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Energy Storage and Management Study


Executive summary

Introduction and Context

Scotland has set a world leading interim target to reduce CO 2 emissions in 2020 by at least 42% compared to 1990 levels. A key part of achieving this is a significant decarbonisation of electricity supply. Hence Scotland has a renewable electricity generation target of 50% by 2020.

These targets will build upon the developing renewable sector in Scotland and some of the best wind, wave and tidal resources in Europe. Utilising these excellent natural resources will mean a large increase in intermittent renewable generation being installed.

High levels of intermittent generation present new challenges to electricity System Operators that have traditionally relied on control of outputs from fossil fuel generation to match demand.

Scotland's position within the GB electricity system with potential constraints in power flows to England (plus the interconnector to Ireland) will result in a more challenging situation than for other countries with high levels of intermittent generation such as Denmark, who are highly interconnected to surrounding countries in Europe. The Scottish Government are therefore keen to understand what role energy storage, demand side management technologies and transmission reinforcement can play in addressing this issue. This study will study is important in identifying the potential balance between reinforcement and storage technologies to address constraints.


This study had four key objectives, these are highlighted below:

1. Evaluate the potential scale of the challenge of having increased shares of intermittent renewable technologies in the electricity generation mix of Scotland. This study has explored this objective by modelling the renewable targets set by the Scottish Government. Three Scenarios have been developed to explore the role that energy storage and energy management may need to play by 2020 and 2030. The Scenarios and the results are presented in section 2.

2. Assess the potential low-carbon technological solutions for addressing the problem of intermittent generation, with consideration to both energy storage and energy management solutions.Section 3 of this report investigates the energy storage technologies available, their current market status and the suitability of the technologies to the Scottish context. Section 4 explores the demand side management solutions available and the role that they could play in dealing with increasing intermittency.

3. Assess the current and potential constraints to developing energy storage and management.Sections 3 and 4 of this report highlight individual technology constraints; these are also highlighted in an energy storage technology matrix provided in appendix 1 that scores each technology against a range of criteria applicable to Scotland. Section 5 of the report summarises the constraints in a concise manner highlighting the key issues identified in the technology review and from speaking to stakeholders involved in the sector.

4. Assess the potential public and private sector costs associated with developing technological solutions.Section 5 and 6 consider the generic costs associated with installing pumped hydro. In addition we consider the regulatory factors and constraints facing the present day energy storage sector in Scotland.

These elements of the study are summarised in the following pages.

Potential Scale of the Challenge

This study considered three Scenarios of future generation in Scotland that were developed to investigate the potential scale of the challenge that Scotland may face from installing increasing levels of intermittent generation.

Scenario 1: Reflects the current targets set by the Scottish Government. It represents a rate of growth for renewables that until recently would have been considered ambitious. Recent market developments and assessments show significantly greater capacity.

Scenario 2: Reflects more recent views on growth rates for renewable energy, with greater growth in the offshore section. This Scenario maintains the same level of demand and thermal generation as Scenario 1.

Scenario 3: This Scenario illustrates growth levels beyond those in Scenario 2 and represents a stress test of the Scottish grid should all planned renewable developments proceed.

In order to determine the role that energy storage measures and potentially demand side management may be able to play in Scotland, the study assessed the impact of Scenarios 1 and 2 on the network flows in Scotland. From this we can determine whether the generation mixes outlined and resulting TWh output present problems that may require energy storage/ Demand Side Management ( DSM) measures.

Using the detailed generation profiles created for Scenarios 1 and 2, the power flows across the Scotland to England boundary have been determined using a half-hourly GB dispatch based on merit order. These flows have been calculated for years 2015, 2020 and 2030.

These flows have been compared with the transfer limits for export and import with the main planned and projected network reinforcements over the period to 2020 (2010 interconnector upgrades, 2012 series capacitors, 2018 West Coast HVDC interconnector and, by around 2020, the East Coast HVDC interconnector).

The results are summarised below, with full details in Section 6.

Scenario 1: Under Scenario 1 the positive power flows from Scotland can be accommodated in 2020 and 2030 - providing the planned interconnection upgrades take place between Scotland and England. This is an important result as it demonstrates that the Scottish grid can accommodate significant volumes of renewables in line with the current targets for 2020 and further growth beyond this without facing problems relating to constraining generation.

Hence in Scenario 1 there would be limited demand for large scale centralised energy storage. There could be a need for localised storage solutions to solve local grid constraints. For example storage connected to a wind farm could lead to improved power flows at a local level. The business case for these would be based on the avoided cost of local grid upgrades - the costs of which are very location specific. However the number of these opportunities and their benefits cannot be assessing using a Scotland level assessment as used in this study.

Scenario 2: Under Scenario 2, which has higher volumes of intermittent generation, demand would be exceeded by supply for 28% of the year in 2030. Even with all thermal generation constrained generation would exceed demand for 15% of the year. This surplus generation is a consequence of installed capacity levels increasing to 21.5 GW by 2020 from 12 GW. In terms of the target of meeting 50 per cent of Scotland's electricity demand from renewables, this is achieved in 2015.

Scenario 2 shows that by 2030 there is a maximum power flow of 13 GW with an excess of 5 GW. At this level of surplus generation pumped hydro is currently the only storage based solution to the problem.

Over recent years the load factors for the current pumped storage stations has doubled compared to the annual average over the period 1996-2004. However, under the Scenario 2 situation the amount of new pumped storage capacity required in 2030 would be around 7 GW, many times the current capacity level in Scotland.

Scenario 3: Scenario 3 has an increase in capacity from 12 GW to 25.5. GW by 2020, increasing to 29 GW by 2030. A large proportion of this increase (15 GW) is driven by an increase in offshore wind capacity. The results show that total Scottish generation output increases to 84 TWh in 2020 and 91 TWh by 2030 compared to current output of around 48 TWh.

Scottish generation output becomes dominated by renewables. By 2020 73% of Scottish generation output is renewable, rising to 88% by 2030, with the majority of renewable output from intermittent sources of generation. In terms of the target of meeting 50 per cent of Scotland's electricity demand from renewables, this is achieved in 2015. By 2020 Scotland is producing electricity considerably in excess of demand. This Scenario shows the outcomes that could occur if all existing plans for generation were realised plus a number of additional developments that could follow on from the recent licensing activity.

In short:

  • Scottish electricity demand is met in all three Scenarios.
  • Demand and export capacity can cope with the generation levels in Scenario 1
  • Excess generation occurs in Scenario 2, where the planned interconnector upgrades are insufficient to cope with the higher generation levels in this Scenario in 2020 and in 2030. These maximum excess generation and the percentage of the year with a generation constraint are shown in the following table:

Table 1 Summary of Scenario 2 Results



Peak excess generation ( GW)

% of Year with Constraint

Peak excess generation ( GW)

% of Year with Constraint

Scenario 2





Assess the potential low-carbon technological solutions

Supply Side Solutions

The study reviewed the leading energy storage technologies and considered their suitability in the context of the scenarios developed for Scotland to 2030. The technologies considered include pumped storage, Compressed Air Energy Storage ( CAES), hydrogen, advanced batteries and flywheels.

Each of these technologies have different storage capacities and response times as shown in the figure below. Hence they can provide different roles in the electricity system. As a result of this variability the potential end uses of the technologies also vary from providing bulk power storage to provide specific distribution line voltage support. Because theses roles differ so greatly, some of the technologies cannot be compared directly with the other technologies.

The results from the Scenarios show that the key role for energy storage in Scotland is large scale energy storage. Hence the technologies that lie in the top the top right hand corner of Figure 1 are the most relevant.

Pumped storage and CAES represent the larger and cheaper storage technologies available but both face significant constraints to site availability. Advanced batteries represent a flexible solution and are also able to provide grid support in remote island communities. However, the present economics and regulatory structure is not conducive to these technologies being installed.

Figure 1: Typical storage capacity versus discharge times for energy storage technologies.

Figure 1: Typical storage capacity versus discharge times for energy storage technologies.

* SMES (Superconducting Magnetic Energy Storage)

A scoring matrix was developed to assess the suitability of the different storage technologies to Scotland, the results of which are presented in the figure below. This found that the most appropriate energy storage technologies in Scotland were,

  • Pumped hydro: existing experience of operation and its ability to deliver large scale energy storage
  • CAES: the only other technology with the current ability to deliver large scale energy storage
  • Flow batteries: highly efficient and able to operate rapidly with multiple discharge and recharge cycle without degradation in performance.

Some of the technologies are more specialised in power quality. These technologies are suited to enabling increasing levels of renewables by deferring or avoiding the costs of transmission/distribution line upgrades. Relevant technologies in this area included Redox flow batteries and flywheels.

Figure 2 Results from the technology scoring matrix

Figure 2 Results from the technology scoring matrix

Demand Side Solutions

With surplus generation at periods of the year DSM will become increasingly important. DSM technologies represent a means to alter the energy demand profile to match generation. Electric vehicles and electric heating have been identified as two key technologies that could be developed further in Scotland alongside the roll out of smart grids and meters. Electric resistance heating represents a very low cost option and this could represent a switchable load of the order of 2,000 MW over an hour. Electric vehicles are projected to become widespread by 2030. At present the charging facilities and options are unclear but the assumptions made in this study found that this could represent a demand of 7,000 MW over 1 hour or 700 MW over 10 hours. DSM can therefore have an important role to play and depending upon the profile of the surplus generation could have the potential to handle a large proportion of the excess.

This study has looked at the economic case for energy storage. The literature review found that few relevant studies provide a useful comparison to the Scottish situation. This reflects that for most of the technologies (with the exception of pumped hydro) very few examples have been demonstrated and trialled at a useable scale and their performance publicly presented.

For pumped hydro we have considered the cost of installation and a 'typical' revenue value required in order to break even. Using two different approaches we found that the cost of constraining renewable generation is less than the cost of installing pumped storage. In addition interconnection capital cost is cheaper than large scale pumped storage.

Therefore there is no need to provide incentives for large scale energy storage as other options appear more cost effective. However, there is a need to address market regulation to ensure storage devices can access the various revenue streams.

Small Scale Solutions

In addition small decentralised energy storage devices will have an important role to play in addressing local grid stability, avoiding the transmission/distribution line upgrades and facilitating greater connection of renewables to the grid.

Examples include fitting a storage system at a wind farm site or within the electricity distribution network. These solutions will provide local benefits such as:

  • Reducing grid connection costs for renewable generation
  • Increasing quality of electricity supply and reducing grid reinforcement costs

These benefits are very specific to the local conditions of the grid network and the generation and demand at the point in the network. Hence the costs and benefits of energy storage can only be assessed at a local and detailed level - which is not possible in a Scotland wide study such as this.

At the current time there are few examples of this type of localised energy storage. While a number of proposals have been developed, few have reached implementation:

  • RWE Npower proposed a utility scale store using redox cells at Little Barford. However this was never commissioned. This was rated at around 10 MW and 20 MWh. It was intended to provide Black Start provision at the 680 MW Little Barford Power Plant as well as frequency & voltage Support for the Grid.
  • The wind farm at Sorne Hill in Ireland proposed a 2 to 6 MW redox store. A study of this suggested the economics were positive. However this proposal was not taken forward.

Siting a store alongside a wind farm and using it to provide arbitrage and smooth the wind farm output may not be the optimal option. The store will realise best value for its operator if it can be sited at a point in the distribution network where it can provide a range of grid support services. However, the current market structure means that it is difficult for a storage device to access the fragmented value chain, as highlighted overleaf.

Scotland's position as a leader in setting and achieving renewable energy targets combined with its specific geography with many island networks means it has the potential to provide a focus for developing and demonstrating a wide range of energy storage technologies across a range of scales. This could bring benefits in both employment and business and should be encouraged.

Assess the current and potential constraints to developing energy storage and management

For large scale energy storage of the scale that Scenario 2 shows may be required there are two main technology options, Pumped Storage and Compressed Air Energy Storage.

There are practical constraints in both cases.

Pumped Storage. This is a well proven technology in use in Scotland and across the world. The two existing Scottish schemes have rated outputs of 300 and 400 MW. The schemes proposed by Scottish & Southern Energy are 300-600 MW. In this study we have used 400 MW as a typical scheme size.

In Scenario 2 in 2020 excess generation is up to 2.8 GW requiring 7 schemes of this scale, rising to a gap of 7.5 GW in 2030, requiring 18 or 19 schemes of this scale if all renewable electricity generate was to be accommodated without constraint.

There are limited numbers of sites for pumped hydro of this scale in Scotland. Proposals for this scale of development would attract significant public attention and debate.

Use of seawater pumped hydro (where the bottom reservoir is the sea) may open opportunities for more sites as less land is affected by the scheme. But the capital costs of seawater pumped hydro are higher and only one small scheme of 30 MW in Japan has been tested.

Compressed Air Energy Storage ( CAES). This is an emerging technology with several large pilot installations. The key constraint is that as suitable storage cavern must be available. This may not be available in Scotland as no specific surveys have been made. Finally CAES burns gas - hence there is a tension between CAES and Scotland ambitions for reducing carbon emissions.

As a result pumped storage is the most suitable technology for large scale energy storage in Scotland.

For small scale technologies there are different constraints:

Firstly the technologies and their costs are not fully mature. Hence their performance and economic results are uncertain and are less likely to meet commercial rates of return.

Secondly the revenues streams are less certain. For small scale systems the difficulty in the GB electricity market is the fragmented value chain (generators, network operators, transmission operators, suppliers all being different companies). Hence it is difficult to realise all the available revenue stream without setting up a series of contractual arrangements and resolving potential conflicts when they arise. In a vertically integrated market (e.g. some US utility companies where they own the entire generation and supply chain) the case for this form of storage is easier to make.

Assess the potential public and private sector costs

The assessment of costs has focused on pumped storage - as this is the key technology identified by the preceding analysis of need.

The costs of pumped storage have been assessed at a high level using two different approaches.

1. A US study on pumped hydro estimates the levelised costs of electricity from pumped hydro at around $400/kW of capacity. Using these results a single 400 MW pumped storage scheme would need to earn about £111 million pa to match costs.

2. A simple assessment of UK energy market conditions suggests a 400 MW pumped storage would have operating costs (excluding finance) of £93 million a year.

A 400 MW pumped storage scheme would store around 911,000 MWh per year. The cost of constraining this rather than storing it would be around £91 million a year (at £100/ MWh).

Hence the cost of pumped storage appears slightly higher than the costs of constraining generation. The costs of pumped storage will change - as electricity prices changes (particularly min and max prices) while site specific investigations may identify sites with lower capital costs.

As a result the case for multiple large scale pumped storage schemes appears marginal - however there may be an economic case for a small number of schemes where the costs are lower than the industry average. There is less likelihood that there would be scope for pumped storage to cover all of the excess generation.


It is concluded that in the short to medium term pumped hydro represents the best storage option to address the potential excess renewable generation in Scotland. However the average costs needed to justify a number of large pumped storage schemes are marginally greater than the value of the excess generation. This will limit the economic case for pumped storage as the only solution to the excess generation as only the lowest costs sites will be economic. Hence increased interconnection, demand side measures and generation constraints will have a part to play in managing the level of generation in Scotland.

The development of the smart grid, increases in technologies such as heat pumps, electric heating and electric vehicle charging offer the potential for low cost demand side response that would reduce the requirements for electricity energy storage. These options should all be developed.

The Scottish Government can both provide financial and other encouragement to such development and work with the energy regulator to ensure that storage technologies across all scales of size are not hampered by the regulatory system and that the various revenue streams they can service are accessible and transparent.

This study recommends that in order to better understand the scale and type of storage technologies required a more detailed modelling analysis is required that will examine the characteristics of excess generation under the high renewable Scenarios. Through better understanding these characteristics the contribution from DSM technologies and storage technologies can be better understood.