Energy UK – Written evidence (LES0040)


About Energy UK

Energy UK is the trade association for the energy industry with over 100 members - from established FTSE 100 companies right through to new, growing suppliers, generators and service providers across energy, transport, heat and technology.


Our members deliver nearly 80% of the UK’s power generation and over 95% of the energy supply for 28 million UK homes as well as businesses.


The sector invests £13bn annually and delivers nearly £30bn in gross value - on top of the nearly £100bn in economic activity through its supply chain and interaction with other sectors. The energy industry is key to delivering growth and plans to invest £100bn over the course of this decade in new energy sources.


The energy sector supports 700,000 jobs in every corner of the country. Energy UK plays a key role in ensuring we attract and retain a diverse workforce. In addition to our Young Energy Professionals Forum, which has over 2,000 members representing over 350 organisations, we are a founding member of TIDE, an industry-wide taskforce to tackle Inclusion and Diversity across energy.



Medium and long duration storage (LDES) could play a range of roles (maintaining system stability, balancing supply and demand, easing constraints, managing outages and creating value for surplus renewables output) over durations of a few seconds to multiple years. In these roles, storage will compete with other technology classes (with demand response and interconnection for shorter durations, and low carbon dispatchable power over longer durations) and between the different durations of storage. The system need will change as variable renewables increase, demand becomes more flexible, and in-line with the buildout of networks and low carbon dispatchable power, and the reduction in conventional power.


LDES is capital intensive with long lead times with many options at a nascent state. As the Call for Input acknowledged, LDES at sufficient scale will not emerge without support (market signals based on unpredictable, high impact events will lead to under-provision). By 2030, there could be 100GW of variable renewables with supply exceeding demand half the time. Where output cannot be used (to meet immediate or time-shifted demand), exported or stored, it will increase rather than reduce system costs (generation will be curtailed to avoid networks constraints). Whilst it is hard to ascertain ‘how much’ storage might be necessary or optimal, it is clear is that insufficient storage will lead to inefficiencies and higher system costs. Timely decision-making is required to mitigate this risk.


Energy UK recommends that Government provides greater clarity on the storage that might be required at different milestones to fulfil different system needs and progress relevant routes to market. The modelling data should be made public so that industry can help refine the estimates as the future system becomes clearer.



  1. How much medium- and long-duration energy storage will be needed by 2035 and net zero by 2050, and by when will it need to be ready?


There are two challenges for predicting the amount required:

i)                    Overall volume of +4-hour storage required

ii)                   Definitions of ‘medium’ or ‘long’ duration storage


i) The overall Volume of +4-hour Storage required

The 100GW of variable renewables was not factored into the modelling for the Government’s 2021 Smart Systems and Flexibility Plan, therefore the 30GW of low carbon flexibility estimated here (which includes storage, demand side response and interconnection) looks much too low.


Modelling by Aurora Energy (Jan 2022) suggests that 46GW of electrical storage might be needed by 2035. 24 GW / 48 TWh[1] would be over 4 hours with most (22GW) classed as ‘medium’ (4 - 48hrs) and only 2GW as ‘medium/ long’ (+48 hours). This suggests a market eight times current capacity for ‘medium’ duration but a smaller (albeit vital) market for ‘long’ duration. This is similar to the Future Energy Scenarios range of c.18GW to 30GW for 2030 and 34-60GW for 2050 (excluding vehicle to grid). Afry assumes a more limited role for storage (12-17.4TWh by 2050) as their model suggests that hydrogen/ gas CCUS could be a lower cost route to closing supply gaps (where generation and network build-out allows). In contrast, a new Royal Society report uses multiyear (37 year) weather data to suggest a much greater need for LDES (up to 100 TWh by 2050). Whilst ‘long’ has a more distinct role, the value/ role of ‘medium’ is dependent on providing services (balancing, ancillary services, alleviating congestion etc) at a lower cost than alternatives.


ii) Definitions of ‘medium’ or ‘long’ duration storage

Whilst there is consensus that ‘short’ duration is able to store/ discharge energy for up to 4 hours, there are differences on ‘long,’ and ‘medium’ duration. This Afry blog Why the definition of long duration storage is important covers the debate well. Whilst the boundaries are porous, the categories help to differentiate the different technologies that tend to predominate at different durations (and highlight why a one size fits all approach is unlikely to be sufficient). Whilst short-term energy storage is dominated by lithium-ion batteries (chemical storage), ‘medium’ duration technologies tend to be mechanical or thermo-mechanical (pumped hydro, liquid or compressed air - flow batteries are an exception). Longer durations require energy to be converted to a gas (such as hydrogen) for storage (then back to electricity).



Key definitions:


Competition within storage classes

In future, it could be feasible for short duration technologies, working in tandem, to cover a ‘medium’ duration gap (e.g. 12-hours). Similarly, long duration approaches could be used for both system adequacy (‘long’) and system balancing (‘medium’). Whilst there will be overlap, care is needed to ensure that competition drives lower overall system costs. Without effective competition, there is a risk that technologies with potential to cover the ‘medium’ duration at the lowest overall cost are crowded out by technologies at either end of the spectrum (that are already viable in other markets or supported for system resilience).


1.1 Under what scenarios would the grid draw heavily on long-duration storage? How well are these scenarios understood?


If defined as +200 hours, ‘long duration’ is used to balance inter-seasonal variation in heating/ cooling demand and ensure resilience (wind droughts, interconnector failure). LCP Delta analysis highlights that in a wind-driven system, most excess and shortfall supply events will last more than 24 hours and require the system to be resilient to prolonged periods of low wind such as ‘wind-droughts, as well as inter-seasonal difference.This contrasts with solar-dependent grids (for example, Spain) where imbalances are generally less than 24 hours and more amendable to batteries, demand response and interconnectors. The resilience deemed appropriate (a trade-off between risk and cost) is, to some extent, a political decision.


1.2 What is the range of estimates for likely electricity demand in 2035?


Demand could vary significantly depending on, for example, how transport and heat are decarbonised. The National Grid Future Energy Scenarios estimate a 340TWh and 410TWh range for 2035. As well as demand quantity, storage requirements will depend on where/ how large electrical demands such as electrolysers, Direct Air Carbon Capture and Storage (DACCS) and data centres are sited. If sited where capacity is available or connected alongside flexible assets, these could compete with storage on balancing. However, without strategic planning, they could increase system stress and demand for storage.


  1. How sensitive is the amount of storage needed to assumptions about the future balance of supply and demand on the grid?


Very sensitive – please see our response to Q1. However, whilst volumes required will vary, the need for storage is driven by the shift to a renewables-led system.


2.1 What role could nuclear power, fossil fuel generation with carbon capture and storage, or other technologies, play in reducing the need for energy storage?


A diverse mix with sufficient storage will deliver the most cost-efficient solution. Gas generation paired with low carbon gas or CCUS is expected to play a significant role for many years. Nuclear power provides firm power that will benefit from energy storage. With higher nuclear and renewables, output is likely to frequently exceed demand. This suggests a larger role for storage to ensure that, where output cannot be exported or used to meet time-shifted demand, it creates system value.


2.2 What role could greater grid interconnectivity between Great Britain, Northern Ireland and other nations play in addressing imbalance?


Greater grid interconnectivity can play an important role in helping to balance the future system. The ambitious targets for set out in the British Energy Security Strategy will make Britain a net energy exporter. Interconnectors will be especially valuable with countries with different power systems (for example, France’s nuclear and Norway’s hydro-based grids) as the power will compliment rather than compete. However, there are risks - where weather is correlated (low wind over a large area) imports may not be available as required (or be expensive). These risks have been exacerbated by Britain’s exit from the EU which has created inefficient market-price signals that, at times, exacerbate constraints and peak demand.


2.3 What role could demand-side management of electricity play?


Energy efficiency would reduce the overall ‘size of the problem’ in the long-term.

Demand side response (DSR) directly competes with ‘short-duration storage. Implicit’ DSR, where a customer is incentivised by cheaper off-peak electricity to time shift electrical loads on an ongoing basis (via a time-of-use tariff) flattens or realigns demand. At scale, this could align demand better with low carbon power, reducing the need for storage. Explicit DSR, where a customer is incentivised to change their behaviour in response to a particular event, will also reduce the need for additional supply (generation or storage) to step in to bridge the gap, (as with NGESO’s Demand Flexibility Service). Whilst a system with smoother demand patterns would be less challenging to manage, more flexible demand may not significantly change the level of ‘long’ duration storage that could be required to back up the system.


2.4 What impact will future climate change have on demand?


Climate change will alter demand profiles. For example, warmer summers will lead to an increase in air conditioning loads, but an increase in rooftop solar generation may balance out this impact. Without a strategic and forward-looking approach to delivery it is uncertain what impact this will have in the UK.


  1. Which technologies can scale up to play a major role in storage?


As an emerging area, it is important that there is a route to market for both existing and new/ emerging technologies and an effective means for them to compete. As LDES will be needed before a high (60%+) penetration of renewables, a stronger focus on supporting First of a Kind (FOAK) technologies could accelerate deployment here (and build from Government’s Longer Duration Energy Storage Demonstration).


3.1 Which timescales for storage are different technologies most suited to? Is there a preferred technology for medium-duration and long-duration storage?


Please see our response to Q1.


3.2 What are the technology readiness levels for storage technologies?


Pumped hydro is an established technology and Highview Power are starting to deploy liquid air energy storage (LAES), providing storage of 12-hours duration on a commercial basis. However, most options are emerging and at various levels of pre-commercial maturity. SSE Thermal and Equinor are developing plans for one of the world’s largest hydrogen storage facilities in Aldbrough, Yorkshire but final investment decisions will depend upon further Government decisions here. This Aurora insight report includes an assessment of market readiness.


3.3 Is it possible to produce enough domestic green hydrogen to fulfil long-term energy storage demand needs?


Some members think this could be feasible if sufficiently prioritised by government whilst others disagree. If feasible, it would take time to establish an industry and there would be competition for both the ‘excess’ generation needed to establish supply and for resulting green hydrogen. The Climate Change Committee (Delivering a Reliable Decarbonised Power System (March 2023) suggest that on current plans, there would be insufficient green hydrogen to fulfil new demand until ‘at least until the 2040s. and that therefore significant additional infrastructure and dedicated supplies would be required.


3.4 Is there a distinct role for technologies that store heat instead of electricity?


Storage technologies (at household or district level) can also store thermal energy, supporting the electricity system by reducing peak demand. Thermal energy storage projects are funded by government’s LDES demonstration programme (LODES).


  1. What policy support is currently in place to support deployment of storage technologies? Is it sufficient to support deployment at scale?


No. Government has committed to developing an ‘appropriate policy to enable investment’ for LDES by 2024 and to design new business models for hydrogen transport and storage infrastructure by 2025. However, little hydrogen production and storage capacity is expected before 2029 and, whilst the current pumped hydro pipeline could double installed capacity, a 2024 decision on the revenue stabilisation mechanism is required for new capacity to be operational by 2030.


4.1 How good is the economic case for long-duration energy storage? What policies and market structures are needed to make the business case viable?


Market frameworks tend to undervalue storage and lead to lower amounts that are optimal (the value of storage only revealed close to real time). Medium duration technologies tend to be capital intensive, with long lead times. This makes them highly sensitive to cost of capital and too risky for private sector investment without specific support (the Capacity Market’s [CM] four-year lead time is insufficient [but could be amended], and the Contracts for Difference scheme does not cover energy storage). A ‘cap and floor’ mechanism (used to de-risk finance for interconnectors) is preferred by those developing new LDES but there is also support for changes to the CM to facilitate investment here.


Hydrogen storage: the sizing of storage (deliverability and volume) is a key issue, and, with long lead times (for both new build and conversion of existing natural gas facilities), early decisions are needed to support a hydrogen economy in the 2030’s. The development of hydrogen storage will need to keep pace with its role in the future economy (for power, industry and potentially heating and transport) as well as its role in balancing the future and maintaining system adequacy (this Royal Society report suggests a different scale of hydrogen storage might be required here). Where hydrogen storage is provided by repurposing natural gas storage, consideration will also need to be given to maintaining security of supply for natural gas customers. Whilst we welcome the government’s work on strategic planning and early support for hydrogen infrastructure, under current plans, there is unlikely to be significant levels of hydrogen storage until the early 2030s. Current barriers to hydrogen storage include the lack of a licensing route for onshore hydrogen storage and little visibility on the process or timeframe for strategic network planning for vectors other than electricity. Avoiding further delays to investment here will require better coordination between DESNZ, ESO and NGT ahead of the creation of the FSO next year.

4.2 How will the grid need to change to support long-duration storage?


Please see our response to 3.3 here on the need for strategic network planning. As storage is a tool for reducing network constraints, provision should be assessed as part of this strategic network planning process. Changes to the grid will depend on the type of storage and where it is located. Some types of LDES are modular (batteries and liquid air energy storage [LAES] such as Highview Power’s technology) and can be sited to ease current/ future stress on the grid. Others are location-specific (pumped hydro and hydrogen storage). New sites may therefore require network expansion and decisions on whether (in the case of hydrogen) to transport it as a gas or electricity. Many projects are already in the connection queue to connect to the energy system, but the backlog in that process is causing significant concern about the ability to get any of these projects online by 2030 or 2035.


4.3 What role does the Review of Electricity Market Arrangements need to play to support medium- and long-duration storage development?


REMA will need to ensure that sufficient investment in storage across all durations is achieved, in the right places for the system, and that these assets are then used as efficiently as possible once operational. Whether it can do this ahead of Government (or FSO) providing further clarity on the key building blocks for net zero is less clear.


4.4 Is the Government’s current reliance on market actors and technology competitions likely to deliver the storage needs on time?


No. As per our response to Q4, Government decisions to de-risk private capital are required here. SSE’s Coire Glas pumped hydro project, for example, is expected to take 7 years but will not proceed until the Government decision on a suitable revenue stabilisation mechanism has been made. Equinor and SSE’s hydrogen storage project has similar lead times and is awaiting a Government decision. Other projects are emerging, but policy uncertainty, planning regimes, and the connections backlog remain as barriers that the existing approach will not address.


  1. How developed is UK industry? Does it compare to global competitors?

5.1 Are there any storage technologies that have a significant export potential?

5.2 For which technologies does UK have existing research or industrial capacity?

5.3 Is the Government doing enough to support the industry to grow?


Britain will reach a high penetration of variable renewables faster than many global competitors. Experience gained effectively managing a variable grid, both in terms of the technologies deployed and policy mechanisms developed to incentivise these, will be valuable elsewhere. Britain is already leading on hydrogen storage (due to its industrial heritage, geography and geology), LAES, battery deployment and innovative longer duration batteries. This export potential will ripple out to benefit related service industries (consultancy, legal and financial).


  1. Beyond the cost, what major barriers exist to its successful scale-up?

Are there sufficient training schemes ensure the UK has a sufficient workforce?


Industry is not confident that a robust pipeline for skilled workers has been established. To build out supply chains and skills at scale, Energy UK recommends:

i)                   Government provides further clarity on its approach

ii)                 Government, Ofgem, and National Grid ESO ensure appropriate routes to market, at an appropriate scale, to incentivise private investment.

iii)               Government retargets existing skills funding toward related industries.


  1. How long is it likely to take to develop the necessary infrastructure?

What steps should the Government take now?

Can the UK learn from other countries with successful policies/ pilot projects?


Delivering support for technologies that are ‘shovel ready’ while developing market signals and innovation projects for other technologies to emerge, will help to deliver a range of technologies at scale, maintaining a diverse range of flexibility sources to balance the system effectively.


11 September 2023

[1] Note: storage requirements are typically given in both storage capacity (GW) and volume (GWh).