The chart in Figure 3 shows the overall installed capacity in Europe in 2019 for each aforementioned technology [1]: traditional steam plants and combined cycles are widely spread in the European Union.

—Steam plants (based on Rankine cycle), including the vast majority of coal and oil-fired plants, although few gas-fired boilers are still in operation;

Focusing on the 27 European countries in EU27, their thermal power plants can be categorized according to the type of fuel and technology. Considering fuel, the main categories identified are [4]:

According to the Eurostat database, the European Union still highly relies on conventional thermal generation for the electricity production. As shown in the following chart (Figure 1), in 2019 about 61 % of the electricity production has been generated by conventional thermal and nuclear power plants; hence, renewables were responsible for the 39 % of the total generation. As a comparison, in 2010, the renewable share was around 25 %, mainly hydropower [1].

A wider review of European energy sector is presented in the annual statistical book [3]. In [4], critical factors that influence the development of the fossil-fuel fired power generation are investigated; moreover, an updated analysis can be found in [5], where the results of a baseline scenario of the total European energy system up to 2050 are also shown. Finally, the perspective of the International Energy Agency is presented in the well-known 2020 World Energy Outlook [6].

In this chapter, the main characteristics of European thermal power stations fed by fossil fuel are described and their actual efficiency levels are analysed based on public data available from the Eurostat database [1] and by the most recent analysis reported in [2], with particular reference to coal, oil and gas thermal plants only.

Chapter 5 reports the conclusions of the assessment carried out on the potentials of each technology for what the energy efficiency is concerned. Wherever possible, a quantification of realistic saving has been performed, under simplifying assumption, showing the potential for improvements in terms of primary energy saving.

The same concept is true also for HVDC systems, dealt with in Chapter 4. HVDC transmission is not suitable to improve the efficiency of transmission systems, which is already very high (about 98%) and could be hardly increased. HVDC transmission is interesting because it makes it possible to transfer energy in conditions where HVAC systems would neither be technically nor economically affordable, and this is true in particular for subsea cables that allow the integration of wind power from large off-shore wind farms, thus resulting in an indirect saving of primary energy. In Chapter 4, the main characteristics of HVDC systems are hence described; for such systems, the operating conditions leading to best efficiency are derived and present and possible future uses in the European context are highlighted.

Regarding storage, in Chapter 3, different types of storage useful for electric systems are considered and described with reference to the maturity of technology. Details are provided for those technologies that show current and future better perspectives (hydro pumped power stations, batteries, compressed air, flywheel). It is worth noticing that it is difficult to compare directly, in terms of efficiency, storage alternatives that might be addressed to the solution of very different technical issues (in other words, one cannot use supercapacitors to deal with large amount of energy issues): each technical problem should be addressed by the proper class of storage systems; within that class, of course, the most efficient technology should be adopted. In general, storage technologies are interesting not because they allow a direct saving of primary energy, but because they make it possible to integrate energy coming from Renewable Energy Sources (RES) into power systems, thus saving primary energy indirectly.

Chapter 2 presents the results on the technology adopted and efficiency assessment in thermal power plants, with particular reference to conventional fossil fuels (coal, gas, oil) power stations. Some statistical data about efficiencies, consumptions, capacities, etc. are also shown. Current and perspective efficiency levels are described and estimates of potential primary energy savings have been determined under some assumptions related to the decarbonisation policy currently adopted.

The guideline is outlined in Article 23 (b) 13. of the revised Energy Efficiency Directive; the report is focused on three main pillars of possible energy efficiency development, namely conventional fuels, storage and High Voltage Direct Current (HVDC) transmission. Therefore, in this document, those three main technological solutions have been taken into account in the light of the energy efficiency, to identify possible savings potentially obtainable. For each topic considered, a review of current efficiency levels has been carried out, margins for improvements have been identified, and rough quantitative assessments have been made in order to estimate possible primary energy savings at European level. The document is organized as follows: first the single technological solutions have been investigated separately; then, conclusions and ranking are presented in the last Chapter.

In this Report, the results of an assessment carried out to perform research for the identification and preparation of a study evaluating the potential for energy efficiency in conversion, transformation, transmission and storage of electric energy is presented.

The revised Energy Efficiency Directive (2018/2002) in Article 23 15 (b) 13 states that “the Commission shall carry out an assessment of the potential for energy efficiency in conversion, transformation, transmission, transportation and storage of energy, and shall submit a report to the European Parliament and to the Council.” This Report presents the results of the assessment of the potential for energy efficiency in conversion, transformation, transmission and storage of electric energy. The report is focused on three main pillars of possible energy efficiency imporvements, namely conventional fuels power generation, energy storage and High Voltage Direct Current (HVDC) transmission. In this report, those three main technological solutions have been taken into account in the light of the energy efficiency, to identify possible energy savings potential. For each topic considered, a review of current efficiency levels has been carried out, margins for improvements have been identified, and simple quantitative assessments have been made in order to estimate possible primary energy savings at European level. The document is organized as follows: first the single technological solutions have been investigated separately; then, conclusions and ranking are presented in the last Chapter.

How to cite this report: Berizzi, A., Benato, R., Bosisio, A., Petrelli, M., Vicario, A., Serrenho, T., Bertoldi, P., Assessment of the potential for energy efficiency in electricity generation, transmission and storage, Publications Office of the European Union, Luxembourg, 2021, JRC125030.

The reuse policy of the European Commission is implemented by the Commission Decision 2011/833/EU of 12 December 2011 on the reuse of Commission documents (OJ L 330, 14.12.2011, p. 39). Except otherwise noted, the reuse of this document is authorised under the Creative Commons Attribution 4.0 International (CC BY 4.0) licence (https://creativecommons.org/licenses/by/4.0/). This means that reuse is allowed provided appropriate credit is given and any changes are indicated. For any use or reproduction of photos or other material that is not owned by the EU, permission must be sought directly from the copyright holders.

This publication is a Technical report by the Joint Research Centre (JRC), the European Commission’s science and knowledge service. It aims to provide evidence-based scientific support to the European policymaking process. The scientific output expressed does not imply a policy position of the European Commission. Neither the European Commission nor any person acting on behalf of the Commission is responsible for the use that might be made of this publication. For information on the methodology and quality underlying the data used in this publication for which the source is neither Eurostat nor other Commission services, users should contact the referenced source. The designations employed and the presentation of material on the maps do not imply the expression of any opinion whatsoever on the part of the European Union concerning the legal status of any country, territory, city or area or of its authorities, or concerning the delimitation of its frontiers or boundaries.

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Appendix II gives out more information on the specifications of GTs, in terms of manufacturers and possible modifications for the increase of its overall efficiency.

Gas turbine can be also fed by synthetic gas, generated by the coal gasification and combined with steam turbines. Such plants, called Integrated Gasification Combined Cycle (IGCC), can reach a higher efficiency rate than coal technologies: ICGG plants could achieve an efficiency rate higher than 45%. In a IGCC plant coal is first gasified by creating a ‘shortage’ of air/oxygen in a closed pressurised reactor, that creates a chemical reaction of the coal with the oxygen. The product from this process, a mixture of carbon and hydrogen (CO and H2), called synthesis gas or syngas or fuel gas, is cleaned and burned in a gas turbine. SO2 and NOx emissions are significantly lower than a conventional coal plant [18].

Figure 11 shows the evolution of the combined cycle efficiency over the years: the efficiency has been constantly increased thanks to the new technologies, especially in GT technology and the specific fuel consumption and CO2 emissions have significantly decreased, making this type of plants very efficient and competitive in the electricity market.

In Figure 10, bottom left, the temperature – entropy diagram of the entire cycle is shown. The global efficiency is very high, reaching the 55 – 60 %; some manufacturers have recently developed a combined cycle plant (using H-class GT Technology) with a net efficiency of 64 % [16]. Thanks to their efficiency and lower fuel consumption, compared to same-sized traditional thermal plants, in the past a lot of oil thermal plants have been dismantled and the steam turbine readapted: as a matter of fact, the pollution emissions are significantly lower, since gas fuel does not present any sulphur production (SO2) and dust; moreover, the overall plant management is simpler. The average size of these plants is in the range 380-800 MW and they can also be built with a single generator (single-shaft). In some configuration, two gas turbines can be combined with a single steam turbine for a total power of 800-1600 MW.

The HRSG consists of three major components, placed downstream to the exhaust gas flow: the economizer, that works as a preheater, the evaporator and the superheater, that converts saturated steam into dry steam. The heat exchangers are simpler, compared to traditional boilers with combustion chamber, and made of finned tubes. HRSG can present horizontal or vertical displacement and multi-pressure steam levels (high, medium and low pressure) to increase efficiency, each one arranged with an economizer, an evaporator and a superheater; reheaters are commonly used, too. The evaporator bank may present different circulating systems: natural, controlled or forced. The remaining part of the plant is very similar to the traditional steam plants. The steam turbine approximately generates half of the electrical power generated by the gas turbine.

Considering a GT like the one described in the previous subsection, its exhaust gases still have a high energy content at high temperature, around 600 °C: instead of discharging such energy to the ambient, like in OCGT, it is sent to a downstream Rankine cycle to produce steam to drive a steam turbine. That steam is therefore not produced by burning any additional fuel in a boiler but taking advantage of the heat recovered from the Brayton cycle. This arrangement is the Combined cycle (CCGT). Figure 10 shows a typical scheme of a CCGT, where a Heat Recovery Steam Generator (HRSG) is present to recover heat from the exhausted gas coming from the GT and produce steam for the Rankine cycle downstream.

The best way to improve efficiency by means of a Brayton cycle, is actually obtained combining the two cycles above-described, namely the Brayton and the Rankine cycle. The first one is characterized by high temperatures for the introduction of heat (about 1500°C) on the cycle, but also discharges heat at high temperatures (about 600°C); the second one discharges heat to the ambient at low temperature (about 30°C), but the same holds for the introduction of heat (about 5-600°C). The basic idea of the combined cycle is to combine the two cycles, in order to have a single cycle with introduction of heat at high temperatures and discharge of heat at low temperatures, which guarantee higher efficiency.

Notwithstanding such values of efficiency, OCGT are well on the market, because of their dynamic performances: OCGTs are quite compact, thanks to the reduced dimensions of the gas turbine, and they can be easily started up in few dozens of minutes. The turbine power can be adjusted controlling the gas stream or the air stream into the compressor. All such characteristics make OCGT suitable for keeping the power system security in modern power systems, and to promote the integration of renewables providing ancillary services like frequency control, fast start up, black-start capability, adding inertia and short-circuit power to the power system, etc.: they look complementary to the development of renewables, keeping power system security.

Actually, GT technology is still showing significant improvements, and it is possible that in the next future the efficiency of OCGT can further increase above 40 %. For example, aeroderivative GT can reach efficiency of 44%; however, their cost per kW is such that lower efficiency heavy-duty GT are preferred today; moreover, aeroderivative GT have higher emissions, that make it necessary to install special and expensive abatement systems.

The first two actions require significant improvements for what the materials are concerned. Inlet air cooling system and fuel heating are currently used.

Nowadays, OCGT can reach an efficiency of 38 – 40 % ( Figure 9); moreover, the generation costs are quite high, due to the high fuel costs. In order to improve efficiency of power generation GT, a few actions could be taken:

—Gas turbine: it is a three/four stage turbine, where the pressurized air-fuel mixture expands. The air-fuel mixture can reach 1400-1500 °C. Therefore, special ceramic materials and cooling systems are applied (film cooling using air from the compressor) to overcome material damage and increase efficiency.

—Combustion chamber: here the fuel is injected and burnt. Special nozzles are used to increase the efficiency of the turbine and decrease the pollution emissions, mainly carbon dioxide, CO2, and nitrogen oxides, NOx, by suitably controlling the combustion.

—Compressor: a multi-stage axial compressor that compresses the ambient air. An efficient multistage filter is always installed before the compressor, to avoid the turbine damage and deterioration. The compression ratio can vary between 16:1 and 30:1, depending on turbine requirements. Instabilities, like surging and stalling, that may affect the performance of the compressor and even damage it, can arise; hence, the fuel flow is controlled in an efficient way monitoring the air streams.

The basic Brayton cycle is made by a compression of the fluid (air), heating by means of gas combustion, expansion of hot exhaust gas and discharge. This is done arranging on the same shaft the compressor, the turbine, and the synchronous generator: the power available from the gas turbine is used to move the compressor, and the remaining power is converted to electricity. The OCGT power output and efficiency highly depend on the ambient conditions; in particular, the ambient temperature and pressure affect the maximum power, that can decrease during the summer period. So, a cooling system may be placed after the filtering stage.

A gas turbine is a fluid combustion machine which is the core of the Bryton cycle schematically depicted in Figure 8; air is the working fluid.

Natural gas can be used to fuel traditional Rankine power plants, as mentioned in previous subsections, or, alternatively, gas turbines (GT). GTs can be then used in open cycle plants (OCGT) or in combined cycle plants (CCGT).

Like oil power stations, also gas-based Rankine cycles are currently out of the market, as generation costs are even higher than oil-based generation. Few power stations of this type are still in operation, but they are typically used as reserve.

In some power stations, boilers can burn natural gas combined with the fuel oil to supply a Rankine cycle. The natural gas is essentially a mixture of methane (95.8 %), ethane (3.0 %), propane (0.5 %), butane (0.1 %) and nitrogen (0.6 %). Its energy value is 8250 kcal/Sm3 at 15 °C and 760 mmHg: the energy content of 1 m3 of natural gas corresponds to 1.2 kg of coal and 0.85 kg of fuel oil. Since natural gas cannot be stored in huge amount, its provision is guaranteed by gas pipelines connected to the gas system (at 50/60 bar) and requires a very accurate schedule. The natural gas is hence decompressed and then finally sent to the boiler, where special burners enable a homogeneous combustion.

The situation in EU is very similar since (Appendix II) gas-fuelled power plants generate about 21,53 % of the overall produced electricity. This percentage is destined to grow more and more in the future due to coal phase-out.

Natural gas is the second most important fossil fuel for generating electricity after coal (Appendix I). In 2019, it covered the 23,3 % of the total global annual electricity production.

Oil power stations are currently out of the market, as their efficiency is low (about 38-40%) and the production costs are high. Few power stations of this type are still in operation, but they are typically used as reserve.

Most of the liquid fuels used are derived from crude oil, characterized by 84 % of carbon, 12 % hydrogen and 2 % oxygen. The sulphur content may vary depending on the refinery treatment. Fuel oil type “bunker C” is usually adopted for the thermal generation, and it can be classified according to its sulphur content. Its energy value ranges from 9600 to 9800 kcal/kg. Emissions generated by the combustion of oil are the sulphur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), and they are generally managed in the same way as in coal power plants.

The Rankine cycle described in Figure 5 can be fed by oil as well. The oil is usually kept warm around 40 °C into the storage tanks, is pumped to the boiler spray nozzles and then ignited.

Appendix I shows the EU annual Production of electricity from coal (1985-2019), from 41.8% to 15.2%, which is expected to be zeroed out due to the EU coal phase-out. Also the classification of pulverized coal combustion plants in terms of steam parameters is presented.

The combination of a good efficiency and the low cost of the fuel makes this type of power plant still competitive in the electricity market. Its main drawbacks are a somehow low flexibility and the decrease of efficiency as the loading in not at its optimal values.

The efficiency of the entire plant is affected by the energy losses along the described elements and depends on the loading level. The maximum efficiency is achieved usually at the maximum generated power: lower loading implies lower efficiency due to the lower pressure and temperature compared to nominal values. Figure 6 and Figure 7 show the required developments of the material, processes and components required to increase the plant efficiency up to a theoretical 50 % efficiency. It is worth noticing that the gross power produced should be decreased by the power of auxiliary services, necessary to run the power station. Such services are particularly significant for coal plants. For example, a 660 MW group can require up to 27 MW for its continuous operation. This of course makes the overall (net) efficiency lower.

The size of a steam turbine can vary between 320 and 1300 MW; this last value can be reached with supercritical and ultra-supercritical boilers with double reheater system and cross, or also tandem, compound turbines.

The overall plant efficiency has been increasing over the years and modern coal power plants are characterised by efficiencies described in Table 1 :

Coal plants, in general, are not very suited to provide fast dynamics and ancillary services for the system. The flexibility allowed can be increased but it is not available in the basic structure of the plant. Regarding the start-up procedure, as a general indication, a 320 MW plant requires 6/8 hours of preheating operations before its synchronization with the grid, depending on the initial conditions, the most binding constraint being the heating of the steam turbine. On the contrary, in case of emergency conditions in the power system, the dynamic response to large load ramps can be very good in the first second after a significant transient, and this is a very important point for the security of the power system.

Among the huge variety of coal types, anthracite, also known as hard coal, presents the highest carbon content and fewer impurities; its energy value ranges from 7000 to 8000 kcal/kg. The most used type of coal for electricity generation is the bituminous coal. The emissions generated by the combustion of solid fuels are the sulphur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), carbon monoxide (CO) and dust. SO2, CO, dust and NOx can be nowadays managed and reduced with specific technologies (primary and secondary measures) while the handling of CO2 is still an open issue. Carbon capture storage is not yet a technology ready for a real implementation [10][11][12].

The raw coal is crushed into small pieces and then pulverized, by coal mills, into fine powder and sent to the combustion chamber. The required air flow is guaranteed by proper fans; the fuel-air mixture is hence introduced as a vortex fluid in different points of the combustion chamber though suitable burners and ignited. Fluidized bed combustion is another common technology used for boilers, as it is able to provide higher efficiency and it can also combust mixtures of fuels.

As previously mentioned, most coal power stations are based on the Rankine cycle. In such cases, the boiler is a pulverized coal-fired boiler, where the pulverized coal is burnt easily and efficiently. Pulverized coal plants can present subcritical, supercritical or ultra-supercritical boilers; these boilers can operate with different types of coal (hard coal, lignite, bituminous coal), but biomass or other materials may be added to the fuel mixture (where usually a Circulating Fluidized Bed boiler is preferred [8][9]).

As mentioned, the basic Rankine cycle can be fuelled by different types of fuels: coal, oil and gas are the most used. The efficiency is basically the same, but due to the low cost of coal, currently coal Rankine cycles are the only power plants competitive on the electricity markets. The use of gas and particularly oil for Rankine cycles is nowadays almost abandoned.

All such measures are always implemented in modern thermal power stations, as the Rankine cycle is a very mature technology. Nowadays, most actions are addressed to the control of emissions and improvement of dynamic performances to be more effective in modern electricity markets, rather than increasing of efficiency. It is worth noticing that Rankine cycles typically have a very high consumption of electrical energy to supply all auxiliary systems: pumps, fans, but also the more and more requiring system to limit emissions and pollutants. This makes the difference between gross and net electricity production very significant.

—Introduction of feedwater heaters (6-7 heaters at both LP and HP) for the feedwater, that make use of steam extracted from the turbine to heat feedwater;

In order to increase the efficiency of the Rankine cycle, it is important to make use of suitable materials, because all the following measures require it:

—Feedwater pumps: needed to increase the pressure of the feedwater and to pump it into the boiled and the turbines.

●Air cooled condensers are made up of modules are arranged in parallel rows. Each module contains a number of fin tube bundles . An axial flow forces the cooling air across the heat exchange area of the fin tubes.

●In cooling towers, the heat is ejected into the atmosphere by the partial evaporation of the water into a tower. Cooling towers are less efficient than condensers, but more efficient than air cooled condensers.

●Condenser: the condenser is installed at the outlet of the steam turbine. The cooling water, flowing through the pipes, condensates the steam, that enters from the shell side and drops down into the hotwell. The cooling water is usually provided by either large rivers or the sea: that water is hence pumped into the condenser. The condenser, along with the drums and the deaerator, is also important from the operational point of view, because it is a reserve of condensate to compensate load variations and transients.

—The cooling system: after the steam is discharged by the LP steam turbine, it has to be converted back to water by cooling. When cooling water is available (sea or river water), condensers are typically used, as they are more efficient; however, when cooling water is not available (because the power station is far from any sea or river) or its use is subject to restrictions or it is too expensive, cooling towers or air-cooled condensers are used.

—The steam turbine: the axial steam turbine is placed on the same shaft as the electrical generator and it is usually made by two or three sections (HP, MP, LP). The boiler reheater placed between the first two sections of the turbine increases the plant efficiency. Other arrangements are possible, depending on the power, on the amount of available steam, etc. The solution described is the standard one, called tandem compound, but in some cases two different shafts are used, at different angular speed, and that solution is called cross compound.

The saturated steam is introduced into superheaters and then sent to the high pressure (HP) steam turbine; back from the HP turbine, it is then reheated in the boiler and resent back to the medium and low pressure turbines (MP and LP respectively); finally, it is discharged to the condenser.

●Forced circulation boiler or once through boiler. In this type of boiler, drum is not required since there is not a distinct evaporation circuit and circulation is guaranteed by feedwater pumps suitably sized.

●Natural circulation boiler: here the circulation is achieved thanks to the density difference of the water. The circulation of the feedwater is simply guaranteed by convection.

—The boiler: the boiler furnace is surrounded by high-pressure pipes belonging to evaporation circuit. They are hit by the thermal radiation of the ignited fuel. The feedwater, previously heated into the boiler convective part, circulates inside the pipes, absorbs the heat and changes into steam; saturated steam is collected in the drum. Different types of boiler are currently available:

From a thermodynamical point of view, the Rankine cycle has the same basic properties independent of the fuel adopted to generate the steam (gas, coal, oils, waste, nuclear, etc.). Its main components are:

After the expansion in turbine, the steam is discharged to a condenser where it is condensed to water at low pressure. This water is then pumped to higher pressure and sent back to the boiler to close the cycle.

The Rankine cycle (Figure 5) makes it possible to generate electric power by means of an electric generator moved by a steam turbine. The steam to be expanded in the turbine is produced by a boiler where the combustion of the fuel (coal, oil or gas, typically) takes place, thus providing the necessary heat to transform the feeding water into steam at suitable pressure and temperature conditions.

—Rankine cycle, used in conventional thermal plant (fuelled by coal, oil, gas or other fuels) as well as in nuclear power stations;

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Considering 2019 (EU27), the electrical energy produced by coal plants (other bituminous coal and lignite) has been equal to 284.92 TWh, corresponding to 743.20 TWh of combustible fuel [1]. Hence, the average efficiency has been 38.3 %. The same amount of electricity could be produced by last generation CCGTs with the best efficiency of 64 %: in that case, the required primary energy would be 284.92/0.64=445.19 TWh, thus saving 743.20-445.19=298.01 TWh of primary energy per year, corresponding to 25.62 Mtoe. It is worth noticing that this value is on the safe side, given that auxiliary services of coal power stations are much more requiring than auxiliary services of CCGT power stations, thus resulting in further primary energy saving. That substitution would also imply as further advantage from the environmental point of view a significant amount of CO2 savings, as the primary fossil fuel would be gas instead of coal.

In order to evaluate a reasonable simple scenario, based on the decision of complete European coal phase out by 2030 [21], we estimated the saving of primary energy assuming that the amount of energy produced in 2019 (which is the latest year with available consolidated data) by coal power stations, is substituted by the most efficient CCGT thermal power stations. That scenario is on one side realistic enough, as the de-carbonisation has been already decided in Europe and can be considered a matter of fact, and on the other side it is also conservative, as that energy might be substituted also by RES generation, thus resulting in further primary energy savings.

Concerning oil power stations, the high cost of the fuel combined to low efficiencies and environmental issues led the operators to dismantle, decommission or reconvert them into the more efficient combined cycle plants as already underlined in 2004 by [19] and in [20]. The electricity produced by these plants (Figure 14) faced a huge decline in the last 20 years [1], confirming this change.

It is worth noticing that efficiencies are average values and include any loading level of generators as well as starting (when different fuels – e.g., diesel – can be used and in general the efficiency is very low). Moreover, there is no difference made between OCGT and CCGT, so that it is difficult to make conclusions about the distinct efficiency resulting from the two gas technologies.

Regarding the EU27 thermal plants, the following graphs show the gross production of electricity in thermal power stations and the gross efficiency of coal and gas plants till 2019 (Figure 12 and Figure 13): lignite and other bituminous coal still represent the main source of electricity.

Using the data available in the Eurostat database [1], the yearly average efficiency and production of the European thermal plants can be calculated, computing the ratio (using suitable units):

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EUROPEAN COMMISSION Brussels, 9.1.2023 SWD(2023) 1 final COMMISSION STAFF WORKING DOCUMENT Accompanying the document REPORT FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS JRC technical report on "Assessment of the potential for energy efficiency in electricity generation, transmission and storage" {COM(2023) 1 final}



Contents Abstract 1 1 Introduction 2 2 Fossil fuels power plants 3 2.1.1 Introduction 3 2.2 Thermodynamics and thermal generation 5 2.2.1 The Rankine cycle 5 2.2.1.1 Coal power plants 7 2.2.1.2 Oil power plants 9 2.2.1.3 Gas power plants 9 2.2.1.4 The Brayton cycle 9 2.2.2 The Combined cycle 11 2.3 Current efficiency of the European thermal power plants 13 2.4 Summary of the thermal plant efficiencies 14 3 Storage technologies 15 3.1 Introduction 15 3.2 Mechanical energy storage 16 3.2.1 Pumped hydro storage 16

3.2.2 Compressed Air Energy Storage (CAES) 18 3.2.3 Liquid air energy storage 19 3.2.4 Flywheels 19 3.3 Electrochemical energy storage 21 3.3.1 Lead-acid batteries 21 3.3.2 Lithium-ion batteries 22 3.3.3 Flow batteries 22 3.3.4 High temperature batteries 23 3.4 Electrical energy storage 24 3.4.1 Supercapacitors 24 3.4.2 Superconducting Magnetic Energy Storage 25 3.5 Chemical energy storage 25 3.5.1 Power-to-hydrogen 25 3.6 Summary of storage efficiencies 26 4 Transmission High Voltage Direct Current systems 27 4.1 Introduction 27 4.2 HVDC system structure 29 4.3 Line Commutated Converters (LCC) 32 4.4 Voltage Source Converters (VSC) 33 4.5 Technical-economic HVAC vs. HVDC comparison 34

4.6 Conclusions on power losses in HVAC and HVDC Transmission Systems 36 5 Conclusions 38 References 39 List of abbreviations and definitions 43 List of figures 45 List of tables 47 APPENDIX I - Coal 48 APPENDIX II - Gas 50 APPENDIX III – Storage 57 APPENDIX IV – HVDC Technologies 58 3Storage technologies 3.1Introduction In a power network increasingly penetrated by renewable energy production, characterized by large variability, storage plays a pivotal role in improving the efficiency of the system while pursuing the objective of a transition towards a carbon-neutral power system. To date, pumped hydro is by far the most widespread type of storage, accounting for more than 90 % of the total capacity installed worldwide [22]. In the European Union, more than 45 GW of pumped hydro are installed [23], while less than 200 MW of electro-chemical storage are available (Figure 15). Figure 15: Electro-chemical storage deployment in Europe [24] Given the strict relation of pumped hydro with the availability of suitable geographical locations, largely already in use, the other storage opportunities are increasingly gaining attention. In particular, lithium-ion batteries are earning a prominent role in the storage market, as shown in Figure 16. Figure 16: Technology mix in storage installations excluding pumped hydro [25]

In the scope of the “Clean planet for all” EU strategy, total storage installed for stationary applications in the European power system is expected to reach between 250 TWh and 450 TWh by 2050 [26]. There is a wide variety of available technologies, each characterized by its response time, efficiency, cycle lifetime, power and energy features, etc. According to these features and to the typical power ratings, a classification of possible services to be provided to the power network is shown in Figure 17. Figure 17: System services that storage technologies can provide depending on the service timescale and typical power ratings [27] The technologies analysed in this report can be divided into the following categories: —Mechanical energy storage: pumped hydro storage, Compressed Air Energy Storage (CAES), Liquid Air Energy Storage (LAES), flywheels; —Electrochemical energy storage: lead-acid batteries, lithium-ion batteries, flow batteries, high-temperature batteries; —Electrical energy storage: supercapacitors, superconducting magnetic energy storage (SMES); —Chemical energy storage: power-to-hydrogen. An efficiency overview of the electric energy storage systems is presented in Appendix III. 3.2Mechanical energy storage 3.2.1Pumped hydro storage Pumped hydro storage (PHS) constitutes more than 90 % of the total storage capacity installed worldwide [22]. It is a very mature and flexible technology, whose most common sizes currently range from few MW up to thousands of MW. A 3600 MW PHS project is currently under construction in China and will become the largest of the world [28]. PHS allows to store electric energy in the form of gravitational potential energy: water is pumped from a lower to an upper reservoir during off-peak hours or in case of excess of energy; water is then sent to the turbine during peak hours or in case of supply of system service to the network. The layout of a typical PHS plant is shown in Figure 18. Figure 18: PHS plant layout [29]. Three configurations are possible [30]: —Quaternary set: this was the first configuration been adopted, in which the pump is driven by a motor and the turbine powers a generator. Hence, the two groups are completely decoupled and individually optimized. This is the most expensive option, which also allows the best overall efficiency, because each functionality is optimized; —Ternary set: pump and turbine on a single shaft, together with the electrical machine. The latter works as either motor or generator, depending on the operating mode of the plant. Also in this case, pump and turbine can be designed individually and high efficiencies are reached. —Binary set: a reversible hydraulic machine is used both in pumping and generation mode (depending on the rotation of the shaft) and it is coupled with an electrical machine working either as generator or as a motor. To date, this is the most widespread configuration due to its reduced cost, but this comes at the expense of efficiency, as the hydraulic machine is designed as a compromise of its double use. The basic layout of a pumped-storage hydropower plant involves two reservoirs, one above the other, and a turbine/pumping hall capable of both generating power from the stored water in the upper reservoir and pumping water from the lower reservoir back to the upper. For hydropower plants in general, the energy available from a given volume of water is greater, the greater the head of water. In the case of the pumped-storage plant, this head is the vertical distance between the upper reservoir and the turbines.

Roundtrip efficiencies (RTE) range from 70 to 84 %, where the highest values are achieved thanks to the development of variable speed PHS [27], [31]. The per-unit cost of the energy produced may vary approximately in the range from 5 up to 100 €/kWh [32], [33]. PHS can provide large-scale storage and a plant can last many decades; on the other side, suitable geographical sites need to be found and the environmental impacts to be carefully considered: indeed, the expansion of this technology in Europe is held back by environmental restrictions and by the fact that most suitable sites have already been exploited [27]. For this reason, some new approaches are under consideration, in particular the use of the sea/ocean or underground caverns as lower reservoirs [34]. Moreover, small scale plants are today considered to store renewable energy produced locally, but their economic sustainability is questionable today, in comparison to other types of storage. For such smaller plants, efficiencies are lower and may fall below 50 %, as machines are not singularly designed and optimized, like in the case of larger power stations. Given the high maturity of the technology, no significant improvements in terms of technical and cost performance are expected in the coming years. 3.2.2Compressed Air Energy Storage (CAES) In Compressed Air Energy Storage (CAES), energy is stored in the form of pressurized air, in a cavern in case of large size plants: electric energy is used to drive compressors to store air in a reservoir. The cavern can be either a former salt or gas reserve or a purpose-built cavern. This last option is rarely adopted, as it leads to a dramatic cost increase. This kind of storage is able to provide very large amount of power (above 100 MW); hence, it results in an interesting option for network operators. CAES stores the energy by compressing air as an elastic potential energy. It has separate compression and expansion processes. During low demand, the extra electrical energy is stored in the form of compressed air in air storage vessels. When the demand is high, the compressed air is converted to electrical energy through an energy conversion process using a high-pressure turbine where the compressed air is mixed with the gas. Two main CAES technologies are available [25], [27], [35], as discussed below and shown in Figure 19: —Diabatic CAES: the compressed air, which needs to be heated when exiting the reservoir, is mixed with natural gas in a combustion chamber and expanded in a gas turbine. This is the only commercially available option, which comes with a cost of about 50 €/kWh and RTE of 55 %. The low efficiency is one of the main drawbacks, together with emissions related to the combustion process. —Adiabatic CAES: the technology stores the heat generated during the compression cycle and uses it to heat the air up before expansion. This removes the need of a combustion and efficiency can reach 70 %. Adiabatic CAES has been under study for years and is now close to reach commercialization phase. Figure 19: Diabatic (a) and adiabatic (b) CAES layout [27] Furthermore, isothermal CAES is currently under development: nearly isothermal compression and expansion would improve the efficiency up to 80 %. No combustion is needed [33]. Several projects have been commissioned in Europe for the years 2020-2024 [25]; this is expected to push towards a cost reduction and an improved efficiency. Some innovative projects have been proposed. In Germany, the world’s first large-scale AA-CAES project—ADELE—with 70% cycle efficiency has been designed by RWE Power, General Electric and other partners [36] [37]. The aim of this project is to optimize the co-existence and smooth interaction of the individual energy sources, especially for wind power. It is planned to have 1 GWh storage capacity and be capable of generating up to 200 MW, said the RWE power. The ADELE project could provide backup capacity within a very short time and replace forty state-of-the -art wind turbines for a period of 5 h. The project is currently in its final phase of development. In the Netherlands, the CAES Zuidwending project, scheduled for commissioning in 2024-25, will have a generation capacity of approximately 300 MW and a daily storage/delivery capacity of approximately 3-4 GWh (gigawatt-hours). In UK, the Gaelectric Energy Storage Ltd promoted the Cheshire CAES project, with a maximum active power of 268 MW and a storage capacity of 1,6 GWh. In China, on July 16, 2020, the Chinese Academy of Sciences Institute of Engineering Thermophysics achieved a new breakthrough successfully performed the integration test of the world’s first 100 MW CAES expander. There is another 50 MW AA-CAES project underway in Jiangsu, China, in 2017, which is certified by the consulting panel. In this 50 MW AA-CAES system, underground salt caverns are adopted as the air reservoirs. The final objective is to build 100 MW AA-CAES informed by the learnings from the 50 MW system. In 2015, Hydrostor has started a pilot project for the World’s First Offshore Compressed-Air Energy Storage Project in Toronto (Canada). It was the first test of an underwater compressed-air energy storage system. The project used drilling techniques that reduces the demand for boats and cranes at the surface to deploy the pipes and storage balloons. 3.2.3Liquid air energy storage

Liquid air energy storage (LAES) is based on cryogenic energy conversion: electric energy is used to remove heat from ambient air taken from the environment to produce liquid air. The fluid is then stored in an insulated tank at low pressure. When electricity is needed, the liquid air is pumped to high pressure, heated and expanded in a turbine [38], [39]. LAES layout is shown in Figure 20. Figure 20: LAES mode of operation [40] The advantage of LAES over CAES is that it does not come with any geographical restriction, as the high energy density allows the use of tanks to store the liquified air [39]. The cost of the technology is 250÷600 €/kWh and is expected to decrease to 150÷400 €/kWh by 2030 [40]. This storage option takes advantage of the use of mature supply chains and components, but it is currently at demonstration phase. Few small-scale pilots have been fully built and have shown a roundtrip efficiency below 20 % [38], [40]. Researchers claim this result is strictly related to the size of the system, and efficiencies of around 50% could be reached for wider scales. An important boost in the efficiency could be obtained by coupling LAES with industrial processes providing waste heat to be used upon expansion. This option could lead to an efficiency >65 % [40]. 3.2.4Flywheels Flywheels store energy in the form of kinetic energy. A rotating mass is connected to a reversible electrical machine which acts as a motor in charging phase, increasing the speed of the rotating mass and the relative stored energy, and as a generator in discharging phase, extracting energy and decreasing the speed of the rotating mass [41]. The system is enclosed in a vacuum chamber to reduce aerodynamic drag and rotation is smoothed by magnetic bearings. These elements allow flywheels to keep their maximum speed for days by only being provided the energy to compensate idle losses [25], [40]. The state of charge is easily determinable from the rotational speed [27]. Figure 21: Flywheels layout [29] There are two types of flywheel: low-speed (<10000 rpm) and high-speed (up to 100000 rpm). The former is made of metallic materials, is easier to build and is characterized by higher weights; hence, it is more suitable for stationary applications. The latter is made of composite materials, such as carbon fibres, which provide better performances at higher costs; this option is adopted for low-energy applications [25], [40]. This system is mainly applied to the high power/short duration EES applications (e.g., 100 kW/10 s), which provide support power during interruptions, for short time periods or when shifting from one power source to another. Flywheels can usually respond extremely quickly. In grid backup systems[42][43] they should be capable of reaching full power within half a cycle (25 ms at 50 Hz), and some are quoted with response times of 5 ms. Such units will probably be able to supply their full output for between 5 and 15 seconds. Commercial flywheels are available with power ratings of between 2 kW and 2 MW and with storage capacities of between 1 and 100 kWh. One of the largest commercial systems is a unit with ten 100 kW flywheels used by the New York Transit System to support its electric traction power network. This system can supply 1 MW of power for 6 seconds. However, the largest flywheel is the one used in Japan for nuclear fusion research. This system can supply 340 MW for 30 seconds. In North Western Australia, a flywheel system has been integrated into a town’s power supply to support the increased power demand during the tourist season [43]. Coral Bay, a wind energy operated power station, consisted of seven 320 kW low-load diesel generators with three 200 kW wind turbines. In 2007, the integration of a 500 kW flywheel virtual generator into the system allowed the wind turbines to provide up to 95% of Coral Bay’s supply at peak times. The reported data shows that for nearly 900 h per year, 90% of the power station’s total supply comes from wind generation. In addition, while maintaining the grid standards and improving the power quality, 80% of this total power is wind-generated for one-third of the year [43]. Another flywheel-based stabilisation system has been planned for the Marsabit wind farm, a remote community served by an isolated microgrid in northern Kenya. A 500 kW flywheel-based system will be integrated into the existing two 275 kW wind turbines and diesel generators. The PowerStore flywheel to be installed by ABB will stabilise the grid connection to maximise renewable energy penetration [43]. Power Store is a flywheel-based stabilising generator which is mainly used for improving the power quality. It enables the integration and control of renewable wind and solar energy in the electrical grid. Acting like a static synchronous compensator (STATCOM), it combines an 18 MWs (Megawatt second) low-speed flywheel with solid state converters that absorb or inject full energy in 1 millisecond. The range of models from 500 kW to 1,5 MW allows the configuration of either a grid support mode for MW scale grids, or as a virtual generator for use in smaller isolated grids. In general, flywheels provide fast-response services thanks to their high power density, their rapidity of charging/discharging and to minimize the impact of idle losses. They are characterized by a long cycle-life and ask for limited maintenance. RTE can reach 90 % in optimal operating conditions [44] and is not expected to go through a significant improvement in the future, while research on material will most likely enable a relevant reduction of costs, currently in the range 500÷3000 €/kWh [40]. 3.3Electrochemical energy storage All the technologies belonging to this category can be identifies as Battery Energy Storage Systems (BESS). The basic concept behind BESS is that both electrical and chemical energy use electrons as carriers. This makes the storage particularly efficient, because it avoids losses due to conversion to any other type of energy. A cell of an electrochemical storage is basically composed by the following components: two electrodes, an electrolyte, a separator to avoid contact of the electrodes and a container. Reversible oxidation and reduction reactions cause the flow of electrons which allow to withdraw or inject energy in the system [25], [40]. Figure 22 shows the connection of BESS to the AC grid: an electronic converter is needed to get AC current and this affects the roundtrip efficiency. In case of connection to a DC bus, the DC/AC stage is not present. Efficiencies in the following subsections will refer to DC/DC RTE. The AC/AC RTE can be obtained by multiplying the DC/DC RTE by the roundtrip efficiency of the DC/AC converter (94÷95 %) [45]. Figure 22: BESS connection to AC grid [46]

This kind of storage has the advantage of being highly modular, cells can be connected in different configurations in order to reach the desired voltage, energy capacity and power, but care must be taken to prevent non-optimal usage from rapidly reducing battery life or even damaging it. The technology is currently increasing its market penetration, exploiting the significant progress made in terms of cost and lifecycle. 3.3.1Lead-acid batteries Lead-acid batteries have been the first to reach technological maturity and are currently the most widespread battery type. There are two types of lead-acid batteries: vented lead-acid (VLA), in which oxygen and hydrogen are dispersed into the environment, and valve-regulated lead-acid (VRLA), in which oxygen and hydrogen are recombined to form water. VLA batteries have lower cost and longer lifetime, but requires more maintenance than VRLA batteries [27], [32]. Lead-acid batteries are normally subject to a 2-3 % monthly self-discharge and do not respond well to deep discharging: the maximum Depth of Discharge (DOD), i.e., the complement of the State of Charge (SOC) (see Figure 23), should be at most 50 %. The maximum number of full charge/discharge cycles can reach 2500 if operated in optimal conditions [32]. Lead toxicity may be an issue for some applications; on the other hand, materials are highly recyclable [27]. Figure 23: Depth of Discharge and State of Charge of BESS Their roundtrip efficiency is in the range 70÷90 % and their cost is around 120÷200€/kWh. These two characteristics make lead-acid batteries one of the most convenient batteries in terms of performance/cost trade-off. Limited improvements in the manufacturing process are expected, which may lead to reduce the cost below 100€/kWh while maintaining similar RTE [27], [40]. Several very large-energy storage facilities based on lead-acid batteries have been built. These include an 8,5 MW unit constructed in West Berlin in 1986, while the city was still divided into East and West and a 20 MW unit built in Puerto Rico in 1994. Although the former operated successfully for several years, cell degradation led to the latter closing after only 5 years. Lead-acid cells have been very popular for renewable applications such as small wind or solar installations where they are used to store intermittently generated power to make it continuously available [47]. Duke Energy added 36 MW of lead-acid battery storage to its Notrees wind power facility in West Texas. When the lead-acid batteries were first installed, the battery system participated in the region’s frequency regulation market, which required rapid charging and discharging that significantly degraded the batteries. In 2016, Duke Energy replaced the original lead-acid batteries with better performing lithium-ion batteries [48]. 3.3.2Lithium-ion batteries These batteries base their electrochemistry on the flow of lithium ions between the electrodes. The peculiarity of lithium ions stands in their very limited size, which allows this technology to have very high power and energy density [25]. Lithium batteries have very high DOD, up to 100 %, very limited self-discharge, impressive efficiencies in the range 92÷96 % and lifetime of 4000÷5000 cycles. The main disadvantage is the need of a battery management system, to improve safety and performance characteristics: in case of overheating, the battery degrades rapidly and gas leaks may even cause fires. Moreover, a robust metallic case is needed [27], [32]. These features lead to a high specific cost of around 250 €/kWh [40]. Besides the massive use of lithium batteries for electronic devices, medium and large size batteries are claiming attention for network services. Many efforts are currently put into improving the performances of such storage technology. By 2030, efficiencies are expected to reach 94÷98 % while costs are expected to decrease to less than 100 €/kWh [27], [40]. The very rapid growth in the use of this technology has brought to pay attention to problems on the supply of raw materials and on the recycling of degraded batteries, on which options are being developed but which at the moment are not yet widely applied given the scarce economic convenience [27]. An early large pilot battery storage installation rated at 2 MW was commissioned on the Orkney Islands, which are located off the coast of north-western Scotland, in 2013. This was topped in 2017 when the US utility San Diego Gas and Electric opened a 30 MW battery storage facility based on lithium-ion batteries with 120 MWh of storage capacity. A 20 MW facility is also being planned by the utility Southern California Edison. The world’s largest lithium-ion power reserve (100 MW/129 MWh storage capacity, now expanded to 150 MW) is the Hornsdale battery energy storage system, in Australia. The future development of lithium batteries may benefit from interest by automotive manufacturers in their use in hybrid and electric vehicles [47]. 3.3.3Flow batteries The electric energy circulates through flow batteries thanks to the presence of two electrolyte materials pumped into two separate loops. The movement of ions to the electrodes is enabled by a membrane putting in contact the two fluids [25]. The most common technologies are vanadium and zinc bromine flow batteries, but to date only the former has been widely employed around the world [27]. Figure 24: Schematic of vanadium redox flow battery [29] This configuration requires the presence of pumps and sensors to regulate the flow (see Figure 24); moreover, the risk of leaking of acid fluids needs to be taken into account. Hence, the system is more complex compared to other types of batteries and it calls for more demanding maintenance. On the other hand, flow batteries respond well to deep discharges and their cycle lifetime can exceed 10000 [27]. A very important characteristic of flow batteries is that power and capacity are completely decoupled: the former depends on the pumps and on the membrane surface; the latter depends on the size of the tanks containing the electrolyte materials [25], [32]. The RTE of the battery is strictly related to the pumps and can vary in the range 60÷85 %; however, by 2030 efficiency is expected to reach and exceed 90 % in the best configuration [27], [33]. Given these interesting characteristics, many researchers have investigated possible advancements in the performances of flow batteries and new options in terms of fluids and materials are currently under study. The cost of this technology is around 400 €/kWh, but given the great research efforts, it is expected to fall below 100 €/kWh before 2050 [35].

3.3.4High temperature batteries The peculiarity of this kind of batteries is that the electrodes are separated by a solid ceramic electrolyte. They operate at 250÷350 °C in order to keep the electrodes in liquid state and to improve the conductivity of the electrolyte. The two most common technologies are sodium sulphur (NaS) and sodium nickel chloride (NaNiCl2) batteries: the former is characterized very high recyclability, safety issues related to the production of a corrosive compound and idle losses of around 3 % of the rated power to maintain the needed temperature; the latter has usually a shorter cycle life but requires lower operating temperatures and is made of less corrosive materials [27]. High temperature batteries are characterized by low self-discharge rates and their DOD can reach 100 %. Roundtrip efficiency is around 85 % and the number of cycles ranges from 1000 to 10000 [27], [33]. Current research is focusing on decreasing the working temperature, to operate in an all-solid state. The cost of the technology is in the range 250÷700 €/kWh, with the potential of decreasing by 75 % if progress is made in terms of operating temperatures. However, the presence of a very limited number of technology providers may slow down these developments [27], [40]. NaNiCl2 batteries have been successfully installed in the Duke Energy Rankin Substation (North Carolina) with the purpose of PV power smoothing in combination with a 1 MWp PV plant. This installation won the 2013 "Grid Integration of Renewable Project of the year award". Another meaningful installation is the "Toucan Project", in French Guiana, where 2 MW of Sodium-Nickel batteries have been connected to the photovoltaic panels in the plant prepared in the area near to Montsinéry near a MV substation, in the back land of the French Guiana, whose energy will be stored by them during the day for releasing it during the night hours. Also, the Italian Transmission System Operator, Terna, is testing the Sodium-Nickel batteries with the installation of 3,4 MW in the high voltage network with the aim of providing grid services, above all the grid frequency regulation [[49][50][51][52]. The overall installed NaS power in the world is 365 MW. These batteries have been installed for both stationary applications and for power supply (UPS): they have found great applications for peak shaving with a twenty-year experience. The biggest installation in the world is at Rokkasho (Japan) with 34 MW rated power. The system is linked with a 51 MW wind farm [53]. In Italy, three NaS battery installations are in South Italy and have a total power of 34,8 MW. Their function in the grid is charging and discharging in long intervals in order to avoid congestions on the power transmission lines due to the great amount of renewable energy fed into the grid[53]. Other meaningful stationary applications are the 9,6 MW installation in the Hitachi car industry and the 6 MW/48 MWh installation in the Ohito substation owned by TEPCO[53]. 3.4Electrical energy storage 3.4.1Supercapacitors Supercapacitors are characterized by the presence of two electrodes immersed in an electrolytic solution and separated by a permeable membrane. Energy is stored in the form of static charge on the surfaces of the electrodes [25]. The most widespread configuration has carbon-based electrodes and organic electrolytic solution (Figure 25). A simple electrostatic capacitor comprises two plates with a dielectric material between them. When a voltage is applied to the plates, charge builds up on them to neutralise the voltage by creating an equal and opposite static charge voltage across the plates. An electrochemical capacitor is similar to this in that it has a dielectric material between the capacitor plates but in this case the dielectric is a liquid electrolyte such as sulphuric acid or potassium hydroxide which can support a much higher build-up of charge. The capacitor plates themselves are inert materials which will not react with these reagents. Electrochemical capacitors can be cycled for tens of thousands of times without degradation, provided the voltage across them is kept below the maximum so that no internal reaction takes place. However, once they are charged, they do lose charge slowly through leakage in the same way as a battery. The leakage levels in water-based electrochemical cells are similar to that of a lead-acid battery. Leakage levels are lower with organic-based electrolytes. Leakage will reduce long-term storage. This technology is characterized by high power density (2000÷5000 W/kg) and low energy density (3÷5 Wh/kg), with a discharge time that spans from few seconds to one minute. The installation cost is in the range 250÷2000 €/kWh and the DC/DC RTE is above 95 % [31], [32]. Figure 25: Supercapacitor layout [29] Despite the very high efficiency, this storage option is not considered for energy services in power systems, while it is already widely used for mitigation of power quality issues (short interruptions and high-power applications). Many aspects are still under development; in particular, much research is ongoing on materials. The high cost and the low energy density do not allow at the moment a wide employment of the technology for grid energy storage, which is mostly limited to pilot projects [32], [40]. Efforts in research are expected to produce a significant cost reduction in the coming years. 3.4.2Superconducting Magnetic Energy Storage In Superconducting Magnetic Energy Storage (SMES), electric energy is stored by making a current flow through a coil made of superconducting material, generating a magnetic field. A schematic representation of SMES is shown in Figure 26. A refrigeration system is needed to allow superconductivity; despite this, DC/DC RTE is extremely high (>95 %) as the resistance of the superconductor is practically null [25], [54]. Figure 26: SMES layout [54]