Benefits and challenges of energy storage

Electrical energy storage (EES) represents a wide range of technologies, all of which can provide a ‘flexible response’ to the electricity system.

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Jul 25, 2017
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Author: Esther Dudek


The amount of electrical energy storage (EES) deployed within electricity systems worldwide has increased rapidly over the last 5 years, often as part of trials/demonstration projects. This has been driven by an increasing need for flexible resources in energy systems, for example, to complement renewable generation or to improve security of supply. These needs are likely to continue in the future and will stimulate increasing numbers of commercial installations of all forms of EES. EES offers a wide range of benefits to the electricity system, which have been proven by various deployments. However, challenges remain to be addressed, including those in relation to core storage technologies, the market and regulatory frameworks. This article briefly describes the storage landscape, before summarising the benefits offered by EES through a number of case studies. It then explores the remaining challenges and how these are being/could be addressed.

Introduction and background

Electrical energy storage (EES) represents a wide range of technologies, all of which can provide a ‘flexible response’ to the electricity system. This response is achieved by charging or discharging when required, thus increasing or decreasing demand or generation. A range of technologies are available, with different ratings (rate of charge/discharge) and capacities (amount of energy stored). Technologies used as part of electricity networks and example locations, include:

  • Pumped hydroelectric schemes (Dinorwig, UK [1]).
  • Compressed air (Huntorf, Germany [2]).
  • Systems based on thermodynamic cycles, such as liquid air (Manchester, UK [3]).
  • Battery technologies including lithium ion, lead acid and sodium sulphur (see section ‘Benefits of EES’ for example projects in the UK).
  • Flow batteries using a variety of electrochemistries.
  • Flywheels (Stephentown, New York, USA [4]).

EES has been used for off-grid power applications and uninterruptible power supplies for many years. Trials and demonstration projects using EES as part of electricity networks have been underway around the world for various applications since the late 1980s. Many of these demonstrations related to islanded networks, or those with particularly poor quality of supply.

In the UK context, there is an increased requirement for flexible resources within the energy system for a variety of reasons, including:

  • Increasing deployment of intermittent (renewable) generation with variable output, driven by the low-carbon agenda.
  • A requirement to accommodate rapidly changing customer electricity usage on electrical distribution networks, using the most cost-efficient method.
  • Forecast reduction in system inertia due to a reduction in the amount of synchronous generators connected to the system.

Within the UK context, the period from 2010 has seen a rapid increase in utility scale EES deployments. This has been supported by various policy measures and sources of research and development (R&D) funding, including those available from the Department of Energy and Climate Change (DECC), the Energy Technologies Institute and the Engineering and Physical Sciences Research Council. Distribution network operators (DNOs) have explored the benefits offered to their networks from EES systems through a number of projects funded by (the UK energy utility regulator) Ofgem's Low Carbon Networks (LCN) Fund. Fig 1 [5] and Fig 2 [6] show the location of these systems, both geographically and their connection point to the distribution network.

Fig 1: Geographical map of DNO EES systems, showing status in December 2014

Fig 2: Network connection of proposed and deployed storage in the UK (DNO and DECC supported demonstrations, as of December 2014)

Energy storage can address a wide range of applications within the electricity system. Section ‘Benefits of EES’ explores these applications and provides case studies of the benefits achieved from EES deployments.

The large-scale installation of EES on transmission and distribution networks remains a relatively recent development, leading to a number of challenges. These include continuing technological improvements and the establishment of a mature market. Section ‘Obstacles to wide scale storage uptake and potential solutions’ highlights some of these challenges and how they are being/could be addressed.

Benefits of EES

An EES system, comprising a core storage technology and a power conversion system (PCS), can control its power output for both charge and discharge. Different technologies can provide a full range of both ratings (speed of charge/discharge) and capacities (amount of energy stored). Energy storage which is connected using a PCS is able to supply and absorb both real and reactive power. This flexibility allows storage to provide various forms of response, or applications, which offers benefits to different parties within the electricity system.

This section summarises the different applications for storage and illustrates the benefits offered through a number of case studies.

Description of energy storage applications

All applications of EES make use of its ability to charge and discharge at the required time. These applications may be required by different parties within the electricity system (e.g. transmission system operator (TSO), DNO, renewables generators) and they involve different types of response, in terms of the size, speed and duration of the charge/discharge. The main EES applications can be summarised as follows:

  • Energy arbitrage: Essentially the idea of ‘buying low’ and ‘selling high’ – exploiting variations in energy prices across hours and days by charging an energy storage system at times of lowest prices, to discharge when the sale price reaches a peak. The financial return from this mode of operation is dependent on the variation in energy prices, and system round-trip efficiency.
  • Distribution network support: EES systems can be used on distribution networks, mainly for providing thermal or voltage support. They can also be used to aid the integration of renewable energy. These applications are location specific – i.e. a DNO will require EES to be connected in specific locations where constraints exist. Network operators are beginning to procure response services from third parties for this purpose, such as the ‘constraint managed zones’ being established by Scottish and Southern Energy Power Distribution (SSEPD) [7].

    • Thermal support: Assets within the distribution network are subject to maximum ratings which determine the current they can supply. Where peak demand is predicted to exceed this capacity then a solution is required – either providing additional capacity, or reducing the loading. Typically this solution will be the installation of a new asset with a higher rating. However, assets within the power system generally have a high capital cost and long life time (40+ years). Where future loading is uncertain, EES can provide an alternative solution, by operating at peak times. This solution can either be used as a long-term option (until the end of the original asset's service life) or a short-term solution until asset replacement/other reinforcement is carried out or the power flow decreases.
    • Voltage support: Distribution networks must operate within statutory voltage limits. Voltage varies in time and along feeders [e.g. lowest at peak demand and (conventionally) furthest from a substation]. Different scenarios may cause the network voltage to stray outside of these limits. For example, embedded generation [e.g. residential photovoltaic (PV)] could cause an increase in voltage. EES offers one solution to voltage issues, by injecting or absorbing real and/or reactive power. Using reactive power does not affect the state of charge of the battery, and so continuous reactive power adjustment can be used.

DNOs have trialled the installation of energy storage at various points on their networks through LCN Fund projects. For example, within the Customer Led Network Revolution (CLNR) project [8], Northern Powergrid procured six systems (EES1 – 1 off 2.5 MVA/5 MWh, EES2 – 2 off 100 kVA/200 kWh and EES3 – 3 off 50 kVA/100 kWh). These were installed at different locations within the Northern Powergrid network [9] (see Fig 3) and their ability to provide thermal and voltage support was investigated.

  • Constraint management: The ability of the electricity network to accept new connections for either load or generation is limited, e.g. by thermal or voltage issues. This can increase the cost of connection due to the need for network reinforcement. Alternatively, ‘constrained’ connections can be offered, which limit the output of the site to the real-time capacity available on the network. However, this reduces the generator's revenue due to the ‘lost’ constrained energy.  EES can be used by renewable generators to store energy which would otherwise be ‘lost’. It can then be discharged when the generation output has reduced (i.e. an ‘unconstrained’ time). The type of storage used and whether it offers a viable solution will depend on the relative length of the ‘constrained’ periods, as the storage requires sufficient capacity to store the ‘constrained’ energy and enough time to discharge again between constrained periods.
  • System balancing services: The TSO (National Grid in the UK) is responsible for ensuring supply and demand for electricity are kept in balance at all times across the Great Britain (GB) transmission system. To achieve this they procure various ‘balancing services’:
    • Frequency response is used to help maintain system frequency within the limits of ±1% of 50 Hz. This requires a high power, quick response, delivered for multiple minutes. The speed of response available from some EES systems when compared with traditional, mechanical plant is particularly beneficial. For this reason, a new service, ‘enhanced frequency response’ (EFR) was launched in 2015, for providers who can respond in 1 s or less [10].
    • The TSO also uses reserve services to provide additional generation, demand reduction or additional demand to deal with unexpected increases in demand, generation unavailability or excess generation. The services most applicable to energy storage are fast reserve (50 MW+) and short-term operating reserve (STOR) [11].
  • Avoidance of imbalance charges: Energy generators and suppliers declare a ‘position’ to the energy market, indicating how much energy they will sell/buy in each half hour settlement period. This is based on complex predictions. If generators/suppliers have a net deficit of energy (e.g. due to a wind forecasting error, or increased demand) they must pay the system buy price, which can be significantly higher than the market price. A supplier or generator with access to EES could use the system to minimise periods during which they are out of balance. They could also submit offers and bids to the balancing mechanism and receive revenue for this.

Fig 3: Connection of EES within the CLNR project. Source: Northern Powergrid

These applications are relevant to different parties within the energy system who may own, operate or contract energy storage services, as shown in Table [12].

Energy Arbitrage✓ (via PPA)✓ (via PPA)
Peak Shaving/Thermal Support(accessed via the market)✓ (via PPA or contract with DNO)
Voltage Support✓ (contract with DNO)
Constraint Management(accessed via the market)✓ (contract with generator, DNO or TSO)
System Balancing Services✓ (contract with TSO)
Avoidance of Imbalance Charges✓ (contract with supplier or generator)

PPA, power purchase agreement.

Table 1: Mapping of EES application to electricity actors

Clearly, a greater financial return is available to energy storage owners/operators if multiple applications are exploited, potentially by providing services to a number of parties. This requires management of potentially conflicting requirements and the development of suitable contracts with those requiring services such as the DNO and TSO.

Case studies

This section provides three examples of systems providing some of the benefits described above.

Distribution network support: integration with renewable generation

SSEPD installed three 25 kW, 25 kWh single-phase EES systems (green units in Fig 4) on a low-voltage feeder in Slough, as part of an LCN Fund project. Ten ‘zero carbon’ homes [13], including 65 kW of PV generation were also supplied from the feeder.

Fig 4: Three single-phase, 25 kW, 25 kWh EES systems, Chalvey. Source: EA Technology

In this example, EES was used to ensure that no reverse power flow occurred from the low-voltage to the high-voltage network – i.e. demand was not lower than zero during the day. Reverse power flow can increase the size of voltage fluctuations on the network, and hence increases the potential to exceed statutory limits. Reverse power flow occurs when generation exceeds demand, which can become commonplace on lightly loaded feeders with large amounts of renewable generation.

In this example, the unit was set to prevent demand <0 kW during the day. Without the EES (blue trace in Fig [14]) this would have occurred between 09:00 and 17:00. By charging the EES, the resultant demand at the transformer (red trace) was around 0 kW throughout this period, as the unit stored the excess generation. After 18:00 the EES unit was used to limit demand to 3 kW, therefore the demand with the battery (red trace) is less than that without (blue trace).

Fig 5: Using EES to prevent reverse power flow. Source: SSEPD

Constraint management

redT [15] have received funding from DECC to develop a 105 kW, 1.68 MWh vanadium redox flow cell energy storage system. This system will be installed on the Isle of Gigha during 2016, alongside four existing wind turbines (total maximum output of 1.1 MW). At the outset of the project the fourth turbine (rating of 330 kW) was constrained to 225 kW and no further renewable generation could be connected on the island. Over the lifetime of this turbine, the ‘constrained’ (‘lost’) energy was estimated to be around 3 GWh, with a value of £300k at today's prices. The primary application of this system is therefore to reduce the constraint on the fourth turbine.

Fig [16] illustrates the way in which the EES could store ‘constrained’ energy on Gigha. The dashed red line shows ‘wind potential’ – i.e. the modelled wind generation output over a 4-day period, without the constraint. Without EES, wind output from the fourth turbine is limited to 225 kW and so on the second day energy would be ‘lost’. The dashed purple line shows the captured wind generation with EES present. On the second day the black line shows the storage charging with the ‘constrained’ energy for around 18 h. After this the store becomes full until it is discharged when wind generation falls at the start of the fourth day.

Fig 6: Using EES with renewable energy for constraint management

System balancing services

UK Power Networks deployed a 6 MW, 10 MWh lithium-ion EES system at Leighton Buzzard primary substation (shown in Fig 7) to defer traditional reinforcement that would entail the installation of a third overhead line circuit. The project is also trialling the multi-purpose application of storage in order to maximise the value of the benefits provided. This includes using the system to provide system balancing services, specifically STOR and firm frequency response [17].

Fig 7: 6 MW, 10 MWh EES system, Leighton Buzzard. Source: UK Power Networks

In Fig [18], the EES responded to a low-frequency event. The red trace shows a drop in system frequency at 04:16. The system responded to this event by immediately lowering the system setpoint to a 3 MW discharge (green trace). The EES then discharged 3 MW active power for 30 min (blue trace).

Fig 8: Low-frequency response event. Source: UK Power Networks

Obstacles to wide scale storage uptake and potential solutions

Globally, the number of deployments of EES systems has increased substantially over the last 10 years, both through R&D trials and commercial installations. Trials have proved the benefits across various applications and have sought to address some of the challenges associated with the use of new technologies within the energy system. However, some challenges remain, and others become more pertinent as EES seeks to move from R&D trials, to mass commercial deployment. This section describes these challenges and the ways in which they are being/could be addressed.

System lifetime costs

The successful commercial deployment of EES requires the revenues earned over the life of the system to exceed the costs associated with installation and operation. These costs are dependent on various factors including:

  • Capital costs: Capital costs of the core storage technology remain high, despite recent decreases. The costs depend on both the technology (e.g. due to materials used, manufacturing costs or commercial maturity) and the size and rating required. When procuring EES, a compromise will be required between the applications to be served and therefore potential revenue, and system size. For example, in Fig.  a larger capacity would allow more ‘constrained’ energy to be captured, thus increasing revenue. However, this increase in capacity would also increase capital costs.

  • Site and network connection costs: These costs include procuring a site, obtaining permissions, site works and connecting to the electricity network. The cost of these vary depending on factors including:
    • Choice of technology and system capacity, as this affects the size of site required and potentially the environmental permissions required.
    • Type of area (e.g. industrial estate vs. street furniture in residential areas).
    • Type of housing (containerised vs. purpose built building).
    • Connection costs, which will depend on the local distribution network, size of connection requested and the cost of any necessary reinforcement (see section ‘Connections’).

As some applications are location specific, a balance must be struck between the costs of deploying storage in these locations and the additional revenue available.

  • Operation and maintenance: These costs depend on factors including technology choice, supplier, insurance requirements, security and any support contract implemented. The costs associated with ‘parasitic loads’ also form part of the operational costs. Parasitic loads include heating, ventilation and air conditioning, or self-discharge of a system with a low utilisation.
  • Decommissioning and disposal: These costs are less certain, due to the relatively ‘new’ nature of utility scale EES. Decommissioning and disposal is likely to involve a recycling cost associated with the core storage technology and potentially returning the installation site to its previous condition.

Cost reductions are likely to be achieved as the market for energy storage grows, both through economies of scale and increased competition as more vendors enter the market.

Deployment and operational costs are likely to fall as a result of learning from early installations. This may include a reduction in the amount of third party contracted support required, or further optimisation of operational modes (e.g. reducing parasitic loads).


The energy industry is heavily regulated, particularly in the areas of distribution and transmission, partly due the natural monopolies that exist. The regulatory structures put in place in the UK since privatisation did not envisage the potential role which EES may play in the energy system. For example, legislation considers ‘demand’ and ‘generation’ as separate entities, without consideration for technologies which may act as both, such as energy storage. EES therefore challenges these existing regulatory structures.

As part of ‘Smarter Network Storage’, UK Power Networks have identified the legal and regulatory barriers to storage deployment on GB distribution networks and how these could be addressed. They have comprehensively reviewed the barriers and consulted with the wider industry and Ofgem. Their report provides detailed recommendations on the way in which these barriers could be addressed. The barriers identified by UK Power Networks [19] can be summarised as:

  • Treatment of EES as a subset of generation.
  • ‘Unbundling’, which requires the legal, functional and accounting separation of electricity distribution, supply and generation adds uncertainty to the deployment of storage by various parties.
  • Operation of storage assets is affected by the need to ensure that competition in generation and supply is not distorted. This requires a DNO storage owner to contract with a third party to handle energy flows.
  • Treatment of import (i.e. charging) as end consumption under climate change, renewable and low-carbon supplier charges increase operating costs for all storage operators. These charges are effectively paid twice, as the final consumer of the discharged energy will pay charges on their imported energy.
  • Differences in DNO charging methodologies (set according to voltage at point of connection) significantly impact operational costs for storage operators. This may inadvertently incentivise the connection of storage at higher voltage levels, even where this may not provide the greatest system benefit.
  • Connections and distribution charging agreements for storage require optimisation in order to support wide scale adoption.
  • Existing methods do not support the recognition of the reactive power capabilities of EES and other power electronic grid interfaced energy resources.

DECC have announced [20] an intention to consult on how to integrate EES into the regulatory landscape.

Addressing the regulatory and legal barriers is crucial to ensure the benefits of storage are properly recognised, EES is not subject to disincentives due to its unclear status and can be deployed by a variety of actors within the energy system, as appropriate.

This is key to ensuring that those deploying storage have sufficient certainty to make investment decisions. Without the appropriate regulatory framework the mass, commercial deployment of EES may be constrained – increasing costs associated with reducing carbon emissions.


As the potential revenue available from owning/operating EES increases (e.g. due to new flexibility services such as EFR), an increasing number of parties have an interest in procuring a system. Those deploying EES need to ensure they optimise the system installed (its technical characteristics of capacity and rating), its location (cost of connection and revenue streams available) and the commercial model used. This can present challenges in understanding likely project costs and potential revenue streams, and running a procurement exercise, including developing a specification.

The relatively ‘new’ nature of the EES market and the rate of change is the principal cause of challenges in procurement. For example, there is currently a lack of relevant standards for utility scale EES which can be included within specifications. This then requires a potential owner/operator to develop a much more detailed specification, increasing the complexity of the procurement process and potentially limiting the responses received from the market.

In addition, as the UK market is still developing and many suppliers are based overseas there can be a lack of experience of UK requirements within the supply chain, requiring additional liaison between the equipment supplier and those procuring storage. Limited UK deployments also make it more difficult for suppliers to cite comparable reference installations when responding to tenders. For those procuring EES this can be seen as an increased risk.

Potential solutions in this area include the development of standards which are relevant to utility scale systems (see section ‘Safety’). Market maturity (e.g. increasing owner/operator experience of procuring EES, and suppliers who routinely install systems in the UK) will also address these issues. However, in order for this market maturity to be reached, other barriers must be addressed – particularly those in relation to system cost and regulatory environment which prevent the creation of a viable business model.


By their nature, EES systems have the potential to contain considerable amounts of energy, with the related safety hazards of the release of this energy during system failures or safety incidents.

The specific failure modes of each technology vary depending on their mode of operation and the chemicals involved. Different technologies therefore present different hazards, such as mechanical hazards from those involving rotating machinery or potential for DC electric shock from a battery or flow cell.

Each installation of EES must address the issues relating to the technology deployed in a way which is appropriate for the site in question. This will generally involve a systematic review of the hazards and risks presented, and appropriate mitigation measures. These mitigation measures may either be part of the system design (e.g. cell chemistry limiting potential for thermal runaway) or associated systems/processes (e.g. an isolation procedure for those working on a battery system).

The challenges relating to safety and energy storage mainly arise due to its relative immaturity at grid scale, for example:

  • 1st of a kind’ issues: The deployments within the UK to date were often novel, such as the first grid scale EES system installed and operated by a network operator, or the first of a particular technology. This requires the development of new procedures and documentation, e.g. training of staff on the relevant hazards, isolation and emergency procedures and risk assessments.
  • Codes and standards: A wide variety of codes and standards are applicable to EES systems at different scales (e.g. overarching legislation such as the Health and Safety at Work Act, or standards applicable to particular storage mediums, at a cell level). However, due to the rapid technology developments within the field, codes and standards have not always kept pace. For example, the British Standard applicable to grid scale EES [21] references its applicability to lead-acid and nickel–cadmium systems only.

The challenges in relation to safety have been met in existing deployments of EES systems, and the work of DNOs in the UK has allowed these systems to be integrated into DNO safety procedures.

Industry collaboration has proven beneficial in this area. During the LCN Fund EES projects, the GB DNOs and TSO worked together in the Energy Storage Operators’ Forum (ESOF). ESOF, run by EA Technology, allowed the industry to share their approach to safety management and other issues, and learn from each other. ESOF consolidated this information into a Good Practice Guide [22] in order to provide a reference guide for others deploying EES.

Work is underway at an international level to develop standards against which EES can be specified. This includes IEC TC-120 [23], whose remit is to consider the need for standards relating to EES systems.

As technologies and storage markets mature, it becomes impractical to perform a detailed safety case review for each installation. Instead, contractual relationships between supplier and customer, conformance with international standards and operator familiarity should ensure that appropriate risk assessment and mitigation can be performed in a more routine manner and mainly considering any particular site-specific issues.


Apart from niche, ‘off-grid’ applications, EES systems require a connection to the public electricity network. Before installation, the EES owner/operator must submit an application to the relevant DNO/TSO detailing the connection required including maximum import and export of real and reactive power. This is used by the network operator to model and approve the installation to ensure it will not risk the ongoing stable operation of the network.

When assessing connection applications, a DNO/TSO conventionally makes conservative assumptions in order to protect network stability. However, in practice, EES operators are likely to operate the systems in a manner which supports network stability (e.g. exporting at peak times and importing when renewable generators are exporting). Potential solutions include the use of flexible connection agreements to prevent modes of operation which would be damaging to the networks stable operation, whilst allowing storage to connect and operate in beneficial ways. Customers, DNOs and TSOs are working to assess how complementary operating modes (e.g. discharging storage at times of peak demand) can be reflected in quicker and cheaper connections, where appropriate.


The period of R&D EES projects in the UK over the last 5 years has proven the full range of EES applications, and there is an increasing trend towards commercial (i.e. non-R&D) installations. Future developments in the field are likely to focus on addressing the challenges outlined in section ‘Obstacles to wide scale storage uptake and potential solutions’. For example, developments such as incremental changes in technologies or new storage mediums could lead to decreased costs or improved safety characteristics. The market for storage will also mature, both in terms of the market supplying EES installations and the markets in which storage will operate. Those supplying EES installations are likely to have increasing familiarity with the UK market, greater numbers of reference installations and an ability to specify their products against relevant standards. The market is also likely to change, possibly addressing potential conflicts between different revenue streams and removing regulatory barriers. In order to facilitate the connection of larger amounts of energy storage, a streamlined connections process will be required – this is an area of potential industry collaboration within the DNO/TSO sector.

Utility scale energy storage, particularly in the UK, is at a tipping point with commercial installations becoming more common. Modelling of the future energy system has estimated that substantial cost savings can be achieved through the deployment of flexible solutions including storage. Significant investment has been made in R&D activities proving the feasibility of EES installations and the benefits available. The barriers to wider storage deployment should therefore be addressed, in order to allow this technology to realise its full potential.


PPA, power purchase agreement


The author acknowledges the contribution of those organisations who have allowed their projects to be included as case studies, and UK Power Networks for their work on the regulatory barriers to energy storage.


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Go to the profile of Esther Dudek

Esther Dudek

Senior consultant, EA Technology

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