uninhabited islands is that social acceptance is not an issue and a substantial
cost reduction gain occurs related to installing mature and cheaper onshore
technologies.
 This study provides a relatively conservative approach to the special constraints’
analysis, including main shipping routes, fishing, environmental protection, and military
use. More detailed analysis on the local level, including the potential multiuse of space,
is needed to refine the potential analysis and the definition of the development zones.
 This study does not include the novel technologies, such as floating PV, CSP, P2X
solutions (green hydrogen generation), and (green) gas transmission. Finally, this study
did not analyse flexibility potential and demand of other storage options. Adding these
technologies and infrastructural planning (power grids versus gas grids) and extending
the analysis for the entire Med region (as recommended above) may further contribute
to faster decarbonisation of the region.
5.5.3 Grid development needs

In general, the transmission grid around the Mediterranean Sea is not very strong or well
meshed. Although increasing since 2017, the interconnection levels of Portugal, Spain, Italy,
and Greece are below the EU 2030 target for 2030 and 2050. This analysis has found that the
ambitious scenario shows significantly higher consumer surplus and lower producer surplus due
to generally lower prices, as expected. This result occurs due to new RES-E volumes being
brought into the market and more congestion for the existing grid resulting in higher congestion
rents. In addition to the analysed grid options, the hub connections always show better results
than the radial connections in 2030. All involved countries except for Portugal are anticipated to
experience major needs for reinforcements in the conservative scenario, whereas all countries
should be affected in a major way in the ambitious scenario. Further analysis taking into
consideration RES potential and EU 2030 target realisation for interconnectivity is needed to
understand the trade-offs between the lower cost of energy, the decrease of CO2 emissions, and
the cost of new infrastructure. This analysis should be developed for the whole region and for
the specific new investment plans.
For onshore wind projects, grid interconnectivity may become an important issue since wind
sites tend to be located further away from the grid and detailed, localisation-specific analyses
need to be undertaken. Since the current analysis did not include any P2G options, extending
the overall system optimisation analysis and exploring gas grid applicability for green hydrogen
generation and transmission is recommended to optimise the use of available RES potential.
This analysis is important to ensuring cost-efficient grid development to integrate the large
amount of offshore RES to demand centres.
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Appendix A. Potential for offshore power generation background

This appendix presents the cost parameter inputs for a levelized cost of electricity (LCOE)
assessment. Multiple sources from various well-known references such as the International
Renewable Energy Agency (IRENA), the International Energy Agency (IEA), and ASSET have been
examined for each cost input to ensure that reliable cost assumptions are taken for the LCOE
calculation. Table A-1 and Table A-2 show the CAPEX assumptions chosen for the LCOE
assessment.
Table A-1: CAPEX of technologies for LCOE assessment (million €/MW)

CAPEX Offshore energy Onshore energy on islands
Bottom- Floating Tidal Wave Utility Rooftop Onshore
fixed offshore energy energy solar PV solar PV wind
offshore wind
wind
2030 1.6 2.2 4.1 5.5 0.3 0.6 1.0
2050 1.4 1.4 3.3 2.7 0.2 0.3 0.8
Sources for CAPEX parameters are:
 Bottom-fixed offshore wind CAPEX in 2030 and 2050: Energinet.dk, 2018.

https://ens.dk/sites/ens.dk/files/Analyser/havvindsnotat_translation_eng_final.pdf.
 Floating offshore wind CAPEX in 2030: Portugal's Final Integrated National Energy and Climate
Plan 2021-2030 (PNEC 2030), 2019. http://www.dgeg.gov.pt/.
 Floating offshore wind CAPEX in 2050: Given the lack of data, this study assumes floating
offshore wind converges to bottom-fixed offshore wind cost levels in 2050.
 Wave & tidal CAPEX in 2030 and 2050: OES & IEA, 2015. International Levelized Cost of Energy
for Ocean energy Technologies, page 6.
https://testahemsidaz2.files.wordpress.com/2017/02/cost-of-energy-for-ocean-energy-
technologies-may-2015.pdf.
 Utility solar PV CAPEX in 2030 and 2050: Vartiainen et al., 2019. Impact of weighted average
cost of capital, capital expenditure, and other parameters on future utility‐scale PV levelized cost
of electricity. https://onlinelibrary.wiley.com/doi/epdf/10.1002/pip.3189.
 Rooftop solar PV CAPEX in 2030 and 2050: Based on National Renewable Energy Laboratory’s
(NREL) technology database (NREL, 2019b) and (NREL, 2019a), this study estimates rooftop
CAPEX levels to be approximately double the amount of utility solar PV CAPEX levels in 2030 and
2050.
 Onshore wind CAPEX in 2030 and 2050: IRENA, 2019. Future of Wind. https://www.irena.org/-
/media/Files/IRENA/Agency/Publication/2019/Oct/IRENA_Future_of_wind_2019.pdf.
Excluding transmission costs, European bottom-fixed offshore wind capital costs are expected to
drop to under 2,000 $/kW towards 2030 and to about 1,500 $/kW in 2040 (IEA, 2019). These
costs are in line with the assumptions taken in the LCOE assessment (Energinet.dk, 2018) and
represent the lower bound of installation costs in IRENA’s Future of Wind report, which range from
1,700-3,200 $/kW in 2030 and 1,400-2800 €/kW in 2050 (Irena, 2019b). For floating offshore
wind, this study assumed that by 2050 this technology will converge to cost levels similar to those
of bottom-fixed offshore technology. Given the lack of data for 2050 projections, bottom-fixed
offshore wind CAPEX levels are assumed to be the best estimate available.
For onshore wind, the CAPEX levels assumed according to Table A-1 also fall in the range given in
IRENA’s Future of Wind report, 800-1,350 $/kW in 2030 and 650-1,000 $/kW in 2050 (Irena,
2019b) and in the ASSET study, 988 €/kW in 2030 and 782 €/kW in 2050 (ASSET, 2018).
Guidehouse’s CAPEX assumptions for solar technologies in 2030 and 2050 (Vartiainen, 2019) are
also in the order of magnitude of IRENA’s Future of Solar PV report: 340-834 $/kW in 2030 and of
165-481 $/kW in 2050 (Irena, 2019a). CAPEX levels in the ASSET study show higher solar PV
overnight investment costs: 627 €/kW in 2030 and 407 €/kW in 2050 for utility-scale solar PV with
a very high potential and 930 €/kW in 2030 and 610 €/kW in 2050 for small-scale rooftop systems
(ASSET, 2018). However, the ASSET study dates from 2018, and given the rapid cost reductions
that solar PV technology is experiencing, it seems realistic to think that 2019 sources incorporate
more updated cost reductions that have a higher impact on overall capital cost projections.
For wave and tidal CAPEX values, this study’s best estimate is based on an international study
from Ocean Energy Systems and IEA (OES & IEA, 2015), a comprehensive technology study based
on different international projects (e.g., SI Ocean, DTOcean, EquiMar, the Danish LCOE Calculation
Tool, Carbon Trust, and US Department of Energy).
Table A-2: OPEX of technologies for LCOE assessment (k€/MW/year)

OPEX Offshore energy Onshore energy on islands
Bottom- Floating Tidal Wave Utility Rooftop Onshore
fixed offshore energy energy solar PV solar PV wind
offshore wind
wind
2030 50 70 228 209 9 8 30
2050 43 43 45 35 4 6 30
Sources for OPEX parameters are:
 Bottom-fixed offshore wind OPEX in 2030 and 2050: Energinet.dk, 2018. Note on technology
costs for offshore wind farms and the background for updating CAPEX and OPEX exists in the
technology catalogue datasheets. CAPEX and OPEX cost values are assumed for a water depth of
up to 38 m and a distance to shore of 22 km. LCOE values given include grid connection cost.
https://ens.dk/sites/ens.dk/files/Analyser/havvindsnotat_translation_eng_final.pdf.
 Floating offshore wind OPEX in 2030 and onshore wind OPEX in 2030 and 2050: Portugal's Final
Integrated National Energy and Climate Plan 2021-2030 (PNEC 2030), 2019.
http://www.dgeg.gov.pt/.
 Floating offshore wind OPEX in 2050: Given the lack of data, this study assumes floating offshore
wind converges to bottom-fixed offshore wind cost levels in 2050.
 Wave & tidal OPEX in 2030 and 2050: OES & IEA, 2015. International Levelized Cost of Energy
for Ocean energy Technologies, page 6.
https://testahemsidaz2.files.wordpress.com/2017/02/cost-of-energy-for-ocean-energy-
technologies-may-2015.pdf.
 Utility solar PV OPEX in 2030 and 2050: Vartiainen et al., 2019. Impact of weighted average cost
of capital, capital expenditure, and other parameters on future utility‐scale PV LCOE included.
Cost figures are given for utility-scale solar PV in European countries. LCOE ranges represent the
cost level with a nominal WACC of 7% for three different locations in France, Italy, and Spain as
described in Figure 9 of the report. https://onlinelibrary.wiley.com/doi/epdf/10.1002/pip.3189.
 Rooftop solar PV OPEX in 2030 and 2050: Based on the NREL technology database (NREL,
2019b), this study assumes rooftop OPEX levels in 2030 as an average of 6.5 k€/MW/year and
10 k€/MW/year and as an average of 4 k€/MW/year and 8 k€/MW/year in 2050.
Similarly, fixed operations and maintenance (O&M) costs assumed are in line with other O&M costs
gathered from well-known studies. IEA reports O&M cost levels for bottom-fixed offshore wind of
around 60 $/kW in 2030 and 50 $/kW in 2040 (IEA, 2019). The ASSET study projects rather
aggressive fixed O&M cost levels for very remote offshore wind, 43 €/kW in 2030 and 39 €/kW in
2050 (ASSET, 2018). For floating offshore wind, given the lack of public data on 2050 cost
projections, this study assumes similar fixed O&M levels for bottom-fixed offshore wind in 2050.
According to the ASSET study, utility-scale solar PV fixed O&M costs amount to 13.5 €/kW in 2030
and 10.8 €/kW in 2050. Small-scale rooftop solar PV O&M costs amount to 17 €/kW in 2030 and
13 €/kW in 2050 (ASSET, 2018). In a similar way as the CAPEX values, the 2019 assumptions
taken might be incorporating more updated and advanced cost reduction projections compared to
the 2018 ASSET study. For onshore wind, 2019 assumptions taken for fixed O&M remain on the
higher side compared to ASSET fixed O&M costs, which amount to around 21 €/kW in 2030 and 20
€/kW in 2050.
Similarly for CAPEX levels, for wave and tidal OPEX values, this study bases our best estimate on a
report by the OES and IEA (OES & IEA, 2015), which is based on a series of different international
sources and projects.
Appendix B. Production scenarios background

B.1 Apollo
Sweco’s power market model Apollo is used to simulate power supply and demand across the
entire interconnected European market in an hourly resolution. The Apollo’s standard dataset
contains data for 31 countries and 43 bidding zones in the European market. As for the
Mediterranean member states, Italy is divided into six bidding zones (north, centre-north,
centre-south, south, Sicily, and Sardinia) while the other member states are modelled as one
bidding zone. Generator dispatch and wholesale electricity prices are modelled based on a range of
defined market input parameters and assumptions. Input parameters are demand, thermal
capacity, RES-E capacity, available transmission capacity, hydrology, fuel price profiles and solar
and wind profiles. Apollo captures the technical characteristics of 381 generating technology
classes and efficiencies.
Apollo’s intuitive interfaces allow simulations where it easily varies inputs to create, refine, and
analyse different scenarios. Graphic visualization is key to interpreting results. The results of an
Apollo model run are presented in a series of automatically generated Excel reports for a number
of different themes. All reports contain interactive charts and graphs for an easy interpretation of
the simulation results. Reports that generated by Apollo include:
 Dashboard Analyzer: this is Apollo’s main report for short- and medium-term planning.
It visualizes a wide range of outputs: weekly prices, weekly price structures, hydro
generation, reservoir levels, and generation by week, generation in week, trade by week,
and trade in week.
Figure B-1: Apollo’s Dashboard Analyzer report
(Source: SWECO)
 Scenario Analyzer: An overview report that summarizes the operation of the system
from an annual and weekly aggregate perspective, showing generation, price, and trade
patterns.
 Price Analyzer: A detailed report that provides hourly price structures in different price
zones and price differences across scenarios.
 Economic Analyzer: An overview report that looks at profitability of different generation
technologies and welfare effects of various policies as defined in the input scenarios. The
report includes a scenario overview, various output data tables, CO2 emissions, and a
hydro analyser.
Apollo is used for both short-term and long-term planning regularly to assess the longer-term
effects of development in the Swedish and European electricity markets. Apollo's inclusion of most
European countries and bidding zones is especially important in longer-term planning as Europe
moves towards a single market. Typical uses for Apollo include scenario analysis, price volatility
analysis following the integration of large shares of electricity generation from RES, interconnector
profitability analysis, interconnector welfare analysis, and investment profitability, including
income stream per technology. Apollo’s hourly resolution provides additional insight into the value
of flexibility, particularly in electricity systems with high penetrations of variable technologies.
For short-term-planning, Apollo is typically used to focus on one region and look at price
forecasting, sensitivity studies including plant or interconnector outages, wet and dry year
sensitivities, cold winters, and financial risk calculations. Users can choose the week of the year to
start model simulations and are able to use near-term forecasts of most inputs to get a closer view
of what lies in store.
Apollo optimizes the annual system cost for a defined scenario. Apollo is not an energy investment
model, and the above input parameters are defined by the user for each modelled scenario and
year. As a basis for simulations of future power systems, input parameters are defined for a
reference scenario maintained through Sweco’s continuous scenario work updates. The reference
scenario is based 2020 actuals and Sweco assumptions of the development of new capacity
installations and demand evolution. Production capacity is based on an aggregation of existing
production facilities, known plans for new capacity, and estimated phase out and potential renewal
of existing capacity. Additional new capacity is based on current trends, national targets, and
Sweco assessments of the development of specific RES technologies. Transmission capacities are
based on current capacities and planned projects in TYNDP 2018. Additional transfer capacities
until 2050 have been added based on the TYNDP Identification of System Needs (IoSN) for 2040 in
TYNDP 2018 and through Sweco’s identification of required capacities in the iterative modelling
process.
B.2 Transmission capacity assumptions

Table B-1: Assumed net transmission capacity between bidding zones in 2030
and 2050 (export)
Sum of Transmission Capacity [MW] Column Labels
Row Labels MedOffshore_NECP_2030 MedOffshore_Ambitious_2030 MedOffshore_NECP_2050 MedOffshore_Ambitious_2050
Portugal 3500 3500 4200 4200
Spain 3500 3500 4200 4200
Spain 13500 13500 18200 18200
Exogenous 1200 1200 1200 1200
France 8100 8100 11800 11800
Portugal 4200 4200 5200 5200
France 32450 32450 39950 39950
Belgium 5750 5750 6350 6350
Germany 4800 4800 7300 7300
Ireland 700 700 1200 1200
Spain 8300 8300 11600 11600
Switzerland 5100 5100 5100 5100
UK 7800 7800 8400 8400
IT-NO 10305 10305 15205 15205
Austria 835 835 3735 3735
IT-CN 4150 4150 4150 4150
Slovenia 1710 1710 2710 2710
Switzerland 3610 3610 4610 4610
IT-CN 5300 5300 7300 7300
IT-CS 2750 2750 2750 2750
IT-NO 2150 2150 4150 4150
IT-SA 400 400 400 400
IT-CS 20100 20100 20100 20100
Exogenous 3200 3200 3200 3200
IT-CN 4200 4200 4200 4200
IT-SA 700 700 700 700
IT-SI 1000 1000 1000 1000
IT-SU 11000 11000 11000 11000
IT-SU 8100 8100 8800 8800
Greece 500 500 1200 1200
IT-CS 6500 6500 6500 6500
IT-SI 1100 1100 1100 1100
IT-SA 1300 1300 1300 1300
IT-CN 400 400 400 400
IT-CS 900 900 900 900
IT-SI 3000 3000 3000 3000
Exogenous 600 600 600 600
IT-CS 1000 1000 1000 1000
IT-SU 1200 1200 1200 1200
Malta 200 200 200 200
Slovenia 6345 6345 8845 8845
Austria 1200 1200 2200 2200
Croatia 2000 2000 2500 2500
Hungary 1200 1200 1200 1200
IT-NO 1945 1945 2945 2945
Croatia 6562 6562 7062 7062
Exogenous 2562 2562 2562 2562
Hungary 2000 2000 2000 2000
Slovenia 2000 2000 2500 2500
Greece 1832 1832 5532 5532
Bulgaria 782 782 2482 2482
Cyprus 0 0 2000 2000
Exogenous 550 550 550 550
IT-SU 500 500 500 500
Cyprus 2000 2000 4000 4000
Exogenous 1000 1000 2000 2000
Greece 1000 1000 2000 2000
Malta 200 200 200 200
IT-SI 200 200 200 200
(Source: SWECO)
Table B-2: Assumed net transmission capacity between bidding zones in 2030
and 2050 (import)
Sum of Transmission Capacity [MW] Column Labels
Row Labels MedOffshore_NECP_2030 MedOffshore_Ambitious_2030 MedOffshore_NECP_2050 MedOffshore_Ambitious_2050
Portugal 4200 4200 5200 5200
Spain 4200 4200 5200 5200
Spain 13000 13000 17000 17000
Portugal 3500 3500 4200 4200
Exogenous 1200 1200 1200 1200
France 8300 8300 11600 11600
France 28750 28750 37750 37750
Belgium 4150 4150 4750 4750
Spain 8100 8100 11800 11800
Germany 4800 4800 7600 7600
Ireland 700 700 1200 1200
Switzerland 3200 3200 3200 3200
UK 7800 7800 9200 9200
IT-NO 11040 11040 18040 18040
Austria 1005 1005 4005 4005
IT-CN 2150 2150 4150 4150
Slovenia 1945 1945 2945 2945
Switzerland 5940 5940 6940 6940
IT-CN 8750 8750 8750 8750
IT-NO 4150 4150 4150 4150
IT-CS 4200 4200 4200 4200
IT-SA 400 400 400 400
IT-CS 14350 14350 14350 14350
Exogenous 3200 3200 3200 3200
IT-CN 2750 2750 2750 2750
IT-SU 6500 6500 6500 6500
IT-SA 900 900 900 900
IT-SI 1000 1000 1000 1000
IT-SU 12700 12700 12700 12700
IT-CS 11000 11000 11000 11000
IT-SI 1200 1200 1200 1200
Greece 500 500 500 500
IT-SA 1100 1100 1100 1100
IT-CN 400 400 400 400
IT-CS 700 700 700 700
IT-SI 2900 2900 2900 2900
Exogenous 600 600 600 600
IT-CS 1000 1000 1000 1000
IT-SU 1100 1100 1100 1100
Malta 200 200 200 200
Slovenia 7475 7475 10275 10275
Austria 1200 1200 2500 2500
Hungary 2565 2565 2565 2565
IT-NO 1710 1710 2710 2710
Croatia 2000 2000 2500 2500
Croatia 5844 5844 6344 6344
Exogenous 2644 2644 2644 2644
Hungary 1200 1200 1200 1200
Slovenia 2000 2000 2500 2500
Greece 3098 3098 6698 6698
Bulgaria 1198 1198 3098 3098
Exogenous 400 400 400 400
IT-SU 500 500 1200 1200
Cyprus 1000 1000 2000 2000
Cyprus 1000 1000 4000 4000
Exogenous 1000 1000 2000 2000
Greece 0 0 2000 2000
Malta 200 200 200 200
IT-SI 200 200 200 200
(Source: SWECO)
B.3 Power generation by fuel

Table B-3: Power generation by fuel category in 2030 and 2050 for the NECP and
ambitious production scenarios
Sum of Generation [TWh] Column Labels
Row Labels Portugal Spain France Italy Slovenia Croatia Greece Cyprus Malta Grand Total
Battery storage
MedOffshore_NECP_2030 -0,2 -0,1 0,0 0,0 -0,1 0,0 0,0 -0,4
MedOffshore_Ambitious_2030 -0,2 -0,1 0,0 0,0 -0,1 0,0 0,0 -0,4
MedOffshore_NECP_2050 -0,1 -0,4 -0,7 -0,4 -0,1 0,0 -0,2 0,0 0,0 -2,0
MedOffshore_Ambitious_2050 -0,1 -0,4 -0,7 -0,3 -0,1 0,0 -0,2 0,0 0,0 -1,9
Coal
MedOffshore_NECP_2030 4,4 0,0 10,7 15,0
MedOffshore_Ambitious_2030 4,3 0,0 9,8 14,1
Oil
MedOffshore_NECP_2030 0,7 0,5 0,9 0,7 0,0 0,0 0,0 0,0 0,0 2,8
MedOffshore_Ambitious_2030 0,7 0,5 0,9 0,7 0,0 0,0 0,0 0,0 0,0 2,8
MedOffshore_NECP_2050 0,0 0,0 0,0 0,0 0,0 0,0
MedOffshore_Ambitious_2050 0,0 0,0 0,0 0,0 0,0 0,0
Gas
Nuclear
MedOffshore_NECP_2030 18,4 364,3 5,4 388,1
MedOffshore_Ambitious_2030 16,9 357,2 5,4 379,5
MedOffshore_NECP_2050 242,6 6,8 249,3
MedOffshore_Ambitious_2050 224,3 6,5 230,8
Hydro
MedOffshore_NECP_2030 11,6 33,2 64,2 48,4 4,6 8,4 6,6 177,0
MedOffshore_Ambitious_2030 11,6 33,2 64,2 48,5 4,6 8,4 6,6 177,1
Biomass and waste
Solar
Wind onshore
MedOffshore_NECP_2030 27,1 116,1 93,8 37,1 0,2 2,7 16,2 0,4 293,7
MedOffshore_Ambitious_2030 27,1 116,1 93,8 37,1 0,2 2,7 16,2 0,4 293,7
Wind offshore
MedOffshore_NECP_2030 1,2 0,0 22,3 3,0 0,0 0,0 26,5
MedOffshore_Ambitious_2030 6,1 16,1 37,2 14,3 1,1 7,5 82,2
Other RES
(Source: SWECO)
Appendix C. Grid options background

As a basis for CAPEX and OPEX for the different grid connection alternatives, connections were
modelled at an aggregated level using the following components:
 HVDC:
 Offshore platform
 Offshore converter station, 320 or 500 kV
 Sea cable, 320 or 500 kV
 Land cable, 320 or 500 kV
 Onshore converter station, 320 or 500 kV
 HVAC:
 Offshore platform
 Offshore 220 kV switchgear
 Offshore transformer to 220 kV
 Sea cable, 220 kV
 Land cable, 220 kV
 Onshore 220 kV switchgear
 Onshore 220/400 kV transformer
CAPEX figures for the above components were mainly retrieved from Study of the Benefits of a
Meshed Offshore Grid in Northern Seas Region – Final Report (Cole, Martinot, Rapoport,
Papaefthymiou, & Gori, 2014), assumed to be relevant for 2019, and summarized in Table C-1.
Reactive compensation was assumed as an additional per-length cost for the HVAC alternative and
assumed to include filtering needs.
OPEX was calculated as a percentage of CAPEX, with assumed values for different categories of
components listed in Table C-1. Additional assumptions and cost figures include the following:
 Resistive losses for each connection were calculated based on the production time series
for each technology and TMA.
 The choice of technology for each connection (HVAC or HVDC) was made based on the
total cost over 25 years with an assumed cost for losses of 50 €/MWh.
 The capacities for the different dimensions of cables were calculated based on
dimensioning criteria of 1.0 A/mm2 for aluminium conductors and 1.2 A/mm2 for copper
conductors.
Table C-1: Cost catalogue for Task 3

HVDC CAPEX, from (Cole, Martinot, Rapoport,
Papaefthymiou, & Gori, 2014)
Component Cost Remark
DC platform 111.3 M€/unit 1
HVDC station VSC 500 MW 300 kV 83.5 M€/unit 1
HVDC station VSC 2000 MW 500 kV 170 M€/unit 1
2x1x300mm² cu ±320 kV DC Offshore 600 €/m
2x1x1000mm² cu ±320 kV DC Offshore 1000 €/m 2
2x1x2500mm² cu ±320 kV Offshore 1324 €/m
2x1x500mm² alu ±320 kV Onshore 546 €/m
2x1x2400mm² alu ±320 kV Onshore 750 €/m
2x1x1500mm2 alu ±500 kV Onshore 858 €/m
2x1x2500mm2 alu ±500 kV Onshore 1000 €/m
Offshore cable installation cost 400 €/m
Onshore cable installation cost 150 €/m 3
HVAC CAPEX, from (Cole, Martinot, Rapoport,

Component Cost Remark
AC Platform 45.5 M€/unit 1
Transformation 10,000 €/MVA
220 kV switchgear 2.68 M€/unit
1x3x400mm² cu 220kV Offshore 540 €/m
1x3x1600mm² alu 220 kV Offshore 875 €/m
2x3x1600mm² alu 220 kV Offshore 1,750 €/m

3x3x1600mm² alu 220 kV Offshore 2,625 €/m
3x1x1200mm² alu 220 kV Onshore 525 €/m
6x1x1200mm² alu 220 kV Onshore 1,050 €/m
Offshore cable installation cost 400 €/m
Onshore cable installation cost 150 €/m 3
Reactive compensation 63,250 €/MVA 4
OPEX, assumed values
Type of component % of CAPEX
AC stations, bays, and transformers 1.50
Land cables 220 -400 kV 0.15
Reactive compensation 1.50
HVDC stations 1.00
Marine HVDC and AC cables 2.00
Platforms 1.00
Remarks
Mid-value of range given in (Cole, Martinot, Rapoport,

1
Assumed value, not in (Cole, Martinot, Rapoport, Papaefthymiou, & Gori, 2014). Added to limit the step
2
increase of cost when moving to a bigger cable dimension than 300 mm2.
Assumed value, not in (Cole, Martinot, Rapoport,

3
4 AC 220 kV cable is assumed to need 1 MVAr/km per phase
(Source: SWECO)
Appendix D. Longlist of barriers

Table D-1 presents an overview of the identified barriers.
Table D-1: Barriers and implementation challenges for offshore grid and offshore renewable development with detailed
description and ranking
Barrier Description and rationale barrier Rank
Offshore grid and renewable generation technologies
1 Mature offshore What: The geographical and climatological conditions (water depth, bottom morphology, minimal distances Strong
renewable energy and from shore, availability of current speeds, lack of tides, etc.) of the Mediterranean require specific renewable
grid technologies energy technologies, such as floating wind turbines due to limited areas with shallow water depth.116,117
suitable for the Why: There is a need for mature technologies, adapted to the environmental characteristics of the
development of an Mediterranean. Sufficient maturity levels of technologies suitable for offshore energy development in the
offshore grid in the Mediterranean are required to exploit available RES potential, such as floating offshore wind or HVDC grid
Mediterranean components. Currently, technologies such as floating offshore wind are not yet fully mature. 117
2 Coordinated offshore What: For an offshore grid system to function in accordance with operational standards coordination of grid Strong
grid technologies and technologies in the region is important. This includes interoperability of protection systems in HVDC
interoperability of systems.118
assets Why: Uncoordinated technologies could result in unsafe operation. For example, protection systems from
different vendors should be able to connect and communicate with each other (Interoperability).118 This is a
key barrier of meshed offshore grids currently investigated under the PROMOTioN project for the Northern
Seas.Error! Bookmark not defined.
3 Availability of supply What: Developing and constructing an offshore grid and large-scale offshore renewables requires a large Strong
chain for components, supply chain of raw materials, manufacturing of technical components, skilled personnel, and specialised
labour force, and infrastructure, such as specialised ships and ground transportation.117
infrastructure to Why: Currently, there is limited experience with and manufacturing of offshore renewable and grid
develop offshore components in the Mediterranean Sea region. Supply chains and capacity must build up to ensure a timely
renewables and grid development of offshore renewables and grid infrastructure.119
infrastructure
116
117
(WindEurope, 2019b)
118
(PROMOTioN, 2017a)
119
(Interreg, 2017)

Offshore grid design and planning
1 Data availability for What: Centralised and open access data is required for spatial planning and project development planning Moderate
planning in the Mediterranean region. There is a need for regional data on sites such as military training sites,
archaeological sites, and tourism areas, and for data on energy production, energy use, and energy
efficiency on islands.
Why: Not all required data is currently (publicly) available, and available data is often spread out between
stakeholders and countries in the region—in particular, data regarding spatial constraints, archaeological
and heritage sites, and island communities.120
2 Regional What: To ensure successful development of a Mediterranean offshore grid that optimises the use of high Moderate
communication and potential offshore sites, a joint initiative from member states in the region with ongoing cooperation and
cooperation on various communication efforts is important, on Transmission System Operator, regulatory,121 and governmental
levels levels and between terrestrial and maritime planning authorities on a national level and across countries.
Why: Regional cooperation on TSO and governmental levels is required to develop an offshore grid.
Currently cooperation in the region regarding offshore grid development is improving through various
initiatives and associations. For example, Med-TSO published a report on key performance indicators for the
regional electricity system in May 2020.122
3 Competing offshore What: High potential offshore sites for renewable energy generation often fall in areas where other offshore Strong
activities limit human activities occur such as industrial shipping, fishing, military training areas, oil rigs, cruise ship
exploitation of full passage, tourism, and other marine activities.123
offshore renewables Why: Competing uses of high potential offshore renewable sites limit the optimal exploitation of renewable
potential energy. In the Mediterranean, this is particularly relevant in shallower water, which is limited due to the
steep fall in bathymetry.124 Shallow areas show high potential for bottom-fixed offshore wind and high levels
of other offshore (touristic) human activities. Currently, there is no clear definition of multiple uses of high
potential RES sites in the region.
120
Databases that already exist are https://www.emodnet-humanactivities.eu/view-data.php and http://www.msp-supreme.eu/files/c-1-3-2-and-c-1-3-3-data-and-
tools.pdf.
121
European TSO cooperation already occurs through ENTSO-E and regional TSO cooperation through Med-TSO: https://www.med-
tso.com/mission.aspx?f=&title=About+Med-TSO; cooperation on a regional Mediterranean level also takes place through MedReg, for example: http://www.medreg-
regulators.org/Aboutus/Members.aspx
122
Med-TSO, 2020. Deliverable 5.2 “Key Performance Indicators of the regional electricity system”. https://www.med-
tso.com/publications/Deliverable_5.2_Key_performance_indicators_of_the_regional_electricity_system.pdf
123
(European MSP Platform, 2018b)
124

4 Natural constraints What: The geographical and climatological conditions of the Mediterranean Sea area provide natural Moderate
constraints to the development of offshore renewables such as water depth, resource availability, and the
presence of archaeological and cultural heritage sites.125 Natural constraints are seen as hard constraints
that restrict offshore development areas.
Why: Water depth can be a barrier to some technologies, such as bottom-fixed offshore wind and offshore
cable development. In the Mediterranean Sea area, shallow water is limited126 and includes archaeological
sites that are currently not well mapped in public and centralised databases (see Data availability for
planning).
5 Regional offshore grid What: To maximally exploit renewable potential in the Mediterranean Sea region and develop joint projects, Moderate
development strategy it is necessary to align development goals and plans for offshore renewable development and on- and
offshore grids on a regional level through a joint offshore grid development strategy. On a European level,
there is cooperation on transmission grid development in the 10-year network development plans from
ENTSO-E.127 On a regional level, increased focus is occurring on the development in the Mediterranean by
Med-TSO.128
Why: Offshore grid development benefits from regional collaboration to understand the siting, timing,
planned clusters, and targets for offshore marine energy development; otherwise joint grid developments
might not be optimised in step with renewable developments to bring renewable energy generation to the
load centres in the region.
6 Offshore grid planning What: The development of an offshore grid requires new planning criteria on a regional level to ensure the Moderate
criteria system will function safely and investments are optimised, in contrast with point-to-point interconnectors
and radial connections of offshore renewable generators to shore.129 This requirement is a common
challenge for all offshore grid developments in European sea basins (e.g., Northern Seas).
Why: For example, reliability standards for meshed offshore grids are an important planning criterion that
do not yet exist. The current criterion of N-1 for transmission networks might not be appropriate anymore,
amongst others being investigated in the Horizon 2020 PROMOTioN project.130 On a regional level, there are
ongoing efforts by Med-TSO.
125
126
127
(ENTSO-E, 2018d)
128
Mediterranean Project I and Mediterranean Project II. https://www.med-tso.com/mediterranean2.aspx?f=
129
(PROMOTioN, 2017a)
130
(PROMOTioN, 2017a)

7 Joint standard models What: To undertake joint grid planning and design, TSOs across the region need to adopt the same Moderate
and datasets for modelling tools for grid planning, network operation, and market simulations to have results that are
long-term grid broadly accepted and to achieve a joint strategy. In addition, joint assumptions (energy development
planning scenarios, adopted weather data, etc.) and datasets need to be developed for these models to compare
results and outcomes.
Why: Currently, limited publicly available joint standard models and assumptions exist on a regional level.
Ongoing efforts by the EU level increase availability of these (e.g. TYNDP scenarios, EU common grid
model131 and MedTSO initiatives).
Offshore and onshore grid
1 (Aligned) grid What: Offshore renewables require a clear grid delivery model that defines the roles and responsibilities for Strong
transmission asset the development, construction, ownership, O&M, and financing of transmission assets of offshore renewable
responsibility for generation units. These responsibilities often fall to the TSO, transmission asset owner (TAO), commercial
offshore energy developer, or another commercial party (e.g., OFTO in the UK). Generally, two main models exist: plan-led
generators (offshore or developer-led, and a range of hybrid models combine aspects of both.132
grid delivery model) Why: Without a defined grid delivery model for transmission asset responsibilities, developers do not have
clarity on costs and procedures for transmission asset development. This situation reduces developer
confidence in developing offshore renewable energy. Currently, some Mediterranean countries do not have a
specified grid delivery model yet.132,133 For example, France is one of the Mediterranean countries with a
defined grid delivery model for offshore wind, placing the responsibility of offshore grid development with
the French TSO RTE rather than the developer. For joint projects, alignment of grid delivery models in the
region could be an added benefit although not required.134
131
(ENTSO-E, 2018a)
132
(Navigant, 2019; WindEurope, 2019d)
133
(RES Legal, 2020)
134
Note that shared projects between two countries with different grid delivery models is not uncommon as, for example, TenneT and Vattenfall are investigating the
feasibility of an interconnector between a TenneT offshore substation in the Netherlands and a Vattenfall offshore substation in the UK: TenneT, 2018. TenneT and
Vattenfall to study potential Dutch and UK offshore wind farm connections. https://www.tennet.eu/news/detail/tennet-and-vattenfall-to-study-potential-dutch-and-uk-
offshore-wind-farm-connections/

2 Aligned rules (regimes What: Onshore connection rules for offshore renewable energy specify the responsibilities to ensure Moderate
and procedures) for appropriate hosting capacity of the onshore grid, and measures/compensations (if any) in case of delayed
onshore grid grid infrastructure.135,136 To ensure timely operation of renewables, often anticipatory investments have to
infrastructure be made in the onshore grid to ensure offshore renewable energy can be evacuated to onshore load centres.
(connection, Why: National differences in rules could hinder the timely development of grid infrastructure through
expansion, and delayed anticipatory investments and the operation of the renewable energy generators. In particular, for
reinforcement) large-scale offshore developments, it is important that these rules match onshore grid connection plans,
with potential long development lead times, to avoid temporarily stranded assets.
Market design specific to offshore area
1 Bidding zone What: Bidding zones within Europe largely follow national borders. Bidding zones are determined based on Strong
arrangement for the the copper plate concept.137 Bidding zones should therefore reflect major congestions in the network.
offshore area Currently, offshore areas are included in the bidding zone of the country in which exclusive economic zone
(EEZ) they belong to. Offshore renewable generation currently participates in its home market.
Why: An offshore grid could result in important offshore congestions that are not reflected through the
current bidding zone arrangement. In addition, offshore renewable energy in an offshore grid could be
located in the EEZ of one country but connected to the offshore grid in the EEZ of another country if that is
optimal from a planning perspective.138 These developments would require an analysis regarding suitable
bidding zone configurations for the Mediterranean region.
135
(RES Legal, 2020)
136
(WindEurope, 2019d)
137
(ENTSO-E, 2018c)
138
(PROMOTioN, 2017a), (PROMOTioN, 2019c)

Offshore RES generation
1 Aligned balancing What: Balancing responsibly defines which market players are responsible for maintaining the balance Strong
responsibility of between supply and demand in the electricity market.139 Balancing responsibility rules can vary between
offshore renewable markets and impact the business case of generators if they cause or alleviate an imbalance and whether
generators they have access to markets after day-ahead to adjust their forecasts and mitigate their own imbalances.140
Why: National differences and uncertainties regarding the responsibility of offshore renewable generators
balancing responsible parties and how remuneration and penalties are organised could hamper offshore
renewable development. Offshore renewables could also be limited to being balancing-responsible parties in
the market they are located in rather than on a regional level in an offshore grid.
2 Aligned requirements What: Grid services include frequency control, reactive power, and voltage control, among others. Grid Moderate
and standards for RES services are determined by the Network Code on Requirements for Grid Connection Applicable to All
grid services Generators (RfG) (art. 21)48,141,142. For HVDC, this is specifically addressed in the HVDC Network Code (art.
37 and 38) from ENTSO-E (2014), which was delivered to ACER, who recommended it for adoption by the
EC. Some ancillary services are to be provided by offshore renewables following national grid codes.
Why: National grid codes for ancillary service provisions for offshore renewables can differ. When offshore
renewables are connected to multiple countries in an offshore grid, these rules should be aligned to ensure
compliance of renewable operation with the grid codes of the different connected countries.
139
(ACER, 2020)
140
(PwC, 2016)
141
(3E and Project Partners, 2015)
142
(PwC, 2016)

3 (Aligned) renewable What: Development of offshore renewables—in particular, starting the scale up of offshore renewables Strong
energy support developments in the Mediterranean—would benefit from appropriate support scheme design and support
schemes and support allocation mechanisms. Support could be important to strengthen the business case of offshore renewables.
allocation mechanisms Several types of support schemes exist, including feed-in tariffs, feed-in premiums, contracts for difference,
or quotas with green certificates.143,144 Other state support is also possible, such as subsidies or tax
incentives. Levels of state support will depend on the ambition level of the targets of each state and
technology cost learning curves among other factors and can be awarded in a technology-neutral or
technology-specific context. There is a clear trend towards auctioning of support for renewables in Europe;
the EU State Aid guidelines mandate that energy subsidies are granted through competitive bidding
processes from 2017.145
Why: Discrepancies in the level of support for offshore renewable technologies and in the support scheme
design and allocation mechanisms between countries might hinder optimised development of renewables
and an offshore grid in the region. Developers might be incentivised to develop in markets with the highest
level of support (combined with lower grid connection costs; see Cost level barriers) rather than
developing in sites with the overall highest renewable potential. Furthermore, this approach might result in
some countries not meeting their RES targets.
In addition, rules around support allocation mechanisms for renewable generation often specify the
requirement of feeding in renewable energy to the market to receive the support available in that market.146
This should be aligned and defined for an offshore grid with joint or hybrid projects, where it could become
unclear if and what type of support would apply for a renewable asset (i.e., policy uncertainty hampers
developments). In addition, for hybrid projects, the possibility exists that renewable generation units could
receive multiple support streams leading to over-subsidising and hampering of international strategies.
Alignment should occur on a region-specific level to facilitate the development of an offshore grid in the
Mediterranean.
143
(RES Legal, 2020)
144
(CEER, 2018)
145
Communication from the Commission, 2014. Guidelines on State aid for environmental protection and energy 2014-2020 (2014/C 200/01). https://eur-
lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A52014XC0628%2801%29
146
(PROMOTioN, 2019c; PROMOTioN, 2019a)

Offshore grid operation
1 Aligned priority What: Renewables Directive 2009/28/EC (Article 16) specifies priority dispatch for renewable energy under Moderate
dispatch regulation for certain conditions.147,148,149 This priority dispatch for renewable energy over conventional fossil-fuel based
offshore renewable energy is adopted in some countries in the Mediterranean.150 Priority dispatch depends on the location of the
energy congestion in the grid. In an offshore grid, this situation might not apply due to only offshore renewable
electricity being exported to the onshore areas, and congestions might occur in the onshore grid requiring
curtailment of onshore renewable generators.151
Why: A framework is required for curtailment of offshore renewable energy connected to an offshore grid
but located in different countries. Compensation for curtailment might differ between countries—potentially
part of the support conditions. If offshore renewables are only seen to be part of the market they are
located in, this barrier is minimal.152
2 Alignment on What: An offshore grid not only connects offshore renewable energy plants to shore but also increases Moderate
cross-border CACM in interconnection (cross-border capacity) between countries (hybrid function) that might not be connected yet
offshore grid operation through point-to-point interconnectors.153 National and regional rules are required for cross-border CACM.
The European Guideline on CACM defines the methodology to determine what part of interconnector
capacity can be used by the market while ensuring measures for secure network operation. In addition, it
provides harmonisation on cross-border markets on a European level (auction type implicit/explicit, flow
based). This is of major importance to facilitate the European single electricity market. 154 The 2019 recast of
the European Electricity Market Regulation (EU) 943/2019 (Art 16, 8b) stipulates that at least 70% of the
physical capacity of each interconnector must be used for cross-zonal trade. Congestions can also occur in
the offshore grid with a hybrid function requiring part of the capacity to be reserved for the transport of
offshore renewable electricity to shore and part for cross-border exchange, which might challenge this
regulation.
Why: Regulations are already in place for point-to-point interconnectors but not for hybrid projects and
meshed offshore assets. Hybrid functions of an offshore grid are not yet aligned with the EU regulation
2009/714, which stipulates that interconnector capacity needs to be allocated without discrimination while
offshore renewable generators need guaranteed output injection in the offshore grid.155 Therefore, sizing of
hybrid interconnectors poses a challenge due to the balance between interconnection and renewable
connection functions.
147
148
(RES Legal, 2020)
149
(Emissions-EUETS, 2020)
150
(RES Legal, 2020)
151
(PwC, 2016)
152
(PwC, 2016)
153
(PROMOTioN, 2019c)
154
(ENTSO-E, 2018b)

3 Regional offshore grid What: To ensure optimal operation and adequacy of an offshore grid, a joint maintenance and repair Moderate
maintenance strategy strategy needs to be developed.156 This includes determining the responsible parties, funding sources,
frequency, and infrastructure required to perform maintenance and contract maintenance operators.
Why: Without joint strategy for an offshore grid, costs might not be optimised, higher levels of forced
outages of equipment could occur, and delays in repair activities could take place since there is no clear
allocation of responsibilities and cost.157
Administrative/governance process
1 Development of What: The Marine Spatial Planning (MSP) Directive obliges all coastal EU member states to develop an MSP Moderate
national and joint by March 31, 2021.158 MSPs will have different levels of enforceability and different formats following general
regional marine spatial guidelines in the directive. MSP is defined in the directive as “a process by which the relevant member
plan and integrated state’s authorities analyse and organise human activities in marine areas to achieve ecological, economic,
coastal zone and social objectives.”159 It is “aimed at promoting the sustainable growth of maritime economies, the
management sustainable development of marine areas, and the sustainable use of marine resources.” The MSP includes
an integrated approach, including multiple sectors. On an EU level, there is also an Integrated Maritime
Policy.160
Why: Currently the coastal member states of the Mediterranean are in different phases of developing their
MSP. In addition, member states can freely decide on the format, content, and level of legal enforceability
(e.g., binding, non-binding vision, strategies, guidelines161). This scenario could delay or hinder the
development of offshore grid infrastructure or offshore renewables in the region. In addition, there should
be alignment on the development of marine offshore energy and the allocation and use of high potential
renewable sites. Harmonisation and alignment of MSPs between Mediterranean member states could more
readily facilitate regional cooperation for offshore grid developments.
155
(PwC, 2016)
156
157
158
(European MSP Platform, 2018a)
159
(European Commission, 2014)
160
(European Commission, 2020a)
161
(European MSP Platform, 2018a)

2 Alignment of licensing, What: Offshore renewable energy developers need to obtain appropriate permits, licences, and leases by Moderate
permitting, and the relevant state bodies to develop their projects. Consenting procedures include a timeline and process for
consenting procedures applications and are typically in the form of open-door policies (open applications), application rounds, or
for development of competitive tenders.162
offshore renewable Why: Consenting procedures can present a high level of complexity for developers due to a high number of
energy permitting and licensing applications with different state bodies and unclear application and award timelines.
Offshore renewable energy consenting procedures are not yet defined for each member state in the
Mediterranean and not regionally aligned in terms of process and lead times. This situation introduces
uncertainty for developers due to varying application timelines, processes, and complexity levels between
countries.163 These challenges decrease developer confidence in the market and could hamper the
development of renewable and joint projects in addition to optimised and timely development of offshore
renewable energy in the region.
3 Legislative issues on a What: Developments in the offshore area require involved stakeholders such as the TSOs to have the Strong
national level to clarify mandate (legal status) to start developing transmission system infrastructure in the offshore area, including
mandates for offshore the EEZ. National legislative frameworks should be adapted to new practices and users.
grid development by Why: Bureaucratic and legislative issues and complexity can introduce uncertainty for developers, TSOs,
the national TSO and other stakeholders, which might delay the development of an offshore grid.
4 Regulatory framework What: The Mediterranean includes many islands, some of them grid connected and others non- Strong
for islands on a interconnected. Islands can experience seasonal demand patterns due to high influxes of tourists over the
national and regional summer.164 Some islands use specific tax relief for fossil fuels to ensure security of supply or restrictions for
level regarding the development of larger-scale renewable generation due to insufficient demand.165,166 These regulations
renewables and fossil often differ from national regulations and regulations on other islands in the region.
fuel support Why: To optimise renewable energy development in the region, islands can play a critical role in the
Mediterranean area due to their high potential for solar PV (high solar irradiation). Support for fossil fuels or
restrictions on renewable energy developments can hamper the optimal development of renewables on
islands. It can also hinder the development of interconnections between islands that have a high potential
for RES development and low population densities, islands with higher population densities and less RES
potential, or with the mainland. Increased interconnections could increase sharing of renewable energy in
the region. Therefore, ensuring appropriate and more aligned regulatory frameworks on islands in the
Mediterranean remains important.
162
(WindEurope, 2019c; Simas, 2015); (PwC, 2016)
163
(WindEurope, 2019d); (PwC, 2016)
164
165
166
(RES Legal, 2020)

5 Jurisdictional What: Member states have jurisdiction in their territorial sea. Beyond the territorial sea in the EEZ, member Strong
definition regarding states have jurisdiction for economic exploitation.167 Jurisdiction needs to be established in the EEZ
grid development regarding the development of grid infrastructure such as interconnectors.
within EEZs Why: Without legislation for grid development in the EEZ, offshore grid development will not be easily
facilitated.
Cost allocation
1 Aligned grid What: Grid connection costs are the costs paid by grid users to obtain and maintain a grid connection.168 Moderate
charges/grid Across Europe, these costs are often carried by the developer applying for a grid connection. The charge can
connection costs for be based on the capacity of the connection (per MW) or on the injection (per MWh).
renewable generation Why: Discrepancies in the level of grid charges for offshore renewable technologies between countries could
units hinder the optimised development of renewables in the region or distort site selection. Developers might be
incentivised to develop generation in those markets with the lower grid connection costs rather than
developing in the overall highest renewable potential sites. This approach might result in some countries
with higher charges not meeting their RES targets or congestions for renewable feed-in markets with lower
charges resulting in possible curtailment.
167
(PROMOTioN, 2017a)
168
(WindEurope, 2019d); (PwC, 2016)

2 Cross-border cost What: An offshore grid not only increases connections between countries but also connects offshore Strong
allocation (CBCA) renewable energy generation units. It could contribute to increasing societal benefits in the region, not only
method for offshore to all directly connected countries (through price convergence, reduction of CO2 emissions169) but also to
grid infrastructure countries removed in the first and second degree from the sea and possibly further. The development of an
(cost-benefit sharing) offshore grid of offshore hybrid projects comes with a high investment and O&M cost. Transmission
infrastructure between countries could qualify as projects of common interest (PCI) on a European level if
they bring benefits to multiple countries and help to integrate the European electricity market. PCI projects
could receive funding from the Connecting Europe Facility fund.170 The remaining costs are carried by the
respective countries relative to the benefits they obtain (For TEN-E projects CBCA rules exist171). For
offshore grids with hybrid infrastructure, there is currently no clear methodology to allocate costs to the
respective stakeholders.172 On a regional level, Med-TSO published preliminary criteria for the
implementation of a CBCA process in April 2020. 173
Why: Hybrid infrastructure such as offshore grids bring multiple benefits beyond increasing market
integration (connecting renewables).174 Without frameworks for cost sharing, the offshore grid in the
Mediterranean would face a development barrier. Current rules stipulate that countries receiving a
“significant positive net benefit”175 of a project should contribute to the costs.176 However, in an offshore grid
system, there might be a case where benefits are spread out between countries, resulting in a few countries
bearing all costs. The current methodology thus requires adaptation.
169
(ENTSO-E, 2018d)
170
(INEA, 2020; European Commission, 2020b; ACER, 2020)
171
(WindEurope, 2019d)
172
(PROMOTioN, 2019a)
173
MedTSO, 2020. Med-TSO defines preliminary criteria for the implementation of a Cross Border Cost Allocation process. Deliverable 4.2 “Procedure for Cross Border Cost
Allocation Application”. https://www.med-tso.com/publications/Deliverable_4.2_Procedure_for_Cross_Border_Cost_Allocation_Application.pdf
174
(WindEurope, 2019d)
175
Around 10%: https://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Recommendations/ACER%20Recommendation%2007-2013.pdf; PROMOTioN
176
(PROMOTioN, 2019c)

3 Cost information of What: Meshed offshore grid developments are only beginning in Europe and are mainly at early Moderate
new technologies development stages.177 Offshore grids connect countries and offshore renewable energy over longer
distances and require new technologies, such as HVDC protection devices178, to be developed and marketed.
In addition, the unique characteristics of the Mediterranean require the use of emerging technologies such
as floating wind turbines.
Why: Some novel technologies are not yet commercially produced (e.g., HVDC protection devices),
resulting in uncertainty regarding the cost evolution in the market for these components. Cost uncertainty
complicates cost estimates for offshore grid developments, and any discussions on cost sharing and revenue
requirements by involved stakeholders introduces uncertainty on the level of support required.
Financing
1 Availability and cost of What: Development of an offshore grid requires significant investments and capital to finance offshore Moderate
capital for offshore assets.179 Financing offshore assets might come at a high cost depending on the risk level of the country,
grid and renewable required returns on investment, and availability and cost of capital. Uncertainty relates to the presence of a
energy generation stable regulatory framework, the strength of the business case, or the participation of public or private
assets investors.
Why: Unavailability of and high cost of capital in a country could decrease confidence from private investors
and hamper the development of offshore assets in a country. Differences in capital cost and availability of
capital between Mediterranean countries might result in a non-optimised offshore infrastructure due to
investors focusing on countries with the lowest uncertainties to decrease perceived risks in financing
assets.180
2 Common (and sharing What: An offshore grid could encompass multiple joint infrastructure assets and potentially joint renewable Strong
of) financing energy projects. Currently, there are no standard mechanisms for financing joint offshore renewable
mechanisms/financing projects.181 For joint projects, government agencies need to define cooperation mechanisms and possibly
rules for joint offshore joint support schemes.
renewable projects Why: Rules for financing hybrid projects and joint offshore renewable projects could increase investor
confidence and ensure timely development of assets in the region rather than relying on bilateral and
case-by-case agreements.
177
PROMOTioN project, https://www.promotion-offshore.net/
178
PROMOTioN project, https://www.promotion-offshore.net/
179
(WindEurope, 2019d)
180
(Intelligent Energy Europe, 2016); (WindEurope, 2019d)
181
(PROMOTioN, 2019a)

3 Tailored and sufficient What: The development of large-scale grid infrastructure and renewable generation units in the Moderate
investment incentives Mediterranean will require significant investments. It is important that investment risks are mitigated as
for offshore grid and much as possible to ensure enough availability of capital and interest from developers.
renewables Why: One risk lies in the high levels of investment required for currently emerging technologies such as
HVDC and floating offshore. This could require targeted funding sources for growth of technologies in the
region.182
Social constraints
1 Public acceptance of What: International experience with transmission infrastructure and offshore renewable energy Strong
offshore renewable developments has shown that public opposition can significantly hinder and delay developments.183 Public
energy developments opposition from coastal communities and tourism industries in the Mediterranean area could result from
onshore landing points and the visibility of offshore renewable energy units from shore. Offshore renewable
energy is key to achieving renewable energy targets in the region due to high potential renewable energy
sites located offshore.
Why: Public acceptance is key to ensuring optimal and timely development of the offshore grid in the
Mediterranean. It is a highly touristic area, which increases risks of acceptance of coastal and visible
infrastructure.
2 Availability of skilled What: Large-scale development of an offshore grid and offshore renewable energy requires skilled technical Moderate
personnel and personnel to design, develop and construct the required infrastructure.184 The skills required relate to new
targeted training and components and technologies would necessitate new targeted training and education programs on
education programs innovation, specialised technological skills, expertise, and sharing of skills and experiences across the
region. These skills relate to the offshore wind farm value chain, the development of marine offshore energy
and offshore grids, socioeconomic assessments, laws and regulations, and energy system modelling, among
others.185
Why: Without locally available and sufficient numbers of skilled personnel, the large-scale development of
an offshore grid in the Mediterranean could be delayed. Currently, experience is being built up in the region
through experiences with subsea cable developments (e.g., TERNA ENERGY186 and RTE187). In addition,
offshore wind tenders in France will build up experience with grid connection developments of offshore wind
and floating technologies in the region.188
182
(Interreg, 2017)
183
(PROMOTioN, 2017b)
184
(Interreg, 2019)
185
(Interreg, 2019)
186
TERNA, 2019. TERNA: new Italy-Montenegro interconnection infrastructure under way. https://www.terna.it/en/media/press-releases/detail/new-Italy-Montenegro-
interconnection-infrastructure-under-way
187
RTE, 2020. Tous nos projects. https://www.rte-france.com/projets/nos-projets
188
RTE, 2020. Tous nos projects. https://www.rte-france.com/projets/nos-projets

Environmental constraints
1 Environmental What: Environmental protection areas in the offshore area are marine areas with restrictions for the Moderate
protection areas protection of unique and rare habitats of marine fauna and flora. Protected nature areas are included in the
limiting exploitation of MSPs of each country, nationally designated, and also defined on a European level (Natura 2000189).
full RES potential Why: Designated environmental protection areas could reduce high potential RES production areas by
prohibiting any developments. These protection areas include current environmental protection areas and
potential designated environmental protection areas.
2 RES development What: The Mediterranean Sea area encompasses strategic bird migrating routes, mainly twice a year traffic Moderate
restrictions due to on the African-Eurasian route.190
impact on animal Why: Bird migration routes specific to the Mediterranean could be impacted by large-scale development of
migration routes offshore wind farms on the routes.
3 Understanding What: Large-scale developments and potential decommissioning of grid infrastructure (offshore substations, Strong
cumulative seabed cables, onshore landing points, etc.) and offshore energy will impact local marine flora and fauna in
environmental impact the sea, air, and on the seabed. Research has shown that offshore developments (such as oil rigs and wind
of large-scale offshore farms) could present new habitats (local reefs) for marine fauna and flora around their bases.191 If hub
grid infrastructure solutions were part of the offshore grid, these could provide new resting and breeding areas for birds and
other animals.
Why: The full extent of the cumulative environmental impact from the development to decommissioning of
an offshore grid and renewable energy assets in the Mediterranean region is not yet understood. Knowledge
of the impact’s extent would ensure developments balance protection of marine flora and fauna with
offshore renewable energy developments and create buy-in from NGOs and the broader public.
189
(European Commission, 2020c)
190
(Birdlife International., 2009)
191
(PROMOTioN, 2019b; Renewables Grid Initiative, 2020; Arvesen et al., 2014)
Appendix E. Stakeholder engagement

To provide additional value, this study has actively engaged stakeholders in the region on
several levels:
 By consulting the Advisory Board on the progress of work

 By developing the stakeholder survey
 By consulting with national grid experts regarding proposed grid solutions
 By holding a stakeholder consultation webinar
 By gathering comments from the second interim report from the stakeholder
consultation participants
 By presenting the conference results in the final conference and external conferences
E.1 Advisory Board

The Advisory Board consisted of the following experts presented in Table E-1.
Table E-1: Advisory Board

# Name Position Organization Country
1 Nikos Hatziargyriou Professor Division of Electric Power Greece
School of Electrical and Computer

Engineering
National Technical University of Athens
2 Angelo Ferrante Secretary Med-TSO Italy

General
3 Kostas Komninos General DAFNI–Network of Sustainable Greek Islands Greece

Manager
The Advisory Board verified this study’s approach and provided a high-level overview of the
draft results of the study. Three webinars were held to discuss the work progress:
 Webinar 1: Discussing the detailed approach to work before finalizing the inception
report
 Webinar 2: Initial conclusions from Tasks 1 and 2 and verification of the approach for
Tasks 3 and 4
 Webinar 3: Draft recommendations
The Advisory Board members will also participate as panellists in the final conference.
E.2 Stakeholder survey

This survey aimed at verifying this study’s view on key challenges and implementation barriers
for the development of an offshore grid and offshore renewables in the Mediterranean, as
presented in the Longlist of barriers. Table E-2 presents the list of interviewees for the barriers
and challenges overview.
Table E-2: Stakeholder interview participants

# Last Name First Name Organization
1 Ozkoc Hasan MedReg
2 Pineda Iván WindEurope
3 Collombet Rémi Ocean Energy
4 Schroeder Robert ENTSO-E
E.3 Stakeholder webinar

The authors of this study prepared an online stakeholder webinar, where they presented the
draft results of the study. The list of participants is presented in Table E-3.
Table E-3: Stakeholder webinar participants

1 Abedrabbo Mudar KU Leuven
2 Airoldi Davide Ricerca sul Sistema Energetico
3 Akbas Tunahan EKOsinerji
4 Alagialoglou Nikolaos Copenhagen Offshore Partners
5 Ayuso Juan Ramon IDAE
6 Bakker Wessel DNV GL
7 Bates Charlotte Commission de Régulation de l'Energie
8 Bennani Smail EBRD
9 Biller Tobias Ørsted
10 Blanco Lucía Miteco
11 Bordenave Thomas EOLFI
12 Breyton Juliette Schneider Electric
13 Capaldi Romain Guidehouse
14 Capra Marcello Italian Ministry of Economic Development
15 Cecchinato Mattia WindEurope
16 Chomo Adam Energy & Water Agency
17 Ciglar Julien AD’OCC, the Regional Economic Development

Agency
19 De Diego Carmen EDPR
20 Demmer Michael DG ENER
21 D'Innocenzo Wolfgang Permanent Representation of Italy to the EU
22 Durand Hermine Government of France
23 Fernández Manuel EDPR Offshore
24 Fitton Jeremy SkyLifter
25 Fonseca Manuela Directorate General for Energy and Geology
26 Fonseca Manuela Directorate General for Energy and Geology

27 Foucher Maud Government of France
28 Francis Adam James Ørsted
29 Frosin Sorin Melita TransGas
30 Gaeta Maria Ricerca sul Sistema Energetico
31 Galea Therese Government of Malta
32 García Fatima Ministry for the Ecological Transition and

Demographic Challenge
33 Garofalo Elisabetta Ricerca sul Sistema Energetico
34 Gaspar Miklos European Commission
35 Graham Shannon Guidehouse
36 Grosaru Alex Cathie
37 Hanif Adil EBRD
38 Hatziargyriou Nikos NTUA
39 Jimenez Maria Government of Croatia
40 Jukić Vjekoslav Ministry of Environment and Energy
41 Komninos Kostas DAFNI Network of Sustainable Greek Islands
43 Krönert Frank Sweco
44 L'Abbate Angelo RSE S.p.A
45 Lahdo Georgina Cyprian Ministry of Energy, Commerce,

Industry & Tourism.
46 Lampasona Alberto Europacable
47 Laugier Romain WWF European Policy Office
48 Lauri Sandro Government of Malta
49 Lindroth Simon Sweco
50 Logothetis Georgios Ministry of Economy and Development
51 López Ocón Carmen IDAE
52 Lundholm Rickard KU Leuven
53 Major Hiyaw KU Leuven
54 Maksijan Boris Government of Croatia
55 Maly Miroslav EBRD
56 Massaras Panagiotis Permanent Representation of Greece to the

EU
58 Nicolini Emilio Cathie
59 Nikou Ioanna Greek Ministry of Environment and

Energy/Executive Authority of the Partnership
Agreement, Energy Sector
60 Ozkoc Hasan MEDREG
61 Panteli Christos Permanent Representation of Cyprus to the

EU
62 Partasides George Ministry of Energy, Commerce, and Industry
63 Pineda Ivan WindEurope

64 Psaroudakis Eleftherios Ministry of Development and Investments
65 Ramaekers Lou Guidehouse
66 Ramirez Lizet WindEurope
67 Renedo Williams Ricardo ENTSO-E
68 Rundqvist Gustaf Sweco

Yeomans
69 Sannino Gianmaria ENEA
70 Sargin Okan Guidehouse
71 Spady Matthew Guidehouse Insights
72 Staschus Konstantin Guidehouse
73 Stefanoudi Aliki Ministry of Development and Investments
74 Tesniere Capucine CRE
75 Vailati Riccardo ARERA
76 Vasconcelos António Directorate General of Energy and Geology
77 Villar Lejarreta Ainhoa Guidehouse
78 Vree Barry Guidehouse
79 Wang Mian KU Leuven
80 Wendt Volker Europacable
81 Wilson Hector Carbon Trust
82 Wouters Carmen Guidehouse
83 Xuereb Michaela Government of Malta
84 Yang Li Elia
85 Zacharia Stella TERNA ENERGY
E.4 List of interviewees for grid options

The following people were interviewed to gain insight into the consequences for the
transmission grids around the Mediterranean Sea.
 Angelo Ferrante, Secretary General, Med-TSO

 Prof. Nikos Hatziargyriou from NTUA
 Dimitrios Chaniotis, ENTSO-E System Development Committee Chair
 Gro Waeraas de Saint Martin, Directrice de Programme, RTE
E.5 List of comments provided by stakeholders

Finally, comments to the second interim report were received from the following stakeholders:
 Malta Permanent Representation to the EU

 Greece Permanent Representation to the EU
 France Permanent Representation to the EU
 Italy Permanent Representation to the EU
 Spanish Permanent Representation to the EU
 Portugal Permanent Representation to the EU

 Europacable
 WindEurope
 OceanEnergy
 TERNA ENERGY
E.6 Conferences and events presenting the study results

The initiative of supporting the offshore energy and regional grid developments in the
Mediterranean region will be promoted via other key offshore energy-specific events. The
following events are proposed:
 European Sustainable Energy Week (https://eusew.eu/), Brussels, 22-26 June 2020

 Med Power 2020 (http://medpower2020.org/), 08-12.11.2020
 Floating Offshore Working Group, Wind Europe, 23.10.2020
 Global Wind Europe Summit, 1-4.12.2020
The final conference will be held online on November 12, 2020. Registration is open at
https://guidehouse.com/events/2020/11/12/offshore-power-grid-potential.
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Study on the offshore grid

potential in the Mediterranean

Contact: Miklos Gaspar

Europe Direct is a service to help you find answers

Freephone number (*):

Manuscript completed in November 2020

Luxembourg: Publications Office of the European Union, 2020

PDF ISBN 978-92-76-25336-5 doi:10. 10.2833/742284

© European Union, 2020

Directorate-General for Energy

Advisory Board contribution

 Angelo Ferrante, Secretary General, Med-TSO, Italy

Guidehouse (previously Navigant Netherlands B.V.)1 provided technical assistance to the

Potential for offshore power generation

Selected technology mix areas

Figure ES-1: Most interesting identified TMAs

Table ES-1: TMA rankings

01 Gulf of Lion 1 Low LCOE

10 South Aegean Sea 7 Close to load centre

Figure ES-2: Regional distribution of offshore generation capacity, NECP

Figure ES-3: Regional distribution of offshore generation capacity, NECP

Impact on CO2 emissions

Figure ES-5: Summary of CAPEX, RES integration, change in socioeconomic

 RES potential and development

 Impact of various bidding zone configurations in the offshore area

1.0 POTENTIAL FOR OFFSHORE POWER GENERATION

1. Offshore wind (bottom-fixed and floating technologies)

A1 Literature and Regulatory Review for Mediterranean Region

ENTSO-E TYNDP2018 ENTSO-E TYNDP2020 k m² Spatial

• Additional performance ranking criteria for potential zones A6 MWh Renewable

Technology mix areas with associated ratings €/MWh Economic

Scenario 2030 Scenario 2050 Challenges

A7 Recommendations on Potential for Offshore Power Generation

Output to Task 2 Activity w ithin Task Major External Input

Figure 1-1: Approach to Task 12

1.1 Current RES development in the Mediterranean region

Table 1-1: Current state of deployment of offshore technologies in the

Italy 05 05 06 0.559 2.8510 7 11 12

Malta 05 05 06 013 013

Portugal 8.405 14 05 8.4015 6 14

Slovenia 016 016 016 016 016

Onshore technologies on Mediterranean islands have seen a considerably greater deployment,

Table 1-2: Current state of onshore technologies in Mediterranean islands (MW)

Croatia 2 MW (Vis)19 020

Portugal N/A N/A

Location Solar PV Onshore wind

Slovenia N/A N/A

1.1.1 Capacity targets up to 2030 and beyond

Croatia 2030 No target No target No target No target No target

Croatia 2040 25 No target No target No target No target No target

Cyprus 2030 No target No target No target No target No target

Cyprus 204026 No target No target No target No target No target

France 2030 500 27

France 2040 27 1,500 28

Greece 2030 No target No target No target No target No target

Italy 2030 90029 No target30 No target No target 1231

Italy 204032 No target

Malta 2030 No target No target No target No target No target