Energy storage regulation in the United Kingdom

1. What electricity storage projects have been commissioned in your jurisdiction to date?

There are currently four operational pumped hydro storage projects in the UK with a combined capacity of over 2.8 GW, the last of which was commissioned in the 1980s. These projects principally provide for time-shifted electricity supply capacity and spinning reserve capacity and, whilst originally developed by the then state-owned electricity company, are now owned by commercial companies.

More recently, industry participants have been turning their attention to battery storage technologies. One distribution network operator (“DNO”), UK Power Networks, commissioned a 6MW/10MWh lithium-ion battery storage project in Leighton Buzzard in October 2014, with the help of funding from the regulator, Ofgem, through the Low Carbon Networks Fund. This project has been pioneering in demonstrating that grid-scale battery storage is viable in the UK and has raised industry and public awareness of this storage technology.

AES’ 10MW battery array became operational in January 2016 and utilises the company’s Advancion technology. This battery storage project is co-located with the coal-fired Kilroot power station in order to optimise its efficient operation. This project is fully commercial and creates no additional cost for consumers.

There are many smaller storage projects installed, in particular lead-iron and lithium-ion battery storage projects installed by DNOs for grid-reinforcement reasons or on islanded networks.

2. What electricity storage projects are anticipated in your jurisdiction in coming years?

Larger-scale standalone grid-scale battery storage is the “hot topic” in the UK currently, with lithium-ion technology being an area of focus. National Grid, the system operator, has very recently completed a tender for enhanced frequency response services (for details please see below) that is particularly well suited for battery technology. The initial tender awarded contracts to the following energy storage bidders and projects:

EFR Winners

Project capacity (MW)

EDF Energy Renewables




Low Carbon


Low Carbon




Element Power






Total MW


The enhanced frequency response services are required to be provided from 1 March 2018.

Co-location with generation (particularly renewables) is also high on the energy storage agenda. Earlier this year, Western Power Distribution, a DNO, signed a contract with RES (a renewable energy company) to deliver an energy storage system co-located with a 1.5MW solar farm. This project aims to demonstrate the network services “solar + storage” can provide behind-the-meter to the owner and operator of the solar farm and to DNOs. The project will be supported by Ofgem in its Network Innovation Allowance programme.

There are a number of pumped storage projects (ranging between 100 – 600MW) currently proposed by various utilities and developers. However, these projects face particular financing challenges, given the infrastructure-heavy nature of the technology.

There are many other anticipated projects, including an increase in the uptake of battery storage at a domestic level and applications to reduce the demand charges of large energy users.

3. Is there any specific legislation/regulation or programme that relates to energy storage in your jurisdiction?

Electricity storage is not separately defined in the GB legislative framework. For historical reasons, it is currently deemed to be generation for the purposes of licensing under the Electricity Act 1989. As a result, projects over 100MW (currently only the existing pumped-hydro developments fall into this category) must hold a generation licence. Holding a generation licence places a number of obligations on the licensee, such as compliance with the Grid Code.

Whilst the Department of Business, Energy & Industrial Strategy (“BEIS”) and Ofgem have been supportive of energy storage and recognise the benefits and flexibility provided by the various technologies, there is no specific legislation on or regulation of storage at present. No specific subsidy or Government commitment to a level of deployment of electricity storage is expected. As a result, developing a viable business case is more complex than has been the case for renewable generation technologies. This can require the “stacking” of multiple revenue streams, such as ancillary services revenues, capacity market payments, Triad benefits and other embedded benefits.

There is certain funding available for research and development purposes, for example the Low Carbon Networks Fund administered by Ofgem.

National Grid recently ran the first tender for a new ancillary service, enhanced frequency response (“EFR”). The tender has been hugely popular with over 1 GW of proposed capacity pre-qualifying, much of which is from utilities and developers looking to develop standalone battery storage projects. Whilst the tender is technology agnostic, it was of particular interest to stand alone battery storage, as the service is required to be provided within one second (or less) of registering a frequency deviation. The successful bidders secured contracts with an average price of GBP 9.44/MW of EFR/h. The EFR contract has a term of four years and requires developers to meet development milestones and pass a commissioning test prior to the project being eligible for availability payments. It is expected that three tender rounds will deliver 600MW of EFR services.

4. Please give examples of challenges facing energy storage projects in your jurisdiction and how current projects have overcome these challenges.

The challenges for new standalone energy storage projects are as follows:

  • revenue uncertainty – the contract terms available for many of the available revenue streams are short in duration; at four years, the term of EFR contract is the longest. As a consequence, projects have to manage greater revenue uncertainty over the lifetime of the project. The current review of embedded benefits has increased this revenue uncertainty. Further, a number of benefits that energy storage projects can offer, such as the deferral of network reinforcement, are not yet formally monetised;
  • higher operational costs – where an energy storage device imports electricity from the transmission or distribution system, it is charged as if the storage device is an “end-user” for the purposes of the Renewables Obligation, Contract for Difference, and Feed in Tariff charges. This is despite the same electricity being exported back on to the system at a later point for use by a true energy end user. The position is similar in relation to the Climate Change Levy (“CCL”); however, HMRC (the UK tax authority) has waived CCL charges on individual projects. Storage projects can also face double-charging in respect of use of system and connection charges; and
  • distribution licence restrictions on DNOs – the distribution licence places further restrictions on DNOs:
    • firstly, a DNO is required to “manage and operate the distribution business in a way that is calculated to ensure that it does not restrict, prevent, or distort competition” in the electricity or gas market. The operation of energy storage assets by a DNO could impact on the competitiveness of the electricity market. As a result, to date, DNOs have contracted with third parties to handle the energy flows in order to demonstrate licence compliance, adding further cost and structural complexity to such projects; and
    • secondly, there are “de minimis” restrictions on DNO licensees conducting non-distribution related business. This “de minimis” is set at 2.5% of the DNO business revenue or the DNO’s share capital. As a result, there is currently a cap on the extent to which DNOs can be directly involved in energy storage.

Co-located projects can also face additional challenges, for example ensuring that the project remains eligible for renewable benefits such as the Renewables Obligation.

To date these challenges have been overcome by the use of the available research and development funding and the scale of projects being such that they do not meet the DNO restrictions requirements identified. The Government intends to consider the removal of some of the additional costs and regulatory barriers that such projects incur in a Call for Evidence expected by the end of 2016.

5. What are the main entities in the electricity sector and what are their roles or expected roles in relation to energy storage?

Electricity storage falls within the remit of BEIS. BEIS is supportive of the development of electricity storage with a consultation regarding the removal of barriers to its deployment expected shortly. Nevertheless, as stated above, a specific subsidy for storage is not currently expected. The newly formed National Infrastructure Commission emphasised the central role that the Government expects electricity storage to play in the move to a smarter electricity system.

Ofgem is the relevant regulator for electricity storage, though as noted above there is no specific storage regulatory regime. Ofgem has recognised that there are regulatory changes required to enable the full commercial development of storage and it has committed to working with other stakeholders to consult on such changes. However, Ofgem has indicated that it is not minded to reform the restrictions on the participation of DNOs in the electricity storage market.

National Grid is the system operator in Great Britain, which procures various ancillary services, including EFR (as described above). Such ancillary services provide key revenue streams for energy storage.

The DNOs have been pioneering storage with research and development funding, such as the Low Carbon Networks Fund. However, as identified above, their future role in the development of electricity storage is uncertain given the licencing restrictions currently in place.

It is expected that other utilities and independent developers will be at the forefront of the deployment of grid-scale electricity storage in the UK.