Barriers to grid-connected battery systems: Evidence from the Spanish electricity market
BBarriers to grid-connected battery systems: Evidence from the Spanish electricity market
Yu Hu, a * David Soler Soneira, a María Jesús Sánchez, b a Invesyde S.L., Madrid, Spain b Escuela Técnica Superior Ingenieros Industriales, Universidad Politecnica de Madrid, Spain
Keywords
Grid-connected battery systems; Spanish electricity market; Market design; Grid flexibility.
Abstracts
Electrical energy storage is considered essential for the future energy system to solve the intermittency problems caused by renewable energy sources such as wind and solar power. Among all the energy storage technologies, battery systems may provide flexibility in a more distributed and decentralized way. In countries with deregulated electricity markets, grid-connected battery systems should participate in the electric power system and interact with other market players. In this study, the market designs of both wholesale markets and ancillary services in Spain are introduced, and the barriers to grid-connected battery storage are investigated under its specific market and regulatory framework. Finally, the numerical and empirical analysis suggests that the high cycle cost for battery is still the main barrier for grid-connected battery systems, and the flexibility offered by such systems would be currently the most promising comparative advantage for this novel technology. Additionally, a correct recognition of the barriers and advantages by all the stakeholders, including the system/market operator, policy maker, investor, and project manager, is the key factor to promote battery storage technologies in grid-connected applications. For market and system regulators, more efforts are necessary to reduce the barriers from regulatory framework, promote pilot projects, and design appropriate market products or services that adequately address the flexibility provided by different technologies. * Corresponding author. Tel: +34-917395257; Email: [email protected] ntroduction
Intermittency is one of the major burdens of renewable energy sources such as wind power and solar power, since the delivery of the energy basically depends on the weather condition. Electrical energy storage is considered to be essential for the future energy system with an increasing penetration level of intermittent energy sources [1]. The battery storage industry has been growing rapidly during the last few years, battery systems are becoming more attractive with falling costs and improving performance [2]. Currently, although grid-connected energy storage systems are dominated by pumped hydroelectric storage [3], with more than 98% of the total installed capacity [4], the number for grid-connected electrochemical storage systems has reached 1600 MW in terms of power capacity in 2017 (almost three times higher than in 2014), where Li-ion batteries account for about 81% (1300 MW) of the total electrochemical capacity. [4] Different research works have been developed on the application of grid-connected battery storage systems. For example, battery storage can be applied in power system regulation by providing frequency control, power reserves and balancing power [5]. When combined with renewable energy sources such as wind power, a battery system may store the excess power generation when necessary and stabilize the power output of renewable energy generators [6]. At the same time, batteries can also increase power system reliability by providing peak load and resolving congestion. Compared with other technologies, battery systems may provide system flexibility in a more distributed and decentralized way [7]. However, as an emerging technology, grid-connected battery systems face a number of barriers which limit their further deployment. According to [5], despite the significant reduction, the initial cost for grid-connected battery storage projects is still high for investors. At the same time, the lack of awareness of the technological and economic benefits of such systems keeps the shareholders from adapting to the new asset class. The feasibility assessment of a grid-connected battery storage project, should be conducted under a specific market and regulatory framework. Although electricity markets in each country vary in term of regulation and level of competition, a general trend toward deregulated and integrated markets has been observed globally in the recent decades. [8], [9] and [10]. In countries with deregulated electricity markets, grid-connected battery systems should participate in the market and interact with other market players and the system operator under the specific regulatory framework. Few research works have addressed grid-connected battery storage systems under a realistic deregulated electricity market design. In this study, we focus on the barriers to grid-connected battery systems under the Spanish electrical power system. We first introduce the market designs of both wholesale markets and ancillary services in Spain and discuss the potential application of battery storage systems. Then we analyze the barriers for the wide deployment of battery systems under the current market and regulatory framework in Spain, and finally conclusions and ecommendations are presented to overcome the barriers. The result and findings of the study suggest that the flexibility is the main value that battery systems bring to the power grid. Market design and regulatory frameworks that fairly and adequately address flexibility would be the key factor to improve the potential market opportunity of grid-connected battery systems. The results of this study contribute to the awareness of battery storage technology and its flexibility in grid applications. The findings also have significant implications for policy makers and market operators interested in promoting grid-connected battery storage under a deregulated power market, and provide meaningful insights for both regulated and deregulated electricity markets for adapting the new technology.
Electricity market and ancillary services in Spain
In Spain, electrical utilities trade their energy production or power capacity through the wholesale electricity market or by providing ancillary services. Table 1 presents the electricity markets, ancillary services and their products in Spain.
Table 1. Wholesale electricity market and ancillary services in Spain.
Market/Service Product Wholesale Market Day-ahead market Energy
Operated by OMIE
Intraday market Primary reserve (Non-remunerable)
Secondary reserve Capacity and Energy Ancillary services Tertiary reserve Energy
Operated by REE
Deviation management Management of Technical constraints Interruptibility Service Capacity and Energy Voltage control Reactive power
Wholesale electricity market
OMIE (Operador del Mercado Ibérico de energía - polo Español) runs the wholesale electricity market in both Spain and Portugal. The market is composed of a set of sub-arkets in which power generators and consumers trade hourly energy production products. In general, the commonly referred to as Spanish electricity price is the market clearing price of the day-ahead market opened at noon for the next day with 24 hourly products. Power purchase and sale offers are matched according to their economic merit order, [11]. The settlement price of energy over a specific hour is determined by the point at which the supply and demand curves intersect, according to the marginal pricing model adopted by the European Union. After the day-ahead market, market participants may adjust their position through intraday markets. There are in total six intraday markets which are held several hours earlier than the delivery of power production [12]. Again, the settlement prices are determined by the power supply and demand curves. There is also a continuous intraday market which runs in parallel where real-time bid and asks are matched like the common exchange market. Similar to other energy storage technologies, battery storage systems are able to perform energy arbitrage by buying energy when the energy price is low and selling the stored energy at the peak hours with high energy prices.
Ancillary services
Ancillary services are defined as the “set of products separated from the energy production, which are related to security and reliability of a power system” [13]. In Spain, REE (Red Eléctrica de España) operates the ancillary services market.
Primary reserve
The Spanish power grid is a part of the Union for the Coordination of the Transmission of Electricity (UCTE) power system. According to the handbook of UCTE [14], “the objective of primary control is to maintain a balance between generation and consumption (demand) within the synchronous area. By the joint action of all interconnected parties / TSOs, primary control aims at the operational reliability of the power system of the synchronous area and stabilizes the system frequency at a stationary value after a disturbance or incident in the time-frame of seconds, but without restoring the system frequency and the power exchanges to their reference values.” Frequency Containment Reserves (FCR) is the main primary reserve service providing balancing capacity in many European countries, including Austria, Belgium, Netherlands, France, Germany and Switzerland, and it is expected that the Western Denmark TSO (Transmission System Operators) will join the common FCR market in the future. The common FCR market operates with weekly-ahead auctions with weekly symmetric product. nlike the market based services mentioned above, the primary control in Spain has been defined as a mandatory non-remunerable service: generating units must be capable of modifying 1.5% of their rated output in less than 15 s for frequency variations less than 100 mHz, and linearly up to 30 s for frequency deviations up to 200 mHz [13]. As a result, there is no profit for battery storages for participating in primary reserve in Spain.
Secondary reserve
The UCTE [14] defines secondary reserve as an ancillary service that “maintains a balance between generation and consumption (demand) within each control area as well as the system frequency within the synchronous area, taking into account the control program, without impairing the primary control that is operated in the synchronous area in parallel.” Automatic generation control (AGC) systems are used in each control area to adjust the active power output of generation units that are participating in the service. In Spain the AGC orders are sent every 4 seconds, and the secondary reserve should respond in 100 seconds when required and should be maintained for 15 minutes. Secondary reserve is hired by the system operator using a specific day-ahead secondary reserve market. Regulating zones (major energy groups) submit bids of upward and downward power capacity reserve (in MW) of their generating units with associated price (in €/MW) of the capacity in an hourly basis. Then the system operator contacts the power capacity band on a least cost basis until the required capacity (calculated by the system operator) is reached. The verification and settlement of the secondary reserve is performed in level of regulating zones, penalties will be applied when a regulating zone does not comply with the response criteria. Besides the income from power capacity band, the remuneration of the secondary reserve contains an energy term (in €/MWh). The energy deviation due to secondary control operation is priced at the substituting tertiary energy that would result if the associated tertiary reserve market were called [13]. At the same time, penalties will be applied when a control zone does not comply with the response criteria. Theoretically, battery storage systems are able to participate in this service and be remunerated in terms of power capacity and energy delivered.
Tertiary reserve and deviation management
The objective of tertiary reserve is to restore the used secondary regulation band. Previously authorized generating units (Normally conventional thermal power producers, pumped hydro storage systems and authorized manageable renewable energies) are forced by law to offer available power in the tertiary market [15]. The bids are sent at 23:00 of the day before the delivery day, and may be updated till 25 minutes before the beginning of the programming hour. Tertiary regulation is allocated and marginal upward/downward prices are determined by the system operator using economic order 15 minutes before the programming hour (if necessary, during the programming hour) [12]. Generating units are xpected to respond within 15 minutes and be able to maintain the services for at least two consecutive hours. Deviation management aims to solve foreseen power imbalances (for example, generation units unavailability or justified changes communicated from generation) maintained during several hours. The system operator will call the service when it has foreseen a large power difference between programmed power production and demand after the intraday market [12]. Again, marginal upward/downward prices are determined by the system operator using economic order. Due to the limited notification time, the volatility of the energy prices in these two services is higher than the price volatility in the day-ahead market or the intraday adjustment market. Battery storage systems may arbitrage in these two services for higher price volatility.
Management of technical constraints
The system operator performs the management of technical constraints after the day-ahead market, when the power generation and demand resulting from the day-ahead market does not comply with power transmission constraints or security criteria. During this process, the system operator holds auctions that aim to increase or decrease the scheduled power production of power plants and finally to solve the technical constraints. Technical constraints are solved with a two phase auction process. The system operator starts with allocates new bids that may solve the constraints in the first phase, and then, in the second phase, bids that may re-establish the balance between power generation and demand. Unlike other markets where the marginal clearing price is used, both bidding processes are based on economic merit order and each participant is paid with the price associated with the bids. Currently the first auction phase of the service is only provided by large thermal power plants.
Interruptibility Service
Interruptibility service is a demand-side response program provided only by the large industrial consumers to reduce the power consumption according to the order issued by the system operator. The objective of the service is to reduce the extraordinary and temporary shortage of power generation caused by peak demands or sudden decrease of renewable generation due to weather changes. In other EU countries, this service is normally classified as a strategic reserve. The provider of the service receives a capacity payment. The allocation of the service is through a competitive allocation mechanism with a face-to-face bidding process managed by the system operator to ensure minimum costs. Currently, the service is standardized by wo types of products with capacity blocks of 5 MW and 40 MW respectively, and the two products are auctioned separately. The provider of the service also receives financial compensations in terms of energy (MWh) at the price of tertiary reserve for the corresponding time period.
Voltage control service
Voltage control service requires power generators and qualified consumers who participate in this service generate reactive power and maintain the system voltage. In Spain this service is partially compulsory and non-remunerable, and partially remunerable based on performance evaluation. Due to the importance of voltage control to maintain the system security and reliability, the system operator defines a minimum mandatory proportion. The reactive capacity exceeding the minimum might be offered and remunerated at a fixed regulated price if the system operator accepts it [13].
Imbalance cost
In Spain, if the final production (consumption) of a normal power producer (consumer) is different from the final scheduled program, without resulting from the ancillary services, an imbalance cost will be applied. The imbalance cost depends on the general state of the grid system. If the grid system faces energy shortage, additional costs will be applied to the power producers (consumers) who produce less (consume more) energy than scheduled, while the power producers (consumers) who produce more (consume less) energy than scheduled will be considered helpful for the system and no additional imbalance cost will be charged. In the other case, if the grid system faces energy surplus, additional imbalance costs will be only charged to the power producers (consumers) who produce more (consume less) energy than scheduled. The additional cost will be calculated according to the usage of deviation management, tertiary reserve and secondary reserve in the corresponding time period. A power producer is able to participate in the ancillary services after passing a set of tests from the system operator. If a power producer is participating in any ancillary services, the imbalance cost would not be applied to this generator. Still, other penalties would be applied if it does not fulfill the service requirements. It is generally accepted that when working together with non-dispatchable power plants, such as renewable generators, batteries may help in reducing the imbalance cost by stabilizing the energy output.
Other services
Currently, there exists an ancillary service named additional upward reserve, aiming to ensure there is enough upward capacity to be offered in ancillary services. This service is provided by dispatchable thermal generators that have not been committed in the day-ahead market. When additional upward reserve is called by the system operator, these units may id its available capacity, and receive the marginal price (in €/MWh) from the additional upward reserve market, if its bid is accepted. In exchange, thermal units that committed in the additional upward reserve market must sell their minimum capacity level to the intraday market, and submit bids in the ancillary services. However, this service is expected to be cancelled in the near future.
Barriers to grid-connected battery systems
Unlike the pumped hydroelectric storage which requires specific geometrical conditions, as a distributed solution, batteries are able to be constructed (located) close to the energy load or areas with technical constrains, and provide reliable energy supply with fast and flexible response. However, batteries face different barriers to widely deployment for grid-connected applications. In this section, the barriers related to the technological concerns, market profitability, and market design and regulations are presented and discussed.
Technological concerns
Despite the fact that battery energy storage technologies, especially the Li-ion battery, have experienced significant cost reductions, the cost for grid-connected battery storage projects is still high compared with mature technologies such as pumped hydroelectric storage [1] and [16]. The key factor that determines the cost barrier to the current battery technologies for grid scale applications is their lifetime. All batteries have a finite life since every charge-discharge cycle results in some degradation [17]. Research works have shown that battery degradation rates is higher during the early cycles than the later cycles, and finally the degradation rates would increase again when the battery reaches its end of life [18]. The general lifetime of battery systems can be described as cycle life which is defined as the number of complete charge–discharge cycles that the battery can perform before its nominal capacity falls below 80% of its initial rated capacity [19]. Besides capacity fading, other effects of battery degradation such as impedance rising may also cause problems for practical applications [20]. The cost of battery degradation can be defined as battery wear cost, which is cost of the delivered energy from the battery. The battery wear cost can be calculated as the battery cost in €/kWh divided by the Equivalent Full Cycles until the battery is replaced [20]. It can be also considered as the depreciation the battery storage by the energy it could deliver throughout its lifetime. Zubi et al. stated in 2018 that Li-ion batteries were still very far from the cost competitive range for grid-connected use given the battery specific cost around 300/kWh with a cycle life around 2000 cycles [21]. And for real battery storage products, Telsa provides a warranty that guarantees 70% energy retention in 10 years with a maximum number of 2800 Equivalent Full Cycles for its Li-ion battery product “Powerwall” [22]. or grid-connected battery storage systems, battery degradation and the associated costs must be considered in the marginal cost model when operating the storage system, specially when power and energy are traded in the market, as in Spain, the battery system operator has to focus specifically on the tradeoff between the total benefit from the market and battery degradation resulting from the operation. It should be noted that, besides Li-ion batteries, other battery technologies such as Vanadium flow, NaS, and advance Lead acid may become attractive in the future given that future cost reduction and higher cycle life are achieved [23]. The major drawback of these technologies such as low energy density, safety and maintaining requirements are not considered to be significant barriers for grid-scale applications. Other minor technological concerns would include the unstable output power capacity in the very low/high SoC (State of Charge) zones, difficulty in accurate measuring of energy retention and remaining energy, sensitivity to weather conditions, etc. These drawbacks would limit the controllability of battery systems in practice when operated in grid-connected applications.
Market profitability
In this section, we address the profitability of grid-connected battery storage systems for common applications using break-even analysis. We consider an empirical battery storage facility cost of 300 €/kWh and a conservative estimation of totally 3000 equivalent full cycles lifetime before the battery is replaced, and if the total cost will be equally amortized by the total energy delivered from the battery through its lifetime, each kWh (cycle) of energy from the battery system would imply a pure battery wear cost of 0.1 €/kWh (100 €/MWh). In the break-even analysis, it is considered to be profitable when the remuneration of an operation is higher than the corresponding battery wear cost caused by delivering energy from the battery, and other O&M costs are not considered.
Energy arbitrage
In deregulated electricity markets, the price of electricity is determined by the power supply and demand, Figure 1 presents the boxplot of the hourly prices in the day-ahead market of Spain from 2015 to 2019 in a monthly level. Figure 1 shows the yearly seasonality, repeated behavior every twelve months is observed from 2015 to 2019. Most outliers in prices are lower values compared with the rest of the monthly data. The behavior of prices is similar to that of demand. igure 1. Boxplot of the hourly prices in the day-ahead market of Spain from 2015 to 2019 in a monthly level.
Energy arbitrage is practiced by buying energy from the grid at a low price and selling it back at a higher price [24]. At the same time, the potential profit of energy arbitrage also depends on the operation frequency. In this study, energy arbitrage using battery storage system is simulated in daily cycles. In other words, the battery system will perform one full charge-discharge cycle daily. The reasons of the daily operation cycle are as follows: On the one hand, due to the demand difference between day and night, a daily pattern of electricity price with peak and valley hours is generally observed. On the other hand, the daily operation aligns with the designed operation pattern for many battery producers in terms of designed lifetime and warranty provided by the manufacturer. Figure 2 presents the boxplot of the hourly prices in November 2019 in a daily and hourly basis.
Figure 2. Boxplot of the hourly prices in the day-ahead market of Spain in Nov, 2019 in daily (a) and hourly (b) basis. (a) (b) urrently in Spain, energy itself as a single product is traded in the wholesale market, and used to provide some of the ancillary services such as management of technical constraints, tertiary reserve and deviation management, meanwhile, battery storage can be installed together with renewable power generators, reducing their imbalance cost when the actual power generation is different from the scheduled generation and the direction of the imbalance is the same as total the system imbalance (in this case additional penalty will be applied as the imbalance cost). Due to the flexibility requirement and real-time system status, the price volatility for the ancillary services is generally much higher than the day-ahead market. Figure 3 presents an example of the market prices on 28 th November, 2019. The lowest available price for this day is the Deviation management service from Hour 3 to Hour 5, and the highest price is the day-ahead market price at Hour 20. Ancillary services and imbalance costs may significantly increase the price volatility that battery storage system may receive.
Figure 3. Market price information for Day-ahead market, Deviation management, Tertiary regulation, and Imbalance costs on 28th November, 2019.
Table 2 presents the mean, median, and standard deviation of the market price of the day-ahead market, related ancillary services, and imbalance cost. It also shows the mean of the daily standard deviation of the day-ahead market price. The daily profit is calculated assuming that the battery storage will be charged at the lowest price of the day and discharged at the highest price. An 85% round-trip efficiency is considered and the energy loss is equally distributed along the charging and discharging phases. In case the calculated profit is less than zero (mainly due to the energy loss in the charging/discharging process), we consider the final profit for that specific operating day is zero (In this case the battery operator would choose not to perform energy arbitrage on that specific day). Note that this is an ideal case, not achievable in practice.
Table 2. Statistical information of Day-ahead market, Deviation management, Tertiary reserve and Imbalance cost. (2015-2019)
Day-ahead price Deviation management Tertiary reserve Imbalance cost Year Mean Median Std. Mean Daily Std. Mean Median Std. Mean Median Std. Mean Median Std. 2015 50.32 51.20 12.37 7.88 52.32 53.26 16.32 49.00 51.97 20.36 49.18 50.29 18.10 2016 39.67 40.20 14.90 5.88 40.39 40.32 16.89 37.71 40.03 19.72 38.79 40.20 17.89 2017 52.24 51.04 12.28 6.21 51.64 48.87 18.22 50.51 50.70 19.40 49.81 48.80 17.83 2018 57.29 60.00 12.80 5.85 60.77 62.64 13.64 55.38 58.33 18.06 56.18 58.01 16.34 2019 47.68 48.95 10.88 5.19 48.37 50.97 13.80 49.02 53.05 15.56 47.19 49.18 19.32
Table 3 presents the simulated average cycle (daily) profit assuming that the battery storage system knows perfectly the price in advance, and the total number of profitable days with simulated profit higher than the battery wear cost (100 €/MWh). The results show that the average cycle profit is generally decreasing from 2015 to 2019. This is mainly due to the deceasing in both market price volatility and daily price variation. Although it is an ideal case, the battery storage will obtain a significant higher cycle profit when participating in the ancillary services and imbalance correction since the price volatility is much higher for these markets. However, if we take a battery wear cost of 100 €/MWh, even the highest theoretical daily profit considering ancillary services and imbalance cost is far from reaching the break-even point. There are only very few days when the profit of energy arbitrage of battery systems would cover the corresponding battery wear cost in the period under study (2015-2019) even with perfect price information. The reason behind this fact is the current low energy price volatility in Spain which suggests that the power generation capacity would generally cover demand in most cases, and price peaks caused by lack of capacity are rare.
Table 3. Average daily profit and total number of profitable days with perfect price information.
Market and Services Day-ahead market only Day ahead market, Ancillary services, and Imbalance cost Year Average daily profit in € Profitable days Average daily profit in € Profitable days 2015 16.81 0 41.09 1 2016 12.71 0 32.98 2 2017 11.09 0 34.38 1 2018 9.63 0 28.30 0 2019 9.42 0 27.57 1 econdary reserve
In the secondary reserve market, the flexibility requirement is higher than the energy based markets, and the required response time would be less than 100 seconds. When participating in the secondary reserve, in addition to the net energy generation or consumption during the service, the service provider will also receive remuneration in terms of the power capacity band. The secondary reserve is an hourly product for which the auction is exercised the day before delivery day and after the day-ahead market and the management of technical restrictions. The payment for power capacity band can be calculated as the product of the contracted power capacity and its band price, a the payment of net energy is calculated as the product of the net energy deviation with respect to the original program and the energy price of secondary regulation of the hour. Table 4 presents the market information for the secondary reserve market in Spain from 2015 through 2019. The average power band price decreases from 19.57 €/MW to 8.31 €/MW in 2019. The total assignment of secondary reserve band also decreases for the upward band. In addition, an average energy use rate per unit of power band provided is assumed.
Table 4. Market information for the secondary reserve market in Spain. (2015-2019)
Year Band Price in €/MW Total Upward Band Assigned in MW Total Upward Energy Used in MWh Average upward band utilization MWh/MW Total Downward band Assigned in MW Total Downward Energy Used in MW Average downward band utilization MWh/MW 2015 19.58 6002468 1366302 0.23 -4477793 -1193013 0.27 2016 15.56 5989670 1529974 0.26 -4468333 -1012330 0.23 2017 14.26 5970916 1203337 0.20 -4498964 -1206475 0.27 2018 12.56 5400159 1086235 0.20 -4519135 -1506230 0.33 2019 8.31 5203169 970742 0.19 -4352156 -1678825 0.39
The final payments of the secondary reserve are made according to the provided power capacity band (€/MW) and net energy effectively delivered (€/MWh). Table 5 presents the average day-ahead market price, the energy price for secondary regulation. It also shows a calculated average profit/cost of energy, which is delivered in secondary reserve and balanced at the average day-ahead market price. An 85% round-trip efficiency is considered for the battery storage and the energy loss is evenly distributed between charging and discharging phases. Considering the sum of the battery wear cost and profit/cost in energy terms as the effective energy usage cost, the break-even cost for power band price can be calculated as the effective energy usage cost divided by the average utilization rate of the secondary band. In other words, it is only profitable for battery storage systems to provide secondary reserve when the remuneration from the power band is higher than the sum of the battery wear cost and the energy profit/cost. able 5. Profit analysis of delivering energy from battery storage considering the average band utilization. (2015-2019)
Average day-ahead market price in €/MWh Average energy price of secondary regulation in €/MWh Average profit/cost of delivering energy from battery storage in €/MWh Year Upward Downward Upward Downward 2015 50.32 53.71 40.11 -9.79 2.71 2016 39.67 44.09 33.21 -6.10 0.40 2017 52.24 54.60 45.05 -11.23 -0.90 2018 57.29 58.05 50.04 -14.00 -1.68 2019 47.68 51.25 40.63 -8.94 -0.30
Table 6 presents the calculated break-even price and the total number of profitable hours with power band price higher than the break-even price. Given the battery wear cost of today, in 2015, a battery storage system would be theoretically profitable during about 2000 hours providing secondary reserve in both directions. However, due to the significant fall in power band price, in 2019 this number decreased to around 300 hours only in upward reserve. Still, we would like to emphasize the fact that thanks to the payment of flexibility, this number of hours that battery storage is theoretically profitable is much higher than the one resulting from the application of energy arbitrage. In addition, the results show that the competition of flexible resources is fierce in the Spanish electricity market and battery storage technics with the current cost may start joining the competition.
Table 6. Estimated break-even band price and the total number of profitable hours. (2015-2019)
Break-even power band price in €/MW Number of hours with power band price higher than the break-even price Year Upward Downward Upward Downward 2015 24.99 25.92 2099 1880 2016 27.10 22.57 1049 1609 2017 22.42 27.06 1155 691 2018 22.93 33.89 676 237 2019 20.32 38.69 317 10
Other services
Research works have also demonstrated the effectiveness potential participation for battery storage in other commonly applied ancillary services such as primary regulation [25] and 26], solving transmission and distribution constraints [27] and [28], and peak-load shaving [29]. However, battery storage systems are not able to be paid for providing these services currently in the Spanish power market. The primary regulation is currently mandatory and non-remunerable. Transmission and distribution constrains, and peak-load reserve can be only solved by large thermal power plants. And demand-response schemes are provided only for large power consumers.
Market design and regulations
Technological definition and recognition
Theoretically, battery systems may work as a standalone unit in the electricity market and provide ancillary services such as the secondary reserve services, similar to the existing pumped hydro plants. However, one of the important concerns nowadays when developing battery storage projects in Spain would be the lack of related supporting regulations. A new standalone battery storage project may need a permit from the system operator REE if the energy storage system is connected to the grid directly. However, there are no regulations related to battery systems, so a battery storage system does not belong to any existing types of power generating or consuming units. Currently in Spain, almost all the pilot battery systems, that have been installed so far, have been integrated in an existing generation facility, and in most cases, the integration only requires industrial permits, but not REE permits (since the device does not increase the evacuation power capacity and batteries are considered as behind-the-meter storage devices). This kind of integration has its drawback. When a battery system is integrated into an existing power plant, the available power capacity of the battery is limited to the power capacity of the plant. Also, the integrated power plant is normally registered as a power generating unit in this case, the battery is able to absorb energy only from the power plant itself but not from the grid. Moreover, for some special applications such as the secondary reserve, the power deviation from the power plant may cause additional problems since balancing the power deviation with the battery is a prerequisite for providing secondary reserve.
Market design
The lack of recognition of the battery technologies directly implies that the market is not designed to accommodate and encourage a wide deployment of battery storage systems. The electricity grid in Spain has generally relied on dispatchable thermal power plants and hydro power units for supporting system security and providing ancillary services [30]. herefore, market design is considered to be a centralized regulation solution based on large energy groups or large consumers. Power flexibility products are commonly defined using the terminology of thermal power plants and only allow the participation of conventional dispatchable power plants. For example, the technical constrains, including those of for transmission and distribution, are currently solved by thermal power plants. The system operator pays the thermal plant to run at its minimum power capacity in some specific areas where technical constrains exist. In a similar way to the technical constrains, the peak load problem is solved only by thermal power plant with the service of additional upward power reserve, in such a way that the participating generation unit is paid to schedule the minimum capacity in the adjusting market. For secondary reserve markets, the service is offered and liquidated by regulating zones. The regulating zones in Spain are the large energy groups such as Iberdora and Endesa. Since the secondary regulation only requires a minimum respond rate, the participating power plants may response to the order with different speed. This may cause additional difficulties in allocating incomes and costs within the regulating zone, especially in case some of the power plants in the same regulating zone do not fulfill the secondary regulation requirements. On the other hand, the secondary reserve auction only opens once a day after the day-ahead market. This would not cause serious problems for large conventional power plants and/or groups of power plants. However, for distributed energy sources with relatively low power and energy capacity, real-time adjustment measures would be essential. Compared with other European countries, the power capacity from hydro power plants is relatively high and provides a significant part of the ancillary services in Spain. Although different research works have explored the profitability of battery storage systems in primary reserves, it is not expected in the near future that Spain will join the central European primary reserve market or change the non-remunerable structure of the primary reserve, since the cost of providing frequency support from hydro power is relatively low.
Conclusion and discussions
Battery storage systems are expected to be an essential part in the future energy system due to their flexible and distributed nature. In this study, the major barriers to a wide deployment of grid-connected battery storage systems in Spain are investigated. Although the cost of battery systems has been reduced in the recent years, the battery cycle lifetime compared with the installation cost is still the main technological barrier for grid-connected applications. In this study, the results show that the battery wear cost resulting from degradation is still too high compared with the marginal generation cost of other echnologies, and this would prevent battery systems from being profitable in energy-based markets and energy arbitrage applications. Market profitability analysis also claims that under a deregulated electricity market such as the Spanish one, although it might be not completely economically feasible nowadays, higher potential is clearly shown for grid-connected battery systems when more flexibility is required. When competing in local flexibility markets, battery storage systems may present some unique comparative advantages. Compared with the commonly used pumped hydro storage plants, battery systems may offer system flexibility in a distributed and decentralized manner. On the other hand, battery systems are much less limited by the technical restrictions commonly faced by the thermal power plants such as minimum capacity, ramp rate, start-up and shut-down cost, etc. Currently in Spain, both the regulatory and market frameworks are designed based on a centralized power system supported by large power plants and energy groups. As a novel technology, battery storage systems are not able to be operated independently in the market. Again, the lack of awareness and recognition of the technology directly leads to missing of supporting regulations and market products that would address the comparative advantages of battery systems. To summarize, the numerical and empirical analysis suggests that the high cycle cost for batteries is still the main barrier for grid-connected battery systems, and the flexibility offered by such systems would be currently the most promising comparative advantage for this novel technology. Besides providing directly subsidies to the development of battery projects, a correct recognition of the barriers and advantages by all the stakeholders, including the system/market operator, policy maker, investor, and project manager, is the key factor to promote battery storage technologies in grid-connected applications. Future research work should focus on, technologically, reducing the energy equivalent cycle cost for battery systems, and economically, exploring new market design and valuation model that address the flexibility provided by the battery systems. For market and system regulators, more efforts are necessary to reduce the barriers from regulatory framework, promote pilot projects, and design appropriate market products or services that adequately address the flexibility provided by different technologies.
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