Renewable energies and storage in small insular systems: Potential, perspectives and a case study

Renewable Energy 149 (2020) 103e114

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Renewable energies and storage in small insular systems: Potential, perspectives and a case study Agis M. Papadopoulos Process Equipment Design Laboratory, Department of Mechanical Engineering, Aristotle University Thessaloniki, GR-54124, Thessaloniki, Greece

a r t i c l e i n f o

a b s t r a c t

Article history: Received 29 October 2018 Received in revised form 24 November 2019 Accepted 9 December 2019 Available online 10 December 2019

Insular electricity systems are of importance, as the security of supply, the competitiveness and the sustainability of the islands’ populations depend on non- or weakly interconnected electrical systems. For this reason, they have until now been treated with a good degree of conservatism in relation to both the power generation technologies used and the regulatory framework applied. This, however, results in power generation costs significantly higher than those of the interconnected systems, whilst it is also linked with high local environmental burdens. However, developments in the fields of renewable energy systems technologies, of weather prediction models and of grids and micro-grids management allow today for a much more responsive and adaptive management of the insular systems than was possible only ten years ago. This is further enhanced by the progress made in electrical energy storage, which makes the autonomy of islands a realistic goal, and also a feasible one, especially for small and very small islands. It is against this background that the regulatory framework has also to be re-considered, in order to enable a fair valuation and charging of storage, of load curtailment and eventually of ensured supply and quality of electrical energy. All this needs to be part of the new modus operandi towards decarbonized and sustainable insular communities. © 2019 Elsevier Ltd. All rights reserved.

Keywords: Insular systems Renewables Storage Optimization Regulation

1. Introduction Electricity markets have undergone a long, and not always frictionless, transformation from the vertically integrated, state monopolies of the 1960s and 1970s to the unbundled, unified, competitive European market of the last 20 years. Still, insular electricity systems have been by and large exempted from this development, without any real market operations taking place, apart from the single-buyer’s model applying to Renewable Energy Sources (RES) systems. This exemption was, and not without a cause, justified by the necessity to ensure security of supply and reasonable energy prices in systems that are usually small, with strong seasonal variation of demand due to tourism and with a generation cost that is significantly higher than the cost in interconnected areas, due to the use of oil-fired power generation plants, with rather low efficiencies and high emissions. This problem is further exacerbated by the necessity to transport the oil by ship and store it locally. RES are therefore considered to be a highly

E-mail address: [email protected]. https://doi.org/10.1016/j.renene.2019.12.045 0960-1481/© 2019 Elsevier Ltd. All rights reserved.

suitable option to reduce the dependency on fossil fuels and the resulting environmental problems, since they are by and large emissions free and locally available. However, insular systems are comparatively weak and are vulnerable to steep frequency and voltage variations, a problem that becomes more important with the increased propagation of RES systems, due to their stochastic and volatile nature. This problem has been in the focus of research over the last 20 years, and is well represented in literature [1e4]. For this reason, ever since the first introduction of wind energy in the 1980s, to be followed by photovoltaics (PVs) and hybrid systems in the 2000s, limitations were introduced by the transmission system operators, to ensure the systems’ reliability and security of supply [5,6]. Still, there are developments to be taken into consideration in four main fields which can be the driving force towards establishing more flexible and predictable energy generation schemes. These developments, which will be now analysed, together with the option of storage, enable a wider propagation of RES in insular systems and also enable the establishment of a market in insular systems above a certain size. (a) The first development relates on the one hand to established RES technologies; which have matured

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and allow for higher efficiencies at reduced costs, wind generators and PVs being good examples for this [7,8]. On the other hand, it also relates to novel RES technologies, like Concentrated Solar Power systems that offer embedded storage and thus flexibility, which are being scaled down and become more cost effective [9]. (b) The second development concerns storage technologies, an area in which significant progress has been made, i.e. in most forms of storage technologies, from batteries to pneumatic storage and from fuel cells to thermo-electrical one, which makes storage much more efficient and effective on the bulk power management, on the transmission and distribution support and on the response and reserves’ service level [10,11]. (c) Micro-grids have also evolved, in form of a self-producing energy network, either integrated to the main grid or independent; and have thus proven to be a powerful ‘space’ for purchasing or selling electricity based on the needs and the production of RES and [12,13]. Finally, (d) there are developments as far as advances in short term, micro-scale weather prediction techniques and in demand side management due to the introduction of smart grids are concerned, which enable a much more responsive and adaptive management of the insular systems [14,15]. It is against this background, that the prospects of renewable energies for insular systems have to be assessed and this should be done on two levels: on the technological level, where storage is expected to provide solutions that improve the technical aspects, like the electrical system’s stability, and on the feasibility aspect, like the sizing or RES in order to minimize the value of lost loads. This paper aims therefore to provide an overview of the current situation along with the perspectives for small, non-interconnected islands (Section 2), as they are determined by the development in renewable energy systems and in energy storage technologies. A case study for the small Greek island Amorgos demonstrates the potential for optimizing the RES production with respect to the storage use (Section 3.2): Efficient storage is necessary in order to keep the installed RES power within reasonable limits, when striving for a renewable share of more than 85%. Section 4 discusses the changes needed in the regulatory framework, as storage conventional power generation capacities and this has to be mirrored in the financial terms of operation. These aspects are examined in the following sections, without neglecting the impact of microgrids or of hybrid energy systems, which, however, are beyond the scope of the present paper. 2. Insular energy systems Not interconnected, insular electrical systems are usually categorized on the basis of the maximum peak demand and the cumulative annual energy consumption. A quite broad range of values can be met in the literature, but a quite common categorization is in four main groups as referred to in Table 1 [1]: The discussion will now focus on the biggest noninterconnected European islands, or island groups, their electrical systems features and also their use of RES for electricity generation. The first of these islands with the biggest not interconnected insular system in Europe is Cyprus, and it is characterized by a peak demand of 1.090 MW and an annual consumption of 4.4 TWh in

Table 1 Categories of islands with respect to their electrical demand and consumption. Islands

Maximum peak demand [MW]

Consumption [GWh/a]

Very small Small Medium Big

1 5 35 more than 35

2 15 100 more than 100

2017. Cyprus has the highest per capita installed capacity of solar thermal systems (approx. 0.8 m2/capita); renewables account for some 11% of the overall electricity production, with 167.5 MW of wind power and 113 MW of PVs. PVs are on the rise, expected to reach 280 MW by 2020. The 13% (RES) goal for 2020 is hence set to be achieved by all these sources, which in 2016 accounted for almost 9% of electricity production, with wind farms alone generating almost 55% of RES electricity [16]. Another important island in this category is Crete which had in 2016 a peak demand of 645 MW and an annual consumption of 2.9 TWh. Some 200 MW οf wind power and 79 MW of PVs account for approximately 23.5% of the overall electricity consumption [17]. The long-discussed project’s implementation of interconnecting Crete to the Greek mainland has been formally announced for the year 2021. It is intended to be part of the Euroasia interconnector, still in the planning stage, which will link Israel, Cyprus and Crete to the Greek mainland. This quite impressive project, that links the Exclusive Economic Zones of 4 countries, foresees a 1,518 km long, 2,000 MW DC interconnection, as it is depicted in Fig. 1. A first stage foresees an initial transmission capacity of 1,000 MW, with a budget of 3.5 bn V, that should be completed by the end of 2021. A second stage, of another 1,000 МW, is planned to be completed by the mid-2020s [16]. This interconnection will enable the utilization of Israel’s significant thermal power plant generation capacities and solar potential, Cyprus’ abundant solar potential and Crete’s solar and wind potential. It will make possible the linking of the three insular systems (Israel being an isolated electrical system in that sense) with the European mainland, in this case the mainland of Greece, providing the much-needed security of energy supply for all partners and enabling a much better utilization of renewable and conventional power generation systems. The project is in the final stage of finalizing contractual and financing issues and its first stage is expected to be completed by the end of 2021 [18]. Another case of a big not-interconnected island used to be that of Malta, which was until 2015 the third biggest not-interconnected island in Europe with a peak demand of 495 MW and a consumption of 2.1 TWh and 5.6% of the electricity was generated from RES [20]. At the beginning of 2015 an interconnection of 200 MW/ 220 kV has been set up to Sicily, hence Malta is technically and regulatory not an insular system anymore [21]. Similarly to Malta, Sardinia and Corsica, islands with fairly big electrical systems (1,850 and 434 MW respectively), are also interconnected with each other and with Italy, by means of the SARCO and SARCOI interconnectors [22]. As are the Balearic Islands, with more than 1,950 MW of demand, which are interconnected to mainland Spain [23]. The Spanish Canary Islands in the Atlantic Ocean present a different type of problem: Tenerife and Gran Canaria have peak demand values close to those of Cyprus, namely approximately 1,100 MW each island, albeit with a lower consumption, approximately 3.6 TWh each island. Together with the smaller islands of Lanzarote, La Palma, Fuerteventura, El Hiero and La Gomera, they form two electrical systems with a total capacity of 3,050 MW and an overall consumption of 9.1 TWh [22]. Lanzarote and Fuerteventura are connected to each other, the interconnection of Tenerife and La Gomera has been approved and the one between Fuerteventura and Gran Canaria is still under consideration. The main features of the Canaries’ electrical systems are depicted in Fig. 2. A series of studies have been carried out, with the overall goal to maximize the utilization of RES potential, mainly the abundant wind and the very significant solar potential, aiming to make the Canaries independent of fossil fuels by 2050 [24]. Given the

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Fig. 1. Euroasia interconnector between Israel, Cyprus, Crete and mainland Greece [19].

Fig. 2. Main electrical features of the Canary Islands [25].

distance of the Canary Islands to Spanish mainland, an interconnection is not possible. It is therefore evident that the goal of fossil fuel free Canaries cannot be achieved without a sophisticated Electrical Energy Storage (EES) system, which will a series of technologies on the levels of power generation, transmission and use. Focusing on the other end of the scale, and at the same time on the other end of the Mediterranean, namely in the Aegean, one cannot fail to notice that Greece has the highest number of islands in Europe, almost 6,000, out of which 117 are inhabited [26]. The non-interconnected islands, which are depicted in Fig. 3, host approximately 15% of the Greek population, namely 1.5 mn people, and account for 14% of the total electricity consumption. What is more important, however, is that those islands host millions of tourists every year (more than 17.5 million tourists in 2017) [27], a fact that leads to an extremely high seasonal variation of demand and consumption, is a challenge in terms of coping with the demand during the summer peak and leads to significant costs

that have to be dealt as services of general interest. The noninterconnected system of Greece consists of 13 medium islands, forming 12 energy systems (the islands of Kos and Kalymnos being interconnected), 18 small and 10 very small islands and island groups [28]. In medium islands, like Samos, Chios or Lemnos, peak demand values vary(10 and 50 MW), whilsttypical small islands, like Kythnos, Amorgos and Astypalaia, have peak demand values of between 3 and 5 MW and respective annual energy consumption values (5 GWh and 10 GWh). Typical very small islands, like Agathonisi, Anafi, Antikithira or Donousa, have significantly lower peak demand (0.1e1 MW) and respectively smaller annual energy consumption values (500 and 1500 MWh). The average full cost of the thermal power plant generation varies between 100 and 500 V/MWh, whilst the average variable generation cost lies between 40 and 350 V/MWh. Typical very small islands, like Agathonisi, Anafi, Antikithira or Donousa, have peak demand values of 0.5e1 MW and annual energy

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Fig. 3. Interconnected and not interconnected Greek islands [28].

consumption values of between 50 and 100 MWh. The average full cost of the thermal power plant generation varies between 1,050 (Anafi) and 2,985 (for Agathonisi) V/MWh, whilst the total variable generation cost varies between 245 (for Agathonisi) and 400 V/MWh (for Antikithira) [29]. The average full generation cost is so high because, it is reflecting capital cost, amortization, reasonable return on investment for the company and in addition all fixed and variable operational cost parameters. It is determined in accordance to Decision 14/2014 by the Regulatory Authority for Energy, ex-post on a monthly base and it is meant to reflect to real full cost that burdens the system’s operator for which the operator has to be remunerated by means of the Public Services charge. In those small and very small islands more reserve capacities are required than in the interconnected system, for obvious reasons of the system’s security, a condition that leads to very high energy generation costs. It is also quite evident that in such small systems there is no real possibility for an electricity market, at least not in the usual ways of a market pool, let alone of a power exchange such as in the interconnected system, where capacity-based support measures tend to reduce the impact of renewables on electricity prices and therefore maximize their market values. This is especially true for systems with high ‘must-run’ requirements such as insular systems, where market-oriented support schemes become ineffective, in contrast to systems with increased flexibility, where the integration of renewables is easier, and requires more marketoriented support schemes [30,31]. Renewable energy systems appear to be ideal options given the outstanding wind and solar energy potential. A recent study of the National Observatory of Athens [16] demonstrated that available

wind potential in the Cyclades is in all islands above of 400 W/m2 at 50 m height and on average around 500 W/m2, as can be seen in Fig. 4. The annual total solar radiation on the horizontal is for the same region on average at around 1,780 kWh/m2 (Fig. 5) [32]. However, the non-dispatchable and interruptible nature of RES based energy generation leads to problems for the conventional power plants’ operation and electrical system’s stability, problems that aggravate with increasing penetration of RES. Furthermore, given that space in the small islands is limited and precious, and that visual and aesthetical reasons are of high importance in touristic destinations, public opinion is not always favourable of large RES systems, let alone of the expansion of conventional power plants [34]. Interconnection of the islands to the main grid is therefore considered as the single and most important step to address the triple problem of security of energy supply, of enabling the utilization of RES and of ensuring reasonable energy provision costs for the islands. It is in the light of this necessity, that the interconnection project of the 12 biggest Cycladic islands to the Greek mainland, as depicted in Fig. 6, was launched in early 2018 and is expected to be completed by the summer of 2020. It is a complex project, planned to be completed in three stages: Stage A includes the connection of Syros Island with Lavrion (mainland) as well as with the islands of Paros, Mykonos and Tinos. Stage B consists of the connection of Paros with Naxos and then of Naxos with Mykonos. Finally, stage C includes the second interconnection between Lavrion (mainland) and Syros island. The project’s budget is close to 389 mn V, with a public expenditure of 176 mn V and co-funding by the European Regional Development Fund [35].

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Fig. 4. Wind potential in the Aegean at 50 m height, in W/m2 [33].

Fig. 6. Interconnection of the Cycladic islands [35].

the art storage technologies seem to provide a sound way to fulfil such requirements. Fig. 5. Annual solar radiation on the horizontal in the Cyclades, in kWh/m2 [32].

Still, even after the accomplishment of this ambitious project, there will still be more than 90 small and very small islands in the Aegean, that will remain without interconnection, but which still need to fulfill the requirements for sustainable and secure energy supply. And it is precisely for these insular systems, which state of

3. Storage strategies and technologies and their implementation Storage is probably the single most important game-changer with respect to renewable energy generation, both in interconnected and, even more so, in insular systems. For both cases, a strategic plan has to consider following issues: (a) the balance between conventional and renewable technologies considering the

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stability of the system, (b) the optimal utilization of resources, (c) the flexible and feasible function of the market and (d) the smooth and effective operation of the energy market taking into consideration other critical issues like water supply [36,37]. There are three main strategies, and respectively levels of storage, which determine both the technologies that have to be used and the regulatory framework that applies [38]: (i) Grid-scale integration of renewable power Energy storage is used to smoothen the output from wind- and PV systems. It reduces the variability of generated power at a given moment, which is of particular importance for small insular systems. It can also provide the reserves needed for ‘dark and calm’ periods when neither wind- nor PV-systems are providing energy. Energy storage is therefore a crucial part of any effort to minimize the use of conventional power generation. It acts as a bulk power management tool, whilst it also supports the transmission and distribution system. This type of storage falls within the responsibility of the grid regulator; as a rule, this is the Transmission System Operator. (ii) Frequency regulation Storage systems are particularly well suited for the regulation of frequency, because of their rapid response time and the ability to charge and discharge efficiently. This use is vital for small insular systems, as such regulation has otherwise to be achieved by means of conventional power plants. Energy storage is used in this case to ensure the level of demand and quality of power supply. This type of storage falls within the responsibility either of the Transmission or of the Distribution System Operator, depending on the level at which frequency regulation is applied. (iii) Reserve and response services This approach can apply either to end use demand management or to small-scale end use storage. In the former case, when peak and off-peak tariffs apply, as is the case for middle tension tariffs in the commercial sector (hotels, big retail stores etc.), energy storage can be used to cut peak consumption and hence reduce energy costs. Energy storage is used in this case as a tool to optimize the energy management of the end user; it provides reserve and respond services. In the latter case, the small-scale end use storage at a building’s level is appealing mainly as a combination of electrical storage and PV-systems, as it can thus cover the energy requirement during the dark hours of the day, without imposing loads to the island’s electrical system. There are also hybrid storage strategies (electrical-thermal combinations), but in any case, the feasibility of storage on the final user’s level depends on market and regulatory conditions, that determine the cost and the value of storage.

which it is rated. A series of studies, mainly in the 2000s, addressed the storage potential optimization by adopting an arbitrary energy to power capacity ratio. This, however, has proven not to lead to the optimal sizing of the storage systems, so contemporary studies use linear optimization or even heuristic models [39,40]. The range of current available storage technologies for use in power grids includes:
mechanical systems, namely pumped hydroelectric (PH), compressed air energy storage systems (CAES) and flywheels (FW);
thermal systems, namely cryogenic electrical systems (CES)
hydrogen related systems, namely fuel cells (FC);
electrical systems, namely capacitors (CAP), high energy or high power super-capacitors (EDLC), and superconducting magnetic energy storage (SMES);
Electrochemical systems, i.e. batteries, namely lead acid (LA), nickelecadmium (NiCd), lithium-ion (Li-ion), sodium-sulfur (NaS), sodium nickel chloride (ZEBRA), zinc-bromine (ZnBr), polysulfide bromide (PSB), and vanadium redox (VR). The available energy storage technologies are depicted in Fig. 7, and, as can be seen, their power rating varies from a few hundred W up to 1 GW and the discharge time at their rated power from milliseconds to some hours. For the order of magnitude of 1 MW, pumped hydropower and compressed air energy storage would be the most feasible options [42,43]. Considering, however, the fact that in the small and very small islands the power generation is not expected to exceed the 10 MW limit, and keeping also in mind that water is a rather scarce resource in most Aegean islands, batteries, either conventional or flow ones, appear to be the most reasonable choice. They offer fairly low purchase and maintenance costs and deliver stable voltage under discharge; they do require precise electronic control and switching equipment, but this is not an issue for contemporary control systems [45]. A detailed study for the Levelized Cost of the various energy storage technologies, depending on the application, is provided in a detailed study by Lazard [44]; the key findings are summarized in the following Fig. 8. As it can be seen, for the case of providing a few hours of storage for the transmission system or as peaker replacement, Flow or Lithium-Ion batteries come up with costs of between 150 and 320 V/MWh. This cost figure strikes one as quite high, and it is, but it should be kept in mind that it is of the same order of magnitude as

3.1. Storage technologies For any of the aforementioned storage levels, one has to determine a series of technical parameters, in order to conclude to the optimal storage solution: the system’s energy and power capacity, the round-trip efficiency and the discharge time at the rated power. Energy capacity is the maximum energy a storage device can hold, whilst power capacity is the maximum rate at which energy can be transferred into and out of the device. Round trip efficiency is the ratio of output-to-input energy for a storage device throughout the charge and discharge of the device. The discharge time at the rated power refers to the time over which it can provide the power at

Fig. 7. Comparison of energy storage technologies based on application [41].

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Fig. 8. Levelized cost of storage technologies.

the average full cost, or even the average variable cost, of generation in small and very small islands, as discussed in the previous section. Surely, compared to the Value of Lost Load (VoLL), which has been estimated to range from 1,000 to 10,800 V/MWh for households and up to 26,000 V/MWh for industrial consumers in Europe, there is no comparison [45]. Furthermore, and given the increased penetration of RES, one should consider not only the cost of lost loads, which may be considered to be a case in extremis, but the much more common problem of loads curtailment that occurs when renewable systems are on purpose over-dimensioned, in order to achieve a significant contribution over periods with high demand. It is in this line of approach that storage becomes important, as it will in the following section be discussed on the basis of the case study on a Greek small island, Amorgos.

3.2. The case study of Amorgos island A case study on optimizing storage with respect penetration was carried out, focusing on the small island of Amorgos, located in the Aegean. It is the most eastern island of the Cyclades island group, in the center of the Aegean archipelagos, with a permanent population of 1,880 that exceeds 4,000 in July and August (Fig. 9). The island’s peak electricity demand is up to 3.1 MW and it is covered by an oil-fired power generation plant of 4.22 MW capacity; the annual electricity generation of the oil-fired power plant was approximately 9,000 MWh in 2016. 290 kW of wind generators and residential PVs produce annually some 45.6 MWh. The total generation cost of the oil-fired power plant was in 2016 446 V/MWh and the total variable cost 231 V/MWh [29]. The load curve

of the island for 2015 is depicted in Fig. 10; it becomes evident, that the peak demand almost triples from December to July, making it impossible to have a high utilization factor for any power generation system. But even during the high touristic season, the diurnal load variation is significant, reaching from a minimum of 1.4 in the early morning hours to a maximum of 3.1 MW in the late evening. A study was carried out at the Departments of Electrical and Mechanical Engineering of the Aristotle University Thessaloniki, in order to determine an optimum mixture of conventional power generation, renewable energy systems and storage, to make Amorgos as autonomous as possible [48]. To achieve this, a series of combinations were considered, consisting of oil-fired power generation, of varying capacities of wind generators and PVs, in conjunction with varying storage capacities in form of batteries, fuel cells and pumped hydro-storage plans. Amorgos is in the area of the Aegean with the highest wind potential, with average annual wind velocities of more than 8 m/s and a potential in excess of 520 W/m2 at 50 m height [33]. The average solar radiation on the horizontal level exceeds 1,750 kWh/m2 [34]. The annual distribution of both solar and wind energy is quite smooth and fits nicely with the load curves, making thus the case of renewables very appealing. Therefore, the renewable energy options considered included combinations of 3e7.5 MW of wind generators and 0.5e2.8 MW of PVs. Electrical energy storage varied from 0 to 2 MW; 3.1 MW of conventional power generation was considered as a backup option. With respect to the generation technologies, the geomorphological restrictions and the cost factors, zinc-bromide flow batteries proved to be the most suitable and cost-effective solution for the

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Fig. 9. Amorgos island in the Cyclades [29,46].

Fig. 10. Annual load curve of Amorgos in 2015 [47].

island’s demand, with a discharge capacity of 100% and an overall efficiency of the storage system of hrt ¼ 70% [48]. The investment cost features of those batteries are 2,300 V/kW and 460 V/kWh, whilst the operational costs are 7 V/kWh fixed and 0.0005 V/kWh variable operation and maintenance costs [49]. The optimization was carried out by means of a linear optimization model in the General Algebraic Modeling System (GAMS) environment and examined a series of scenarios. Its detailed presentation does not fall within the line of scope of this paper, but it is of interest to note that it focused on a minimum RES fraction of 90%, to justify the term ‘autonomous island’ and a maximum of 98%, as it was technically impossible to meet the goal of 100% on economically realistic terms. Initial investment ‘turn-key’ costs were estimated between 1,150 and 1,350 V per kW for the wind generation:

65% of the cost is due to wind generators, 15% to foundations, 10% for grid connection and 10% for planning and licensing. For the PVs the ‘turn-key’ costs were estimated between 1,400 and 1,600 V per kW of PVs, depending on the size of the systems: the panels account for 65% of the cost, 5% is due for the inverters, 15% is due to wirings, automation and controls and 15% for planning, licensing and commissioning. The operational and maintenance costs were considered to be fixed, without a variable component, at 2.8% for wind generators and 1.5% for PVs. The value of land was not taken into consideration. The investment cost of the conventional power plant was not included, since it was the same for all solutions. Within this frame, the optimum solution depends less on the initial investment but rather on the Value of Lost Load (VLL) and on the Working Average Capital Cost (WACC), as it is depicted in Fig. 11.

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Fig. 11. Sensitivity analysis of installed power and storage capacities, with respect to Value of Lost Loads [48].

The ‘Business as usual’ approach consists of a WACC rate of 7%, which is almost optimistic for the Greek economy after 9 years of deep recession, and a VLL value of no more than 0.4 V/kWh, which mirrors the power generation cost of the old and amortized current conventional power plant, without any replacement costs or externalities and, most importantly, it assumes that the conventional power plant of 3.1 MW will be in reserve, with at least one of its generation units always kept in spinning reserve, to be able to cover at any given moment 15% of the maximum demand. In this approach, one comes up with an optimum solution of 3.1 MW of wind power, 0.4 MW of PVs and no storage at all. However, annual load curtailments of more than 1,218 MWh of the renewable energy production will be inevitable, corresponding to 174% of the island’s annual consumption, and demonstrating the inefficiency of this solution. The ‘autonomous’ approach assumes a more reasonable Value of Lost Load value of 5 V/kWh as discussed in section 3 [42]. This value corresponds to an autonomous island, featuring a back-up conventional plant that will operate only on the ‘dark and calm days’, which on average for Amorgos would be no more than 12e15 days annually. In this approach, 6 MW of wind power, 3.1 MW of PVs and 1.9 MW of battery power capacity with an energy capacity of 1,140 MWh seem to be the optimum solution to cover the island’s demand. In this case, a load curtailment of only 107 MWh/year will emerge, which corresponds to 15.3% of the island’s annual consumption, a figure that is token of a much more efficient solution. The Levelized Cost of Energy for this solution over a twenty years’ period is 210 V/MWh, which is significantly lower than the total energy generation cost for 2016, which was 446 V/MWh. It is therefore evident, even from the brief presentation of the specific case study’s results, that the assessment of the Value of Lost Load determines to a great extent the feasibility of energy storage. One can therefore safely conclude, that the technical optimum of energy storage is an easier problem to solve than the economic one, as the latter aspect will determine the degree to which it is feasible to implement storage technologies. It is evident that the value of storage incorporates externalities which are currently not being captured by the regulatory framework, a point that has to be addressed in order to foster sustainable insular energy systems [50]. Therefore, it is precisely in this line of approach, that the assessment of the value and the pricing of energy storage should be part of the discussion on the regulatory framework for small islands, in order to be able to determine the ‘missing money’ in the non-interconnected insular electricity systems and to provide targeted measures. One can pursue the analysis further on a higher level of integrations, involving thermal and electrical storage being used in an interchangeable way: This would involve the use of solar thermal

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plants for power generation, the use of combined thermal and power systems in settlements and big buildings like hotels, reversible heat pumps and traditional thermal energy storage systems. Utilizing surplus electricity in ice-banks overnight, to reduce the peak air-conditioning requirements that occur in the midday, is certainly not a new technology, but to use it as an active energy storage strategy based on reliable weather and wind forecasts is a much more sophisticated way to go. Eventually, utilizing smart metering in buildings, so as to use hot water production for domestic use or for space heating as a storage option at practically no additional investment cost could be an option for existing residential buildings. Finally, the idea of using hybrid energy management and storage strategies should not be left unmentioned: The use of surplus RES generated electricity to desalinate water in Reverse Osmosis facilities, to mention one example, is an interesting option, especially for small, dry islands. All these technological options can provide electricity, heat and cooling to endusers and can be optimized as a single Distributed Energy System [51,52]. Again, the regulatory framework has to be adapted to the possibilities offered by storage technologies, in order to incentivize the building owners and/or users to utilize these possibilities. It is a complex technological, economic and social exercise, but it is the most promising way forward towards truly sustainable management of resources [53]. 4. Regulatory issues in small insular systems Even in the case of high RES penetration, small insular electrical systems will continue to be based on small thermal power plants, as a rule internal combustion engines and/or gas-turbines. Given the fact that loads are small and their seasonal variation predictable, up till now it made well sense to have two or three smaller generators in a cascade scheme and, in the case of strong seasonal variation, utilizing some additional internal combustion generators, leased and ferried to the islands to meet the peak demand of the touristic season. This provisional solution also contributed to addressing the problems of lack of space for bigger power plants, as expansion of existing plants meets public reaction. However, since the introduction of the European Directive in 2015 (EU 2015/2193 “On the limitation of emissions of certain pollutants into the air from medium combustion plants”), time is running out for such power generation constellations, as power plants have to be placed in cold reserve by 2020. Otherwise utilities, and eventually the consumer, will face significant surcharges for the increased emissions, even on small islands. Given the fact that this Directive applies to single combustion plants, or to combinations formed by two or more combustion plants, with a total rated thermal input from 1 MW and up to 50 MW, it practically covers all the islands of the Aegean, from the small ones like Amorgos, to the big ones like Crete and Rhodes [54]. The ongoing interconnection of bigger islands and of small ones close to other islands smooths out this problem, but it will not eliminate it entirely, since several islands are too far and too small to allow for interconnection to be an option. As the penetration of renewables increases, the capability of the conventional power plant to reduce its output becomes critical, as the capability of diesel generators to reduce their output becomes the critical issue. A typical diesel generator can work at a lower limit of 30e40% of its capacity. Should the RES based energy generation be higher than this, on a sunny, windy day with rather limited demand, power curtailment becomes necessary to cope with the renewable power excess in the grid [55]. Furthermore, and due to the insular systems’ lack of interconnection, large frequency variations are expected to occur. To cope with this problem a

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combination of active power reserve and storage capacities has to be maintained both for frequency regulation purposes and to ensure the system’s stability. However, this means that new grid codes must be developed, providing the framework for the advanced control capabilities needed to support those sensitive systems and, at the same time, to utilize the capabilities offered by advanced micro-grids’ technologies. What makes things more complicated, is that such insular codes cannot be addressed in a uniform way, since the differences amongst the various insular systems are significant, as it has been demonstrated in the discussion of the examples ranging from Cyprus and the Canary Islands to Amorgos and the French islands and the variations these highlight [56]. A further aspect one has to keep in mind is that, since in the case of all of the small islands the market is run on the base of the singlebuyer model, with a guaranteed feed-in-tariff, the revenue losses caused by curtailment or disconnection of the RES systems may be higher than the cost of maintaining the conventional generation. In this case the system’s operator may choose to curtail the conventional power generation part of the load, which again induces instability in the system. It is true that contemporary weather forecasting tools enable a fairly reliable prediction of wind and solar conditions. But even a detailed and reliable prediction will not obviate the necessity to curtail energy generation, if the installed capacities exceed the occurring demand [57]. The advance of aggregators is expected to extend and eventually replace the single-buyer model for bigger islands like Cyprus and Crete. It will eventually lead to the aggregation of various intermittent and stochastic renewable generation systems, like wind generators and PVs with conventional generation and with different types of reserves including electrical storage and electric vehicles, into a portfolio that will be as reliable as the dispatchable thermal power plants [58,59]. It is at this stage where energy storage becomes an even more valuable option, as it can serve the following purposes: (i) It allows the reduction of curtailment of conventional and/or generated power. (ii) It replaces services provided by the conventional generation, such as regulation or spinning reserve. (iii) It replaces the reserve/auxiliary function of conventional power generation. Defining an optimum energy storage system that meets both the energy and the power requirements in a cost-optimum way is certainly not an easy task, as it is a stochastic problem that depends strongly on the type of application, on the power rating, on the charge/discharge frequency and on the discharge time. Furthermore, electrical energy storage is undergoing a rapid technological development, which affects both the technical and the economic aspects of its application. As recent studies have shown, some storage technologies are better suited than others bulk management, whilst the same observation applied to electric bill management applications. In any case, storage can only be feasible when either a significant difference between high and low electricity prices applies, or when high peak demand charges occur [60]. Since none of this is the case in small insular systems, the current regulatory framework has to be changed to foresee some form of compensation for electrical energy storage services. There are positive developments, although they refer mostly to big insular systems: The liberalization of the electricity market, which is already the case for example in Cyprus, inevitably leads to more challenging pricing policies, which include off-peak tariffs, nighttime tariffs and, most interestingly, flexible tariffs in conjunction with smart metering [61,62]. Furthermore, electricity energy storage can be a very useful tool, since it makes it possible for big

commercial consumers to achieve price arbitrage, by shifting electricity demand from peak to off-peak periods, i.e. during the night, or whenever there is an increased wind or solar power generation. The profitability of storage in price arbitrage depends on the level of fluctuations in spot prices and the possibility to adopt an optimal strategy in charge/discharge scheduling also with respect to the own demand that needs to be covered [63]. One of the most interesting regulatory developments is the advance of energy communities, also known as community energy projects, which can play a pivotal role for storage projects, like they did for renewable energy projects in the last 15 years in Denmark, the UK or Germany [64]. Energy community projects may include two approaches, the bottom-up and the top-down one: In the former citizens establish and own renewable energy projects, whilst in the latter they are only partly involved in the project. In the top-down approach, aggregators are gradually contracting the electricity generated by individual energy producers, leading to bundled energy portfolios which reduce the overall risk taken by the producers, yet this may result in a gradual loss of the producers’ independence. The bottom-up approach is of interest, in the case of insular systems, as it allows both renewable and energy storage projects to be co-owned by citizens, thus making projects on the scale of an island community much more appealing, since the valuation of externalities can be directly monetarized for the users, who become in this way self-producers on a scale not possible until now. It is particularly encouraging, that the formal agreement on the new directive of renewable energy sources reached in the European Commission in June 2018 explicitly mentions in Article 21, Section 2, and in relation to renewable self-consumers that “Member States shall ensure that renewable self-consumers, individually or through aggregators, are entitled to: install and operate electricity storage systems combined with installations generating renewable electricity for self-consumption without liability for any double charge, including grid fees for stored electricity which remains within their premises”. In addition, in Section 52 it is further stated that “It is appropriate to allow for the development of decentralised renewable energy technologies and storage under nondiscriminatory conditions and without hampering the financing of infrastructure investments. The move towards decentralised energy production has many benefits, including the utilisation of local energy sources, increased local security of energy supply, shorter transport distances and reduced energy transmission losses. Such decentralisation also fosters community development and cohesion by providing income sources and creating jobs locally.” [65].

5. Conclusions Insular electrical systems, like those in the Mediterranean islands, the Canary and the Azores, present a challenge and an opportunity: They are pillars of the European tourism and hence present very significant load variations over the year. For decades the main concern was to ensure the security and the quality of electricity supply, a problem that was traditionally solved by providing increased power generation capacities and more reserves. This approach, however, is extremely costly and also causes significant environmental burdens on the local level, especially in the case of smaller islands. As the discussed example of Greek small

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islands shows, the full generation cost in those islands can be 2 to 10 times higher than in the interconnected system, a cost that eventually is carried by all consumers. On the other hand, both on the Mediterranean and on specific Atlantic islands, there is an abundance of renewable energy sources, which has been detected and quantified since the 1970s. However, there are very specific problems linked with the integration of renewable energy systems, the main one being the temporal mismatch between a non-dispatchable, stochastic power generation system and a periodically strongly varying demand. These problems, which are common across the cases, from big islands, like Cyprus, Crete and Malta to very small ones, like those in the Cyclades, have imposed limitations to the installed renewable energy systems, which on average cannot exceed 25e30% of an island’s peak demand. Advance in the renewable energy systems’ technology, in weather forecasting models and in grids and microgrids management can alleviate the problem, but they cannot solve it. Electrical energy storage is therefore a powerful weapon, in order to utilize renewables to an extent that will enable islands to become autonomous, or almost so, by utilizing renewables. There are many technologies of electrical energy storage and they can be used from grid-scale integration of renewable energies to response and reserve services on a consumer’s level. In recent years a series of applications, with quite impressive energy storage capacities, have been deployed in many countries, but, surprisingly, there are not many applications on a grid-scale level in islands. This is surprising, as storage can accelerate the penetration and integration of renewables, as it can store the surplus energy produced in periods of favourable conditions and then make it available to cover the demand in calm and dark hours. It can also reduce power and frequency fluctuations, replacing the traditional spinning reserve. A series of studies, one of which has been presented in this paper, have shown that storage in form of zinc bromide flow batteries can make high levels of RES penetration feasible. When used on a generation level, it reduces the need for installed capacities of wind generators and/or PVs to much more realistic levels. It thus reduces capital investment to much more affordable levels. When used on a consumer’s level, it contributes to directly reducing energy costs, by shaving off the peak demand. Pilot projects, like the TILOS, have shown that these observations apply and that it is realistic to achieve a high degree of electrical autonomy in small islands. There are, however, barriers that have to be overcome before grid-scale electricity storage facilities can become a common sight in insular systems as part of an integrated renewable energy system. The issue of financing a quite cost-intensive initial investment is not a straight-forward one, especially in times of changing electricity market regulations and despite the feasibility of such a project. What is particularly important, in order to come up with a realistic feasibility evaluation, is the assessment of Value of Lost Loads, with respect to the generation and storage cost. This is a figure that can vary significantly, depending on the economic activities and the overall financial conditions. It is of importance to notice that on small islands the average full generation cost can be very high, due to the small utilization of the systems. Linking these cost factors to the savings achieved by an optimized storage system is crucial, but it is not a straight forward exercise. It can hardly be determined by a single investor or a consumer on a microeconomic level, hence the regulator and/or the transmission system operator has not only to develop an effective yet flexible regulatory framework, but also to determine the boundary conditions, especially in the new forms of energy aggregators and energy communities that are beginning to operate. A respective guideline has therefore to be elaborated by the regulators for small and very

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